ML20209D104
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{{#Wiki_filter:i I l AE00 ENGINEERING EVALUATION REPORT
- UNIT: See Table A EE REPORT NO.: AEOD/E416 DOCKET NO.: See Table A DATE: June 11, 1984 LICENSEE: Several EVALUATOR / CONTACT: E. J. Brown
SUBJECT:
EROSION IN' NUCLEAR POWER PLANTS EVENT DATES: See Table A SUMARY This engineering evaluation covers a broad overview of erosion events in nuclear plant systems. The initial impetus was the rupture of an extraction steam line at Oconee 2 on June 23, 1982. The intent of the investigation was to identify the scope of degradation related to erosion and assess potential generic implications. This study identified more than 140 events related to erosion of various components including pumps, valves, heat exchangers,- and piping in various systems. Although a significant effort was made to obtain this data, a caution is offered that the data base should be considered' as representative of the types of degradation that can occur rather than a complete list of events. Based on the data, it does not seem that a specific safety problem needs immediate corrective action; however, there are potential safety issues. Although specific recommendations do not appear fusible, potential constructive actions relate to: (1) cognizance of the phenomenon for certain sites and systems; (2) identification of specific plant equipment and physical configurations that may be susceptible to erosion; and (3) implementation of monitoring programs to detect degradation of equipment (pumps, valves, heat exchangers, and piping). Some areas have potential safety implications and it is suggested the NRR review and consider the following items: A. Water Systems
- 1. Erosion events appear related to the specific water source with suspended solids (raw water, radwaste, etc.), the use of throttling devices (valves and orifices), or a combination of these effects.
Systems and components with these conditions may warrant considera-tion for monitoring as part of ongoing inservice inspection programs to detect degradation. I
*This document supports ongoing AE00 and NRC actiities and does not represent the position or requirements of the responsible NRC program of .
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- 2. Service water systems appear to be ideal candidates for erosion and warrant acnitoring for degradation and potential impact on safety related equipment. There may se a relationsnip oetween sizing criteria for accident conditions and the need for tnrottling devices for normal plant loads.
- 3. Erosion of steam generator feedwater J-tubes should be reviewed for possible monitoring requirements to detect erosion that may lead to draining of the feedwater header and suosequent water hammer.
4, The emergency feedwater system at Ft. St. Vrain has had approximately 25 erosion events in valves and piping.
- 3. Steam Systems C
- 1. Erosion of MSIV. seats way lead to leakage and adversely impact the leakage control systea. This issue is currently under review by NRR and we suggest it continue until it is resolved.
- 2. Leakage or rupture of steam piping may be more frequent than the data indicates because the events are generally not reportable. We are not 4
aware of ruptures that have affected safety systans. Plant specific reviews 7ay be needed in order to identify specific safety issues. Data suggests that pipe ruptures may pose personnel (worker) safety. i ssue s. 4 1
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't
. j INTRODUCTION
', The rupture of an extraction steam line at'Oconee 2 on June 28,1982 was reported in PNO-II-82-72 and PNO-II-82-72A (Ref.1). An update of the event with additional infonnation relating the cause of rupture to erosion was provided in .IE IN 82-22 (Ref. 2). Review of these reports relative to erosion as the cause of failure and potential effects led to initiation of a search ano evaluation of failures related to erosion. The intent of the investigation was to identify the scope of degradation related to erosion ^ and assess potential generic implications. i The pipe rupture event at Oconee 2 occurred at the outside radius of an elb,ow of a 24-inch line which branches off the 42-inch high pressure turbine exhaust. The cause of failure was thinning of pipe wall material due to steam erosion. The break area was approximately four souare feet. With this ' background, initial efforts to find additional _ events were directed toward l large steam piping with leakage or rupture caused by erosion. It soon became 4 evident that large steam piping in which erosion related degradation had l occurred was not covered by technical specification reporting requirements. Therefore, in general, there are no licensee event reports. (LERs) for large steam pipe ruptures. Consequentially, the Oconee 2 event was not reported in an LER. , 7 DISCUSSION Based on the preceding infonnation, the search for erosion events was broadened to cover piping system components in addition to the piping; also, infonnation sources were expaned to include LERs, daily reports, and preliminary notification of events (PNO). The search revealed more than 140 events specifically identified as related to degradation by erosion (there would be many more events if all LERs referenced in specific LERs were included in the search). Table A is a listing of all erosion events. The listing is arranged by component for pumps, valves,-heat exchangers, and piping with piping further subdivided by system. For each event, i the tables identify the plant name, docket number, LER number, event date (if available), plant type, system affected, and a brief event description to provide
- the problem and cause'(if it was available in the data source). The data search covers the period from 1976 to early 1984.
The total number of erosion events listed in Tables Al through A4 exceeds 140 ovents. The approximate breakdown for events is: Table Al with 14 ovents for pumps; Table A2 with 31 events for valves, Table A3 with 40 events for heat exchangers (31 events were for leaks in the containment fan coil units at one plant), and Table A4 with 60 events in piping systems. Table A4 is subdivided into A4.1 for Main Steam piping including hfgh> pressure coolant injection (HPCI) and reactor core isolation cooling (RCIC); A4.2 for feedwater systems; and A4.3 for service water and other systems. ww r ,e-<~ ---- -- . - , - ---- e m --->e--e - -, w w e
The erosion events listed in Table Al involving pumps prinarily address erosion of pump internals, bell nousing, and coolers for notors or oil. l Five of the 14 events ;ere for leaks in the notor cooler for the same high pressure service water pump at one plant. The erosion for tne motor cooler - as attributed to continuous flow of lake water through the cooler whether t.9e pump was in use or not. Although this would appGar to be a potentiai generic situation for all such puaps at that plant, there were no otner recorted failures in tae data base. Eight of the 14 events involved eitner , raw water systems or radwaste systems. This appears to indicate that particulates in suspension in the water system were an inportant aspect contributing to these erosion events. Item 4 of Table Al provides an exanple of significant erosion of all four service water pump casings after 12 years of plant service. The raw water source was the ilississippi River. Although t..'re was significant casing erosion and a small leak in punp l A (estinated at two gallons per day), pump perfomance still net aesign requiranents. Actual operating time of the pumps as estinated to oe 300 hours per year per pump for a total of 3600 hours during the 12 years (2ef. 3). This would suggest a naxiaum pump running time of 150 days on a continuous running basis. The erosion events affecting valves were observed to involve both steam and water systems. One type of valve in steam service that has received previous N?.C attention for seat leakage is main steam isolation valves (MSIV). Reference 4 (IE I:132-23) identified over 151 inservice tasts-in which an
- iSI/ failed to meet a maxiaum pemissible leak rate. The Itl indicated that 19 operating :3NRs were involved. Fron the standpoint of erosion, the I:1 identifies only three plants (Browns Ferry 1 and 3 and Quad Cities 2) tnat attribute dSIV seat leakage to steam erosion. This AE00 searen for erosion events identified MSIV leakage (Taole A2) at Browns Ferry 1, 2 and 3, not the .
sarne LERs as in Ref. 3 in all cases, byt did not find the Quad Cities 2 event. Since so few plants attribute leakage to steam erosion, there may be a subjective aspect in the detemination such that erosion or some other surface condition may be contributing to the occurrence of MSIV leakage. The primary concern about itSIY leakage relates to offsite . dose calculations i following a LOCA. The NRC staff approach for dose contributions from MSIV i leakage is based on a technical specification pemitted limit. Exceeding i the limit may adversely affect operation of the MSIV leakage control system with a subsequent impact on dose considerations. Reference 5 discusses a ! revised priority effort for Generic Issue C-8, "MSIV Leakage and Leakage Control System Failures." Although leakage rate is the primary issue, it appears that causes of leakage, such as erosion, could have an important impact on resolution of the MSIY leakage contribution to offsite doses following a LOCA. l 4 i e
The issue of MSIY leakage in BWR plants has been under review by NRC and the nuclear industry. Two EPRI reports, References 6 and 7, discuss efforts to identify factors that affect leak-rate performance and a test program which included development of tooling to facilitate preparation of the i mating surfaces during maintenance. These reports suggest that poor maintenance procedures were responsible for the past high frequency of occurrence of excessive MSIV leakage. Reference 8 provides a summary of the BWR Owners Group meeting with NRC staff as part~ of the staff evalua-tion of MSIV leakage. We understand that evaluation of this effort will be a part of tne resolution for Generic Issue C-8. The number of reports on' valves were distributed among all reactor types with 11 for PWRs,19 for BWRs, and 1 for an HTGR for a total of 31 reports (a single report may involve many valves and one report identified 38 valves). The number of reports for BWRs was nearly evenly distributed between valves in water and steam service while PWRs had more reports for valves in water service than in steam service. The PWR steam erosion was limited to steam cutting of the valve seat and internals with one event in the auxiliary feedwater system and one event in the pressurizer over pressure protection system. PWR water erosion events wre reported at three sites with the largest number at the D.C. Cook site. Both units reported erosion of valves in the containment isolation system with most valves being located in the NESW (13 of 14 in one report and 17 of 38 in another report). Also, one 1983 report for D.C. Cook referenced ten other reports dating back to 1976. There were three events at Connecticut Yankee in the chemical and volume control system in the charging pump recirculation line. These events involved both seat and valve body erosion. The other event was at Beaver Valley in which erosion of a check valve hinge pin in the river water system resulted in separation of valve internals that wre found in the diesel generator lube oil cooler.* Hence, the data suggests that valve erosion in PWR water systems is related to raw water systems or use of throttle devices in the system, but it appears to be limited to a few plants (this may actually be more a function of time for erosion of the valve to occur because subsequent data on piping involves more plants). The 19 valve events in BWR plants involved 10 with steam service and nine in water filled systats. For steam service, as discussed previously, three events identified seat erosion in MSIVs. Pilot valve erosion of main steam system safety-relief valves (SRV) was reported at five plants with one report citing steam cutting on five of six valves tested. One event (Table A2, item 1) was the subject of a previous AE00 evaluation, Ref. 9, concerning possible inoperability of SRVs at high leakage rates that may resulc from pilot seat erosion. In response to the concern about the effect of pilot valve leakage on SRV operability, Reference 10, indicates that test data supported a conclusion l that leaking pilot valves will not adversely affect operability of two stage SRVs. Also, Reference 11 identifies industry recommendations to increase the SRV simmer margin.. The simmer margin is the difference between the set
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i i I pressure and the reactor pressure vessel operating pressure. Hence, an increased simmer margin should reduce leakage and subsequent erosion of pilot-seats. The remaining two events involved drain lines for the main steam and RCIC systems at one plant. The nine valve events in BWR plant water-filled systems were distributed among several water systems. Valves in service water systems represented more 'than 50 percent of the events (5 out of 9 events and involved 5 separate plants). The i erosion related problems involved wear through the wall of valve bodies, rubber i seat deterioration, and retaining device wear (set screw). Although this search identified'about 30 events associated with erosion of valves, i a recent AE00 investigation, Reference 12, of the failure of an anti-cavitation ! device in a valve apears to illustrate that a general search on erosion may not i be adequate to identify valve erosion events. In Reference 12, the LER for the event did not mention erosion as the cause of failure (it may not have been known at the time the LER was prepared). However, subsequent investigation detennined that erosion, resulting from suspended solids in the service water system, was the primary cause of failure. Additionally, several similar events were discovered involving the same type of valve and each incident was representative of a potential safety problem relative to loss of cooling during an accident. Hence, erosion may be more prevalent than suggested by the data retrieveable by a general
- search on erosion.
- The 40 erosion events involving heat exchangers are listed in Table A3. These i events include 31 reports identifying leakage in the Containment Fan Coil Unit at Salem 2. Since the events are all similar, the description for each event I was omitted from the table. All of those events were attributed to erosion resulting from silt in the service water. The fan coil units at Salem 2 were i repl aced. The remaining 9 events include tw with leakage in fan coolers and eight involving lube oil and motor cooling heat exchangers. The most prevalent i systems affected by the oil cooler leakage were the charging punps in the chemical 1 and volume control system and emergency diesel generator at the Salem site (5 of l the 10 events). All leakage was related to erosion in the service water system.
The leakage in these cooling units does not appear to have the potential for large failures but loss of oil cooling or water mixing with the oil would eventually I result in pump damage and loss of capability to perfona the intended function. l 1
! Table A.4 identifies events related to erosion of piping with nearly 60 reports. l It is subdivided into three portions by system to cover main steam systems with 31 reports, the feedwater systems with 9 reports, and service water systems with 20 reports. Reports involving the main steam system, Table A.4.1, are '
- distributed such that 19 are for BWRs and 12 are for PWRs. However, both the i distribution of reports among plant types and the number of reports appear to be questionable relative to completeness or signficance. To illustrate, the 19 BWR events include 15 reports submitted by a single licensee. Each of these 15 events was an LER for a steam leak in a drain line with 6 of the 15 for a HPCI or RCIC e
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l steam supply drain line. These types of leaks could be relatively common, I but no reports by other licensees were retrieved from the data base. I Although the number of steam leaks seems rather large and yet may be repre- I sentative of events at a given plant, the absence of reports by other i licensees suggests interpretation of reporting requirenents may be a reason l for the difference. In any event, it would appear that either solutions have been developed or reporting requirements (or perhaps interpretation of reporting requirements) have changed because the most recent report for a drain line leak from that licensee was in July of 1981. Even though the drain line leaks may not appear to be a safety problem, the cause of erosion, ! which was reported as flow down stream of a restricting orifice, does have important implications relative to use of such devices in both steam and water systems. - 4 The remaining four (out of 19) pipe leaks in piping larger than that for a small drain line generally involved lines from the moisture separator or the turbine bypass line. Two of these events at Dresden 1 and 3 were reported by , LERs (items 4 and 5, Table A.4.1). The other two events were at Browns Ferry 1 (item 11, Table A.4.1) and Vennont Yankee (item 10, Table A.4.1). The latter events were reported by NRC as a daily highlight and a preliminary notification of an unusual occurrence (PNO), but the licensees were not required to prepare an LER and none was submitted for either event. l l The 12 events identified for PWR plants can be grouped as those that were reported by licensees and others that were not reported. The five events l 4 reported were generally associated with the steam generator including drains. ; Since the steam generator is safety-related, these events were covered by l reporting requirements (or at least interpretated as such). The other seven ' events involved leaks or rupture of 1arge steam lines that are generally not ' covered by reporting requirements. Hence, the large pipe failures were only reported as PN0s, monthly operating report, or IE daily reports, but none were reported by LER. The subject of failures in large steam piping was investigated further through
- discussions with resident inspectors at several operating plants. The primary areas examined were safety significance (plant and personnel), frequency of occurrence (leaks or rupture), and surveillance programs for detection of erosion prior to failure of the pipe. The few events identified in this review do not appear to have resulted in situations that caused immediate plant safety issues. Some of the pipe ruptures have resulted in destruction of equipment such as a motor control center and instrtsnents but no safety-related loads or functions were involved. 'In one event (PWR), two of four
- turbine steam header pressure transmitters were destroyed and were the reason for a loss of indication of steam header pressure during the event,
~ but safety-related steam generator header pressure instruments wre not affected. In this same event, two people were hospitalized overnight with steam burns , and then released. Although we are not aware of serious injury associated l with any of the events cited in this report,'it would appear that personnel injury may be a potential safety issue relative to erosion and subsequent . rupture of piping in the turbine building. )
The very nature of transporting high velocity steam with pipe bends and possible pressure changes makes piping susceptible to erosion. It appears from discussions 1 with resident inspectors that this fact has been recognized and several licensees either have established a monitoring program or are in the process of developing such guidelines. The monitoring generally is based on wall thickness changes ! (thinning) with time in service. The monitoring programs tend to be very plant specific and related to experience from leaks or preliminary baseline measure-ments to identify local wall thinning. There were illustations of local wall l i thinning of approximately 80% (from .350" to .070") without leaking or rupture. In addition, several plants have replaced piping and elbows with more erosion resistant materials while continuing a monitoring program. The nine reports (Table A4.2) that involved feedwater (including auxiliary or emergency feedwater) systems included 4 reports for BWRs, 3 reports for PWRs, and 2 reports for HTGRs. The BWR reports were for the same plant between April ~ 1977 and September 1978. Each report was about a leak in a minimum feedwater flow bypass line. Also, each leak appeared related to erosion resulting from - turbulent flow from an orifice or reducer. It would appear that corrective action was implemented because no further reports appear in the data base subsequent to 1978. One of the three reports at a PWR was also attributed to flow patterns downstream of an orifice in an auxiliary feedwater mini flow line. The other two events in pWRs involved erosion of J tubes at Ginna and Surry 2 that were recently installed as one of the elements to help prevent and mitigate steam generator water hammer.
- one J tube and up to 50*. wall loss in all 38 The event at Ginna involved a hole in J tubes. Similarly, Surry 2 reported -
hole ~s in 7 J tubes and reported that all J tubes were to be replaced with tubes manufactured from a more erosion resistant material. These J-tubes had been in service approximately three years prior to the erosion events. Based on discus-sions with the licensees and NRC staff, it appears there are no NRC requirements in either plant technical specifications or Inservice Inspection Rules of the ASME Code, Section XI, to cover the J tubes. One plant discovered the erosion i inspection as part of a maintenance program. If installation of the J tubes to reduce or prevent water hammer relates to specific steam generator safety issues, NRR may want to consider the need for surveillance requirenents. The remaining two reports associated with feedwater systems were both for the emergency feedwater supply to the loop 1 helfun circulator at Ft. St. Vrain (HTGR). In addition, these two reports referenced seven other reports covering erosion events between 1980 and 1982 on this systrsn. The same emergency feedwater system was identified in item 31, Table A2 with valve erosion. That LER referenced eight other reports which together represent 16 events related to similar valve problems between 1980 and 1982. Thus, the emergency feedwater system has encountered a signficant number of erosion events (approximately 25) for both piping and valves over a three-year span. i ' Table A4.3 is a list of 20 reports involving erosion of piping in service water and other (only 2 reports) systems. There were four reports for BWR plants and 16 reports for PWR plants. Three of the four events for BWRs occurred at Cooper. In each event, a contributing factor cited was solid / silt content in the water or adverse effects due to throttling of a valve at the outlet of a heat exchanger. 4 The other BWR event appears to be an isolated occurrence with the TIP system due to flow characteristics in the cleanup equalizing line. -
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The majority of the 16 reports at PWR plants appear to be related to turbulent flow conditions developed by the throttling of flow control valves. The ' erosion also seems related to suspended solids in the service water (either identified in the report or other reports in Table A for events at the same pl ant) . The other systems affected by this damage to service water piping were generally fan coil coolers or component cooling water systems for high head injection pumps. Hence, deterioration of the service water system piping or components (valves and pumps) does have safety implications. Most of the leaks have been of the pinhole type without the threat of large ruptures. Furthennore, the service water systems are relatively low pressure systems and,
.in contrast to steam piping, they should not have sufficient stored energy to produce rapid propagation of pipe failures. Also, the type of failures that have been observed appear to be of such a nature as to provide sufficient time to either accomplish . repairs or establish alternate water sources. It should be recognized that this situation for service water piping relative to time for corrective action may not apply to heat exchangers in which cooling water passing through eroded tubes could mix with oil and subsequently render a pump or motor 4
inoperable due to inadequate lubrication or cooling. There was one event attributed to erosion in the RHR recirculation line, thus it would seem to be an isolated case. Based on discussions with resident inspectors, erosion of service water systems may be more prevalent than reports indicate. It appears that licensees are aware of the phenomenon such that piping has been replaced prior to development of gross leakage or unavailability of a system or a train of a system. Wi th thi s replacement approach, degraded piping would not be a reportable event. i The distribution by number of service water events among LWRs (4 BWR and 16 PWR) and the apparent cause relationship to valve throttling and/or solid suspension I in fluids may warrant further investigation relative to identification of potential erosion sources and monitoring or detection of degradation. For example, the large number of PNR events compared to BWR events does not seem intuitively obvious. Since most events are related to throttling of valves, i there may be a relationship that PWR service water systems are sized for I accident conditions with significantly larger capacity requirements than nonnal j operation cooling loads. Hence, the reduced flow requirements for normal loads
- would be expected to result in throttling of valves with subsequent local l l turbulent flow and erosion of piping and/or valves. If this hypothesis is valid, it may provide guidance or suggest areas that may benefit from
! monitoring for possible degradation. However, it also appears that the service water source, such as one with significant amounts of suspended solids, may be the dominant contributor to erosion degradation. FINDINGS l This study has identified more than 140 events related to erosion of various components including pumps, valves, heat exchangers, and piping. It is also evident that there are many events referenced in some of the reports such that erosion may be more prevalent than the nunber of reports might suggest. The purpose of this evaluation was to review the many events to develop a perspective
-ind draw relatively broad interpretations relative to safety implications. Based on the evaluation, the following findings are provided: _
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- 1. Pumps A. The erosion events with pumps appear to be concentrated in those used in raw water or radwaste systems. This appears to indicate that particulates in suspension in the water are an important contributor.
B. Service water pump damage in a highly erosive environment (item 4, Table A1) resulted in replacement of all four pump casings in one facility after 12 years of plant operation. However, actual operating time was estimated as 300 hours per year per pump or 3600 hours over 12 years. ] . This time would translate into 150 days of continuous pump operation.
- 2. Valves A.
- The 31 erosion related reports for valves were distributed among plant types with 19 for BWRs,11 for PWRs, and 1 for an HTGR. However, a single report may involve many valves and one report identified 38 valves. The BWR events were nearly evenly distributed anong steam and water systems; the PWR events were mostly for water systems; and
{ the HTGR events were all for emergency feedwater systems. B. The majority of the BWR valve steam erosion events involved MSIVs and SRY pilot seat erosion. The SRV pilot seat erosion appears to have been resolved as indicated in References 9,10, and 11. The MSIY leakage has been under review as identified in References 6, 7, and 8. C. The majority of the PWR valve erosion events in water systems appear related to use in raw water systems or throttling of the valve. There _ is some evidence that certain sites may be more susceptible based on the raw water source. l
- 0. Based on an AE00 report in progress (Reference 12), there is some evidence that erosion may not be identified in LERs because of the time needed to evaluate or identify the cause of equipment failure.
3 Heat Exchangers A. There were 40 erosion reports involving heat exchangers with 31 reported for the containment fan coil unit at Salem 2. The fan coil units were replaced. B. Eight of the remaining nine reports involved lube oil and motor cooler heat exchangers for safety systems such as high head injection punps. l All leakage was attributed to erosion from the service water system which ' is normally raw water. Hence, safety systems have been affected and water in lube oil systems could result in rapid degradation of needed , equipment.
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- 4. Piping A. Steam Piping (1) The distribution of erosion events in steam pi' ping was 19 BWR reports and 12 PWR reports.
(2) For BWRs,15 of the 19 reports were steam drain lines at one plant, Monticello, between 1976 and 1981 (no reports after 1981). Most of the events appear related to erosion downstream of a restricting orifice. These drain line leaks were reported by LER. (3) The large diameter BWR steam pipe leaks which occurred after 1978 have not been reported by LER. (4) For PWRs, 5 of the 12 reports were for events associated with steam generators, which are safety-related equipment, and LERs
, were submitted.
(5) For PWRs, 7 of the 12 reports involved large steam piping leaks or ruptures. The events were reported in PN0s, IE daily reports, or licensee monthly operating reports, but none was reported by l an LER. (6) Large steam line ruptures have generally occurred in the turbine building. The equipment destroyed or damaged during such events has not been safety related. (7) Rupture of large steam piping in the turbine building appears to l raise concerns related more toward personnel safety rather than plant safety. Some licensees are implementing inservice inspection (ISI) programs to monitor pipe wall thinning. B. Feedwater (1) The nine reports wre distributed with four for BWRs, three for PWRs, and two for the HTGR. The four BWR reports were all for Dresden 3 during 1977 and 1978. Each report was for a minimla feedwiter flow bypass line downstream of an orifice. (2) Two of the three PWR reports were for J tube erosion in steam generator feedwater ring headers. The J tubes were installed l as one step in a procedure to reduce the occurrence of steam generator water hammer. (3) The two reports for the HTGR (Ft. St. Vrain) were both for l the emergency feedwater supply to the hellun circulator. The two repcrts referenced seven other reports on the same system.
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d 12 - C. Service Water !. (1) Sixteen of 20 events in service water systems occurred at PWR I pl ants. For both BWR-and.PWR, the amount of suspended solids
'or silt was cited as a contributing factor to erosion.
(2) A majority of the 16 events in PWRs cited either suspended solids in the water or throttling of the valve as the causes of pipe erosion. (3) The type of degradation observed in service water piping (pinhole leaks) does not st;ggest that rapid propagation would occur. Also the systems are ' generally at a relatively low pressure which would tend to limit a large fracture. CONCLUSIONS ^ Based on an evaluation of the more than 140 reports involving erosion, there are some general conclusions that appear warranted. First, the data base is probably , incomplete because many events are not reportable. Hence, the data base in ;
- Table A should be conslered only as representative of the types of degradation that can occur in nuclear plants due to erosion rather than a. complete list of 4 events. Secondly, there does not appear to be a direct relationship between these events and a specific safety problen that needs fanediate attention;
. however, there are potential safety issues. Thirdly, this overview evaluation suggests broad areas with potential safety concerns, but a detailed review of individual events may reveal specific safety impacts as indicated in Reference 12. ! Some of the broad erosion issues identified in this study are currently being i reviewed by NRR or industry owner groups while others appear worthy of consideration by NRR. Although specific recommendations do not appear feasible, l it would seem that potential constructive actions relate to (1) cognizance of the phenomenon for certain sites and systems; (2) identification of specific plant equipment and physical configuration that may be susceptible to erosion; and (3) implementation of monitoring programs to detect degradation of equipment (pumps, valves, heat exchangers, and piping) . The areas that appear to have potential safety implications and should be considered and reviewed by NRR are as follows: A. Water Systems
- l. Many erosion events appear related to the specific water source with suspended solids (raw water, radwaste, etc.), the use of throttling devices such as valves and orifices, or a combination of t' affects of water with suspended solids and a throttling device. These water
, , sources and devices may be situations that warrant review for monitoring as part of ongoing inservice inspection programs to detect degradation.
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- 2. Service water systems appear to be ideal candidates for erosion and warrant closer review to monitor for degradation and potential impact on safety-related equipment. One possible issue would be to review the system requirements for capacity and flow characteristics corres-ponding to accident conditions and nomal plant loads. It appears that throttling devices, used in a nearly closed position, have been introduced to reduce flow to accommodate norinal plant heat loads that are significantly 1ower than accident 1oads. This results in erosion in the vicinity of these devices. These locations may be candidates for monitoring to detect degradation or possible system changes.
- 3. Erosion of J-tubes in feedwater headers seens to indicate a potential wear problem. The J-tube was initially installed to address a water hammer problem in steam generators. This appears to be an area for consideration of a need for possible monitoring and detection requirements.
- 4. The emergency feedwater systen at Ft. St. Vrain has had approximately .
25 erosion events involving valves and piping in this system. This system provides water to the turbine drives of the helitri circulator and the relatively large number of events appears to be worthy of review for possible safety implications or changes to reduce the number of erosion events. B. Steam Systems
- 1. Pilot seat erosion of SRVs in BWR plants has occurred quite frequently.
! However, it appears that safety concerns relative to possible inopera-l bility of SRVs at high leakage rates have been resolved.
- 2. The MSIV leakage, that may be erosion induced, in BUR plants is l related to offsite dose calculations following a LOCA and therefor'e I
has safety implications. This issua is currently under review by NRR and BWR owners group (References 6, 7 and 8) and should be followed until resolved. j 3, Leakage or rupture of steam piping may be more frequent than the data l indicates because these events generally are not reportable. The majority i of large steam pipe ruptures in the data base occurred at PWR plants. Based on available data, it does not appear feasible to draw generic conclusions related to plant safety concerns because we are not aware of' any ruptures that affected safety systems. Furthemore, it would seem I that plant specific reviews may be needed in order to identify specific safety issues. However, the data does suggest that steam pipe erosion could pose personnel (worker) safety concerns. Some licensees have t implemented monitoring programs to detect degraded piping. i l ' 1 i i
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1 REFERENCES
- 1. NRC, PNO-II-82-72 and 72A, " Extraction Steam Line Break,"
June 28,1982 and June 29, 1982. '
- 2. NRC, IEIN 82-22, " Failures in Turbine Exhaust Lines," July 9,1982.
- 3. NRC, Inspection Report No. 50-254/83-24(DE) and 50-265/83-23(DE),
dated March 1, 1984.
- 4. NRC, IEIN 82-23, " Main Steam Isolation Yalve (MSIV) Leakage,"
July 16,1982.
- 5. NRC, R. Mattson to D. Eisenhut, et al, " Generic Issue C-8, MSIV Leakage and LCS Failuree," May 16, 1983.
- 6. EPRI NP-2381, " Measurements and Comparisons of Generic BWR Mair. Steam Isolation Yalves," Volume 1, July 1982.
- 7. EPRI NP-2454, " Comparison of Generic BWR-MSIY Configurations,"
June 1982.
- 8. NRC, O. O. Parr to Distribution, " Summary of Meeting on MSIV Leakage,"
March 7,1984 (NRC meeting with BWR Owners Group).
- 9. NRC, J. Pellet, " Operability of Target Rock SRVs in the Safety Mode with Pilot Valve Leakage," AE00/E312, May 18,1982.
- 10. NRC, H. R. Denton to C. J. Heltames, Jr., "AE00/E312 - Operability of Target Rock SRVs in the Safety Mode with Pilot Valve Leakage," (NRR Safety Evaluation), Sept. 19, 1983.
- 11. NRC, W. J. Dircks to the. Commissioners, " Adequacy of Safety and Relief Yalve Testing and Performance," SECY-83-270, July 5,1983.
- 12. NRC, C. Hsu to K. V. Seyfrit, " Failure of Anti-Cavitation Device in Residual Heat Removal Service Water (RHRSW) Heat Exchanger Outlet .
Yalve," E411, May 22,1984.
._-u .-.4-, -- - - _.- ,, - -.,a-- --- - - - , . . - . - . - , . . . - . - . + - - - . - . - . , - . , . . .-.- . , _ , ,- . . -- ,- . - . , _ -
l ; TABLE A1. EROSION EVENTS IN PUMPS l BWR ' PLANT DOCKET NO.; REPORT NO.; ' 1 DATE SYSTEM AFFECTED , EVENT DESCRIPTION { 1. Big Rock Point Radioactive 4 155; 81-026 Waste During processing of water from the chemical waste receiving tank i 11-07-81 the #1 radwaste pump went plug failed and discharged 300 gallons of Management low activity radioactive water. The cause was long term deteriora- ] tion of the pump casing due to corrosion and erosion. . i 2. Nine Mile Poin'; Feedwater
- 220; 81-044 Number 11 feedwater pump had a lube oil leak and a water seal leak.
09-14-81 The outboard water seal leak was caused by erosion in the seal i face. Similar occurrences in LERs 80-17 and 76-43.
- 3. Hatch 1 Service I' 321; 81-079 Plant service water pump failed to meet total dynamic head Water requirenents. Inspection revealed wear and erosion consistent 07-13-81 with end of normal life cycle. Repetitive event, last j #
reported in LER 80-026. i 1 4. Quad Cities 2 Residual Heat 265, Daily Report Residual heat renoval service water systen booster ptanps were { Renoval Service 09-27-83 Water Systen found to have excessive wear on the inlet and outlet side of the casings. The wear appears to result from the raw water from the Mississipi River. The casings for all four pumps will be replaced. Pump performance was not degraded. Estimated operating time per pump for the 12 years of plant operation was 300 hours per year for 4 12 years or 3600 hours for each pump (about 150 days). PWR 1
- 5. Oconee 1 Service Water Water was leaking from the "B" high pressure service water pump d
269; 80-026 pump motor cooler. i 08-11-80 Cause was erosion of tubes due to constant flow o f Iake. wa ter. Leaking tubes were soldered.
- 6. Oconee 1 Service Water Water was leaking from the "B" high pressure service water pump 269; 80-022~ motor cooler.
! 07-07-80 The cause was erosion and corrosion of thw t@es i due to constant flow of lake water. Valves will be added to i permit flow only when the pump is in operation. i
- 7. Oconee 1 Service Water Water was leaking from the "B" high pressure service water pump
. 269; 80-018 motor cooler. The cause was erosion and corrosion of the tubes 06-01-80 due to constant flow of lake water. Leaking tubes _ were soldered.
0 -. -
1
- Table Al (Continued)
I PWR I PLANT + 1 DOCKET NO.; REPORT NO.; ! DATE SYSTEM AFFECTED EVENT DESCRIPTION i
- 8. Oconee 1 Service Water Water was leaking from the "B" high pressure service water pump I 269; 80-004 motor cooler. The cause was erosion of the tubes due to constant 02-16-80 -!
flow of lake water. Valves will be added to pensit flow only when ' ] the pump is on.
- 9. Oconee 1 Service Water Water was leaking from the "B" high pressure service water pump ;
269; RO 79-34 12-10-79 motor cooler. The cause was erosion of the tubes due to constant l flow of lake wa ter. Valves will be added to pennit flow only when the pump is on.
- 10. Millstone 2 Service Water During scheduled maintenance, a large section of the suction bell,
! 336; System . including the lower bearing, was found broken and had fallen free of ! i 005-18-77 the pump. The cause was erosion attributed to excessive velocity j 7 through the cast iron suction bells. Replacement suction assemblies i were cast with a more resistant material.
- 11. ft. Calhoun Raw Water A raw water cooling system pump failed with a sheared shaft coupling.
285; LER 77-07 Cooling ! 03-15-77 The cause.was erosion of internals .that increased clearances to such I a point that vibraticn increased and caused wear and eventual shaft . failure. I
- 12. Ft. Calhoun Raw Water During an inspection of the raw water pumps, erosive wear due to
{ 285; LER 76-9 Cooling Missouri River water was found on the pump impeller and galvanic l 04-09-767 corrosion within the connecting threads of the top core bearing. Areas worn by erosion were built up by welding. J 4 I _ _ _ _ _ . _ _ _ _ _ _ _ n _ __
1 l I ! Table Al (Continued) HTGR PLANT DOCKET NO.: REPORT NO.: 3 DATE SYSTEM AFFECTED EVENT DESCRIPTION
- 13. Ft. St. Vrain Condensate and The motor driven boiler feedwater pop became inoperable during 267; RO 79-03 Feedwater nomal operation. The cause was erosion of the pap casing.
01-05-79
- 14. ft. St. Vrain Coolant Bearing water makeup pump, P-2105, was inoperable due to less 267; RO 78-06 Recirculation than acceptable discharge pressure. The cause of deterioratica 04-03-78 in pump perfomance was erosion of'3 bowls of the 14 stage pump
. Erosion was attributable to faulty castings.
t l i i 4 T t 4
TABLE A2. EROSION EVENTS IN VALVES l < BWR PLANT ! DOCKET NO.; REPORT NO.; } DATE SYSTEM AFFECTED ' EVENT DESCRIPTION l ! 1. Pilgrim 1 Main Steam Two Target Rock 2 stage S/R valves did not pass set point lift tests. 293; 81-061 E,rosion of pilot disc being evaluated. { ! 2. Browns Ferry 1 Main Steam 259; 81-014 8 main steam isolation valves failed leak rate test. Cause was steam ) erosion of valve seating surface ( Atwood-Morrill, 26-inch globe valves). Previous similar occurrences 50-259/80-003, 78-034, 77-023, 50-260/80-024, 79-007;50-2 % /80-058, 80-058, 79-014, 78-025.
- 3. Duane Arnold Reactor Water 331; 80-067 Reactor water cleanup system to main condenser control valve, CV-2729, i Cleanup System developed a body leak. Cause was high velocity water flow erosion.
i The leak sprayed water on electrical equipment which resulted in RWCU system isolation.
- 4. Browns Ferry 3 Main Steam 7 min Steam isolation valves failed leak rate test. Cause was steam 296; 80-059 erosion of the seating surface. ( Atwood-Morrill, 26-inch globe valve).
) Siellar event on 50-260/80-049. b 3. Monticello RCIC Leaking valve caused erosion of a 1-inch, 90 elbow in the reactor 263; 79-024 core isolation cooling system drain to the condenser. ] 6. Browns Ferry 2 Main Steam i -260; 80-042 '4 min Steam isolation valves failed leak rate test. Cause was steam erosion of valwe seating surface ( Atwood-Morrill, 26-inch globe valve). Similar event on 50-259/80-003. l i 7. Humbcidt Bay 3 Station Service Leak observed in the housing of the gate valve at the discharge of the ! 133; 80-006 Water #6 screen wash pump. A 1-1/2-inch hole was caused by corrosion and
! erosion.
f
- 8. Quad Cities 1 Main Steam Electromatic relief valve, 1-203-78, failed to close during
- 254; 80-020 operability surveillance test. Cause was steam cutting of the pilot
. valve.
- 9. Monticello RNR Service Leak was discovered in the RHR service water difference pressure 263; 78-021 Water System control valve. Cause of the leak was corrosion and erosion of the upper valve body.
i .
! __ __IO_ _ ___
~
~
} ! Table A2 (Continued) 1 BWR f PLANT DOCKET NO.; REPORT NO.; i DATE SYSTEM AFFECTED EVENT DESCRIPTION ,
- 10. Quad Cities 2 Standby Liquid Standby liquid control system pump failed to produce sufficient ',
! 265; 78-15 Control (S8LC) flow rate under test as required by technical specifications. A i relief valve was leaking and recycling the water to the S8LC tank d
rather than the test tank. Cause of leak was eroded seat in the relief valve. ) ! 11. Cooper Station Service Leak in service water outlet line from the REC heat exchanger "A." i 298; 77-49 Water The leak was downstream from an outlet butterfly valve used as a , I throttle valve. Part of 18-inch rubber seat on. the butterfly valve
- was missing. Erosion was caused by high flow and silt concentratiocs.
! 12. Duane Arnold Main Steam During hydrostatic testing, excessive water leakage was observed from 1 331; 76-26 the pilot ports and exhaust ports on 6 main steam relief valves. !' Excessive steam cutting of the pilot disc was found on five of six 1 valves. l 13. Montiello Mair: Steam During leak rate testing of outboard main stream drain isolation j 263; 82-011 valve, it was found to exceed technical specification limits. l 09-03-82 Leakage of the 3-inch gate valve was caused by erosion of disc which
- resulted from seat ring misalignment.
l i
- 14. Millstone 1 Recirculation The recirculation system sample isolation valves 1-RR-36 and 1-RA-37 j 245; 82-023 System failed local leak rate test. Leaking was caused by seat erosion on
. 10-05-82
- both valves and plug erosion on valve 1-RR-37 only. Similar l occurrence in RO 79-19/3L and 80-14/IT.
l 15. Duane Arnold . Residual Heat The "D" residual heat removal system service water puinp discharge l 331; 82-032 . Removal Service check valve V-46-ll was found leaking. The cause was an eroded j 05-04-82 Water set screw which allowed the hinge pin to loosen and tiie valve to move from the proper seat.
- 16. Hatch 2 Residual Heat While perfoming the daily inside rounds, .the "B" residual heat
! 366; 82-132 Removal Service renoval service water valve was found inoperable. A pin hole leak j 12-03-82 Water had developed in the valve body via internal erosion. i L
1 Table A2 (Continued) BWR
, PLANT
! DOCKET NO.; REPORT NO.; ) DATE SYSTEM AFFECTED EVENT DESCRIPTION
- 17. Duane Arnold Reactor Core Reactor Core Isolation Cooling full flow test valve, MOV-2515, was j 331; 81-033 Isolation Cooling found to have a pinhole leak in the valve body. The original
; 08-17-81 600 lb. Class 2 valve was replaced with a 1500 lb. Class 1 valve.
j 18. J. A. Fitzpatrick Main Steam During ascension to power, following a normal reactor startup,
, 333; 82-037 abnomally high tail pipe temperatures were indicated on "F" safety i
07-30-82 relief valves. Pilot discs most eroded were found to correlate with ) the high tail pipe temperatures. 1 ) 19. Quad Cities 1 Main Steam While manually operating a Target Rock three stage safety / relief ! 254; 83-035 valve, it stuck in the open position. Inspection revealed that the 09-15-83 second stage pilot seat was eroded and was the cause for the valve to j remain open. PWR 4
- 20. D. C. Cook i NESW Erosion of valve seats.was discovered during B&C leak rate tests.
i 315; 81-025 (Containment 13 of 14 NESW check valves exceeded Technical Specifications leakage. i isolation) Valves will be replaced with diaphran valves. Similar events in 50-315/81-11, 79-34, 78-37, 77-11, 76-23; 50-316/81-18, 79-53, 79-20.
- 21. Sal m 1 Pressurizer Leakage discovered through valve IPRI to the pressurizer relief tank.
i 272; 81-061 overpressure Inspection revealed steam cutting of the valve cage. systen
; 22. D.C. Cook 2 Containment 38 containment valves exceed leakage limits during B&C leak rate l 316; 81-013 isolation system test. 17 valves were in the NESW system and six containment purge
- valves also experienced excessive leak rates.
i ! 23. Connecticut Yankee Chemical and Leak was found in the charging pimp recirculation orifice bypass ! 213; 78-008 Volume Control valve. Cause was erosion from high velocity water on both the body 5 and gasket surfaces. The valve was being used as both a throttle and bypass v !ve. 1 I 1 a .
Table A2 (Continued) PWR 1 !
- PLANT DGCKET NO.; REPORT NO.; '
DATE SYSTEM AFFECTED
- EVENT DESCRIPTION
- 24. Connecticut Yankee Chanical and Leak was found in the charging pump recirculation orifice bypass 213; 78-007 Volume Control valve. Cause of leak was severe eroston. The valve was being -
- used as a throttle valve in order to increase the amount of j
recirculation on the 8 charging pump. ' ! 25. Haddam Neck Chemical and During a watch tour, an operator observed a pinhole leak on the ! (Conn. Yankee) Yolume Control body of the "B" charging pump recirculation throttle valve CH-V-275. ! 213; 82-009 Rev. 1
- 10-15-82 '
- 26. D. C. Cook 2 Containment While performing B and C leak rate tests..several valves exhibited
; 316; 83-016 Isolation
! 01-13-83 excessive leakage which resulted in the total leak rate exceeding ' the technical specification limit. Leakge was attributed to dirt and i scale deposits on the seating surface and erosion of the valve seats. Similar concurrences in 50-315/82-058, 81-11, 81-25, 79-34, 78-37, 77-11, 76-23; 50-316/81-18, 79-20, and 79-53.
- 27. Beaver Valley River Water Hinge pin erosion of a check valve in the river water system resulted 334; 80-027 Rev. 1 in separation of the internals from the valve and they were found in 1 04-30-80 diesel generator lube oil cooler. Failure of a header upstream of the check valve could reduce available cooling water flow from the other j header to the diesel generator. A preventive maintenance systen to j inspect similar type check valves has been implemented.
} 28. D.C. Cook 1 Containment While performing the BSC leak rate tests, several valves exhibited
- 315; 82-058 Rev. 1 Isolation 07-21-82 excessive leakage causing the total leak rate to exceed the technical 1 System specification limit. Leakage was attributed to dirt and scale l
' deposits on the seating surfaces and erosion of the valve seats. (See item 26 for siellar occurrences.)
- 29. Salem 1 Main Steam Steam generator blowdown valve 14 GB 4 exhibited leakage in excess
! 272; 83-010 of requirements. The internals were wire cut. Due to a recurrence ! 02-05-83 of the problems, further engineering invvestigation will be perfonned.
- 30. Millstone 2 Auxiliary Drain valve, 2-MS-342, on steam supply to auxiliary feedwater pump 336; 80-034 Feedwater P-4, seating surface was steam cut with excessive leakage.
l , _ _ _ _ . _ _ ._ ._ -. , - - - - - - - - - - - -
Table A2 (Continued) HTGR PLANT DOCKET NO.; REPORT NO.; DATE SYSTEM AFFECTED EVENT DESCRIPTION
- 31. Ft. St. Vrain Condensate and The emergency feedwater supply header had excessive leakage through 267; 82-028 Feedwater System valve PV-21244. The cause was water cutting of the valve seat and 07-07-82 pl ug. Other related R0s are 82-015 (2 events), 81-060 (3 events),
81-054, 81-046, 81-019 (2 events), 80-058, 80-032, and 80-23 (4 events) . i l I 1 l ,
l TABLE A3. EROSION IN HEAT EXCHANGERS i PWR PLANT DOCKET NO.; REPORT NO.; DATE SYSTEM AFFECTED EVENT DESCRIPTION PWR
- 1. Salen 2 Containment An operator discovered a 0.25 gpm leak on No. 23 Containment Fan Coil 311; 82-128 Heat Removal 10-31-82 Unit )CFCUO. The cause of leakage was erosion of the CFCU cooling coil by silt in the service water.
- 2. Salen 2 " l:
NOTE: 311; 82-135 ALL REPORTS WERE SIMILAR TO THE STATEMENT IN ITEM 1 AND ARE . NOT REPEATED. THE FAN C0ll. UNIT HAS BEEN REPLACE 0. 11-21-82
- 3. Salen 2 " "
311; 82-122 10-18-82 4 Salen 2 " 311; 82-075 ' 08-14-82
- 5. Salen 2 " "
311; 82-074 08-13-82 6 Salen 2 " 311; 82-120 10-11-82
- 7. Salen 2 " "
311; 82-119 10-08-82
- 8. Salen 2 " "
311; 82-113 10-05-82
- 9. Salen 2 "
311; 82-112 O _ -- - -
Table A3 (Continued 0 PWR PLANT DOCKET NO.; REPORT NO.; DATE SYSTEM AFFECTED EVENT DESC,R,IPTION,
- 10. Salen 2 Contairunent NOTE: ALL REPORTS WERE SIMILAR TO THE STATEMENT IN ITEM 1 AND ARE 311; 82-111 Heat Renoval NOT REPEATED. THE FAN C0ll UNIT HAS BEEN REPLACED.
- 11. Sales 2 " "
311; 82-109 09-23-82 ,
- 12. Salen 2 " "
311; 82-101 - 09-16-82
- 13. Salan 2 "
311; 82-100 09-15-82
- 14. Sales 2 "
311; 82-093 - 09-10-82
- 15. Salen 2 "
311; 82-092 09-08-82
- 16. Salen 2 "
311; 82-091 09-06-82
- 17. Salen 2 "
311; 82-089 08-30-82
- 18. Salen 2 .
311; 82-084 08-29-82 O _ _ _ _
Table A3 (Continued) PWR PLANT
- DOCKET NO.; REPORT NO.;
DATE SYSTEM AFFECTED EVENT DESCRIPTION
- 19. Sal m 2 Containment NOTE: ALL REPORTS WERE SIMILAR TO THE STATEMENT IN ITEM 1 AND ARE 311; 82-080 Heat Removal NOT REPEATED. THE FAN COIL UNIT HAS BEEN REPLACED.
08-21-82
, 20. Salen 2 311; 82-078 08-19-82
- 21. Salen 2 311; 82-077 i 08-18-82
- 22. Salam 2 311; 82-075 08-14-82
- 23. Salen 2 311; 82-074 08-13-82
- 24. Salen 2 311; 82-073 08-13-82
- 25. Salem 2 311; 82-070 0 82
- 26. Salen 2 311; 82-040 05-19-82
- 27. Salen 2 311; C2-039
i i e 1 Table A3 (Continued) \ , j PM - PLANT DOCKET NO.; REPORT NO.;
- DATE SYSTEM AFFECTED EVENT DESCRIPTION i
~ 28. Salen 2 Containment NOTE: ALL REPORTS WERE SIMILAR TO THE STATEMENT IN ITEM 1 AND ARE 311; 82-028 Heat Removal NOT REPEATED. THE FAN C0ll UNIT HAS BEEN REPLACED. ; i
- 29. Salen 2 "
! 311; 81-118 -
- 30. Salen 2 l 311; 82-136 1 11-24-82 +
- 31. Salen 2 Chemical and During routine operation, a sample of No. 21 charging pump lube oil j 311; 82-126 Volisme Control revealed that a water-oil mixture existed. The cause was erosion
- 10-19-82 of the lube oil cooler from silt in the service water. The service water then mixed with the lube oil.
- 32. Salen 2 Emergency A service water leak was discovered in the piping on No. 2A 311; 82-115 Generator energency diesel generator oil cooler. The leak was in a pipe cap 1
, 09-28-82 Systen and was caused by erosion from silt in the service water. s 33. Salen 2 Station Water was observed dripping from the oil level sightglass of No. 24 } 311; 82-086 Service Water service water pump anotor. The cause was erosion and corrosion of the' i l 09-15-82 motor bearing oil cooler. A new design cooler will be installed at i , the next refueling.
; 34. Salen 1 Chanical and During a routine inspection, a sample of No.12 charging piasp gear 272; 82-041 Volunut Control oil confirmed that a water-oil mixture existed. The cause was erosion j 06-26-82 of the gear oil cooler from unsulted material in the service water.
e e
a i Tchie A3 (Centinued)
~
PWR PLANT l DOCKET NO.; REPORT NO.; j DATE SYSTEM AFFECTED EVENT DESCRIPTION I 35. Indian Point 2 Containment While the unit was at cold shutdown, a pinhole leak was discovered on the i 247; 81-021 Heat Renoval 2-inch service water outlet line from No. 25 fan motor cooler. The leak ! 08-29-81 was in an area adjacent to the downstream side of a 90' elbow weld heat j affected zone. The supply and return motor cooler lines contain 228 - i elbow welds and 81 were selected for radiographic examination with 12 ' ! indications of reduced. thickness. .The cause was erosion caused by
- brackish salt water at high velocity (10 ft/sec.).
4 1 36. H.B. Robinson 2 Containment Containment fan cooler HVN-2 was found to have a motor cooler leak. I 261; 82-006 Heat Removal The leak was attributed to erosion of the cooler tubing. All four HVN i 07-15-82 motor coolers will be replaced when new units are received.
- 37. H.B. Robinson 2 Containment Containment from cooler HVN-3 was found to have a service water leak.
! 251; Prompt Heat Removal . i Hotification l 04-10-83 1 ! 38. Conn. Yankee Containment A service water leak was discovered in one coil of the number 4 car - l 213; 83-001 Heat Renoval fan cooler. Failure was due to corrosion / erosion. i 01-14-83
- 39. Salem 1 Chemical and Oil was observed coming from No.11 charging pump speed increaser air j 272; 83-048 Volume Control breather. Tubes in the lube all cooler of the charging pump speed j 08-15-83 increaser had failed due to erosion and corrosion. The lube oil ,
j cooler was replaced. ' 1 BWR ' $ 40. Dresden 3 Feedwater During a routine plant inspection at normal unit startup, an operator ! 249; 83-008 discovered a steam leak on the shell of the 3C3 low pressure feedwater l 03-07-83 heater near the extraction stean inlet nozzle. The cause was erosion l
- -of the heater shell by deflected steam.
l 1 ] i -
-...,.---.-----~--.--------,..-.--.---.--,,-.-o-.-- .
TABLE A4. EROSION EVENTS IN PIPING A4.1 Main Steam System Piping 8WR PLANT DOCKET NO.; REPORT NO.; DATE SYSTEM AFFECTED EVENT DESCRIPTION
- 1. Monticello Main Steam Main stea' drain line on tee to condenser leaked. Believed to be 263, 80-029 erosion and impingement of steam and water from restricting orifice 09-30-80 upstream of tee. 7 previous similar events 76-01, 16, 24; 77-19, 78-07, 13, 27.
- 2. Monticello Main Steam Steam leak in a 90* elbow on turbine main steam bypass header due 263, 79-001 to erosion of a 1" drain line to the condenser. Seven previous '
similar occurrences R0-76-01,16, 24; 77-12; 78-07,13, 27.
- 3. Monticello Main Steam Steam leak in a tee downstream of M0119 on the 2" HP turbine "U" 263, 78-027 bend drain line to the condenser. Believed due to restricting 11-21-78 orifice.
- 4. Drcsden 3 Main Steam Found steam leak during check of moisture separator area. Steam 249; 78-052 was blowing from theb ottom of an elbow.
11-04-78
- 5. Drcsden 1 Main Steam Two leaks in turbine extraction bypass line (2705-4"-88) 010; 78-031 10-07-78 6 Monticello Main Steam Steam leak in a 90* elbow on turbine main steam bypass header 263, 79-013 1" drain line to the condenser. Due to erosion from restricting orifice R0-2569 upstream of the elbow.
- 7. Monticello Main Steam Erosion of elbow wall in a 1" HP turbine bypass header drain line.
263; 76-24 Caused by hot flashing after passing through an orifice.
- 8. Monticello Main Steam Leaking of elbow in a 1" HP turbine inlet steam line U bend 263; 76-16 drain. Erosion from hot steam flashing after passing throgh an orifice.
l
Table A4.1 (Continued) BWR PLANT - DOCKET NO.; REPORT NO.; ' 7 DATE SYSTEM AFFECTED EVENT DESCRIPTION
- 9. Monticello Main Steam Leak in 1/2"' elbow 4n the ' condensate return line (in air ejector 263; 76-01 room) downstream of tiie trap. Erosion caused by hot steam drains flashing after passing through the trap.
4
- 10. Verimont Yankee Main Stean Operations personnel noticed leakage from the."C" Moisture 271; No LER Separator Drain Line during routine tours. Leakage initially Inspection
. appeared as wetted insulation. By January 25.' 1982 laakage 50-271/82-01 -
fr. creased to the point where minor wisps of steam were blowing from the piping. A through wil defect was found in a 6-inch
- diameter section of the drain line just upstream of the 24-inch expansion volume. Extensive corrosion / erosion showed' by ultrasonic
~
examination. Damage included a pinhole leak and a crack at a gusset support welded to the;ex~terioF of the pipe. c The pipe was schedule. 40 carbon, steel pipe'instead of schedule 80 pipe called for in the speci h c'ations. ' 1 j 11. Browns Ferry 1 Main Steam The report mentions tuo pipe ruptures caused by erosion. On'9-28-83
- 259; No LER the pipe to the C-2 moisture separator between the high pressure and i
Daily Highlight the C low pressure turbine. ruptured. Approximately one month earlier i Report ( August 1982) an elbow on the steam line to the 8 low pressure; 09-29-82 1 turbine rupturad due to erosion. TVA plans to implement UT i 5 l examinations of these lines. ~
- 12. Monticello Main Steam Main steam leak in a drain line to the condenser. Leak was in piping 263; 81-020 downstream of a 45 degree elbow due to erosion and impingement of 07-24-81 steam and water from restricting orifice upstream of the elbow.
j Eight previous similar events 76-01, 16, 24; 77-19; 78-07, 13, 27; 80-29. Stainless steel piping with long radius bends will be i installed during the next convenient outage. I 13. Monticello Main Steam Steam leak on the 15A feeduater extraction steamlinw drain. 263- 79-017 Erosion i , through the wall of the steam trap. (Insufficient maintenance. j 08-d6-79 Yarway 3/4" 600# Carbon Steel body type trap.) , } e
Table A4.1 (Continued) BWR PLANT DOCKET h0.; REPORT NO.; DATE SYSTEM AFFECTED EVENT DESCRIPTION
- 14. Monticello Main Steam IIPCI Steam supply leak in the weld of a 45* elbow of a 1" drain line 263; 78-028 to the condenser. Erosion from water and steam through leaking valve 11-24-78 Cv2043 upstream of the elbow.
- 15. Monticello Main Steam HPCI steam supply leak in a 45* elbow of a 1" drain line to the 263; 78-007 condenser Erosion caused by steam and water flow through leaking 05-08-78 valve CV-2043 upstream of the elbow.
- 16. Monticello Main Steam HPCI steam supply leak in a 45* elbow on a drain line to the 263; 77-19 condenser. Erosion caused by failed steam trap upstream of the elbow.
08-02-77
- 17. Monticello Main Steam Steam supply leak in 1", 90* elbow in RCIC (steam supply) drain 263; 79-024 to condenser. One previous occurrence 79-09. Elbow, upstream elbow 12-20-79 and connecting pipe replaced.
- 18. Monticello Main Steam Steam supply leak in 1", 90* elbow in RCIC d ain to condenser.
263; 80-028 Erosion, pnhole failure, due to high velocity steam through a leaking 08-25-80 valve. Two previous occurrences, 79-09, 79-024.
- 19. Monticello Main Steam Steam supply leak in 1", 90* elbcw in RCIC (steam supply) drain 263; 78-009 to condenser. Pinhole failure of 3000# socket weld due to erosion 04-04-79 from a leaking valve. Five previous occurrences, 76-01, 16, 24; 77-19; 78-07.
PWR
- 20. Calvert Cliffs 1 Main Steam Err.ston from 2 phase flow. Steam Generator 11 bottom blowdown was 317; 76-4 leaking at an elbow immediately downstream of an orifice inside t antainment.
n - - _ - _ - -
Table A4.1 (Continued) i PWR PLANT DOCKET NO.; REPORT NO.; DATE SYSTEA AFFECTED
. EVENT DESCRIPTION
- 21. Arkansas 1 Main Steam 313; 82-027 Reactor Coolant Systaa leak rate calculation indicated leakage of ;
i 07-14-81 3A 9pa. Water as located beneath a steam generator. Pressure
. baaring surfaces on the steam generato and a manway cover were
*uuad eroded by leakage. A gasket had deteriorated.
- 22. Arkansas 2 Main Steam 368; 82-011 A leak was discovered inside contalmeent in the B steam generator "
04-15-82 blowdown line between valve 2CV-1065 and contaiennent penetration WP-64. The cause was erosion from steam water impingement on the piping down-stream of control blowdown 2CV-1065. Valve 2CV-1065 had been throttled to achieve because of inadequate performance of the blowdown control valves outside containment in the non-Q portion uf the system. The schedule 40 pipe was replaced with scheddle 80 pipe.
- 23. Oconee 2 Main Steam 270; No LER lAlle at 957, power, a high pressure turbine extraction steam line PNO-II-82-72A ruptured (24-inch line). The ruptured area was 4 square feet and released steam to the turbine building. The cause was wall thinning ;
due to steam erosion. An electrical control panel was severely damaged but it did not affect safety-related equipment. Zion ', 1, 24. 295; No LER Main Steam A steam leak was discovered in a 150 psig high pressure exhaust steam PNO-111-82-21 line on 2/12/82. There was an 8-inch crack at a weld joining 24-inch 02-16-82 piping (leading to 15 heaters) with the 37.5-inch high pressure stram exhaust leading to the moisture separator reheater.
- 25. Maine Yankee Main Steam 309; No LER A 2-inch hole developed in a 16-inch high pressure turbine extraction PNO-I-81-102 steam line in the turbine building.
09-10-82 a I
. - _ _ - _ _ _ _ - _ _ _ _ _ _ _ _ . . - ._ - .-- . .- . __ _. w. - - - _ . - - . _ _ _ _ _ _ _ _ _ _ _ _ _ _
Table A4.1 (Ccntinuid) ' PWR PLANT DOCKET NO.; REPORT NO.; DATE SYSTEM AFFECTED EVENT DESCRIPTION
- 26. Trojan a. Main Stean Control Room Operators received signals indicating a fire in the turbine 344; No LER b. Fire Control building. The turbine building was found filled with steam from failure No PN0 & feedwater of a 90-degree elbow in a low pressure (150 psig) steam line running IE Daily Report from the high pressure turbine to the No. 5 feedwater heater. The cause j
01-11-82 was erosion of the elbow to 50 mil thickness compared to at least 200 mil thickness on other elbows.
- 27. Kewaunee Main Steam On December 27, 1982, while the unit was operating at 100% power, the 305; No LER reactor was tripped when an unsolable steam leak started to fill the t
IE Daily Report turbine hall with steam. The leak was due to a crack in an 8-inch drain 12-29-82 line from the moisture separator to the heater drain tank. !
- 28. Yankee Rowe Main Steam During heatup in Mode 3, a leak was discovered in a'2", schedule 80, 029; 83-028 SA-106 Grade B carbon steel elbow in a high pressure steam drain line.
I l The leak was caused by steam erosion and is the first event of this ! nature. The elbow and piping up to and including the downstream elbow were replaced in kind. !
- 29. Salen 2 a. Main Steam A.large amount of stems was released from the vicinity of the No. 33 311; 83-033 b. Auxiliary auxiliary feedwater pump during routine startup operations. The steam 07-07-33 Feedwater came from a hole in the pump steam supply drain line. A section of pipe downstream of the outlet line orifice had eroded. The leaking section of pipe was replaced. An engineering review of the drain line will be performed.
- 30. Calvert Cliffs 1 Main Steam A steam leak occurred in .a high pressure turbine extraction steam line.
317; No LER ; 11-23-81 The leak was through an approximate five inch split in the 16 inch ~ steam line. A two day outage was anticipated to replace the pipe. IE Daily Report *
- 31. Davis Besse 1 Main Steam Erosion of moisture separator reheater drain piping to the condenser 346; Ho LER required realignment of feedwater heater drains. The reactor power 6 - 83 was limited to 90% due to increased condensate flow. ;
Monthly Operating Report ' 9
i ! t lA4.2 Feedwater System Piping (Including Auxiliary or Emergency) i BWR i PLANT
- DOCKET NO.; REPORT NO.;
DATE SYSTEM AFFECTED EVENT DESCRIPTION
- 1. Dresden 3 Feedwater System Excessive flow while shutdown and later at 95% power. Leaks found in 249; 78-037 3f., 38, and 3C feed pump minimma flow lines. 3B had a crack. 3A and 3C 09-18-78 had pinhole leaks at the top of the pipe downstread of the 3x6 reducer in 6" diameter pipe. Plan to reduce flow velocity by replacing the pressure control valve and resizing the restricting orifice in each minimum flow line.
- 2. Dresden 3 Feedwater System Pinhole leak in the minimum flow line from 3A feed pump. Leak was 249; 78-030 3" downstrema of a 3x6" reducer in the 6" diameter piping.
07024-78
- 3. Dresden 3 Feedwater System Pinhole leak due to erosion in the minimum flowline 3-32058-6 inch 249; 78-005 from feed pump 38. Leak located at 12 o' clock position about 3 inches 03-06-78 downstreas of 3x6 expander.
- 4. Dresden 3 Feedwater System Pinhole leak, believed due to erosion, in the minimum flow line from 249; 77-21 feedwater punp 3A (line 3-3205C-6 inch). Leak was about 3 inches 04-07-77 downstream of the 3x6 expander.
PWR
- 5. R. E. Ganna Feedwater System As a result of performing UT examinations of the J tubes on the "A" 244: Daily Report steam generatoi' feedwater rings, significant metal loss from the J 04/14/83 tube walls was detected. Nominal wall loss up to 50% in all 38 J tubes was found. A hole was found in one J tube approximately 1" above the weld.
0 .
Table A4.2 (Continued) i PWR PLANT DOCKET NO.; REPORT NO.; DATE SYSTEM AFFECTED EVENT DESCRIPTION
- 6. San Onofre 2 Feedwater Three pinhole leaks were found in the miniflow line for auxiliary 361; 83-035 feedwater pump P141. Caused by cav.itation downstream of-flow 04-14-83 orifice F0-4711. Erosion was found in twu similar orifices.
The leaking section of pipe was removed and replaced. A design ' change to prevent recurrence will be evaluated.
- 7. Surry 2 Feedwater Inspection of the feedring in "A" steam generator revealed holes in 281; 83-032 7 J tubes. The holes ranged from 1/8" to 1" in diameter. Westinghouse
- 04-05-82 was reported to be preparing a program to investigate the cause of J-tube thinning. All J-tubes.will be replaced with Inconel which is a better erosion resistant material.
HTGR
- 8. Ft. St. Vrain Feedwater System Erosion in emergency feedwater supply to loop I helium circulator water 278; 80-058 turbine drives. Inside line at a 90 degree elbow downstream of PV-21243-1.
10-09-80 Previous occurrences R0 80-15, 80-23, 80-32. i 9. Ft. St. Vrain Feedwater Emergency feedwater supply,to loop 1 helium circulator pelton wheel 267; 83-015 drives was isolated due to a leaking 1-inch line downstream of 03-11-83 PV-21243-1. Excessive wear caused by fluid velocity at a pipe bend. Similar reports 82-034, 82-031, 82-028, 81-060 and 81-054. l e
l i i jTabloA4.3 Service Water System Piping (and Other Systems) PWR PLANT DOCKET NO.; REPORT NO.; DATE SYSTEM AFFECTED EVENT DESCRI_P_ TION
- l. D.C. Cook 2 Service Water Leak due to erosion from butterfly valve throttling . Leak was in ESW 316; 82-011 System pipe downstream of outlet valve from east CCW heat exchanger. A flange 01-28-82 1 Train of CCW and a 3 foot section of pipe were replaced.
inoperable i
- 2. D.C. Cook 1 Service Water Leak due to erosion from butterfly valve throttling. Leak was in ESW 315; 82-009 System pipe downstrean of the outlet from the east CCW heat exchanger. A flange 01-28-82 1 Train of CCW and a 3 foot section of pipe were replaced-inoperable i
! 3. Salem 1 Service Water Service water leak from the bottom of a reducing tee by valve 125W913 272; 81-083 System on charging pump oil cooler.
08-31-81 ECCS subsystem charging pump secured. '
- 4. Indian Point 2 Service Water Pinhole leak ^ in an elbow on the 2" SW outlet line from No. 25 fan 247; 81-021 System cooler motor cooler. Elbow and pipe replaced.
08-29-81 Fan Cooler Motor Cooler 4
- 5. Salem 1 Service Water Leak in the 1D" service water return from if. CFCU motor cooler. ASTM 272;78-050 System A333, schedule 40 repaired by welding. New spool installed following 08-21-78 Containment Fan a second failure.
Coil Unit 1 O
Table A4.3 (Continued)
~
PWR PLANT ' ' DOCKET NO.; REPORT NO.; DATE SYSTEM AFFECTED EVENT DESCRIPTION
- 6. Salen 1 Service Water Two brazed fittings leaking service waterfron 14 CFCU motor cooler.
272; 78-059 System Caused by corrosion and erosion. 08-30-78 Containment Fan Coil Unit
- 7. Calvert Cliffs 2 Service Water 318; 77-42 System Pinhole leak in service water outlet line downstream of the outlet 06-13-77 control valve on the heat exchanger. Change request implemented to eliminate need to throttle the outlet control valve. This was a 30" concrete mortar-lined, welded carbon steel pipe. "
- 8. Calvert Cliffs 1 Service Water 317; 76-56 System Leak in service water outlet piping downstream of 1-CV-5210 in heat exchanger 11. The leak was caused by erosion of a previously welded 12-27-76 patch. Piping to be replaced during next refueling.
9 Calvert Cliffs 1 Service Water 317; 76-33 System Leak in service water outlet piping downstream of throttling valve in heat exchanger 11. . Patch welded over leaking area.
- 10. Calvert Cliffs 1 Service W&ter 317; 76-11 System Leak in service water outlet piping downstream of throttling valve in heat exchanger 11. An orificed gate valve is being procured to replace the butterfly valve. Downstream piping will be lined with fiberglass for several pipe diameters.
- ll. Salen 2 Service Water 311;-82-046 System A 1.5 gpn leak was discovered inside containment on the service 05-19-82 water piping to the containment fan cooler unit (CFCU) cooling coils.
This incident was overlooked until 6/3/82 (from 5/19/82) due to inadequate implementation of administrative procedure AP-6. The cause was erosion of a blank flange in the service water pipe to No. 22 CPCU. k
t Table A4.3 (Continued) PWR PLANT DOCKET NO.; REPORT NO.; DATE SYSTEM AFFECTED . EVENT DESCRIPTION
- 12. Salem 1 Service Water 272; 82-069 Systen Service water leak was discovered on the number 12 charging pomp 08-31-82 ECCS Charging lube oil cooler outlet piping. Piping was replaced. A design change package has been submitted. .See previous event on Pump Inoperable 8-31-81.
13 Crystal River 3 Service Water 302; 83-022 Two pinhole leaks were found in seawater piping on the downstream Systen 05-16-83 side of two Nuclear Service Heat Exchangers. Erosion degradation was ,found on six spool pieces including the Polyvinyl Chloride (PVC) liner. Degraded piping will be repaired or replaced with siellar pieces that have a urethane liner. A surveillance prograa to monitor the piping condition will be initiated. i 14. Salen 1 Service Water 272; 82-069 Rev. 1 Systen Reported on 3/30/83 that a design change had been implasented which 08-31-82 ECCS Charging replaced the original pipe with 316 stainless steel for greater erosion resistance. Pump Inoperable
- 15. Kewaunee Service Water 305; 83-027- The l A component cooling water heat exchanger was removed from System 10-26-83 Component service to repair a leak on its service water temperature controlled bypass ilne. The leak was caused by sand erosion due to turbulence Cooling Water on the discharge ride of the throttled temperature controlled Heat Exchanger bypass valve, SW-1306A.
t6. Indian Point 2 . Residual Heat 247, 78-028 Removal Leak in elbow connection between containment isolation valves in 09-20-78 recirculation path from the RHR pump. Caused by cavitation and/or impingement erosion.
o s a Table A4.3 (Continued) BWR PLANT DOCKET NO.; REPORT NO.; DATE SYSTEM AFFECTED EVENT DESCRIPTION
- 17. Cooper Service Water Erosion in backwash line for service water pump strainer. Piping 298; 79-40 System was part of the service water pressure boundary. Caused by high 12-03-79 velocity water and solids content (3" schedule 40 at 50 psig).
- 18. Cooper Service Water Pinhole leak in service water outlet line from REC heat exchanger A.
298; 77-49 System Leak was on downstream side of heat exchan9er throttle valve (18" 09-12-77 butterfly) with portion of rubber seat missing.
- 19. Cooper Service Water Leak in bottom of the discharge expansion joint for service water 298; 77-5 System pump B. The uniroyal 20x8 expansion joint had cracked in the 01-23-77 hellows area. Joint. service is severe dueto the high silt concentration.
- 20. Dresden 2 Other TIP Machine failed to retract. Pinhole leak found on cleanup 249; 79-008 equalizing line (2-1292-2"), 2" pipe to socket weld. Erosion 05-03-79 . due to flow characteristics and possible cavitation.
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l Attachment 6 PIPE FAILURES AND PRA THE RELIABILITY OF PIPING SYSTEMS IN NUCLEAR POWER PLANTS (NPPs) HAS RECEIVE CONSIDERABLE ATTENTION BY THE STAFF. THIS SUBJECT WAS ALSO DISCUSSED IN APPENDIX III 0F WASH-140C WHICH ESTIMATED THE MEDIAN FREQUENCY OF PIPE RUPT 4 AS 10 / REACTOR YEAR. UNCERTAINTIES ASSOCIATED WITH THIS ESTIMATE ARE LARGE A REPRESENTED BY AN ERROR FACTOR OF 10 MAINLY DUE TO THE SPARSITY OF EXPERIEN DATA. DR. S. H. BUSH IN HIS OCTOBER 1977 PAPER ENTITLED " RELIABILITY OF PIPING IN LIGHT WATER REACTORS," IAEA-SM-218/11 REACHED THE CONCLUSION THAT THE FAILURE FREQUENCY OF LARGER SIZES OF NUCLEAR PIPING IS CONSIDERED TO BE IN THE RAN 6 OF 10'4-10 / REACTOR YEAR, EXCLUSIVE OF INTERGRANULAR STRESS CORROSIO 6 THE RANGE OF 10 5-10/ REACTOR YEAR WAS IDENTIFIED AS ENCOMPASSING DISRUPTIVE 6 FAILURES, AND 10 /REACTORYEARWASQUOTED AS THE FREQUENCY OF CATASTROPHIC FAILURE FOR LARGE PIPING. THEREFORE WASH-1400 LOCA FREQUENCIES INCLUDES THE CONSIDERATION OF CATASTROPHIC FAILURES. THESE FREQUENCIES ARE GENERALLY USED IN PRA STUDIES AFTER BEING UPDATED TO REFLECT PLANT SPECIFIC EXPERIENCES AS WELL AS EXPERT JUDGMENT. SURVEY OF SOME OF THE LATEST PRA STUDIES SHOWED LARGE LOCA FREQUENCIES TO BE CLOSE TO THE WASH-1400 ESTIMATES. I SURVEY OF PAST LWR PIPING FAILURE EXPERIENCE IDENTIFIED CRACKING AS THE MOST SIGNIFICANT PROBLEM IN LWR PIPING SYSTEMS. THE MAJORITY OF FAILURES OCCURRED AT WELDS OR WELO-HEAT-EFFECTED ZONES OF THE PIPING. IN THAT RESPECT THE l
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SURRY INCIDENT APPEARS TO BE UNUSUAL AND MAY BE RELATED TO EROSI WHICH IS CONSIDERED AN INSIGNIFICANT CONTRIBUTOR TO SAFETY GRAD MOST OF THE PRIMARY SYSTEMS PIPING IS STAINLESS STEEL OR STAINL WHICH IS KNOWN TO BE VIRTUALLY IMMUNE TO EROSION /AN CORROSION. EXCEPTION IS THE UNCLAD CARBON STEEL LINES IN BWRs WHERE EXISTING CONDITION CHEMISTRY POSE NINOR SUSCEPTIBILITY TO THIS PROBLEM. SPECIAL FEATURES OF SAFETY GRADE PIPING SUCH AS CONFIG PROCESS CONDITIONS, MAY INCREASE THE SUSCEPTIBILITY TO EROSION /CORRO FAILURES AND CONSEQUENTLY INFLUENCE THE FREQUENCY HOWEVER,OF TH PIPING RELIABILITY CAN BE ENHANCED BY PERIODIC INSPECTIO THE PURPOSE OF ASSESSING THE CONDITION OF THEOFPIPING. SURVEY EXISTING SAFETY GRADE PIPING CONFIGURATIONS AND EVALUATION OF ITS SU MODE OF FAILURE CAN BE USED TO ASSESS THE MAGNITUDEl FAILURE FREQUENCIES USED IN PRA STUDIES.
Attachment '7 HISTORY OF ESCALATED ENFORCEMENT ACTIONS FOR SURRY EA Action Date Subiect 73-1 $40,000 Proposed 5/15/73 Technical Specification "f olaticas
$38,000 Paid 7/12/73 including failures to (1) test in-(CPMitigated) strumentation channels, (?) conduct sampling tests, and-(3) report design changes.
75-2 $12,000 Proposed 1/18/75 Security violations involving access
$10,000 Paid 3/19/75 and inoperable alarms.
(CPMitigated) 79-08 $15,000 Proposed 8/15/79 0verexposure to an employee of Paid 10/23/79 approximately 10 rens. 80-28 $8,000 Proposed 5/28/80 Waste shipment which exceeded 00T Paid 6/20/80 dose rate limits. 81 45 Notice of 5/5/81 8 reaching nf package integrity, Violation fined by ~ South Carolina (No CP issued) 82-58 S50,000 Proposed 5/10/82 Operating with three of six high Paid 6/?/82 steam flow measurement instruments inocerable which resulted in one of three main steam _ lines being unmanitored and the loss of redundancy on a second main steam line. 82-143 $20,000 Proposed 3/24/83 Failure to meet a tech spec LCO for Paid 5/6/83 the chemical addition tank for linit 1. 83-36 $40,000 Proposed 5/9/83 Violations involving radiation pro-Paid 6/3/83 tectinn requirements and supervisinn of personnel to ensure compliance. 84-52 540,000' Proposed 7/30/84 Inadeouate program to monitor the Paid 9/7/84 service life of hydraulic snubbers. 85-123 Notice of 11/21/85 Failure to control access to the' pro-Violation tected area vehicle gate. (No CP Issued) 86-46 Notice of 4/4/86 Undetected passage of a packaged ar.d Violation assembled rifle 'into a protected (No CP Issued) area. I North Anna and Surry l 84-57 $40,000 Proposed ?/1/85 Material false statements regarding l Paid 3/4/85 the operability of reactor coolant vent system.
SPS UFSAR 14B-1 Attachment 8 Appendix 14B EFFECTS OF PIPING SYSTEM BREAKS OUTSIDE CONTAINMENT 1
45.1 INTRODUCTION
148.1.1 APPENDIX COVERAGE AND
SUMMARY
This appendix is based on Appendix D to the initial FSAR and provides the response to a Commission letter dated December 18 1972, which contained a j document entitled " General Information Required for Consideration of the Effects of a Piping System Break Outside Containment" (later revised in January 1973).
- Since Surry Units 1 and 2 are similar in design, and to avoid unnecessary repetition, the analysis within this Appendix is oriented to Unit 2. However, wherever Unit 1 is unique with respect to Unit 2, an additional analysis is made for the unique portions.
This appendix presents an analysis of the consequencs. of postulated pipe failures outside the contain=ent. In addition to the direct effects on safety resulting from the postulated break of a high-energy line, it is shown in this analysis that Surry Units 1 and 2 can be shut down and maintained in a shutdown condition. The postulated break of a pipe is shown not to negate any safety function as a result of the postulated failure. The analysis ensures that the Commission's General Design Criterion 4 is met, i.e., that all structures, systems, and components important to safety are designed to accommodate the effects of and are compatible with the environmental conditions associated with normal operation, maintenance, testing, and postulated accidents, including loss-of-coolant accidents (LOCAs). These structures, systems, and components are protected against dynamic effects, including the ef fects of missiles, pipe whipping, and discharging fluids that may result in equipment failures and from events and conditions outside the nuclear power unit.
i SPS U7SAR 14B-2 14B.I.2 APPENDIX ORGANIZATION The sectional organization of this Appendix is d e lineat .v' in Figure 14B-1. The approach used to analyze the consequences of pipe failure is to identify and locate the high-energy sources, identify and locate the safety-related targets, and determine and evaluate the physical effects. The criteria for determining pipe breaks and methods of analysis are presented in Section 14B.2. The identification and location of high-energy systems are found in Section 14B.3. The safety-ralated and shutdown equipment is identified, and the location listed in Section 14B.4. Calculation results and the evaluation of the physical effects from a pipe system break are found in Section 14B.S. The conclusions are found in Section 14B.6. l l I ( l ! l i
SPS UFSAR 14B-3 14B.2. CRITERIA FOR PIPE BREAKS AND METHODS FOR ANALYSIS 14B.2.1 GENERAL DISCUSSION High-energy systems that require analysis for the consequences of pipe breaks are identified based on the fluid in the pipe, and the pressure and temperatura during normal station operation. i In pressurized water reactors, the fluids are water, steam, and water solutions. High-pressure nonflashing gas lines are not included in this analysis. The temperatures and pressures used for determination of high-energy systems are the maximum normal operating temperatures and pressures. The type of analysis that is required ic based on the temperature and pressure conditions as shown in Figure 14B-2. The lines that are both high-temperature and high-pressure are analyzed for pipe whip and environmental J effects. The pipes that are low-pressure and high-temperature, or low-temperature and high-pressure, are postulated to crack and are analyzed for environmental effects. The analysis of these effects (environmental, pipe whip, steam jets, etc.) involves consideration of the source and the target. The source includes the postulated pipe failure and the resulting reactions of the . ! l failure. The target includes components or systems that are considered ' 3 essential in shutting down and maintaining the reactor in a safe-shutdown condition in the event of a postulated break outside containment of a pipe containing high-energy fluid, and which provide protective functions such that a loss of redundancy can be permitted but a loss of function cannot be permitted. The approach taken involved the determination of the effects of the source on the target. After the high-energy lines are identified in accordance with the above definition, the function of each line is determined. Failure of lines that do not serve a safety function do not require the plant to be shut down. The criterion to which these lines are analyzed is that all safety functions must
- -. . . - -. __= -
SPS UFSAR 14B-4 be protected. Failure of one out of two redundant components is acceptable if the safety function is not degraded. It is assumed that the plant must be shut de in to repair damage to safety equipment in accordance with the Technical Specifications. Failures in lines that serve "a safety function require the plant to be shut down and maintained in a shutdown condition. The criterion under which these lines were analyzed is that all redundant components required to operate to recover from this failure are to be protected, including all redundant equipment required to bring the plant to shutdown and to maintain the plant in the shutdown condition. l To analyze the consequences of the postulated break, the targets must be identified. Targets are identified on the various drawings within this appendix. After the high-energy break points and targets are located, the consequences of pipe whip and jet impingement are determined. The criteria and methods of analysis for determining these effects are discussed below. As a part of the analysis of each break point, it is determined that either the consequences are acceptable, or pipe whip protection and/or jet impingement protection is required. 14B.2.2 CRITERIA FOR PIPE BREAKS AND CRACKS d 14B.2.2.1 Definition of High-Energy Lines I ) Design-basis pipe breaks are postulated in piping for which the maximum operating pressure exceeds 275 psig and the maximum operating temperature I equals or exceeds 200*F. The critical crack size is taken to be one-half the pipe diameter in length (d/2) and one-half the wall thickness in width (t/2). i Pipe cracks (d/2 x t/2) are postulated in piping for which either the operating pressure exceeds 275 psig or the operating temperature equals or ] j exceeds 200*F. If both operating pressure and temperature are below these values, breaks and pracks are not postulated (Figure 14B-2) .
. . . . . . --- - . . - . ~ . _ _ . - - ..
SPS UFSAR- 14B-5 Operating temperature and pressure are defined as the maximum temperature and pressure in the piping system, during occurrences that are expected frequently or regu1.arly in the course of power operation, startup, shutdown, standby, refueling, or saintenance of the plant. Protection from pipe whip is not provided if any of the following conditions exists: i
- 1. The piping is physically separated by protective barriers or is otherwise isolated from structures, systems, or components important l co safety, or is restrained from whipping by plant design _ features such as concrete encasement.
- 2. Following a single break, the unrestrained pipe movement of either and of the broke pipe in any possible direction- about a plastic
; hinge formed at the nearest pipe whip restraint cannot impact any i structure, system, or component important to safety.
l 3. The internal energy level associated with the whipping pipe- can be ; demonstrated to be insufficient to impair the safety function of any structure, systas, or component to an unacceptable level. 4 The internal fluid energy level associated with the pipe break reaction may take into account any line restrictions (e.g., flow limiters) between the pressure source and break location, and the effects of either single-ended or double-ended flow conditions, as l l applicable. The energy level in a whipping pipe may be considered as insufficient to break an impacted pipe of equal or greater nominal
- pipe size and equal or heavier wall thickness.
j i 14B.2.2.2 Pipe Break Criteria Design-basis break locations are postulated in accordance with the following pipe whip protection criteria. However, where pipes carrying high-energy fluids are routed in the vicinity of structures and systems necessary for safe shutdown of the nuclear plant, supplemental protection of these
.-. _ - -. - . ~ . _ . -
a SPS UFSAR 14B-6 structures and systems is provided to cope with the environmental effects (including effects of jet impingement) of a single postulated open crack at the most adverse location with regard to these essential structures and systems, the length of the crack being chosen not to exceed the critical crack size.
- 1. ASME Section III, Class 1 piping breaks are postulated to occur at certain locations in each piping run or branch run. Piping is defined as a pressure-retaining component consisting of straight or curved pipe and pipe fittings (e.g., elbows, tees, and reducers). A piping run is defined as piping that interconnects components such as l
pressure vessels, pumps, and rigidly fixed valves that may act to restrain pipe movements beyond the restraint required for design thermal displaceaant. A branch run differs from a piping run only in that it originates at a piping intersection, as a branch of the main pipe run. The postulated locations of piping breaks are
- a. The terminal ends,
- b. Any intermediate locations between terminal ends where the primary-plus-secondary stress intensities S (circumferential or longitudinal) derived on an elastically calculated basis under the loadings associated with one-half of the safe shutdown earthquake and operational plant conditions exceed 2.0 S, for ferritic steel and 2.4 S ,for austenitic steel.
Operational plant conditions include normal reactor operation, upset conditions (anticipated operational occurrences), and testing conditions. S, is the design stress intensity as specified in Section III of the ASME Code.
- c. Any intermediate locations between terminal ends where the cumulative usage factor (U) derived from the piping fatigue rr.-,- --,. , -- , . - .-- ~ - . . . , , , , - - -
~
SPS UFSAR 14B-7 analysis and based on all normal, upset, and testing plant conditions exceeds 0.1. U is the cumlative usage factor as specified in Section III of the ASME Code. I
, d. At intermediate locations in addition to those determined by 1.a and 1.b above, selected on a reasonable basis as necessary to ; provide protection. As a minimum, there are two intermediate l locations for each piping run or branch run.
- 2. ASME Section III, Class 2 and 3, and ANSI-B31.1.0 (1967 Edition) piping breaks are postulated to occur at the following locations in each piping run or branch run: :
4
- a. The terminal ends.
k
- b. Any intermediate locations between terminal ends where either the circumferential or longitudinal stresses derived on an !
elastically calculated basis under the loadings associated with seismic events and opers,tional plant conditions exceed f 0.8 (Sh+S), A r the expansion stresses exceed 0.8 S
- A i
I S is the stress calculated by the rules of NC-3600 and ND-3600 h I for Class 2 and 3 components, respectively, of the ASME Code, Sectica III, Winter 1972 Addenda. S A is the all wable stress f range for expansion etress calculated by the rules of NC-3600 cf { the ASME Code, Section III-1971, or the USA Standard Code for ; Pressure Piping, ANSI B31.1.0-1967. !
- c. Intermediate locations in addition to those determined by 2.b !
i above selected on a reasonable basis as necessary to provide ; protection. As a minimum, there are two intermediate locations for each piping run or branch run, selected on the. basis of l h maximum combined primary and secondary stress. For nonseismic : e
.- -, . . . , - . - . - - .- - . . - . . ,, . - - - , . - - . - - .~. - - - , - .-
SPS UFSAR 14B-8 piping systems, the intermediate locations are selected on the basis of maximum thermal stress. l
- 3. For systems meeting maximum operating conditions of either pressures greater than 275 psig or temperatures greater than 200*F, piping cracks were postulated at the most adverse points with respect to targets.
14B.2.2.3 Pipe Break Orientation l The criteria used to determine the pipe break orientation at the break locations as specified in Section 14B.2.2.2 above are equivalent to the . following:
- 1. Longitudinal breaks in piping runs and branch runs, 4-in. nominal pipe size and larger, and/or I. Circumferential breaks in piping runs and branch runs exceeding 1-in.
nominal pipe size. A tee-joint that connects a branch run and main piping is not necessarily a break location for the main piping if it does not qualify as a high-stress and/or high cumulative usage factor location in this main piping run; however, at its velding junction to the branch run, which is a terminal point of the branch run, a break location has to be postulated. If one of the computed stresses and/or cumulative usage factors of the
- various points of an elbow (tee or reducer) is high enough to be qualified as an intermediate break location, and the other(s) varies within 210% of it, all these points are considered as a single break location.
i Longitudinal breaks are parallel to the pipe axis and oriented at any point around the pipe circumference. The break area is equal to the effective cross-sectional flow area upstream of the break location. Dynamic forces resulting from such breaks are assumed to cause lateral pipe movements in the direction normal to the pipe ends. _ . _ . _ . . _ _ . . _._ ___ . ~ . . _ . _ _ _ _ - - _ . _ - _ _ _ _ _ . _, .._.
SPS UFSAR 14B-9 Circumferential breaks are perpendicular to the pipe axis, and the break area is equivalent to the internal cross-sectional area of the broken pipe. The, dynamic (blowdown) forces resulting from a circumferential break act to separate the piping axially; there is no transverse force during a circumferential break event. 14B.2.3 METHODS OF ANALYSIS AND GENERAL RESULTS 14B.2.3.1 Whipping Pipes-and Interactions with Concrete Walls The velocity of a whipping pipe is dependent on
- 1. The blowdown forces. -
- 2. The pipe, break geometry, and size.
- 3. The distance traveled.
A typical mathematical model is shown in Figure 14B-3. At time zero, before the break occurs, the system is in a state of stress due to internal pressure, but these pressure forces are in static equilibrium with the axial loads in the pipe. As the circumferential crack propagates, tha load-carrying metal area decreases, so a force imbalance results (Figure 14B-3, Part A). The axial load at the break is assumed to drop linearly to zero in 1 msec. Af ter the break, the forces exerted on the pipe by the fluid are determined by time-dependent pressure and momentum effects. The combined behavior of these two terms is equivalent to a pressure drop to 0.7 of the initial value af ter the passage of the decompression wave. A wave velocity, assumed to be 1600 fps, results in the forcing functions as shown in Figure 14B-3, Part B. The results of the above analysis indicate that, during most of the pipe displacement, the applied forces are only 0.7 of the initial forces and that approximately 30% of the energy is dissipated by plastic deformation in the pipe before impact. Due to strain hardening and strain rate effects, a j distinct hinge may not form, but rather an extended region of large plastic deformation occurs. The plastic hinge lengths are also determined by this { analysis (Table 14B-1) for the initial condition of 1050 psi. c i
l SPS UFSAR 14B-10 Effects from whipping pipes on concrete walls were analyzed as follows. The local crushing stiffness of the pipe elbow may be readily determined in the elastic range, but only with difficulty once plastic deformation begins. The case of the actual elliptical contact area between the pipe elbow and wall has been considered, as well as an idealized case in which the portion of the elbow near the contact area is modeled as an equivalent sphere. PISCES computer runs indicate that once crushing (or denting) is initiated, a flat area forms on the elbow. (Without internal pressure, bounce-back or " oil canning" occurs.) The forces transmitted by the wall to the pipe occur mainly at the circumference of the contact area. Thus, analyses presented in the literature for the stiffness of a sphere intersected by a pipe with normal loading may be used to get an approximate stiffness.' , The crushing resistance of the elbow is modeled as a spring (connected to ground) in the mathematical model. This is acceptable, since the great inertia of the wall prevents any appreciable movement prior to the moment that 4 the peak forces occur. The peak force in this spring is the maximum load transmitted to the wall during the impact. The effects of the continuing blowdown forces and the inertia of the pipe away from the impact point are automatically included in the analysis. Typical examples of these peak forces as a function of impact velocity are plotted in Figure 14B-4. I Since the load is applied to the concrete wall in a short time compared to the natural period of a concrete wall, the application of a dynamic load
- factor of two is required when using static design equations. The madel used for punch shear is shown in Figure 14B-5. The equation used for punching 5
shear 1, , , ,g, y,71 g, i F=4Vf d2r(r+h where F = applied force f = compressive strength of concrete d = wall thickness r = radius of contact area
SPS UFSAR 14B-11 In all cases, wall thicknesses employed in normal plant construction are sufficient to stop whipping pipes. 145.2.3.2 Fluid Jets and Interactions with Reinforced-Concrete Walls 145.2.3.2.1 Assumptions
- 1. The pipe break location is very close to the pressure reservoir (s).
The pressure drop in the pipe due to flow friction is negligible.
~
- 2. The total jet force remains constant throughout its traveling distance; i.e., the friction force between the jet stream and ambient air is negligible. -
- 3. The jet stream is totally intercepted by the concrete wall.
4 The jet impingement is a suddenly applied load to the concrete wall. 14B.2.3.2.2 Jet Force The maximum value of the initial jet pressure from a pipe break can be expressed as Py =CPy l where P, = fluid pressure inside pipe Cy = jet coef ficient Cy = 1.26 for steam Cy = 2.0 for subcoolid nonflashing water t (If the pressure drop due to friction is taken into consideration, the values of Cycan be reduced.) l
1, L SPS UFSAR 14B-12 The total jet force is then Fy = PA y where A=pipebreakarea={D D = inside diameter of pipe : As the jet stream progresses away from the pipe break area, the width of the jet increases with the axial distance.- The angle of divergence is assumed to be 20 degrees.0 ' 14B.2.3.2.3 Punch Shear Failure of Concrete Wall The punch shear failure mechanism of a concrete wall due to jet impingement from a pipe break is shown in Figure 14B-6. The failure of a , concrete wall is a diagonal cracking along the surface of a truncated cone or i pyramid around the jet impingement area. The area of the shearing surface is: Ag= wD,W where D W
=D + 2L can 10' + W P
W = wall thickness i. L = distance between wall and pipe break location W Without shear reinforcement, the shear strength is (CI= 4 Vf'c where f' = specified compressive strength of concrete
SPS UFSAR 14B-13 The total shear resistance of the reinforced concrete wall is R=A3 (23 where f= ccpacity reduction factor = 0.85 for shear The total jet impingement load seen by the wall is 1 F =C T D J 4 where ~ CD = dynamic load factor = 2.0 for suddenly applied load If R is greater than or equal to F , there T will be no punch shear failure. Curves relating dimensionless wall thickness (X = W/D ) and dimensionless distance (Y = L/D ) are shown in Figures 14B-7,14B-8, and 14B-9 for steam and water lines, respectively. The specified concrete compressive strength, f',, is assumed to be 3000 psi. These curves are extremely conservative. A more realistic analysis to determine the effective jet impingement force requires additional parameters, l such as pipe lengths from sources, elbows, and flow restrictors and fluid characteristics. A conservative approach was used in the analysis -for this appendix. a 4 14B.2.3.2.4 Fluid Jets 3rd Interaction with Steel Plates For a fluid jet issuing from a crack (one-half the pipe diameter times one-half the pipe thickness) in a pipe wall, the magnitude of the jet force is small because the break area is small. It can be shown that either a 1-ft reinforced-concrete wall or a 1/8-in. steel plate being hit by a jet from close distance from a crack in a 32-in., 2300-psi water line will not
SPS UFSAR 14B-14 experience a local failure by punch shear. ' Therefore, it is not necessary to analyze the local punch shear failure of concrete walls or steel plates due to fluid jets from cracks in pipe walls. 14B.2.3.2.5 Fluid Jet Range Any safety-related structure, piping component, and equipment located in the fluid jet traveling path is considered susceptible to jet impingement. As the jet propagates away from the pipe break area, it expands at a diverging nngle. Therefore, the jet intensity decreases with distance from the break 1; cation to the target, whereas the total. jet force is assumed to remain cinacant. , 14B.2.5.2 Pressure and Environment The pressure buildup from the postulated break of a high-energy pipe in a compartment or building is calculated using the computer program CUPAT. 14B.2.3.3.1 Introduction CUPAT is a computer program used to calculate pressure and temperature transients in various nuclear power plant compartments resulting from a postulated high-energy pipe break. The output is used mainly for design purposes in establishing the peak pressure differeettals across the compartment walls. This program was derived from the LOCTIC computer program, which is used to calculate pressure and temperature transients for the primary containment. There are two major. differences between LOCTIC and CUPAT: l
- 1. LOCTIC includes the effects of heat transfer by providing subroutines ,
to handle sources and sinks. CUPAT assumes a volume that receives I heat and mass from a broken piping scurce and discharges heat and mass to its surroundings, but aside from that there are no other heat sources or sinks (adiabatic assucption).
SPS UFSAR 14B-15 l
- 2. CUPAT allows for flow out of the volume considered as well as flow l in. There is no provision in LOCTIC for mass outflow frca the containment volume.
In order to calculate the transients within a compartment. CUPAT numerically solves finite difference equations defining heat and mass flows into and out of the compartment. The program uses the.same basic assumptions as those used in LOCTIC, namely:
- 1. Mass and energy added or removed during each small time step are based on rates determined at the start of the time step; i.e., during any time interval, the thermodynamic state is assumed to be steady and the response of the flow out of the volume to changes in the thermodynamic state is instantaneous (quasi-steady-state assumption).
- 2. The atmosphere in the compartment mixes instantaneously and
, homogeneously, i.e. , at each point in time, the atmosphere is in a state of thermodynamic equilibrium. A detailed description of the approach to the rroblem is presented below. The calculational approach used in CUPAT is summarized in the block diagram shown in Figure 14B-10. Blocks (1) through (5) in the figure are traversed once for each time step. 14B.2.3.3.2 Calculational Approach 14B.2.3.3.2.1 Quasi-Steady-State Assumption. The problem of analyzing'
, the transient effects of a LOCA is very complex. The thermodynamic state of the compartment atmosphere is continuously changing. This state depends on the mass and energy flows into and out of the co=partment. The flows, in turn, are dependent on the thermodynamic state within the compartment. In order to solve such a problem numerically, some simplifying assumptions must be made.
- SPS UFSAR 14B-16 First, the system is defined as the compartment atmosphere at any given i time. This includes any air, steam, and water droplets present, but not the walls, equipment, or internal structure of the compartment itself. If the time step is small enough, the net rate of mass and energy addition to the system will not vary appreciably during the time step. Thus, the flow rates are calculated assuming that the thermodynamic state does not change during the time step, and this assumption eliminates the need to iterate and converge on the inflow and outflow for each time step. This approach is used in LOCTIC (which also includes heat flows) for the primary containment transients, and is also used in CUPAT.
145.2.3.3.2.2 Mass and Energy Flow Rates into Compartment. The mass and energy flow rates into the compartment are supplied as input to the program in tabulated form. These blowdown rates into the compartment may be obtained from the output of a LOCTIC or LOCTVS' computer run or from the assumption of Moody flow with a known pressure blowdown. The flow of fluid from a piping break is relatively insensitive to the back pressure in the compartment, since the pressure in the high-energy line is above 275 psig. Thus, the mass and energy inflow data specified as input are close to the actual flow, but are conservatively high. 14B.2.3.3.2.3 Calculation of the Thermodynamic State of the Compartment. In each time step of the numerical calculation, equilibrium temperature and pressure in the compartment are determined . based on new values of mass and I internal energy. Properties of water are obtained from the steam tables. The l detailed procedure by which the pressure and . temperature of the compartment j atmosphere are found from the updated values of mass and internal energy is described below. Initially the equilibrium state is considered to be a two-phase mixture l of air, saturated steam, and saturated liquid. However, if the energy content l for the given mass is greater than that required for saturation, a single-phase mixture of air and superheated steam is determined. I I I
.. , . , , .. - - . . .- . - . . - - - -- - - , _ - . . . _ . . . ~ . . . . . . - .
\
SPS UFSAR 14B-17 To arrive at the correct equilibrium conditions, a curve of internal - 1 energy of the air, steam, and liquid in the volume versus temperature is generated.. The basis for the curve is that the. mass of water present in the compartment is at a saturated equilibrium state for each temperature, and the total internal energy of the system at this temperature is calculated accordingly. The actual total internal energy is _ then used to enter this curve and find the true temperature. The total pressure is then determined by adding the vapor pressure to the air partial pressure, which is calculated by the ideal gas flow at this temperature. In the case where the contents form a superheated vapor, the superheat section of the steam tables is used to match the specific volume of the steam
~
and the internal energy to find the equilibrium temperature and pressure. 14B.2.3.3.2.4 Calculation of Flow Rate Out of Compartment. The CUPAT computer program uses the LOCTVS vent flow to determine the flow rate out of the compartment. A homogeneous flow model is used in LOCTVS to calculate flow out of the drywell through the vents of a pressure suppression containment. Although flow through the vents is characterized by slip between the gaseous and liquid phases, a homogeneous model yields lower flow rates and is used for conservatism. The ability of the vent flow model to conservatively predict flow through the vents has been checked against the Bodega and Humboldt Bay pressure suppression tests. i ! 14B.2.4 PROTECTION AGAINST PIPE WHIP l I A combination of three basic approaches was used for the protection of I targets from whipping pipes These approaches include
- 1. Separation of redundant features by distance or location so that at least one feature remains intact.
- 2. The incorporation of many redundant features into the design of the safety-related syste=s for assurance of reliability.
I i
-__ __ _ _ _ . , _ . . - ~ . _ _ . ., _ _
SPS UFSAR 14B-18
- 3. For the largest main steam and feedwater lines, an extensive -
inspection program was devised for each postulated break point. By ) means of ultrasonic and/or radiographic testing in addition to a visual surveillance program, defect propagation can be detected at any early stage and repaired accordingly, thereby ensuring the integrity of each postulated break point. , 14B.2.5 ANALYSIS OF SEISMIC CATEGORY I STRUCTURES ~ Analysis of Seismic Category I structures for loads other than pipe break in the main steam valve house is given in Section 15.2. 1
SPS UFSAR 14B-19 14B.3 HIGH-ENERGY SYSTDN 14B.3.1 SYSTEM IDENTIFICATION The following systems contain high-energy lines, as defined in Section 14B.2:
- 1. Main steam.
- 2. Feedwater.
- 3. High-pressure heater drains and vents.
- 4. Moisture separator drains.
- 5. Auxiliary steam.
- 6. Condensate.
- 7. Low-pressure heater drains and vents.
- 8. Boron recovery.
- 9. Liquid waste.
- 10. Chemical volume and control.
- 11. Safety inj ection.
- 12. Steam-generator blowdown.
- 13. Extraction steam.
- 14. Sample.
The high-energy lines in these systems were reviewed in conjunction with safety-related and safe-shutdown equipment (Ta' ole 15.2-1) by means of a detailed drawing review and onsite inspection. Those portions of the high-energy lines in proximity to the safety-related and safe-shutdown equipment have been identified. These portions of the high-energy lines are defined as sources and are presented in Table 14B-2. The safety-related equipment and plant shutdown equipment in proximity to these sources (identified as targets) are listed in Section 14B.4.1. Table 14B-2 presents a listing of the high-energy line sources with their maximum operating conditions, locations, and seismic classifications. These lines were individually analyzed for adverse effects on targets. Sources such ;
SPS UFSAR 14B-20 as smaller lines located in the target areas were not individually analyzed, since the sources listed were the worst cases for their respective areas. 14B.3.2 QUALITY ASSURANCE AND INSPECTION Piping presently installed was designed and fabricated in accordance with the criteria described in Section 1.4, " Compliance with Criteria." 14B.3.3 DETECTION OF FAILURES As described in Section 7.2 and delineated in Table 7.2-1, reliable and redundant systems have been incorporated into the present plant design for , detection of failures in the main steam and feedwater systems. As described in Section 11.3.4, the area radiation monitoring system is designed to alarm when radiation levels in their associated areas are slightly above background. This system detects pipe failures in systems containing radioactive fluids. d r
SPS UFSAR- 14B-21 14B.4 PLANT SHUTDOWN AND SAFETY-RELATED EQUIPMENT 14B.
4.1 INTRODUCTION
Table 14B-3 lists the systems and major equipment locations that constitute postulated targets among the plant shutdown and safety-related equipment. Associated cables and controls are considered along with this equipment. 14B.4.2 EMERGENCY PROCEDURES Main steam or feedwater breaks outside the containment are discussed in Sections 14.2.11 and 14.3.2. Subsequent to a main steam or feedwater break, assuming offsite power is unavailable, plant shutdown is achieved by actuation of the emergency core cooling system and removal of core decay and sensible heat via steam release through the atmospheric steam dusip valves, and maintenance of steam-generator water inventories by means of the auxiliary feedwater system. Section 9.3 details the operation of the residual heat removal system i i necessary for long-tera cooling and cold shutdown of the reactor. l Shutdown equipment is normally controlled from the control room. l However, in the event that evacuation of the control room is necessary, , shutdown equipment can be controlled from an auxiliary shutdown panel. l l 14B.4.3 RELATIONSHIP OF HIGH-ENERGY LINES TO SAFE-SHUTDOWN AND SAFETY-RELATED EQUIPMENT l Figures 14B-11 through 14B-19 show the high-energy systems and the safe-shutdown and safety-related equipment. 4 1 1 l i l _ _ _ _ - - _ _ _ _ _ _ _
SPS UFSAR 14B-23 ! 1 i 14B.5 EFFECTS OF PIPE BREAKS AND CRACKS 14B.5.1 . MAIN STEAM 14B.5.1.1 Break Locations Break locations were postulated in the main steam lines from the containment to the turbine building in accordance with Section 14B.2.2. For the main steam line. 0.8 of the allovable thermal stress is 22,500 psi, and 0.8 of the allowable combined primary and secondary stress is 0.8 (S g +S h " 37,500 psi. Since 0.8 of the allowable stresses was not exceeded, the two intermediate locations between terminal points were selected on the basis of maximum primary-plus-secondary stress. Piping downstream of the manifold common to the three steam lines was not analyzed seismically. For this piping, pipe breaks were assumed; however, because of separation, no further analysis is required. At all break points, both circumferential and longitudinal breaks were postulated to occur. The break points are listed in Table 14B-4 along with the thermal and combined stress levels. The break locations are shown on Figures 14B-11 and 14B-12. Cracks were selected in the vicinity of all targets. 14B.5.1.2 Separation The steam lines in the turbine building were analyzed, and satisfactory separation was found to exist between steam lines and any safety-relatad features. The control room and energency diesel-generator rooms are separated by sufficient distance fron all high-energy lines, so that whipping pipes or 1 steam jets will not adversely affect their respective functions. These l I conclusions were based on results given in Section 14B.2.3. ) I i i
SPS UFSAR 14B-24 The auxiliary feedwater modification described in Section 14B.S.I.7 provides a system widely separated from postulated breaks. 14B.S.I.3 Pipe Whip An extensive nondestructive testing program, as described in Section 14B.5.1.6, is used to preclude breaks, thereby making pipe whip a noncredible incident. Since the guideline referenced in Section 143.1.1 requires a postulated failure, each postulated main steam line break has been evaluated fer the effects of pipe whip. Because feedwater supply to the steam generators is the . ultimate requirement for a safe shutdown, the evaluation -was based on maintaining the feedwater function. The results of this investigation are shown in Table 148-5. These results were based on the plastic hinge lengths established in Section 14B.2.3.1 and on discussions with the turbine-driven auxiliary feedwater pump manuf acturer indicating that the pump can operate in a steam environment. Since loss of offsite power must be assumed, and the turbine drives are not environmentally qualified by tests, additional assurance that feedwater will be maintained is obtained by the auxiliary feed cross-connect system. As shown in Table 14B-5, there are no effects on the auxiliary feed cross-connect system, considering all postulated breaks. The auxiliary feed cross connect was a modification to the initial plant design and is discussed in Section 14B.5.1.7. 14B.5.1.4 Fluid Jet Effects Jet impingement loadings on the walls, valves, and pipes inside the main steam valve house have been calculated. The time-history results of jet force from a pipe break at the most adverse location in the steam line within the valve house is calculated as follows (Section 14B.2.3.2): F(c) = 1.0 P,A for t 5 0.020 see F(c) = 0.7 P,A for 0.020 see i t 10.113
'SPS tiFSAR 14B-25 F(t) = 0.19 P,A for t > 0.113 see The initial jet force on the walls was calculated as Fo =KP Ao where i i K = initial thrust coefficient = 1.0 P, = hot standby pressure = 1005 psig A = flow area = 616 in.
F = 619 kips For the longitudinal breaks, the break size was taken as 60 x 10.3 in. .i with the jet diverging at a 20-degree inclusive angle. The impingement areas, jet pressures, and loads corresponding to each of the postulated breaks are
. indicated in Table 14B-6.
Local damage to the walls and floors was checked based on Section 14B.2.3.2. The conservative calculation, which assumes a dynamic factor of two and no energy loss, indicates that the floor at elevation 27 ft 6 in. is subject to some local damage from jet impingement. However, the containment, the walls, and the roof withstand the effects of jet impingement with no punch shear damage. For breaks of the main steam lines, jet impingement loads on the valves were calculated. The maximum normal force on the valves is given by i F, = C Pt At cos a/1000 (kips) where l 1 l C = shape factor for flow around the valve, cylinder. C = 0.6 Pg = initf 21 jet pressure at the target (psi) Ag = impingement area (in. ) a = incident angle
i i SPS UFSAR 14B-26 The maximum normal jet forces on the valves are listed in Table 14B-7. It should be noted that these loads drop instantaneously t2 a fraction of the levels recorded. Available calculations indicate.that the nonreturn valve will continue to function as a check valve, preventing blowdown of the undamaged loops. Calculations indicate that jet impingement will not break a main steam trip valve housing, but can cause the valve to fail open. However, with the nonreturn valve operable, a broken line could still be isolated, so that only one steam generator would blow down. 145.5.1.5 Pressure and Environment ~ The main steam valve house, the containment spray pump room, and the , reactor trip switchgear room, as shown in Figures 145-11 and 14B-12, are the i only target areas that can be affected by steam following a postulated break or a crack in a main steam line, as discussed in the following sections. As shown on Figure 14B-11, the reactor trip switchgear room is far removed from the source lines; therefore, the probability of having a steam l environment within the room is extremely remote. With the existence of the nondestructive testing program, as described in Section 14B.5.1.6, only smaller steam-line breaks need to be considered for i
- pressure effects on the main steam valve house. The pressure buildup within the valve house, following a smaller steam-line break, is negligible.
In order to comply with the criteria, as referenced in Section 14B.I.1, the pressure in the main steam valve house has been calculated for the largest steam-line break. Frictionless Moody flow and the CUPAT computer program, as described in Section 14B.2.3.3, were used in these calculations. The results I i are shown in Figure 14B-20. ' l i The main steam valve house contains many targets, as shown in Table 14B-3. As detailed below, all the targets either fail in the safe l 1 l ? I l
l l SPS UFSAR 14B-27 position, operate mechanically, or have backup features outside the valve house:
- 1. Targets that fail in the safe position.
- a. Main steam trip valves (close),
- b. Auxiliary fee pump steam isolation valva (open).
- 2. Targets that operate mechanically,
- a. Feedwater isolation check valves.
- b. Main steam nonreturn valves.
- c. Main steam safety valves.
- d. Turbine driver for auxiliary feed pump.
- 3. Targets that have backup features outside the valve house.
Pressure transmitters for steam-line break input to the cafety injection system. Backup for the input is high steam-line flow indication from inside the containment area and low coolant T,y . Furthermore, all electrical cables considered as targets are the same as the cables used inside the containment. Since this cable has been qualified by test for post-design-basis-accident conditions inside the containment, the cabling is not subject to coc: mon mode environmental failure. All transmitters considered as targecs are designed with NEMA-4 enclosures and for ambient temperatures of 212*F. The blowdown rates used to obtain the above results were based on blowdown of one steam generator, following the postulated steam-line break. The blowdown of only one steam generator can be justified by taking no credf + for the main steam trip valves, but taking credit for the nonreturn valve (NKV-201A, B, C for Unit 2) in the affected steam line. Credit for the nonreturn valve is justified as follows:
- 1. As described in Section 14B.S.I.4, jet impingement will not affect the intended performance of this valve.
l SPS DTSAR 14B-28 I i
- 2. There is no instrumentation 'or electrical component required for 1 operation of the valves. The nonreturn valves require only reverse steam flow for their intended operation.
- 3. In the worst case, where blowdown is the greatest following the postulated steam-line break, the steam system is in the hot standby condition. Blowdown is greatest for this case, since the steam-line pressures are at a maximum. In this condition, there is little or no steam flow to hold the valve disk in an open position; therefore, the valve is performing its required function even before the postulated failure. In all cases, when the system pressure is high, with respect to the pressure at 100% power, the flow rates are low and the valve is in a nearly closed position before the postulated incident occurs.
4 14B.5.1.6 Inspection Program for Large Steam Lines An extensive nondestructive testing program is provided for the main steam postulated break points in the main steam valve house. These points, a total of 12 for each unit, are shown in Figure 14B-11. 14B.S.I.6.1 Procedures ' A program of periodic examination exceeding the requirements of ASME Section II, Winter Addenda 1972, as instituted by Regulatory Guide 1.51, is provided as follows:
- 1. A baseline examination was performed including 100% coverage of all
, subject points.
- 2. Inservice examinations were perforned including 100% coverage of all subject points for the iriitial 3 years of the 10-year inspection interval ac defined by ASME Section XI.
- 3. Examinations were perforced including 100% coverage of all subject points for two subsequent inservice examinations.
i
SPS UFSAR 14B I i
- 4. An examination will be performed including 100% c. overage of all !
l subject points at the completion of the 10-year inspection interval during a refueling outage. 4
- 5. Upon successful completion of the 10-year program described above, further examinations will be in accordance with the ASME Section XI requirements.
- 6. Repairs are made as required. Upon completion of any repairs, the program, as described above, will be reinstated for the repaired postulated break point.
~
In addition to the above testing program, a visual inspection of the surface of the insulation at the main steam break point locations in question is performed weekly for detection of leaks. If a leak is dstected, it is immediately investigated and repaired if the leakage is caused by a ! through-wall crack. 14B.5.1.6.2 Metheds The ultrasonic test procedures include the examination of the postulated break points and heat-affected zones using both straight besm and angle beam techniques. A review is made on a case-by-case basis to establish the specific test requirements for each veld. Consideration of weld thickness, geometry, material, and curvature parameters results in establishing the appropriate probe sizes, optimum beam angles, and frequencies for test reliability and repeatability. Where possible, two angle beam directions are used for evaluating reflectors and obtaining characterization data. Test sensitivity is in accordance with ASME Section III, Appendix IX, which defines reference calibration block requirements. 14B.5.1.6.3 Basis for the Inspection Program As shown in a PVRC report, toughness of nuclear power plant piping materials is high enough to prevent brittle fracture at operating conditions. This conclusion can be supported by fracture mechanics calculations.
k SPS UFSAR 148-30 4 t d Furthermore, from the following fracture mechanics techniques and I calculations, the critical size of surface and internal flaws far exceeds the j thickness of the piping material. Consequently, a surface or an internal flaw will extend through the wall thickness and . form a suberitical through-wall crack, which will leak before it reaches its critical size. The main steam line material is SA155, grade CMS 75 Class 1, outside
~
j diameter 30 in., wall thickness 1 in. Place material for piping is SA299. Fittings are SA234 WP, Grade A 299.
, 148.5.1.6.4 Fracture Mechanics I
J The application of fracture mechanics techniques allows prediction of the critical flaw size that can cause fast or unstable fracture in a stressed structure. f When the critical flaw size is established for a nominal stress level, it
. is possible to decide the acceptable defect size. One of the, criteria is the leak-before-fracture criterion, which requires that the defect will propagate slowly through the wall of the pipe and that the pipe will leak before the
- crack is large enough to trigger the fast fracture.
j Fabricated structures usually contain several types of defects, including f surface flaws, internal flaws, and through-the-thickness cracks. The critical flaw size will be calculated for each of these flaws using fracture mechanics relationships. These formulas were used in two recently published papers ' treating similar problems. As emphasized in the PVRC Recommendations on Toughness Requirements for Ferritic Materials, the pipe wall section is usually not thick enough to support plane strain fracture propagation, which t can be properly analyzed by the fracture mechanics methods. In other words, the load limits and critical flaw size calculated using fracture mechanics will in general be more conservative for pipe than for the thick section l
- structures where the plane stress conditions can exist. Fracture will occur when the value of the stress intensity factor Kg reaches the critical value
! K g. The critical flaw size is related to the K in several different IC ! formulas depending on geometry of structures, flaws, shape, and environmental 4
SPS CTSAR 14B-31 factors. In this work, the following assumptions were made about ' factors affecting the relation between the K and the critical flaw size: IC
-1. Material properties (toughness and strength) ' of the weld metal and the heat-affected zone in the longitudinal and circumferential veldsents are the same as in the base material.-
l' '
- 2. The lowest and the highest temperatures in the main steam line are l 510*F and 547'F. The lowest and th2 highest temperatures in the feedwater line are 438'F and 450*F. However, only the lowest j temperatures are used in calculations of fracture toughness because 4
they give more conservative values for critical crack size. 4 j 3. Because of uncertainty involved in evaluating the possible stress I state Irwin's suggestion was accepted that the membrane stress is equal to the yield strength. For SA106B pipes, Class i data are j given in Section III. For SA155 (plate SA299) material, the elevated l temperatura yield strength was not given in Section III, Class 2, and the allowable design stress data for Class I were used to get the yield stress.
; 4. The stress intensity factor of 300,000 psiG. was used for SA1068 pipe. In this work, a lower value of 200,000 psi 6. was accepted, which would correspond to the reference stress intensity factor K IR i at the temperature NDT + 180*F. The lowest temperature for SA1068 pipe is 438'F, and for SA155 pipe, 510*F, which means that the NDT
- temperature in the first case would be 438-180 = 258'F, and in the l second case, 510-180 = 330*F. This is of course a very conservative assumption, because the NDT temperature for these materials is below ll i
, room temperature. 14B.5.1.6.4.1 Internal Flaw. The internal flaw is an ellipsoid, as j shown in Figure 14B-21, Part A. The flaw is located in the center of the pipe
- wall. The flaw can be axial (major axis parallel to the pipe axis) or
,\ circumferential (major axis perpendicular to the pipe axis). - A further l assumption is that the flaw is small compared to the pipe radius. Thus the j curvature effect can be neglected and the pipe can be approximated with an 1
,_ ~ , _ _ . . . . ._ . . . , . . _ . . _ . _ . _ . , . . , . . _ . . _ _ _ _ , . _ , . ~ . . _ - . . . _ _ , , . _ . _ _ _ . . . _ . , . _ _ . _ _ _ . . . _ _
SPS UFSAR 143-32 l infinite plate under uniform applied stress. The stress intensity factor K 7 for this model is given " 'as
=
2 a 2 a(wa) K 7 sin # + b7 cos # - where a = applied stress
# = angle at which the stress intensity is calculated 4 = the following elliptical integral:
~
*/ 2 -
2 2 1/2 b -a ,f ,26 1- de 4 =J - b 2 o At the tip of the major axis, # = 0, while at the tip of the minor axis,
- = "2-If it is assumed that the major axis of the ellipsoid is twice as long as the minor axis, the equation for K becomes 7
K IC " * # (** cr It has been shown that, for an elongated crack (bna), the critical stress intensity factor is given by K IC = 1.2a(racr) Substituting the values for the stress intensity f actor and applied stress (yield strength at the te=perature) in the first equation for K IC results in the following: 2 ac , (Critical Material Temperat2re, 'F Flaw Size), in. SA106B 400 42.0 SA155 500 46.5
SPS LTSAR 14B-33 Substituting the values for the stress intensity factor and applied stress in the second equation for K IC results in the following: 2a (Critical Material Tem 9erature, 'F Flaw Size), in. SA1063 400 19.6 SA155 500 22.8 As can be seen, all critical flaw size values are much greater than the wall thickness, which means that the flaws would extend through the wall without becoming critical. In other words, the internal flav vill become a through-the-thickness crack and will leak. 148.5.1.6.4.2 Surface Flaw. The surface flaw is a semi-ellipsoid, as shown in Figure 14B-21, Part B. The flaw can be axial or circumferential, as in the previous case. Again the curvature effect is neglected, and the stress intensity factor is given as KIC " l'12 (**cr) ac , (Critical Material Temperature, 'F Flaw Size), in. , SA1065 400 11.3 SA155 500 13.2 As in the case of the internal flaw, the surface flaw will penetrate the pipe wall without becoming critical. 14B.5.1.6.4.3 Axial Through-Wall Crack. The simplest formula for axial through-wall cracks is obtained when the pipe is assumed to be infinite plate; that is, the diameter is much greater than the thickness. The critical crack size for such a simple case is K-IC " # (* cr)
SPS ESAR 14B- 34 where 2b r is the critical crack length. . The p oetry is shewn in Figure 14B-21, Part C. When the pipe diameter decumses, corrections are necessary. As a result of tests at Battelle Memorid Institute on SA106B piping, the critical size of the axial through-wall anck is given as 1 U2 b,= e lt 1 -1 },
! l where b = critical half-length r
e* = flaw stress . 4 R = average pipe radius t = thickness 2t,,(Critical Material Temperature, 'F Equation Fier Size), in. SA106B 400 K 28J IC SA106B 400 b 5.5(14.4-in. o.d. Schedule 80) SA106B 400 7.5 (18-in. .o.d. Schedule 100) b, SA155 500 K 33J IC SA155 500 b,, 9.5 Flow stress data were not available for SA155 pising. The strength of this material is higher tan the strength of SA106B satel. Consequently its flow stress must be steater than the flow stress of SA106B steel. To calculate b ,, the flow stress value used was based as the ratio of ultimate tensile strength of SA106B material to SA155 material. 14B.5.1.6.4.4 Circumferential Through-Wall Craak It is shown that the critical length of a circumferential through-wallerack is greater than the critical length of an axial crack. 14B.5.1.6.4.5 Flaw Growth. Under the influence af cyclic loads, small defects can grow to critical size. It has been sham that an empirical expression accurately describes the flaw growth: h=C(AK)*
1 SPS UFSAR 14B-35 where is the flaw growth rate,AK is the change in stress intensity factor per cycle, and C and a are constants. ; The following calculation l describes the growth of. the code allowable
. internal and surface flaws into through-wall cracks. Since the size of these flaws is small, pipe curvature can be neglected and there is no difference between axial and circumferential flaws. Surface defects in Seismic Category I piping allowed by the code are defects 7s:!. maximum depth of 5%
of the wall thickness (t). Therefore the maximum tiaw depth will be 0.05 c. The material constants have values of C = 1.6 x 10 in, and a = 4 (at 550*F). Note that the value of the exponent a is censarvative. The exponent varies between 2 and 4 for different steels and, using its maximum value, tne growth rate will be the fastest. i Integration of the previous equation gives the number of cycles: a da n= ag C(AK) where a g
= 0.05 t is the initial flaw depth (the code allowable defect) and a f is the final flaw depth. For a surface flaw, the integral becomes a
1 da a=C- -1.12 a(ra) U 2 4 a . t If a =g thickness, then n is the number of cycles to develop a through-wall l crack. When the equation for n is applied to SA155 pipe, a = 0.05 x 1 = 0.05 in, and ag = 1 in, g a = yield stress at 550*F (the flaw growth will be faster at higher temperatures) . n = 4.13 x 10' x 0.05
- 1 = 132,000 cycles (27.7)4 I The additional growth of this defect to reach critical size is not I important because the pipe will leak and the leak will be repaired.
f
SPS UFSAR 14B-36 It has been shown that the growth of an internal flaw is even slower than in the above case. The number of cycles during the lifetime of a nuclear power plant can be obtained taking into account daily and weekly power reductions, startups, shutdowns, and other changes in pressure. An estimate gives the number of cycles at about 13,000, which is much smaller than the value for the formation of a through-wall crack. 145.5.1.7 Modifications The following modifications to the initial plant design were made to further ensure safe-shutdown reliability and the operation of plant protective features:
- 1. The pump discharge piping of tht. auxiliary feedwater systems in Units 1 and 2 were cross connected so that the unaffected system will f
have the capability of maintaining both units in a shutdown condition. Furthermore, an additional source of makeup water for the auxiliary feedwater systema has been installed. An additional . 110,000-gal missile-protected condensate storage tank and two booster j pumps supply the suction of the unaffected auxiliary feedwater pumps. These modifications were designed and installed in accordance with ASME Section III Seismic Category I criteria, and are also tornado-protected. These modifications are shown in Figure 14B-22. i As described in Section 14.2.11, only one 350-gpm auxiliary feedwster pump is required to removed stored and residual heat. Therefore, no redundancy requirements were lost for either unit, since there are two 350-gpa auxiliary feudwater pumps and one 700-gpm feedwater pump available from the unaffected unit. Since, with the modifications, the unaffected auxiliary feedwater system is required to supply both units, the residual heat removal capacity from the original 100,000-gal condensate storage tank is i halved. Another reliable source of water is the fire protection system main, which has the capability of supplying 500,000 gal of water to the suction side of the unaffected auxiliary feedwater
SPS UFSAR 148-37 l pumps. In addition, the 300,000-gal condensate storage tank used for normal feedwater makeup can be used to supply the 100,000-gal condensate storage tank utilizing gravity flow. The additional 110,000-gal missile-protected condensate storage tank was added to enhance the reliability of the modified system.
- 2. The turbine drivers for the containment spray pumps were disconnected from their steam supply lines and the 3-in. lines were removed from the containment spray pump room. These modifications eliminated the
, containment spray pumps as a target. Since the turbines were used only as redundant pump drivers for the two full-size containment spray pumps, the pumps with their motor .: drivers still maintain the redundancy requirements of the containment l spray system. 14B.5.2 FEEDWATER 14B.5.2.1 Break Locations i Break locations were postulated in the feedwater lines from the containment to the feedwater pumps in the turbine room in accordance with l Section 14B.2.2. For the feedwater lines, 0.8 of the allowable thermal stress is 18,000 psi. For each line considered, none of the calculated thermal stresses exceeded 0.8 of their allowables. Piping upstream of the containment was not analyzed seismically, so that intermediate points were selected on the j basis of maximum thermal stress. For piping from the containment to the turbine building, two intermediate locations were selected. Breaks were assumed for pipias in the turbine building; however, because of physical separation, no detailed analysis was required. At all break points, both circumferential and longitudinal breaks were considered. i The break points are listed in Table 14B-8 along with the thermal stress levels, as calculated. The break locations are shown in Figures 14B-11 and 14B-12. 2
. . _ - . , . - _ , ,,- - , - . . . - - , , . - . _ . , , _ , . ~ . - . - _ . . . .. ,.. -- - - .
SPS UFSAR 14B-38 Cracks were selected at all locations in the vicinity of targets. 148.5.2.2 Separation The same degree of separation provided between targets and a postulated steam-line break is found for the postulated feedwater line break. 14B.5.2.3 Pipe Whip and Fluid Jet Effects The effects of pipe whip and fluid jets from a postulated feedwater line break are similar but less severe than a main steam line break. Table 143-9 contains the results of the evaluation for maintaining the I feedwater system functional. All the assumptions required for the main steam system as described in Section 148.5.1.3 also apply to the feedwater system. 14B.! 2.4 Pressure and Environment
; The main steam valve house will withstand the pressure buildup from a postulated feedwater line break, which is less than the steam-line break pressure buildup. Environmental effects are similar to the main steam line break but less severe.
14B.S.2.5 Inspection Program for Larger Lines An extensive nondestructive testing program was initiated for the main feedwater postulated break points in the main steam valve house. These points, a total of eight for each unit, are shown in Figure 14B-11. 14B.5.3 OTHER HIGH-ENERGY LINES THAT MAINTAIN MAXIMUM OPERATING TEMPERATURES GREATER THAN 200'F AND MAXIMUM OPERATING PRESSURES GREATER THAN 275 PSIG 14B.5.3.1 Break Locations Figures 14B-13,14B-14, and 14B-15 show the break locations that were postulated for circumferential and longitudinal breaks. Postulated break
SPS UFSAR 14B locations were selected in accordance with the criteria - specified in Section 14B.2.2. Tables 14B-10 and 14B-11 list the stresses in the piping systems at the postulated break locations. Designated numbers for these high-energy lines are
- 1. Steam-Generator Blowdown Unit 1 Unit 2 3"-WGCB-1-601 3"-WGCB-101-601 4 3"-WGCB-2-601 3"-WGCB-102-601 3"-WGCB-3-601 3"-WGCB-103-601 f
- 2. I.etdown from Regenerative Heat Exchanger ~
l l Unit 1 Unit 2 2"-CH-6-602 2"-CH-306-602 Cracks were postulated throughout the length of the lines for any adverse effects on targets. For computation of crack size, the diameter and wall thickness of these pipes are given in Table 14B-2. 14B.5.3.2 Pipe Whip and fluid Jet Ef fects I The letdown line and the steam-generator blowdown lines will be permitted to whip in the event of a postulated circumferential break. It has been determined by an extensive drawing review, onsite inspection, and pipe break analysis sheets that no additional restraints are required in order to meet i . the criteria for pipe breaks. An example of the pipe break analysis sheets for these lines is given in Table 14B-12. Target protection is maintained in the following manner:
- 1. By means of physical separation, including distance, building support columns, concrete walls, and larger sized pipes, and/or
- 2. By means of the many redundant features originally designed into the existing systems.
- - , . _ _ . . - .- ---.,,-...-.-wo . . , , - _ . - - - _ - - , . ,. ..---. .,_,,___,--,.,-
.--~r . - - - - . - - - . - - - . - - .,_.r . -
SPS UFSAR 14B-40 In all cases, the postulated pipe break will not jeopardize a safe plant i shutdown. 14B.5.3.3 Pressure and Environment The maximum flow from the broken letdown line is only 60 gym with a maximum operating temperature of 287*F and pressure of 289 psig; therefore only local effects were considered. The limiting case for pressure buildup and auxiliary building environmental conditions is the break of a 3-in. steam-generator blowdown line. The maximum flow rate through this line is 140 lb/sec at a maximum J operating temperature of 515*F and pressure of 775 psig. Calculations were ~ made considering the area in which the blowdown lines are located as the worst
! case. This area is shown in Figure 14B-13 and extends to the charging pump cubicle walls as shown in Figure 14B-14. Because of the large volume and the large vent areas, there will be negligible pressure buildup within this volume, but the temperature in this area can essentially reach 212*F if blowdown is not stopped.
, An excess flow-measuring device mitigates the consequences of a steam-generator blowdown line break outside the containment. This device is located upstream of the inside containment isolation valve. If blowdown line flow l exceeds a predetermined value, a signal will close the inside containment i isolation valve for that blowdown line. t ! Also, excess flow is annunciated in the control room. Indication of isolation valve closure presently exists in the control room. Detection and subsequent isolation of the affected line will inhibit the increase of temperature and humidity of the environment in the areas adjacent to postulated cracks or breaks. a i i
SPS UFSAR 14B-41. f 14B.5.4 HIGH-ENERGY LINES THAT MAINTAIN A MAXIMUM OPERATING TEMPERATURE OF. GREATER THAN 200*F CR A MAXIMUM OPERATING PRESSURE OF GREATER T hN 275 PSIG 14B.5.4.1 Break Locations Figures 14B-13 through 14B-17 show the locations of the high-energy lines
, in question. In addition, Table 143-2 gives the maximum operating conditions of each of the lines shown. Cracks were postulated throughout the entire length of each line shown, and evaluated for any adverse effects on targets.
The diameter and thickness of these pipes are given in Table 14B-2 for computation of crack size. 14B.S.4.2 Separation Source lines not located within the confines of the areas shown in Figures 14B-11 through 14B-17 have no adverse effects on targets because of the physical separation provided by the building arrangement. For this reason, high-energy lines outside these areas were not considered as sources. 14B.S.4.3 1.ocal Environmental Effects and Jet Impingement In many cases, shutdown and other protective features are far enough removed from the lines in question that local effects of a postulated crack :
- will have no effect on even the redundant features. i In other cases, target protection is maintained with the many redundant features designed into the present systems and the separation of these by means of distance, walls, and location. An example of one of the pipe break / mini-crack analysis sheets is shown in Table 14B-13.
Except for minor modifications, as discussed in Section 14B.5.4.4, the plant will always maintain shutdown capability, and at least one each of'the redundant protective features will remain operable following a crack in these high-energy lines. l l j l
I SPS UFSAR 14B-42 14B.S.4.4 Modifications - In order to ensure a safe cold shutdown, the following modifications to the initial plant design were made:
- 1. The charging pump cooling water pumps are shielded from direct impingement, in accordance with Figure 14B-23.
- 2. One of the four component cooling pump cables is rerouted (shown in Figure 14B-16), so that two of the pumps are always available (only one is required for hot standby).
O 1
SPS UFSAR 14B-43 14B.6 CONCLUSIONS Surry Units 1 and 2 are designed with highly reliable and redundant systems for the purpose of safe shutdown, considering normal and accident conditions. Furthermore, with the modifications described in the text of this appendix, safe plant shutdown is ensured for all postulated failures of high-energy piping outside of the containment. The control room, which serves Units 1 and 2, will remain habitable and ftmetional following a failure of any high-energy line. The emergency diesel generators, which are required to satisfy loss-of-offsite-power criteria, will maintain integrity throughout a postulated high- - energy piping failure incident. i 1 4
SPS UFSAR 14B-44 , 14B REFERENCES
- 1. A. Giambusso, Atomic Energy Commission letter, " General Information Required for Consideration of the Effects of a Pipintt ;ystem Break Outside Containment," December 18, 1972.
- 2. General Electric Company. " System Criteria and Applications for Protection Against the Dynamic Effects of Pipe Break," Document No. 22A2625, Nuclear Energy Division, 1971.
- 3. PISCES Computer Code. Physics International Multispacial Codes for Engineering and Science, Physics International Company.
o
- 4. K. R. Wichman, A. G. Hopper, and J. L. Marshon, Local Stresses in
- Spherical and Cylindrical Shells Due to External Loadings, Welding Research Council.
- 5. Building Code Requirements for Reinforced Concrete (ACI 318-71), American Concrete Institute, 1971.
- 6. G. Berkhoff and E. H. Zarantonello, Jets, Wakes, and Cavities, Academic Press Inc., New York, 1967.
- 7. "CUPAT - A Computer Program to Calculate Pressure and Temperature in Various Nuclear Power Plant Compartments Resulting from a Postulated High Energy Pipe Break," Stone & Webster Engineering Corp., 1973.
- 8. "LOCTIC - A Computer Code to Determine the Pressure and Temperature Response of Dry Containments to a Loss-of-Coolant Accident," SWND-l, Stone & Webster Engineering Corp., September 1971.
- 9. "LOCTVS - A Computer Code to Determine the Pressure and Temperature Response of Pressure Suppression Containments to a Loss-of-Coolant Accident," SWND-2. Stone & Webster Engineering Corp., October 1969.
1
SPS UFSAR 14B-45 14B REFERENCES (continued)
- 10. F. J. Moody, " Maximum Two-Phase Vessel Blowdown from Pipes " APED-4827, General Electric Co., April 20, 1965.
- 11. "LOCTVS - A Computer Code to Determine the Pressure and Temperature Response of Pressure Suppression Containments to a Loss-of-Coolant Accident," SWND-2, Supplement No. 1, Stone & Webster Engineering Corp. ,
March 1973. i
- 12. PVRC Recommendations on Toughness Requirements for Ferritic Materials, WRC Bulletin 175 August 1972.
- 13. W. E. Senchak and O. E. Widera, " Application of Fracture Mechanics to Nuclear Piping Systems," Engineering Fracture Mechanics, 1972. Vol. 4,.
- p. 877.
. 14. H. Liebowitz, ed., Fracture - An Advanced Treatise, Vol. V, p. 211. i i d i
l SPS UFSAR 14B-67 i 1 Table 14B-1 l LENGTH OF PLASTIC HINGE POINT l Nominal Pipe Size, in. Schedule Length, in. 10 80 97.4 14 80 122.6 24 80 197.8 30 1-in. wall 167.5 32 1-in. wall 155.6 3" 80 77.4 Notes: 1. Carbon steel pipe (A106, Grade B).
- 2. Break at elbow. .
- 3. Steam initially at 1,050 psi.
" Saturated water - 775 psig. 515'F.
l . l S i
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Table 14B-2 (continued) HICH-ENERCY LINES SOURCES
.i meas e nees e um. weis ape. sa. eye. e. es,e s..eb se... ns, bee . r.eee .. reep.. .. :: en. sensee, se . . .. e so. so. _ ,.s a _
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(1s - M2 3 e.4 M 2Me 8M Esossemeneest. 3 Ame338esy butadseg the ace 4 and esteme seestel jet Septaseeeet , tu - DMs 3 e.4 M 2Me 8M Emel.eementet. 8 anestlery beeldles j taeos,es .e4 wesene . .. ses septagemens tu - 322 2 e.M 3 2%88 SM teels rel. I amelliery betidseg (hencet med wetene emesset les taptagemens ! wrs - 34% 88 8.8% 8el2 458 Flye esb8p. jet 54 Tesbles bulldtag. l 54eee-geesseter feed Septagement,
*
- service belldseg 3 ee - f eee.es.: peepe . emeltameneral se feee. eses meetfeld as - 386 2 e.4% 289 287 F8pe esim8p. jet nee 84e8 and volume seasse! -
8 aselltesy beeldtag Septagement, i j tenden. 8. e .egemesessee emelsammensel bees eastheaees os - Me 4 e.4 38 23e8 EM Ometramesesel. 8 aeostsesy b stdeag (/n n.ess.4 eed se8mme senaret - See Seplagemens N sheasles hades " i
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<he.steg boedes em - ns, . 3 e.4 2 25ee 8M Emelseemsetet. I amostsee, bettesse Chematen end seleen seessen jos septagemens
, cm - tes 3 e.4M 3SAS B38 Seessammaesel, I thenaset and wetene camaret e ametateep besteses jet Septee.ames (a - Me 2 e.343 21ee im Seeseammeesel. 3 asesstasy besseseg th esset and wetene seessel jee Seysagemens O D8 8
*e4 - est appl 8 cable.
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Table 148-2 (cositinued) HICH-ENERGY LINES SOURCES sh=otes 3 anos 8mme unneseem
- ESee t$e t 8 SpesasSag eyesesSag y$ye Seash
$8se. Thistmees, pseeems e, feeperosese, ti f ees e setense Serotee to, go. yta *f Eseleased C8eest f tces ten
- Lesessee (a - Me 2 S. M 3 FMe SM Bevis Tel. 8 Amelltosy b 88dteg Chee8 set and solese cesaret les Sep8eemeses (a - M3 3 S4M 2MS IM Emets el. I ansellery betidleg e.neesset med solene seasset les Sep8eeseems ta - 383 3 8.4 M 2188 SM ametseamseset. I aestilesy bm8 tete-Cheeseel and eetwee emessel les Septageeses St - MF 3 S.4M 2%ee IN Geelsemesesel. 8 Ame888esy belld8ag Setesy gegocesen chesstag los Seplagueses yemy - se med see8.48eg she 8 5ses to 8essee selee
! sg - 257 3 8.4M 2140 IM Seelsomenesel. 8 Amelitary betidlag l Setesy Sejecales chesgleg jos 8eplagueses y-ap - se and Sec tednes she l seses s.esentee selee j se - 2:2 3 a.4M 2see SM seessemeenset. I sees 38esy belleses l Sefesy talesaSee ahasaleg Jos Imp' _ yeep - ee end SacSedtag ahe Eases SeelesBee selve i s/n l N 1 Ub e C ea - ees apyBleebte. evg s18 1
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SPS UFSAR 16B-53 Table 145-3 i POSTULATED TARGETS Systes Major Equipment Mark No. Location Auxiliary feedwater Auxiliary feed pumps 2-FW-P-L Main steam 2- W-P-3A valve house 2-FW-P-35 (MSVH) Auxiliary feed pump MSvH oil coolers (1 per feed pump) Auxiliary feed check valves VCW-60A MSVH j (1 per feed pump)
- Chemical and volume' Charging pumps 2-CH-P-1A Auxiliary control 2-CH-P-1B building
- 2-CH-P-1C Boric acid tanks 1-CH-TK-1A Auxiliary 1-CH-TK-1B building 1-CH-TK-1C I
- Boric acid tank heaters 1-CH-E-6A Auxiliary 1-CH-E-6B building 1-CH-E-6C Boric acid transfer pumps 1-CH-P-2C Auxiliary '.
1-CH-P-2D building Boric acid isolation valves MOV-2350 Auxiliary building Volume control tank 4-C42 Auxiliary isolation check valve building Cold-leg isolation valves MOV-2289A Auxiliary (normal charging) MOV-22895 building i Chemical and volume Charging pump discharge MOV-2286A Auxiliary j control valves MOV-2286B building MOV-2286C MOV-2287A MOV-2287B MOV-2287C
- Reactor coolant pump MOV-2370 Auxiliary seal isolation valve building Refueling water storage LCV-2115B Auxiliary tank isolation valves LCV-2115D building
2 SPS UFSAR 16B-54 ; Table 145-3 (continued) ' POSTUI.ATED TARGETS f, System Major Equipment Mark No. I.ocation i Chemical and volume Alternate charging paths - FCV-2160 Auxiliary control (continued) isolation valves MOV-2867A building (redundancy) MOV-28675 3 MOV-2867C MOV-2867D ! MOV-2869A i MOV-28695 ; i MOV-2842 l Charging pump discharge FT-2121 Auxiliary j pressure (not required buildins ; { because of the availability l 1 of pressurizer level) .i j j Charging pump flow trans- FT-2122 Auxiliary ;
- mitter (not required because building l of the availability of l pressuriser level)
l j Flow control valve for the FCV-2122 Auxiliary charging pump (fails open) building i 3 Main feedwater Main feedwater isolation VCW-60A MSVH j check valves (3) Main steam Main steam nonreturn valves NRV-MS201A MSVH
< NRV-MS2018 i ,
NRV-MS201C I Main steam trip valves TV-MS201A MSVE i Tv-MS2018 l TV-MS201C Auxiliary feed pump steam MOV-MS202 MSVH isolation valve PCV-MS202 MSVH (F/open) 1 Main steam safety valves SV-MS201A MSVR (required only for main SV-MS2015 i steam line rupture) SV-MS201C l SV-MS202A SV-MS2025 SV-MS202C
- SV-MS203A
- SV-MS2035 1 SV-MS203C a
SFS UFSAR 148-55 Table 145-3 (continued) POSTULATED TARGETS jytJg t Major Eeutonent Mark No. - Location Main steam Main steam atmospheric steam RV-M8201A MSV5 (continued) duay valves (backup system for RV-Mg2015 main steam safety valves) RV-Mg201C Inputs to staan-line breakt FT-2474/ MSV5 (a) steam-line break input is 475/476 ensured by steam-line flow FT-2444/ and low T (b) safety 445/444 injection *IEp;ut is a high FT-2494/ steam-line differential 495/496 pressure which would follow loss of these transmitters Component cooling Component cooling water 1-CC-F-1 A Auxiliary ' system pumps 1-CC-F-1B building 1-CC-F-1C 1-CC-F-1D Component cooling water 1-CC-E-1A Auxiliary heat exchangers 1-CC-E-15 building 1-CC-E-1C
. 1-CC-E-1D Charging pump cooling 2-CC-F-2A Auxiliary water pumps 2-CC-F-28 building Charging pump lube-cil 2-CR-E-5A Auxiliary coolers 2-C5-E-58 building 2-CR-E-SC Charging pump seal coolers 2-CH-E-7A Auxiliary 2-CH-t-78 building 2-CH-E-7C 2-CH-E-70 2-CH-E-7 E 2-CH-E ,7F Flow transmitters, component FT-CC200A Auxiliary cooling pump discharge FT-CC2003 building (Unit 2)
Containment spray Containment spray pumps 2-CS-F-1A Containment systen 2-CS-F-1B spray pump area Containment spray pump PT-CS201A Containment discharge pressure trans- PT-CS2015 spray pump sitters (refueling water area storage tank ' level and recirculation spray sump level can be used to ensure operation)
SFS UFSAR 165-56 i ! Table 14B-4 MAIN STEAM BREAK LOCATIONS AND STRESSES i Thermal Combined Line Break Stress, Stress, Desianation Point voi poi Description 30-SHF-101 1 3,850 15.937 Terminal - containment 79 2,560 11,727 Terminal - annifold 3 6,680 19,322 Intermediate - elbow valve house 37 5.330 14,718 Intermediate location - 40 5,670 15.064 bend 30-SHF-102 135 4,380 17.484 Terminal - containment
]
206 1,965 10,335 Terminal - manifold 138 7.355 20,671 Intermediate - elbow valve house 1 163 5.690 15.116 Intermediate location - 166 6.060 15,240 bend 30-3H7-103 275 4,365 17.528 Terminal - containment 341 1.180 9.508 Terminal - manifold 277 7,210 18,257 Intermediate - elbow valve house 309 6,565 15,485 Intermediate location - 305 5,990 14,910 bend : i i I
Table 145-5 FEEDWATER SYSTDtS AVAIIABILITY AFTER MAIM STEAM FIFE matar IN VALVE BOUSE Main Auxiliary Feed Auxiliary Feed Break No. Location Feed Turbine Motors (2) Crooe-Comeect C1. C135. C275 Containment 0 0 I-S 0 C2 Cl36. C276. C461 Riser 0 0 I-S 0 C3, Cl38. C277 Elbow 0 0 I-S 0 Lt. L135. L275 Containment 0 0 I-S 0 L2, L136. L276. L461 Riser (0)-J O I-S 0 L3. L138. L277 Elbow (vertical) 0 I-J I-S 0 Elbow (lateral) 0 0 I-S 0 Key: O = operable I = inoperable (0) = 2 lines operabic , W = whip damage % J = jet damage S = steam damage Q C = circumferential L = longitudinal l
?
O
- --- - - - . , , - - - _ r-- -
c --r, , ,Q, __ __ ,
SPS UFSAR 14B-58 Table 14B-6 JET IMPINGEMENT ON WALLS - FORCE = 619 KIPS Jet Wall Min. Wall - Impingemegt Pressure, Thickness, Punch Shear, Target Area, ft pois in. in. Floor 44.90 95.7 9 22 Roof 142.05 30.2 24 24 Containment (N) 10.23 420.0 54 54 Shield (S) 102.53 41.9 36 36 East vall 18.85 228.1 24 24 West wall 42.23 102.1 24 24 Shield (S) 26.97 159.4 36 36 l l
SPS UFSAR 145-59 l l Table 145-7 JET IMFINCIMENT ON VALVES Ft At Fv Jet Pressure. Impingemeng Incident Normal t Velves sein Area. in. Anale Force-kine ! NRV/MS2013 74.6 3927 0 175 TV/MS2013 126.3 2182 0 165 SV/MS203A 37.8 673 60 3.8 SV/MS201A 37.8 312 60 1.8 RV/MS201A 34.2 200 25 2.8 , l l i
\
l ! l
l SPS ETSAR 168-60 Table 148-8 l FEEDWATER BREAK 1,0 CATIONS AND STRESSES Thermal , Line treak Strees, Desianation Point sei Description , 14-WTFD-117 1 1,565 Terminal - containment l l 76 6,563 Terminal - manifold 72 5.837 Intermediate - valve 4 5,383 Intermediate - elbov valve house 14-WTFD-113 101 2,393 Terminal - containment 100 4.722 Terminal - manifold ' l' i 107 5.333 Intermediate - albov valve house 171 5,466 Intermediate - at valve ; 172 5,046 , 14-WFPD-109 241 2,860 Terminal - containment 195 4,200 Terminal - annifold ; 210 4,169 247 11,171 Intermediate - albov valve house 249 11,962 , l 244 8,814 Intermediate - elbow valve house i 246 7,989 i 18-WFPD-104 90 3,539 Terminal - manifold i 93 5.333 Terminal PW-E1A 108 4,796 Intermediate ' wend i 95 6,368 Intermediate - bend - valve 18-WFPD-105 190 5,209 Terminal - manifold 14 3,260 Terminal PW-E18 48 3,220 Intermediate - bend - 16 4,460 Intermediate - band - valve I
Table 148-9 FEEEMATER STSTBES AVAILABILITY AFTER ItalN FEE 3 MATER FIFE marar in VALyg gegSg Mata Aansiliary Feed Annu11fary Feed Break Mo. Imcation Feed Terbine Iloters (2) Crece-Commect C5. C6 Caetatement er elbaar (0) 0 I-S 4 C101. C241. C244 Contai-r er elbona (0) I-U I-5 0 Elbeer (0)
~
C107. C247. C249 0 I-5 0 L5. L101. L241 Caetatament (0) 0 I-S O L6. L244 Elbeen (0) 0 I-S 0 LIO7 Elbena (0) 0 I-5 0 L247. L249 Elboer (0) 0 I-S 0 ! Key: O = eperable I = Inaperable (0) = 2 lines operable g W = n&lp damage sa i J = Jet ' - ;- Q a S = steam dama0e ! C = circumferential N L = leagitandiaal E
?
2 i
SPS UFSAR 148-62 Table 145-10 STEAM-CENERATOR BLOWDOWN BREAK LINE LOCATIONS AND STRESSES Line Break Thermal Stress, Designation Point psi Description Unit 1 3-WCCB-1 . 60 3952 Terminal - containment
- 61 4991 Intermediate - elbow l
l 3-WGC3-2 63 1414 Terminal - containment 66 4411 Intermediate - elbow 3-WCC5-3 67 3251 Terminal - containment - 70 4942 Intermediate - albow Unit 2 i 3-WCCB-101 22 3952 Terminal - containment 21 4991 Intermediate - elbow 3-WCC5-102 23 1414 Terminal - containment 26 4411 Intermediate - elbow 3-WCCB-103 27 3251 Terminal - containment . 30 4942 Intermediate - elbow i i l i i
SPS UTSAR 148-63 Table 148-11 l LETDOWN LINE FROM REGENERATIVE HEAT EXCHANGER BREAK LOCATIONS AND STRESSES Line Break Thornal Stress, j Designation Point get Description l Unit 1 2"-CH-6-602 238 5102 Terminal - anchor 236 17,175 Intermediate - elbow l 71 2487 Terminal - containment 73 2727 Elbow 74 2774 Elbow 64 90 Anchor Unit 2 2"-CH-306-602 38 5102 Terminal - anchor 36 17,175 Intermediate - elbow 35 2487 Terminal - containment i 32 2727 Elbow l 33 2774 Elbow 95 90 Anchor l 1 l l l l
SPS UFSAR 14B-64
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Se c APPENDIX ORGANIZATION EFFECTS 2 OF lilGH ENERGY PIPING SYSTEM - BREAK OUTSIDE CONTA8NMENT E SURRY PoisrER STATION b testTS I Assis 2
SPS UFSAR Figura 14B-2 's i
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ENViRCNMENT [ l l l PIPE BREAK (WHlP, JETS, E TO.) l TEMPe l + ENVIRONMENT i oF . , l i I l t I i . i 200 . l ENVIRON M ENT REA 175 PRESSURE", PSIG l ! M PRESSURE AND TEMPER ATUR E CORRESPONDING 70 " MAXIMUM NORM AL QPERATING" l INCLUDES START-UP, SHUTOCWN, STAN08Y, POW ER OPERATION 1 PIPE SPLIT, CRACK AND BREAK ANALYSIS REQUIRED FOR HIGH ENERGY PIPING
. SURRY POWER STATION UNITS I AND 2
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- SATURATED WATER-77 5 PSIG ,51S*F iA106 Gr CAR 8ON STEEL 1050 PSI STEAM FORCE DUE TO PIPE IMPACT (TYPICAL EXAMPLES)
SURRY POWER STATION UNITS I AND 2
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'TH AN THE LONGITUDINAL BREAK WCOEL 00ES.
PUNCH SHEAR FAILURE OF CONCRETE WALL SURRY POWER STATION
. UNITS l AND 2
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1 1 l INPUT (2) THERMOOVNAMIC STATE ( T P. ANO (l) NEW MASS AND ENERGY - VAPOR ANDLIQUlO FM ACTIONS)ARE MASS AND ENERGY ; INVENTORVa0LD4lNPUT CALCULATED FROM MASS AND ENERGY INFLOWS ( INVENTORIES AND STE AM TABLES l 1r (3) MASS FLOW OUT CALcuL ATru PROM ' . (6) MASS AND ENERGY INVENTORY Paf. ,To PgWAPOR AM9 bleulp ; S m mNALpmatsuma la uppATEa Isv eumTRaeTINe j I S. I , O P THE OUTFLOWS EN T. FRICTION FACTOR iN , I (4) CHECK FOR CRITICA F. 4 FLOW t i $ us i v> i -> E. CUPAT LOGIC Di AGRAM i SURRY POWER STATION S UNITS LAND 2 h i .i I 3 4 0
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SPS UFSAR 140 2-57 Attachment 9 coolant system or the main steam system. Pressure-relieving devices incorporated in the two systems are adequate to limit the maximum pressures to within design limits. The integrity of the core is maintained by the hi;h pressurizer pressure reactor trip. The minimus DNBR never falls below 1.45, which is well above the L.3 design value. 14.2.11 LOSS OF NORMAL TEEDWATER i A loss of normal feedwater (from a pipe break, pump failures, valve malfunctions, or loss of outside ac po-ter) results in a loss in the capability of the secondary system to remove the heat generated in the reactor core. If the reactor were not tripped during this incident, reactor core damage could
~
possibly occur from a sudden loss of heat sink. If an alternative supply of j feedwater were not available for the unit, residual and sensible heat following reactor trip would heat the reactor coolant system water to the point at which water relief from the pressurizer relief valves occurs. A loss of significant water from the reactor coolant system could conceivably lead to core damage. i The following provides the necessary protection against a loss of normal feedwater
- 1. Reactor trip on a low-low water level in any staan generator, unless i the loop stop valves are closed.
1
- 2. Reactor trip on a main steam flow-feedwater flow mismatch coincidental with a low water level in any steam generator, i
- 3. The operation of two motor driven auxiliary feedwater pumps (350 spa
; each), which can be started either automatically or manually. They
! are started automatically on l l
- a. A low-low water level in any steam generator. .
- b. The opening of both feedwater pump circuit breakers.
- c. Any safety injection signal.
- d. The loss of all ac power.
SPS UFSAR 14.2-58 4 The operation of one turbine-driven pump (700 gpm), which can be started automatically or manually. It is started automatically on
- a. A low-low level in two of the three steam generators.
- b. A loss of voltage on all 4160-V buses.
The motor-driven auxiliary feedwater pumps are supplied by the diesel generators if a loss of outside power occurs, and the turbine-driven pump uses steam from the steam generators. The turbine exhausts the steam to the atmosphere. The auxiliary feedwater pumps take suction directly from the l buried 100,000-gal condensate storage tank for delivery to the steam generators. ( The above provides functional diversity in equipment and control logic to ensure that reactor trip and automatic auxiliary feedwater flow will occur following any loss of normal feedwater, including that caused by a loss of ac power. l 14.2.11.1 Method of Analysis l The analysis was performed using a digital simulation of the unit to show that, following a loss of normal feedwater, the auxiliary feedwater system is adequate to remove stored and residual heat. The following assumptions were made
- 1. The steam-generator water level (in all steam generators) at the time reactor trip occurs is at the lowest level, which will result in reactor trip and automatic initiation of the auxiliary feedwater J flow. The initial water level in the analysis is assumed to be at the lower narrow-range level tap. I
- 2. The unit is initially operating at 102% of 2546 Mk't (the maximum calculated turbine rating).
SPS UTSAll 1402-59 3. The heat transfer coefficient (conductance) assumed for the steam generators in the analysis of the loss-of-normal-feedwater-flow accident is the lowest design value with an allowance for steaa-generator tube fouling. This leads to the lowest or worst steam-generator UA factor. The primary-side film coefficient is assumed to vary from the value at full flow as w 0 .8, where w is th reactw coolant systes flow during the accident.
- 4. Conservative core residual heat generation based on long-term
, operation at the initial power level is taking place preceding the trip.
- 5. Only one motor-driven auxiliary feedwater pump is available at 1 min after the incident.
- 6. Auxiliary feedwater is delivered to only two steam generators.
7. l Secondary system steam relief is provided through the self-actuated safety valves. (Steam relief will, in fact, be through the power-l operated relief valves or condenser dump valves for most cases of ; loss of normal feedwater. However, these were assumed to be I unavailable in the analysis.) . l 14.2.11.2 Results Figure 14.2-98 shows the unit parameters following a loss-of-normal-feedwater incident according to the assumptions listed above. Following the i reactor and turbine trip from 1.02 x 2546 We, the water lev'el in the stean l generators will fall because of a reduction of the steam-generator void fraction and because steam flow through the safety valves continues to 1 l dissipate the stored and generated heat. One minute following the initiation of the low-low level trip the auxiliary feedwater pump is automatically started, reducing the rate of water level decrease. The capacity of the auxiliary feedvater punp is such that the water level in the steam generators being fed does not recede below the lowest level at which sufficient heat transfer area is available to dissipate core residual heat without water relief from the prianry system relief or safety valves. _= . - - _. - - _.
1 SPS UFSAR 14.2-60 i \ 1 From Figure 14.2-98 it can be seen that at no time is the tube sheet uncovered in the steam generators receiving auxiliary feedwater flow and at no 1 ties is there water relief from the pressurizer. If the auxiliary feed
- delivered is greater than that of one actor-driven pump, the initial reactor j power is less than 102% of 2546 MWe, or the steaa-generator water level in one
{ or more steam generators is above the low-low level trip point at the time of L ! trip, then the result will be a stean-generator minimum water level higher than shown and an increased margin to the point at which reactor coolant water- ! relief from the pressuriser securs. k Subsequent to the initial FSAR analysis described above, the loss-of-l normal-feedwater event was reenalyzed to explicitly account for the effects of reactor coolant system pump heat. The reanalysis was performed using the RETRAN computer code and the single-loop analysis model described in j Reference 10. The analysis assumptions included the followings i
- 1. Initial operation at 102% of the design rating.
i !
. i l 2. A conservative core residual heat generation based on long-tera 1
operation at the initial power level preceding the trip. 4 i j 3. Reactor trip occurs en low-low steam-generator level. l U
- 4. Only two actor drives auxiliary feedwater pumps are available 1 min !
l af ter the accident. l 5. Auxiliary feedwater is delivered to all steam generators. M
- 6. Secondary systen steam relief is achieved through the self-actuated
) safety valves. Note that steam relief will, in fact, be through the l power-operated relief valves or condenser dump valves for most cases j of loss of normal f eedwater. However, for conservatism these have i been assumed unavailable. l
- 7. The initial reactor coolant average to:cperature is 4'T higher than the nominal value, and the initial pressuriser pressure is 30 psi
! higher than nominal. I, L-_--_.---.-._..-_.- -_ _ _ . . - , -
SPS UFSAR 140 2-61
- 8. Continuous operation of the reactor coolant pumps.
The reanalysis results are presented in Figures 14.2-99 through 14.2-102 for pressurizar water volume, pressurizer pressure, loop temperature, and steam pressure, respectively. As can be seen from the figures, at no time is there water relief from the pressurizer safety or relief valves. 14.2.11.3 Conclusions The loss of normal feedwater does not result in any adverse condition in the core, because it does not result in water relief from the pressurizer relief or safety valves, nor does it result in an uncovering of the tube sheets of the steam generators being supplied with water. 9 14.2.12 LOSS OF ALL ALTERNATING CURRENT POWER TO THE STATION AUXILIARIES l In the event of a complete loss of offsite power acd a turbine trip, there would be a loss of power to the unit auxiliaries (i.e., the reactor
\ coolant pumps, main feedwater pumps, etc.). The events following a loss of ac power with turbine trip are as follows:
- 1. Unit vital instrument loads are supplied by the emergency power sources. l
- 2. As the steam system pressure incisases, the steam system power-operated relief valves are automatically opened to the atmosphere. (Steam bypass to the condenser is assumed to be i
unavailable, since the seeam bypass is not required for reactor
- protection.)
- 3. If the steam flow rate through the power-operated relief valves is not sufficient (or if the power relief valves are not available), the steam-generator self-actuated safety valves may life to dissipace the sensible heat of the fuel and coolant plus the residual heat produced in the reactor. I I
SPS UFSAR 14.2-62 l 4. As the no-load temperature is approached, the steam power-operated relief valves (or self-actuated safety valves if the power-operated relief valves are not available for any reason) are used to dissipate 4 the residual heat and to maintain the unit in the hot-shutdown condition.
- 5. The emergency diesel generators will start on a loss of voltage on
- the emergency 4160-V buses to supply unit vital loads.
The auxiliary feedwater system is started automatically as discussed in ' S:ction 14.2.11. The steaa-driven auxiliary feedwater pump uses main steam cad exhausts to the atmosphere. The actor-driven auxiliary feedwater pumps j cre supplied by power from the diesel generators. The pumps take suction l directly from the buried 110,000-sal condensate storage tank for delivery to the steam generators. The auxiliary feedwater system ensures a feedwater I 1 supply of at least 500 gym upon the loss of power to the station auxil-i icries,11 since the auxiliary steam turbine-driven feedwater pump has a l ccpacity of 700 spa and the motor-driven auxiliary feedwater pumps have a ' capacity of 350 spa each. The staan-driven pump can be tested at any time by admitting steam to the turbine driver. The motor-driven pumps also can be tested at any time. The velves in the systes can be operationally tested at any time. l Upon the loss of power to the reactor coolant pumps, coolant flow cccessary for core cooling and for the removal of residual heat is maintained l by natural circulation in the reactor coolant loops. The natural circulation j flow was calculated for the conditions of equilibrium flow and maximum loop i flow impedance. The results given by the model are within 15% of the measured flow values obtained during natural circulatio'n tests conducted at the Ycnkee-Rows plant and confirmed at ' Stan Onof re and Connecticut Yankee. The notural circulation flow ratio as a function of reactor power is given in Table 14.2-4 l It is shown in Section 14.2.11 that a loss of normal feedvater f rom any ccuse, including a loss of offsite ac power, does not result in water relief i from the pressurizer relief or safety valves. l
.. - - - . . . . . - - . _. . - . - - - - . . - . . ~ - ...
l l ~ Attachment 10 l .- j . u ooetente Event t.umoer ofta0
.unevolueted !ctoreetion , .
Pacility i SURAY Cote hetified i 12/09/86 : Unit t 2 Time *:otified i 19804 ! Reyfon i2 Cete of Event i 12/09/86 Vender NEST,*ERT Time of Event i 14:40 Cleggificttien S . Alert Coerotions Officer : % ACM!Mf:Ch Category 1 i SCRAW NRC hetiftec by : SAr.Ltd Ree Release.: Po Category 2 ESP Actuation Cause : rechanical Failure Categoey 3 .- Component r F .4 SVCTION RUPTURE Category 4 8 . l
- f,
- RTR PotER PAICR TO THE EVENT 1005.RTR P0atp AFTER THE EVENT OS. 14 INCH [.
SUCTION LINE 0h MP4 "A" UNIT RUPTURED. 3 PEOPLE CRITICALLY INJURE 0. 2 PEOPLE I HAVE *!h0R INJUR!ES. LEAM HAS WEEN C08PLETELY ISOLATED. 4 RCP'S SUPPLYING PORCED CIECULAT!aN. SECONDARY PCRV'S BEING USED TO C00LOOWN THE PLANT. MOTOR-OP!VEN AUX FEED ..ATEP PUvP SUPPLYING PATEe 70 THE STEAM GENERATOR. OTHER PCTC#-0&!VEM PuuP AND TURF!NE ORIVEN PUMP AVAILASLE ANO IN STAN06Y. 40 LEANAGE FROM TME P*!*ady SYSTEM. PRESSUR!!ER LEVEL AT 255. PLANT !$ STASLE. RI INF0h*ED 8V LICEPSEE. P200(9 LAME),EQ(J0PDAN),(J. ROSENTHAL),NRR INFORME0 PROJECT WANAGEP 19 CENTEE, PEHA(RENEE LITT0h), EPA (MARRY CALLEY), 00E(PHYLIS MC0cNaLD) ANC Mws(GALE SCH'81DT) h0T!PIEO. ==* OPOATE ese LICENSEE REPORTED THAT Cht CONTECL 400 STUCK (DID P OT GET R00 60TT09 LIGHT). OPERATORS ' EkERGENCY a0R ATED PEq pacCEDURES.***UPD ATE 1625e** ALERT TERMINATED , RI w!LL F 8E thPCE*F.3, R2CC(urP!G9T), EO(JCP0AN), (J. 90SE'4Tn AL), PEW 4(AUSTIN), 00E(n. ' ROMINScr ), HMS(e. G80VE) n'.C EPt (wadRY c ALLE T) athE NOTIFIE0 0F THE ALERT SEING TEA!NA TED.
*** UPDATE (03delsee EeTAILisr*: '* 4 AT 53J5. Sc3 Td' P 335 D'04EES, PRESS 310e. .
GothG TC CJLD 3/0. dC? ;EiFLES. G0!hG 70 120 DEGREES. i eseuPC&TECOTn3)**e PEACTa2 !* CrL*, S/me 4 l l i I
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3; s T [s DATE OF EVENT.- 04/01/8; TIME OF EVENT - 0950 DATE OF-NOTIFICATION - 04/01/03 ' TIME OF NOTIFICATICN - 1112 FACILITY NAME - SURRY-1 SEGION - 2 l TYPE CF FACILITY - POWER REACTOR { LICENSEE EVENT CLASSIFICATION - NOTIFICATION OF UNUSUAL EVENT CATEGORIES OF EVENT - CONTAMINATED INJURY _l - CAUSE OF FAILURE - ACCIDENT R&DICACTIVE RELEASE 7 NO , 1 g
. EVENT DESCRIPTION -
g- WORKMAN WAS TAKING OIL COLLECTION SYSTEM OFF RCP. THE-SYSTEM FELL OFF AND STR UCK HIM CN THE HEAD AND SHOULDERS. HE RECEIVED A 6-INCH GASH ON THE HEAD: BLE , EDING STOPPED,' VICTIM CONERENT, ' WOUND CONTAMINATED -- 100,000 CPM ON WOUND. I-h't NJUGED TRANSPORTED TO 9EDICAL L:OLLEGE OF VIRGINIA, RICHMOND. *** UPDATE AT 13 28* **NOUE TEFtt!NATED AT ' 1156. - NO FURTHER INFORMATION AVAILABLE ON INJURED. ACTION TAKEN NY HDO/RDO - RDO J. LANDIS, EO FRANK LANIK, FEMA R. LITTDN FERSON NOTIFYING NRC - C.~ JACKSON FERSON ENTERING REFORT - F. LOMAX/MERRILL i 3 s G -
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Attachment llA INFORMATION NOTICES, BULLETINS, and PRELIMINARY NOTIFICATIONS IE Date Bulletin of Number Subject Issue issued To TEB-83-07 Apparent Fraudulent Products sold 07/22/83 To all power facilities sold by Ray Miller Inc. holding OL or CP. IEB 83-06 Nonconforming materials supplied by 07/22/83 To all power facilities by Tube-Line Corporation. Facil- holding OL or CP. ities at Long Island City. New York, , Houston, Texas, and Carol Stream, Illinois. IEB 83-02 Stress corrosion cracking in large- 03/04/83 Table 1 for BWRs for diameter stainless steel recircula-action, and all other tion systems piping at BWR facilities. licencees and holders of CP. l l 1 l l 1
INFORMATION NOTICES, BULLETINS, and PRELIMINARY NOTIFICATIONS Attachment llB IE Date Information of Number Subject Issue Issued To IN-83-01 Ray Miller, Inc. Some piping was 01/26/83 To all power reactor provided under fraudulant terms. facilities holding OL or CP IN-83-07 Nonconformancies with Materials 03/07/83 To all facilities holding Supplied by Tube-Line Cocoration. an OL or CP, IN-84-63 Defective RHR Replacement Piping. 07/13/84 To all facilities holding an OL or CP IN-84-87 Piping Thermal Deflection Induced 12/03/84 To all facilities holding by Strati fied Flow. an OL or CP. IN-85-24 Failure of protective coatings in 03/26/85 To all power facilities pipes and heat exchangers, holding OL or CP. Deficiencies were found in spray pond piping. IN-85-97 Jail term for former contractor 12/26/85 To all power facilities employee who internationally holding OL or CP. falsified weldino insDeCtion records. The records involved piping, pipe braces, and struc-tural steel, but no particular nuclear systems were specified. IN-86-45 Potential falsification of test 06/10/86 To all reactor reports by Golden Gate Force facilities. and F1ance, Inc. No specific nuclear systems were indicated. IN-86-106 Feedwater Line Break at Surry 2 12/16/86 To all nuclear facilities occurring on 12/09/E6. holding OL or CP. 1 IN-86-108 Degradation of RCS pressure 12/19/86 To all PWRs holding boundary resulting from boric CP or OL. ' acid corrosion. I 2
.- =. - _
O INFORMATION NOTICES, BULLETINS, and PRELIMINARY NOTIFICATIONS
. Attachment ' 11c Preliminary <
Notification Number ~ Subject Date Licensee 11-83-82 Nonradiological Industrial Fatality 10/17/83 Surry 2 This is the only 83' report included. 3 III-84-13 30 Week Outage To Replace 02/03/84 Monticello i Recirculation System Piping II-84-21 Cracks in Replacement Recirculation 03/12/84 Hatch 2 Pipe Elbows. III-84-26 Auxiliary Feedwater Piping Damage. 03/13/84 Palisades II-84-31 Crack in Residual Heat Removal System 05/01/84 Grand Gulf 1 - Piping. I-84-99 Extraction Steam Line Break. 11/21/84 Calvert Cliffs 1 I-84-58 Intergranular Stress Corrosion 07/05/84 Pilgrim Cracking In Pioing Outside Containment. I-84-59 Unscheduled Outage To Repair Pioe 07/05/84 Salem 2 i Leak. l III-84-104 Crack Indication In Recirculation 11/30/84 Dresden ? Pipino. I-84-104 Degraded Salt Water System. '12/13/84 Calvert Cliffs 1 I II-85-20 Thrcugh-Wall Cracks in Piping. 0?/22/85 Brwons Ferry 2 III-85-22 Through-Wall Crack in Recirculation 03/13/85 Duane Arnold Piping. III-85-30 Pipe Crack. 05/02/85 Quad Cities 2 II-85-102 Crack Indications On Surface of 10/31/85 Grand Gulf 1 Recirculation Piping. I-86-58 Drain Line Break. A 6 inch drain 07/29/86 Ginna line from the 2A steam reheater failed. 1 i i I I 1 3
'INFORMATION NOTICES. BULLETINS, and PRELIMINARY NOTIFICATIONS Attachment i t cont.
Preliminary Notification Number Subject Date Licensee II-86-91 Personal Injuries Following Secondary 12/10/86 Surry 2 System P1)e Break. This event occurred on 12/09/436, causing two fatalities. II-86-91C Secondary System Pipe Failure-Update. 12/15/86 Surry 1&2 Ultrasonic testing showed that a piping elbow in Unit I had eroded in a manner similar to that of Unit 2 which caused injuries on " 12/09/86. III-86-70 Through Wall Cracks Found In 07/18/86 La Crosse Non-Isolable Portion of Primary System Piping. I I l t
.i 4
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SSINS No: 6820/5340 OMB No.: 3150-0011' i IEB 83-07 l UNITED STATES NUCLEAR REGULATORY COMMISSION OFFICE OF INSPECTION AND ENFORCEMENT WASHINGTON, D. C. 20555 July 22, 1983 APPARENTLY FRAUDULENT PRODUCTS SOLD BY RAY MILLER, INC. IE BULLETIN N0. 83-07: Addressees: For Action: All nuclear power reactor facilities and fuel facilities holding an operating license (OL) or construction permit (CP). . For Information: Other fuel cycle licensees and Category B, Priority I (processors and distributors) material licensees.
Purpose:
Power reactor facilities were informed in January 1983 by Information Notice 83-01 that fraudulent products may have been sold to nuclear industry companies by Ray Miller, Inc. An updated and comprehensive list of Ray Miller, Inc. customers for the years 1975-1979 was provided to power reactor licensees and to selected fuel cycle and Category B, Priority I material licensees in Supplement 1 to IN 83-01 that was issued on April 15, 1983. Since information is now available regarding specific purchase orders for which materials were apparently substituted, licensees are requested to determine where suspect material has been installed in plants, evaluate its safety significance, and tag or dispose of the suspect material not yet installed. The specific information on apparently fraudulent material covers a five year period and pertains to orders filled by the Charleston office only. Although the Charleston office was apparently the major offender, the other Ray Miller, Inc. branch offices may have also supplied fraudulent materials, in some cases. However, the NRC has been unable to locate any records for review from these other branch offices. In an effort to aid in determining the scope of the fraudulent materials problem, licensees are requested to examine and test materials from other Ray Miller, Inc. branch offices that they have been able to identify, are in stock, but which are not included in the NRC-identified list of apparently fraudulent materials. y< n
i IEB 83-07 i' July 22. 1983 Page 2 of 7 Discussion: During February 1983, the NRC completed a detailed review of 29 file boxes of Ray Miller, Inc. records that were in the custody of the U.S. Attorney's Office in Charleston, West Virginia. These records related to oraers filled by the Charleston, West Virginia branch office of Ray Miller, Inc., and covered the period 1975 through 1979. No other Ray Miller Inc, records have been identified thus far. The data obtained from the records review are presented in Attachment 1. " Fraud Data Base Alpha Sequence Condense." These data are for apparently fraudulent items only, and were selected on the basis of notations made-on the Ray Miller, Inc. work sheets which indicated that unauthorized substitutions or modifications were made. The data are arranged alphabetically by buyer, and include delivery point, order number, order date, line number, material size, material type, fraud code, and consnents. The order number column provides the buyer's purchase order number when this was available. When it was not available, the Ray Miller, Inc. order number is provided. g The order date column lists the date of the buyer's purchase order when this was available. When it was not available, the Ray Miller, Inc. order date is listed. The line number column provides the line number of the buyer's order for which substitution or modification of material was apparently made. The material size column provides a code entry for the size of the material ; involved. For tubing, the size indicates the outside diameter. For pipe, the size indicates the nominal size. For fittings and flanges, the size indicates l the nominal pipe diameter for the material, however, there may be some incon'- sistency in recording values in these cases. The codes are as follows: Material size codes: 0 = 1" or less ' l = greater than 1" and less than or equal to 2" 2 = greater than 2" and less than or equal to 4" 3 = greater 1han 4" ; The material type column lists a code entry for the type of material involved. All items that are not piping or tubing are included in fittings and flanges. The codes are as follows: Material type codes: PIPE = Piping ' TUBE = Tubing FTFL = Fittings and Flanges : l The fraud code column provides a code entry for the type of substitution or modification that was apparently made. Dual or multiple entries for fraud i code indicate either substitutions of more than one type or that a determination of which substitution was made could not be established from the information available. l
IES 83-07 July 22, 1983 Page 3 of 7 Fraud codes: W = Welded for Seamless C = Carbon Content (Std. grades of stainless steel for low carbon or in some cases low carbon for Std.) F = Foreign-made for Domestic-made X = Forming or Machining performed P = Pressure Ratings substituted T = All others, e.g., 304 55 for 316 SS The and/or column indicates whether multiple entries for the fraud code were multiple substitutions (AND column) or detemination of which substitution was made could not be established (OR column). The comments column presents various notations that were found on the Ray Miller, Inc. work sheets. - Attachment 2 " Fraud Data Fase Condense Buyer / Delivery Point Of ffer" is a different sorting of selected data contained in Attachment 1. In this case, the data are arranged alphabetically by delivery point and only include data when the receiver (delivery point) differs from the buyer. This presentation is useful to identify materials that were delivered directly to a company that did not originate the purchase order. The fraud data base file is not complete in all cases. Some of the information was not available from the Ray Miller, Inc. records. Items from the NRC work sheets have been compared with the computer file only for NRC licensees and 00E contractors. For these items, 100 percent accuracy was verified. At approximately the same time this Bulletin is issued, the NRC will be sending a letter to each non-licensee company that received apparently fraudulent ma-terial from Ray Miller, Inc. Appropriate portions of the fraud data file will i, be included. These companies will be asked to identify any nuclear facility i that may have been supplied the fraudulent materials. They will be asked to notify licensees, as appropriate, and the NRC by August 31, 1983. J The actions listed below deal primarily with material included in the fraud data base file, however, the actions also include a request to examine and test a sample of other materials supplied by Ray Miller, Inc. that are still in stock, regardless of which Ray Miller branch office supplied the material. The basis for this request is the need to compile and evaluate data on the quality of ship- l i ments that were presumed " legitimate." The results of this evaluation will be 4 provided to the nuclear industry on a timely basis. Action Requested of Nuclear Fuel Cycle Licensees (Except As Noted Below) and j Category B, Priority I Material Licensees: This Bulletin is provided for information only. No specific action or response is required. Action Requested of All Nuclear Power Reactor Facilities and Fuel Facilities Holding an OL or CP: Within eight months of the date of this bulletin complete the actions identified in items 1 throt,gh 4:
IEB 83-07 July 220 1983 Page 4 of 7
- k. Based on a review of the attached lists of Ray Hiller, Inc. ~ customers who received apparently fraudulent materials (Attachments 1 and 2), and pertinent infomation obtained from any of these companies, either directly or indirectly: *
(a) Identify those companies on the lists that supplied nuterials or services to your facility (include subcontractors as well as major contractors);and (b) Determine whether any of the apparently fraudulent Ray Miller, Inc. materials were provided to or used at your facility.
, (c) Determine whether any of the apparently fraudulent material supplied -
to you was installed in safety-related systems ** at your facility, or is still in stock. (d) If other Ray Hiller, Inc. materials not listed in Attachments 1 and 2 have been identified by your own initiative, determine whether any was installed in safety-related systems ** at your facility, or is still in stock. .
- 2. For Ray Miller, Inc. materials, both the NRC-identified apparently fraudulent materials listed in Attachments 1 and 2, and other materials identified by your own initiative, that are installed in safety-related systems ** of your facility:
(a) Evaluate the safety significance of the presence of these materials assuming the fraud is as identified in the attachments or assuming material failure. (b) Determine the disposition of the installed material; e.g., use as is, remove and replace, etc.
- 3. For all material from Ray Miller, Inc. still in stock, whether identified by item 1 or previously identified by your own initiative:
To aid in this identification, a supplement to this Bulletin will be issued within 75 days from the date of this Bulletin to provide the results obtained from the survey of non-licensee companies that received apparently fraudulent material . However, this does not relieve the licensees of the responsibility of contacting their suppliers to ascertain whether any of the material listed in Attachment I has been supplied to their facility.
** For the purpose of the applicable actions of this bulletin " safety-related" th constitutes Appendix A those systems Sections covered
!!!.(c)(1), !!I. by(c)e definition oiven (2),and!!!.Ic)(3). in 10 CFRthe In assessing Part 100 impact of Ray Hiller, Inc. supplied materials in other systems at their facilities, licensees should consider the provisions of GOC 1 to 10 CFR Part 50 Appendix A.
i h .
IE8 83-07 agebf (a) Segregate into two groups: (1) material included in the purchase orders ' listed in the fraudulent data file, and (2) all other material supplied by Ray Miller, Inc., regardless of the branch office that I supplied the material. l (b) For the material included in the fraudulent data file:
- (1) Discard the material, or (2) Tag or otherwise mark the materials for use only in Systeus not important to safety.
1 (c) For material supplied by Ray Miller that is not included in the fraudulent data file, do one of the following: (1) Discard the material. f (2) Tag or otherwise mark the materials for use only in systems not important to safety, or . (3) Subdivide material into groups of identical items and examine and test material in each group in accordance with either ites (i) or (ii), below: * (i) Perform sufficient comprehensive examinations and tests to qualify each group of material for use in systems important to safety. If there are less than 10 identical items in the group, each item should be examined. If there are 10 or more identical items, a statistical sampling plan may be used to demonstrate with 90% confidence that 90% of the material conforms to the purchase specifications. Groups of material found acceptable may be used as desired. (ii) Perform comprehensive examinations and tests of a limited sample of each group of identical items. The minimum sample size is to be two items, or 10% of the items in the group, whichever is greater. Examination and test of this limited sample does not provide a high degree of assurance that the entire group satisfies the procurement specifications. The NRC will Compile the resuTts of all the data received, detemine the statistical significance of the results, and advise industry of the overall results and conclusions. Therefore, a utility should not use this material in systems important to safety until the NRC's evaluation is complete. 1
= 1.tcensees are encouraged to perform examinations and tests rather than to '
discard the material, even though the economic incentives probably favor ! discarding the material. Data obtained in response to this Bulletin will be I compiled by the NRC and disseminated to the industry. The extent to which I this material deviates from its procurement specifications may be an important consideration in evaluating the safety significance of Ray Miller. Inc. material not included in the fraudulent data file, i
IE8 83-07 1983 July Page 22,f 6o 7 ! 4. Provide a written report describing the results of the actions in items 1 through 3. Table 1 (Attachment 3) provides a suggested format for reporting the results of the examination and testing of materials. The written report requested by item 4 above should be submitted to the appropriate Regional Administrator under oath or affimation under provisions of Section 182a, Atomic Energy Act of 1954, as amended. In addition, the original copy of the cover letters and a copy of the reports should be transmitted to the U.S. Nuclear Regulatory Commission, Document Control Desk, Washington 0.C. 20555 for reproduction and distribution. Because it appears that some equipment suppliers may be substituting substandard or nonconforming materials when filling orders, licensees are cautioned to be particularly sensitive to this issue. For example, in addition to the Ray Miller, Inc. problem, the NRC has substantiated that some nuclear power plants were supplied with nonconforming pipe fittings and flanges by the Tube-Line Corporation (see IE Sulletin 83-06). Therefore, although the specific details involving apparently fraudulent materials received from Ray Miller, Inc. may not directly apply for your facility, you are requested
- to review the general concerns expressed in the Bulletin for applicability at your facility. Your response should describe the results of the review, and if the general concerns apply, you should describe the short-term and long-term corrective actions to be taken and the schedules thereof.
This request for information was approved by the Office of Management and Budget under clearance number 3150-0011. Consents on burden and duplication should be directed to the Office of Management and Budget. Reports Management. Room 3208 New Executive Office Building Washington, D.C. 20503. Although no specific request or requirement is intended, the following information would be helpful to the NRC in evaluating the cost of this Bulletin:
- 1. Staff time to perform requested review and testing. ,
- 2. Staff time spent to prepare requested documentation.
If you have any questions regarding this matter, please contact the Regional Administrator of the appropriate NRC Regional Office, or one of the technical contacts listed below.
,:=-
Richard C. tor Office of in ho.Di n and Enforcement Technical Contacts: Mary)S. Wegner, IE (301 492-4511 Ronald M. Young, IE (301)492-9672 Attachments: see page 7 l l 1 l k
IE8 83-07 1983 July Page 22,f 7o 7 Attachments:
- 1. Fraud File, Alphabetical by Buyer
- 2. Fraud File, Buyer and Delivery Point Differ, Alphabetical by Delivery Point
- 3. Table 1 - Material Examination and
< Test Results
= 4. List of Recently Issued IE Bulletins i 0 1 4 I t 4 n- ,----,-- -,. ,- - - - - - - - , . _ - . _ , , , , . - - , - ,, ,n , ,-c,,n-.--, ,,-- ,n-.,., -, ,, ,,. , - . , - - -
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SSINS No.: 6820 OMB No.: 3150 0011 IEB 83-06 UNITED STATES i NUCLEAR REGULATORY COMMISSION OFFICE OF INSPECTION AND ENFORCEMENT
; WASHINGTON, D.C. 20555 July 22, 1983 IE BULLETIN NO. 83-06: NONCONFORMING MATERIALS SUPPLIED BY TU8E-LINE CORPORATION FACILITIES AT LONG ISLAND CITY, NEW YORK; HOUSTON, TEXAS; AND CAROL STREAM, ILLINOIS Addressees:
For action: All nuclear power reactor facilities or fuel facilities holding an operating - license (OL) or construction permit (CP). I
Purpose:
' Power reactor and nuclear fuel facilities received initial notification of non-conformities with materials supplied by Tube-Line Corporation (T-L) in Informa-tion Notice No. 83-07 dated March 7, 1983. This bulletin is being issued as a result of the findings from Region IV Vendor Program Branch inspections at the T-L facilities at Long Island City, New York; Houston, Texas; and Carol Stream, Illinois. It was concluded from these inspections that there are potential generic safety impitcations at plants which either have received direct shipment materials fu.nished by T-L (i.e., pipe fittings and flanges) or receive piping subassemblies and other components from holders of ASME Certificates of Authori- 1 zation which incorporate these materials. Therefore, we ask all recipients of i this bulletin to review the information herein for applicability to their ! facilities and: (1) to take appropriate actions to confirm the adequacy of l affected components for intended service; or (2) submit reports stating that T-L materials received from the referenced manufacturing locations will not be used in safety-related systems at their facilities. Description of Circumstances:
- 1. On December 6, 1982, Capitol Pipe and Steel Products Company (CPSP Co.)
sent a letter to the NRC which identified nonconformities with certain materials that they had obtained from T-L and furnished to their customers. In this letter, CPSP Co. identified the customers who had received the T-L materials and stated that the customers had been notified in regard to the material nonconformities. The products identified by CPSP Co. were carbon steel pipe fittings (caps, tees, and elbows) and flanges. The nonconform-ities ideritified were shipment from an unapproved nuclear source, failure to i
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l TEB 83-06 July 22, 1983. Page 2 of 1 perfom required heat treatment, and failure to perform nondestructive examinations in accordance with the applicable provisions of the ASME Code. l 1
- 2. A 10 CFR Part 21 report dated January 10, 1983, was received from the )
Babcock & Wilcox Company (B&W) which additionally addressed T-L carbon i steel materials that had been furnished by CPSP Co. This report stated i that certain materials furnished to B&W had been supplied by the Houston, Texas, facility of T-L which was not an approved nuclear supplier per NCA-3800 requirements. It was additionally stated that B&W had perfomed mechanical testing of four heats of received fittings and flanges and had found that the strength properties in two heats of flange materials were i; lower than shown on the material certifications; ou heat was below the ! minimum requirement .in the procurement specification. Subsequent testing ( initiated by Carolina Power & Light Company has further identified strength l properties in fittings (caps) that were below :naterial specification
- requirements and differences in chemical analysis from that reported on the
, T-L Certified Material Test Report. i, l
) 3. Of rect inspections by the Region IV Vendar Program Branch have identified l discrepant conditions at both the T-L carbon steel facilities in
. Long Island City, New York; and Houstan, Texas; and the stainless steel facility in Carol Stream, Illinois. Known and intended recipients of these materials are listed. in Tabl's 1 - Carbon Steel (see Attachment 2) j and Table 2 - Stainless Steel (sea Attachment 3).
1 i 4. As a result of the inspections performed by the Region IV Vendor Program Branch, the following additional pertinent information has been obtained in regard to materials furnished by T-L:
- a. Certain carbon steel materials were procured from unsurveyed s'ources and improperly certified to CPSP Co. and Dravo Corporation, Marietta, Ohio, as having been manufactured in accordance with the quality program which CPSP Co. and Dravo Corporation had audited and approved i as meeting the requirements of NCA-3800 in Section III of the ASME 1 Code. Similarly, certain stainless steel materials were procured from unsurveyed sources and improperly certified to customers as having been manufactured in accordance with the requirements of NCA-3800 and l referencing the T-L (Carol Stream) ASME Certificate of Authorization t
No. QSC-435. It was additionally established at T-L (Carol Stream) that the basis for approval of some vendors of materials and services (i.e., heat treatment, NDE, mechanical testing, and chemical analysis) was a self-evaluation form filled out by the vendor,
- b. Numerous instances were observed at T-L (Long Island City) in which comercial carbon steel materials (i.e., materials procured solely i
in accordance with a material specification) had been procured and manufacturing had been completed before the establishment'of the T-L quality program. These materials were then furnished to CPSP Co. . , and Dravo Corporation and improperly certified as being both in l j accordance with specified Section III of the ASME Code requirements l , and as having been manufactured in accordance with the quality program i 1 _ . ~ - - - - . . - - - - - - . - - _ - - . - - , . - - . . - _ . _ - . . , _ - _ . - _ , , - _-_. .- .-
IEE 83-06 July 22, 1983 Page 3 of 6 which these companies had audited and approved as meeting the require-men:s of Section III of the ASME Code. Similar procurement and certi-
- fication of commercial stainless steel materials was identified by direct inspection at T-L (Carol Stream).
! c. Several 3", 600 lb. ASTM A105 carbon steel weld neck flange forgings j (e.g., 362 from T-L Heat Code EUUA and 1480 from T-L Heat Code EKP) ! which have not been appropriately heat treated have been shipped to various customers (both nuclear and non-nuclear). Similarly, the NRC has been notified that documentation was not available to demon-strate that approximately 530 SA-182 stainless steel flanges received the required solution annealing heat treatment. These flanges have . been shipped to .various customers.
- d. Direct inspection has resulted in the current identification that
- T-L (Carol Stream) furnished 521 stainless steel fittings welded with i filler metal to various customers and that vendor documentation for #
1 these fittings does not indicate compliance with Section III of the ASME Code requirements in regard to: ~ (1) Manufacture by a holder of a ASME Certificate of Authorization for an NPT symbol using the ASME accepted QA program.
! (2) Use of welders and welding procedure specifications which have L been qualified in.accordance with the requirements of Section IX ; of the ASME Code.
(3) Inspection during manufacture by an Authorized Nuclear Inspector
- and certification by issue and signing of a Partial Data Report
! Form NM-1.
i e. Foreign material manufacturers were surveyed and approved by T-L (Long Island City) representatives as having documented quality
- assurance programs which were in compliance with the requirements of NCA-3800 in Section III of the ASME Code. Interviews and examinations of available survey / audit records established, however, the following: l 1
(1) Certain manufacturers were approved although they did not, in fact, have documented quality assurance programs. 1 (2) Other manufacturers were approved although their documented quality assurance programs were not available in the English language and the auditors were unable to read the applicable q quality assurance manuals. l (3) Certain manufacturers were maintained on the Qualified Supplier List after identification that previous surveys / audits had improperly stated that the documented quality assurance programs 2 were in full compliance with the requirements of NCA-3800 in j Section III of the ASME Code, i j . l
IE8 83-06 July 22, 1983
- - Page 4 of 6 I f.
. Materials were procured tion of the applicable for T-Lexamination nondestructive (Long Island NDE)City)(without requirementsspecifica-j contained in Section III of the ASME Code. Subsequent purchase orders . to NDE subcontractors referenced either that only commercial NDE was ! required or specified that a paragraph in Section III of the ASME Code l ' was applicable without reference to or assuring use of an approved NDE procedure. Failure to assure use of approved subcontractor NDE proce-i dures was also identified at T-L (Carol Stream). It was further ! established that T-L (Carol Stream): (1)failedtohaverecords i ! demonstrating that lli and PT was perfomed; (2) had no records of eye ] examinations being given to their level II examiner; (3) failed to have i qualification records of their NDE subcontractor's personnels and j (4) did not address acceptance criteria in their PT procedure. 4
, 5. Tube-Line Corporation representatives, in a letter to Region IV dated ;
April 8,1983, stated they would send letters to all identified end-users i of their carbon steel products in nuclear facilities. The letters would - l request meetings with the affected end-users to determine whether the l products met the necessary requirements, or to detemine whether upgrading ! or replacements are necessary. Additionally T-L In letters to Region IV 1 (dated April 25, April 27, May 3. May 6, and May 13,1983), stated they would send letters to the identified end-users of their stainless steel i products of concern. ' i 6. The information available to date indicates that T-L started supplying l ASME Code components to the nuclear industry in 1981. i Actions To Be Taken by Holders of Operating Licenses or Construction Pemits: i 1. Review the lists of purchasing and receiving companies given in Attachments l I 2 and 3 and determine if any T-L supplied ASME Code materials have been I furnished to your facility. The lists of purchasing and receiving companies i given in Attachments 2 and 3 have been developed based on correspondence from
- T-L and inspections at T-L; however, NRC has not verified the completeness 1 of these lists.
I i 2. For ASME Code materials furnished by T-L which are either not yet installed in safety-related* systems at your facility or are installed in safety-related < j systems of plants under construction, the following actions are requested: i (perfom action a and either action b or c) !
- a. Provide a list of T-L supplied materials and identify the systems j in which these materials are/will be installed.
I i *For the purpose of the applicable actions of this bulletin " safety related" i
' constitutes those systems covered by the definition Appendix A Sections !!I.(c)(1), !!!.(c)(2), and III.given in 10 In (c)(3). CPR Part 100, assessing.the i
impact of T-L supplied materials in other systems at their facilities, licensees ] should consider the provisions of GDC 1 to 10 CFR Part 50 Appendix, A. 1
IEB 83-06 July 22, 1983 Page 5 of 6 ( b. Implement a program which provides assurance that received ma comply with ASME Code Section III and applicable procuremen requirements, intended service. or which demonstrates that such materials are suita This program should include specific verification condition, that received austenitic stainless steels are in a nonsen c. Replace fittings and flanges with materials which have been man in full ment compliance specification with ASME Code Section III and the applicab r.equirements. - 3. For ASME Code materials furnished by T-L which are installed in - related* systems in operating plants, the following actions are reque a. Provide a list of the T-L supplied materials and identify the system in which the materials are installed. b. Implement a program as discussed in 2b or 2c above. c. 4. by Item 3b has not been completed by the tim . Provide either: a written report within 120 days of the date ofa this bulletin t a. States facility forthat use no T-L supplied in safety-related systems. raterials have been furnished for your b. Provides the results of those actions taken in response to Items 2a, 2b, and 2c above, as they apply to materials not yet installed and to materials installed in plants under construction. The report should and/or 2c.include your plan and schedule for completing actions 2b c. Provides the results of those actions taken in response to Items 3a 3b, and plants. 3c above, as they apply to materials installed in opera , item 3b and your basis for continued operation if completed. Although the specific details involving the nonconforming materials supplied by T-L may not directly apply for your facility, you are requested toatreview applicability the general concerns expressed in the bulletin for your facility. of the review, and if the general concerns apply, you should de short-term thereof. and long-term corrective actions to be taken and the sche
*For the purpose of the applicable actions of this bu Appendix A Sections III.(c)(1), III.(c)(2), and III.(c)(3). .
should consider the provisions of GDC, licensees 1 to *10 CFR P
l IEB 83-06 l July 22, 1983 ; j , Page 6 of 6 l The written reports required.by Items 4a, 4b and 4c above shall be submitted to i the appropriate Regional Administrator under oath or affirmation under the pro- l visions of Section 182a, Atomic Energy Act of 1954 as amended. In addition, the original copy of the cover letters and a copy of the reports shall be transmitted ~ to the U.S. Nuclear Regulatory Commission, Document Control Desk, Washington, D.C. [ 20555 for_ reproduction and distribution. l This request for information was approved by the Office of Management and Budget under clearance number 3150-0011. Although no specific request or requirement is intended, the following information would help the NRC evaluate the cost of implementing this bulletin:
- 1. Utility staff time to perform requested inspections and evaluations.
- ! 2. Radiation exposure attributed to requested inspections.
- 3. Utility staff time spent to prepare written responses.
If you have any questions regarding this matter, please contact the Regional i Administrator of the appropriate NRC Regional Office, or the technical contact i listed below, i j -
- h.
Richard C. un etor Office of I ctbnOrndEnforcement
! Technical
Contact:
J. R. Fair, IE J (301)492-4509 Attachments:
- 1. List of Recently Issued IE Bulletins
! 2. Table'l - Listing of known and intended recipients of Tube-Line i Corporation furnished carbon steel materials
- 3. Table 2 - Listing of known and intended recipients of Tube-Line Corporation furnished stainless steel materials 1
l i
- 1
,__,._.._._._,_a
- Attachment 1 IEB 83-06 July 22, 1983 LIST OF RECENTLY ISSUED IE BULLETINS t
Bulletin Date of i
- No. Subiect Issue Issued to 8eb 83-05 ASME Nuclear Code Pumps and 05/13/83 Utilities with power
; Spare Parts Manufactured by reactor facilities
- The Hayward Tyler Pump holding an OL or CP
! Company ' . use or plan to use i
ASME Nuclear Code j Pumps Mfg by Hayward Tyler Pump Co. I i' 83-04 Failure of the Undervoltage 03/11/83 All PWR facilities Trip Function of Reactor Trip holding an OL except
... Breakers W D8 type breakers j
Tor action and other
~ nuclear reactor facil- -
ities for informa-g tion 83-03 Check Valve Failures in Raw 03/11/83 All power reactor Water Cooling Systems of facilities holding Diesel Generators an OL or CP i i 83-02 Stress Corrosion Cracking 03/04/83 Table 1 BWRs for 1 in Large-Diameter Stainless action and all other l Steel Recirculation System Itcensees and holders Piping at BWR Plants of a CP 83-01 Failure of Reactor Trip 02/25/83 All PWR facilities
! Breakers (Westinghouse 08-50) holding an OL and i to Open on Automatic Trip other power reactor Signal facilities for information
- 82-04 Deficiencies in Primary Con- 12/03/82 All power reactor i tainment Electrical Pene- facilities holding
{ tration Assemblier an OL or CP 82-03 Stress Corrosion : racking in 10/28/82 Operating BWRs in Rev. 1 Thick-Wall Large-)iameter Table 1 for action
! Stainless Steel Recircula- and other OLs and cps tionSystemPipIngatBWR for information Plants l
l i i OL = Operating 1.tcense ' i CP = Construction Permit ! i i l
, . _ . . , . . _ , . _ , . . - - - , _ _ , . _ , ~ . _ , . , . , . . - , . _ _ . _ . . - - . . _ . , . . _ . . _ , , _ _ _ _ _ - . . . _ ... .,_ _ ..-. .., m . . . . - . , - , , . _ - . - , _ , , . ,
Attac .ent 2 IEB 83-06 July 22, 1983 Page 1 of 3 _ TABLE I - CARBON STEEL PURCHASER RECEIVING COMPANY ' Dravo Corporation Dravo Corp. _ NUCLEAR PLANTII)(If Known) Seabrook, Units 1 & 2 Capitol Pipe & Steel Wolf Creek Products Coc:pany Tennessee Valley Authority (TVA) TVA Bellefonte TVA Watts Bar Sequoyah Pipe Lining & Coating Co., College Point, NY - Metal Bellows Co., Chatswor'h, t CA Peter Kiewit . WPPSS Pullman Power Products. Paramount, CA -- Carolina Power & Light Co. Shearon Harris Duke Power Co. Catawba RECO Industries Richmond, VA Shearon Harris Catawba Florida Power & Light Co. ' St. Lucie Babcock & Wilcox Co., Barberton, OH (1)purchasing The NRC has not and receiving verified companies that the list of Nuclear Plants is complete. receiving Tube-Line materials thr'; ugh ~any of the listed
Attac.s nt 2 IE8 83-06 July 22, 1983 Page 2 of 3 TABLE 1 - CARBON STEEL PURCHASER RECEIVING COMPANY ORACLEAR PLANTIII(If Known) Capitol Pipe & Steel Georgia Power Co. - E. I. Hatch Products Company Baltimore Gas & Electric Co. Calvert Cliffs Stone & Webster Engineering Corp. Nine Mile Point. Unit 2 Pittsburgh Des Moines 8eaver Valley, Unit 2 Duke Power Co. Oconee l l Koch Process Systems. Westborough, MA -- 1 Chicago Bridge & Iron, Birmingham, AL -- Public Service Electric & Gas Co. Salem Baldwin Associates Clinton Magnetrol. Downers Grove IL -- Florida Power & Light Co. Turkey Point l Stone & Webster Engineering Corp. Millstone. Unit 3 Westinghouse , (1) The NRC has not verified that the list of Nuclear Plants receiving Tube-Line anterials through any of the listed purchasing and receiving companies is complete.
Attac. a t 2 IE8 83-06 July 22, 1983 Page 3 of 3 TABLE 1 - CARBON STEEL PURCHASER RECEIVING COMPANY NUCLEAR PLANTIII(If Known) Capitol Pipe & Steel Crane Cb M, Warrington, PA -- Products Company ITT Grinnell, Milwaukee, WI - j Ionics, Inc., Bridgeville, PA --
\
Portland Eng., Co., Portland, ME -- Hap Dong Express, Inc., Brooklyn, NY -- Toledo Edison Co. Davis-Besse United McGill Corp., Columbus, OH -- Woolley Mfg. , Canton, OH -- Cherne Contracting Monticello j
- 8. F. Shaw, Wilmington, DL TVA
- Prefex McQuary, New Berlin, WI --
Northeast Utilities, Waterford, CT -- GPU Nuclear, Sales, NJ -- (1) The NRC has not verified that the list of Nuclear Plants receiving Tube-Line materials through any of the listed purchasing and receiving companies is complete.
. 4 - , - --
l Attach ===t , IES 83-06 l July 22, 1983 l Page 1 of 2 TABLE 2 - STAIIE.ESS STEEL PURCHASERS BECEIVING CGIFANY DISCBEPAIICV III M EAR M ANT (2){gg y Capitol Pipe & Steel Bechtel Power Corp. B Palisades Products Company Tennessee Valley Authority B Matts Bar
. Balduin Associates A Clintoe stetal Bellows, Chattsworth, CA - -
UESC - Davis-Besse 58830 - -- Chicago Tube & Iron Co. r - alth Edison Co. A&B - Byron Station Guyon Alloys Seco Industries Richmond, VA A&B -- Northeast utilities A ~ Millstone Units 1 & 2 Pittsburgh Des Maines Steel B San Gnofre Corp., Provo, UT Bechtel Power Corp. A Hope Creek Bechtel Power Corp. A&B Limerick Balduin Associates B Clinton D. G. O'Brien A Niagara flohawk Bell Schneider A Ginna Duke Feuer - Catauha Bechtel - Palisades l Midland l Portland Engineering. - -- Portland IE Tubeco Tubeco., Inc., Brooklyn, BY B - . Joliet Valves Inc. re lth Edisen Co. B Quad Cities . Lisguld Carhenics, c/o 8 -
- 8. Alger Co., Kenner LA (1) Discrepancy: A. Solution Annealing Heat Treatment flot Performed
- 8. Fittings Melded with Filler Metal (2) The NRC has not verified the list of Iluclear Plants receiving Tube-Line materials through any of the listed purchasing and receiving campanies is complete.
Attachment . IEB 83-06 July 22, 1983 Page 2 of 2 TABLE 2 - STAlfa.ESS STEEL ' PURCHASERS RECEIVING COMPANY DISCREPANCY (I} Liquid Carbonics, NUCLEAR PLANTI2)(If Known) Buenos Aires A Joliet Valves, Argentina Inc., -- Minooka, IL A Barr Saunders Braidwood Gulf Alloy Cocoonwealth Edison Co. A Gulf Alloy, Houston, TX Zion Carolina Power & Light A Hub, Inc. - Hub, Inc., Tucker, GA H. B. Robinson Niagra Mohawk . A Georgia Power - - Florida Power a Light - Nine Mile Pt. Atlas Alloys - Hatch Atlas Alloys Turkey Pt. Louis P. Canuso Inc. Bechtel - TEK - TEK Susquehanna Gray Pipe - Gray Pipe -- Liberty Equircent - Bingham-Willamette, -- Portland, OR - Bechtel - Consolidated Pipe & - Supply Co. Georgia Power Midland Hatch Vogtle
* (1) Discrepancy: A.
B. Fittings Welded with Filler MetalSolution e Annealing Heat Treatment Not (2) The NRC has not verified the list of Nuclea purchasing and receiving coceanies is completer Plants receiving Tube-Line mat of the listed
SSINS No.: 6820 OM8 No.: 3150-0096 Expiration Date: 12/31/84 IEB 83-02 UNITED STATES NUCLEAR REGULATORY COMMISSION OFFICE OF INSPECTION AND ENf0RCEMENT WASHINGTON, D.C. 20555 March 4,1983 IE BULLETIN NO. 83-02: STRESS CORROSION CRACKING IN LARGE-DIAMETER STAINLESS STEEL RECIRCULATION SYSTEM PIPING AT BWR PLANTS Addressees: Those licensees of operating boiling water reactors (8WRs) identified in Table 1 for action. All other licensees and holders of construction permits (cps) - for information only.
Purpose:
IE Bulletin 83-02 is issued to further inform all Ifcensees and CP holders about the recent generic pipe cracking problems involving BWR plants and to require actions of those licensees listed in Table 1. Description of Circumstances: As a result of the extensive intergranular stress corrosion cracking (!GSCC) found at Nino Mile Point Unit 1, the NRC issued IE Bulletin 82-03, Revision 1 for action to nine BWR plants scheduled for refueling outages in late 1982 and early 1983. Inspections pursuant to IEB 82-03, Revision 1, and NUREG-0313, Revision 1, have shown cracking of the main recirculation system piping in l five of seven plants examined to date. Table 2 presents a summary of affected plants based on information available to date. IEB 82-03 Rev.1 discusses the IGSCC problems experienced at Nine Mile Point Unit 1. A brief description of the cracking problems at Arowns Ferry Unit 2, Monticello and Hatch Unit 1 is presented below. At Browns Ferry Unit 2, the inservice inspection (ISI) was extended to include the welds joining the jet pump piping sweapolets to the manifold of both A and 8 loops. Unacceptable indications were found in the heat-affected zone of the manifold in the loops A and 8 sweepolet-to manifold joint nearest the end caps. All of the indications were interpreted to be cracks near the inside surface and were determined by UT to be about II: inches long (roughly parallel to the weld), and of about 20 percent depth through-wall. As a result of further design analysis, review of shop fabrication records, and supporting in-situ metallography and ferrite determinations, the licensee established that the affected wold was solution heat treated and, therefore, not subject to the 10$CC. The licensee believes the cracking may be duo to fatigue from flow induced vibration. At this time the licensee is trying to resolve the problem.
---8312000M - 1
IEB 83-02 March 4, 1983 Page 2 of 6 At Montice110, IGSCC was confirmed in one end-cap-to pipe weld of the 22-inch-diameter distribution header (manifold) and at five welds in the jet pump inlet piping safe-ends which are 12 inches in diameter and are made of schedule 80 stainless steel. The cracks initiated on the inside surface in heat affected zones (HAZs) of the welds. Some cracks were oriented axially and some circum-farentially. They varied from inch to 1 inch in length. Some axial cracks in the recirculation inlet risers were found to be through-wall during subsequent repair activities and hydrotesting, although ultrasonic examination previously performed on these welds did not reflect this condition. At Hatch Unit 1, multiple If near indications characteristic of the !GSCC found at Monticello were identified at seven welds in the large-diameter recirculation and associated residual heat removal (RHR) piping. The affected welds were located as follows: All four 22-inch-diameter manifold end-caps, one 22-inch-diameter branch connection (sweepolet-to-manifold) of the recirculation piping, one elbow-to pipe weld in the 20-inch RHR piping, and one pipe-to pipe weld in the 24-inch diameter RHR piping. The location and orientation of the indications were very similar to those found at Monticello. The length of the ' indications ranged up to \ inch in the axial direction and 1 -inch in the circumferential direction. Based on UT measurements, the depth of axial component of the crack indications were found to have essentially penetrated through the wall in three of the four end-cap welds repaired to date. The discovery of extensive IGSCC in the large-diameter recirculation piping at Nine Mile Point Unit 1 (NMP 1) after a decade of acceptable service has resulted in increased concern about the effectiveness of UT methodology used in the inservice inspection of stainless steel BWR pipe welds, particularly in ! large-diameter piping. Therefore, the goal of Item 1 of IEB 82-03, Revision I was to obtain reassurance of the capability of UT inspection systems, techniques, and operators to detect significant IGSCC problems in the nine BWR plants that were performing ISI during fall / winter outages. The performance test protocol as stated in Item 1 of IEB 82-03, Revision 1 required the Itcensee and/or ISI agencies to demonstrate their capability to detect IGSCC in large-diameter recirculation system piping before resuming power operation. Within this context, Electric Power Research Institute's NDE (EPRI-NDE) Center arranged to have five reasonably characterized, service-induced cracked pipe samples from the NMP 1 plant available at Battelle Columbus Laboratories (DCL) for industry performance capability demonstrations (PCDs). All nine plants have now satisfied the demonstration phase of IEB 82-03, Revision 1. By letter dated January 28, 1983, EPRI provided each licensee a s umary of all teams performances, based on composite results from the five samples, plus a key to identify their IS! team's achievement. The PC0 results at BCL have shown that excellent performance can be achieved by well trained and experienced personnel with appropriate procedures and evaluation methods. However, personnel from a relatively few licensee /ISI organizations achieved this level of competence during the first qualification attempt. The overall results revealed a high failure rate which required ratesting of the Itcensee/IS! organization teams. Several interrelated factors contributed to l this rate of failure: l l
IEB 83-02 March 4, 1983 Page 3 of 6 1. UT procedures essentially meeting only the minimum requirements of the ASME Section XI code were ineffectiva.
- 2. UT procedures lacked specific detailed guidance on UT systems and methods proven capable of detecting IGSCC in thick walled piping.
3. Some UT operators were inexperienced in evaluating signal patterns of reflectors in thick walled, large-diameter piping. Thus, some cracks were missed, or were called geometry effects; some geometry effects were falsely called cracks. 4. Many UT operators, inexperienced about the nature of IGSCC in large-diameter piping, did not establish finite metal path calculations during scanning; this resulted in falsely identified conditions. In view of the collective results at BCt., a continuation of the PCO program appears necessary. Accordingly, the EPRI NDE Center has arranged to have a series of service-induced cracked specimens available for this purpose at their facility about March 14, 1983. The NRC recognizes that the prescribed actions of this bulletin exceed present plant ISI survel11ance requirements under ASME Code Section XI rules. However, t in view of the apparently generic pipe cracking experience and results of the UT demonstration trials, the NRC believes such an augmented ISI plan is necessary to reasonabl operations. y assure the integrity of the recirculation system for continued These actions are intended to apply only to the currently scheduled refueling outage for those plants listed in Table 1. Any licensee who finds these actions will significantly impact the duration of the refueling outage may request relief by written request to the appropriate NRC regional office. Such requests must address (1) the impact on the length of the outage, (2) proposed alternative actions, and (3) technical basis for continuing operation. Actions to Be Taken by Licensees of BWR Facilities Identified in Table 1: 1. Before resuming power operations following this scheduled or extended outage, the licensee is requested to demonstrate the effectiveness of the detectior capability of the UT mothodolo welds in recirefrculation system piping.gy It planned to be that is intended usedthe to examine demonstrations be performed at the EPR! NDE Center on service-induced cracked pipe samples made available for this purpose. Each licensee should assure system that theofdemonstration piping is valid for the weldments of the recirculation their plant. Arrangements should be made to factittate NRC witnessing of those tests. The demonstration tests wt11 employ the following critoria.
- a. Ultrasonic Testina System: To ensure that the field UT system will respond in the same way as the demonstrated system, the same procedures, standards, make and model of the UT instrument, and transducers to be utilized in the plant ISI are to be used in the !GSCC detection capability demonstration.
r IEB 83-02 March 4, 1983 Page 4 of 6
- b. Personnel Performino Demonstration: UT personnel teams drawn from the licensee /ISI contractor who will be actually supervising, performing examinations, recording data, and evaluating indications at the plant site will participate in the performance demonstration tests. All members of the teams must participate directly in the UT scanning, data recording, and evaluation of the test samples. To ensure completion of testing within the time constraints below, the team should be Ifmited to six persons. For subsequent plant inspections, the personnel / equipment requirements noted below will apply,
- c. Pipe Samples: The total' number of pipe samples selected should constitute an equivalent of 120 inches of weld for the demonstration tests, i d. Acceptable Criteria: Eighty percent of the total number of preselected l cracks in the sample control group must be called correctly to
! constitute an acceptable test. Excessive false call rates may result l in an unacceptable performance rating. <
- e. Demonstration Time Limit: ALARA radiation dose considerations place constraints upon the time spent in field inservice inspection of a weld. Therefore, a time Ilmit of six hours, not including equipment I
calibration time, will be imposed for the examination and data recording. Completion of data evaluation and preparation of final results of individual Itcensee/ISI contractors should take no longer than one additional working day,
- f. _ Review of UT Procedures: The specific procedure (s) to be used by the licensee /ISI contractor (s) for plant inservice inspection is to be made available for review as part of the demonstration activity. It is expected that the UT procedure and equipment system will have been validated to be capable of detecting !GSCC by the Itcensee/ISI con-tractor before initiating the scheduled demonstration activities.
NOTE: Some of the licensees listed in Table 1 have completed efforts to validate the UT detection capability to be used to perform plant inspections in accordance with the requirements of Action Item I of IE8 82-03, Revision 1. These licensees need not repeat this effort ! in accordance with Action Item 1 of this bulletin provided that: the previous validated inspection group performs the new plant examination using identical UT pr'ocedures, standards, make and model of UT , instrument, and the same make and model transducers that were used to complete the previous validation effort. In addition, the UT personnel employed in the new examination must be the same; or those having appropriate training (documented) in IGSCC inspection using cracked thick wall pipe specimens, and are under direct supervision of the Level !!/!!! UT operators who successfully complete the performance demonstration tests. 1
q ., -
' b' ,, ..
4 IEB 83-02
._' , March 4, 1983 Page 5 of 6
~
t 2.~ Before resuming power operations licensees _ are to augment their ISI programs s to~ include an ultrasonic examination of the following minimum number of
. recirculation system welds:"
- a. Ten welds in recirculation pipingLof 20-inch diameter, or larger.
. 3- b. Ten welds of the jet pumps inlet riser piping and associated safe-ends.
- c. Two sweapolet-to-header (manifold) welds of jet pump risers nearest the end caps, if applicable to the design.
If flaws indicative'.of cracking are._found in the above examination, additional inspection is to be conducted in accordance with IWB 2430 of ASME Code Section XI. '
- 3. Before resuming power operations following the outage, the licensee is to
- u report the results of the Item 2 inspection and any corrective actions (in '
- the event cracking is identified). This report should also include the susceptibility matrix used as a basis for welds selected for examination i (e.g. stress rule index, carbon content, high stress location, repair history) and their values for each weld examined.
- 4. The NRC has an on going program to evaluate possible additional longer-- i term requirements relative te the IGSCC problem in the BWR recirculation system piping. The NRC may need additional information as part of this program. Therefore, licensees are requested to retain the' records and data developed pursuant to the inspections performed in accordance with Item 2.
~
- 5. The written report required by Item 3 shall be submitted to the appropriate Regional Administrator under oath or affirmation under provisions of i Section 182a, Atomic Energy Act of 1954, as amended. The original copy of the cover letter and a copy of the reports shall be transmitted to the U.S.
l Nuclear Regulatory Commission, Document Control Desk, Washington, D.C. 20555 for reproduction and distribution. This request for information was approved by the Office of Management and Budget under clearance number 3150-0096 which expires 12/31/84. Comments on burden and duplication should be directed to the Office of Management and Budget, Reports Management, Room 3208, New Executive Office Building, Washington,
, D. C. 20503.
"Since Big #cck Point and Lacrosse do not have jet pumps, the licensees of these plants should provide an equivalent sampling of the recirculation piping system based on the plant design.
l 4.. . _:____, , . , ._m, -- _. _ _ - _ _ _ , , _ _ . _ - . _ . . , _ _ , _ _ .
l 1 IEB 83-02 ! March 4, 1983 ' Page 6 of 6 Although no specific request or requirement is intended, the following information would help the NRC evaluate the cost of implementing this bulletin: Staff time to perform requested demonstration. Staff time to prepare written responses. The or:upational radiation exposure experienced. If you have any questions regarding this matter, please contact the Regional Administrator of the appropriate NRC Regional Office or one of the technical contacts listed below.
/t'Af Richard C./D Young, D ector Office of spection and Enforcement .
Technical
Contact:
WiiliamJ. Collins,IE 492-7275 Warren Hazelton, NRR 492-8075 i Attachments:
- 1. Table 1
- 2. Table 2
- 3. List of Recently Issued IE Bulletins i
l l l l l
Atttchment 1 IEB 83-02 March 4, 1983 Table 1 BWR Plants Scheduled to be in the Next Refueling Mode or Extended Outage After January 31, 1983 LICENSEE - PLANT RELOAD DATE Philadelphia Electric Co. Peach Bottom Unit 3 February 1983 Vermont Yankee Nuclear Power Vermont Yankee March 1983 Company Tennessee Valley Authority Browns Ferry Unit 1 March 1983 Nebraska Public Power District Cooper April 1983 Georgia Power Co. Hatch Unit 2 April 1983 , Consumers Power Co. Big Rock Point May 1983 Power Authority of the State FitzPatrick May 1983 of New York Commonwealth Edison Co. Quad Cities Unit 2 August 1983 Termessee Valley Authority Browns Ferry Unit 3 September 1983
.arolina Power & Light Co. Brunswick Unit 2 September 1983 Dairyland Power Corp. Lacrosse October 1983 Philadelphia Electric Co. Peach Bottom Unit 2 October 1983 Commonwealth Edison Co. Dresden Unit 3 October 1983 Boston Edison Co. Pilgrim Unit 1 January 1984
1 Attachment 2 ! IEB 83-02 l March 4, 1983 TABLE 2 CRACK INDICATIONS IN BWR RECIRCULATED SYSTEM PIPING PLANT PIPE SIZE WELD LOCATION HOW OETECTED NMP 1* 28" Ofa. Pipe to safe ends Initial crack-visual Visual leakage 28" Dia. Pipe to Pipe UT 28" Dia. Pipe to pump casing Visual - UT Monticello 12" Ofa. Riser to Safe End Leakage (weepage) 12" Dia. Riser to Safe End Weepage - UT 12" Dia. Riser to Safe End Weepage - UT 12" Dia. Riser Elbow to Pipe UT 22" Ofa. Manifold End Cap UT 12" Dia. Elbow to Pipe Leakage (weepage) During Hydrotest-visual Hatch 20" Dia. Elbow to Pipe (RHR) UT 22" Dia. Manifold End Cap UT 22" Dia. Manifold End Cap UT 22" Dia. Manifold End Cap UT 22" Dia. Manifold End Cap UT 24" Dia. Pipe to Pipe (RHR) UT 22" Dia. 12" Riser Sweepolet to Manifold UT Browns Ferry 22" Dia. 12" Riser Sweepolet to Manifold UT 22" Dia. 12" Riser Sweepolet to Manifold UT Brunswick 28" Dia. Elbow to Pipe UT 12" Dia. Riser to Safe End Leakage (weepage) 12" Dia. Riser to Safe End Leakage (weepage) Dresden 2 28" Dia. Pipe to Safe End UT 12" Dia. Riser Pipe to Elbow UT Footnotes: Cracks were found in 90% of welds examined Generally, there were indications of more than one axial or circumferential aligned crack in each affected weld. l l l
Attachment 3 . IEB 83-02 March 4, 1983 LIST OF RECENTLY ISSUED IE BULLETINS Bulletin Date of No. Subject Issue . Issued to 83-01 Failure of Reactor Trip 02/25/83 All PWR facilities Breakers (Westinghouse 08-50) holding an OL and to Open on Automatic. Trip other power reactor Signal facilities for information 82-04 Deficiencies in Primary Con- 12/03/82 All power reactor tainment Electrical Pene- facilities holding i) tration Assemblies an OL or CP 1 82-03 Stress Corrosion Cracking in 10/28/82 Operating BWRs in Rev. 1 Thick-Wall Large-Diameter Table 1 for action Stainless Steel, Recircula- and other OLs and cps . tion System Piping at BWR for information Plants 82-03 Stress Corrosion Cracking in 10/14/82 Operating BWRs in , Thick-Wall Large-Diameter, Table 1 for action ' Stainless Steel, Recircula- and other OLs and cps tion System Piping at BWR for information Plants 82-01 Alteration of Radiographs of Rev 1, 08/18/82 All power reactor Welds in Piping Subassemblies facilities with Supp 1 an OL or CP 82-02 Degradation of Threaded 06/02/82 All PWR facilities Fasteners in the Reactor Coolant with an OL for Pressure Boundary of PWR plants action and all other OLs or cps
, for information 82-01 Alteration of Radiographs of 05/07/82 All power reactor Rev. 1 Welds in Piping Subassemblies facilities with an OL or CP 82-01 Alteration of Radiographs of 03/31/82 Welds in Piping Subassemblies The Table 1 facilities for action and to all others for information 81-02 Failure of Gate Type Valves 08/18/81 All power reactor Supplement to Close against Differential 1 Pressure facilities with an OL or CP OL = Operating License CP = Construction Permit
A SSINS No.: 6835 IN 83-01 UNITED STATES NUCLEAR REGULATORY COMMISSION OFFICE OF-INSPECTION AND ENFORCEMENT WASHINGTON, D. C. 20555 January 26, 1983 IE INFORMATION NOTICE NO. 83-01: RAY MILLER, INC.~ Addressees: j All holders of a nuclear power reactor or fuel facility operating license (OL)
- or construction permit (CP).
Purpose:
This information notice is provided as an early notification of a potentially < i significant problem pertaining to fraudulent products that may have been sold i to nuclear industry companies by Ray Miller, Inc. This problem may affect both PWR and BWR facilities. The Nuclear Regulatory Commission staff is reviewing the problem and its effects. If the evaluation so indicates, the NRC may request explicit licensee or CP holder action. In the interim, we expect the addressees of this information notice to review the information herein for applicability to their facilities. No specific action or response is required at this time. Description of Circumstances: A. Background During November 1982, the Nuclear Regulatory Commission became aware that Ray Miller, Inc. , Charleston, West Virginia had been systematically defrauding its customers, including some nuclear industry companies, by marketing products under false pretense, i.e. , the markings on cheaper, ' lower quality products were altered to make them appear to be of higher quality. Former company officers pleaded guilty in the US District Court in Charleston, West Virginia to 10 felonies: six counts of mail fraud and four counts of wire fraud. Ray Miller, Inc. was a New Jersey corporation with its main office located in West Caldwell, New Jersey and with branch offices in Charleston, West Virginia; Decatur, Georgia; Buffalo, New York; and Skokie, Illinois. The Ray Miller office in Charleston, West Virginia was stated to b'e the only office with equipment capable of making alterations of markings on materials. The firm had been under investigation by special FBI agents for three years before prosecution by the Office of U.S. Attorney, l Charleston, West Virginia.
'-- 22!2000;so-
. _ __ _ _ __ . .. __ _ . _ _ _ ~ . _ _ .
IN 83-01 {- January 26, 1983 Page 2 of 4 The precise number of nuclear-related businesses that may have been defrauded by Ray Miller, Inc. remains an unknown. Records are incomplete and the situation is further complicated by the firm ceasing to operate and filing for reorganization under Chapter 11 of the bankruptcy statutes. An Assistant U.S. Attorney has determined that Ray Miller may have shipped substandard products to at least 125 companies in the 19 year period before the FBI began its probe in July 1979. Under the terms of the plea agreement, Ray Miller, Inc. is to notify, by February 1,1983, all com- , panies with which it had business dealings, concerning the firm's frau-dulent practices. Some of the nuclear industry companies appearing on an FBI generated list of Ray Miller customers for the year 1979 include Babcock and Wilcox, Combustion Engineering, Goodyear Atomic, Tennessee Valley Authority, Virginia Electric and Power (VEPCO), and Allied Chemical (at Barnwell). VEPCO and Barnwell are aware of the Ray Miller problem. VEPCO has placed - J suspect fraudulent material, which had not been installed, on hold.
, 8. Discussion l
Specifically, the scheme to defraud as practiced by Ray Miller, Inc. from ' approxmiately 1960 to 1979 was exposed by an extensive investigation conducted by the Federal Bureau of Investigation. The primary practices which formed that scheme, as detailed by the FBI, are as follows:
- 1. Markings on pipes and nipples indicating the foreign country where the product was manufactured were removed and the pipes and nipples were sold as domestic-made products.
j 2. Stainless steel (304 and 316) couplings, flanges, and bushings having standard carbon content were altered by imprinting an "L", making the marking on couplings, flanges and bushings appear as low carbon content materials.
; 3. Falsely notarized documents were prepared with billings, certifying that the materials shipped were of low carbon content when in fact '
i they were not.
- 4. Welded and drawn tubing was altered by removing the markings "WD" from this product and it was sold as seamless tubing.
The Ray Miller records were made available to the NRC after the company officers who pleaded guilty were sentenced on December 23, 1982. On January 6 and 7, 1983, members of the NRC met with the FBI and the Assistant U.S. Attorney in Charleston, West Virginia to discuss the Ray Miller, Inc. case and to review a sample of the 29 boxes of records
; currently in the custody of the FBI. These records cover the period from 1975 to 1979. After 1979, Ray Miller, Inc. apparently ceased its frau-dulent practices. The NRC is checking on the availability of. records that pre-date 1975.
I
IN 83-01 January 26, 1983 Page 3 of 4 During the sampling of records by the NRC, the following additional documentation of product substitution was identified: machined items were sold as forged ones, and materials with a low capacity.to withstand pressure, i.e., 150 psi pipe plugs, were sold as materials capable of withstanding much greater pressures, e.g., 3000 psi pipe plugs. Some of the invoices reviewed by NRC representatives and used as undeniable evidence by the U.S. Attorney's Office, were_found to actually have the written notation, " Remark", indicating product fraud. Primari',y, the NRC representatives attempted to ascertain the extent that Ray Miller's fraudulent practices may have impacted nuclear-related companies. Based on a sampling of the records, the NRC staff reached the following very general conclusions:
- 1. It appears that Ray Miller, Inc, supplied products to only a few companies directly involved in the nuclear power industry. However, the full extent to which the firm's products may be used in the -
nuclear industry is not known, since these products were sold to many jobbers and distributors.
- 2. Most shipments which were received directly by nuclear-related businesses were relatively small.
- 3. Generally, only a small portion of Ray Miller products purchased by nuclear industry companies appears to be fraudulent.
A search of the License Event Report file has been conducted by the National Science Information Center (Oak Ridge, Tennessee) for the NRC and no instances were identified in which nuclear facilities have reported deficiencies attributed to Ray Miller, Inc. materials. C. Guidance Enclosed for your information and appropriate action is a list from the Charleston office of Ray Miller's customers in 1979. As previously noted, this list resulted from an FBI investigation and may not be all inclusive, since orders made through other Ray Miller branch offices were sometimes filled by the Charleston office. A composite list of customers for other years is not available. Therefore, the NRC staff suggests that, like VEPCO, other nuclear industry companies isolate suspect Ray Miller products which may have been received and prevent the further installation of such materials until more information is obtained. Efforts are continuing to coordinate resources from various sectors of the nuclear industry and DOE to provide a detailed examination of all Ray Miller records known to exist. It is conjectured that these efforts will yield useful information for
l l IN 83 ! January 26, 1983 Page 4 of 4 placing " bounds" on the types of fraudulent materials shipped and identi-fying a more comprehensive list of buyers who may have received these materials. 1 - fI
'Edwar L. oYd'a'n, Director Divisio f Emergency .*reparedness and E ineering Response- -
Office of Inspection and Enforcement Technical
Contact:
R. M. Young, IE ., 301-492-9672 Attachments:
- 1. List of Ray Miller Customers for 1979
- 2. List of Recently Issued IE Information Notices 1
1
)
l l I 1.
l l
. l Attachment 1
. IN 83-01 January 26, 1983 Page 1 of 8 The followng are custe=ers of the Ray Miller Corporation for the year 1979: (With the exception of inter-cocpany accounts).
Alcoa Center 7th Street Rd. Route 780 Alcoa Center, Pennsylvania-15069 , Allegheny Power Service Corporation Cabin Hill Creensburg, Pennsylvania 15601 Allied Chemical Specialty Chemicals Division North Cate, State Route #1 Moundsville, West Virginia 26041 Allied General Nuclear Services Barnwell, South Carolina 29812 Appalachian Power Coupany P.O. Box 2021 Roanoke, Virginia 24022 , Aqua Chem., Inc. 240 West Capitol Drive Milwaukee, Wisconsin 53212 Argo Welded Products Alpha Industrial Park Phillipsburg, New Jersey 08865 Ashland Synthetic Taels, Inc.
?. O. Bor. 391 Ashland, Kentucky 41101 Avtex Fibers, Inc.
Plant Road Nitro. West Virginia 25143 Babcock and Vilcox Company 609 Wcrren Avenue Apollo, Pennsylvania 15613 3ASF Vytndotte Corporation Pigments Division 24th Street and 5th Avenue
. Hun:ington, West Virginia 25722 Beaunic yabrics Corporation P. O. Box 791 Statesville, North Carolina 28677 Bendix Corporation U.S. 219 North Lewisburg, West Virginia 25901 Bethlehem Steel Corporation '
Johnstown, Pennsylvania 15907 Brighton Corporation 11861 Mosteller Road i Cincinnati, Ohio 45241 ) Calson Corporation . P.O. Box 1346 Pittsburd h, Pennsylvania 15230
Attachment 1
'IN 83-01 January 26 1933 Page 2 of 8 Casale Industries
;00 South Avenue Car.ood, New Jersey 07027
.C. E. ':turston and Suns , Inc.
P.O. Box 968 F.ichoond, Virginia 23207 Celsnese Fibers Company P.O. Box 2334 Charlotte, tierth Carolina 28234 central Suppliers, Inc. 162!. Debaun Avenue Chesapeake, Virginia 23320 Cc; eda Associates, Inc. 1823 L.sser Lane L:utsville, Kentucky 40299 CF Industries . U.S. 41 1< orth Terra itaute, Indiana 47803 Cha: pion Papers Cha: pion International Corporation Canton Mill Canton, liorth Carolina 28716 Che:etron Corporation Pigments Division P.O. Esx 2166 Huntington, West Virginia 25722 Chesapeake Corporatien of Virginia West Point, Virginia 23181 Cincinnati Tasteners Company 16 East 73rd Street Cincinnati, Ohio' 45216 C&l/ Girdler, Inc. P.O. Box 32940 icuisville, Kentucky 40232 Cofsco, Inc. P.O. Box 184
'a' coster Ohio 4!.691 j Cc:bustion Engineering, Inc. j Monogahelia, Pennsylvania 15063 continental can Cc=pany. Inc. l P.O. Box 201 Hopewell, Virginia 23860 s CVI Corporacica P.O. Box 2138 Colunbus, Ohio 43216 Cyclops Industries i P.O. Box 8614 6 South Charleston, Wes t Virginia 25303 Dayton Power and Light Co:pany Ccurthouse Plaza, Scuchwest P.O. Box 1247 2ayton, Ohio !.5401 4
.~ . - . -. .
Attachment 1 IN 83-01' January- 26, 1983 Page 3 of 8 Dusenbery En5 i neering, Inc. Hanover Avenue Morris to.n, New Jersey 07960 DuCell . Tabricating 4220 West 123rd Street Als ip , Illinois 60658 E. I. DuPont De Nemours and Company 901 West DuPont Avenue - Belle, West Virginia 25015 Erdmann Corporation 6209 East Maxwell Avenue 4 Evansville, Indiana 47715 F. B. Wright Company of Cincinnati, Inc. P.O. Box 46412 Cincinnati, Ohio 45240 .
~
Tiber Industries. Inc.
' 8 5 *'oodruff Road i Greenville, South Carolina 29602 FMC Corporation Industrial Chemical Group P.O. Box 8127 South Charleston, West Virginia 25303 l Torma Scientific, Inc.
P.O. Box 649 Marietta, Ohio 45750 1 j Cage Company i P.O. Box 1168 Pittsburgh, Pennsylvania 15230 Good Supply and Equipment Company ' 905 Mismi Street - Akron, Ohio 44311 Goodyear Atomic Corporation P.O. Box 628 . Piketon, Ohio 45661 1 Coodfear Tire and Rubber Conpany , 4 Chemical Plant l Point Pleasant, West Virginia 25550 l Creene Supply Company 703-33 East Market Street Kingsport, Tennes s e e 37662 Henry Walke Company P.O. Box 1041 Norfolk, Virginia 23501 Hercules, Inc. Radford, Virginia 24141 Milliard Corporation l 100 West 4th Street Elmira, New York 14902 i 1 Holston Defense Corporation a Subsidiary of East =sn Kodak Cocpany P.O. Box 749 Kingsport, Tenne s s a e 37662
Attachment 1 IN 83-01 January ;25,1983 Huntington Alloys , Inc. Page 4 Of 8 Riverstde Drive . Huntington, Was,t Virginia 25720 Industrisi Rubber Products Company P.O. !ox 107 Parkersburg, West Virginia 26101 ITT Crinnell Corporation 350 South Douglas Avenue Chillicoche, Ohio 45601 Ivorjlee Corporation P.O. Box 6 50 Sharon, Pennsylvania 16146 Jabo Supply Corporattun P.O. Box 238 Huntington, Vese Virginia 25707 J. J. Finnigan Indus tries. Inc. Old Peach Tree Road Duluth, Cecrgis 31036 John R. Vad Company, Inc. P.O. Sox 392 Huntingdon, Pennsylvania 16652 Kanawha Manufacturin5 Company P.O. Box 1786 Charles ton, West Virginia 25326 Kelly Springfield Tire Company P.O. Box 300 Kelly Road Cumberland, Maryland 21502
. Kentucky Power Company P.O. Box 1428 Ashland, Kentucky 41101 Koppers Company P.O. Box M Tollansbee, Wes t Virginia 26037 Koppert Company, Inc.
3900 SoutM Larzeie Avenue Cicero, Illinois 60550 i Libbey-0wans-Ford, Company
. 811 Madison Avenue Toledo, Ohio 43695 l
3M Company ' P.O. Box 33030 Saint Paul, Minnesota 55133 Main Line Supply Company, Inc. 905 East Third Street Dayton, Ohio 45402 Mid-Valley Supply Co:pany, Inc. P.O. Box 762 Ironton, Ohio 45638 Mobay Chemical Corporation New l'arciesville , Vec- Virginia 26155 lbdern Welding Company 1500 East 12th Street Owensboro, Kentucky 40301
l
. Attachment 1 IN 83-01 January 26, 1983 Monsanto Corporation Page 5 Of 8 Anniston, Alabama 36201 ,
P.ouldagraph Corporation P.O. Box 485 Dunbar, West Virginia 25064 M & T Chemicals. Inc. ~ 2316 Highland Avenue Carrollton, Xantucky 41008 National Lead Company of Ohio P.O. 3cx 39158 Cincinnati, Ohio 45239 i Nackin & Company . P.O. Box 26444 Richmond, Virginia 23261 North American Rayon Corporation Wes t Elk Avenue Elizabethton, Tennessee 37643 . Govasont Corporation P.O. Box 189
- Kenova, West Virginia 25530 Ohio Electric Company Chio State Route #7 Cheshire, Ohio 45620 Or=et Corporation Box 176 Hannibal, Ohio 43931 Cwens-Illinois Forest Products Division Big Island Virginia 24526 j
Paul >Meller Company 1600 West Phelps Springfield, Missouri 65801 Paul 0. Abbe 139 Center Avenue ) LePalls, New Jersey 07424 l PBI Industries Steel Service Center Division ., P.O. Box 3373 , Youngstown, Ohio , 44512 Pa-bles Supply Corporation P.O. Drawer 2777 . Newport News. Virginia 23602
?eltz 3rochers, Inc.
P.O. Box .12596 Norfolk, Virginia 23502 Pennsylvania Electric Company 1001 3 road Straet Johnstown, Pennsylvania 15907 Power City Plu=bing and Heating. Inc. P.O. Box 6540 Wheeling, West Virginia 26003
?PG Industries , Inc.
Industrial Chasic~al Division P.O. Box 191 l New threinsville , '.*es t Virginia 26155
Attachment 1
. Precision Pu:p Service IN 83-01 517 Colf Mountain Road Janaury 26, 1983 Nitro, West Virginia 25143 Page 6 Of 8 o
Pre-ision Stainless Products Company 4701 Hesperedies Road
- Tampa, Florida 33614 .
Process Supply, Inc. P.O. Box 6010
- Charleston. West Virginia 25302 Procter & Camble Company Miami Valley Laboratories Route 27 Ross (Butler County), Ohio 45061 Raub Supply Company P.O. Box 1020 Lancaster, Pennsylvania 17604 Ray Mtiler. Inc.
4234 Kanawha Turnpike South Charleston, West Virginia 25309 , Rich =ond Engineering Company, In c . P.O. Box 25139 Richmond, Virginia 23260 Ripco, Inc. P.O. Box 9366 South Charleston, West Virginia Rust Engineering Co=pany P.O. Box $87 Cak Ridge. Tennessee 37830 Samson Steel Fabricators and Machine, Inc. P.O. Box 126 Canton, Ohio 44701 Sauer, Inc. Mechanical Contracters 30- 51 s t Street < Pittsburgh, Pennsylvania 1 5201 Shar;sville Steel Fabricators, Inc. Sharpsville, Pennsylvania 16150 Sheet Metal Products, Inc. 794 North 6th Str'e et Newark, New Jersey 07107 Shell Chemical Company P.O. Box 235-Belpre, Ohio 45714 Sistersville Tank Works (a Division of Superior Welding Company) P.O. Box 200 i I Sistersville, ' Jest Virginia 26175 Southeast Paper Manufacturing Company i Highway 199 Dublin, Caorgia 31021 l l Standard 011 Company Midland Building Cleveland, Chis 44115 v y-- y w --
Attachment 1 IN 83-01 Stauffer Chemical Company JanaurY 26' 1983 Ca111 polis Perry, West Virginia 25515 Page 7 of 8 Stolle Corporation 1501 Michigan Street Sicney, chia 45365 Summers Rardware and Supply Company . Buffalo and Ashe Streets Box 210 Johnson City. Tennessee 37601 Taylor-Parker Company, Inc. 500 Industry Drive - Hampton, Virginia 23361 Tennessee Eastman Co=pany Division of Eastman Kodak Company Kingsport, Tennessee 37662 Tilton Corporation 130 South Pine Lima, Ohio 45802 , Timet 100 Titanium Way Toronto, Chio 43964 TVA Chemical Stores Building Muscle Shoals Reservation
- Muscle Shoals, Alabaos 35660 T. V. A. Cumberland Steam Plant Cueberland City Tennessee 37050
' Union Camp Corporation .
P.O. Box 220 Cover, Chio 44622 Union Carbide Corporation F.O. Box 8361 South Charleston West Virginia 25303 Virginia Ilectric and Power Company P.O. Box 26666 Rich:end,. Virginia 23261 , Vulcan Manufacturing Company (a Subsidiary of Zurn Industries Inc.) - P.O. Box 46465 Cincinnati, Ohio
- 45246 Walker Stainless Equipment 601 State Street -
New Lisbon, Wisconsin 53950 :
' 1 Walter N. Yoder and Sons. Inc. j P.O. Box 1337 Cu=berland, Maryland 21502 Weirton Steel (Division of National Steel Corporation)
"a'eirton, Wes t Virginia 26062
'Jestvaco (Pine Papers Division)
Luke. :'.aryland 21 540 W. H. Kiefaber Company P.O. Box 1226 , Dayton, Ohio 45401
. . ~ . - . . . - . . _ . . . . . . _ . . ._ - _ - .. ..
k ( - 3, . Attachment 1 IN 83-01 Wheeting-Pittsburah Steel Corporation Janaury 26, 1983
- o. A cateway Center F.O. 3cx 118 -Page 8 of 8 Pittsburgh, Pennsylvania 15230 Wides Pipa and Supply Company '
1728 John Screet Cincinnati, Ohio 45217 . W. J. Gill 113 South Thomas Road ' Tallmadge, Chio 44278 W. R. Grace and Company Oavison Chemical Division 4775 Paddock Road CLncinnacL, Ohio 45229 i l Youngstown Welding and Engineering Company i
- 3700 Oakwood Avenue Yeungstown, Chio 44509 e
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SSINS No.: 6835 IN 83-07 UNITED STATES NUCLEAR REGULATORY COMMISSION OFFICE OF INSPECTION AND ENFORCEMENT WASHINGTON, DC 20555 March 7,1983 t INFORMATION NOTICE NO. 83-07: NONCONFORMITIES WITH MATERIALS SUPPLIED BY TUBE LINE CORPORATION Addressees: All nuclear power reactor facilities holding an operating license (OL) or construction permit (CP) and fuel facilities.
Purpose:
This information notice is provided as a notification of nonconformities with materials supplied by Tube Line Corporation. Although NRC review of this matter is not complete, the failure to meet the procurement specifications shows similarities to the Ray Miller, Inc. materials problems described in Information Notice 83-01, dated January 26, 1983. It is expected that recipients will review the information for applicability to their facilities. No specific action or response is required. Descriotion of Circumstances: On December 6,1982, Capitol Pipe and Steel Products Company (CPSP Co.) sent a letter to the NRC identifying nonconformities with materials supplied to its customers; CPSP Co. had obtained these materials from Tube Line Corporation. In the December 6,1982 letter, CPSP Co. identified the customers who had received the Tube Line Corporation materials, and had been notified about nonconformities in the materials. In addition, a followup Part 21 report by Babcock and Wilcox (B&W) identified in a letter dated January 10, 1983 that the material shipped to B&W had been supplied by the Houston, Texas facility of the Tube Line Corporation, which was not an approved nuclear supplier per ASME Section III, NCA 3800 requirements. The products identified by,CPSP Co. were pipe fittings (caps, tees, and elbows)
! and flanges. The nonconformities identified were shipment from an unapproved nuclear source, failure to perform proper heat treatment, and failure to meet i ASME Code requirements for nondestructive examinations.
According to the B&W 1etter, Tube Line Corporation purchased the fittings and base flange forgings from three different suppliers and performed the finished machining of the flanges. B&W has conducted tests of samples of four heats and has identified two heats with strength lower than that reported in l the materials certifications. I CM 20f9?f9
IN 83-07 March 7,1983 Page 2 of 2 Information available to date indicates that material was purchased from foreign stock material suppliers by Tube Line Corporation with the specification that heat treatments not be performed. Further, Tube Line Corporation never performed the required heat treatments when they received the material. The first procurement of the material in question was 1980 and the first shipments for nuclear application were made in 1982. It is suggested that holders of operating licenses or construction permits review this information for applicability to purchases of material at their facilities. No written response to this notice is required. If you have any questions regarding this matter, please contact the Regional Administrator of the appropriate NRC Regional.0ffice, or this office. M dward Jordan, Director Divisi of Emergency Preparedness and Engineering Response Office of Inspection and Enforcement Technical
Contact:
J. R. Fair 301-492-4509
Attachment:
List of Recently Issued Information Notices
Attachment IN 83-07 March 7, 1983 LIST OF RECENTLY ISSUED IE INFORMATION NOTICES Information Date of Notice No. Subject Issue Issued to 83-06 Nonidentical Replacement 02/24/83 All power reactor Parts facilities holding an OL or CP 83-05 Obtaining Approval for 02/24/83 All production and Disposing of Very-Low- utilization facilities Level Radioactive Waste including nuclear
- 10 CFR Section 20.302 power reactors and research and test reactors, holding an OL .
83-04 Failure of ELMA Power 02/18/83 All power reactor Supply Units facilities holding an OL or CP 83-03 Calibration of Liquid Level 01/28/83 All power reactor facilities holding an OL or CP 83-02 Limitorque H0BC, H18C, 01/28/83 All power reactor H2BC, and H38C Gearheads facilities holding i an OL or CP 83-01 Ray Miller, Inc. 01/26/83 All power reactor facilities holding an OL or CP 82-56 Robertshaw Thermostatic 12/30/82 All power reactor Flow Control Valves facilities holding an OL or CP 82-55 Seismic qualification of 12/28/82 All power reactor Westinghouse AR relay with facilities holding latch attachments used in an OL or CP , Westinghouse solid state l protection system J l OL = Operating License CP = Construction Permit ! 1
SSINS No.: 6835 IN 84-63 UNITED STATES NUCLEAR REGULATORY COMMISSION OFFICE OF INSPECTION AND ENFORCEMENT WASHINGTON, D.C. 20555 August 13, 1984 IE INFORMATION NOTICE NO. 84-63: DEFECTIVE RHR REPLACEMENT PIPING Addressees: All nuclear power reactor facilities holding an operating license (OL) or construction permit (CP).
Purpose:
This information notice is being provided to inform licensees of a potentially ~ significant problem pertaining to defects in large diameter piping formed by hot piercing and inspected to the Summer of 1980 Addenda to the ASME Boiler and Pres-sure Vessel Code.1 The NRC is continuing to evaluate this issue ; meanwhile, recipients are expected to review this notice for applicability to their facilities. Suggestions contained in this notice do not constitute NRC requirements; therefore, no specific action or written response is required. Description of Circumstances: On June 29, 1984, Northern States Power Company reported, in a 10 CFR 21 report, that base metal discontinuities had been discovered in the 18-inch ASME Class 1 pipe furnished to Specification SA-333, Grade 6, and special require-ments of SA-655 for replacement piping for the residual heat removal (RHR) system for its Monticello nuclear plant. While spool pieces were being fabri-cated at the site, the defect was seen in the section of pipe that was to be used to connect the RHR lines to the recirculation system on the discharge side of the RHR pump inside primary containment. The design pressure of the spool piece was 1248 psig at 562*F. Further visual and ultrasonic testing (UT) determined that the defect extended significantly into the pipe wall. The defect was found to be a laminar type discontinuity that had opened and separated in several areas. It was located about half way along the length cf the pipe, running about 360' around the inside and extending 0.44 inches into the material (43% through the wall). The orientation of the discontinuity was oblique to the surfaces. 8408100009 1ASME Boiler and Pressure Vessel Code, Section II, Part A,1980 Edition, Summer of 1980 Addenda, American Society of Mechanical Engineers, New York, NY
- . IN 84-63 August 13, 1984 !
Page 2 of 3 A second defect was found in another piece of SA-333, Grade 6 piping. It was determined to extend 330' around the interior of the pipe and 0.2 inches deep (19% through the wall). ! Northern States Power plans to perform a comprehensive UT scan on all replace-ment pipe used in the RHR system, using a five scan inspection: two directions axially, two circumferential1y, and a straight beam. The suppiter of the. piping had conducted inspections in compliance with the Code Specification , SA-655. These were inadequate to detect the defects that were found. SA-655
)
calls for scans in both circumferential directions only. Without axial scans or straight beam, defects such as these can go undetected. 1 In hot forming of seamless piping, a momentary loss of tool lubricant, hot scale release, or tool wear can result in embedded folds, laps, and seams in 4 the piping. Because of expansion dynamics associated with hot forming, the i piping may also be severely stressed locally to a degree that material inhomo-i genetties become prone to laminar separation or cracking. The frequency and - orientation of these processing discontinuities are not predictable and their
; presence may not be detected solely on the basis of visual inspection. It is necessary, therefore, that greater emphasis be placed on a comprehensive ultra-j sonic examination, as described above, to assure that unacceptable manufac-turing defects, irrespective of orientation, are detected and eliminated in
, piping used in the reactor coolant pressure boundary and other. safety-related i systems during the current and future replacement programs. j Regulatory Guide 1.68, " Nondestructive Examination of Tubular Products", was i issued in October of 1973, calling for the examination of pipe and tubing to i the ASME Code requirements in NB2550 supplemented by ASTM E-2132, " Standard Method for Ultrasonic Inspection of Metal Pipe and Tubing for Longitudinal 1 Discontinuties." Supplementing these requirements, the Regulatory Guide specified that ultrasonic examination be performed in both axial and both } circumferential directions. The Reg Guide was withdrawn in October oTTf77 as
- announced in Federal Register notice 42 FR 54478 on the premise that the ASME 5
Code Section III, at that time had adopted the supplementary requirements of the Regulatory Guide. Comprehensive review of the appropriate Codes and their referenced standards since that time failed to locate any unambiguous standard i which included the supplementary requirements of the Regulatory Guide in Code Sections II or III or in referenced material standards; i.e. , E-213, A-655, SA-655,.etc. Further NRC action in this matter is being contemplated. l I i 1 i zAmerican Society for Testing and Materials,1916 Race Street, Philadelphia, i Pennsylvania 19103 l
. _ , - . _ _ _ , _ _ _ _ _ . _ _ _ _ _ _ . _ _ _ _ _ _ _ . _ . _ _ . _ ~ - . . _ _ _ . . _ _ . . ~ , . . _ _ _ _ _ _ _ ____ .__ _ _ __.._,. _ ._ _ _ _ _ _ , - , _ . . .
IN 84-63 August 13, 1984 Page 3 of 3 No written response to this information notice is required. If there are any questions regarding this matter, please contact the Regional Administrator of the appropriate NRC regional office or this office. m-) _ dward I. ordan, Director Divisiof f Emergency Preparedness and Er neering Response Office of Inspection and Enforcement Technical Contacts: M. S. Wegner, IE (301) 492-4511 W. J. Collins, IE (301) 492-9630 -
Attachment:
List of Recently Issued IE Information Notices t 4
, - - . , , - - - . , - . - - - . , , - - - - - - - - , . , - - - - - -- , , - , , , - w
Attachment IN 84-63 i August 13, 1984 LIST OF RECENTLY ISSUED
, IE INFORMATION NOTICES
, Information Date of Notice No. Subject Issue Issued to i 84-62 Therapy Misadministrations 08/10/84 All NRC licensees To Patients Undergoing authorized to Cobalt-60 Teletherapy possess and use Treatments sealed sources in teletherapy units. 84-61 Overexposure of Diver in 08/08/84 All power reactor ! Pressurized Water Reactor facilities holding (PWR) Refueling Cavity 'and OL or CP. Failure of Air-Purifying All power reactor 84-60 08/06/84 Respirator Filters To Meet facilities holding Efficiency Requirement an OL or CP. l
) 84-59 Deliberate Circumventing of 08/06/84 All power reactor Station Health Physics facilities holding Procedures an OL or CP.
I 84-57 Operating Experience Related 07/27/84 All power reactor i, to Moisture Intrusion in facilities holding Safety-Related Electrical an OL or CP ! Equipment at Commercial Power Plants ; 84-58 Inadvertent Defeat of Safety 07/25/84 All power reactor l Function Caused By Human Error facilities holding Involving Wrong Unit, Wrong an OL or CP
- Train, or Wrong System
) 84-56 Respirator Users Notice for 07/10/84 All power reactor
! Certain 5-Minute Emergency facilities holding i Escape Self-Contained an OL or CP Breathing Apparatus ~
84-55 Seal Table Leaks at PWRs 07/06/84 All power reactor facilities holding an OL or CP
; 84-54 Deficiencies in Design Base 07/05/84 All power reactor Occumentation and Calcula- facilities holding tions Supporting Nuclear an OL or CP Power Plant Design j OL = Operating License ! CP = Construction Permit i
SSINS No. 6835 IN 84-87 UNITED STATES l l ' NUCLEAR REGULATORY COMMISSION 0FFICE OF INSPECTION AND ENFORCEMENT WASHINGTON, D. C. 20555
- . December 3,1984 INFORMATION NOTICE NO. 84-87
- PIPING THERMAL DEFLECTION INDUCED BY STRATIFIED FLOW 4
Addressees: All nuclear power reactor facilities holding an operating license (0L) or
; construction permit (CP).-
Purpose:
] This notice is provided to inform licensees and applicants of a recent event -
! that demonstrates a previously unidentified mechanism for piping system and pipe support damage. Recipients are expected to review the information for , applicability to their facilities and consider actions, if appropriate, to preclude similar problems occurring at their facilities. However, suggestions i contained in this information notice do not constitute NRC requirements; therefore, no specific action or written response is required.
1 Description of Circumstances:
- On August 22, 1984, WNP-2 experienced a thermal transient that damaged a i portion of the feedwater system. Following an cutage of about 5 days, the
! plant began to slowly admit feedwater to the reactor vessel with the reactor at about 1% power. About 15 minutes after beginning flow, the licensee heard a dull " thud" in the plant. The licensee found several feedwater pipe hangers . and snubbers damaged and a flange loosened, allowing a small leak of feedwater. The licensee reported the event to the NRC Operations Center as a " water i hansner"; but after consulting with experts and considering other circumstances, the licensee determined that the event could be the result of a thermal deflection induced by stratified flow. In this type of transient, the plant's configuration and the slow admission of cold feedwater to a pipe filled with high temperature water causes stratified flow in the pipe with cold water i cooling the bottom of the pipe and hot water remaining in the top of the pipe. i The difference in temperature between the top and bottom of the pipe causes j the pipe to bend and may pull hangers out cf their supports. l An unusual design feature of the WNP-2 plant allows the feedwater system to be heated by the reactor water cleanup system (RWCUS). The RWCUS return lines
< join two 24-inch feedwater lines upstream of two isolation check valves, but j downstream of normally open motor-operated valves. In many boiling water i
reactors, the RWCUS enters the feedwater system between the inboard and out-I board isolation check valves so that reverse flow of the RWCUS into the feedwater system is not possible. i
~
amuovai
IN 84-87 4 December 3, 1984 l j Page 2 of 3 ' i
, When the RWCUS is operating at WNP-2, but feedwater is not, flow is insufficient i
to open both sets of check valves. Some of the RWCUS return flows in the reverse direction back into the feedwater system before returning to the vessel. - Consequently, during hot standby, the RWCUS flow heats a long run _of
. horizontal feedwater piping. When a low rate of feedwater flow is initiated,
] the cold feedwater (about 100 'F) flows along the bottom of the pipe. The pipe ! bending phenomenon occurs because of the large temperature difference between 4 the top of the pipe (previously heated to about 400 'F by the RWCUS flow) and : i the bottom of the pipe cooled by the feedwater. Any system configuration and i i operating conditions where stratified flow can cause large temperature differences ! ! between.the top and bottom of a pipe could produce the pipe bending phenomenon, j -Following the event on August 22, 1984, the licensee instrumented the feedwater t line to detect and record pipe movement and differences in temperature between the top and bottom of the pipe. The additional instrumentation for detecting :
- and recording pipe movement was installed both in positions that were suspected j of moving such as at a hanger that failec, and in positions that were suspected ;
of not moving such as at a hanger that was believed to be acting as a fulcrum. Despite procedures designed to preclude recurrence of the event, the event occurred again following a scram from 60% power on September 10, 1984. Because lI of the instrumentation on the feedwater lines the licensee can exclude other explanations for the phenomenon, such as water hariner. l Discussion: The licensee's investigation of this complex phenomenon is detailed in a report ; j titled " Design Engineering Report, WNP-2 Feedwater Thennal Deflection Events" - 1 and will not be repeated here. Copies of the report may be obtained from: ) Mr. P. L. Powell, Manager ]i WNP-2 Licensing Washington Public Power Supply System , P. O. Box 968 t
- 3000 George Washington Way
) Richland, Washington 99352 Although this report is useful as a description of the event, the NRC has not f
; evaluated the report and does not necessarily endorse all of the conclusions of
- the report.
i Other licensees may wish to consider whether events that are apparently water hammer are caused by a pipe bending phenomenon similar to that which has
; occurred at WNP-2. Any time a licensee slowly feeds cold water into a hot i filled pipe there may be the potential for this type of event.
i l There are several reasons why licensees may wish to determine if some apparent j water hamers are really a thermal-gradient-induced pipe bending phenomenon: i l 1. Piping systems can be designed to accommodate this phenomenon without l
! damage, thereby preventing further events. Repositioning, strengthening, I or modifying pipe supports or hangers and snubbers may allow for pipe '
movement.
- l
IN 84-87 December 3,1984 Page 3 of 3
- 2. The stresses on the pipes subject to thermal pipe bending may or may not be within the design capacity of the pipes.
- 3. Changes to operating procedures may prevent pipe bending caused by stratified flow.
No specific action or written response is required by this information notice. If you have any questions about this matter, please contact the Regional Administrator of the appropriate regional office or this office. P,, . . ! dward . Jordan, Director l Divisi ) of Emergency Preparedness and Engin ering Response , Office of Inspection and Enforcement Technical
Contact:
Eric Weiss, IE (301)492-9005
Attachment:
List of Recently Issued IE Information Notices
. l 1
I Attachment IN 84-87 December 3,1984 LIST OF RECENTLY ISSUED IE INFORMATION NOTICES -l I Information Date of Notice No. Subject Issue Issued to 84-86 Isolation Between Signals 11/30/84 All boiling water of the Protection System reactor facilities and Non-Safety-Related holding an OL or CP Equipment i l 84-85 Molybdenum Breakthrough 11/30/84 All NRC licensed ) l from Technetium-99m medical institutions l l Generators and radiopharmaceutical - suppliers 84-84 Deficiencies In Ferro- 11/27/84 All boiling water . Resonant Transformers reactor facilities l holding an OL or CP 84-83 Various Battery Problems 11/19/84 All boiling water reactor facilities holding an OL or CP i 84-82 Guidance for Posting 11/19/84 All boiling water l Radiation Areas reactor facilities holding an OL or CP ! 84-48 Failures of Rockwell 11/16/84 All boiling water Supp, 1 International Globe Valves reactor facilities holding an OL or CP 84-81 Inadvertent Reduction in 11/16/84 All boiling water Primary Coolant Inventory In reactor facilities Boiling Water Reactors During holding an OL or CP Shutdown and Startup l 84-80 Plant Transients Induced by 11/8/84 All B&W power reactor Failure of Non-Nuclear facilities holding Instrumentation Power
- an OL or CP I
84-79 Failure to Properly Install 11/5/84 All boiling water Steam Separator at Vermont reactor facilities ' Yankee holding an OL or CP , l l 84-78 Underrated Terminal Blocks 11/2/84 All power reactor , that may Adversely Affect facilities holding Operations of Essential an OL or CP l Electrical Equipment OL = Operating License CP = Construction Permit
SSINS No.: 6835 IN 85-24 UNITED STATES
, , NUCLEAR REGULATORY COMMISSION 0FFICE OF INSPECTION AND ENFORCEMENT 1
; WASHINGTON, D.C. 20555 March 26, 1985 IE' INFORMATION NOTICE N0; 85-24: FAILURES OF PROTECTIVE C0ATINGS IN PIPES AND HEAT EXCHANGERS Addressees:
All nuclear power reactor facilities holding an operating license (OL) or construction permit (CP).
Purpose:
~
This information notice is provided to alert reci)ients of a potentially significant problem pertaining to the selection and application of protectiv'e coatings for safety-related use, especially painting interior surfaces of pipes - and tubing. It is expected that recipients will review the information for applicability to their facilities and consider actions, if appropriate, to l
. preclude a similar problem occurring at their facilities. However, suggestions contained in this information notice do not constitute NRC requirements; therefore, no specific action or written response is required.
Description of Circumstances:
- 1. Spray Pond Piping While making minor repairs to the spray pond piping system in 1982, Palo Verde Nuclear Generation Station Unit 1 personnel discovered delamination and peeling of the interior epoxy lining in three 24-inch-diameter 90' ,
elbows. Examination of the remainder of the piping system showed similar l lining failures in other elbows, such as 3-inch blisters that contained solvent, poor adhesion, soft film, and excessive film thickness. The spray pond is the ultimate heat sink for the Palo Verde Station. During a shut.dewn where the ultimate heat sink was needed, separation of the epoxy l lining from the elbows could potentially cause a flow restriction in the piping system. The epoxy coating specified was Plasite 7122-H, a product of Wisconsin Protective Coatings Company. This material is formulated to be applied by mechanical spraying equipment in layers 2-1/2 to 4 mils thick with sufficient time allowed for each layer to cure. The use of mechanical spray equipment provides a uniform and controlled coating film thickness. The straight sections of the piping system were coated in this manner. The multilayer mechanical deposition and curing of 12-15 mils of coating in the straight i sections of pipe took 7 days, and no discrepancies similar to those in the l elbows were found. . 8312990444
IN 85-24 March 26, 1985 Page 2 of 3 However, the elbows were coated in two layers using a hand-held gun. The lining'was uneven with the coating up to 25 mils thick. Coating took only 3 days-in December of 1980; this reduction in curing time can'be critical, especially in the winter when chemical curing and solvent evaporation tends to be retarded. In addition, the elbows were capped after the final coating application and there was insufficient air necessary for curing. A hand-held gun was used to spray the coating because of the shape of the elbow. There are other methods of applying epoxy coatings that are more : controllable and use less solvent. Electrostatic spray uses less epoxy
.and solvent for the same coating thickness. Electrodeposition in a water E
solution provides the most uniform coating and does not use solvents. The. fluidized bed method will provide the thickest epoxy deposit. Whatever application method is selected, epoxies are thermosetting materials and are normally cured by oven baking or infrared heating. Heating reduces curing time from several days to several hours. The elbows were repaired by removing the deficient lining, preparing the - surface by grit blasting, and recoating with Plasite 9009-IT. The repairs were acceptable and a final report was issued in January 1984.
- 2. Diesel Generator Heat Exchangers
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While operating train A of the spray pond piping system in May 1984, Palo Verde Nuclear Generation Station' Unit 2 personnel discovered an accumulation of epoxy material. The jacket water cooler, air after-coolers, and lube - oil coolers of all the train A and train 8 diesel generator heat exchangers had extensive failure of the epoxy coating and resulted in complete blockage of the governor oil coolers. 4 The failures of the epoxy coating included severe blistering, moisture l entrapment between layers of the coating, delamination, peeling, and widespread rusting. The epoxy coating specified was Plasite 7155-H. It
- is formulated to be deposited in thin layers using mechanical spraying equipment.
An evaluation of the deficiencies showed the presence of cutting oils on the heat exchanger surface before the coating was applied. It is a basic requirement to have a dry, oil-free surface before applying coatings. In addition, the surface was too smooth for the epoxy cocting to adhere. Epoxy coatings are applied directly to the metal without a primer and it is necessary to slightly roughen the metal surface. Finally, the heat exchangers were sealed after spraying and there was insufficient air to complete the curing process. Repairs were successfully made with Plasite 9009-IT and a final report was issued in September 1984. t
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IN 85-24 i March 26, 1985 Page 3 of 3 It should be noted that this information notice is not intended to imply that Plasite materials produced by Wisconsin Protective Coatings Company are unacceptable. Other applications using appropriately selected materials and application techniques have been successful. No specific action or written response is required by this information notice. If you have any questions about this matter, please contact the Regional Administrator of the appropriate regional office or this office. A_ n oward o n, Uirector Divisio f Emergency Preparedness ) and E ineering Response j Office f Inspection and Enforcement - Technical
Contact:
P. Cortland, IE (301) 492-4175 .
Attachment:
List of Recently Issued IE Information Notices w
I l SSINS Ns.: 6835 IN 85-97 ) l UNITED STATES NUCLEAR REGULATORY COMMISSION l OFFICE OF INSPECTION AND ENFORCEMENT WASHINGTON, D.C. 20555 : December 26, 1985 IE INFORMATION NOTICE NO. 85-97: JAIL TERM FOR FORMER CONTRACTOR EMPLOYEE WHO l INTENTIONALLY FALSIFIED WELDING INSPECTION RECORDS Addressees: All nuclear power react'or facilities holding an operating license (OL) or a construction permit (CP).
Purpose:
This information notice is to inform licensees, contractors and their employees of the criminal prosecution by the U.S. Department of Justice of a contractor QC inspector employed at the Seabrook Nuclear Power Station, and a resultant jail sentence. The individual intentionally falsified records of liquid penetrant and magnetic particle testing of welding joints in piping, pipe braces and structural steel. The NRC suggests that recipients review and provide widespread dissemination of this notice to employees and contractors' employees involved in safety-related activities, especially those employees involved in making and keeping records. The NRC further suggests that recipients remind their own and contractor employees that not only are licensees subject to civil enforcement action for violations of NRC requirements, but individuals who intentionally violate these requirements are also subject to criminal prosecution. The suggestions for dissemination of this notice do not constitute NRC requirements; therefore, no specific action or written response is required. Description of Circumstances: 1 In March 1983, management of Pullman Higgins (P-H), principal contractor for l construction of the Seabrook Nuclear Power Station, identified deficiencies in a QC inspection report of liquid penetrant and magnetic particle testing. Rather than assuming the deficiency to be an isolated occurrence, P-H investigated other reports prepared by the individual and found similar deficiencies. As a result, the individual's employment was terminated in April 1983. Subsequently, during an investigation conducted by the NRC's Office of l Investigation (01), the individual, after initial denial, admitted falsifying ! the inspection reports in that he documented work as being complete and accept-able when, in fact, he had not performed the inspection of the work. Further, the individual also admitted that he had lied on his job application and resume regarding his formal education and previous NDE certification. The case was O p 164 M U l
- - - -~ -.
IN 85-97 Page 2 of 2 December 26, 1985 referred to the Department of Justice and on September 30, 1985, the U.S. Attorney in New Hampshire announced that the individual was sentenced to six months imprisonment and three years probation following his guilty plea to two counts of an indictment charging, under 18 U.S.C. 51001, that he filed false statements on documents required by the NRC to be maintained. Discussion: Licensees have the responsibility to ensure the safe construction and operation of nuclear power generating facilities to ensure quality in all licensed activities. In so doing,. licensees must not only use trained individuals, maintain accurate records, and provide adequate procedures, but must also exercise supervision over their employees and their contractor employees to assure adherence to procedures and NRC requirements. While violations of NRC requirements caused by inattention to detail or human error are unacceptable - to the NRC and may result in civil enforcement action, they do not subject individuals to criminal prosecution. However, violations caused by intentional acts may subject corporations, the individual wrongdoer, and others who knew and condoned his acts to criminal prosecution. As evidenced by this reported case, the criminal sanctions available may include a jail sentence.
' No specific action or written response is required by this information notice.
If you have any questions about this matter, please contact the Regional Administrator of the appropriate regional office or this office. 1 A- I war Jordan, Director Divisi of Emergency Preparedness and gineering Response Office of Inspection and Enforcement Technical
Contact:
Steve Burns, ELD 492-7268
Attachment:
List of Recently Issued Information Notices
SSINS Ns.: 6835-IN 86-45 UNITED STATES NUCLEAR REGULATORY COM4ISSION OFFICE OF INSPECTION AND ENFORCEMENT WASHINGTON, D.C. -20555 June 10, 1986 IE INFORMATION NOTICE NO. 86-45: POTENTIAL FALSIFICATION OF TEST REPORTS ON FLANGES MANUFACTURED BY GOLDEN GATE FORGE AND FLANGE, INC. Addressees: All nuclear reactor facilities (including test and research facilities) holding i an operating license (OL) or a construction permit (CP).
Purpose:
This notice is provided to alert recipients to potential falsification of certifications for piping flanges. It is expected that recipients However, will review suggestions the infomation for applicability to their facilities. contained in this notice do not constitute NRC requirements; therefore, no specific action or written response is required. Further efforts are underway and more definitive information and specific requirements for licensee action may be issued in the future. Description of Circumstances: On March 7,1986 the NRC received notification from Consolidated Pipe and Valve Supply Company (CP&VS) of a potentially reportable condition under 10 CFR Part 21 regarding forged flanges fabricated by Golden Gate Forge and Flange (GGF&F) Inc. located at Hunters Point,. San Francisco, California. Subsequently, some GGF&F management personnel and the president of a tes, ting laboratory (Westex) pleaded guilty and were sentenced in Federal Court on criminal charges in connection with falsification of test certifications for material supplied to the U.S. Department of Defense (000). i The convictions were based on falsifications of records and fraud related to copper nickel forged flanges for marine applications. These activities involved ; (1) altering independent laboratory test reports to make unacceptable material j appear acceptable (2) delivering and representing unacceptable or untested l material from several heats as originating from a single heat for which accept- 1 able test results were available, and (3) altering original material manufacturer mill tes.t reports to make unacceptable material appear acceptable. The NRC cannot conclude by the currently available information whether any defective material has been supplied for use at nuclear power plants. However, GGF&F certifications furnished by Consolidated Pipe and Valve Supply Company to NRC for material supplied to D.C. Cook and Midland appear to indicate that GGF&F
- 4) L. ..,n 3
T Off G J U V s - ,
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IN 86-45 Juno 10, 1986 Pago 2 of 2 , failed to perform required heat treatment, testing of mechanical properties after for ing, and nondestructive examination (NDE). These licensees have been separate 1 informed. Golden Gate Forge and Flange receives alloy materials in ingot or bar form to forge and machine the flanges. The steel mills that produce the alloy materials provide certificates of chemical and mechanical properties of those materials before forging. In some cases, samples are required to be submitted to inde-pendent testing laboratories to allow certification of chemical and mechanical properties after forging. In the case of material supplied to D00, both of these types of reports were altered to make unacceptable or unevaluated material appear acceptable. Golden Gate Forge and Flange is incorporated in the State of Nevada; its only San Francisco, California.. GGF&F produces place of business a full range is atsizes,from of flange Hunters Point, 1/2 inch to 24 inches with pressure ratings from 125 to 2500 psi. Materials available include carbon steel, stainless steel, high nickle and cosper alloys. The flanges are supplied to specifications including ASTM, AS9E Section III Class I, and D00. Current information indicates that the falsifications took place from or before May 1983 and continued at least until June 1984. 1 No specific action or written response is required by this notice. If you have ) any questions regarding this matter please contact the Regional Administrator oftheappropriateNRCregionaloffIceorthisoffice. I
- Mar L. Jordan, Director Division.of Emergency Preparedness andEnWneeringResponse Office of Inspection and Enforcement Technical
Contact:
- 0. P. Gormley, IE 301-492-9763
Attachment:
List of Recently Issue IE Information Notices 1 e M + Jiuese Me= = # e3
Attachment 1 IN 86-45 June 10, 1986 LIST OF RECENTLY ISSUED IE INFORMATION NOTICES Information Date of Notice No. Sub.iect Issue Issued to 86-44 Failure To Follow Procedures 6/10/86 All power reactor When Working In High facilities holding Radiation Areas an OL or CP and research and test reactors
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86-43 Problems With Silver Zeolite 6/10/86 All power reactor Sampling Of Airborne Radio- facilities holding ' iodine an OL or CP i 86-42 Improper Main'tanance Of 6/9/86 All power rector Radiation Monitoring Systems facilities holding c.' OL or CP , 86-41 Evaluation Of Questionable 6/9/86 All byproduct Exposure Readings of Licensee material licensees Personnel Dosimeters 86-32 Request For Collection of 6/6/86 All power reactor Sup. 1 Licensee Radioactivity facilities holding Measurements Attributed To an OL or CP The Chernobyl Nuclear Plant Accident 86-40 Degraded Ability To Isolate 6/5/86 All power reactor The Reactor. Coolant System facilities holding From Low-Pressure Coolant an OL or CP Systems in BWRS
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86-39 Failures ~0f RHR Pump Motors 5/20/86 All power reactor , And Pump Internals facilities holding , an OL or CP l l 86-38 Deficient Operator Actions 5/20/86 All power reactor Following Dual Function Valve facilities holding i Failures an OL or CP l , 86-37 Degradation Of Station 5/16/86 All power reactor Batteries facilities holding an OL or CP OL = Operating License CP = Construction Permit
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1 SSINS No.: 6835 IN 86-106 UNITED STATES NUCLEAR REGULATORY. COMMISSION OFFICE OF INSPECTION AND ENFORCEMENT WASHINGTON, D.C. 20555
' December 16, 1986 j- IE IV O!ATION tiOTICE NO. 86-106: FEEDWATER LINE BREAK , Addressees:
All nuclear power reactor facilities holding an operating license or a con-struction permit.
Purpose:
This information notice is to alert addressees of a potentially generic problem with feedwater pipe thinning and other problems related to this event. Recipients are expected to review the information for applicability to their facilities and consider actions, if appropriate, to preclude similar problems occurring at their facilities. However, suggestions contained in this information notice do not constitute NRC requirements; therefore, no specific action or written response is required. i f Description of Circumstances: On Tuesday, December 9, 1986, at 2:20 p.m., both units at the Surry Power i Station were operating at full power when the 18-inch suction line to the main i feedwater pump A for Unit 2 failed catastrophically. Eight workers who were replacing thermal insulation on a nearby line were burned by flashing feedwater. All were transported to area hospitals. Two workers were treated and released. Four other workers subsequently died. i Units 1 and 2 are identical. In each unit, feedwater flows from a 24-inch header to two 18-inch suction lines that each supply one of two main feedwater pumps. At maximum load under normal conditions, feedwater flew through each pumgis5million1b/hr. Feedwater temperature, pressure, and enthalpy are 370 F, 450 psig, and 346 Btu /lb, respectively. At these conditions the fluid is in the single phase, liquid only regime. That is, the piping does not see a mixture of liquid and vapor. L The event was initiated by the main steam isolation valve on steam generator C } failing closed. Because of the increased pressure in steam generator C that collapsed the voids in the water, the reactor tripped on low-low level in that steam generator. A 2-by-4 foot section of the wall of the suction line to the A main-feedwater pump was blown out and came to rest in an overhead cable tray. The break was located in an elbow in the 18 inch line about one foot 1 from the 24-inch header. The lateral reactive force generated by escaping
- 001:1000:0 -
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IN 86-106 December 16, 1986-Page 2 of 3 " feedwater completely severed the suction line. The free end whipped and came to rest against the discharge line for the other pump. Steam flashing from the break and condensing in control . cabinets and in open
. conduit piping apparently caused the fire suppression system to actuate, resulting in release of halon and carbon dioxide in the emergency switchgear room and in various cable tunnels and vaults and in the cable spreading room.
- Because of the volume of water and steam being released, operators isolated lines carrying high energy fluids to areas inundated by steam. Steam generator water levels were maintained with the auxiliary feedwater system, and system cooling was provided by actuating atmospheric dump valves as necessary.
l The primary system responded normally to the loss of load transient with a partial loss of main feedwater. Primary coolant temperature was stabilized at 520*F and pressurizer level was recovered as it reached the low level set point. Primary pressure decreased from 2235 to 2015 psig following the reactor trip. By 2 a.m. on the following day, reactor temperature had been reduced to the point where the residual heat removal system could be put on line. The unit reached cold shutdown that morning. During the recovery effort, the operators and the plant performed as expected. Discussion: The pipe material is A-1068 carbon steel and the elbow is 18-inch, extra strong i A-234 grade WPB carbon steel. Nominal wall thickness of the suction piping is
! 0.500 inch. Measurements of the wall fragment demonstrated that the wall had l been generally eroded to about 0.25 inch and was one of the causes of the failure. Preliminary examination of the 2-by-4 foot section of pipe blown out during the event shows the thinning to be relatively uniform except for some i small localized areas. The thinnest areas are localized and appear to be about l 1/16 inch thick. Some corrosion pitting is present. A preliminary micro-examination indicated that the pipe surface near the fracture had not been i
highly strained as with a high stress event, such as a high pressure spike in j the system. i It has not been determined at this time whether a pressure spike in the system ! was a contributor to this event. There was no damage evident in the hanger supports to the condensate system. Inspection revealed a disabled check valve in the discharge piping of the A main feedwater pump. This check valve was found with its seat displaced and a hinge pin sissing.
- On December 10, the licensee shut down Unit 1 for examination of the condition
- of feedwater piping. Inspection of the Unit 1 feedwater piping shows wall thinning similar to but not cs severe as that in Unit 2.
The NRC dispatched an augmented investigation team (AIT) to the site . The AIT includes a metallurgist and a water hammer analyst. 1
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IN 86-106 December 16, 1986 Page 3 of 3 The NRC will issue additional information as more inspection and analysis is completed. No specific action or written response is required by this information notice. If you have questions about this matter, please contact the Regional Adminis-trator of the appropriate NRC regional office or this office. Edward L. Jorda , Director Division of Emergency Preparedness and Engineering Response Office of Inspection and Enforcement Technical
Contact:
Roger Woodruff, IE H (301) 492-7205 i 1 Vincent Panciera, Region II (404) 331-5540
Attachment:
List of Recently Issued IE Information Notices W-
Attachment 1 IN 86-106 December 16, 1986 LIST OF RECENTLY ISSUED IE INFORMATION NOTICES Information Date of Notice No. Subject Issue Issued to 86-105 Potential for loss of 12/19/86 All holders of OL or CP Reactor Trip Capability for PWR or BWR at Intermediate Power Levels 86-104 Unqualified Butt Splice 12/16/86 All pressurized and Connectors Identified in boiling water reactor Qualified Penetrations facilities holding an OL or CP 86-14 Overspeed Trips Of AFW, HPCI, 12/17/86 All power reactor i Supplement 1 And RCIC Turbines facilities holding . an OL or CP 86-103 Respirator Coupling Nut 12/16/86 All power reactor Assembly Failures facilities holding an OL or CP and fuel facilities , 86-102 Repeated Multiple Failures Of 12/15/86 All power reactor Steam Generator Hydraulic facilities holding Snubbers Due To Control an OL or CP Valve Sensitivity 86-101 Loss Of Decay Heat Removal 12/12/86 All PWR facilities Due To Loss Of Fluid Levels holding an OL or CP In Reactor Coolant System 86-100 Loss Of Offsite Power To 12/12/86 All PWRs or BWRs Vital Buses At Salem 2 holding an OL or CP 86-99 Degradation Of Steel 12/8/86 All power reactor Containments facilities holding an OL or CP 86-21 Recognition Of American 12/4/86 All power reactor Sup. 1 Society Of Mechanical facilities holding Engineers Accreditation an OL or CP Program For N Stamp Holders 86-98 Offsite Medical Services 12/2/86 All power reactor facilities holding an OL or CP OL = Operating License CP = Construction Permit
SSINS No.: 6835 IN 86-108 UNITED STATES NUCLEAR REGULATORY COMMISSION OFFICE OF INSPECTION AND ENFORCEMENT WASHINGTON, D.C. 20555 December 29, 1986 IE INFORMATION NOTICE NO. 86-108: DEGRADATION OF REACTOR COOLANT SYSTEM PRESSURE BOUNDARY RESULTING FROM BORIC l ACID CORROSION l Addressees: '
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All pressurized water reactor (PWR) facilities holding an operating license or a construction permit. 1
Purpose:
This notice is to alert recipients of a severe instance of boric acid induced corrosion of ferritic steel components in the reactor coolant system (RCS). l Recipients are expected to review the information for applicability to their facilities and consider actions, if appropriate, to preclude similar problems occurring at their facilities. However, suggestions contained in this information notice do not constitute NRC requirements; therefore, no specific action or written response is required. I Description of Circumstances: In October 1986, the Arkansas Nuclear One, Unit 1 (ANO-1) Plant was in cold shutdown and was performing nondestructive testing of the high pressure injec- l l tion (HPI) nozzle thermal sleeves. An HPI nozzle is attached directly on the i side of each of the four RCS cold legs. The metallic insulation was removed from the "A" HPI nozzle to allow radiographic examination. Removal of this i insulation revealed severe corrosion wastage on the exterior of the HPI nozzle i and some wastage on the RCS cold leg pipe. The corrosion apparently was caused I by reactor coolant leakage from an HPI isolation valve located about 8 feet above the nozzle as shown in the attached Figure 1. The wastage began adjacent to where the 3-1/2 inch OD stainless steel safe-end is welded to the carbon steel HPI nozzle. The safe-end is located between the stainless steel HPI line and the carbon steel HPI nozzle. The wastage was approximately 1/2 inch at its deepest location (adjacent to the stainless-to-carbonsteelweld). The HPI nozzle (including cladding) is approximately 3/4 inch thick at this point. At the transition weld between the safe-end and the carbon steel nozzle, the wastage extended approximately 20 percent around the i circumference of the nozzle in the form of several trenches. From this point, the wastage narrowed to two separate trenches that became shallower as they progressed more than 10 inches along the bottom of the HPI nozzle towards the RCS cold leg. The two trenches then continued down the cold leg for approx-imately 6 inches. The depth of the trenches on the cold leg were less than 1/4 inch.
- 0'a2230CL 1
IN 86-108 December 29, 1986 Page 2 of 3 The HPI nozzle is castructed of ferritic (ASTM, A-105, grade 2) steel. The cold leg also is castructed of ferritic (ASTM, A-106, gr:de C) steel. The HPI nozzle and the old leg are clad on the inside with stainless steel of 3/16 inch nominal thickanss. Leakage from the HPI isolation valve was first noted in August 1985, through RCS leak detection athods. The measured leakage was approximately 0.08 gal-lons per minute (gin). The leakage was attributed to a valve body-to-bonnet leak. The valve's seal ring and yoke clamp were replaced in September 1985. A leakage of 0.09 gm was again detected from this valve 8 days later during plant startup. This leak rate continued until subsequent repair of the valve in February 1986. The insulation was not removed at the time of these repairs. After the damaged WI nozzle was discovered, a reddish stain, resulting from the leaching out of iron oxide corrosion products, was found on the exterior of the insulation near the damaged area. Discussion: J There have been a mober of reported incidents of boric acid corrosion wastage of ferritic steels. In 1981 Calvert Cliffs, Unit 2, experienced boric acid corrosion wastage on an RCS cold leg near the suction to a reactor coolant pump (RCP). This corrosien wastage was from 1/8 to 1/4 inch in depth and extended about 20 percent around the circumference of the RCS pipe. This RCS piping is fabricated from ferritic (ASME, SA 516, grade 70) steel. Most incidents, howser, have been wastage of threaded fasteners. In June 1982, IE Bulletin 82-02, ' Degradation of Threaded Fasteners In The Reactor Coolant Pressure Boundary 0F PWR Plants," was issued. The closecut of this bulletin was addressed in NUREG-1095, May 1985. The affected threaded fasteners were of a low alloy high strength ferritic steel. A generic issue, " Bolting Degradation,or Fallwes in, Nuclear Power Plants," is currently under review by the NRC staff to determine if additional actions are necessary. One of the main concerns in this issa is boric acid corrosion. The 1983 edition of the ASME Code, Section XI, was revised to provide for more restrictive requirements for visual examinations of systems containing borated water. Part of these require-ments is an inspection of insulation at the joints for evidence of leaks. This revision is contained in Section IWA-5242(a), Insulated Components. Boric acid corrosion has been found to be most active where the metal surface is cool enough so that it is wetted. If the metal is sufficiently hot, then the surface will stay dry and this loss of electrolyte will slow the corrosion rate. At ANO-1, borated water leaked from the HPI isolation valve in the form of a liquid and then ran down the HPI piping on the inside of the insulation to the HPI nozzle. As the leakage approached the cold leg, the increased piping temperatures caused evaporation of the water, thus increasing the boric acid concentration and lowering the PH of the solution. It is believed that the close tolerance between the HPI nozzle and the insulation, aided by boric acid crystallization, caused pooling of the solution at the nozzle. This pool of highly acidic solution wetted the nozzle and resulted in accelerated corrosive
IN 86-108 December 29, 1986 Page 3 of 3 m attack. Experience has shown that even relatively hot metal can be sufficiently cooled on the surface by the flow of the leakage so that the surface stays wetted and boric acid corrosion is promoted. In addition, periods during which i a metal surface is below normal operating temperature may allow corrosion in j areas that would not otherwise be expected. Boric acid corrosion rates in excess of 1 inch depth per year in ferritic steels have been experienced in
- plants and duplicated in laboratory tests where low quality steam from borated reactor coolant impinged upon a surface and kept it wetted.
Additional information is contained in EPRI-NP-3784, "A Survey of the Literature on Low Alloy Steel Fastener Corrosion in PWR Power Plants," December 1984, and NUREG/CR-2827, " Boric Acid Corrosion of Ferritic Reactor Components," July 1982. Followup: The damaged HPI nozzle has been repaired by grinding out all indications of corrosion and rebuilding by welding in those areas with less than the minimum - required wall thickness. Repair to the cold leg reoutred only grinding out the corrosion. All repairs were in accordance with ASME codes. The other HPI nozzles were inspected and no evidence of corrosion wastage was found. The 4 licensee continues to evaluate methods and procedures to minimize recurrence of this type of event. The primary defense is to minimize leaks, detect and stop leaks soon after they start, and promptly clean up any boric acid residue, i Detection of leaks will be enhanced by an evaluation of any iron oxide stains
- on insulation.
! No specific action or written response is required by this information notice.
j If you have questions about this matter, please contact the Re strator of the appropriate NRC regional office or this office.gional Admini- . l b i dward [ Jordan, Director Divisi of Emergency Preparedness 1 and Engineering Response Office of Inspection and Enforcement 1 Technical
Contact:
Henry A., Bailey, IE (301)492-9006 ! Attachments:
- 1. Figure 1: ANO-1 HPI Line/ Nozzle Configuration
- 2. List of Recently Issued IE Information Notices i
4 1 (
- i. . - - - . _ _ _ . _ . - . _ _ _ _ _ --- _ _ _ _ -_- _ _ _ _ _ _ _ .., _ _ _ _ _ _ _ - - -
Figure 1: ANO-1 HPI Line/ Nozzle Configuration
, 2, t OALISOLATION I (I l , 2ZZZn VALVE a I
i 7 RCS Cold Leg Piping SS Line i i- SS Safe End i
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~ 8 Ft. \- >s A\\ .
u -____ ,s - - - d Mazzle-to-Cold Leg Weld ggg
- Inconel Weld 2=0
.???
4 4
-a I
Carbon Steel Nozzle ;88, (Dan.agedareashowndarkened) - - G
s Attachment 2 l IN 86-108 December 29, 1986 LIST OF RECENTLY ISSUED IE INFORMATION NOTICES Information . Date of Notice No. Subject Issue Issued to 86-107 Entry Into PWR Cavity With 12/29/86 All power reactor Retractable Incore Detector facilities holding Thimbles Withdrawn an OL or CP 86-106 Feedwater Line Break 12/16/86 All power reactor facilities holding an OL or CP 86-105 Potential For loss Of 12/19/86 All holders of OL or CP Reactor Trip Capability for PWR or BWR At Intermediate Power Levels 86-104 Unqualified Butt Splice 12/16/86 All pressurized and Connectors Identified In boiling-water reactor QualifiedPenetrations facilities holding an OL or CP 86-14 Overspeed Trips Of AFW, HPCI, 12/17/86 All power reactor Supplement 1 And RCIC Turbines facilities holding an OL or CP 86-103 Respirator Coupling Nut 12/16/86 All power reactor Assembly Failures facilities holding an OL or CP and fuel facilities i 86-102 Repeated Multiple Failures Of 12/15/86 All power reactor Steam Generator Hydraulic facilities holding Snubbers Due To Control an OL or CP valve Sensitivity 86-101 Loss Of Decay Heat Removal 12/12/86 All PWR facilities Due To Loss Of Fluid Levels holding an OL or CP In Reactor Coolant System 86-100 Loss Of Offsite Power To 12/12/86 All PWRs or BWRs Vital Buses At Salem 2 holding an OL or CP l 86-99 Degradation Of Steel 12/8/86 All power reactor Containments facilities holding an OL or CP l l 1 OL = Operating License CP = Construction Permit
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October 17. 1983 - PRELIMINARY NOTIFICATION 0F EVENT' 0R UIsl50AL OCCURRENCE Pm0-l!-83-82 - l This preliminary notification constitutes EARLY notice of events of POSSIBLE safety or i public interest significance. The inforestion is as initially received without verifi-cation or evaluation, and is basically all that is known by 'the Region, II~ staff on this date. FACILITY: Ytrginia Electric & Power Carpany Licensee Emergency Classification: ) Sorry Unit 1 , Notification of Unusual Event ! Docket No. 50-200 _ Alert - ' l Surry, Vfrginia .
, site Area Emergenc
- Eeneral taerm acy y ,
h t Applicab'e l
SUBJECT:
NONRA0!0 LOGICAL INDUSTRIAL FATALITY . t A 23-year-old control room operator trainee was killed instantly at 9:00 p.m. (EST) l Saturday (October 15) when a fist-stred hole alew open in the well of a 24-inch, carbon I i steel pipe attached to the Unit 1 "A" hiqh pressure feedwater drain pump. The men was l down in a valve pit in the auxiliary bui' c.ing to operate a suction valve and was hit by
- 360-degree stese from the rupture.
i A shift supervisor sustained second degree burns from his knees down during efforts to , remove the men from the plt. The supenitor was treated and released from a local I i hospital. The Ifne in which the failure occurred takes water from the feedwater heater drain tank on the secondary side of the plant to the feeduster heater drain pump. The Unit, which is served by seven feedwater heaters, continued operation at 100 percent power. l There was no contamination involved in the incident. The NRC resident inspector was notified of the event and reviewed circumstances associated with the event on Sunday. He will closely monitor the Itcensee's inquiry into the cause of the accident. Unf t 2 was also operating at 100 percent power at the time and was r.ot af fected by the accident. j The Itcensee did not issue a news release but has been respondine to wdta inoutetes. i The NRC does not plan to issue a news release. 1 1 Th2 Comonwealth of Virginia has been informed, as has the U.S. Occupational Safety and Health Administration. i a The NRC received initial notification of this event by telephone to the headquarters i i duty officer from the Itcensee at 9:32 p.m. (EST) on October !!. , This information is current as of 8:00 a.m. on October 17 1 )
Contact:
K. Landis, Rl! 242-5536 H. Dance, Rf! 242-5533 l
, ,, (,
j y R 831017 ,3 - V LI-93-082 PDft ' I. '\
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RELIMINARY NOTTFICATION OF.r: VENT OR UNUSUAL OCCURRENCE--PNO-III- 84-13 Dato February 3, 1984 hio preliminary notification constitutes EARLY notice of events of POSSIBLE safety or ublic interest significance. The information fa as initially received without vari-icati n or evaluation, and is basically all that is known by the staff on this date. acility: Northern States Power Licensee Emergency Classification: 1 Monticello Nuclear Generating Station Notification of an Unusual Event ' Monticello, MN 55362 Alert Docket No. 50-263 Site Area Emergency General Emergency Joe Applicable ubjcet: 30-WEEK OUTAGE TO REPLACE RECIRCULATION SYSTEM PIPING The licensee will commence a reactor shutdown on February 3, 1984, as it prepares for a 30-week outage'to replace recirculation system piping. The piping is being replaced as.a result of intergranular stress corrosion cracking. Other major activites to be completed during the outage include: Retubing the main condensor; replacing the main turbine low pressure rotors; replacing the high pressure feedwater heater; performing modifications oursuant to 10 CFR 50, Appendix R; completing Mark I torus modifications; and refueling the reactor. The news media has been informed of the 30-week outage. Both the licensee and Region III (Chicago) will respond to inquiries. The State of Minnecota will be notified. Region III has known of the scheduled outage for many months. This information is current as of 1 o.m. (CST), February 3, 1984 CONTACT: G
/J. Grebe
- r. .b
~ . Walker W. af FTS 388-5520 TS 388-5565 FTS 388-5656 .
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D9h%Q v v /T U gfchely* Johnson IISTRIBUTION!
- 1. St. MNBB Phillips E/W Willste
- hairman Pellsdino EDO NRR IE NMSS 1
- es. Gilinsky PA OIA RES l o: m. Roberen MPA AEOD I
- ocm. Asselstino ELD Air Rights MAIL:
.u.m. Burnthal SP INPO ADM:DMB
{CY NSAC DOT: Trans Only
\CRS l < ;A Applicabic Resident Site 'DR Regions I _ , II . IV ,V Licensee (Corporate Office) ha n^'"
ifarch 12, l'J84 uREt.IMINARY MOTIFICATION OF EVENT OR lini!SIML OCCHRRENCE PNO-II-84 21 This preliminary notifiedtion constitutes EARLY notice of events of POSSIBl.E safety or-publir (nterest $ttnificance. Tlee infomation is as init.f ally received without veriff-catinn or ovaluation, and is basically all that is known bv the f!egion Il staff on this date. MCit.ITY: Georgia Prver Company 1.icensee Enernency Classification:
~ ~ ~ - ~
Hatch Unit ? Notification of linusual Event Docket No. 50-366 Alert . Baxley, Georgia ~--~~~ Site Area Emergency
~
General Emergency -
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. f Not Applicable ELBilFCT!, CRACK $ IN REPLACEMENT RECTRCilt.ATION PIPE ELROWS The ifcansee has identified indications of crackino in all 1417-inch riser elbows'in replacement recirculation piping scheduled to be installed at this facility. The cracks are similar to thor.e found in otoing scheduled to be installed at Pilgrim during pipe replacement work (Daily Staff Notes - March 6,1984).
Gonarat Elec'tric has infomed the licensee that the cracking is t, tie result of improper for,ning temperatures used during the bendine; process. Th'c 1;censee will not use the cracked c1 bows but will install new elbows currentiv I being manufactured for Unit 1. Delivery is expected to take from four to six weeks and may delay restart of the linit. The Unit's four new 72-inch headers were also inspected and found not .to have Indications of cracking. The vendor group has baon informed. The State of Georgia has been infonned. helther Recion 11 nur Lhe licens44 plans to issue a news release. This infomation is current as of 1:00 p.m. (EST) today.
Contact:
.1. J. Slake, RI! 247-5639 .1. F. Roqqe, RI! ?42-55fia l stag.yg,g, f1 R g Y N El y y _ .. 401Y1$Yhf*._M
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PRFLIMLNARY NOTIFICATTON OF EVENT OR UNUSUAL OCCURILENCE--PHO-TII-H4-26 Dat3 March 13,1984 Tht:n preliminary notification constitutes EARLY notice of events of POSSIBI,E safety or TN public interest significance. The information is as initially received without veri-Cit tion or evaluation. and is basically all that is known by the staff on this date. rceility: Consumers Power Comneny Licensee Emergency Classification: Palisades Nuclear Plant Covert, MI 49043 Notification of an Unusual Event l Alert i Occket No: 50-255 Site Area Emergency General Emergency
.xx _Not Applicable
Subject:
AUXIl.IARY FEEDWATER PIPING DAMAGE During insoection of the two steam-qenerator secondary sides to verify support plate integrity af ter tube-oulting activities, damage was observed to auxiliary feedwater (AFW) soarger pioing for refueling andinmaintenance. both steam generators. The reactor has been shut down since August 12,1 In stean generator "s", horimntal to vertical) the wcld between the thermal sleeve and an elbow (which changes 2 f t.) vertical section above the elbow.is conoletely broken, as is a retaining clamo on the s The piping is physically disclaced about three inches, baf and fle into thesuch that most downcomer flow would byoass the AFW feed ring and solash off an internal region. The pioing subsequently loops back to the horizontal about a foot above the penetrathn, th forms a soarger ring covering about 120* of the internal circumference of the steam gene Feed In steam ' rom the soarger, generator "A", which is held by three retaining clamps, is via vertical "J-tubes" . one of these three clamps is missing, and the thermal sleeve is cracked circumferentially near the sleeve-to-elbow weld. ' The licensee has still-chotos and videotaca of these conditions. The vendor (Combustion Ergineering) needed. will be consulted to determine the cause of the damage and corrective action The olant was scheduled to resume coerations in May 1984. generator problems will delay startuo. It is not known if the stean The State of Michigan will be notified. Region III (Chicago) was informed nf these problems on March Inscector. This information is current as of 8 a.m., March 12, 1984, by the Senior Resides 13, 1984.
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CONTACT:
. 0 R. DeFayett
$ p D. Boyd h
FTS 388-5767 FTS 388-5546 m pg)g i
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- )tSTRIBL' TION:
- 11. St. NNBB Chairman Palladino Phillips_ E/W Ccan. 0111nsky EDO NRR IE Willate I PA NMSS Comm. Roberts MPA OIA RES Comm. Asselstine EI.D Agon Comm. Bernchal Air Rig i C sp '
I MB { Michelle Johnson Trans only CA Applicable Resident SL VDR Regions l_ . II _ IV
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. May 1. 1984 PRELIMINARY NOTIFICATION OF EVENT OR UNUSUAL OCCURRENCE PNO-II-84-31 This preliminary notification constitutes EARLY notice of events of POSSIBLE safety or public interest significance. The.information is as initially received without verf fi-catinn or evaluation, and is basically all that is known by the Region Il staff on this date, c.
FACILTTY:' Mississippi Power and Light Co. Licensee Emergy Classification: Grand Gulf Unit 1 Notification of Unusual Event Docket No. 50-416 Alert Port Gibson, Mississippi site Area Emo Twneral Eme P 6t Applicab n SUUJECT: CRACR 14 RESIDUAL HEAT REMOVAL SYSTEM PIPING l Licensee employees, making regular tours of residual heat removal (RHR) system piping areas at 5:40 p.m. yesterday. observed leakage from a three-inch lismuhich. rung from the "B" loop RHR heat exchangers' outlet to the reactor core isoleden cooling (RCIC) . system pump. This piping which is used in the steam condensing mode of RHR, was isolated, and the Tesk was stopped. The unit was operating at three percent power at the time. Preliminary inve'stigation by the licensee disclosed cracks in the pipe elbow and weld o-let located between the heat exchanger outlet and an isolation valve. The piping involved is a three-inch carbon steel line. Water haniner is thought to be the cause, as the hangers en the three-inch line are distorted and because no leaks were Mississippi Power and Li observed during earlier tours of the system that day.still investigating the cause of the c Because the "S' loop heat exchangers have been declared inoperable, and they cannot be used for containment spray, technical specifications require that the plant proceed toward cold shutdown if conditions are not rectified within 72 hours. A Region II metallurgist in on site. Both IE and NRR have been advised of the situation. Grand Gulf Unit 1 attained recrf ticality on April 22 after having been shut down since November 1983 for maintenance, operator training racertification and correction of eachnical specification deficiencies. The unit is limited to five percent power by its l operating license. ; Pedia interest may occur in view of continuing coverage of Grand Gulf. The licensee does not plan a news release, but is prepared to respond to inquiries. Region !! does not plan a news release. The State of Mississippi has been informed. The licensee infonned the NRC headquarters duty officer of this event at 7:49 p.m. yesterday. This information is currznt as of 3 p.m. today.
Contact:
C. A. Julian, 242-5535 A. R. Herdt. 242-5585 - Ifiche11e Johnson
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mesureussessessesse 005 No: 50317441120 Date: November 21, 1984 PRELIMINARY NOTIFICATION CF EVENT OR UNUSUAL OCCURRENCE--PNO-!-84-99 This pre 11minary nottf tcation constitutes EARLY notice of events of POSSIBLE safety or pubite interest significance. The information is as initially received without vorification or evaluation, and is basically all that is known by the Region I staff on this date. Fact 11ty: Baltimore Gas & Electric Co. Licensee Emergency Class'ification: Calvert Cliffs Unit 1 Notification of Unusual Event Alert (DN50-317) Lusby, Mary land Site Area Emergency General Emergency T Not Applicable
Subject:
' EXTRACTION STEAM LINE BREAX At 5:16 PM on November 20 Unit 1 was manually tripped from 100% pcwor due to the accumulation of dead fish on the circulating water intake pereen. (The fish kill resulted from the large ambient temperature drop). At 5:18 p.m. a steam break occurred and the main steam isolation valves were closed. Investigation revealed a break in the extraction steam line supply to a feedwater heater. A worker approximately 50 ft. away from the location of the break suffered burns of the face and left hand. He was taken to the hos released. During the trip all plant systems functioned property. pital and was subsequently Analysts of the break revealed a 30 inch long rupture at an elbow in the extraction stears line. The original 0.375 inch steel wall was eroded to razor thin thickness. The Itcensee is perfoming nondestructive examination on similar elbows in both extraction steam lines to determine minimum wall thicknesses.
The plant is currently in hot standby and the Itcensee is estimating a six day outage to complete evaluation and repairs. The Resident Inspectors are onsite following the licensee's actions.
'The State of Maryland has been notified.
CMTACT: "K. Perife 484-1121 T. Elsasser 488-1235
//E MD-0157R15UT!0N: .
W. St. MBB Phillips E/W Vf11ste_ Mati: ACM:DMB Chaiman PaHadino EDO NRR IE NHS$ 00T:Trans only Coss. Zech PA OIA RES
~Comm. Bernthal MPA AE00 Cons. Roberts ELD Casm. Asselstine
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ACAS Air Rights . SECY $P CA Michelle 3302 MNBB Johnson (2) POR Regional Offices - Licensee: (Reactor Licensees) Aegion ! Forn 83 _ (Rev. J31y,1984)
DC5 No: 50-293/M0705 Date: July 5, 1984 ' PRELIMINARY NOTIFICATION OF EVENT OR UNU$UAL OCCURRENCE--PMD-I-84-SS. . . . . , -- This prettuinary notification constitutes EARLY notice of events of P05$3tl safety '
~
or public interest significance. The information is as initially received without , verification or gvaluation, and is basically al,1 that is known by the Aetlion 1 staff on this date.
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Facility: Boston fdison Company _ -. _. - - - Pilgrim Licensee Emergency Classifictattsp:.'. .. Nott fication of Unusual Eveet Docket No. 50-293 Alert Site Area Emeygeety . : :::::: .:::: General En.w.:.w. -- t- _ . _ l X Not App 11 cable
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Subject:
INTERGRANULAR STRESS CORROSION CRACKING IN PIPING OUTSIDE CONTAIMENT - fr,dications of Intergranular Stress Corrosion Cracking (IGSCC) have been detected.in portions of the residual heat remoYa1 (RHR) and core spray systeas which are not currently scheduled to be replaced daring the on going outage. i The indications of small cirebuferentiel' cracks were identified in two RHR and one core spray pipe welds located just outside ther drywell. In both systems, the affected welds are between the drywell and the firstiinjection valve. , The licensee pipe welds is eYaluating during the outage. the IGSCC indication and plans te inspect,4ddikiOSA.I cere-Spr4y The Comonwealth of Massachusetts has been informed. - I Region I will continue to monitor the licensee's actions. l l . l I. CCNTACT: J. Beall ' 8-488-1318 j........
; DISTRIBUTION: ' ' ' ' ~ ~ "
i H. St. MN88 Phillips E/W W111ste t i Chairman Palladino EDO NAA Maili W :W -' IE M55 . ,IET:Trsas sely -
. ... . PA O!A AE5 - - --
1 Comm. Bernthal MpA AE00 ' Cosa. Roberts ELD Ccan. Asse1stine '
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. .. p v y DCS No: 50311/840705 '
Date: July 5, 1984 . . [_ ; *. .. . '
- N!14! NARY NOTIFICATION OF EVENT OR UNUSUAL OCCURRENCE--PN0-1-84-59 1Hs preliminary nutification constitutes EARLY notice of events of POSSIBl.E safety or sublic interest significance. The information is as initially received without va'ficattan or evaluation, and is basically all that is known by the Region J statt on this date. ,, ,, .,, ,,
ni11ty: Punlic Service Electric & Gas Co. Licensee Emergency Classification: . Salem Nu.-leae Generating Station X Notification of Unusual Event Unit 2 .- . . . . . . Alert : "" "" . . . . _ _ . _ _ . _ . ON 50-311 _ Site Area Emergency . . .. .. General Emergency ... _. _. __. . _ Not Applicable ! l . ..
$;ofe::: J LEO CUTAGE TO REPAIR PIPE LEAK UNSCHED' m -- NN u 6:.!2 a.m. on July 5,1984, the licensee ccminenced a shutdown of the unit f' m N 1005 power 5:3u.e o' through wall cracits in the 8-inch charging pump common suctio'n Ifns hea? Ont valve i' C W 7. The unit was off-line at 9:42 a.m. and suberitical at 9:48 proceeding.toward eold shutecwn. ,
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**ttid reports from the NRC r esident office indicate two cracks approximately 3/4-inch and 94-inch icog tengential to ar.d on either side of the weld where ,the 3/4-inch,yntli_ng.,10(ns rne 5-inch aipa. The cracks are parallel to the 8-inch pipe centerline.
- 1 ihe Ingth of the outage to of fect repairs is currently unknown. ;
% l'ce.6se+ has included this event in their daily public information phone pe sessage.
Tu Ntc.s of New Jersey and Delaware have been notified. ,, .. .. t
- W ACT: J Linville L. Norrholm j 488-1067 488-1114
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- M11T' JDi:Us NRR IE NMS5 DOT:Trans only PA DIA RE5 Mre Bernthal MPA AE00
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om. Asselstine ' CRS Air Rignts -!NPO---- f***- ICY SP NSAC---- I A . _. _. . - -- JR Regional Offices
- THI Resident Section.._'.. _ . . .
R1 Resident Office I Licensee: (Reactor Licensees) - 4lca 1 form 83 ! ja[UN __ . tev. July,1984) ' ' u
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M LIMINARY NOTIFICA. gN OF EVENT OR UNUSUAL CCURRENCE--PNO-Ill-84 10 Date _11/30/84 This preliminary public notification constitutes EARLY notice of events of POSSIBLE interest significance. The information is as initially received without veri-I fication or evaluation, and is basically all that is known by the staff on this date.
; Factifty: Comonwealth Edison Company Licensee Emergency Classification:
Dresden, Unit 2 (Docket No. 50-237) Morris, IL 60450 Notification of an unusual Event , i' Alert
~ Site Area Emergency i General Emergency w Not Applicable
Subject:
CRACK IN0! CATION IDENTIFIED IN RECIRCULATION SYSTEM PIPING j i The licensee reported that a crack indication has been confirmed in one weld in the
! recirculation system pump discharge piping (28 inch diameter piping). Initial i
l information one approximately shows inch the indication in length with an to unknownbe in the depthheat affected at this time. Thezone of weld unit has ) been shutdown inspection since October 5,1984 for refueling, maintenance, and inservice activities. Ultrasonic examination of approximately 40% of the welds included in the augmented i inspection date program with no as required indications by NRC Generic Letter 84-11 has been completed to reported. i indication and possible corrective actions.The licensee is continuing evaluation of the The Resident Inspectors and Regional Specialists are monitoring the ifcensee's activities. t in this matter.The Office of Nuclear Reactor Regulation (NRR) has lead responsibility i The State of Illinois will be notified. j Region III learned of this development via comunication with the licensee on November 29,1984 at approximately 4:00 p.m. (CST). of 10:45 a.m. (CST) on November 30, 1984 This information is current as l CONTACT: h N. Chrissotimos W. Key FTS 388-5716 FTS 388-5583 { i I I Yl0h ' O!STRIBUTION:
! H. St. MNB8 Phillips Chairman Palladino E/W- W111ste EDO NRR 1E i Comm. Roberts PA NMSS Conn. Asselstine 01A RES MpA Come. Bernthat AE00 .
i comm. Zech ELO Air Rights MAIL: SP INP0 SECY ADM CM8
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ACR$ DOT: Trans Only
; CA Applicable Resident Site i PDA -
Regions ! , II , IV ,V Licensee (Corporate Office) 1 1 Rev. 07/06/84 i _ - _ _ _ _ _ _ _ _ _ _ _ . _ _ _ __ _ .._._ ~ _ - _ _ ------_ _ _ _.-_.-
Date: December 13, 1984 PRELIMINARY NOTIFICATION OF EVENT OR UNUSUAL OCCURRENCE..PNO-!-44-104 This preliminary notification constitutes EARLY notice of events of POS$!BLE safety or public ! intsrest si The information is as initially received without verification or evaluation,gnificance.and is basically all that is known by the Region ! staff on this date. l
- Facility: Baltimore Gas and Electric Licensee Emergency Classification:
Company ,#etification of Unusual twent i Calvert Cliffs Nuclear Power Station _ Alert Site Area fuergency t Unit 1(50-317) ~ ~"Seneral Emergency Lusty. Maryland T Net Applicable
Subject:
DEGRADED 5 ALT WATER SYSTEM On December 10, 1944, thelicenseeinformedtheSeniorResidentInspector(SA!)of l deterioration of the Salt Water System (SWS). Two leaks have developed. Each is on an
- isolable elbow section of the concreto lined SWS piping downstroom of the No.11 and No.12
! salt water pumps. The licensee has kept the system in operation by placing a temporary patch ! over one leak and isolating the pipe section containing the second. There is no immediate
{ safety hazard associated w' th the currently identified degradation. l The licensee had previous corrosion problems with the SWS (Ref: PNO-!-84-41. -42. -42A and ! Meeting 80 317/84 41). Unit 1 was shutdown in May 1944 when extensive deterioration was discovered in the salt water channel heads of both the primary and secondar
! water heat exchangers on both Units 1 and 2 (eight heat exchangers total). y component coo
! salt water system components were subsequently ' dentified as being d graded but at markedly different rates depending on the local environment. Concrete-lined 1pe sections were not identified as a significant deterioration problem at Unit 1 before t e current problem but piping similar to the leaking Unit 1 pipe had been replaced on Unit 2 with a rubber.lin,ed
- carbon steel pipe, i
l Presently, preliminary ultrasonic testing indicates that the corrosion / erosion of the leaking
- pipe section is localised. Current plans are to replace the 1eeking sections of pipe and
' examine addacent isolable sections. If the excessive deterioration is not leea11aed to the elbow secttons, pondestructive examination of accessible concreto-lined SWS seetiens will be performed to assess the problem further. Also, a complete walkdown of the SWS piping is
; planned during the Spring 1988 refueling outage.
The SRI is following the licensee's inspection program and evaluation. Re o follow the licensee's action. The State of Maryland has been notified.gion I williscontinue This PN for femation. l 3 g ACT: 7.Felb.2628 (alg) K. Ferlic 8 448 1121 _hN!N ' 1 - 0!$7A!8Uf!ON: 1 N. 3 MN88 Phillips ~ t/W W111ste ~ Meil ADMIDMS Chet T73TTIIine t00 """" NRA !! NMS$ 007:frans only Comm. h PA CIA ASS
- Comm. Bernthal MpA At00
- Case. Roberts ELO l Case. Asselstine i ACAS g Air Afghts INP0. -
i ) SECY SP NSACao CA l POR Aegional Offices TMI Assident Section i Al Assident Office l I,isensee: _ l (AcesterLicensees; tee ete'm ______Qy par _yy( =,.
t *d 1wloi 1 d rais seess/so vi m Av. san wows February 22,1M5 PRELIMIMMY NOTIFIChi- . 0F EVENT OR UNUSUAL OCCURRENCE PN0-!!-48-20 This re11minary fee constitutes EARLY notice of events of poss!stt safety or pubtf interese sign The inferination is as inttielly received withest verifi-catten er eyelvation, a e basically all that is known by the Region !! staff on this Cte. M Tennessee Valle Authority Licensee Emergency Classificatient trouna Fe Unlt 2 <.
" Notification of Unusual Event Osaket No. 260 .
Alert Athens, Alabama site Area Bnergency eeneral Beerpncy A Mot Applicat e M THROUSf-idALL CRACK IN.P!P!NG The Itsensee re ed that on February 21 at 5:00 p.m. CST) crack was iden fed at the welded , junction of the reci(rcula, tion header and the risere on sections (GR-t-15 on the 1eop. , The licensee is evaluating the piping in order to determine the appropriate corrective action to be taken. Region II will conduct a routine follow-up to see that 'the licensee takes required corrective action. Media interest is not expected. The licensee does not plan to issue a news release. The State of Alabama has been informed. Region II (Atlanta) recefved initial notification of this event from the duty officer in the headquarters incident response center by telephone at 5:45 p.m. (IST). on February 21. This inferinstion is current as of 1:00 p.m. (EST) on February 22. ,qujg1L K. Jenison 242 419g J. slake 242-5539 D!sTR!sUT!0N: da rina ralladino Comt. Roberts PA OTA RES DCT: Trans Only Cous Asselstine WA Ar00 Applicable state Cash Bernthal ELD Case,Zech Air Riehts INP0 SECY 3r NSAC MM a
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CA ~, .i POR Regions: m 4 Licensees M ' -- eactor Licensees) '8 ,f.' 11 cable Resident Site ? O A;h.' l R m (a' I w e cas E ! SO$t%Q-Qff"'"*
PRET.!MINAMY NOTIFICATION OF EVENT OR UNUSUAbOCCURRENCE 0 te March- 13. 1985 public interest significance.This preliminary notification cotistitutes EARLY notice A of fication or evaluation, and is basically all that is known by the staffYon th i Facility: Iowa Electric Light & Power - Duane Arnold Energy Center Licensee Emygency Classification: Palo. IA 52324 Notification of an Unusual Event Alert Docket No: 50-331 Site Aree Emergency General Emergency xx Not Applicable j Sbbject: THROUGH-THE-WALL CRACX IN RECIRCULATION PIPING The from unit is in cold the reactor shutdown for an extended refueling outage. All fuel has oeen removed vessel. At 1 a.m. (CST). March 13. 1985 following application of an Induction Heating c Stress Improvement (IHSI) treatment to a weld on a 10-inch pipe (riser) in the Recirculation ! Systen piping, the licensee notedl water seeping through the treated weld. The licensee i datemined about one-half that the water was coming from a through-the-wall circumferential crack meas inch. (The weld and crack are located on the riser just before the riser enters the reactor vessel.) Inservice Indications. inspections perfonned prior to the IHSI treatment did not reveal any rejectable following completion of the IHSI treatments.The licensee is scheduled to perfonn add The licensee is currently evaluating the crack and corrective measures. Region III will monitor to the plant. the licensee's course of action. A Region III pipe soecialist will be dispatched
, The State of Iowa will be notified. '
The Senior Resident Inspector wasq notified of this event at 10 a.m. (CST), March 13, 1985. This information is current as of 12:15 p.m. (CST), March 13,' 1985.
*/ /- TV CONTACT: D. Boyd R. Warnick FTS 388-5546 388-5575 M r ox Trstr3W Y-DISTRIBUTION: ^
- d. St. MNBB Phillips._
~,hairman Palladina E00 NRR E/W Willste IE NMSS Comm. Roberts PA OIA RES Comm. Asseistine MPA AE00 .
Cosm. Bernthal
- ELD Air Rights Cons. Zech MAIL:
m SP IMP 0 SECY ADM:DMB NSAC DOT: Trans Only
'ACRS CA Applicable Resident Site
, fDR Regions I _, II , IV .V Licensee (Corporate Office) {} Rev. 07/06/84
PRELIMINARY NOTIFICATION OF EVENT OR UNUSUAL OCCURRENCE PNO-II-85-102 This preliminary notification constitutes EARLY notice of events of POSSIBLE safety or public interest significance. The information is as initially received without verifi-i cation or evaluation, and is basically all that is known by the Region !! staff on this date. FACILITY: MississippT Power & Light Company Licensee Emergency Classification: Grand Gulf Unit 1 Notification of Unusual Event i Docket No. 50-416 _ Alert i Port Gibson, Mississippi Site Area Emergency General Emergency T ot Applicable I
SUBJECT:
CRACK INDICATIONS ON SURFACE OF RECIRCULATION PIPING Mississippi Power & Light (MP&L) has detected numerous crack-like indications on the surface of the cross assembly which ties the 24-inch discharge piping of one recirculation pung to the piping's associated jet pump 16-inch ring supply header. The indications were disclosed by dye penetrant testing after MP&L's contractor, Nutech Engineering Inc., had performed induction heat stress . improvement work on selected recirculation piping welds. These indications are circumferentially located within a _ seven-inch band below the cross-to-cap weld area and within a six-inch band above the cross-to-discharge piping weld area. The base metal is more than two inches thick at these locations. Tha indications are about three-quarters of an inch long and a quarter-inch deep, with the exception of one indication in the lower six-inch band which is about three and a half inches long. MP&L believes they are related to the induction heat stress improvement process. Grand Gulf Unit I has been shut down for scheduled maintenance since October 13. Region II is monitoring MP&L and Nutech's continuing evaluation, and is keeping the Offices of Nuclear Reactor Regulation and Inspection and Enforcement advised. MP&L is prepared to respond to media inquiries.
.The State of Mississippi has been infonned.
This information is current as of 2:30 p.m. (EST) today.
Contact:
R. Carroll, 242-5543 8. R. Crowley, 242-5579 DISTRIBUTION: H. Street MNB8 Phillips _ELW, Willste MAIL: Chainnan Palladino W NRR IE NM55 EIiiDh8 Comm. Roberts PA OIA RES 007: Trans Only Com. Asselstine MpA AE00 Applicable State Cosen. Bernthal ELD Com. Zech Air Rights INPO SECY SP NSAC ACRS CA Licensee: Michelle Johnson (ReactorLicensees) 3302 MNSB Applicable Resident Site DM) / / A Al / Q s ir{f (j %~ "
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s . . ,7 . s - ./ DCS No: 50244860729 l Date: July 29, 1986 . . . -)RELIMINARY NOTIFICATION OF EVENT OR UNUSUAL OCCURRENCE--PNO-I-85-58
- this praliminary notification constitutes EARLY notice of events of POSSIBLE safety 3r public interest significance. The information is as initially received without
- eerification or evaluation, and is basically all that is known by the Region I , //
, staff on this date, r r acility: Rochester Gas and Licensee Emergency Classification: Electric Company X Notification of Unusual Event % R. E. Ginna Station Alert Ontario, New York Site Area Emergency ON 50-244 General Emergency Not Applicable
Subject:
ORAIN LINE BREAK l ivsnt At 3:51 A.M. , July 29, 1986, the reactor was manually tripped from 100% power because - af a break in a 6-inch drain line from the 2A main steam reheater to the SA feedwater neater. All ECCS operated as expected following the scram. No radiological release
- and na injuries occurred. The reactor is currently in hot standby. The licensee is investigating the cause of the line break and the extent of work necessary to restart lths unit. The licensee declared an, Unusual Event at 4:00 A.M. and terminated the Event at 5:14 A.M. The resident inspectors are reviewing licensee actions.
.Tha State of New York has been notified.
lThe Licensee conducted a press briefing at 8:30 A.M., July 29, and also issued a press
- release. Region I has responded to media inquires.
- CONTACT: R. Gallo 488-1234
. DISTRIBUTION:
- d. St. MNBB Phillips E/W Willste Mail: ADM:0MB
- Chairman Zech E00 NW lT NMSS 00T
- Trans only OIA RES l PA Comm. Bernthal ELD AE00 Comm. Roberts Comm. Asselstine ACRS Air Rights INPO----
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.CA ?DR Regional Offices TMI Resident Section RI Resident Office Licensee:
(Reactor Licensees) Region I Form 83 l (Rev. July, 1986) e b, L n T hegge Degose, IE e-. W7 &T "goz mBB
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4 December 10, 1986 l PRELIMINARY NOTIFICATION OF EVENT OR UNUSUAL OCCURRENCE PNO-II-86-91 l This preliminary notification constitutes EARLY notice of events of POSSIBLE safety or public interest significance. The- information is as initially received without verifi-cation or evaluation, and is basically all that is known by the Region II staff on this date.
- FACILITY
- Virginia Electric & Power Company Licensee Emergency Classification:
Surry Unit 2 Notification of Unusual Event l Docket No. 50-281 X Alert Surry, Virginia Site Area Emergency ~ General Emergency Not Applicable
SUBJECT:
PERSONNEL INJURIES FOLLOWING SECONDARY SYSTEM PIPE BREAK On December 9,1986, at 2:20 p.m. (EST), with both units operating at 100 percent power, Unit 2 experienced a reactor trip after receiving a low-low water level signal from its "C" steam generator. Shortly thereafter, an 18-inch feedwater line ruptured upstream of the -
"2-A" main feedwater pump, injuring eight contractor personnel, some seriously, who were working in the area.
Operators immediately isolated the affected area in the secondary system. Of the eight ' i persons injured, the more seriously injured personnel were transported to area hospitals. ' Five remain in serious condition, suffering from burns, in local general hospitals. One fatality has occurred and two others have been treated and released. The licensee maintained the Unit in a stable condition, following the reactor trip and shutdown of the secondary system's main feedwater pumps, by feeding water to the steam generators through the auxiliary feedwater system and by venting steam from the steam ! generators through the power operated relief valves. i ,' The licensee declared an Unusual Event at 2:30 p.m. (EST) and escalated it to an A1.ert at 2:40 p.m. (EST). Both were terminated at 4:23 p.m. (EST) after all plant personnel had {> been accounted for. Upon notification of the event, Region II manned its Incident Response Center and went on Standby. The Regional center remained in constant contact with Headquarters and the Surry control room throughout the event. The Regional center was downgraded from standby at 5:05 p.m. (EST) but remained staffed until 2:30 a.m. (EST) December 10, 1986. The Surry senior resident inspector was at the site and the North Anna senior resident inspector arrived at th'e Surry site at approximately 7:00 p.m. (EST). A four-person Regional inspection team arrived at the site at 10:20 p.m. (EST), led by the Deputy Director of the Division of Reactor Safety, and accompanied by a Regional public affairs officers. Preliminary information from the inspection team indicates that the probable cause of the low-low steam generator water level was shrink associated with the failing shut of the "C" main steam isolation valve. The ruptured suction line experienced a circumferential break in the elbow on the "A" mainfeed pump header. The pipe was displaced several feet by the force of the rupture. Today (December 10) the NRC site team has been officially implemented as an Augmented Inspection Team (AIT) after being joined by a Regional metallurgy expert and a water hammer expert. from the Headquarters Office of Nuclear Reactor Regulation. 71 . . . > _ ~. OW/b UfuV
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linit' 1 resained at 100 percent power throughout tha period, but the licensee has announced that Unit I will be shut down at 7 p.m. (EST) tonight for inspection and evaluation. Considerable media interest has occurred. The licensee and the NRC responded to numerous media inquiries throughout the night. The licensee activated its emergency news center in Richmond for a time last night and held two news briefings today. A Region II public affairs officer participated in those briefings. The Commonwealth of Virginia was notified, and Region II has kept state officials fully informed throughout the night and today. Health physics surveys of the damaged area, and of injured personnel, indicated that the individuals were not contaminated prior to transport offsite and that no radioactivity was involved with the event. As of 7:03 a.m. (EST) today, the Unit was in cold shutdown at less than 200 degrees (F). The NRC (Region II) received. initial notification of this event by telephone from the resident inspector at 2:25 p.m. (EST) on December 9. This information is current as of 4:00 p.m. (EST) on December 10.
Contact:
R. Croteau, 242-4668 F. Cantrell, 242-5534 l l DISTRIBUTION: H. Street MNBB Phillips E/W Willste MAIL: Chairman Zech UT NRR TF NM55 XDEIIMB Comm. Roberts PA OIA RES DOT: Trans Only Comm. Asselstine MPA AE00 Applicable State Comm. Bernthal ELD Comm. Carr Air Rights INPO SECY SP NSAC ACRS CA Regions: PDR Licensee: ! (Reactor Licensees) Applicable Resident Site I
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November 15, 1986 ( PRELIMINARY NOTIFICATION OF EVENT OR UNUSUAL OCCURRENCE PNO-II-86-91C {I This preliminary notification constitutes EARLY notice of events of POSSIBLE safety or public interest significance. The information is as initially received without verifi-cation or evaluation, and is basically all that is known by the Region II staff on this d nt'). FACILITY: Virginia Electric & Power Company Licensee Emergency Classification: Surry Units 1 and 2 Notification of Unusual Event Docket Nos. 50-280/281 Alert Surry, Virginia Site Area Emergency General Emergency X Not Applicable l l
SUBJECT:
SECONDARY SYSTEM PIPE FAILURE - UPDATE This PN updates PNO-II-86-91, PNO-II-86-91A, and PN0-II-86-91B, issued on December 10, , December 11 and December 12. During the weekend, ultrasonic testing in Surry Unit 1 of a piping elbow similar to that which broke in Unit 2 disclosed a minimum pipe wall thickness of .16-inch. Design sptcifications call for this pipe to be half an inch thick with a minimum code allowable thickness of .36-inch. Ultrasonic testing is continuing. Most members of the Augmented Inspection Team (AIT) left the site on Friday, December 12. One inspector from the Region II office remained on site until yesterday morning observing the licensee's continuing investigation. The resident inspector also was in contact with VEPCO officials during the weekend. Region II management will decide today on deployment of additional personnel to continue the NRC inspection. Today, VEPC0 is conducting a tour of the accident area for representatives of the Commonwealth of Virginia. A similar tour was conducted Friday for representatives of Surry County, and a visit is scheduled for tomorrow by officials of the City of Newport News. Extensive media coverage continues. VEPC0 conducted another news conference for television reporters Friday afternoon, participated in by a Region II-based NRC public affairs officer who accompanied the AIT. VEPC0 on Saturday announced the findings of the ultr onic tests of the Unit 1 piping. NRC is continuing to respond to inquiries. This information is current as of 3:00 p.m., (EST) today. 4 c F. S. Cr 00 ,e. *
Contact:
R. Croteau, 242-4668 9 DISTRIBUTION: H. Street MNBB Phillios E/W TE-Wi. NMS, (( Chairman Zech E5D- NRR Comm. Roberts PA OIA RES . Trans Only Comm. Asselstine MPA AE00 8pplicable State Comm. Bernthal ELO Comm. Carr Air Rights INPO f ) /_ j g a s _ ,_ s SECY SP NSAC _ W/ m J ()yj ACRS
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