ML20204G707

Forwards Engineering Evaluation Rept AEOD/E416, Erosion in Nuclear Power Plants

ML20204G707
Person / Time
Issue date:	06/11/1984
From:	Ellen Brown NRC OFFICE FOR ANALYSIS & EVALUATION OF OPERATIONAL DATA (AEOD)
To:	Seyfrit K NRC OFFICE FOR ANALYSIS & EVALUATION OF OPERATIONAL DATA (AEOD)
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ML18150A013	List: ML20204G707 ML20204G724 ML20204G738 ML20204J362 ML20204J416 ML20205B005 ML20207Q696
References
AEOD-E416, NUDOCS 8407160035
Download: ML20204G707 (2)

Text

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?, ' v June 11, 1984 AEOD/E416 MEMORANDUM FOR: Karl V. Seyfrit, Chief Reactor Operations Analysis Brancn Office for Analysis and Evaluation of Operational Data FROM:

Earl J. Brown, Lead Engineer Engineering Systems Reactor Operations Analysis Branch Office for Analysis and Evaluation of Operational Data

SUBJECT:

EROSION IN NUCLEAR POWER PLANTS The enclosed Engineering Evaluation Report is forwarded for your information and further consideration.

The report concludes that the data base should only be considered representative of the types of degradation that can occur due to erosion rather tnan a complete list of events and that there are potential safety issues even though it does not seem feasible to identify a specific safety problem that requires immediate attention. Areas in which constructive action may be possible are (1) recognize that certain sites or systems appear susceptible to erosion, (2) identification of specific plant equipment and physical configurations that appear susceptible to erosion, and (3) implementation of monitoring programs to detect degradation of equip-ment (pumps, valves, heat exchanges, and piping).

Some areas appear to have potential safety implications and the report suggests that NRR consider and review the following:

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 suc:1 as valves and orifices, or a combination of the effects of water with suspended solids and a throttling device.

Service water systems appear to be candidates for monitoring to detect degradation.

2.

Erosion of J-tubes in steam generator feedwater headers may warrant consideration for possible monitoring and detection requirements if water hammer relates to a specific safety issue.

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. Karl V. Seyfrit 3.

The emergency feedwater system at Ft. St. Vrain has had approximately 25 erosion events and appears worthy of review for possible safety implications.

.c B.

Steam Systems 1.

The current NRR review of MSIV leakage should be continued until it is satisfactorily resolved.

2.

A review of available data on leakage or~ rupture of steam piping appears to suggest that erosion could pose a personnel (worker) safety concern in contrast to a plant safety problem.

Some licensees have implemented monitoring programs to detect-degraded piping.

It is appropriate to emphasize that a general data base search on erosion will not retrieve all events associated with the penomenon and may in fact miss, as discussed in the report, some safety significant events such as identified in Reference 12. This suggests that a review of individual events may identify safety concerns that are not apparent from a broad overview such as this report.

xb I)1..t(s. N Earl J. Brown, Lead Engineer Engineering Systems

Enclosure:

As Stated l

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AE00 ENGINEERING EVALUATION REPORT

• UNIT: See Table A EE REPORT NO.: AZOD/E416 00CKET 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

SUMMARY

This engineering evaluation covers a broad overview of erosion events in nuclear plant systems.

The initial impetus was the rupture of an extraction stean 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 sys tems. 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 feasible, potential i

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.

i Systems and components with these conditions may warrant considera-tion for monitoring as part of ongoing inservice inspection programs to detect degradation.

• This document supports ongoing AE00 and NRC actfities and does not represent the position or requirements of the responsible NRC program office.

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9 2-2.

Service water systems aopear to be ideal candidates for erosion and warrant monitoring for degr3dation and potential impact on safety rel a ted' equi paent.

There aay ae a relationsnip oetween sizing critaria for accident cunditions 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 tnat nay lead to draining of the feedwater header anc suosequent wa ter hammer.

4, The emergency feedwater systen at Ft. St. Vrain has had approxinately 25 erosion events in valves and piping.

3 Steam Systems 1.

Erosion of MSIV seats way lead to leaxage and adversely fapact the leakage control syste1. This issue is currently undar review by URR and we suggest it continue until it is resolved.

2.

Leaxage or rupture of steam piping may oe more frequent than the data indicates because the events are generally not recortaole.

Je are not aware of ruptures that nave affected safety systaas. Plant specific reviews may be needed in order to identify specific safety issues.

Data suggests that pipe ruptures may pose personnel ( orker) safety

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% 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 information 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 and 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.

The pipe rupture event at Oconee 2 occurred at the outside radius of an elbow 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 large steam piping with leakage or rupture caused by erosion.

It soon became evident that large steam piping in which erosion related degradation had 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.

DISCUSSION Based on the preceding information, the search for erosion events was broadened to cover piping system components in addition to the piping; also, information 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 subJivided by system.

For each event, 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 fran 1976 to early 1984.

The total number of erosion events listed in Tables Al through A4 exceeds 140 events. The approximate breakdown for events is:

Table Al with 14 events 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 high pressure coolant injection (HPCI) and reactor core isolation cooling (RCIC); A4.2 for feedwater systems; and A4.3 for service water and other systems.

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f 1 The erosion events If sted in Table Al involving pumps primarily address erosion of pump internals, bell nousing, and coolers for notors or oil.

Five of the 14 events sere for leaks in the notor cooler for the same hign pressure service water pwnp at one plant.

The erosion for tne motor cooler was attriouted to continuous flow of lake water tnrough the cooler wnetner the pump was in use or not. Although tnis would appear to be a potential generic situation for all such pumps at tnat plant, there were no otaer reported failures in tne data Dase.

Eight of the 14 events involved either raw water systens or radwaste systems.

This appears to indicate that particulates in suspension in the water systeu weregtn important aspect contributing to tnese erosion events.

Ital 4 of Tab e Al provides an example of significant erosion of all four service water ownp casings after 12 years of plant service. The raw water source was tne dississippi River. Althougn t..'re was significant casing erosion and a small leak in pump 1 A (estinated at two gallons per day), pump performance still net aesign requirenents.

Actual operating time of the nudos nas estinated to be 300 nours per year per pung for a total of 3600 nours during the 12 years (Ref. 3).

This would suggest a maxinum pump running time of 150 days on a continuous running oasis.

The erosion events affecting valves were observed to involve both steam and water systems. One type of valve in stama service that has received previous NRC attention for seat leakage is main stema isolation valves (dSIV).

Reference 4 (IE IN 82-23) identified over 151 inservice tests in which an JSIV failed to meet a maximum permissible leak rate.

The IN indicated that 19 operating SURs were involved. Fran the standpoint of erosion, the IM identifies only three plants (Browns Ferry 1 and 3 and Quad Cities 2) tnat attribute ilSIV seat leakage to stemn erosion.

This AE00 search for erosion events identified MSIV leakage (Table A2) at Browns Ferry 1, 2 and 3, not the same Leas as in Ref. 3 in all cases, but 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 detennination such that erosion or some other surface condition may be contributing to the occurrence of MSIV leakage.

The primary concern about itSIV leakage relates to offsite dose calculations following a LOCA. The r4RC staff approach for dose contributions from 11SIV leakage is based on a technical specification pennitted limit.

Exceeding 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 i

appears that causes of leakage, such as erosion, could have an important impact on resolution of the HSIV leakage contribution to offsite doses following a LOCA.

~

t' 1 The issue of MSIV 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 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 sumrtary of the BWR Owners Group meeting with NRC staff as part of the staff evalua-j l

tion of MSIV leakage. We understand that evaluation of this effort will be a part of the resolution for Generic Issue C-8.

The number of reports on valves were distributed amarg all reactor types with 11 for P'4Rs,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 were 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.

j The other event was at Beaver Valley in which erosion of a check valve hinge pin in the river water system resulted in j

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).

i The 19 valve events in BWR plants involved 10 with steam service and nine l

in water filled systems. For steam service, as discussed previously, three i

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 result 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 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

1 1 pressure and the reactor pressure vessel operating pressure.

Hence, an increased simmer margin should reduce leakage and subsequent erosion of pilot The remaining two events involved drain lines for the main steam seats.

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 erosion related problems involved wear through the wall of valve oodies, ruboer seat deterioration, and retaining device wear (set screw).

Although this search identified about 30 events associated with erosion of valves, a recent AEOD 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 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 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 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 repl aced. The remaining 9 events include two with leakage in fan coolers and eight involving lube oil and motor cooling heat exchangers.

The most prevalent systems affected by the oil cooler leakage were the charging pumps in the chemical and volume control system and emergency diesel generator at the Salem site (5 of 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 result in pump damage and loss of capability to perform the intended function.

Table A.4 identifies events related to erosion of piping with nearly 60 reports.

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 distribution of reports among plant types and the number of reports appear to be questionable relative to completeness or signficance. To illustrate, the 19 BWA events include 15 reports submitted by a single licensee. Each of these 15 events i

was an LER for a steam leak in a drain line with 6 of the 15 for a HPCI or RCIC 1

' steam supply drain line. These types of leaks could be relatively common, but no reports by other licensees were retrieved from the data base.

Although the number of steam leaks seems rather large and yet may be repre-sentative of events at a given plant, the absence of reports by other licensees suggests interpretation of reporting requirements may be a reason fc 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.

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 Vemont 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 (PN0), but the licensees were not required to prepare an LER and none was submitted for either event.

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 reported were generally associated with the steam generator including drains.

Since the steam generator is safety-related, these events were covered by reporting requirements (or at least interpretated as such).

The other seven events involved leaks or rupture of large 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 pla~nt safety issues.

Some of the pipe ruptures have resulted in destruction of equipment such as a motor control center and instruments but no safety-related loads or functions wre 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 were 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 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.

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T, t The very nature of transporting high velocity steam with pipe bends and possible pressure changes makes piping susceptible'to erosion.

It appears from discussions 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 cased on wall tnickness enanges (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 thinning of approximately 805 (from.350" to.070") without leaking or rupture.

In addition, several plants ' ave replaced piping and elbaws with more erosion resistant materials while co.tinuing a monitoring program.

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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.

The event at Ginna involved a hole in one J tube and up to 50*. wall loss in all 38 J tubes.

Similarly, Surry 2 reported holes 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 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 requirements.

The remaining two reports associated with feedwater systems were both for the emergency feedwater supply to the loop 1 helitan circulator at Ft. St. Vrain (HTGR).

In addition, these two reports referenced seven other reports covering erosion events between 1980 and 1982 on this system. 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 valvt 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.

The other ' LWR event appears to be an isolated occurrence with the TIP system due to flow characteristics in the cleanup equalizing itne.

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t 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 an t). 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.

Furthermore, 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 I

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 i

through eroded tubes could mix with oil and subsequently render ~a pump or motor 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 rasident inspectors, erosion of service water systems i

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.

4 The distribution by nwnber of service water events among LWRs (4 BWR and 16 PWR) and the apparent cause relationship to valve throttling and/or solid suspension in fluids may warrant further investigation relative to identification of i

potential erosion sources and monitoring or detection of degradation.

For example, the large nwnber of PWR events compared to BWR events does not seem intuitively obvious. Since most events are related to throttling of valves,

)

there may be a relationship that PWR service water systems are sized for accident conditions with significantly larger capacity requirements than normal operation cooling loads.

Hence, the reduced flow requirements for normal loads l

would be expected to result in throttling of valves with subsequent local turbulent flow and erosion of piping and/or valves.

If this hypothesis is f

valid, it may provide guidance or suggest areas that may benefit'from i

monitoring for possible degradation. However, it also appears that the service l

water source, such as one with significant amounts of suspended solids, may be the dominant contributor to erosion degradation.

FINDINGS 4

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 nwnber of reports might suggest. The purpose of this evaluation was to review the many events to develop a perspective and draw relatively broad interpretations relative to safety implications. Based t

on the evaluation, the following findings are provided:

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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 hours0.00347 days <br />0.0833 hours <br />4.960317e-4 weeks <br />1.1415e-4 months <br /> per year per pump or,3600 hours0.0417 days <br />1 hours <br />0.00595 weeks <br />0.00137 months <br /> 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 among steam and water systems; the PWR events were mostly for water systems; and the HTGR events were all for energency feedwater systems.

B.

The majority of the BWR valve steam erosion events involved MSIVs and SRV pilot seat erosion.

The SRV pilot' seat erosion appears to have been resolved as indicated in References 9,10, and 11. The MSIV 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.

D.

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.

8.

Eight of the remaining nine reports involved lube oil and motor cooler heat exchangers for safety systems such as high head injection pumps.

Al' 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 equi pment.

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Piping A.

Steam Piping (1)

The distribution of erosion events in steam piping 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 equipnent, and LERs vare submi tted.

(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 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 ouilding appears to 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 i

(1) The nine reports were 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 minimum feedwater 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 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 the energency feedwater supply to the helium circulator.

The two reports referenced seven other reports on the same system.

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. C.

Service Water (1)

Sixteen of 20 events in service water systans occurred at PWR plants.

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 suggest that rapid propagation would occur.

Also the systems are generally at a relatively low pressure which woul d tend to lini t i 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 incanplete because many events are not reportable.

Hence, the data base in Table A should be considered only as representative of the types of degradation that can occur in nuclear plants due to erosion rather than a complete list of events.

Secondly, there does not appear to be a direct relationship between these events and a specific safety problem that needs funediate 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 reviewe8 by NRR or industry owner groups while others appear worthy of consideration by NRR. Although specific recommendations do not appear feasible, 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 1.

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 the effects 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.

f y

~,. _

~

~ ~ '

i 2.

Service water systems appear to be :fdeal 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 normal plant loads.

It appears that throttling devices, used in a nearly closed position, have been introduced to reduce flow to accommodate normal plant heat loads that are significantly lower than accident loads.

This results in erosion in the vicinity of these levices.

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 stein generators.

This appears to be an area for consideration of a need for possible monitoring and detection e

requi renents.

4.

The emergency feedwater systed 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 hellui circulator and the relatively large number of events appears to be worthy of review for possible safety implications or :hanges to reduce the-number of erosion events.

8.

Steam Systems a

1.

Pilot seat erosion of SRVs in BWR plants has occurred quite frequently.

However, it appears that safety concerns relative to possible inopera-bility of SRVs at high leakage rates have been resolved.

2.

The MSIV leakage, that may be erosion induced, in BUR plants is related to offsite dose calculations following a LOCA and therefore has safety implications.

This issue is cur.rently under review by NRR and BWR owners group (References 6, 7 and 8) and should be followed until resolved.

3, Leakage or rupture of steam piping may be more frequent than the data indicates because these events generally are not reportable.

The majority 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 4

conclusions related to plant safety concerns because we are not aware of any ruptures that affected safety systems.

Furthermore, it would stem 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

)

implemented monitoring programs to detect degraded piping.

4

~

i

'o 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.

i 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 valve (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 Main Steam Isolation Valves," Volume 1, July 1982.

7.

EPRI NP-2454, " Comparison of Generic BWR-MSIV Configurations,"

June 1982.

8.

NRC, O. D. 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 bbde with Pilot Valve Leakage," AE00/E312, May 18,1982.

10. NRC, H. R. Denton to C. J. Heltemes, 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 l

Valve 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 Valve," E411, May 22,1984, t

i I

-v,

~

i TABLE Al.

EROSION EVENTS IN PUMPS BWR PLANT DOCKET NO.; REPORT NO.;

DATE SYSTEM AFFECTED EVENT DESCRIPTION k

1 Big Rock Point Radioactive During processing of water from the chemical waste receiving tank 155;81-026 Waste the #1 radwaste pu.np vent plug failed and discharged 300 gallons of 11-07-81 Management low activity radioactive water.

The cause was long tenn deteriora-tion of the pump casing due to corrosion and erosion.

2.

Nine Mlle Point Feedwa ter 220;81-044 Number 11 feedwater punp 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 face. Similar occurrences in LERs 80-17 and 76-43.

3.

Hatch 1 Service Plant service water pump failed to meet total dynamic head 321;81-079 Water requirenents.

Inspection revealed wear and erosion consistent 07-13-81 with end of nonnal life cycle. Repetitive event, last reported in LER 80-026.

4.

Quad Cities 2 Residual Heat Residual heat renoval service water system booster pumps were 265, Daily Report Removal Service found to have excessive wear on the inlet and outlet side of the 09-27-83 Water System casings.

The wear appears to resul t fran the raw water from the Mississipi River.

The casings for all four punps will be replaced.

Pump perfonnance was not degraded.

Estimated operating time per pump for the 12 years of plant operation was 300 hours0.00347 days <br />0.0833 hours <br />4.960317e-4 weeks <br />1.1415e-4 months <br /> per year for 12 years or 3600 hours0.0417 days <br />1 hours <br />0.00595 weeks <br />0.00137 months <br /> for each punp (about 150 days).

l PWR l

5.

Oconee 1 Service Water 269;80-026 Water was leaking fran the "B" high pressure service water pump pump motor cooler. Cause was erosion of tubes due to constant 08-11-80 flow of lake water. Leaking tt.bes were soldered.

6.

Oconee 1 Service Water l

269;80-022 Water was leaking fran the "B" high pressure service water pump motor cooler.

07-07-80 The cause was erosion and corrosion of thw tubes due to constant flow of lake water. Valves will be added to penuit flow only when the pump is in operation.

7.

Oconee 1 Service Water 269;80-018 Water was leaking fran the "B" high pressure service water punp motor cooler.

06-01-80 The cause was erosion and corrosion of the tubes due to constant flow of lake water. Leaking tubes were soldered.

I

_~

. Table Al (Continued)

PWR PLANT DOCKET NO.; REPORT NO.;

DATE SYSTEM AFFECTED EVENT DESCRIPTION 8.

Oconee 1 Service Water Water was leaking fran the "B" high pressure service water pump 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 pennit flow only when the pump is on.

9.

Oconee 1 Service Water Water was leaking fran the "B" high pressure service water pump 269; RO 79-34 motor cooler.

The cause was erosion of the tubes due to constant 12-10-79 flow of lake water. Valves will be added to penuit flow only-when the pump is on.

10. H111 stone 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 005-18-77 the pump. The cause was erosion attributed to excessive velocity through the cast iron suction bells.

Replacement suction asseablies were cast with a more resistant inaterial.

11. Ft. Calhoun Raw Water A raw water cooling systen punp failed with a sheared shaf t coupling.

285; LER 77-07 Cooling The cause was erosion of internals that increased clearances to such 03-15-77 a point that vibration increased and caused wear and eventual shaft failure.

12.

Ft. Calhoun Raw Water During an inspection of the raw water pumps, erosive wear due to 285; LER 76-9 Cooling 04-09-767 Missouri River water was found on the punp impeller and galvanic corrosion within the connecting threads of the top core bearing.

Areas worn by erosion were built up by welding.

I

. Table Al (Continued)

HIGR PLANT DOCKET NO.: REPORT NO.:

DATE SYSTEM AFFECTED EVENT DESCRIPTION 13.

Ft. St. Vrain Condensate and The motor driven boiler feedwater pump becane inoperable during 267; RO 79-03 Feedwater nonnal operation.

The cause was erosion of the pump casing.

01-05-79 14.

Ft. St. Vrain Coolant Bearing water makeup punp, P-2105, was inoperable due to less 267; RO 78-06 Recirculation than acceptable discharge pressure.

The cause of deterioration 04-03-78 in punp performance was erosion of 3 bowls of the 14 stage puinp Erosion was attributable to faul ty castings.

l

4 TABLE A2.

EROSION EVENTS IN VALVES BWR PLANT DOCKET NO.; REPORT NO.;

DATE SYSTEM AFFECTED EVEt4T DESCRIPTION 1.

Pilgrim 1 Main Steam Two Target Rock 2 stage S/R valves did not pass set point lift tests.

293;81-061 Erosion of pilot disc being evaluated.

2.

Browns Ferry 1 Main Steam 8 main steam isolation valves failed leak rate test.

Cause was steam 259;81-014 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;50-296/80-058,80-058, 79-014,78-025.

3.

Duane Arnold Reactor Water Reactor water cleanup systen to main condenser control valve, CV-2729, 331;80-067 Cleanup System developed a body leak. Cause was high velocity water flow erosion.

The leak sprayed water on electrical equipnent which resul ted in RWCU systen isolation.

4.

Browns Ferry 3 Main Steam 7 Main Steam isolation valves failed leak rate test. Cause was steam 296;80-059 erosion of the seating surface.

( Atwood-Morrill, 26-inch globe valve).

Similar event on 50-260/80-049.

5.

Monticello RCIC Leaking valve caused erosion of a 1-inch, 90 elbow in the reactor 263;79-024 core isolation cooling systen drain - t.o the condenser.

6.

Browns Ferry 2 Main Stean 4 Main Steain isolation valves failed leak rate test.

Cause was stean 260;80-042 erosion of valve seating surface ( Atwood-Horrill, 26-inch globe valve).

Similar event on 50-259/80-003.

7.

Humboldt Bay 3 Station Service Leak observed in the housing of the gate valve at tiie discharge of the 133;80-006 Water

1. 6 screen wash panp. A 1-1/2-inch hole was caused by corrosion and erosion.

8.

Quad Cities 1 Main Stean Electranatic 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 RHR Service Leak was discovered in the RilR service water dif ference pressure 263;78-021 Water Systen control valve. Cause of the leak was corrosion and erosion of the upper valve body.

I

Table A2 (Continued)

BWR PLANT DOCKET NO.; REPORT NO.;

DATE SYSTEM AFFECTED EVENT DESCRIPTION

10. Quad Cities 2 Standby Liquid Standby liquid control systen pump failed to produce sufficient 265; 78-15 Control (SBLC) flow rate under test as required by technical specifications. A relief valve was leaking and recycling the water to the SBLC tank 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 fran the REC heat exchanger "A."

298; 77-49 Water The leak was downstream fran an outlet butterfly valve used as a throttle valve. Part of 18-inch rubber seat on the butterfly valve was missing. Erosion was caused by high flow and silt concentrations.

12. Duane Arnold Main Steam During hydrostatic testing, excessive water leakage was observed fraa 33); 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 valves.

13. Montiello Main Steam During leak rate testing of outboard main stream drain isolation 263;82-011 valve, it was found to exceed technical specification limits.

09-03-82 Leakage of the 3-inch gate valve was caused by erosion of disc which resulted fran seat ring misalignment.

14. Millstone 1 Recirculation The recirculation systen sample isolation valves 1-RR-36 and 1-RR-37 245;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 occurrence in R0 79-19/3L and 80-14/lT.

15. Duane Arnold Residual Heat The "D" residual heat renoval system service water punp discharge 4

33);82-032 Removal Service check valve V-46-Il was found leaking.

The cause was an eroded 05-04-82 Wa ter set screw which allowed the hinge pin to loosen and the valve to move fran the proper seat.

16. Hatch 2 Residual Heat While perfonning the daily inside rounds, the "B" residual heat 366;82-132 Removal Service renoval service water valve was found inoperable.

A pin hole leak 12-03-82 Water had developed in the valve body via iriternal erosion.

I

. Table A2 (Continued)

BWR 1

PLANT DOCKET NO.; REPORT NO.;

DATE SYSTEM AFFECTED EVENT DESCRIPTION

17. Duane Arnold Reactor Core Reactor Core Isolation Cooling full flow test valve, H0V-2515, was 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.

18.

J. A. Fitzpatrick Main Steam 333;82-037 During ascension to power, following a normal reactor startup, abnormally high tail pipe-temperatures were indicated on "F" safety 07-30-82 relief valves.

Pilot discs most eroded were found to correlate with the high tail pipe tenperatures.

19. Quad Cities 1 Main Steam 254;83-035 While manually operating a Target Rock three stage safety / relief 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 remain open.

PWR i

20.

D. C. Cook i NESW Erosion of valve seats was discovered during B&C leak rate tests.

315;81-025 (Contaimeent 13 of 14 NESW check valves exceeded Technical Specifications leakage.

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.

Salem 1 Pressurizer Leakage discovered through valve lPRI to the pressurizer relief tank.

272;81-061 overpressure Inspection revealed stean cutting of the valve cage.

systen 22.

D.C.' Cook 2 Containuent 38 containment valves' exceed leakage, limits during Il&C leak rate 316;81-013 isolation system test.

17 valves were in the NESW system and six containment purge valves also experienced excessive leak rates.

23. Connecticut Yankee Chemical and.

Leak was found in the charging pump recirculation orifice bypass i

213;78-008 Volume Control valve.

Cause was erosion fran high velocity water on both the body and gasket surfaces.

The valve was being used as both a throttle and bypass valve.

i

' Table A2 (Continued)

PWR PLANT DOCKET NO.; REPORT NO.;

l 1

DATE SYSTEM AFFECTED EVENf DESCRIPTION

24. Connecticut Yankee Chemical and Leak was found in the charging punp recirculation orifice bypass 213;78-007 Volume Control valve. Cause of leak was severe erosion.

The valve was being used as a throttle valve in order to increase the anount of 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)

Volume Control body of the "B" charging pump recirculation throttle valve CH-V-275.

213;82-009 Rev. I 10-15-82

26. 'D. C. Cook 2 Containment While perfonning 8 and C leak rate tests, several valves exhibited 316;83-016 Isolation excessive leakage which resulted in the total leak rate exceeding 01-13-83 the technical specification limit. Leakge was attributed to dirt and 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 fran the valve and they were found in 04-30-80 diesel generator lobe oil' cooler. Failure of a header upstream of the check valve could reduce available cooling water flow fran the other header to the diesel generator. A preventive maintenance system to inspect similar type check valves has been implenented.

28.

D.C. Cook 1 Containment While perfonning the D&C leak' rate tests, several valves exhibited 315;82-058 Rev. 1 Isolation excessive leakage causing the total leak rate to exceed the technical 07-21-82 Systen specification. l fmi t.

Leakage was attributed to dirt and scale -

deposits on the seating surfaces and erosion of the valve seats.

(See Item 26 for similar occurrences.)

29.

Salem 1 Main Steam Stean generator blowdown valve 14 Gil 4 exhibited leakage in excess 272;83-010 of requirements.

The internals were wire cut. Due to a recurrence 02-05-83 of the problans, further' engineering invvestigation will be performed.

30. Millstone 2 Auxiliary Drein valve, 2-MS-342, on steam supply to auxiliary feedwater pump 336;80-034 Feedwa ter P-4, seating surface was stean cut with excessive leakage.

l l

0

$\\

-s-Table A2 (Continued)

HTGR PLANT 00CKET 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.

07-07-82 The cause was water cutting of the valve seat and 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).

l 1

i ENCLOSURE 2 DISPOSITION OF AE00 ENGINEERING OR TECHNICAL EVALUATION REPORTS

.1 Report Number:

// 8 O'h A/ PD L

(, is g y Date:

Author:

g a g gpg 4

ysz45g4 Subiect:

vWbG7ecm.b uun v4no giurr o/

W4 TvQwS h4 vdu 4t:u Tt4/u CognizantBranch(es):

hl3 Cognizant Branch Chief (s):

0.1_ 8444 Date Report was Received:

A v6 )3

/9 f 7

/

Disposition (Check as Appropriate):

Retained for General Information Forwarded to SPEB (DST) for Generic Issue Prioritization*

Other:

5 7/11 c.o a ct1 A ktet

• If an AE00 Engineering or Technical Evaluation Report is considered to have generic implications, the forwarded branch should complete to assist SPEB in the prioritization process.

cc: OST/SPEB

c. w [ v;". m r tr W }'

@? ', ADOS DY NUREC/BR-0051

[EliD E2 tak0iiirl,2 UDrary Vol. 6, No. 3 6....i,2 POWER REACTC'R EVENTS s.@.. 2,/United States Nuclear Regulatory Commission i

Date Published: November 1984 Power Reactor Events is a bi monthly newsletter that compiles operating experience information about commercial nuclear power plants This includes summaries of noteworths esents and listings and'or abstracts of USNRC and other documents that discuss safety-related or possible generic issues It is intended to feed back some of the lessons learned from operational esperience to the various plant personnel. i e, managers. licensed reactor operators. training coor-dinators.and support personnel Referenced documents are asailable from the USNRC Pubhc Document Room at 1717 H 5treet. Washington. DC 20555 for a c pying fee Subscriptions and additional or back issues of Power Raactor Events may be requested from the NRC CPO Sales Program. (301) 492 9530. or at Mail Stop P-130A. Washington. DC 20555 Table of Contents 0

1.0 SUA!AfARIES OF EVENTS 1.1 Inoperable Containment Spray System..

I 1.2 Held Open Check Valve on Residual Heat Removal System....

3 1.3 Reactor Trip on High Reactor Coolant Pressure Following Loss of Non-nuclear Instrumentation..

6 1.4 Naturat Circulation in Pressurized Water Reactors..

7 1.5 Inadvesient Draining of the Pressurizer During Preparations for Plant Startup..

13 1.6 Loss of Vita! Electrical Buses During Refue!;og..

19

f. /

O. "cnal:r g Transient..

2']

1. 8 Loss of ECCS Charging Systems and Baron Injection Tank..

24 1.9 Torus Corrosion Pitting and Atissing Structural Welds...

26 1.10 References...

29 2.0 EXCERPTS OF SELECTED LICENSEE EVENT REPOR TS..

31 30 A BSTRACTS OF O THER NRC OPERA TING EXPERIENCE DOCUAfENTS 3.1 Abnormal Occurrence Reports..

53 3.2 Bulletins and Information Notices..

54 3.3 Case Studies and Engineering Evaluations..

63 3.4 Generic Letters..

70 3.5 Operating Reactor Event &?emoranda..

73 3.6 NRC Document Compilations..

74 l

'J. 3 NtJCLEAR REGULATORY COMMISSION Editor: Sheryl A. Massaro l500iDV Omce for Analysis and Evaluation l

. O.c.

r555 y,.

of Operational Data U S. Nuclear Regulatory Commission Period Covered May-June 1984 Washington, D.C. 20555 1

hb I3fp.

I 3.3 Case Studies and Engineering Evaluations Issued in May - June 1984-

- The Office for Analysis and Evaluation of Operational Data'(AE00) has as a primary responsibility the task of reviewing the operational experience reported by NRC nuclear power plant licensees.

As part of fulfilling this task, it selects events of apparent interest to safety for further review as either an engineering evaluation or a case study.

An engineering evaluation is usually l

- an immediate, general consideration to assess whether or not a more detailed protracted. case study is needed.

The results are generally short reports, and the effort involved usually is a'few staffweeks of investigative time.

Case studies are in-depth investigations of apparently significant events or situations.

They involve several staffmonths of engineering effort, and result in a formal report identifying the specific safety problems (actual or potential) illustrated by the event and recommending actions to improve safety and prevent recurrence of the event.

Before issuance, this report is sent for

~

l peer review and comment te at least the applicable utility and appropriate NRC offices.

l These AE00 reports are made available for information purposes and do not impose any requirements on licensees.

The findings and recommendations contained in these reports are provided in j

support of other ongoing NRC activities concerning the operational event (s) discussed, and do not represent the position or requirements of the respon-sible NRC program office.

Engineering Date Evaluation Issued Subjact E409 5/16/84 OPERATING EXPERIENCE INVOLVING AIR IN SENSING LINES Proper operation of reactor safety systems in both PWR and BWR plants requires an accurate measurement of various differential pressure ~ signals.

Liquid level' instruments are used to determine water level in the various tanks and vessels in various safety and non-safety systems.

Fluid flow instru-ments are used to measure the fluid flow rate at various points within primary,. secondary, and standby safety systems. -Air getting into sensing lines of one or more redundant level, fluid flow, or pressure instruments at the same time without detection could'have important safety consequences.

Nineteen instrument failures due to air.getting into instrument sensing lines were reviewed.

i Failed instruments consisted of water level instru-4 ments, fluid flow instruments, and pressure measuring 4

63 y

,-,'1

-r,-

• -*,r 1--

e r-r

a

!j Engineering Date Evaluation Issued subject the' account of the actual event demonstrates the benefit of the new reporting requirements.

(See

p. 20.)

E416 6/11/84 EROSION IN NUCLEAR POWER PLANTS 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 28, 1982.

The intent of the investigation was to identify the scope of degradation related to erosion and assess potential generic implications.

The evaluation. 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 Jata base should be. considered as represen-tative 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.

i Although specific recommendations do not appear feasible. potential constructive actions relate

.(1) cognizance of the phenomenon for certain to:

sites and systems; (2) identification of specific plant equipment and physical configurations that may be susceptible to erosion, and (3) implementa-tion of monitoring programs to detect degradation of equipment (pumps, valves, heet exchangers, and piping).

69

TABLE A3.

EROSION IN llEAT EXCilANGERS PWR PLANT 00CKET NO.; REPORT NO.;

DATE SYSTEM AFFECTED EVENT DESCRIP!!0N PWR 1.

Salen 2 Containment An operator discovered a 0.25 gpu leak on No. 23 Containment Fan Coil' 311;82-128 Heat Renoval Unft )CFCUO.

10-31-82 The cause of leakage was erosion of the CFCU cooling coil by silt in the service water.

2.

Salen 2 NOTE:

ALL REPORTS WERE SIMILAR TO Tile STAIEMENT IN ITEM 1 AND ARE 311;82-135 NOT REPEAIED.

Tile FAN C0ll UNIT llAS 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 I

~ Table A3 (Continued 0 PWR PLANT DOCKET NO.; REPORT NO.;

DATE SYSTEM AFFECTED EVENT DESCRIPTION 10.

Salen 2 Containment NOTE: ALL REPORTS WERE SIMILAR TO Tile STATEMENT IN ITEM 1 AND ARE 311;82-111 Heat Renoval NOT REPEATED.

THE FAN C0!L UNIT HAS BEEN REPLACED.

11. Salen 2 311;82-109 09-23-82 12.

Salen 2 311;82-101 09-16-82

13. Salen 2 311;82-100 09-15-82 14.

Salen 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 i

O

. Table A3 (Continued)

PWR PLANT DOCKET NO.; REPORT NO.;

DATE SYSTEM AFFECTED EVENT DESCRIPTION 19.

Salen 2 Contairunent NOTE: ALL REPORTS WERE SIMILAR TO Tile STATENENT IN ITEM 1 AND ARE 311;82-080 Heat Renoval NOT REPEATED.

Tile FAN C0ll UNIT llAS BEEN REPLACED.

08-21-82 20.

Salen 2 311;82-078 08-19-82 21.

Salen 2 311;82-077 08-18-82 22.

Salen 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. Salen 2 311;82-070 08-09-82

26. Salen 2 311;82-040 05-19-82 27.

Salen 2 311;82-039.

I

. Table A3 (Continued)

PWR PLANT 00CKET NO.; REPORT NO.;

DATE SYSTEM AFFECTED EVENT DESCRIPTION 28.

Salen 2 Containment NOTE: ALL REPORTS WERE SIMILAR TO IllE STATEMENT IN ITEM 1 AND ARE 311;82-028 Heat Renoval NOT REPEATED.

Tile FAN C0ll UNIT HAS BEEN REPLACED.

29.

Salen 2 311;81-118 30.

Salen 2 311;82-136 11-24-82 31.

Salen 2 Chenical and During routine operation, a sainple of No. 21 charging pump lube oil 311;82-126 Volume Control revealed that a water-oil mixture existed.

The cause was erosion 10-19-82 of the lube oil cooler fran silt in the service water.

The service water then saixed 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 09-28-82 Systen and was caused by erosion fran silt in the service water.

33. Salem 2 Station Water was observed dripping fran the oil level sightglass of No. 24 311;82-086 Service Water service water puing inotor.

The cause was erosion and corrosion of the 09-15-82 motor bearing oil cooler. A new design cooler will be installed at the next refueling.

l 34.

Salem 1 Chenical and During a routine inspection, a sample of No.12 chargirig pu.op gear 272;82-041 Volume Control oil confinned that a water-oil mixture existed.

The cause was erosion 06-26-82 of the gear oil cooler frad unsuited material in the service water.

l l

-S-Table A3 (Continued)

PWR PLANT DOCKET NO.; REPORT NO.;

DATE SYSTEM AFFECTED EVENT DESCRIPTION 35.

Indian Point 2 Containment While the unit was at cold shutdown, a pinhole leak was discovered on the 247;81-021 Heat Removal 08-29-81 2-inch service water outlet line fran No. 25 fan motor cooler.

The leak was in an area adjacent to the downstream side of a 90* elbow weld heat affected zone.

The supply and return motor cooler lines contain 228 elbow welds and 81 were selected for radiographic exanination with 12 indications of. reduced thickness.

The cause was erosion caused by' brackish salt water at high velocity (10 ft/sec.).

36.

H.B. Robinson 2 Containment Containment fan cooler HVN-2 was found to have a motor cooler leak.

261;82-006 Heat Removal 07-15-82 The leak was attributed to erosion of the cooler tubing. All four HVN 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.

261; Pronpt Heat Removal Noti fication 04-10-83

38. Conn. Yankee

' Containment A service water leak was discovered in one coil of the nunber 4 car 213;83-001 Heat Removal fan cooler. Failure was due to corrosion / erosion.

01-14-83 39.

Salen 1 Chemical and Oil was. observed couing fran No. Il charging punp speed increaser air 272;83-048 Volume Control breather.

08-15-83 Tubes in the lube oil cooler of the charging punp speed increaser had failed due to erosion and corrosion.

The lube oil cooler was replaced.

BWR

40. Dresden 3 Feedwater 249;83-008 During a routine plant inspection at nonnal unit startup, an operator 03-07-83 discovered a steam leak on the shell of the 3C3 low pressure feedwater heater near the extraction steam inlet nozzle.

The cause was erosion of the heater shell by deflected steam.

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TABLE A4.

EROSION EVENTS IN PIPING A4.1 Main Steam Systen Piping BWR PLANT DOCKET NO.; REPORT NO.;

0 ATE SYSTEM AFFECTED EVENT DESCRIPTION l.

1.

Monticello Main Steam 263,80-029 Main steam drain line on tee to condenser leaked.

Believed to be erosion and impingement of stean and water from restricting orifice j

09-30-80 upstream of tee.

7 previous similar events 76-01, 16, 24; 77-19, 78-07, 13, 27.

2.

Monticello Main Stean 263,79-001 Steam leak in a 90* elbow on turbine main steam bypass header due 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 263,78-027 Steam leak in a tee downstream of M0119 on the 2" itP turbine "U" 11-21-78 bend drain line to the condenser.

Believed due to restricting orifice.

4.

Dresden 3 Main Steam 249;78-052 Found stean leak during check of moisture-separator' area.

c Steam 11-04-78 was blowing fran theb ottan of an elbow.

S.

Dresden 1.

Main Stean 010;78-031 Two leaks in turbine extraction bypass line (2705-4"-88) 10-07-78 6.

Monticello Main Stean 263,79-013 Stean leak in a 90* elbow on turbine main steam bypass header 1" drain line to the condenser.

orifice R0-2569 upstream of the elbow.Due to erosion from restricting 7.

Monticello Main Stean 263; 76-24 Erosion of elbow wall in a 1" llP turbine bypass header drain line.

Caused. by hot flashing af ter passing through ari orifice.

8.

Monticello Main Steam 263; 76-16 Leaking of elbow in a 1" llP turbine inlet steain 1irie 11 berid

~

i drain.

Erosion from hot steam flashing af ter passing through.an orifice.

. Table A4.1 (Continued)

BWR PLANT DOCKET NO.; REPORT NO.;

DATE SYSTEM AFFECTED EVEllT DESCRIPTION 9.

Monticello Main Steam 263; 76-01 Leak in 1/2" elbow on ti.e condensate return line (in air ejector room) downstream of the trap. Erosion caused by hot steam drains flashing af ter passing through the trap.

10. Vermont Yankee Main Stean 271; No LER Operations personnel noticed leakage from the "C" Moisture Inspection,

Separator Drain Line during routine tours. Leakage initially 50-271/82-01 appeared as wetted insulation. By January 25, 1982 leakage increased to the point where minor wisps of steam were blowing fran the piping.

A through wall defect was found in a 6-inch diancter section of the drain line just upstream of the 24-inch expansion volume.

Extensive corrosion / erosion showed by ul trasonic examination.

Damage included a pinhole leak and a crack at a gusset support welded to the exterior of the pipe.

The pipe was schedule 40 carbon steel pipe instead of schedule 80 pipe called for in the speci fications.

11. Browns Ferry 1 Main Stean 259; No LER The report mentions two pipe ruptures caused by erosion.

On 9-28-83 Daily Highlight the pipe to the C-2 moisture separator between the high pressure and Report the C low pressure turbine ruptured. Approximately one month earlier 09-29-82

( August 1982) an elbow on the steam line to the 8 low pressure turbine ruptured due to erosion.

TVA plans to implenent UT-exaninations of these lines.

12. Monticello Main Steam 263;81-020 Main stean leak in a drain line to the condenser.

Leak was in piping 07-24-81 downstrean of a 45 degree elbow due to erosion and impingenent of steam and water from restricting orifice upstream of the elbow.

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 installed during the next convenient outage.

l

13. Monticello Main Steam 263 79-017 Stean leak on the ISA feedwater extraction steamlinw drain.

Erosion 08-06-79 through the wall of the steau trap.

(Insufficient maintenance.

Yarway 3/4" 600# Carbon Steel body type trap.)

1

3-Table A4.1 (Continued)

BWR PLANT DOCKET NO.; REPORT NO.;

DATE SYSTEM AFFECTED EVENT DESCRIPTION

14. Monticello Main Stean llPCI Steam supply leak in the weld of a 45* elbow of a 1" drain line 263;78-028 to the condenser.

Erosion fran water and steam through leaking valve 11-24-78 CV2043 upstream of the elbow.

15. Monticello Main Stean llPCI 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 upstreain of the elbow.

16.

Monticello Main Steam llPCI stemn supply leak in a 45* elbow ori 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 Steau 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 drairi 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* elbow in RCIC (steam supply) drain 263;78-009 to condenser. Pinhole failure of 3000# socket weld due to erosion 04-04-79 fran a leaking valve. Five previous occurrences, 76-01, 16, 24; 77-19; 78-07.

PWR 20.

Calvert Cliffs 1 Main Stema Erosion from 2 phase flow.

Steaisi Generator 11 bottom blowdown was 317; 76-4 leaking at an elbow immediately downstream of ari orifice inside containment.

I

. Table A4.1 (Continued)

PWR i

PLANT DOCKET NO.; REPORT NO.;

DATE SYSTEM AFFECTED EVEllT DESCRIPTION

21. Arkansas 1 Main Steam 313;82-027 Reactor Coolant Systen leak rate calculation indicated leakage of 3.4 gpm. Water as located beneath a steain generator. Pressure 07-14-81 bearing surfaces on the steain generator and a inanway cover were found eroded by leakage. A gasket had deteriorated.

22.

Arkansas 2 Main Steam 368;82-011 A leak was discovered inside contaishnent in the B steam generator blowdown line between valve 2CV-1065 and containoient peitetration WP-64.

04-15-82 The cause was erosion fran steam water impinganent on the piping down-stream of 2CV-1065. Valve 2CV-1065 had been throttled to achieve blowdown control because of inadequate performance of the blowdown control valves outside contairunent in the non-Q portion of the system.

The schedule 40 pipe was replaced with schedule 80 pipe.

23. Oconee 2 Main Steam 270; No LER While at 951 power, a high pressure turbine extraction steam line ruptured (24-inch line).

The ruptured area was 4 square feet and PNO-II-82-72A released stean to the turbine building.

The cause was wall thinning due to steam erosion.

An electrical control panel was severely danaged but it did not affect safety-related equipnent.

24.

Zion 1 Main Stean 295; No LER A steau leak was discovered in a 150 psig high pressure exhaust stean line on 2/12/82.

PNO-l ll-82-21 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 stean exhaust leading to the moisture separator reheater.

25. Maine Yankee 11ain Stean 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 i

]

Table A4.1 (Continued)

PWR i

PLANT DOCKET NO.; REPORT NO.;

DATE SYSTEM AFFECTED EVENT DESCRIPTION

26. Trojan a.

Main Steam 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 IE Daily Report of a 90-degree elbow in a low pressure (150 psig) stean line running fran the high pressure turbine to the No. 5 feedwater heater.

The cause 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 1001 power, the 305; No LER IE Daily Report reactor was tripped when an unsolable steam leak started to fill the turbine hall with steam.

)

12-29-82 The leak was due to a crack in an 8-inch drain line fran the moisture separator to the heater drain tank.

l 1

28.

Yankee Rowe Main Steam 029;83-028 During heatup in Mode 3, a leak was discovered in a 2", schedule 80, SA-106 Grade B carbon steel elbow in a high pressure stema drain line..

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.

Salem 2 a.

Main Steam A large amount of steam was released fran the vicinity of the No. 33 311;83-033 b.

Auxiliary auxiliary feedwater punp during routine startup operations.

The steam 07-07-83 Feedwater cane fran 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 perfonned.

30. Calvert Cliffs 1 Main Steam-317; No LER A steam leak occurred in a high pressure turbine extraction steam line, l

11-23-81 The leak was through an approximate five inch split in the 16 inch steam line.

IE Daily Report A two day outage was anticipated to replace the pipe.

31. Davis Besse 1 Main Steam 346; No LER Erosion of moisture separator reheater drain piping to the condenser required realiganent of feedwater, heater drains.

The reactor power 6 - 83 was limited to 901 due to increased condensate flow.

Monthly Operating Report I

.. A4.2 Feedwacer Systen Piping (Including Auxiliary or Emergency)

BWR PLANT DOCKET N0.; REPORT NO.;

DATE SYSTEM AFFECTED EVENTDESCR(PTION 1.

Dresden 3 Feedwater Systen.

Excessive flow while shutdown and later at 95% power. Leaks found in 249;78-037 3A, 3B, and 3C feed punp minimun flow lines. 3B had a crack. 3A and 3C 09-18-78 had pinhole leaks at the top of the pipe downstreaia of the 3x6 reducer.in 6" dianeter 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 Feedwa ter System Pinhole leak in the minimum flow line fran 3A feed p ap.

Leak was 249;78-030 3" downstreain of a 3x6" reducer in the 6" diameter piping.

07024-78 3.

Dresden 3 Feedwater Systen Pinhole leak due to erosion in the minimum flowline 3-32058-6 inch 249;78-005 fran feed punp 38. Leak located at 12 o' clock position about 3 inches 03-06-78 downstrean of 3x6 expander.

4.

Dresden 3 Feedwater Systen Pinhole leak, believed due to erosion, in the miniinu.n flow line from I

249; 77-21 feedwater punp 3A (line 3-3205C-6 inch). Leak was about 3 inches 04-07-77 downstrean of the 3x6 expander.

'PWR 5.

R. E. Ganna Feedwater System

' As a resul t of performing Uf examinations of the J tubes on the "A" 244: Daily Report 04/14/83 stean generator feedwater. rings, significant metal loss fran the J '

tube walls was detected. Nominal wall loss up to SQL in all 38 J tubes was found.

A hole was found in one J tube approximately 1" above the weld.

1

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• Table A4.2 (Continued)

PWR PLANT DOCKET NO.; REPORT NO.;

i DATE SYSTEM AFFECTED EVENT DESCRIPTION 6.

San Onofre 2 Feedwater 361;83-035 Three pinhole leaks were found in the miniflow line for auxiliary feedwater pump P141.

03" sed by cavitation downstream of flow 04-14-83 orifice F0-4711. Erosion was found in two 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.

04-05-82 The holes ranged fran 1/8" to 1" in diameter. Westinghouse was reported to be preparing a progran to investigate the cause of J-tube thinning. All J-tubes will be replaced with Inconel which is a better erosion resistant material.

J l

HTGR 8.

ft. St. Vrain Feedwater Systen 278;80-058 Erosion in anergency feedwater supply to loop I hellun circulator water turbine drives.

10-09-80 Inside line at a 90 degree elbow dovnstream of PV-21243-1.

Previous occurrences R0 80-15, 80-23, 80-32.

9.

ft. St. Vrain

.Feedwater Emergency feedwater supply to loop 2 nellun circulator pelton wheel 267;83-015 03-11-83 drives was isolated due to a leak;ng 1-inch line downstream of-PV-21243-1.

Excessive wear cau,ed by fluid velocity at a pipe bend.

Similar reports82-034, 82-031,82-028, 81-060 and 81-054.

i 4

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_8_

Table A4.3 Service Water Systen Piping (and Other Systens)

PWR PLANT DOCKET NO.; REPORT NO.;

DATE SYSTEM AFFECTED EVENT DES _Cp_1PTION 1.

D.C. Cook 2 Service Water Leak due to erosion from butterfly valve throttling. Leak was in ESW 316;82-011 Systen pipe downstrean of outlet valve fran east CCW heat exchanger.

A flange.

01-28-82 1 Train of CCW and a 3 foot section of pipe were replaced.

Inoperable 2.

0.C. Cook 1 Service Water Leak due to erosion from butterfly valve throttling. Leak was in ESW 315;82-009 System pipe downstream of the outlet fron the east CCW heat exchanger. A flange 01-28-82 1 Train of CCW and a 3 foot section of pipe were replaced.

Inoperable 3.

Salem 1 Service Water Service water leak fron the bottom of a reducing tee by valve 12SW913 272;81-083 Systen 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 5.

Salem 1 Service Water Leak in the 10" service water return fran 15 CFCU motor cooler.

272;78-050 System A333, schedule 40 repaired by welding. New spool installed following ASTM 08-21-78 Containnent Fan a second failure.

Coil Unit 1

. Table A4.3 (Continued)

PWR PLANT DOCKET NO.; REPORT NO.;

DATE SYSTEM AFFECTED EVENT DESCRIPTION 6.

Salem 1 Service Water Two brazed fittings leaking service waterfrom 14 CFCU motor cooler.

272;78-059 System Caused by corrosion and erosion.

08-30-78 Containnent Fan Coil Unit 7.

Calvert Cliffs 2 Service Water Pinhole leak in service water outlet line downstream of the outlet 318; 77-42 Systen 06-13-77 control valve on the heat exchanger. Change request implenented 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 Leak in service water outlet piping downstredin of 1-CV-5210 in heat 317; 76-56 System 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 Leak in service water outlet piping downstream of throttling valve in 317; 76-33 Systen heat exchanger 11.

Patch welded over leaking area.

10.

Calvert Cliffs 1 Service Water Leak in service water outlet piping downstream of throttling valve in 317; 76-11 Sys ten 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 dianeters.

11. Salen 2 Service Water A 1.5 gpm leak was discovered inside containitient on the service 311;82-046 Systen water piping to the containnent fan cooler unit (CFCU) cooling coils.

05-19-82 This incident was overlooked until 6/3/82 (from S/19/82) due to inadequate implenentation of adininistrative procedure AP-6.

The Cause was erosion of d blank fldnge in the service water pipe to No. 22 CPCU.

l

Table A4.3 (Continued)

PWR PLANT DOCKET NO.; REPORT NO.;

DATE SYSTEM AFFECTED EVENT DESCRIPTION-

12. Salem 1 Service Water Service water leak was discovered on the nunber 12 charging punp 272;82-069 System lube oil cooler outlet piping. Piping was replaced. A design 08-31-82 ECCS Charging change package has been submitted. See previous event on Pump Inoperable 8-31-81.

13.

Crystal River 3 Service Water Two pinhole leaks were found in seawater piping on the downstream 302;83-022 Systen 05-16-83 side of two Nuclear Service Heat Exchangers. Erosion degradation was_ found on six spool pieces including the Polyvinyl Chloride (PVC) 1.i ner. Degraded piping will be repaired or replaced with similar-pieces that have a urethane liner. A surveillance progran to monitor the piping condition will be initiated.

14. Salem 1 Service Water Reported on 3/30/83 that a design change had been impleaented which 272;82-069 Rev. I System replaced the original pipe with 316 stainless steel for greater 08-31-82 ECCS Charging erosion resistance.

Pump Inoperable

15. Kewaunee Service Water The l A canponent cooling water heat exchariger was renoved fran 305;83-027 Systen service to repair a leak on its service water tenperature controlled 10-26-83 Component bypass line.

The leak was caused by sand erosion due to turbulence Cooling.Wa ter on the discharge ride of the throttled tenperature controlled Heat Exchanger bypass valve, SW-1306A.

16.

Indian Point 2 Residual Heat Leak in elbow connection between contairmnent isolation valves in 247,78-028 Removal 09-20-78 recirculation path fran the RHR pump.

Caused by cavitation and/or -

impingenent erosion.

I i

f

]

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 h19h 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 fran REC heat exchanger A.

298; 77-49 System Leak was on downstream side of heat exchanger 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 bellows area. Joint service is severe dueto the hi h silt 9

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.

l I

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