ML20116M956
| ML20116M956 | |
| Person / Time | |
|---|---|
| Issue date: | 03/31/1989 |
| From: | Office of Nuclear Reactor Regulation |
| To: | |
| References | |
| NUREG-BR-0125, NUREG-BR-0125-V01-N4, NUREG-BR-125, NUREG-BR-125-V1-N4, NUDOCS 9608210187 | |
| Download: ML20116M956 (7) | |
Text
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Severe Accident issues by Thomas E. Murley One of NRR's major efforts during the past 2 years has been to certainly delay closure for years. Instead,it is contemplated that develop, with the Office of Nuclear Regulatory Research, an several activities such as improved plant operations, accident integrated plan for the closure of severe accident issues for management, and mntainment performance improvement (CPI) operating nuclear plants. In this context, closure means that all would be carried out in parallel with the IPE work. For example, of the major issues have been examined for each plant, and cost-we are working with NUMARC in its efforts to develop an effective changes made if needed, so that the NRC can confirm accident management framework. Each licensee could use this the conclusion that there is no undue risk to public health and frameworktoincorporatenewinformationdevelopedintheIPE safety from severe accidents.
into plant-specific severe accident management procedures. It would be both illogical and inefficient to await completion of the Mat is the technicalissue concaning sevene accidents 7 IPE before implementing an accident management framework.
The answer is simply that core-melt accidents were not included Similarly, our plan emisions that containment performance as part of the original design basis for safety systems and improvements can be developed and implemented in parallel containment s'.ructures because the likelihood of such accidents with the IPE work. The staff has years of severe accident was thought to be too remote. Our views have changed since the experience available to g,uide us inrecommendingcost-effee-TMI-2 accident, of course. We now are faced with the question live generic containment improvements that could improve the of what additional feat ures or procedures,if any, are required for abihty of containments to withstand severe accidents. It would safety systems and containments to provide reasonable assur-not be efficient to have each licensee duplicate the level of ance of protection against the risks of core-melt accidents. The analysis that the staff can bring to bear from our own experience.
Chernobyl accident mtensified the focus on containments and on Of course, any plant-specific containment improvements would reaching an answer to this question.
have to be integrated closely with the IPE results, and plant modifications, whether from the CPI or IPE programs, would The Commission's Severe Accident Policy Statement, issued in have to be carefully integrated at each plant. We will have to be August 1985, states: " 4 the Commission plans to formulate an flexible in discussing actual schedules for any plant modifications integrated systematic approach to an examination of each nu-that might be required.
clear power plant now operating or under construction for possible significant risk contributors (sometimes called 'outli-Finally, it is important Ihat we keep the severe accident program ers') that might be plant specific and might be missed absent a on the tracks for closure. If the program gets off the tracks and systematic scarch...The examination willinclude specific atten-closure ap, pears to be substantially delayed, our plans for plant tion to containment performance in striking a balance between life extension would be immensely complicated. It would not be accident prevention and consequence mitigation."
practical to contemplate renewing operating licenses if the severe accident issues have not been closed. Therefore,it will In May 1988 the staff developed a c,evere accident pro, ram that take close attention and discipline to resolve problems as they j
g integrates several of our regulatory activities and research tasks arise and stick to the severe accident plan.
into a plan leading to closure of severe accident issues. The keystone of this plan is the Individual Plant Examination IPE) that requires cach licensee to examine his plant for signi(ficant risk contributors. It is not intended, however, that the IPE bear What's in this issue? See Page 2 the full burden of settling all severe accident issues. That would overly complicate the 1PE methodology and would almost 9608210187 890331 i
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perspective of each plant.iti the country.
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IN THIS ISSUE Following the identificat on of the plants to be d.iscussed at the-December meeting, the Risk Assessment Branch of the Dhision Severe Accident Issues 1
of Radiation Protection and Emergency Preparedness and NR R by Thomas E. Marley Projects worked together to generate a risk analysis write-up of NRC Senior Management Meeting 2
each plant using available Probabilistic Risk Analysis (PRA,)
by William Bateman information. This analysis was extremely informative as it Integrated Performance Assessment Team evaluated the risk siguilicance of the design and served to
)
i Inspections in Region L 2
emphasize the importance of strong management and good by James E. Kaucher operations and mamtenance staffs.
Reactor Scram at River Bend Station with Subsequent Complications -
3 The performance and Quality Evaluation Branch received input by Walter A. Paulson and Timothy E. Collins for the meeting from most divisions of NRR, the Regions, South Texas Overcomes Problems and Goes AEOD, and RES and integrated it all into both a summary and Commercial -
4 a narrative analysis for each plant. The schedule required the by Claudia Abbate, George Dick, and report to be sent to attendees two weeks before the meeting, but Patrick O'Reilly it was distributed slightly ahead of schedule.
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Erosion / Corrosion
.6 by Paul Wu Each Senior Mana the previous one, gement hieeting Report hasbeen bett NRR Technical Intern Program -
6 and each has involved more of the Agency by Valeria 11. Wilson among its contributors and in its preparation. This fact reflects Service Water Operability Issues.-
7 the competence and commitment of all those involved in the by Rudolph Bernhard and Ellis Merschoff production of the report and serves to demonstrate the benefits of effective communication and teamwork. The process has begun again to support the May 1989 Senior Management NEWSLETTER CONTACT:
Meeting.
Valeria Wilson, NRR 492-1208 Integrated Performance NRCSenior Management Meeting Assessment Team by William Bateman, PQEB InSpOCtIOnS in Region l I
by James E. Kaucher, DRP, Region i On December 6-7,1988, the sixth semi-annual Senior Manage-ment Meeting was held in Arlington, Texas. This meetmg afforded the opportunity for senior NRC managers to review The Integrated Performance Assessment Team (IPAT)lnspec-and discuss selected plants and decide what, if any, action should tion,was developed in 1986 in Region I as a tool to be used to be taken to address concerns. Other topics ofinterest were also obtam a more complete understandingof the underlying reasons discussed.
for licensee performance as reported in the Systematic Ap-praisal of Licensee Performance whether corrective action, program (SALP) reports sin place are properly struc-The plants to be discussed at the meeting were decided upon following Regional pre-screeening meetings conducted between tured and focused to achieve the necessary improvements.
September 29 and October 12, 1988. These meetings were attended by representatives of the Office for Anal" sis and The objective of the lPAT is to, determine how current perform-Evaluation of Operational Data (AEOD), the Office of Nuclear ance impacts safe plant operation.
Regulatory Research (RES) and the Office of Nuclear Reactor Regulation (NRR), and the appropriate Regional Administra-IPATs specifically address most or all of the SALP functional tor.
areas, and they are tailored to a heensee's performance history.
The teams are comprised of Regional specialists, Resident In-Eachplantin the Re spector.. and Headquarters' representatives. They are led by a performance level. gion was discussed to evaluate the licensee's rnanager from the Region I Divisi Design strengths and weaknesses were l
identified and evaluated from a risk perspective. Based on a rucal S,upport Staff. The inspections are two to three weekslong, review of these issues and other information provided by meet-neludmg preparation time.
ing attendees, a plant discussion list was established.
The first IPAT inspections were conducted at Pilgrim and Peach A substantial effort went into preparing for these pre-screening Bottom in early 1986. Since then, seven additional IPAT inspec-meetings. The Division of Engmcering and Systems Technology p ns have been conducted at both problem and other plant sites prepared a list of design issues, and each Project Manager used in Region I. All of the inspections have produced inform this list to ascertain the status of each design issue at his/her that t e NRC has used to gam insights on the performance of assigned plant. This information obtained was categ licensee management, and all have provided valuable calibration design strengths and weaknesses. It was then used, m,orized into and added mput,to the SALP process. In conjunc-tion with the Regional presentation on operations and man-useful cross-traimng and perspective for the Regional inspection agement strengths and weaknesses, to help form an overall staff. The Region's goal is to conduct one IPAT each quarter.
2 s
%ncfor Scram a*t River Bend HPCS wi Reactor CaeIsdabmCmling(RCIC)
System inlection l
Stat. ion with Subsequent Both the HPCS and RCIC systems injected as the result of a l
Complications spurious iow reactor water icvei 2 signai caused by a hydrauiic l
pressure perturbation in wide range reactor water Icvel instru-by Walter A. Paulson, PDIV, and ment reference lines. The spurious level 2 signal was caused by the induced reactor dome steam ressure spike. Following the 1
Timothy E. Collins, SRXB turbine trip the spike was immelately transmitted to the four reactor water level reference lines located near the top of the On August 25,1988, the River Bend Station reactor scrammed vessel but it was not immediately sensed by the narrow and wide from 100% power. The scram was initiated by a turbine control range variable line taps located at a lower devation in the reactor valve fast closure that occurred when the main generator tripped pressure vessel. The plant process cc.nputer indicated that the because of an exciter brush failure. Reactor pressure spiked to llPCS low water level signal was preser.: from 20 to 42 millisec-a peak between 1100 and 1117 psig causing the live low-low-set onds. The fast acting Rosemont 1154 tr.msmitters sensed the relief valves to cycle as designed. The turbine bypass valves (10% short duration pressure spike and initiated the automatie injec-bypass capability) also opened as designed. Although the reac-tion. As a result of continued feedwater flow and IIPCS and tor shut down as expected, several complications occurred fol-RCIC injection, reactor water level rapidly increased to level 8, lowing the reactor scram. NRR Project and technical staff, plant causing the HPCS injection va:ve and the BCIC steam supply Resident inspectors, and the Chief of Section C, Region IV, valve to automatically close and the three reactor feedwater participated in a cooperative effort to assess this event and its pumps to trip as designed.
implications. This effort included onsite inspections of event-related records and equipment walkdown.
A generator / turbine trip from 100% power on September 6, 1988, also resulted in HPCS and RCIC injection.
1 Failure of 4.16-KV Switchgear To Transfer to PreferMation Service Transformer High Temperature Water Backflow Through the HPCS Piping During the voltage transient caused by the generator trip, non-safety-related 4.16-KV switchgear failed to transfer (fast and About I hour after the August 25,1988 generator / turbine trip, slow) from the normal station service transformer to the pre-a fire watch in the auxiliary building reported that the IIPCS ferred station service transformer because a circuit breaker piping at elevations 114 and 123 was hot. Further investigation failed to close. This resulted in the loss of power to the high-found that the HPCS pump suction line was cold and the pressure core spray (HPCS) safety-related 4.16 KV bus. The minimum flow line was warm (see HPCS diagram at the end of IIPCS diesel generator received an automatic initiation si because of the undervoltage condition on the HPCS bus. gnal this article). The scating of the HPCS injection va The using the handwheel. It was concluded that reactor coolant had HPCS diesel generator successfully started and its output breaker backflowed into the IIPCS line, causing the piping to become closed, restoring power to the bus as designed.
hot.
Because of the loss of power to the 4.16 KV switchgear, two Hot reactor coolant had to flow back through the HPCS check turbine plant component cooling water pumps also tripped. The valve (F005) and through the HPCS injection valve (F004). The third pump automatically started; however, this pump alone sequence of events showed that the injection valve reopened for could not provide adequate cooling to the instrument air system about 10 seconds,18 minutes after it had originally closed. In i
cornpressors and they tripped on high temperature. After power addition, the sequence of events showed that the valve reopened i
to the 4.16-KV switchgear was restored, a second pump was again for about 24 seconds,33 minutes later. The reason for the i
restarted and the air compressors also were restarted. The injection valve reopening has not been conclusively determined.
lowest instrument air header pressure was 80 psig compared to The licensee postulated that the valve could reopen if thelevel 8 the normal operating pressure of about 120 psig.
signal was reset with the level 2 signal still in. The licensee postulated that there was not enough pressure differential across the check valve to cause it to seat. The licensee also postulated loss of Powerto ReactorProtection System (RPS) that the liquid in the HPCS line flowed out to the suppression pool through the minimum flow line and/or the test return line BusA during the backflow. In the subsequent scram from 100% power on September 6,1988, HPCS injected but there were no mjec-RPS bus A lost power because the motor-generator set output tion lme high temperatures, indicating that backflow did not breaker tripped as a result of the voltage and frequency tran.
ccur.
sients that were generated at the time of the exciter brush failure.
RPS bus B contmued to be energized with power supplied from the B RPS motor-generator set. RPS bus A was manually llCensee Corrective Actions transferred to an alternate supply.
The loss of wer to RPS bus A also resulted in an automatic The corrective actions taken or to be taken by the licensee are as I0Il *S:
initiation o the standby gas treatment and annulus mixing systems, and an automatic trip of the annulus pressure control system. These systems responded as designed. A spurious high o The preventive mamtenance procedure is to be modi-drywell pressure alarm also actuated.
fled to establish a specific frequency when the exciter brushes are to be replaced.
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I South Teds Overcom'es @
Undervoltage relays were replaced and the contacts o
l will be cleaned every 6 months instead of every24 months.
Problems and Goes Commercial o
Rosemont 1154 transmitters are to be modified to by Claudia Abbate, Project Directorate j
dampen the signal input.
IV, George Dick, Project Directorate IV, The licensee conducted a pipe stress evaluation of and Patrick O'Reilly, AEOD o
the HPCS system. Visual exa,mination, dye penetrant examination, and volumetric exammation were i
conducted.
Preliminary analyses showed that all The history of the South Texas Project has been one of change.
l stresses met,the allowable, limits, all supports met the The two-unit nuclear facility located 85 miles southwest of allowable limits, and margms remam m the ipmg, llouston, Texas has been under construction since 1975 (see supports, and other com nents to accomm ate at t
photograp,h next page), and during the early stafega es it was least an additional event, s ould it occur.
lagued with numerous construction, financial, and At the request of the NRC staff, the licensee is evaluat-ems. These include allegations of harassment and intimidation o
I "*"'Y c ntrol mspectors, stop work orders, allegations of 9
in8 the possibility of(1) a waterhammer event as a construct on defic,encies, and NRC fines. In early 1980, Hous-i i
result of the hot reactor coolant backflow and ( 2) an mterfacm system loss-of coolant accident (LOCA) ton Lighting & Power Company (HL&P) initiated a series of (Event V as the result of hot reactor coolant backflow management changes. These were followed by intentional reductions in construction activity that lasted until mid-1982.
mto the,o,w {ressure (suction) side of the HPCS sys-During that time, HL&P commissmned an ind ndent review tem. An mitia evaluation by thelicensee indicate,d th,e of pro;cct status, which was followed by the re acement of the low-pressure HPCS pipmg would not rupture ifitis architect-engineer (AE) and constructor. Be htel was named pressurized to reactor pressure.
the AE/ construction manager in 1981, and Ebasco was named the constructor in 1982.
The NRC staff will continue to monitor the licensee's evaluation of this event and the licensee's corrective actions.
Construction of South Texas Project, Unit 1 (STP-1), was com-pleted in August 1987, and on August 24,1988, STP-1 was T"67 any declared to be in commercial operation. STP-1 completed the roo4 roos o
entire test program with only three unplanned scrams of tbc y-reactor from a critical condition. On a normalized basis, this amounts v an unplanned scram frequency of Li scramsper 1000 I
us -o-critical hours. The NRC staff's recent New Plant Study, docu-l l
mented in NUREG-1275, Volume 1, found that the average unplanned scram frequency for a gwup of newly licensed plants v
during the pre-commercial period of operation was 53 scrams i
per 1000 critical hours. Compared to this experience, the STP-A, its,-o-1 startup rformance was quite good. In the past, other newly licensed lants (e.g., Limerick 1, Palo Verde 3) have also expe-I o
rienced elatively good performance during startup. What makes the STP-1 experience exceptional is the fact that, unlike l p - sor-o-the other plants which achieved good performance during startup, STP-1 is the first nuclear unit that HL&P has operated. Other licensees had the benefit of previous nuclear experience, either with an earlier unit operating at the same site or with another uov nuclear unit operating elsewhere in the utility's electric genera-ron tion network. The results of the New Plant Study indicate that a j
lack of nuclear experience on the part of the licensee can be a
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to supantssion root detrimental factor m the startup performance of a newly licensed j
plant. The New Plant Study also identified a number of lessons learned that are based on the startup experience of new plants.
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i These can be a positive influence on the performance of a newly rE licensed plant,if they are properly implemented by the licensee.
ico'-s.
From the startup performance of STP-1, it is apparent the R- $
management and staff at STP-1 took these lessons learned quite seriously, ww I
m rum Achieving such a high level of quality performance required a i
determined and responsive effort by STP management and staff, as well as a concerted effort on the part of the NRC staff. Of M
specific interest was the intensive inter-Office operational readi-ness evaluation that was undertaken by a team composed of representatives from Region IV, the Office of Nuclear Reactor Regulation, and the Office for Analysis and Evaluation of i
High Pressure Core Spray System Operational Data. The evaluation was a week-long on-site
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evaluation of the readiness for power operation that addressed 4
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bNiiMARIMI South Texas Project all aspects of STP's operational programs. The evaluation iden-thimble tube wear, aluminum-bronze piping, steam generator tiGed a number of deficiencies and weaknesses in the licensee's feedwater pumps, and feedwater pump shaft failure. STP programs. In response to each of the concerns identined, STP aggressively pursued these complex technicalissues and worked management proposed and implemented prompt corrective with the NRC until resolution was complete.
action. The effectiveness of these actions can best bejudged by the resulting good performance of the plant durmg the startup It is only a short extrapolation to show that a combination of and power ascension periods.
mtra-Agency cooperation and effective utility management should be used not onlyduring the startup and power ascension of a new In addition to the operational readiness evaluation performed by plant, but also during the every day operation of nuclear plants.
the NRC, other measures were used to provide assurance of a As demonstrated by STP, the results are positive and benefit all smooth startup. These include a self-evaluation performed by who are involved.
STP at various milestones during power ascension and testing programs. The self-evaluations consisted of holding the plant at a previously specified power level while STP management per-formed a complete review of the plant's performance and readi-ness to begin the next phase of the startup program. The results were then discussed with NRR and Region IV before the plant resumed its startup and power ascension testing schedule The success of STP-1 during its startup and power ascension programs has demonstrated that, through an effective manage-ment organization, a utility can overcome problems and, in the end, have a better than average product. Further, through a cooperative effort by different parts of the Agency,the NRL can carry out an efficient regulatory process. The results of this effort were seen during the resolution of a number of complex technical problems prior to criticality. These issues included 5
I;
Erosion / Corrosion NRR TechnicalIntern ProgIanM by Paul Wu, ECEB by Valeria H. Wilson, PMAS On December 9,1986, Surry Unit 2 experienced a catastrophic failure of a main feedwater pipe. Since then the irbstry, m in April 1988, the Office of Nuclear Reactor Re NRR) conjunction with NRC initiatives, has taken steps to evelop initiated itsTechnicalintern Program. Recent college gra monitoring programs toprevent rupture of high energy piping and others with limited experience are hired at a grade commen-due to smgle-phase erosion /corrosmn.
surate with their education level and work experience. The program provides a mix of training and work experiences for in March 1987, the Institute of Nuclear Power Operations entry-level employees who have limited nuclear-related, indus-(INPO) issued SOER 87-3 which recommended that a continu-trial, and regulatory experience.
j mg program be established at all U.S. nuclear power plants that included analyses to predict wear rates and regular inspections. The 18-to 24. month program consists of rotational assignments i
in June 1987, the Nuclear Management and Resources Council in NRR and the Regmns. Participants are given an opportunity l
(NUMARC) issued guidelines for erosion / corrosion monitor-to work in the projects and technical review divisions of NR R and l
ing in single-phase lines. At the same time, the Electric Power to pin on-site Regional and plant experience. The assignments Research Institute (EPRI issued the computer code CHEC to provide exposure to project management, engineering review, assist licensees in identify)mg the piping locations most suscep-and inspection functions. Recently, a tible to crosion/ corrosion.
include the Office of the Secretary and the Office of the Executive Director for Operations in the rotational assignments Because of the immediate concern about high-energy, carbon whenever possible.
steel systems and the absence of regulatory requirements for pipe wall thickness inspections, the staffissued NRC Bulletin 87-Upon entering on dut 01 on July 9,1987 to assess the generic implication of the Surry reading, orientation, y, each intern is give incident. In addition, NRC Information Notice 87-36 was issued required to maintain a record showing when each assignment is on August 4,1987 to alert licensees about the significant unex-completed. Training courses are added as necessary during ro-l pected pipe wall thinning in t he safety-related portion of feedwa-tational assignments. In addition, the interns participate in the i
ter lines at the Trojan plant.
technical traming courses at the Technical Training Center in l
Chattanooga, as well as in other courses taught at NRC for l
Alllicensees responded to the Bulletin, and the staff completed technical professionals. Interns also prepare monthly reports l
its review in late December 1987, in June 1988, N UMARC also regarding their assignments and accomphshments.
l completed its survey on crosion/ corrosion among U.S. light-(
l water reactors. The resultsof the staff reviewand the NUMARC NRR management is committed to making the intern program
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survey indicated that crosion/ corrosion is widespread, espe-work. To ensure that the interns get the attention and support cially among the pressurized water reactors. Wall thinning has they need, a mentor (an SES manager) is assigned to each intern.
been discovered in both safety-related and nonsafety-related The mentor assists in structuring the training program, and portions of the feedwater lines, meets with the intern weekly during the first month of each i
rotational assignment and at least monthly thereafter (or more l
As a part of the NRC's overall program to address the pipe wall frequently if needed) to provide guidance and assistance as thinmng issue, the staff and its consultants have just completed necessary. In addition to the supemsor and mentor,the interns l
inspection of 10 plants to assess licensees' crosion/ corrosion also have a program coordinator with whom they can discuss monitoring programs and their efforts to implement them. The concerns and problems. Interns are encouraged to meet as a l
results of these ms at the present time,pections are still being evaluated. Ilowever, group to discuss their assignments and issu the staff finds that all licensees have in place l
an crosion/ corrosion monitoring program that meets the intent The intern program is one way that NRR is meeting its egual of NUMARC guidelines. Nonetheless, with a few exceptions, employment opportunity (EEO) goals and objectives and brmg-most licensees have no written procedures or administrative ing m entry iate concern about FTE accountability withm level employees. To help make this a viable program controls to implement their pipe wall thinning monitoring pro-and to allev gram.
allinterns are placed under the Office Director, rather thanin a specific division. When an intern completes the program, he/
The staff is also working with the American Society of Mechani. she will be permanently assigned to a position in bRR. Cur-cal Engineers (ASME) Code Committee to address the pipe rently, NRR has nine techmcal interns. The NRR Technical wall thmning issue. A decision from the ASME Section XI Intern Program provides NRR with a cadre of entry-level engi.
Committee on pipe wall thickness inspection and the staff neers,who,throughtrainingandselectedworkassignments,will l
evaluation of industry's effectiveness in implementing its moni-help the Office meet its regulatory mission in the future.
I toring program will form the basis for the staff's recommenda-l tion regarding the need of additional, regulatory requirements concermng cros on/ corrosion mspection.
6
e 3
Oconce's source of senice water is a very clean fresh water lake.
GrVICO Water Operability Issues Thisfaciiiiyopc,atedformo,ethanadecadewithnoinspections by Rudolph Bernhard and of many ofits service water heat exchangers. When testmg was performed, heat removal capability of the lowpressure injection Ellis W. Merschoff, Region ll (LPI) heat exdiangers and reador butiwas found to hav coo Nuclear plant service water systems are designed to perform Analyses Report (FSAR). Cleaning the LPI heat exchangers i
many functions. They remove decay heat, remove the environ-restored an adequate heat removal rate with a moderate heat exchanger fouling rate. However, the fouling rate for the air and mental heat from spaces contammg equgpment that must per-water sides of the RBCD heat exchangers was such that contin-form a safety function, and remove contamment heat to control They provide coohng water for emer-ued monthly and, more recently, biweekly performance tests containment pressure.,de an emergency backup source of water have been required to ensure the conii pcney equipment,provi for emergencycore coohng systems, and, at some plants, serve as systems.
the ultimay heat sink (U!!S).
Catawba has experienced problems with Asiatic clams and silt-Accident av.-!ym usually assume senice water is available for ing. Clams had migrated to normally, stagnant lines and re-short-term support of emergency eqmpment and long-term mained undetected. Clams in the semce water backup to the m
i support for decay heat removal. Ilowever, despite the impor-auxiliary feed piping partially clogged an auxiliary feed flow 1
control valve on an actuation of the system. Some shell residue tance of these functions, there are very few require,ments for was injected into the steam generators.
regular testing of senice water systems. Problemswith semce water have been discovered because, components have become Farley has clam infestation and silting problems. The charging inoperable. The resolution of Generic Issue 51 with the issuance of a proposed Generic Letter on Senice, Water System Problems mp lube oil coolers were found to be plugged with silt and Affectmg Safety-Related Equipment usil improve the reliability [g"ams. Chlorination is bein of the nuclear industry's scmce water, systems by prescribmg Robinsonhasorganicgrowthandmicrobiologicallyinducedcor-testing to identify problems with semcc water components rosion (MIC) in its senice water system. Containment senice before they render the systems inoperable.
water pipmg was found to be perforated as a result of the MIC.
Region II has conducted special inspections of senice water Grand Gulf has found organic growth and MIC present in its systems that can provide an ovemew of some current semcc senice water and emergency senice water system. The organic water operability issues.
growth fouled piping to the point that flow was almost cut off At Brunswick, which uses brackish water for its senice water, through smaller bore pipes. Careful rebalancing of flows t o help senice water problems have been caused by oysters, corrosion, maintain higher water velocities has helped minimize growth.
and crosion. The residual heat removal (RilR) heat exchangers MIC required weld repair on system pipmg.
at Brunswick became inoperable because service water from the At Crystal River, while trying to reduce senice water flows to j
inlet tox bypassed the heat exchanger tubes.md went directly t decrease diesel generator electrical load requirements, the li-the outlet. Ovsters had plugged the mlet tube sheet, which had censee discovered that the senice water component flows were resulted in a higher than normal differential pressure between the inlet and outlet boxes. This caused Ihe baffle plate to become not consistent with the FSAR design values. The system was re-displaced, leading to the bypass flow. Although flow test resuhs balanced to ensure adequate flows.
l appeared to be normal, the heat exchanger would performed its function if called upon. Efficiency test,not have V. C. Summer had clams in its water source for the plant. Prob-mg of the tems were encountered with RBCU senice water flows. Acid heat exchanger would have detected this type of failure. The cor-cleaning was effective.
rosion problems at Brunswick were due to the salt content of the water. More recently, the copper-nickel alloys that have been A recent safety system functionalinspection at Surry discovered used to replace the corroded pipmg are provmgto be susceptible design problems with the senice water system. Nonsafety-i to crosion due to the flow vek) cities of the semcc water.
related components would have had toperform active functions Turkey Point uses a closed canal for its heat smk. The canal in the event of an accident to prevent loss of the ultimate heat sink. Oysters, clams, seaweed, and other macrofouling organ-wat er has levels of dissolved calcium carbonat,e, coming from the isms are present in the silty, brackish water. Senice water flow surrounding strata which are at near saturation concentrations.
As the water is heated in the main condensers or m the closed through the plant's component cooling water (CCW) heat ex-cooling water heat exchangers, the calcium carbonate precipi-changers was found to be a fraction of the required flow. The tates out onto the tubes, causmg a rapid decrease m heat transfer degradation was due to organic fouling. The main condenser water boxes were cleaned regularly (sometimes weekly) because rates. Even at full flow the heat exchangers cannot actueve rated of the fouling, but the CCW heat exchangers were infrequently heat removal rates when the fouhng is present. The problem cleaned' remained undiscovered for years. Now the Turkey Point heat excharpers are cleaned as often as several times per week to Virt uallyevery plant in Region 11 has experienced problems with mamtam the reqmred heat removal rates. Monitormgis accom-l plished by testing heat exchanger efficiency. Simple flow tests its senice water systems. These problems are not unique to the would not adequately reveal degradation of heat exchanger South. The proposed Generic Letter on senice water recom-performance with this fouling mechamsm.
mends testing that will alert plants to these types of problems.
This Generic Letter,in concert with efforts by the Electric Power t
i.
Research Institute to promote industry understanding of these At McGuire, visual m.spect. ion revealed heavy s.ltmg of heat issues, should result in substantialimprovement in the reliability exchangers. This led Duke Power to perform heat-balance of nuc! car plant senice water systems.
testing of heat exchangers at McGutre,Octmee,and Catawba.
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