ML20079Q726
| ML20079Q726 | |
| Person / Time | |
|---|---|
| Site: | Brunswick  |
| Issue date: | 06/13/1983 |
| From: | Overbeck G, Vosbury F FRANKLIN INSTITUTE |
| To: | Chow E NRC |
| Shared Package | |
| ML20079Q731 | List: |
| References | |
| CON-NRC-03-81-130, CON-NRC-3-81-130, RTR-NUREG-0737, RTR-NUREG-737 TER-C5506-174-1, TER-C5506-174-175, NUDOCS 8306160513 | |
| Download: ML20079Q726 (22) | |
Text
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TECHNICAL EVALUATION REPORT ECCS REPORTS (F-47)
TMI ACTION PLAN REQUIREMENTS CAROLINA POWER AND LIGHT COMPANY BRUNSWICK STEAM ELECTRIC PLANT UNITS 1 AND 2 NRC DOCKET NO.
50-325, 50-324 FRC PROJECT C5506 FRC ASSIGNMENT 7 NRC CONTRACT NO. NRC 03-81 130 FRC TASKS 174, 175 Preparedby Franklin Research Center Author:
F. W. Vosbury 20th and Race Streets G. J. Overbeck Philadelphia, PA 19103 FRC Group Leader:
G. J. Overbeck l
Preparedfor
~
,7 Nuclear Regulatory Commission Lead NRC Engineer:
E. Chow Washington, D.C. 20555 June 13, 1983 l
This report was prepared as an account of work sponsored by an agency of the United States l
Government. Neither the United States Goverrament nor any agency therect or any of their employees, makes any warranty, expressed or impl(ed, or assumes an) se "hility or responsibility for any third party's use, or the results of such use, of any intr.,:w, c", appa-ratus, product or process disclosed in this report, or represents that its use t,f..och third party would not infringe privately owned rights.
Prepared by:
Reviewed by:
Approved by:
cs A -
AmAhY kff Principal AuthoQ Group Le'ader Department Dir/ctor()
Date-
'DN Date:
/, 93 Date:
d ' #3 3
"A XA. Copy Has Been Sent to P I')ukae XA
. Frankiin Research Center i
(C8Sd6/655/
A Division of The Franklin institute
- n. Benen Franen PeM. %. Pa. 19103 (215)448 1000
e TER-C550 6-174/175 CONTENTS Section Title Page 1
INTRODUCTION 1
1.1 Purpose of Review.
1 1.2 Generic Background.
1 1.3 Plant-Specific Background.
2 2
REVIEW CRITERIA.
3 3
TECHNICAL EVALUATION 4
3.1 Review of Completeness of the Licensee's Report 4
3.2 Comparison of ECC System Outages with Those of Other Plants.
5 3.3 Review of Proposed Changes to Improve the Availability of ECC Equipment.
16 4
CO!CLUSIONS.
17 5
REFERENCES.
18 9
A Dumon of The Fransen w
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TER-C5506-174/175 FORDf0RD This Technical Evaluation Report was prepared by Franklin Research Center under a contract with the U.S. Itaclear Regulatory Commission (Office of Nuclear Reactor Regulation, Division of Operating Reactors) for technical assistance in support of NBC operating reactor licensing actions. The technical evaluation was conducted in accordance with criteria established by the NBC.
Mr. G. J. Overbeck and Mr. F. W. Vosbury contributed to the technical preparation of this report through a subcontract with WESTEC Services, Inc.
e 9
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00h ranidin Research Center A Onamen of The Fransen insamme I
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TER-C550 6-174/175 1.
INTRODUCTION 1.1 PUhtPOSE OF REVIEW This technical evaluation report (TER) documents an independent review of the outages of the emergency core cooling (ECC) systems at Carolina Power &
Light Company's (CP&L) Brunswick Steam Electric Plant Units 1 and 2.
Se purpose of this evaluation is to determine if the Licensee has submitted a report that is complete and satisfies the requirements of TMI Action Item II.K.3.17, " Report on Outages of Emergency Core-Cooling System Licensee Report and Proposed Technical Specification Changes."
1.2 GENERIC BACKGROUND 7ellowing the 'Bree Mile Island Unit 2 accident, the Bulletins and Orders Task Force reviewed nuclear steam supply system (NSSS) vendors' small break loss-of-coolant accident (IOCA) analyses to ensure that an adequate basis existed for developing guidelines for small break LOCA emergency procedures.
During these reviews, a concern developed about the assumption of the worst single failure.
Typically, the small break LOCA analysis for boiling water reactors (BWRs) assumed a loss of the high pressure coolant injection (liPCI) system as the worst single failure. However, the technical specifications permitted plant operation for substantial periods with the HPCI system out of service with no limit on the accumulated outage time. Were is concern not l
only about the HPCI system, but also about all ECC systems where substantial outages might occur within the limits of the present technical specification.
Therefore, to ensure that the small break LOCA analyses are consistent with the actual plant response, the Bulletin and Orders Task Fcrce recommended in NUREG-0 626 (1], " Generic Evaluation of Feedwater Transients and Small Break l
Ioss-of-Coolant Accidents in GE-Designed Operating Plants and Near-Term j
Operating License Applications," that licensees of General Electric (GE)-designed NSSSs do the following:
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" Submit a report detailing outage dates and lengths of the outages for all ECC systems. We report should also include the cause of the outage (e.g., controller failure or spurious isolation). The outage data for l
_nklin Resear_ch Center l
TER-C550 6-174/175 ECC components should include all outages for the last five years of operation.
Se end result should be the quantification of historical unreliability due to test and maintenance outages.
B is will establish if a need exists for cumulative outage requirements in technical specifications."
Later the recosamendation was incorporated into NUREG-0660 [2], "NRC Action Plan Developed as a Result of the M-2 Accident," for all GE-designed NSSSs as StI Action Item II.K.3.17.
In NUREG-0737 [3], " Clarification of TMI Action Plan Requirements," the NBC staff expanded the Action Item to include all light water reactor plants and added a requirement that licensees propose changes that will improve and control availability of ECC systems and components.
In addition, the contents of the reports to be submitted by the licensees were further clarified as follows:
"Se report ahnold contain (1) outage dates and duration of outagest (2) cause of the outager (3) ECC systems or components involved in the outage; and (4) corrective action taken."
1.3 PLANT-SPECIFIC BACKGROUND On December 31, 1980 [4], CP&L submitted a report in response to NUREG-0737, Item II.K.3.17, " Report on Outages of anergency Core-Cooling Systems Licensee Report and Proposed Technical Specification Changes." The report submitted by CPEL covered the period from November 3,1975 to December 31, 1979 for Brunswick Unit 2 and from March 18, 1977 to December 31, 1979 for Brunswick Unit 1.
CP&L did not include any recommendations in its report to improve the availability of ECC system components.
. N Franklin Resear.ch Center a on a. n. rr
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TER-C550 6-174/175 i
2.
REVIEW CRITERIA The Licensee's response to NUREG-0737, Item II.K.3.17, was evaluated against criteria provided by the NBC in a letter dated July 21, 1981 [5]
outlining Tentative Work Assignment F.
Provided as review criteria in Reference 5, the NBC stated that the Isicensee's response should contain the following information:
1.
A report detailing outage dates, causes of outages, and lengths of outages for all ECC systems for the last 5 years of operation. mis report was to include the ECC systems or components involved and corrective actions taken.
Test and maintenance outages were to be included.
2.
A quantification of the historical unavailability of the ECC systems and ea= pan =ats.due to test and main *=amace outages.
3.
Proposed changes to improve the availability of ECC systems, if necessary.
The type of information required to satisfy the review criteria was clarified by the NBC on August 12, 1981 [6]. Auxiliary systems such as component cooling water and plant service water systems were not to be considered in determining the unavailability of ECC systems.
Only the outages of the diesel generators were to be included along with the primary ECC system outages. Finally, the "last five years of operation" was to be loosely i
interpreted as a continuous 5-year period of recent oper'ation.
On July 26, 1982 (7], the NRC further clarified that the purpose of the review was to identify those licensees that have experienced higher ECC system outages than other licensees with similar NSSSs.
@e need for improved reliability of diesel generators is under review by the NIC.
A diesel generator interim reliability program has been proposed to effect improved performance at operating plants. As a consequence, a comparison of diesel generator outage information within this review is not required. Nud Franklin Research Center A Dhemen of The Fransen insensee
TER-C550 6-174/175 3.
TECHNICAL EVALUATION 3.1 REVIEW OF COMPLETENESS OF THE LICENSEE'S REPORT The ECC systems at CP&L's Brunswick Units 1 and 2 consist of the following four separate systems:
o high pressure coolant injection (HPCI) system o autcmatic depressurization system (ADS) o core spray (CS) system o low pressure coolant injection (LPCI) system.
In Reference 4, CPEL also included systems and components that support the ECC systems in carrying out their design functions under various accident conditions. m e support systems area o containment cooling mode of the residual heat removal (RHR) system o RER s6rvice water system o standby diesel generators.
o me purpose of the containment cooling mode of the RER system is to limit the temperature rise in the suppression pool and condense steam in the drywell following a LOCA. S e RER service water system provides cooling water to the RHR heat exchangers.
Neither of these systems is considered a primary ECC system for this review.
In addition to outage data on four ECC systems and the support systems, CPEL also included data on the reactor coolant isolation cooling (RCIC) l system. Se RCIC system is a non-safety-related high pressure system available for high pressure injection. Although the RCIC system mitigates the l
consequences of a loss of normal feedwater, this systect is not required to prevent core damage and therefore is not considered to be an ECC system.
2e ECC system outage data were extracted from the following plant records:
o records for Limiting Conditions of Operation (LCOs) o shift foreman and operator daily journals. u001) er.nuiin a.rch center a cm
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TER-C550 6-174/175 For each ECC system outage event, CP&L provided the outage dates, the duration, and the cause, plus sufficient description to discern the corrective action taken. Maintenance and surveillainde lasting activities were included
' n the ECC system outage data, unless these activities were performed during a i
shutdown condition in which the affected ECC system was not required to be operational.
The results of CP&L's review were provided for the period from March 3,1977 to December 12, 1979 for Unit 1, and from November 3,1975 to December 12, 1979 for Unit 2.
Se period for Unit i represents the plant operating time since fuel loading.
Based on the preceding discussion, it has been established that CP&L has submitted a report which fulfills the requirements of review criterion 1 without exception.
3.2 COMPARISON OF ECC SYSTEM OUTAGES WITH THOSE OF OTHER PLANTS The outages of ECC systems can be categorized as (1) unplanned outages due to equipment failure or (2) planned outages due to surveillance testing or preventive maintenance.
Unplanned oatages are reportable as Licensee Event Reports (LERs) under the technical specifications.
Planned outages for periodic maintenance and testing are not reportable as LERs. The technical specifications identify the type and quantity of ECC equipment required t.s well as the maximum allowable outage times.
If an outage exceeds the maximum l
allowable time, then the plant operating mode is altered to a lower status consistent with the available ECC system components still operational.
The purpose of the technical specification maximum allowable outage times is to prevent extended plant operation without sufficient ECC system protection.
The maximum allowable outage time, specified per event, tends to limit the unavailability of an ECC system. However, there is no cumulative outage time limitation to prevent repeated planned and unplanned outages from accumulating extensive ECC system downtime.
Unavailability, as defined in general terms in WASH-1400 (8], is the probability of a system being in a failed state when required. However, for this review, a detailed unavailability analysis was not required.
Instead, a 000 Franidin Research Center A Denman of The Fransen humane
f TER-C550 6-174/175 preliminary estimate of the unavailability of an ECC system was made by calculating the ratio of the ECC system downtime to the number of days that the plant was in operation during the last 5 years. To simplify the tabulation of operating time, only the period when the plant was in operational Mode 1 was considered. This simplifying assumption is reasonable given that the period of time that a plant is starting up, shutting down, and cooling down is small compared to the time it is operating at power.
In addition, an ECC system was considered down whenever an ECC. system component was unavailable due to any cause.
It should be noted that the ratio calculated in this manner is not a true measure of the ECC system unavailability, since outage events are included that appear to compromise system performance when, in fact, partial or full function of the system would be expected.
Full function of an ECC system would be expected if the design capability of the system exceeded the capacity required for the system to fulfill its safety function.
For example, if an ECC system consisting of two loops with multiple pumps in each loop is designed so that only one pump in each loop is required to satisfy core cooling requirements, then an outage of a single pump would not prevent the system from performing its safety function.
In addition, the actual ECC system unavailability is a function of planned and unplanned outages of essential support systems as well as planned and unplanned outages of primary j
ECC system components. In acco; dance with the clarification discussed in Section 2, only the effects of outages associated with primary ECC system components and emergency diesel generators are considered in this review.
The inclusion of all outage events assumed to be true ECC system outages tends to I
overestimate the unavailability, while the exclusion of support system outages tends to underestimate the unavailability of ECC systems and components.
Only a detailed analysis of each ECC system for each plant could improve the confidence in the calculated result.
Such an analysis is beyond the intended scope of this report.
The planned and unplanned (forced) outage times for the four ECC systems l
(HPCI, ADS, CS, and LPCI) and the emergency diesel generators were identified b) Franklin Research Center Acm.m.nes m nemen
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TER-C550 6-174/175 from the outage information in Reference 4 and are shown in number of days and as percentage of plant operating time per year in Tables 1 and 2 for Brunswick l
Units 1 and 2, respectively.
Outages that occurred during nonoperational periods were eliminated, as well as those caused by failures or test and maintenance of support systems. Data on plant operating conditions were obtained from the annual reports, "ta.iclear Power Plant Operating Experience"
[9-12), and from monthly reports, " Licensed Operating anactors Status Summary asport" [13 ].
me remaining outages were segregated into planned and unplanned outages based on CPEL's description of the cause.
S e outage periods for each category were calculated by summing the individual outage durations.
Included for informational purposes are the RCIC system outage data.
Observed outage times of various ECC systems at Brunswick Units 1 and 2 were compared with those of other BWRs.
Based on this comparison, it was concluded that the historical unavailability of the CS, LPCI, and ADS systems has been consistent with the performance of those systems throughout the industry and consistent with existing technical specifications. We observed unavailability was less than the industrial mean for the CS, LPCI, and ADS systems.
Me HPCI system at both units, however, has an observed unavaila-bility significantly higher than that observed in other plants and has exceeded the industrial mean by greater than about one standard deviation, j
assuming that the underlying unavailabilty is distributed lognormally.
Se outages of the diesel gener~ators and the BCIC system were not included in this comparison.
I A detailed review of the HPCI outages at both units indicates that the excessive outage time was not caused by a small number of unique occurrences, but by an accumulation of a large number of long and short outages.
Se major l
contributors to the HPCI system outages are listed in Tables 3 and 4 for Units 1 and 2, respectively. Each table includes the outage date, duration, cause as reported by CP&L, and a remark section whicn provides more information if available. A large number of the HPCI system outages seem to be more related l
to maintenance practices rather than to equipment failures or surveillance nklin Research Center A Onesen of The Franien kuumme
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Table 1.
t:il Planned and implanned (purced) Outage Times for Brunswick thit 1 r
e9 CS LPCI IICIC RPCI ADS EtW2
= ?.
Days of Plant Outage in Days Outage in Days Ntage in Days Outage in Days Outage in Days Outage in Days S
Year Operation Forced Planned Forced Planned Forced Planned Forced Planned Forced Planned Forced Planned 1977 147.38 0.0 0.02 0.0 0.0 0.38 0.98 5.77 2.53 0.0 0.0 12.66 7.05 Comunercial
(<0.1%)
(0.3%) (0.7%)
(3.9%) (1.7%)
(0.6%) (5.3%)
operation 3/18/77 1978 317.79 0.0 0.32 0.0 0.0 3.14 & 1.70 1.31 30.82 0.0 0.0 1.50 7.27 (0.1%)
(1.06) (0.50)
(0 48) (9.7%)
(0.5%) (2.36)
I 1979 199.25 0.99 0.59 0.83 0.0 18.80 7.25 6.41 11.20 0.0 0.0 6.90 5.52 (0.4%) (0.3%)
(0.44)
(9.4%) (3.6%)
(3.2%) (5.6%)
(3.5%) (2.8%)
intal 664.42 0.99 0.93 0.83 0.0 22.32 9.93 13.49 44.56 0.0 0.0 21.06 20.64 (0.14) (0.1%)
(0.14)
(3.4%) (1.5%)
(2.0%) (6.7%)
(3.2%) (3.14) 4 Ut Om I
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EC if 3
5E as p 30
,a 12 g3 Table 2.
Planned and thplanned (Purced) Ostage Tlass for Brunswick thit 2
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- R CS LPCI RCIC HPCI ADS EDG Days of Plant Outage in Days Outage in Days Outage in Days Outage in Days Outage in Days Outage in Days Year Operation Forced Planned Forced Planned Forced Planned Forced Planned Forced Planned Forced Planned 1976 204.83 0.0 0.0 3.0 1.00 2.92 9.65 1.00 5.39 0.0 0.0 1.68 0.0 (1.5%)
(0.5e)
(1.46) (4.76)
(0.54) (2.6t)
(0.86) 1977 203.17 0.0 0.0 0.01 3.98 0.42 5.02 0.04 1.92 0.17 0.0 0.0 2.58
(<0.14 (2.04)
(0.2%) (2.5%)
(<0.14) (0.9%)
(0.14)
(1.3%)
Ij' 1978 292.54 0.25 0.0 0.0 0.0 12.25 1.73 3.59 25.11 0.0 0.0 1.02 1.62 (0.14)
(4.2t) (0.64)
(1.24) (8.64)
(0.3%) (0.6t) 1979 239.29 0.32 1.90 7.11 0.85 19.73 5.87 12.21 15.57 0.0 0.0 9.05 19.84 (0.1%) (0.8%)
(3.0 %)
(0.4 %)
(8.2%) (2.5%)
(5.14) (6.5 %)
(3.8%) (8.3%)
Total 939.83 1.47 0.0 10.12 5.83 35.32 22.27 16.84 47.99 0.17 0.0 11.75 24.04 (0.2%)
(1.1%)
(0.6%)
(3.8%) (2.44)
(1.84) (5.14)
(<0.14)
(1.3%) (2.6 % )
6-3 t
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TER-C550 6-174/175 Table 3.
Major Contributors to EPCI Gatages for trunswicz Unit 1 Duration Cutage Date (daysl Licensee Stated Causes Romerts 11-5-77 5.89 Ground on auxiliary oil pump motor f.ER 77-95 describes the cause as high water in the EPCI room which shorted the auxiliary oil pump motor. With the reactor operating at 1004 power and while testing the EPCI turnine, the auxiliary EPCI oil pump tripped, causing the E7CI turbine to trip. S e high water was caused by operator error which permitted water to be pumped ti the IPCI toom from the south core spray and south RER room sumps instead of to radweste system.
4 12-78 5.85 1-841-v9 failed to operate during LER 78-39 describes the cause as corrosion in the periodic test 9.5 EG-R actuator. EPC turbine control valve V9 would not operate during performance of quarterly surveillance test des to excessive corrosion inside the electro / mechanical / hydraulic (EG R) actuator. The pilot valve plunger would not operate on signal and, therefore, prevented the control valve from moving. A new EG-R actuator was installed.
4 78 5.99 Repair gasmet test on high pressure pump casing 5-15-78 1.88 perform periodio test on steen leak detection 10-24-78 2.50 aepel: 1eek en steen supply trap E41-M54 is a 1-inch, normally closed, drain valve E41-F054 air-operated, condensate pot drain valve.
11-14-7s 5.13 Actuator corroded LER 78-089 describes the cause as water in the hydraulic fluid caused corrosion. With the reactor at sit power and during a EPCI system component test, the RFCZ EG-R actuator failed to operate properly. The corroded actuator was replaced. It was postulated that steam lemmage past the seat of E41-F001 valve allowed water to enter the hydraulic fluid. M e hydraulic fluid was replaced on 12/12/70. E41-F001 was repaired to stop the steam leakage on 12/5/78.
12-5-78 4.70 sepair E41-r001 valve See remark for outage dated 11-14-78.
12-13-78 1.49 Investigate water loam into oil sump the maintenance record indicates that the water wee from valve F=001 and that the oil in the sump was replaced. No further details were available.
12-29-70 1.44 Calibrate drain pot level switches 1-4-79 8.52 Failed periodic test 4.5.3.4 LER 79-001 describes the cause as an out-of-(response time) adjustment governor, with the reactor at 964 power and while performing periodic test FT 45.3.4, the EPCI turbine failed to meet response time limits. Troualeshooting work on the governor controls was in progrees when the reactor was shut down on 1/13/79 for a refueling outage. The governor assimely was found to have various parameters out of alignment or adjustment. With the assistance of a Terry Turbine technical representative, the governor assemoly was aligned and adjusted per instructions in technical manual.
12-6-79 6.04 No speed control EGM (electric governor module) was defective. It was replaced. Upon ratesting, it was further discovered that the tachometer had a bad spot.
The initial probism was a bad EGM, because no electrical signals were being generated. b Franklin Research Center A Ohemenof 7he FrankenIruunne
TER-C550 6-174/175 Tanle 4.
Major Contstbutors to EPCI outages for Brunswten Unit 2 Duration Outage Date (days)
Licensee Stated Causes Remarks 3-13 -76 1.00 valve 2-E41-2002 failed to open Motor Phases A and 3 were shorted out. Apparently a torque limit switch had malfunctioned during the previous closing sequence. D e motor attempted to run after the valve was closed.
7-10-76 5.00 Inspect and repair temperature detectors 4-12-78 3.13 Speed controller not operating LER 78-039 describes the cause as a defective properly hydraulic actuator unit. During a EPCI flow rate test, it was discovered that the EPCI speed control could not be maintained at a constant revolutions per minute. no EG-R (hydraulic actuator), weich is used to control the EPCI turbine speed, wee defective. The EG-R hydraulic unit was sent to the vendor for repair.
4-24-78 3.30 Repairs to speed controller Instrumentation and control technicians replaced the Etat *= it had a part nummer different from that shown in the technical manual. D e new EGE would not malthrate. It was eventually datorustnad that the ES-a wee not commetible with the 338 and so it was replaced.
10-9-78 4.76 Steen supply isolated to repair n e proelem was a steam leet. n e valve is 2-E41-FOS 2s the steem supply valve to the RER system during MR steen condensing operation. It is a 6-inch valve that was disassembled to lap the seat and disc.
10-23-78 5.18 Steam supply isolated to repair leak on 2-841-7001 valve 11-27-78 8.38 Repack 2-E41-TV37 7037 is a 1-inch teolation valve normally locked open and located in the condensate drain line from the steam supply header drain pot. The Licensee i
I has indicated that no information is available to emplata the raaaaa for such a long delay to repect j
a 1-inah valve. Se Licensee indicated that the esive wee not repaired until March 9, 1979.
Instead, the eyeten wee returned to service and a manual valve was used to remove condensate from the EPCI supply line.
2-9-79 11.54 Calibrate level switches and lap Initially, the EPCI system was taken out of valves into seats service to calibrate level switches and repair system valves. Upon checting the operantlity of the EPCI system before returning to service, a l
governor problem occurred. LER 79-033 states that I
the EPC2 turbine tripped on mechanical overspeed l
at 3500 valle testing EPCZ to determine its operamility on 2-19-79.
ne testing was being conducted prior to cancellation of a limiting condition for operation for a routine calibration.
H e EPCI turbine tripped on mechanical overspeed at 3500 rpm. De spring adjusting screw was found approximately 5 turns out of position. In addition, a set screw used to loct the spring adjusting screw in piace was also found approximately 6 turns away from engaging the spring adjusting screw. D e correct positioning of the spring adjusting screw and its set screw I
l was accomplianed with the assistance of a Terry Turbine representative.
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TER-C550 6-174/175 Taale 4 (Cont. )
Duration Outage Date (days)
Licensee stated Causes Ramerks 2-26-79 1.23 sepair steen supply drain pot drain valve 3-1-79 1.11 Failed periodic test 4 5.3.4 LEA 79-004 describes the cause as loose set screws weich hold speed reference in governor. While performing FT 45.3.4, the spCI initiation response test, a large oscillation in turbine speed was esperienced after the initial acceleration ramp was completed. Set screws wnich hold the spur gear used for speed reference in the governor were loose. The Licensee stated that the ' set screws
- have a hiatory of vibrating loose per the General Electric instructions.
Self-Locaing screwe were used as the reoccurrence control seasure.
7-21-79 12.21 2-E41-r001 valve motor failure LEn 79-053 describes the cause as binding in the motor operator caused the motor to burn out.
Closer emanination of the LER revealed that the binding was caused by an improperly installed motor pinion gear. While performing Pt 9.$, the EpC2 steam isolation valve 2=E41-r001 breamer tripped teile *'ami=g.
The valee motor wee found borned e M further investigation found that the motor pinion gear was installed becaward on tae motor shaft. This permitted the motor pinion gear to ride on tripped busaing when in operation, thersey binding the operator.
C
. ' branidin Research Center J
A Olvean of 7he Freresn inssage
.i TER-C550 6-174/175 testing.
In general, when examining the outages, it appears that the specific causes of many of the outages are independent of each other.
However, taking the outages collectively, there appears to be a commonality which reflects accepted maintenance practices at the plant site. Apparent shortcomings in the maintenance practices can be generalized into two categories.
Se first category consists of outages caused by a failure to correctly diagnose earlier failures and by incorrect or ineffective maintenance action due to an apparent lack of sufficient technical expertise at the plant to identify or correct an existing condition.
Examples of outages in this category are outages of the HPCI turbine control valve actuator and outages of the turbine controller.
On April 12, 1978, the HPCI turbine control valve actuator failed on Unit 1.
Se reported cause was excessive corrosion of the actuators however, no information was provided as to the reason for the corrosion.
Seven months later, on November 14, 1978, the control valve failed a second time due to actuator corrosion.
During this repair, the source of the corrosion was determined to be water in the hydraulic fAuid caused by a leaking seat on valve F001. Conditions that caused the corrosion of the turbine control valve actuator the second time existed previously but had not been identified.
On April 12, 1978, the HPCI system on Unit 2 became unavailable due to a defective electronic governor reverse (EG-R) actuator. W e LER description states that the actuator was returned to the manufacturer. On April 24, 1978, instrumentation and control technicians replaced the Unit 2 electronic I
governor module (EGM) because it has a part number different from that shown in the technical manual. D e EGM could not be calibrated and it was eventually determined that it was not compatible with the EG-R actuator installed 12 days before. Se available data do not indicate that any problem j
existed with the turbine controller between April 12 and April 24 except that a part number did not match that found in the technical manual.
Rather than replace the EGM, the ' Licensee could have sought other alternatives to correct this discrepancy.
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TER-C550 6-174/175 I
On at least two occasions, a manufacturer's representative was called to resolve turbine governor problems.
Se first occurred on January 4,1979,
{
when the HPCI turbine failed to meet response time limits. This outage lasted for 8.5 days and was the longest outage recorded for the Unit 1 HPCI system.
Se governor assembly was found to have various parameters out of alignment or adjustment. With the assistance of a manufacturer's representative, the governor assembly was aligned and adjusted. Se second outage occurred on February 19, 1979 when the HPCI system was being tested following maintenance to calibrate level switches and lap valves into their seats.
This outage lasted 11.5 days and was the second longest outage recorded for the Unit 2 HPCI system. A spring-adjustment screw was found approximately five turns out of position, and the set screw used to lock the spring-adjusting screw in place was also found approximately six turns away from engaging the spring adjusting sceew. With the assistance of a manufacturer's representative, the governor was adjusted.
Although it may be suggested that the first two examples are isolated cases, they are typical of other outages which leave the impression that a thorough and detailed review of proposed and completed maintenance activities was not being conducted. We numerous problems with the calibration of the governor and the eventual need for a manufacturer's representative suggest that the technical expertise at the plant site to identify and correct governor-related problems was insufficient.
Se second category consists of equipment failures that appear to result from poor individual workmanship. Included in this category is an outage which was not corrected quickly and may not have been severe enough to justify taking the system out of service for an extended period of time.
Outages in this category may be indicative of inadequate supervisory control of
~
maintenance activities performed on safety-related systems.
W e following are examples of events in this category.
On November 5,1977, with the reactor at 100% power and a HPCI surveillance test in progress, the HPCI auxiliary oil pump was shorted out.
The short resulted when a transfer of waste water through the HPCI room sump b Franklin Research Center A on
.e m r,
.=
TER-C550 6-174/175 was inadequately monitored and allowed the water level to reach the motor.
This caused a 5.7-day HPCI outage on Unit 1.
On December 15,1978, a differential pressure instrument, DPIS-N005 on Unit 2, failed to operate due to a disconnected wire. Only partial loss of system function occurred in that the HPCI system would have operated normally unless when a steam line high flow signal was received. Maintenance work on the relay was performed ran December 4,1978, during which time a relay wire was not returned to its proper position. The technician doing the maintenance work did not follow wire removal procedure, and system operability was not demonstrated af ter the work was completed. This loss of partial function apparently lasted for 11 days. On July 21, 1979, the Unit 2 HPCI steam isolation valve N01 breaker tripped while closing. The motor was burned because of binding in the valve actuator. Upon investigation, the valve operator was found with the motor pinion gear installed backwards on the motor shaft. This allowed the pinion gear to ride on the tripper bushing when in operation, thereby binding the operator. This outage resulted in over 12 days of HPCI system unavailability 4
and was the largest single contributor.
On September 9, 1980, during a normal reactor startup, the HPCI system turbine control valve on Unit 2 would not open with the auxiliary oil pump running. The EG-R actuator connector plug was found cracked. The connector was damaged by personnel working in the area during the refueling / maintenance outage.
In a least one instance, an outage occurred over a long period of time, but a repair was not made. This outage occurred on November 27, 1978.
The Unit 2 HPCI system was tagged out to repack a 1-inch valve, F037. The 1
l function of this valve is to remove condensate from the HPCI steam supply line i
that has collected in the drain pot. After 8.4 days, the HPCI system was placed back in service; however, M37 had not been repaired.
In a telephone conversation [14], CP&L stated that a manual valve was used to remove condensate from the HPCI steam supply line and that F037 was not repaired i
until March 9,1979.
From the Licensee's discussion, it seems that the HPCI l
was tagged out and taken out of service for 8.4 days without sufficient justification.
If the manual valve was sufficient to effect condensate removal, then it should have been used immediately to avoid placing the HPCI l dOJ Franklin Research Center A Dhnman of The Fransen W
TER-C550 6-174/175 system out of service.
This outage did not exceed the technical specification limit; however, a significant portion of the allowable outage time of the technical specification was used without apparent concern for the cumulative effect on safety from such outages.
3.3 REVIEN OF PRCPOSED CHANGES TO IMPROVE THE AVAILABILITY OF ECC EQUIPMENT In Reference 4, CPEL did not include any recotamendation to improve the availability of ECC systems and components.
e 9
l i
nidin Research Center A Ommen of The Freruen W
TER-C550 6-174/175 4.
CONCLUSIONS Carolina Power and Light Company (CP&L) has submitted a report for Brunswick Steam Electric Plant Units 1 and 2 that contains (1) outage dates and duration of outages, (2) causes of the outages, (3) ECC systems or components involved in the outages, and (4) corrective actions taken.
It is concluded that CP&L has fulfilled the requirements of NUREG-0737, Item II.K.3.17.
In addition, the historical unavailablility of the CS, LPCI, and ADS systems has been consistent with the performance of those systems throughout the industry. Se observed unavailability was less than the industrial mean for the above ECC systems. Se observed unavailability of the HPCI system at Units.1 and 2.did not. compare favorably with those of other HPCI systems throughout the industry.
Se observed unavailabilities exceeded the industrial mean by greater than about one standard deviation, assuming that the underlying unavailability is distributed lognormally. Major contribution to these high unavailabilities can be assigned to planned maintenance activities.
Review of the HPCI outages seems to indicate that this high unavailability can be attributed to apparent shortcomings in the maintenance practices at both Units 1 and 2 during the period from initial commercial operation to December 31, 1979.
A N ranklin Research Center A Dhmen af The Fransen m
e TER-C550 6-174/175 5.
REFERENCES l.
" Generic Evaluation of Feedwater Transients and Small Break Ioss-of-Coolant Accidents in GE-Designed Operating Plants and Near-Tera Operating License Applications" NRC, January 1980 2.
NUREG-0660 "NBC Action Pl&n Developed as a Result of the TMI-2 Accident" NBC, March 1980 3.
" Clarification of TMI Action Plan Requirements" NRC, October 1980 4.
E. E. Utley (CP&L)
Letter to Director of Licensing, D. G. Eisenhut. Subject.
Post 'DtI Boquirements Contained in NUREG-0737 December 31, 1980 5.
J. N. Donohew, Jr. (NRC)
Letter to Dr. S. P. Carfagno (FRC).
Subject:
Contract No.
NRC-03-81-13 0, Tentative Assignment F July 21,1981 6.
NRC Meeting between NRC and FRC.
Subject:
C5506 Tentative Work Assignment F, Operating Reactor PORV and ECCS Outage Reports August 12, 1981 7.
NRC Meeting between NRC and FRC.
Subject:
Resolution of Review Criteria and Scope of Work July 26, 1982 8
WASH-1400
" Reactor Safety Study" NRC, October 1975 9.
' Nuclear Power Plant Operating Experience 1976" NRC, December 1977 10.
" Nuclear Power Plant Operating Experience 1977" NRC, February 1979 A O ranklin Resear
~~-.ch Center l
1
TER-C550 6-174/175 11.
" Nuclear Power Plant Operating Experience 1978" NRC, December 1979 12.
NUREG/CR-1496 "latelear Power Plant Operating Experience 1979" NRC, May 1981 13.
" Licensed Operating Reactors Status Summary Report" Volume 4, Nos. 1 through 12, and volume 5, No.,1 NRC, December 1980 through January 1981 14.
NRC/CP&L
'Nlephone conversation with J. Van Vieit (Project Manager, NRC), R.
Poulk (CP&L), and G. J. Overbeck (FRC)
Subject:
Clarification of Reported Outages June 1,1982 o
b^
e A 000 ranklin,w arch Center Rese
~.
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