IR 05000272/1989011
| ML18094A568 | |
| Person / Time | |
|---|---|
| Site: | Salem  |
| Issue date: | 07/05/1989 |
| From: | Swetland P NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I) |
| To: | |
| Shared Package | |
| ML18094A566 | List: |
| References | |
| 50-272-89-11, 50-311-89-10, NUDOCS 8907170412 | |
| Download: ML18094A568 (47) | |
Text
Report N License Licensee:
Facility:
Dates:
Inspectors:
Approved:
U. S. NUCLEAR REGULATORY COMMISSION
REGION I
50-272/89-11 50-311/89-10 DRP-70 DRP-75 Public Service Electric and Gas Company P. 0. Box 236 Hancocks Bridge, New Jersey 08038 Salem Nuclear Generating Station - Units 1 and 2 May 1, 1989 To June 5, 1989 Kathy Halvey Gibson, Senior Resident Inspector Stephen ~. Pindale, Resident Inspector 7-5"-8~
Projects Section 2B Date Inspection Summary:
Inspection 50-272/89-11; 311/89-10 on May l, 1989 - June 5, 1989 Areas Inspected:
Resident safety inspection of the following areas:
operations, radiological controls, surveillance testing, maintenance, preparedness, security, engineering/technical support, safety assessment/assurance of quality, and review of licensee event report emergency Results:
One violation was identified during this inspectio The violation involved the failure to properly evaluate a temporary facility modification with respect to its impact on adjacent _seismically qualified safety related equipment (Section 8.2.D).
Seven Unresolved Items were identified regarding a potentially generic issue concerning leakage of a certain design safety valve (Section 2.2.2.B), inservice testing techniques (Section 4.2.B), the accept-ability of previous testing on the safety injection system (Section 4.2.C), the adequacy of the licensee's programs to report events *required.by federal regulations (Section 6.2.B), resolution of security computer problems (Secio.2.C), T-mod status reporting and duration (Section 8.2.D), and the effective-ness of Salem nonconformance reporting and corrective action programs (Section 9.1.A).
Five previously open NRC_items were closed.
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DETAILS.SUMMARY OF OPERATIONS Unit 1 was in Mode 6 at the* start of the inspection perio Reactor reassembly, design modifications, system restoration and testing were completed.' A loss of shutdown cooling event occurred on May 20, 1989 during accumulator check valve testin The unit was in Mode 3 at the end of the period with preparations for reactor startup in progres Unit 2 operated at 100% power until May 27, 1989, when the unit was shutdown to Mode 4 due to inadequate Technical Specification response time testing of steam generator main and bypass feedwa*ter regulating valve The unit returned to power operation on May 31, i98.
OPERATIONS (71707, 71710, 93702)
2.1 Inspection Activities On a daily basis throughout the re~ort period,* the inspectors verified that the facility was operated safely and in conformance with regulatory requirement Public Service Electric and Ga*s ( PSE&G) Company management control was evaluated by direct observation of activities, tours of the facility, interviews and discussions with personnel, independent verification of safety system status and Limiting Conditions for Operation, and review of facility record These inspection activities were conducted in accordance with the NRC inspection procedures listed abov The inspectors performed 241 hours0.00279 days <br />0.0669 hours <br />3.984788e-4 weeks <br />9.17005e-5 months <br /> of normal and backshift inspection including deep back.shift and weekend tours of the facility on May 5 (4:15 a.m. - 5:00 a.m.), May 6 (12:30 a.m. - 4:30 a.m.), May 11 (2:00 a.m. -
5:00 a.m.), May 22 (3:30 a.m. - 5:00 a.m.), and May 30 (3:15 a.m. - 5:00 a.m.).
2.2 Inspection Findings and Significant Plant Events 2.2.1 Unit 1 On May 11, while in Mode 6 (Refueling), the licensee was draining the reactor coolant system (RCS) to a mid-loop conditio During a backshift inspection, the inspector observed the associated draindown activities from the control roo The residual heat removal (RHR)
system was in operation as require The inspector reviewed the procedure in use, II-1.3.6, 11Draining the RCS 11, and identified the following:
Technical Specification (TS) 3/4.9.8 required that at least one RHR loop shall be in operation while in Mode 6 at a flow rate of at least 3000 gp ~.,,...-.*"'"'>'""-"l:.'V.:.;~-.::-~~
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A pump vortex curve was part of the procedur At elevations 97 16 11 to 98 10 11, RHR Oow must be between 1000 and 3000 gpm, inclusiv Note: 97 10 11 corresponds to RCS loop cen.terline leve Due to the above RHR flow requirements, an exact system flow of 3000 gpm (with zero tolerance) wai require The.inspector brought this concern to shift supervision's attention, who ordered that draindown activities be stopped when the 99 10 11 loop elevation was reached and that RHR flow be maintained at greater than 3000 gp The licensee then informed the inspector that they would maintain RHR flow at 3000 gpm, however, that since having flow on the low side of 3000 gpm was conservative from a RHR pump vortexing perspective, their efforts would be towards maintaining flow less than or eq~al to 3000 gp Therefore, entry into the TS 3.9.8 Action Statement would possibly be necessary, whose action required closing all containment penetrations providing direct access from the containment to the outside atmosphere within four hour The containment personnel hatch was open at the time, providing a path for several hoses used inside containment for steam generator sludge lancing activitie The inspector returned to the control room about two hours later.and questioned the operators as to what RHR system flow wa The operators responded that the flow was 3000 gp The inspector then reviewed control room instrumentation and found that the indicators have a logarithmic scale and were subject to reading interpretation of about plus or minus 200 gp Control room supervision was consulted on obtaining more precise RHR flow reading A safety parameter display system (SPDS) screen was called up which displayed an RHR flow trend. The totalized RHR flow at that time was 3256 gp Operators immediately reduced flow to 3000 gpm and then mai*ntained system flow using the more accurate SPDS displa During the day shift, licensee management was informed of the inspection findings. Specifically, that plant operators were controlling the plant in a mid-loop condition and were provided with a zero flow tolerance per procedur Additionally, plant operators and supervision did not proactively use a very useful tool in the SPDS to monitor and trend critical plant parameter Rather, only the control board instrumentation was used which was subject to large errors in reading the flow rate The licensee subsequently implemented a procedure change and safety evaluation which provided an enhanced operational band for the vortex curve (1000 to 3500 gpm).
Therefore, a 500 gpm tolerance was provided*
between the TS m1n1mum 3000 gpm flow requirement and the 3500 gpm maximum vortex concern valu *-...
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. On t~e following day, May 12, the inspectQr reviewed a relate Abnormal Operating Procedure, AOP-RHR-2, 11 Loss of RHR Cooling - RCS Level Below the Pressurizer - Elevation 10411, and found that the same vortex curve was included in the. AOP ( 1000-3000 gpm).
The inspector brought this to the licensee's attention, ~ho subsequently revised that curve to reflect the recently developed number This appears to be an example of the licensee fixing a specific problem without fully reviewing the issue on a broader spectrum to determine whether other documents or systems were similarly.affecte During a followup review of this issue, the inspector identified that the first initial condition in the procedure II-1.3~6 specified that the RCS be in Cold Shutdow Per Technical Specifications, Cold Shutdown is defined as Mode However, the plant was in Mode 6 at the time of entering the procedur That initial condition was initialed by a reactor operator as being completed or satisfied. The licensee informed the inspector that using the term Cold Shutdown has not always been interpreted as Mode 5, rather as having the plant at least shutdown to those conditions (including Mode 6).
The licensee agreed, however, that the procedure step is misle~ding. The licensee also stated that including specific Mode requirements for procedure.
entry is not a standard practice, however, procedures will be reviewed to determine whether additional action is necessar In summary, there were several procedural problems associated with Operating Procedure IJ-1. The ~rocedure was reviewed and approved by the Station Operations Review Committee (SORC) on March 29, 198 Procedure reviews may not be providing the appropriate level of attention with respect to procedure adequacy since several inadequacies continued to exis Further, there have been several recent examples of inadequate procedures and failure to properly implement procedure The licensee informed the inspector that they recognize that procedures need improvement, and that their current plan to enhance procedure quality will be reviewed to provide better short term result The inspector will continue to assess the effectiveness of the licensee's actions in this*area during future routine inspections.
On March 20, while in Mode 5 (Cold Shutdown), a total loss of shutdown cooling event occurred at Unit 1 while performing a surveillance test on the safety injection accumulator See Special Inspection Report 50-272/89-17 for additional detail.2.2 Unit 2 On May 27, 1989, a Unit 2 shutdown was commenced after the'licensee determined that the surveillance tests for isolation time response of
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the main and bypass feedwater regulating valves historically have not tested each of the two reactor protection system trains independently as required by Technical Specification Similar problems were also identtfied for Unit See Special Inspection Report 50-272/89-16 and 50-311/89-15 for detail On May 31, during a Unit 2 startup with the reactor critical (Mode 2
- "Startup"), one main steam safety valve (23MS15) lifted prematurel The design lift setpoint is 1070 psig, however, this valve lifted at 1033 psi No unusual activities were in process at the time of the lift. The valve lifted and then properly reseated.- Technical Specification (TS) 3.7.1.1 requires that the Power Range Neutron Flux High reactor trip setpoint be reduced to 87% when one safety valve on any steam generator becomes inoperabl The licensee mechanically blocked the safety valve closed and reduced the trip setpoints to comply with TS The acceptable range_for the lift setpoint for 23MS15 is 1070 psig ~
1% (1059 - 1081 psig). The valve was last' tested satisfactorily in place in February, 198 The licensee identified that the same valve had lifted prematurely on at least two other occasions in the pa~t (November, 1988 and February, 1989).
Both times, the valve lifted at about 1030 psi The inspector reviewed the event and interviewed licensee personnel to determine the cause for the repeated premature safety valve lift The licensee stated that ~he primary reason was that 23MS15 had periodically experienced some amount of leakage, and through discussions with the valve manufacturer (Crosby), the licensee -
determined that the safety valve.actual lift setpoint becomes lower when there is leakage., Further licensee discussions with the vendor identified that the valve's 11flexidisc 11 design characteristically reseats tighter following a lift. This phenomenon possibly explains why the safety valve setpoint verification tests following the previous premature lifts were satisfactor On June 2, with the unit operating at. about 70% power, the licensee tested the main steam safety valve in plac The average setpoint for the three valve lifts was 1066 psig and therefore met the test acceptanc~ criterion. The unit was subsequently returned to full power, This safety valve testing was the.first time the licensee.had tested those valves while operating at powe The test pro~edure was properly reviewed and approved by the Station Operations Review Committee on June 1, 198 The inspector reviewed the test procedure and its associated safety evaluation and observed portions of the test performanc ~o significant deficiencies were identifie *
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The inspector questioned whether the licensee (and the valve manufacturer) could calculate the impact on safety valve setpoint based upon specific valve leakage value The licensee stated that no such calculations had or could be performe The inspector was concerned that this is potentially a generic concern with this type design of safety valves and its impact on valve performance* and therefore, its effect on postulated accident analyses should be addresse Licensee review of this potentially gene:ic issue is an unresolved item (311/89-10-01).
2.2.3 Both Units On May 3i 1989, the licensee declared an Unusual Event due to a helicopter hovering low over several locations within the protected area of the plants. A passenger in the helicopter appeared to be taking pictures of the plants. Several attempts by members of the security force to motion the helicopter to land for identification purposes were apparently ignored and a security alert was initiate The local law enforcement agency was notified ar.d a local office of the Federal Aviation Administration (FAA) was contacted for assistanc The FAA identified the helicopter as being chartered by th~ license It was determined that the hel_icopter had been chartered by the licensee's training department to make a public information film, but plant personnel had not been informe Subsequently, the Unusual Event was terminate Licensee investigation into the cause of the communication breakdown identified that the licensee's transportation department, which made the arrangements for the helicopter, was also responsible for
notifying the site of the date and time that the aircraft would be at the site. This communication did not take plac Site management has reconfirmed with the transportation department their responsibility to provide notification to site personnel fo~ similar future occurrence The inspector had no furthe~ questions concerning this even On May 15, 1989, during Unit 1 protection system modifications, the licensee identified loose clip wire connections on circuit boards in the solid state protection system (SSPS).
The loose connections were apparently due to improper installation of the clips during the manufacturing proces The circuit board units were supplied by Westinghous The licensee has submitted a 10 CFR Part 21 report on this issu Since Unit 1 was in a refueling outage, the licensee performed pull tests on all of the clip connections associated with *the Unit 1 SSP Of the 2,644 connections per train, 119 clips failed the pull test for Train A, and 103 failed for Train The licen~ee replaced the deficient clip connection A.**.;~.;.;;:;.. ~'*
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A visual inspection was performed by the licen$ee on the-Unit 2 SSPS connections and no loose wires or connections were observe Unit 2 was operating at 100% powe Modifications were made to the Unit 2 SSPS during its fourth refueling outage in October, -1988, and no similar discrepancies were identified at that tim The licensee documented a Justification for Continued Operation (JCO) for Unit 2 as related to this issu The lic~nsee plans further Unit 2 inspection the next time the unit is placed in Mode Licensee review of historical operating records has not identified any unexplain~d actuations that cou~d be attributed to loose wire connections in the SSP The inspectors reviewed the licensee's pull test procedures and results, the clip connection replacement procedure, the Unit 2 JCO and the Part 21 repor The inspectors had no further questions on this issue and will follow licensee inspection and results related to Unit 2 when performe.
RADIOLOGICAL CONTROLS (71707) Inspection Activities PSE&G's compliance with the radiological protection program was verified on a periodic basi.2 Inspection Findings The inspectors routinely toured the Unit 1 and Unit 2 radiological controlled areas, including the Unit 1 containment buildin The overall condition and contamination controls in *the Auxiliary Building had improved over the last inspection perio Individual deficiencies were brought to the licensee's attention for resolutio On May 13, the.licensee identified that a contractor employee received a whole body radiation dose above the administrative quarterly limit of 1000 mRe The dose received (1365 mRem) did not exceed the maximum quarterly occupational dose specified in 10 CFR Part 20 of 3000 mRe *
The individual reported to Salem on April 19, and properly completed Form NRC-4 (Form 4), documenting that he had received an estimated prior occupational exposure during the current quarter of 583 mRem (self-reading dosimeter).
That data was then transferred to a data sheet for input-into the licenseers*computerized dose control system (Alnor).
The transfer to the data sheet was supject to a peer review to ensure that the proper information was transferred; these actions were properly performe However, due to an administrative error, a zero was input into the licensee's computer system, and an administrative limit of 1000 mRem (vs. 417 mrem) was allowe,,*:* *
Upon exiting the RCA, the computerized Alnor.reader alarmed because the individual's exposure was approaching the 1000 mRem administrative limi Upon performing a records review to authorize a dose extension to 2000 mRem, the licensee identified that the 583 mRem was not input to the syste Licensee supervision was immediately notified, and the individual's film badge was proces~e The licensee also performed a review of all high dose contractors within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> to verify the integrity of the computer control syste No additional errors were iden~ified~
The licensee subsequently received the accurate film badge reading obtained previously during the current quarter, 508 mRe He received 857 mRem from Salem, totalling 1365 mRe Additional
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corrective actions implemented.by the licensee included providing a second verification for all computer inputs, and instructing workers of the necessity to* maintain data input integrity and the seriousness in errors of that typ Procedur~ changes are also planned by the licensee. -
The licensee had provided the appropriate attention in addressing this event and implementing actions to prevent recurrenc The inspector will monitor the effectiveness of the licensee action during routine resident inspection.
SURVEILLANCE TESTING (61726). Inspection Activity During this inspection period, the inspector performed detailed technical procedure reviews, witnes*sed in-progress surveillance testing, and reviewed completed surveillance package The inspector verified that the surveillance tests were performed in accordance with Technical Specifications, approved procedures, and NRC regulation The following survei.llance tests were reviewed, with portions witnessed by the inspector:
Unit 1 SP(0)4.0.5-P-CV(ll)
SP(0)4.5.2H
- OP-TEMP-8913-1 Inservice Testing - Charging Pump Throttling Valve Flow Balance Test Charging Pump Flow Test
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- Unit 2 SP(0)4.0.5-P-AF(23)
SP(0)4.0.5-V-AF-3A T-252
!ST - Auxiliary Feed Pump
!ST - Valves - Auxiliary Feedwater Main Steam Safety In Place Testing Inspection Findings During a review of surveillance test procedufe SP(0)4.0.5-P~AF-3A,
"IST - Valves - Auxiliary Feedwater", the inspector noted that there were no procedure steps which required initials of the performer, including action step This is a poor practice in that the potential to perform steps out of sequence or missing steps entirely is unnecessarily create This was brought to licensee management's attention, who acknowledged the inspecto~s concer.
During observation of surveillance test SP(0)4.0.5-P-AF(23), "IST -
Auxiliary Feed Pump 11, the inspector noted that the pump was not marked as to where the vibration probe should be placed to obtain the necessary readin The test procedure included a pump/motor drawing and the approximate location to place the vibration probe, however, the location was subject to interpretatio ASME Section XI, IWP 4160 specifies that !ST readings be taken at the same
~ocation. The licensee's procedure did not appear to be consiste~t with IWP.416 The vibration data could be made more useful if the exact locations were somehow marked, to assure accurate performance monitoring and trending result This concern was brought to the licensee's attention, who stated that they would evaluate this concer This issue is unresolved pending NRC review of !ST program commitments and licensee actions on this matte (UNR 272/89-11-06) From May 17 to May 25, the licensee performed surveillance test SP(0)4.5.2H, 11 ECCS Throttle Valve Flow Balance Test" several times on the No. 11 and No. 12 charging pump The two centrifugal charging pumps provide the high head injection portion of the emergency core cooling syste The Technical Specif~cation designated acceptance criteria are 1) a total flow rate of less than or equal to 550 gpm, and 2) the sum of the three lowest injection line flow rates greater than or equal to 346 gp Several test performances failed to meet the second acceptance criteri-0n. Additionally, the flow rates obtained from a flow indicating device located on the common charging pump discharge piping did not agree with the downstream indicated total flow rate, being the sum of the four cold leg injection flow path Specifically, the common line flow rates were consistently about 100 gpm higher than the total of the four injection flow rate *- --. -~- _______..::_
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- The licensee_investigated all feasible leakage paths, however, no leakage was identifie Flow instrument calibrations were also verified, however, the same unacceptable flo~ rate~ were obtaine The licensee then performed additional tests to determine whether there was system leakage and to investigate whether the pump performance characteristits had degrade No performance deficiencies or leaks were identified during those test Followin~ additional full flow test failures,*the licensee identified that the four orifices in the separate injection lines were installed backwards. The-orifices were subsequently reversed, however, the following flow test passed on only the No. 12 charging pum The*
licensee then consulted with the pump vendor and initiated a design change to install a flow orifice immediately downstream of the No. 11 charging pum This maintenance activity is further discuseed in Sectiqn 5. The post-maintenance full flow test subsequently passed for both charging pump The inspector expressed concerns as to how and when the orifices were installed backwards and as to the fe3sibility that the full flow test could have passed its previous performance (last refueling outage) as*
installe Further licensee investigation into the details of this event is necessary to determine the above and to develop calculations
_ to determine if it was technically possible to obtain acceptable flow rates as configure Pending the results of the li~ensee review, this item fs unresolve (272/89-11-01) MAINTENANCE (62703) Inspection Activity During this inspection period, the inspector observed portions of selected maintenance activities to ascertain that these activities were conducted in accordance with approved procedures, Technical Specifications (TS), and appropriate industrial codes and standard Portions of the following activities were.observed by the inspector:
Activity N Procedure WO 871019012 M3L-1 WR 0082605 M3Z Description Limitorque maintenance 1 surveillance and MOVATS testing.of 12RH1 Troubleshooting 12RH19 failure to close from the control roo "'-
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Activity N Procedure WO 890419006 *
M3Q-3 WO 890522135 M23A
Descri pt ibn Reactor trip, 'bypass, and rod drive MG breakers and switchgear 18 month periodic inspection and maintenanc Install flow restricting orifice in No. 11 charging pump discharge lin.2 Inspection Findings
/ During operability retesting of the 12RH19 (12 RHR heat exchanger discharge cross connect valve) following MOVATS testing, it was determined that the valve would not close from the control roo The inspector observed the associated troubleshooting activit Licensee technicians*discovered that two wires were not reconnected following the MOVATS testin The wires were connected and the valve tested satisfactorily. The inspector determined that the leads were not retermi nated by the MOVATS crew s*1 nee operability testing could not*
be accomplished immediately because the control room bezel for the valve was also being worke The technicians intentionally l~ft the leads lifted and the procedural steps were not signed-off so that the valve would not be exercised without maintenance personnel presen Subsequently, the inspector reviewed the MOVATS procedure (M3L-1)
relative to documentation and control of lifted lead The inspector observed that on Attachment 5,Section III of the M3L-1 procedure, the documentation of the removal and restoration of several lifted leads was inadequate since the independent* ~erification was either not performed, or performed by the same person who lifted or restored the lead The inspector further observed that the procedural steps associated with the lifted leads did not specifically require independent verification. Station administrative procedures do not specifically require independent verification for leads repositiorie as part of an established procedur The inspector was concerneo since it has been the licensee 1s policy to require independent verification for lifting and retermination of leads. Additional concerns with lifted leads are discussed in Section During performance of step 9.4.3 of the M3Q-3 procedure, which tests the operation of breaker position switches, leads are lifted to prevent potential arcing ac~oss contacts and parallel paths during the testin The inspector was in the control room during performance of this step and identified that the RP4 status lamp illuminated for
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safety injection train unbloc The unit was in Mode 6 in mid-ioop operati~n. Licensee investiga~ion revealed that the lifting of leads resulted in the unblocking of one train of safety injection. The test was suspended as directed by operations s~pervision and the leads reterminate *
The inspector noted that the shift supervisor approval signature was obtained prior to performing the breaker position switch test, however the test procedure was not clear as to what the function of the lifted leads wa The inspector also noted during review of the maintenance procedure that the independent verification and QA verification signatures were sp~cified and completed in the procedure, however, each block of leads ~ere initi~led once on the top line with an arrow through the list of signature spaces indicating completion of the verification. This is a poor practice in that verification of blocks of leads rather than individual
. verification and signoff may result in one or more leads being misse The NRC_previously observed that controlled documentation of lifted leads was a strength in the licensee 1s maintenance progra These*
procedural deficiencies related to lifted leads were discussed with licensee managemen Weaknesses with resp~ct to maintenance protedures are also a previously identified concern for which the
- licensee has recently instituted a procedure upgrade ~rogra However, to address these particular concerns, the maintenance manager committed to upgrade these specific procedures. *The inspector verified that the procedure writers guide used for the procedure upgrade program provides for independent verification of jumpers and lifted lead * The inspector reviewed the maintenance activities associated with the No. 11 charging pump discharge piping orifice installtion. The inspector determined that the affected drawing was incorrect in that a flow orifice was shown to exist for the No. 12 pum The same print also omitted an existing flange from charging pump no. 1 The licensee plans to correctly update the drawings as part of the design change package (DCP) closeout effor Th.is maintenance activity was to resolve: pump flow concerns identified.during surveillance testing. A DCP was developed for the maintenanc The inspector observed portions of the maintenance, and significant deficiencies were not identifie The inspector noted that Quality Assuran*ce personnel al so ob~erved portions of the activities, and System Engineering also.provided the appropriate levels of interfac Minor installation problems were experienced, however, they were properly resolve., _._,-~"...-:<>f~~
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13 EMERGENCY PREPAREDNESS 6.1 Inspection Activity The inspector reviewed the licensee's use of and compliance with the Event Classification Guide (ECG) and Abnormal Operating Procedures (AOPs) during events that occurred during the inspectio.2 Inspection Findings During the March 20 total loss of shutdown cooling event at Unit 1, the licensee failed to properly classify and report the event in * accordance with 10 CFR 50.72 reporti~g requir~ments. The use and adequacy of AOPs during that event is discussed in detail in NRC Special Inspection Report 50-272/89-17:
The licensee event reports (LERs), as listed in Section 10.1 of this report were reviewed by the inspector, and a concern was identified concerning the immediate notification required by 10 CFR 50.7 Specifically, Unit 2 LER 89-04, "Engineered Safety Feature (ESF)
Actuation - Containment* Ventilation Isolation, on the March 4, 1989 event was reported as a 10 CFR 50.73(a)(2)(iv) event. Ho~ever, the four hour non-emergency NRC notification required by 10 CFR 50.72(b)
was*not made by the license The licensee did not recognize that
50.72 was applicable until question~d by the inspector in June, 198 Discussions with licensee personnel indicated that there was confusion regarding which systems or components were ESF Further review in this area with respect to how ESF actuations are categorized, documented and reported fs necessary to determine whether the licensee's programs properly implement NRC requirement Pending resolution of the above concerns, this item is unresolve (50-311/89-10-02)
. SECURITY (71707)
7.1 Inspection Activity PSE&G's compliance with the security program was verified on a periodic basis, including adequacy of staffing, entry control, alarm stations, and*
physical boundarie.2 Inspection Findings The inspector determined that security's response to the May 3, 1989 event involving an unidentified helicopter over the protected area was satisfactory and appropriate relative to the requirements specified in the licensee's safeguards contingency pla The inspector had no further questions on this even.:,~*..,...;.::~..
14 On May 12, 1989, a licensee senior manager's office received an*
anonymous telephone call, apparently from a Security organization member, expressing concerns that the guards.were workirig e~cessive hour The licensee treated this concern as an allegation, and the licensee developed an action plan to evaluate the alleger's concern Review of work schedules, performance monitoring and worker complaints were included in the action plan scop Additionally, the Quality Assurance organization conducted an independent audit of Securit The inspector met with licensee representatives and reviewed portions of the investigation report The licensee's evaluation documented that while ~verage work week hours had increased due to the recent Unit 1 outage, work hours were not excessiv The licensee informed the inspector that they had attempted to be proactively responsive to decrease the amount of worker overtim The inspector also
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independently monitored security organization effectiveness, and no deficienci~s w~re identifie The inspector's review of this issue is complet On May 24, 1989, ~ loss of all electrical power (AC and DC) to the security computer occurre Compensatory measures were impleme_nted by Security and a one hour report to the NRC was mad The cause of the loss of power appeared to be a design problem associated with the automatic transfer from the primary to the backup AC power source The inspector discussed this issue with security and licensing personnel and determined that problems with the automatic transfer have occurred intermittently since December, 198 Since the December, 1987 occurrence, licensee security and engineering personnel have initiated an investigation into the cause of the transfer proble However, security has not aggressively pursued resolution of this problem, nor have they instituted proactive interim actions to ensure the integrity of the security computer until the problem is resolve As a result of discussions with the inspector, the licensee initiated an engineering work request (EWR) to implement enhancements to the system such as additional annunciators for loss of powe Until the root cause of the deficiency is identified and corrected, the licensee is taking several actions to ensure the integrity of site Security when power is lost to the* security compute Procedures are being developed to require close monitoring of the security computer and power supplies by Operations personnel, during planned transfers, to ensure prompt identification and return of a power supply if a problem occur In addition, Security has issued a memorandum to Security shift supervisors to implement compensatory actions upon the loss of AC power to the security computer.* This wi 11 ensure that site security will be maintained if AC feed cannot be returned to service prior to the DC batteries being discharge This matter will remain unresolved pending completion of the licensee's short and long term corrective actio~ (272/89-11~02)
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15 ENGINEERING/TECHNICAL sµPPORT (71707, 92702) Inspection Activity The inspector held discussions with licensee personnel and the NRR project manager, and reviewed NRC and licensee documentation related to the following issue.2 Inspection Findings (Closed) Unresolved Item 272/87-32-01; Acceptability of alternative test method for auxiliary feed pump heade The licensee submitted an Inservice Inspection Program Relief Request dated November 28, 1988 to acquire formal approval for use of an alternate test method for pressure testing buried auxiliary feedwater pipin Licensee actions are complete and this item is close (Closed) Unresolved Item 272/311/87-05-01; Technical adequacy of one point incore/excore calibration. The inspector reviewed NRC Safety Evaluation Report dated December 30, 1988, which concludes that the licensee's calibration method is satisfacto*r This item is clo~e (Closed) Violations 272/87-02-02 and 272/87-02~03; Lack of procedures for piping and pipe support design activitie The inspecto~
veriiied that the final draft of the consolidated pipe stress and pipe support specifications is complet These items are close During a routine plant tour on May 10, the inspector noted that each control room contained a tall, (about 6 1 high), portable reactivity computer, and whose approximate dimensions were 2 1 by 1.5 1 *
Each had four wheels mounted at its botto Each computer was physically located adjacent to the electrical distribution and emergency diesel generator control consol The inspector expressed concern to the licensee regarding its seismic qualification or evaluatio The li~ensee stated that its installation was covered under the current Temporary Modification (T-Mod) Program and has been in place for both units since essentially initial plant. operation (Unit 1 - 1977, Unit 2 - 1981).
The licensee's Updated Final Safety Analysis Report (UFSAR), Section 3.2, classifies the control room as a Seismic Class I (SC-I)
structur SC-I is further defined as those structures and components, including instruments and controls, whose failure might cause or increase the severity of an accident or result in an uncontrolled release of radioactivit r
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The licensee's current T-Mod program is defined by Administrative Procedure No. 13 (AP-13),
11Temporary Modification Control Program 11 *
The inspector reviewed the T-Mod safety evaluations associated with the reactivity computers and identified the followin )
An April 6, 1984 engineering eval~ation concluded that an unreviewed safety question was not involved and that all potential, realistic failure modes have been considered, and are not applicabl )
A December 13, 1985 engineering evaluation determined that a tecbnical review and not a 10 CFR 50.59 safety evaluation was require The evaluation stated that the electrical jumper*
request related to the computer had previously been over-.
classified as being safety relate The evaluation further stated that a safety evaluation was not required because the wire terminations had been made at non-safety related terminal stri.ps of the Hagen and NIS rack The reactivity computer was further described as a non-safety related testing and monitoring devic The evaluation forms required that all potential, realistic failure modes and/or malfunctions must be considered and listed, including the effects on adjacent systems and structures, and protective or mitigative design features must be
- describe Since neither evaluation addressed the potential impact of the. non-seismic computers on adjacent seismic safety related structures, the inspector determined that both safety evaluations were inadequat AP-13 had undergone a major revision on January 19, 198 The inspector questioned several members of the licensee's organization as to whether more recent evaluations had been performed for the reactivity computer T-Mo Over a two week period, none were found, and the licensee had not yet addressed the presence of the computers fn the control roo CFR 50.59 specifies that licensee's may modify the facility, provided the modification does not involve an unreviewed safety questio Licensee's are further required to perform and maintain written safety evaluations of those modifications which provide the bases for the determination that.the modification did not involve an unreviewed safety questio The failure for the licensee to complete an adequate safety evaluation to address the impact on adjacent safety related equipment is a violation of 10 CFR 50.5 (272/89-11-03)
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On May 27,-the licensee informed the inspector of their intentions with respect to the reactivity computer concern They stated that a safety evaluation addressing the impact on adjacent equipment was not performed and that the Unit 2 computer would be removed from the control roo The Unit 1 computer was planned to remain in the control room until after restart from its refueling outag By the end of the inspection period, the Unit 2 computer was remove Since the licensee committed to remove the Unit 1 computer prior to any sfgnificant power operation, the inspector concluded that the computer could be controlled like other transient maintenance and test equipment used in the plant. The licensee also stated that future permanent modifications were planned as part of ongoing control room redesign effort Several additional concerns w~re identifie One, the-use of the 11temporary 11 change may have been inappropriat Specifically, the above Unit 1 T-Mod had been in place for about 10.year AP-13 states that T-Mod duration should be less than 91 day Since a permanent modification is planned and this procedure is relatively
-
new, its effectiveness in that respect will continue to be monitore A second concern is that AP-13 requires that the status of T-Mods shall be formally reviewed and re-present~d to the Statioh Operations Review Committee every 91 day The inspector found that the required review was several months past du These concerns were brought to the licensee's attention. This item remains unresolved pending prompt, satisfactory implementation of AP-13 with regard to old T-Mod (UNR 272/89-11~05)
NRC Bulletin No. 88-04, 11 Potential Safety-Related Pump Loss 11, was issued on May 5, 1988 to request all licensees to investigate two miniflow design concern The-licensee responded to the bulletin by letter dated August 11, 1988, however, vendor evaluation of pump minimum flows was continuin These results and the licensee's proposed actions were submitted to the NRC by letter dated April 11, 198 The licensee's response sta~ed that residual he~t removal (RHR) pump recirculation flows as low as 450 to 500 gpm were acceptable, however, a maximum time limitation of three hours in any 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> period should be established.. The licensee also included in their respbnse that the minimum required flow for continued RHR operatjon exceeding three hours is 2000 gpm, and that operating procedures II-6.3.2, 11Initiating RHR 11 and II-1.3.6, 11Mid-loop Operation 11, would be revised to incl~de that minimum flow requiremen Cautions were also to be provided in emergency, abnormal, and normal operating procedures_ to avoid placing the RHR pumps on recirculation for more
than three hours in any 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> perio The licensee also stated where that RHR pump operation will be logged so that practical service limits and inspection frequencies could be determine The inspector reviewed licensee procedures and determined that the majority of the changes had not been made by the end of the inspection perio Additionally, the licensee subsequently requested that the vendor support a lower minimum required flow number than 2000 gpm {1500 gpm) for continuous RHR operatio The licensee stated that their response will be revised to reflect current commitment The inspector also identified that the licensee had not
.yet implemented any controls to log RHR pump operation as stated in the bulletin respons Licensee actions to implement commitments specified in the bulletin response have not appeared to be aggressively pursue The inspector will continue to track licensee implementation of the above actions during a subsequent inspectio * SAFETY ASSESSMENT/QUALITY VERIFICATION. (40400, 62703, 71707, 90712) Inspection Findings. On April 27, 1989, during Unit 1 control room (CR) numan factors upgrade modifications, licensee quality assurance (QA) identified potential nonconforming solder connections related to Bailey control and indication relay cabinets. A work order was written for one particular wire which was completely separated from its connectio On April 28, QA's concern was discussed at the morning managers meeting at which time the licensee's engineering and plant betterment (E&PB) department agreed to address the problem since an E&PB project team had a soldering crew working in the relay cabinets in support of the CR modification From April 27 to May 8, licensee QA personnel performed a 100% audit of Unit 1 solder connections, identifying approximately 300 connections which did not meet inspection criteria contai~ed in licensee field directive S-C-EOOO~CFD-0222-0. The deficiencies identified included loose wires, lack of solder, b~rnt or melted insulation, wire strands broken or outside of terminal, and cold solder joints. Approximately 70 connections were identified by QA as needing immediate dispositio In two licensee memorandums from QA to E&PB, dated May 6 and May 9, a list of the 70 connections was provided with a request to evaluate and repair the deficient solder connection On May 10, 1989, Operations submitted a work order for a problem with the containment sump discharge valve which resulted in the
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inoperability of the containment sump pum Troubleshooting related to this work order identified the c~use-as the separated wire discussed previously for which QA had already submitted a work order on April 2 QA's work order had been planned, but was not worke However, as a result of the May 10 work order, the separated wire was resoldered on May 1 On May 17, 1989, QA personnel became aware that no action was being taken regarding the solder connection concerns stated in their May 6 and 9 memorandums, which prompted them to submit an action request to system engineering for resol~tion. * Again the issue was discussed at the managers meeting, and station management directed the station system engineers to resolve the concer System engineering evaluated each of the 70 connections for dispositio By May 26, the connections were either repaired or determined to be acceptable "as is 11 *
On May 18, the inspector was informed of the identified'deficiencies and repair of the sold~r connection The inspector questioned system engineering and QA as to whether the Unit 2 relay cabinets were planned to be inspected for similar deficiencie Unit 2 was operating at 100% powe They stated that the decision to inspect Unit 2 was up to the station manage The inspector's concerns were discussed with the station manager whb directed QA to prepare and conduct a documented planned inspection of Unit 2 relay cabinet From May 18 to May 22 the Unit 2 inspection was performe Twelve
~onnections were identified as needing immediate engineering evaluatio System engineers determined that one involved a safety concern while the others provided control room indication, alarms, or non-safety function No. 23 containment fan coil unit (CFCU) was declared inoperable and the Technical Specification Action Statement ente-red since a nonconforming connection was related to an auxiliary relay and interlock for a high speed breaker which allows the CFCU fan to go to low speed and.positions associated service water valves for high flow under accident condition This connection was repaired on May 23 and-the CFCU returned to operable statu By the end of the report period, the 11 deficient connections for Unit 2 were repaired. A work request has been initiated to evaluate and repair the remaining connections and is planned for future refueling outage The licensee has determined that the deficiencies with solder connections were due to poor workmanship during previous soldering evolution The licensee is in the process of evaluating the method of training-and qual~fication of ~tation and contractor personnel who perform solderin QA review of solder connections made by contractor personnel during the present Unit 1 outage did not identify any deficiencie The same outage contractor personnel repaired the deficient solder connections for both,Unit The
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inspector witnessed soldering activities performed under work order 890521061 and no problems were note The inspector expressed concerns with regard to the slowness of attention to a potential safety problem displayed by licensee management, the informality with which QA documented their concerns and the resulting delay for a period of nearly three weeks to evaluate and resolve the discrepancies. -This issue is unresolved pending NRC review* of the effectiveness of the licensee's non conformance reporting and corrective action programs, and will be verified in a subsequent inspection. (UNR 272/88-11-04) NRC Information Notice (IN) 89-42, "Failure of Rosemount Models 1153 and 1154 Transmitters", was issued on April 21, 1989 to alert licensees of recent transmitter failure Specifically, the failure mechanism of several subject transmitters was the loss of oil from the transmitter's sealed sensing modul Rosemount Inc. issued a notification under 10 CFR Part 21 on February 8, 198 The notification docu~ented several potential characteristic symptoms that may indicate a pending transmitter failure, and provided recommendations to d~termine transmitter degradatio The licensee reviewed the Part 21 report to determine whether Salem was affecte They found that only.one subject transmitter was installed (Model 1154 at Unit 2).
The licensee generated a safety evaluation, which concluded that the Unit 2 transmitter d~es not present a significant safety concer The bases for the licensee's conclusion are as follow Rosemount reported that all but one of the reported failures to date have occurred during the fi-rst 30 months of service. Available data also showed that transmitters in service for more than 36 months are not expected to fail as reporte The transmitter used *at Unit 2 has been in service at high pressure (reactor coolant flow) for 54 months, and during that time, has repeatedly satisfactorily passed calibration and time response surveilJance testin The inspector reviewed the licensee's safety evaluation and found no deficiencie The inspector review in this area is complet.
LICENSEE EVENT REPORT ( LER) AND OPEN ITEM FOLLOWUP (92700)
10.1 Inspection Activity The inspector reviewed the following licensee reports submitted to the NRC Region I Offic For LERs, the inspector verified ~bat the details of the event were clearly reported, including accuracy of the description of cause and adequacy of corrective actio The inspector determined whether further information was required from the licensee, whether generic
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implications were indicated, and whether the event warranted onsite followu The LERs were also reviewed with respect to the requirements of 10 CFR 50.73 and the guidanc~ provided in NUREG 102 The following LERs were reviewed:
Unit 1 and 2 Monthly Operating Reports - April, 1989 Unit 1 LER 89-018; Solid State Protection System Cabinet Connections Unsatisfactory Due to Inadequate Initial Fabricatio This event is detailed in Section 2.2.3 b of this repor Unit 2 LER 89-004; Engineered Safety Feature Actuation - Containment Ventilation Isolation due to System Design/Equipment Contern This event is detailed in Section 7.2.b of this repor Unit 2 LER 89-005; Reactor. Trip/Safety Injection* From 100% Power due to an Equipment Failur This event was detailed tn NRC In~pection Report 50-311/89-0 Unit 2 LER 89-006; Reactor Trip Signal After R2quired Shutdown - TS Acti0n Statement 3.7.7.b. This event was detailed in NRC Inspection Report 50-311/89-0 Unit 2 LER 89-008; Reactor Trip from 100% Power due to an Equipment Failur This event was detailed in NRC Inspecti0n Report 50-311/89-0.2 Reference to Open Items The following open items from previous inspections were followed up during this inspection and are tabulated below for cross reference purpose Closed Closed Closed Closed Closed UNR 272/87-32-01 UNR 272/87-05-01 UNR 311/87-05-01 VIO 272/87-02-02 VIO 272/87-02-03
- Section Section Section Section Section. 1 EXIT INTERVIEW (30702, 30703)
The inspectors met with Mr. L. Miller and other PSE&G personne 1 periodically and at the end of the inspection report period to summarize the scope and findings of their inspection activitie On May 15, a meeting was held between the NRC and the licensee in the NRC
~egion I office to discuss recurrent problems associated with the Unit 1
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and 2 main steam flow indication The licensee outlined the history of problems with main steam flow instrumentation, and discussed short term and long term corrective actions taken or planne The NRC will continue to monitor the corrective actions taken and their effect on the reliability of the main steam flow indications, as they affect reactor protection system and engineered safety features performanc Meeting attendees are listed in Attachment 1 and a meeting outline is included as Attachment Based on Region I review and discussions with PSE&G, it was.determined that this report does not contain information subject to 10 CFR 2 restriction... *-*~-¢*~~-~-=-
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ATTACHMENT 1 LIST OF ATTENDEES - PUBLIC SERVICE ELECTRIC AND GAS MEETING Main Steam Flow Indication May 15, 1989 Nuclear Regulatory Commission P. Swetland, 'Chief, Reactor Projects Section 28, Division of Reactor Projects (DRP)
M. Conner, Project Engineer, Technical Support Section, DRP C. Anderson, Chief, Plant Systems Section, Division of Reactor Safety (DRS)
L. Cheung, Senior Reactor Engineer, Plant Systems Section, DRS K. Gibson, Senior Resident Inspector Public Service Electric and Gas Company P. White, Technical Manager - Salem Operations J. Gueller, Operations Manager - Salem Operations L. Miller, General Manager - Salem Operations F. Thomson, Supervisor - Nuclear Licensing L. Griffis, I&C System Engineer D. Lyons, Technical Engineer - I&C C. Williamson, Senior Staff Engineer G. Roggio, Station Licensing Engineer - Salem D. Martrano, Senior Staff Engineer R. Heaton, System Engineer
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ATTACHMENT 2
- -AGENDA
- NRC PRESENTATION STEAM FLOW MEASUREMENT MAY 15, 1989
- INTRODUCTION * -
L.K. MILLER
- HISTORY AND ACTIONS L.C. GRIFFIS SALEM - UNIT 1
- LEA 50-311/89-007 D.W. LYONS
. SALEM - UNIT 2
OPERATOR ACTIONS J.C. GUELLER
- CONCLUSIONS AND L.K. MILLER SUMMARY (1)
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STEAM. FLOW CONCERNS SALEM UNIT 1 LEE C. GRIFFIS-SYSTEM ENGINEER - l&C SYSTEMS
STATEMENT OF PROBLEM AND CONCERNS
DESCRIPTION OF MEASURING SYSTEM AND CALIBRATION TECHNIQUE
INFORMATION RECEIVED FROM INDUSTRY AND VENDOR CONTACTS
ACTIONS TAKEN, THE RESULTS AND ANALYSIS -
OF THE -RESULTS
SAFETY SIGNIFICANCE
SHORT TERM ACTIONS TO MINIMIZE RECURRENCE OF TECH SPEC ACTION STATEMENT ENTRIES
LONG TERM ACTIONS TO RESOLVE STEAM FLOW MEASUREMENT CONCERNS
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SUMMARY (2)
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PROBLEM STATEMENT
PRIOR TO THE 7TH REFUELING OUTAGE STEAM FLOW INDICATION REMAINED CONSTANT AT 100% POWER USUALLY REQUIRING SENSOR CALIBRATION ONCE DURING A CYCLE
FOLLOWING THE 7TH REFUELING OUTAGE (3/4/88) INDICATED STEAM FLOW BEGAN TO INCREASE WITH NO INCREASE IN TURBINE POWER OR FEED FLOW
AFTER START UP FOLLOWING A REACTOR SHUTDOWN THE INDICATED STEAM FLOW IS LOW REQUIRING SENSOR RECALIBRATION
AFTER RECALIBRATION STEAM FLOW BEGINS TO TREND UP AGAIN REQUIRING ADDITIONAL SENSOR CALIBRATIONS
INDICATED STEAM FLOW STOPS INCREASING AND APPEARS TO LEVEL OFF AFTER ABOUT TWO -
MONTHS (3)
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FLOW MEASUREMENT SALEM DESIGN LOW DIFFERENTIAL PRESSURE BASICALLY A FLOW RESTRICTOR LOW SIGNAL TO NOISE RATIO CALIBRATE BY SETTING 100% FLOW TO MEASURED VALUE HAVE RECALIBRATED THE SYSTEM APPROXIMATELY
. ONCE PER CYCLE PRIOR TO CYCLE 8 (4)
120 INCHES TO 140 INCHES OF WATER AT 100% POWER FLOW
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CHANNEL 1
- CHANNEL 2 u INDICATES PLANT TRIP
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INDUSTRY EXPERIENCE CONTACTS:
ISSUED NETWORK QUERY TO ALL UTILITIES THE FOLLOWING PLANTS RESPONDED:
BEAVER VALLEY DAVIS BESSE DIABLO CANYON KEWAUNEE MILLSTONE 3 PRAIRIE ISLAND H.B. ROBINSON SAN ONOFRE SEABROOK YANKEE
ALSO, SPOKE WITH THE FOLLOWING:
SEQUOYAH TROJAN NORTH ANNA ZION RESULTS:
MOST PLANTS USE CALIBRATION TECHNIQUE SIMILAR TO SALEM'S
TWO PLANTS STATED THEY HAD EXPERIENCED DRIFTING PROBLEMS. ONE HAS EVEN HAD TO REPLACE TRANSMITTERS DUE TO THE AMOUNT OF DRIFT. NEITHER HAS EXPERIENCED THE *RESET" AFTER A TRIP
MOST PLANTS HAVE STEAM FLOW MEASURING INSTRUMENTATION WHICH RESULTS IN LOW DELTA P's SIMILAR TO SALEM'S SYSTE *
ONE PLANT HAS A CENTER TAPPED VENTURI. THEY HAVE A LARGE DELTA *
INSTRUMENT TUBE AND TRANSMITTER
_PROBLEMS HAVE OCCURRED BUT NOT _WITH
_ (G) ___ **-----~~:*:=:-~;_
-SAME SYMPTOMS.AS AT SALEM r
- VENDOR CONTACTS WESTINGHOUSE
BASED ON REVIEW OF OUR INFORMATION THEY OFFERED THE FOLLOWING POTENTIAL CAUSES:
- FOULING OF INSTRUMENT LINES
- FOULING OF VENTURI
- CHANGE IN VENTURI GEOMETRY
EXPLAINED THE MAIN PURPOSE OF THE VENTURI MS A FLOW RESTRICTOR NOT A FLOW MEASURING DEVIC BIF, THE VENTURI MANUFACTURER
THE MANUFACTURER OFFERED THESE CAUSES:
-IMPROPER TAPPING OF VENTURI COUPLED WITH CONTAMINATION OF VENTURI OR INSTRUMENT TUBING
- CHANGE IN VENTURI GEOMETRY
THEY HAVE NOT SEEN SIMILAR OCCURRENCES ROSEMOUNT
THEY WERE NOT AWARE OF ANY FAILURE MODE OF TRANSMITTERS WHICH WOULD GIVE Ti-IE OBSERVED SYMPTOMS (7)
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ACTIONS TAKEN AND THE RESULTS ACTION
- As FOUND* DATA COLLECTION TO MONITOR TRANSMITTER DRIFT CHECKED STEAM FLOW DIFFERENTIAL PRESSURE WITH TEST TRANSMITTER TRENDED DIFFERENTIAL PRESSURES BLED.DOWN AND REFILLED INSTRUMENT LINES TO CHECK FOR BLOCKAGE INSPECTED NOZZLE AND TAPS WITH BOROSCOPE MODIFIED OPERATOR'S LOG SHEETS (8)
RESULT TRANSMITTERS CONSISTENTLY REMAIN WITHIN CALIBRATION REQUIREMENTS TEST TRANSMITTER READ SAME VALUE AS.
INSTALLED INSTRUMENT BOTH CHANNELS ON EACH STEAM GENERATOR HAVE SAME DIFFERENTIAL PRESSURE SHIFTS INSTRUMENT RETURNED TO SAME READING AS BEFORE (NO BLOCKAGE)
APPEARED CLEAN; NO WEAR OR FOULING SEEN INCREASED AWARENESS OF SITUATION & SYMPTOMS
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ANALYSIS OF
.ACTIONS TAKEN CONCLUSION THE ELECTRONIC INSTRUMENTS DO NOT
. APPEAR TO BE THE CAUSE INSTRUMENT TUBING DOES NOT APPEAR TO BE THE CAUSE FOULING -OR WEARING OF THE VENTURI AND/OR TAPS DOES NOT APPEAR TO BE THE CAUSE (9)
BASIS AS FOUND DATA DOES NOT SHOW DRIFTING TEST TRANSMITTER HAD SAME READING TRENDS ARE THE SAME ON BOTH CHANNELS. FOULING WOULD NOT BE IDENTICAL BOTH CHANNELS BLEEDING AND REFILLING DID NOT AFFECT READING INSPECTION DID NOT REVEAL FOULING OR WEAR
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- SAFETY SIGNIFICANCE
THE PAA ANALYSIS FOR SALEM STATION ASSUMED ALL STEAM FLOW TRIPS HAVE FAILED. A CHANGE IN STEAM FLOW FAILURE RATE WOULD NOT AFFECT THE PAA RESULT OUR PAA PREDICTS A CORE DAMAGE RATE COMPARABLE TO OTHER PLANT *
THE SALEM FUELS GROUP HAS PERFORMED A SAFETY ANALYSIS OF FUEL DAMAGE WITH
. HAVING THE STEAM FLOW CHANNELS CALIBRATED 50/o LOW (NON-CONSERVATIVE) DURING A MAJOR STEAM LINE BREAK. THE ANALYSIS SHOWED NO AFFECT ON THE FUE (10)
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- SHORT TERM ACTIONS
SET CONSERVATIVE CALIBRATION PRIOR TO START UP AFTER REFUELIN *
SLOWDOWN STEAM FLOW INSTRUMENT LINES DURING -START U *
TAKE STEAM FLOW DATA AT SEVERAL POWER PLATEAUS DURING POWER ASCENSIO *
PERFORM ENGINEERING STUDY (BY CONSULTANT)TO DETERMINE ROOT CAUS *
TAKE WEEKLY STEAM FLOW DATA TO MONITOR CHANGES AND TREND *
ENSURE A CONSERVATIVE CALIBRATION AFTER A SHUTDOW *
DETERMINE IF EXAMINATION OF THE REFERENCE LEGS WHILE AT POWER TO ENSURE THEY REMAIN FULL IS POSSIBL *
REVIEW FSAR AND DESIGN BASIS DOCUMENTS TO DETERMINE IF OUR CHANNEL CHECK CRITERIA IS TOO RESTRICTIV (11)
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LONG TE*RM ACTIONS
INVESTIGATE REPLACEMENT OF THE EXISTING STEAM FLOW MEASUREMENT SYSTEM WITH A,
CENTER TAPPED VENTURI SYSTE *
INVESTIGATE ENGINEERING CHANGES SUCH AS ADDITION OF A FOURTH LEVEL CHANNEL, MEDIAN SELECTOR LOGIC FOR STEAM GENERATOR LEVEL, OR ADVANCED DIGITAL
'FEEDWATER CONTROL TO ELIMINATE NEED FOR STEAM FLOW/ FEED FLOW MISMATCH TRI *
INVESTIGATE ELIMINATION OF HIGH STEAM LINE FLOW SAFETY INJECTION SIGNAL BY USING RATE OF CHANGE OF STEAM PRESSURE IN PLACE OF HIGH STEAM FLOW TRIP
INVESTIGATE WOG SAFETY.INJECTION ELIMINATION STUDY RECOMMENDATION (12)
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SALEM UNIT 1 STEAM FLOW SUMMARY
OUR MEASURING SYSTEM AND CALIBRATION -
TECHNIQUES ARE SIMILAR TO MOST WESTINGHOUSE PLANTS
THE SHORT TERM ACTIONS WILL MINIMIZE RECURRENCE OF ENTRY INTO TECH SPEC ACTION STATEMENTS
WE ARE CONTINUING TO INVESTIGATE TO DETERMINE THE ROOT CAUSE
THERE IS NO SAFETY SIGNIFICANCE
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(13)
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STEAM FLOW EVENT SALEM UNIT TWO DAVID W. LYONS TECHNICAL ENGINEER - l&C SYSTEMS
STEAM FLOW DRIFT IS BEING MONITORED ON UNIT TWO, THUS FAR IT SHOWS NONE OF THE -
INDICATIONS OF DRIFT OBSERVED ON UNIT ONE..
LER 50-311/89-007
THREE STEAM FLOW CHANNELS WERE READING HIGH (ONLY TWO WERE OUT OF TECH SPEC LIMITS) RECALIBRATION WAS INITIATED ON THESE THREE CHANNEL *
UNIT W&.S SUBSEQUENTLY SHUTDOWN FOR AN UNRELATED PROBLE *
DURING THE SHUTDOWN THE DELTA T LOOPS WERE RECALIBRATED BASED ON NEW STATEPOINT DAT *
UPON RETURNING TO POWER OPERATIONS, THE THREE STEAM FLOW CHANNELS THAT. WERE RECALIBRATED DID NOT MEET THE 3% CHANNEL CHECK CRITERI *
T.S.A.S. 3.0.3 WA.S ENTERED AT THIS TIM THIS VAS A VERY CONSERVATIVE APPLICATION. THE PROVISIONS OF T.S..0.4 COULD HAVE BEEN USED TO ALLOW RECALIBRATION OF THE STEAM FLOW CHANNELS AT THE FIRST STEADY STATE CONDITION. RECALIBRATION OF DELTA T LOOPS AFFECTS STEAM FLOW CHANNEL CALIBRATIONS. THE STEAM FLOW CHANNELS CAN ONLY BE RECALIBRATED AT POWE *
THE THREE CHANNELS WERE RECALIBRATED AND THE ACTION STATEMENT WAS EXITED
ON APRIL 6, 1989 WITH THE UNIT AT STEADY STATE OPERATION, STEAM FLOW DATA WAS OBTAINED FOR ALL CHANNEL. _(14)
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SAL'EM UNIT TWO STEAM. FLOW SUMMARY
- UNIT TWO DOES NOT HAVE ANY OF THE SAME SYMPTOMS AS UNIT ONE
THE UNIT TWO EVENT WAS CAUSED BY RECALIBRATION OF DELTA T LOOPS AND A CONSERVATIVE ENTRY INTO T.S.A.S. 3. *
BETTER COMMUNICATION ABOUT ACTIONS BEING PERFORMED WHICH MAY AFFECT CALIBRATIONS AND TRAINING ON APPLICATION OF T.S.A.S 3.0.4 SHOULD PREVENT RECURRENCE.
OF THIS TYPE OF EVENT (15)
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OPERATIONS JAMES GUELLER 1)
Operator Monitoring 2)
Operator Training (1)
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PARAMETERS MONITORED
- . 11-14 SG STMIFW FLOW CHANNEL CHECK
11-14 SG STM FLOW CHANNEL CHECK
11-14 SG STM FLOW /POWER LEVEL CHANNEL CHECK (2)
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CONTROL CONSOLE READING.
PARAMETERS MAL..
11-14 SG STMIFW FLOW CHANNEL 6/4 CHECK
. Either Stm Flow Channel shall be within MAX limit o either Feed Flow Channel, if not, contact System Engineering for corrective. actio T /S 3.3. 1. 1 applies for the following:
0-16'1 Reactor Power
16 - 100'1 Reactor PoMer
MANAGEMENT ACTION LEVELS (MAL) PRIOR TO THE ACTION STATEMENT LEVELS B_EAOING_S_ARE TAKEN_QNCE_PER EIGHI HOURS (3)
TIS
%
8/5
5
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- CONTROL CONSOLE READING PARAMETERS 11-14 SG STM CHANNEL CHECK (8 Channels) highest to lowest between any two channels READINGS ARE TAKE_N ONCE PER EIGHT l:IOUR_S (4)
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CONTROL CONSOLE READING PARAMETERS MAL T/S
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. N/ A CHANNEL CHECK
- At 100% Reactor PoYt49r check all eight STM FLOW CHANNELS to power, if any channels are greater than 103% or leaa than
.
98.6% CONTACT System Engineering IMMEDIATELY READINGS ARE TAKEN ONCE PER EIGHT HOU SS (6)
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INCREASED OPERATOR AWARENESS AND RESPONSE By;
- Operations Management discussions with Shift Personnel.
- Shift Supervisor discussions with Nuclear Control Operators
- Revised Reactor Operator Console Logs
- Monitoring of Steam Flow Indications and Trends by Station Management -/
System Engineering (6)
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CONTINUING TRAINING
- Pre - Startup Simulator Training on Steam. Flow Sensitivity & Control
- Steam Flow Instrumentation & Control will be reviewed during the first requalification segmen * Training is scheduled to include
_ coverage of LER's on Steam Flow Problems.. in the Industry Events portion of * Licensed Operator
- Requalificatio (7)
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j CONCLUSIONS OPERATOR AWARENESS INCREASED QUICKENED OPERATOR IDENTIFICATION OF STEAM FLOW TRENDS MANAGEMENT ACTION LEVELS (8)
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SALEM STEAM FLOW SUMMARY
OUR SHORT TERM ACTIONS ON UNIT ONE WILL MINIMIZE ENTRY INTO TECH SPEC ACTION STATEMENTS FOR STEAM FLOW PROBLEMS
WE ARE CONTINUING TO INVESTIGATE TO DETERMINE THE ROOT CAUSE OF THE UNIT ONE STEAM FLOW CONCERNS
THERE IS NO IDENTIFIED SAFETY SIGNIFICANCE OF HAVING THE STEAM FLOW CHANNELS SLIGHTLY NON-CONSERVATIVE
THE EVENT ON UNIT TWO IS UNRELATED TO UNIT ONE CONCERNS
OUR OPERATORS HAVE A HEIGHTENED.
AWARENESS OF THESE ISSUES (LAST)
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