IR 05000272/1990013
| ML18095A334 | |
| Person / Time | |
|---|---|
| Site: | Salem, Hope Creek  |
| Issue date: | 06/28/1990 |
| From: | Swetland P NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I) |
| To: | |
| Shared Package | |
| ML18095A332 | List: |
| References | |
| 50-272-90-13, 50-311-90-13, 50-354-90-10, NUDOCS 9007100152 | |
| Download: ML18095A334 (77) | |
Text
I 'l Report No License No Licensee:
Facilities:
Dates:
Inspectors:
U. S. NUCLEAR REGULATORY COMMISSION
REGION I
50-272/90-13 50-311/90-13 50-354/90-10 DPR-70 DPR-75 NPF-57 Public Service Electric and Gas Company P. 0. Box 236 Hancocks Bridge, New Jersey 08038 Salem Nuclear Generating Station Hope Creek Nuclear Generating Station May 1, 1990 - June 18, 1990 Thomas P. Johnson, Senior Resident Inspector David K. Allsopp, Resident Inspector Stephen M. Pindale, Resident Inspector Stephen T. Barr, Resident Inspector Paul D. Kaufman, Project Engineer Glenn M. Tracy, Reactor Engineer Leonard S. Cheung, Senior Reactor Engineer Ronald L. Nimitz, Senior Radiation Specialist Herbert J. Kaplan! Senior Rea~tor Engineer
'b, ro/zg/9CJ 2A lbatf!
on May 1, 1990 -
Areas Inspected:
Resident safety inspection of the following areas:
operations, radiological controls, maintenance & surveillance testing, emergency preparedness, security, engineering/technical support, safety assessment/quality verification, and licensee event reports and open item foll owu PDR ADOCK 05000272 G!
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Results:
The inspectors identified five non-cited violations for Salem concerning, the failure to obtain a hot work permit during maintenance activities (4.3.1.D), the failure to adequately test a portion of the containment spray system automatic start logic (9.1), the failure to reduce containment radiation monitor setpoints (9.1), an unmonitored containment vent evolution due to personnel error (9.1) and the failure to make a timely event notification (2.2.1.C).
The inspectors identified one non-cited violation for Hope Creek concerning the miscalibration of a reactor building exhaust radiation monitor (4.3.2.0).
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SUMMARY Salem Inspection Reports 50-272/90-13; 50-311/90-13 Hope Creek Inspection Report 50-354/90-10 May 1, 1990 - June 18, 1990 Operations (Modules 71707, 71710, 71711, 60710, 93702)
Salem:
Operators adequately responded to events. initiated during maintenance and surveillance activitie One late ENS call was mad Unit 1 restart activities, and Unit 2 core reload and midloop activities were observe Licensee followup to the Vogtle loss of power event was aggressiv The Unit 1 safety injection system was adequately aligne Hope Creek:
Operators adequately responded to two events caused by spurious equipment starts and trip The high pressure coolant injection (HPCI) system was adequately aligne An allegation regarding a HPCI overpressurization event during 1986 was reviewe Radiological Controls (Modules 71707, 93702)
Salem:
The inspector reviewed licensee corrective actions for a contaminated person who was allowed to leave the sit An unmonitored containment venting was a non-cited violatio Failure to reset a containment radiation monitor during refueling was also a non-cited violatio Hope Creek:
The licensee has been aggressive in decontaminating the reactor core isolation cooling and high pressure coolant injection (HPCI) room Controls during HPCI testing were considered to be conservativ Maintenance/Surveillance (Modules 61726, 62703, 73756, 92702)
Salem:
The licensee responded adequately to a diesel generator turbocharger failur Failure to follow a hot work permit was a non-cited violatio Failure to adequately test the containment spray logic was also a non-cited violatio Hope Creek:
Failure to remove surveillance test equipment was considered a weaknes Numerous maintenance team open items were close Miscalibration of a radiation monitor was a non-cited violatio Emergency Preparedness (Module 71707)
The design of power supplies for the Salem ENS phone was unresolve *..
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Executive Summary-2-Security (Module 71707, 93702)
Although licensee response to a loss of security system coordination and communication between Salem operations was weak and resulted in this power los~. The licensee to NRC concerns associated with an unattended vehicl promptly to a fitness for duty even Engineering/Technical Support (Modules 71707)
power was timely, and security personnel adequately responded The licensee responded Salem:
A charging pump repair using Belzona was unresolve The licensee 1 s response to discrepant flow measurement devices was initially too narrowly focuse A metallurgical evaluation for a boron injection tank leak was satisfactor Licensee fo 11 owup to a reactor trip breaker bypass breaker failure was timely and effectiv System engineer performance was noted as being effective during a lighting transformer failur Hope Creek:
A metallurgical evaluation for a recirculation instrument line was satisfactor Safety Assessment/Assurance of Quality (Modules 30702, 30703, 40500, 71707, 90712, 90713, 92700)
Salem:
Incomplete and ineffective actions to resolve continuing surveillance implementation weaknesses were note Unit 2 refueling activities were effectively performe Emergency core cooling system operability demonstration was noted as being aggressive and thorough; however, the initial response to the Westinghouse letter and the completeness of the review of flow measurement devices were wea Hope Creek:
Management was noted as being aggressively involved in day-to-day Hope Creek activities.
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DETAILS SUMMARY OF OPERATIONS 1.1 Salem Unit 1 Salem Unit 1 began the report period shutdown to repair emergency core cooling pump The unit remained shutdown throughout the inspection period until the reactor was made critical on June 6, 1990 and operated at 100% power until the end of the inspection perio.2 Salem Unit 2.4 Salem Unit 2 began the report period shutdown in a refueling outage with all fuel remove The core was reloaded on May 13, 199 The unit remained shutdown throughout the inspection perio At the end of the inspection period the unit was in Mode 3 (hot standby)
preparing for startu Hope Creek The Hope Creek unit began the report period at 100% power and remained operational throughout the perio Scheduled load reductions occurred on May 13, 1990 for turbine control valve tests, on May 19, 1990 for 11 C 11 secondary condensate pump preventive maintenance and on June 2, 1990 for control rod redistribution needed for flux shapin Power was also reduced on June 13, 1990 when the 11N 1 main condenser south water box was isolated due to a suspected tube leak indicated by a higher than normal conductivity reading in the 11A 11 condenser hotwel Repairs were made, and the plant returned to full power by the end of the report perio Common NRC Chairman K. Carr visited both the Hope Creek and Salem stations on May 22, 199 NRC Commissioner J. Curtiss and Regional Administrator T. Martin visited the Salem station on June 18, 199.
OPERATIONS
.. **-.* Inspection Activities The inspectors verified that the facilities were operated safely and in conformance with regulatory requirement Public Service Electric and Gas (PSE&G) Company management control was evaluated by direct observation of activities, tours of the facilities, interviews and discussions with personnel, independent verification of safety system status and Technical Specification Limiting.
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Conditions for Operation, and review of facility record These inspection activities were conducted in accordance with NRC inspection procedures 60710, 71707, 71711 and 9370 The inspectors performed normal and back shift inspection, including deep backshift inspection as follows:
Unit Salem Salem Inspection Hours 3:00 a.m. - 5:00 :00 p.m. - 5:00 Oates June 5, 1990 June 5-6, 1990 Inspection Findings and Significant Plant Events 2. Salem Unit 2 Safety Injection Actuation on May 1, 1990 With the reactor defueled, an inadvertent Unit 2 safety injection (SI) actuation occurred at 11:03 a.m. on May 1, 199 Maintenance I&C modification work, design change package (DCP)
2EC-2272, associated with the sequence of events recorder in the solid state protection system (SSPS) panels was in progres Available equipment started and associated valves realigne The equipment which started included the 2A, 28, and 2C diesel generators, the 21 auxiliary feed water pump, the 24 service water pump, the 24 containment fan cooler unit, two emergency air compressors, and the 22 auxiliary building ventilation fa The licensee's review of the event determined that the I&C technician used the incorrect SSPS print (train A in lieu of train B) during the modification rewirin This caused the shorting of the manual SI initiation circuitry which caused the SI logic to actuat With the circuitry shorted, the SI signal could not be rese The licensee had to de-energize the safeguards equipment cabinet in order to stop the equipment that auto starte No emergency core cooling system injection occurre Once the equipment was stopped, a deficiency report was initiated, the licensee corrected the wiring error, reset the signal, reviewed the circumstances of the error, and initiated corrective action Corrective actions included reviewing the event with all maintenance personnel, holding.
personnel involved in the event accountable, and reviewing the adequacy of the OCP instruction The inspector observed post event response to the SI signal in the control roo The inspector also observed portions of the troubleshooting and fact finding activities performed by the maintenance I&C enginee The licensee's incident report and Licensee Event Report (LER) 90-17 were reviewe The inspector
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concluded that the licensee's root cause analysis and followup activities were adequat Unit 2 Lighting Transformer Failure At 3:34 a.m. on May 11, 1990, a Unit 2 lighting transformer failed due to an apparent internal fault on one of the phase The resulting electrical transient caused the 4 KV group bus 2H (non-safety related) feeder breaker to the transformer to trip on instantaneous overcurren Because of the electrical configuration with both units shutdown, this transient caused an electrical spike on all the Unit 2 busses which resulted in an inadvertent actuation of the r'adiation monitoring syste A resultant containment ventilation isolation occurred. -Also the ENS phone was lost as were other licensee telephone system (See Section 6.2.A).
The licensee reset the containment isolation and restored the ENS phon Repairs were performed on the lighting transforme The licensee also initiated Unit 2 LER 90-018 regarding this even The 2HL lighting transformer failure had been attributed to age degradation of a high voltage winding, resulting in high phase to phase current Engineering is continuing to review the failure mechanis The inspector examined the failed transformer in the field and reviewed the licensee's incident report and LE The inspector noted that system engineering was present in the field to followup on the even The inspector questioned the system engineers and determined them to be knowledgeable and effective in directing f4eld related activitie The inspector had no further questions at this tim Unit 2 Vital Bus Trip At 6:22 p.m. on May 16, 1990, the electrical feeds to the Unit 2 4KV vital bus 11 2A 11 tripped open due to an apparent personnel error by a maintenance electrician during a safeguards equipment cabinet (SEC) 18 month surveillanc During setup for the testing on the 11 2A 11 SEC, the electrician erroneously landed the leads for his 11 Visicorder 11 test equipment at the wrong points..
When the test was performed, the SEC actuated causing the electrical feeds to the 11 2A 11 4 KV vital bus to ope No required safety loads were lost when this vital bus was de-energize The 2A diesel generator did not start because it was out of service for maintenanc All systems were restored to normal by 7:00 p.m. on May 16, 199 A late 4 hour4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> non-emergency report of an ESF actuation was made at noon on May 17, 199 *.*
The reason for the late report was that the on-shift personnel considered the event to be initially non-reportabl However, upon further review by management the next day it was concluded that the breaker actuation was an ESF actuatio This licensee identified violation is not being cited because the criteria specified in section V.G of the Enforcement Policy were satisfie (NON 50-311/90-13-04)
The inspector reviewed the event and discussed it with licensee personne The inspector had no further questions at this tim The LER will be reviewed in a future inspectio Licensee Followup to the Vogtle Loss of Power Event With Unit 1 in a forced outage and Unit 2 in a refueling outage, the licensee performed maintenance in the Salem switchyar The licensee had been informed of the Vogtle loss of power event caused by switchyard activitie The licensee conducted a review of their planned work activities associated with power source The licensee conducted safety meetings to communicate to aJl personnel the details of the Vogtle event and to raise awareness of electrical power configurations during outage period Longer term actions include the development of a program for the control of work in the switchyar The licensee also reviewed Technical Specifications (TSs)
associated with AC power sources (onsite and offsite).
During Modes 5 and 6, the redundancy for AC power 1s not require The TSs allow one of two offsite sources and one of three diesels to be out of servic The licensee stressed the importance of minimizing the number of vehicles in the switchyard, of maintaining attention to detail when working, of following established procedures, and of maintaining proper work standard The inspector discussed this item with licensee outage management personne The inspector toured the Salem switchyard and observed work in progres No abnormal activities were note On May 4, 1990, the inspector reviewed out of service equipment for both unit One of the two station power transformers, and one of three Unit 2 diesel generators were out of service for maintenanc The inspector concluded that the licensee was aggressive in ensuring personnel were informed of the Vogtle loss of AC power even Licensee actions associated with continuity of AC power appeared to be adequate during this outage perio Unit 2 Midloop Operation On May 23, 1990, in order to perform reactor coolant pump maintenance and to recover the steam generators, Salem Unit 2 entered midloop operation In midloop operations, the reactor coolant level is lowered to the midpoint of the reactor vesse hot and cold leg nozzle In this state of reduced inventory, additional instrumentation and monitoring of reactor water level is required to ensure proper core coverage and coolin Licensee procedures require thermocouples to be used to monitor core exit temperatures and intermediate leg loop flow differential pressure cells be used to measure water leve Vessel water lev~l is also measured visually by use of transparent tubing connected to an intermediate leg loop drai Temperature and level alarm set points are adjusted to provide early indication of a loss of cooling or a decrease in ~oolant inventor Additional monitoring and logging of these parameters is required as wel Shortly after the reactor vessel water level had been established at the midloop point, the inspector tour~d the plant in order to review the licensee's control The inspector determined that the required instrumentation* had been installed and all monitored parameters were indicating in the safe rang Through discussions with the control room operators, the inspector found the operators knowledgeable of present plant conditions, the indications available to them, and of the procedures to be followed if core cooling were to be los The inspector also reviewed the control room logs and found them to be complete and satisfactor Based on this tour, the inspector concluded that midloop operations had been reached and maintained in a safe and proper manne Unit 2 Fuel Load The Salem Unit 2 reactor core reload began on May 10 and was completed on May 13, 199 The inspector verified that reactor operators and senior reactor operators were knowledgeable of refueling activities. Activities were observed from the refueling bridge and spent fuel are Contractor personnel conducting core offload activities were also interviewe The bundle pull sheets were checked and the core status board was verified to be accurat Appropriate refueling procedures and Technical Specifications were also reviewe No unacceptable conditions were note The inspector concluded that fuel load activities were being effectively controlle *
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6 Unit 1 Main Steam Line (MSL) Isolation On June 3, 1990 at 7:12 a.m. during reactor heatup with the residual heat removal (RHR) system in service in Mode 4, Unit 1 received a MSL isolation signal due to spurious high steam flow signal The bistables associated with one high steam flow channel for each of two (of four) steam generators (nos. 11 and 12) actuated spuriousl The actuations occurred approxi-mately 30 minutes apar The isolation logic was satisfied when two high steam flow channels associated with the two steam generators tripped with reactor coolant average temperature less than 543 degrees F and steam pressure less than 600 ps Actuation of the second high steam flow channel satisfied the MSL isolation coincidence logi The main steam isolation valves (MSIVs) and bypass MSIVs were closed prior to the actuatio MSL drain valves (MS-7 valves) were open and went closed as_
expecte The licensee's investigation postulated that the MSL isolation signals were due to uneven heatup of the steam flow sensing lines which occu.rred during reactor heatu The MSL isolation signals were reset and the MS-7 valves opene The unit continued reactor heatup into Mode The licensee intends to submit an LER for this event.
The inspector reviewed the event and discussed it with licensee personne The inspector had no further questions and will review the LER when it is submitte Unit 1 Restart Concerns Resolved Unit 1 restart issues were discussed at a management meeting on May 2, 1990 (see section 10.3 of this report).
Also, periodic status and update meetings and discussions were held between the inspector and licensee management personne Resolution of safety injection and charging pump problems and flow measurement errors are discussed in sections 8.1.B and 7.1.C, respectivel On June 4, 1990, a conference call with PSE&G, Region I Manage-ment, the resident inspector, and the Office of Nuclear Reactor Regulation was conducted to resolve other Unit 1 restart concern The residual heat removal (RHR) pump operability curves were reviewed after the curves had been adjusted to account for the pressure drop across the discharge check valv The RHR pump deadhead test results were evaluated which indicated a dead-heading problem did not presently exist even during the worst case frequency fluctuation which would exist if the RHR pumps were being powered from the emergency diesel generator PSE&G 1s confidence in the accuracy of their flow measuring devices was
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2. discussed including PSE&G's walkdowns of certain service water systems to ensure orifices were correctly installe PSE&G's engineering evaluation concerning the use of teflon tape in the containment was reviewe In May 1985 PSE&G's engineering group after evaluating the use of teflon tape issued a field directive to implement the use of nuclear grade Grafoil thread sealant tape in lieu of teflon tap Based on the Integrated Performance Assessment Team findings it appears that teflon tape is still being utilized in the containmen Although a technical justification may exist for the teflon tape currently in place, the continued use of this tape indicates implementation weaknesses with this field directive~ The inspectors had no further questions and concluded the cal Unit 1 Restart Activities Unit 1 restarted on June 6, 1990, after a forced outage that occurred on April 9, 199 The inspector reviewed licensee preparations for restart including resolution of restart open items and technical issue The inspectors observed the mode changes, the reactor and plant startup, and related testing activities from the control roo No unacceptable conditions were noted.
Hope Creek Filter Recirculation and Ventilation System (FRVS) Fan Start At 5:00 p.m. on May 12, 1990, the *reactor operator noted that the reactor building FRVS fari 11 E 11 was operating for no apparent reaso The fan was secured and an investigation was conducted to determine why the fan was operatin An ENS call was mad The FRVS fans auto start on accident signals and the "E" and
"F 11 fans additionally start when a non-accident low flow signal is sensed for fans "A" through "D".
As stated in LER 90-006, the licensee concluded that the root cause could not be determine A similar event occurred in 1987 (LER 87-033).
The licensee committed to initiate a system engineering review of the low flow switches and to update this LER by October 31, 199 The inspector discussed the event with operators and engineers, and reviewed the LER and associated incident repor The inspector had no further questions at this tim. ',
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8 Reactor Water Cleanup (RWCU) Isolation and Reactor Protection System (RPS) Half Scram At 1:53 p.m. on May 17, 1990, a RWCU system inboard isolation and half scram were received due to loss of power on the 11A
RPS bu The 11A 11 RPS motor generator set electrical protection assembly (EPA) breakers tripped for an unknown reason causing a loss of power to 11A 11 RPS bu All systems functioned as require Power was restored to 11A 11 RPS from the alternate sourc The RWCU system was restored and the half scram rese The licensee initiated a review of the event. and submitted LER 90-00 They concluded that the exact cause of the EPA breaker trip could not be determine However, the licensee determined that this spurious trip was similar to events described in GE SIL-496, dated February 199 The SIL discusses performance problems with the EPAs, including spurious trips, maintenance and calibration deficiencies, and inability to rese The licensee is pursuing a design change to replace the EPA logic card The inspector reviewed the event and the LE Discussions were held with operators, engineers and management personne The inspector had no further questions or concern.3 Engineered Safety Feature (ESF) System Walkdown 2. Inspection Activity 2.3.*2 The inspectors independently verified the operability of selected ESF systems by performing a walkdown of accessible portions of the system to confirm that system lineup procedures match plant drawings and the as-built configuratio The ESF system walkdown was also conducted to identify equipment conditions that might degrade performance, to determine that instrumentation is calibrated and functioning, and to verify that valves are properly positioned and locked as appropriat This inspection was conducted in accordance with NRC inspection procedure 7171 Inspection Findings Salem The inspectors performed an ESF walkdown inspection on the charging system and concluded the system was fully functional with minor housekeeping deficiencie The inspectors performed a system walkdown to evaluate the accuracy of plant drawings and
the accuracy of valve lineup The inspectors verified Technical Specification requirements and reviewed recent corrective maintenance for the syste The inspector concluded the system was fully operational, but did identify several minor housekeeping issues not previously identified by PSE& These include an unauthorized scaffold, a misaligned spring can, an invalid posted fire impairment, and several body to bonnet leak These items were promptly and appropriately addressed when brought to the attention of PSE& Hope Creek The inspectors performed an ESF walkdown of the accessible portions of the High Pressure Coolant Injection (HPCI) syste At the time of the inspection, the HPCI system was declared operable by the licensee in accordance with Hope Creek Technical Specification 3.5. During the course of the inspection, the inspector reviewed applicable HPCI piping and instrumentation diagrams, system operating procedures and system surveillance and inservice test procedures for accuracy and adequac No discrepancies were identifie In order to assess the operability of the HPCI system, the inspector toured the control room to examine the status of the control panels and the HPCI pump room in the reactor building to examine the material condition of the syste The inspector found no significant deficiencies in the system line-up or physical condition of the syste The inspector noted the positive steps PSE&G had recently taken to improve the material condition of the HPCI pump roo Historically this room has been a contaminated area, and HPCI components were not readily accessibl During the inspection period, the licensee decontaminated and cleared the room, and covered the floor with an epoxy paint, such that the entire room and its components are now accessibl In summary, the inspector concluded that
~he HPCI system was operable and able to perform its safety related functio On June 7, 1990, the maintenance contracted to perform the required analyses of HPCI turbine lube oil reported a high moisture content in the oi The Hope Creek operations crew on shift declared HPCI inoperable and entered the required Technical Specification Action Statemen An ENS call was mad Immediate steps were taken to drain the old oil, clean the oil reservoir and add new oil to the syste HPCI was declared operable again approximately 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> after the report of high moisture in the oil had been receive The inspector noted that the licensee took appropriate and timely action once informed of the oil*
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received by the inspector during this inspection perio The alleger stated that during initial startup testing of the HPCI system in 1986 the system had been overpressurized due to a design deficiency concerned with the premature start of the auxiliary oil pump during a manual start of the HPCI syste The alleger was concerned that action to correct the deficiency had never been implemente The inspector reviewed previous NRC inspection reports and licensee test data and determined that the overpressurization event had occurre In discussing the matter with the system engineer, however, th~ inspector learned that during the last Hope Creek refueling outage (November 1989)
Design Change 4HC-0256 had been implemented, correcting this deficienc The modification. prevents the auxiliary oil pump from starting until the turbine steam admission valve has lifted off its seat or 12 seconds after the pump start switch has been engage This delay guarantees that a steady supply of steam will be available at the inlet to the turbine control valve just before it starts to ope This will prevent a sudden rush of steam through the turbine, thus not overpressurizing the dis-charge pipin Through his review the inspector determined that the alleger's initial concern was substantiated, but that the licensee has since implemented appropriate corrective modifi-cation The inspector determined there was not an existing safety concern, and this allegation is close RADIOLOGICAL CONTROLS Inspection Activities PSE&G's conformance with the radiological protection program was verified on a periodic basi These inspection activities were conducted in accordance with NRC inspection procedures 71707 and 9370.2 Inspection Findings and Review of Events 3. Salem Personnel Contamination Event On May 2, 1990, a worker was allowed to leave the site with contamination on his shoe This event was reviewed in NRC specialist inspection 50-272/90-14; 50-311/90-1 The inspector reviewed the licensee's immediate corrective actions for this even These included:
confiscating the individual 1 s shoes, surveying his car and security areas, calculating the individual 1 s
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dose at approximately 50 mrem, counseling the technicians that performed the inadequate survey, and briefing security personne Additional planned actions include enhancements to the security and radiation protection interfaces and communication, and changes to the frisking procedur The inspector concluded _that these immediate actions were adequat Further followup will be performed by the r~diation protection specialist inspecto.
Unmonitored Liquid. Release At the morning meeting on May 21, 1990, the inspector learned of a Salem Unit 2 unmonitored liquid release of the 22 chemical and volume control system monitor tan The tank was released at 1:44 a.m. on May 21, 1990, with the radiation monitor 2R18 inadvertently isolate A sample had been taken prior to the releas The licensee concluded that a chemistry technician failed to follow the release procedur The inspector reviewed the incident report, chemistry and operations procedures, Technical Specifications and the sample result The inspector also discussed the event with licensee personne The inspector concluded that the immediate corrective actions were adequat This event was reviewed in detail in NRC Specialist Inspection 50-272/90-16; 50-311/90-16.
Hope Creek High Pressure Coolant Injection (HPCI) Room Controls During the HPCI test on May 23, 1990 (see sections 4.2, 4.3.2.A) the inspector reviewed the radiation work permit (RWP)
number 90-0H-42 During the test the HPCI room was declared a high radiation area with expected levels of 1-2 Rem per hou A radiation protection technician remained in the area during the test to control acces Radiation measurements taken during the test were 100 mrem per hour on contact with the steam pipin The licensee was determined to be conservative in their RWP and appropriate radiation controls were demonstrate.
Reactor Building Decontamination Efforts During the report period, the licensee has decontaminated and painted the reactor core isolation cooling and high pressure coolant injection room This effort has greatly improved the rooms* housekeeping and the ability to routinely inspect the equipment in the area.
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12 MAINTENANCE/SURVEILLANCE TESTING 4.1 Maintenance Inspection Activity The inspectors observed selected maintenance activities on safety-related equipment to ascertain that these activities were conducted in accordance with approved procedures, Technical Specifications, and appropriate industrial codes and standard These inspections were conducted in accordance with NRC inspection procedure 6270 Portions of the following activities were observed by the inspector:
Unit Salem 1 Salem 1 Salem 2 Salem 2 Salem 2 Hope Creek Work Request (WR)/Order (WO) or Procedure Description M6G 11 and 12 Charging pump WO 900523059 23 Charging pump repair WO 9005021006 WO 900106105 WO 891006114/M4C*
WO 900613092 Remove/install new turbocharger on 28 diesel generator Installation of sequence of events recorder 24 Containment fan cooler unit Condenser tube leak repairs The maintenance activities inspected were effective with respect to meeting the safety objectives of the maintenance progra.2 Surveillance Testing Inspection Activity The inspectors performed detailed technical procedure reviews, witnessed in-progress surveillance testing, and reviewed completed surveillance package The inspectors verified that the surveillance tests were performed in accordance with Technical Specifications, approved procedures, and NRC regulation These inspection activities were conducted in accordance with NRC inspection procedure 61726.
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The following surveillance tests were reviewed, with portions witnessed by the inspector:
Unit Procedure N Salem 2 2PD-2.7.041 Salem 1 PI/S-SJ-4 Salem 1 Sl.OP-ST.SJ-0013(Q)
Salem 2 SP(0)4.0.5-P-SJ(21)
Salem 2 SP(0)4.. 0. 5-P-SW( 21)
Hope Creek OP.IS.BJ-OOl(Q)
Hope Creek OP.ST.KJ-002 Test Channel Time Response Test on No. 22 Steam Generator Steam Pressure
- Ful 1 Fl ow Test of No. 1 22 Safety Injection Pump Full Balance Test of 11 and 12 Charging Pumps Inservice Testing of No. 21 Safety Injection Pump Inservice Testing of No. 21 Service Water Pump High Pressure Coolant Injection Inservice Test Emergency Diesel Generator Operability Test - Monthly The surveillance testing activities inspected were effective with respect to meeting the safety objectives of the surveillance testing program. * Inspection Findings 4. Salem Emergency Core Cooling System (ECCS) Surveillance Test Review The ECCS flow balance test procedure Sl.OP-ST.SJ-0013, Revision 1,
11Throttling Valve Flow Balance Verification 11, was reviewed to verify that the ECCS flow inconsistencies documented in Westinghouse Electric Corporation letter dated December 4, 1989, had been properly evaluated and incorporated into the ECCS flow test procedur The inspector determined that Westinghouse recommendations made in the December 4, 1989 letter were being satisfactorily dispositioned or incorporated into the licensee's ECCS flow test procedure.
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The procedure has been upgraded to limit the flow inbalance through each systems 1 (charging/safety injection) branch line to within 1.68 gpm at the same backpressur This is more conservative than Westinghouse 1s 5 gpm recommendatio The licensee met with Westinghouse on May 10, 1990 to discuss the completed Unit 1 surveillance pump flow test data and resolve issue No. 2 noted in Westinghouse 1s letter dated December 4, 198 The issue relates to the hydraulic resistance associated with charging/safety injection (SI) pump runout condition The inspector was informed by the licensee that Westinghouse had evaluated the ECCS pump flow test data for the number 11 and 12 SI pump and the number 11 charging pum Westinghouse determined, that these ECCS pump fl ow performance curves were acceptable based on comparing the licensee 1 s performance test results to the pump vendor 1s curve and the analytical curv The inspector reviewed the licensee 1 s ECCS surveillance test results for the two Unit 1 SI pumps and the 11 charging pUm The results appeared to meet the Westinghouse analytical assumption The inspector concluded that the performance test results demonstrate that the pumps and components are functioning properly and the SI subsystem flow rates meet Technical Specification Surveillance 4.5.2h requirement On May 18, 1990, the licensee reported to the NRC the discrepancies identified concerning vendor supplied orifice 11 K
factors in accordance with the requirements of 10 CFR Part 2 On May 24, 1990, the licensee submitted the associated written repor No deficiencies were identified concerning licensee reporting of this issu The licensee adjusted the affected ECCS subsystem flow rates by pump repairs, installing new orifice plates, and adjusting the throttling valve Pump repairs consisted of replacing the rotating element on the 11 SI pump and replacing the 12 charging pum The previously installed flow orifice plates had not been shop flow tested prior to installatio The licensee utilized the vendors engineering calculated 11 K 11 value for the orifice plates. A sample of the newly installed orifice plates were shop flow tested by the licensee prior to installation. Also, see section 8. Technical Specification (TS) Surveillance Audit One of the licensee 1 s corrective actions for a missed TS required surveillance test was to perform a verification audit
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of the Unit 1 and 2 TS Unit 2 LER number 89-15 was revised (revision 1) on April 20, 1990 to update this proposed corrective actio The licensee has modified their audit completion date to December 199 The audit is currently in progres The scope of the audit includes a review of all TS amendments and development of a TS-surveillance cross reference matri A check of surveillance test technical adequacy is planned to be performed through the Procedure Upgrade Project which is scheduled for completion in March of 199 The inspector reviewed the revised LER and discussed the audit with licensee engineer The inspector.will review the effectiveness of the audit in a future inspectio The inspector had no further questions at this tim Diesel Generator 28 Failure During Testing At 6:30 a.m. on May 2, 1990, the licensee shutdown the 28 diesel generator (DG) after heavy smoke was noted in the DG exhaus Unit 2 was in Mode 6 (refueling) at the time of the failur The failure occurred about 20 minutes into a 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> surveillance test being conducted after the 18 month DG inspectio The 28 DG had been successfully tested for about 3 to~ hours immediately following the 18 month inspection for compression checks and testin The DGs at Salem are ALCO, 900 rpm, Vl8 cylinder, turbo-supercharged model number 251Gl8G The equipment operator noted that the DG load dropped instantaneously from 2800 KW to 700 KW prior to observing the heavy smok The licensee inspected the DG and found an inducer blade on the air intake ~heared off the turbocharger uni The licensee had performed inspections of the turbocharger during the 18 month 28 DG inspection and had not identified any deficiencie The inspector examined the sheared fan blade on the failed 28 diesel generator turbocharger fa The fan was disassembled and the sheared fan blade was shipped to Maplewood Labs for metallurgical analysi The lab determined the failure to be brittl The inspector observed the installation of the new turbocharger and reviewed the maintenance procedur The inspector did note that several work procedure steps which involved rigging out the old turbocharger (which was performed on the previous day) had not been signed off in a timely manne This oversight was quickly corrected when brought to the attention of the maintenance personne The inspector also discussed the failure with maintenance personnel and system engineer The inspector questioned the licensee regarding their assurance of no foreign material in
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- the diesel air intake that could possibly get into the cylinder The licensee stated that they had inspected the air intake system from the roughing filter through the after coole A 1/2 11 hex nut was found in the inlet silence The licensee believes this nut did not cause the brittle failur No other foreign material was foun The failed turbocharger was replace Subsequent post maintenance testing was satisfactory and the DG was declared operable on May 23, 199 The licensee initiated a Technical Specification required special report number 90-5 dated June 1, 1990 discussing this DG failur The report concluded that the failure was due to bearing failure of the turbocharger inducer fan uni The licensee has also shipped the failed inducer fan to their metallurgical lab for evaluatio The results will be factored into the preventive maintenance progra Containment Fan C6oler Unit (CFCU) Heat Shrink Work On May 3, 1990, a specialist inspector was touring the Unit 2 containment observing the radiological controls associated with outage work in progres The inspector noted that the motor leads for the 24 CFCU were being connected and insulated using a pr~pane torch and a Raychem motor lead splice ki The inspector questioned the two electricians performing this heat shrink work regarding the availability of fire protection equip-ment and control After discussions with the maintenance personnel, their supervisor and the containment coordinator, the inspector concluded that no fire watch nor hot work permit was in plac The hot work as~ociated with 24 CFCU Raychem splices was immediately suspended and the licensee performed an investigatio The licensee concluded that the maintenance electricians and their supervisor failed to recognize the necessity for obtaining a hot work permit (HWP) as required by administrative procedure AP-25, 11 Fire Protection Program 11 *
In addition, the containment coordinator was not cognizant of the work in progres The use of a torch to heat shrink the insulation splice was accepted by the vendor (Raychem) as an appropriate metho This was verified per Raychem Installation Instruction PII-57608-AB dated May 13, 1990, and was referenced by the maintenance procedure M4C, 11 Reactor Containment Fan Motor Cable Connector Insulation 11, Revision. \\
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The licensee concluded that a procedural violation occurred caused by personnel error, The supervisor should have required the HWP when the decision was made to use the propane torc He stated that he was aware of AP-25 requirements for a HWP and agreed that an open flame from a propane torch was clearly an ignition sourc He overlooked this during the pre-job briefings which was a personnel erro Licensee corrective actions included the following:
Work was stopped until the situation was reviewed and understoo The deficiencies were corrected before the job resume This incident and the AP-25 requirements with respect to HWPs was reviewed with all maintenance-controls personnel, including the topic of fire watch qualification A procedure change request was initiated to revise the M4C procedure to agree with the Raychem Product Control Documen The job supervisor and technicians involved, and containment coordinator were counseled.
This incident report will be forwarded to training for inclusion in General Employee Training (GET) as a lesson learned related to HWP Training personnel *will also be requested to ensure the GET lesson plan conveys the fact that special qualifications are required prior to being assigned as a fire watc AP-25 is being reviewed for a possible clarification of the definition of an ignition sourc The inspector reviewed the completed incident report and discussed the report and corrective actions with licensee personne The licensee's actions were prompt and adequat The inspector interviewed fire protection personnel and deter-mined that no recent instances of failure to obtain HWPs had occurre Based on the NRC maintenance team inspection, and other NRC resident and specialist inspections, the inspector concluded that this failure to obtain a HWP as required by procedure AP-25 was an isolated cas Therefore, this NRC identified violation is not being cited because the criteria specified in Section V.G of the Enforcement Policy were satisfied (NON 50-311/90-13-01).
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4. Hope Creek Surveillance Instrumentation Not Removed After Testing During a routine plant tour at approximately 3:00 p.m. on May 4, 1990, the inspector noted that portable flow instrumentation was installed in the D loop of core spra The instrumentation was isolated from the core spray discharge heade The inspector reported this observation to the control room shift superviso The shift supervisor directed I&C to remove the temporary instrumentatio The licensee initiated an investigation including an incident report 90-04 The licensee determined that the portable flow instrumentation was used during surveillance testing the previous da Upon completion of the test (OP-IS.BE-002Q), the instrumentation was not remove This temporary flow instrumentation is required because the installed flow device does not meet ASME Section XI requirement The licensee identified this condition in LER 89-19 dated November 3, 1989, and it was discussed in NRC Inspection 50-354/89-1 The surveillance procedure directed the installation and removal of the instrumentation, but did not require a signoff for these activities. A work order installed the instrumentatio When the testing was completed, the work order was close However, the instrumentation was not remove Licensee corrective actions included removing the instrumentation, rev1s1ng the surveillance procedure, and modification to the maintenance planning department recurring tasks to ensure instrumentation removal prior to work order closur The inspector reviewed the completed incident report dated May 29, 1990 and discussed the event with licensee maintenance personne The inspector concluded that the licensee had taken prompt corrective actions and had performed a good root cause investigatio The inspector had no further questions at this tim.
High Pressure Coolant Injection (HPCI) Test The inspectors observed test performance from the control room and from the HPCI roo The test was properly briefed and conducted well, with infield superv1s1o Operations, radiation protection, and test personnel were noted as being knowledgeable and professional during the tes The inspector had questions regarding radiological controls (see section 3.2.2.A).
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19 Status of Previously Identified Maintenance Related Open Items (Closed) Violation 50-354/89-80-04 pertaining to the di ese 1 generator 1 ube oil 1 eakag During the October 1989 maintenance team inspection, the inspector observed that the 1 ube oil that 1 eaked from the 11 C 11 di ese 1 generator was not immediately cleaned as required by the station procedur The oil leak was subsequently cleane Following that inspection, the licensee's management took several corrective actions to improve their housekeeping effort and to ensure timely cleanup of all oil leak They issued station directive SA-SD.ZZ-22 on February 5, 1990 to designate specific personnel to enforce good housekeeping effort.* In addition, the licensee include housekeeping effort in their daily planning schedul The inspector considered the licensee corrective action adequat This item is close (Closed) Unresolved Item 50-354/89-80-09 pertaining to the unsealed cable to the diesel generator control panel During the October 1989. maintenance team inspection, the inspector observed that the cable entry from the overhead cable trays into the tops of diesel generators 11A11 and "D" control panels were not sealed as required by the installation procedur Following that inspection, the licensee sealed the affected penetrations with "SE Foam".
During this inspection, the inspector observed the installed condition of these penetration seals and found them to be acceptabl The inspector considered the licensee's corrective action adequat This item is close.
(Closed) Unresolved Item 50-354/89-80-03 pertaining to the missing flange connection stud on the diesel generator fuel tan During the October 1989 maintenance team inspection, the NRC inspector identified that one of the vent pipe flange connection studs on diesel generator 11 811 fuel tank was not installe The inspector evaluated the safety impact of the missing stud as lo Following that inspection, the licensee issued work order no. 891005095 to correct this deficienc The work order record indicated that the stud was installed on November 2, 198 During this inspection, the inspectors verified the stud instal-latio This item is close.
(Closed) Violation 50-354/89-80-10 pertaining to a temporary test gage installed without a temporary plant
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... modificatio This item was identified during the October 1989 maintenance team inspectio The test gage was removed by the licensee on the same day that this item was identifie Following that inspection, the licensee management instructed their maintenance personnel to emphasize their attention to ensure that the test equipment installed is properly documente In addition, an office memo was issued on April 9, 1990 to the maintenance personnel, directing them not to install test equipment without approved documentatio The inspector considered the licensee 1 s corrective actions adequat This item is close (Closed) Violation 50-354/89-80-07, 11Cause of failure 11 was not identified on the work activity sheet for corrective maintenanc Following the October 1989 inspection, the licensee developed a work order repair/cause maintenance status (WORMS) form to be included in each work order packag This form lists all possible equipment failure by categories and codes, and is being used by the maintenance personnel for corrective maintenanc The inspector reviewed the records of five corrective maintenance work activities and noted that this form was properly filled out and attache During the week of this inspection, the licensee was in the process of revising their work control procedure NC.NA-AP.ZZ-009(Q).
The revision was essentially complete but had not been approved by managemen The revised procedure contains instructions to complete the WORMS for The licensee's corrective actions were considered adequat This item is close.
(Closed) Violation 50-354/89-80-02 pertaining to the periodic status reports for Rosemount transmitter Maintenance Department Directive 1C-DD-ZZ-020(Q),
paragraph 4.2 required that the system engineer generates periodic status reports from transmitter test result During the October 1989 maintenance team inspection, the inspector identified that no status reports were generated for the Rosemount transmitter Following the maintenance team inspection, the licensee determined that the directive requirements for periodic status reports from the system engineer was needlessly include Directive procedure 1C-DD-ZZ-020(Q) was revised to eliminate this requiremen The licensee also explained that during the short period that this directive procedure
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was in effect, an insufficient number of transmitter calibrations were done to generate a status repor The inspector considered the licensee's corrective actions adequat This item is close Miscalibration of a Radiation Monitor On June 4, 1990, the licensee made a 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> report of a Technical Specification violation regarding a reactor building exhaust radiation monitor setpoin A Hope Creek I&C technician, while performing a surveillance on one of three reactor building exhaust radiation monitors, discovered that the setpoint for one of the other two monitors had been set non-conservativel The licensee determined that the calibration error had occurred during a surveillance four days prior to the discover Apparently, the setpoint for the refueling floor monitor had been mistakenly input for the reactor building exhaust radiation monitor, and the error resulted in a violation of Technical Specification 3.3.2,
- "Isolation Actuation Instrumentation. 11 Once discovered, the affected monitor's setpoint was restored to the required rang The inspector was notified on the day the error was discovered and followed the licensee's corrective action The inspector concurred with the licensee's determination that the root cause of the incident was personnel error and found their corrective actions to be timely and appropriat This licensee identified violation is not being.cited because the criteria specified in Section V.G. of the Enforcement Policy were satisfied (NON 50-354/90-10-01). EMERGENCY PREPAREDNESS Inspection Activity The inspector reviewed PSE&G 1 s conformance with 10CFR50.47 regarding implementation of the emergency plan and procedure In addition, licensee event notifications and reporting requirements per 10CFR50.72 and 73 were reviewe.2 Inspection Findings Loss of Emergency Notification System (ENS) Telephone On May 11, 1990, a Salem Unit 2 non-safety related lighting transformer failure resulted in the loss of licensee telephone systems and the ENS phone (see section 2.2.1.B).
The licensee reviewed the loss of the ENS phone and documented their review
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in a letter (NEP-90-117) dated June 11, 199 The licensee determined that ENS phone power units are supplied by the 2HL transformer (120VAC).
The licensee concluded that the ENS does not require a special uninterruptible power but rather a 11 reliable 11 power sourc However, the licensee is pursuing a number of recommendations to ensure this 11 reliable 11 power is maintaine The inspector reviewed the licensee's investigation and discussed it with emergency planning engineer The inspector reviewed NRC Bulletin 80-15 which appears to specify an emergency power supply for the ENS phon This item remains unresolved pending NRC specialist review (UNR 50-272/90-13-01). Inspection Activity PSE&G's conformance with the security program was verified on a periodic basis, including the adequacy of staffing, entry control, alarm stations, and physical boundarie These inspection activities were.conducted in accordance with NRC inspection procedure 7170.2 Inspection Findings Security System Power Loss At 4:27 a.m. on May 5, 1990, the Salem security system computers lost powe The normal power tripped at about 2:30 a.m. and the backup power operated until depleted approximately two hours late Adequate security compensatory measures were initiate The control room established alternate power from another source and the security computer was reinitiate The licensee made a one hour safeguards event repor The inspector was notified at hom Additional followup included discussions with licensee operators, engineers, and security personne The inspector concluded that the licensee's immediate response was consistent with procedure A previous power failure had occurred on May 24, 198 The licensee performed an investigation and root cause analysi This was documented in a safeguards event report (SER) 90-SOl dated May 29, 199 The licensee concluded that the power supply static switch failed and personnel were slow in restoring power from the alternate sourc Licensee corrective actions included procedure and training enhancements, and improvements in coordination and communications between security and operational personne The inspector reviewed the SER and discussed it with licensee personne Corrective actions will be reviewed by a specialist inspector in a future inspection.
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23 Vehicle In The Protected Area On May 16, 1990 at 10:45 a.m., inspectors on an NRC team noted a vehicle in the protected area with keys in the ignitio The driver was initially not seen in the immediate vicinit The vehicle was located outside the Salem Unit 2 service water manhole above the 78 foot entranc The vehicle had a liftgate which was in use that required the ignition key to be o The inspectors notified the resident inspector who in turn notified security managemen The licensee initiated a security incident report and investigation.. The licensee concluded that it was necessary to leave the keys in the ignition of the truck while the driver was outside of the cab to operate the lift gat At no time was the vehicle left unattended while the keys were in the ignition, since the driver and others present had full visual contact with the vehicl The inspector reviewed the report and discussed this event with licensee security managemen An NRC security specialist was also contacte The inspector concluded that the licensee performed an adequate review and evaluation of the even The inspector had no further questions.
Fitness For Duty (FFD) Suspension From Work At 1:28 p.m. on May 23, 1990, a supervisor with no operations responsibilities at the Salem/Hope Creek Nuclear Generating Station failed a random alcohol test*conducted by the plant Medical Department as part of the FFD progra Two breath analyzer tests indicated the presence of alcohol above the program limit In accordance with the FFD program, the supervisor's site access was suspended and the supervisor entered the licensee's rehabilitation progra A decision on access reinstatement will be made in accordance with the FFD program requirements after completion of the rehabilitation progra Initial licensee assessment of this supervisor indicated the individual was a good employee and no previous problems were identifie The supervisor admitted drinking during the five hour abstinence period prior to reporting for wor The licensee has initiated an independent review of the supervisor's work over the past few month The inspector was informed of this event from the licensee, by telephone at 12:00 p.m. (EST) on.May 24, 199 The inspector discussed this event with licensee personnel and concluded that the initial response was adequate.
- 24 ENGINEERING/TECHNICAL SUPPORT Salem Emergency Core Cooling Charging Pump Repairs During the repair of the number 12 -charging pump rotating element, the licensee performed inspections of the pump casin Visual and dye penetrant inspections noted cracks in the pump casing clad materia These inspections have been performed at Salem since 1980, based on vendor information dated June 20, 1980, and December 2, 1983, and an NRC Information No~ice number 80-38 dated October 30, 198 The charging pumps are eleven stage centrifugal, horizontal, Pacific/Dresser, Inc.,
with a solid casin The casing is carbon steel clad with
.125 11 of stainless stee The number 12 charging pump was inspected in 198 Clad cracking was noted and subsequently repaired by excavation with a Belzona coatin The licensee attempted to grind out the new crack However, they concluded that the cracks might proceed to less than the minimum wall thicknes Based on this, the licensee replaced the entire pump casing with a stainless steel casin The inspector questioned the acceptability of the previous Belzona repair metho The licensee stated that the repair was to the cladding material only and did not affect the ASME pressure retaining casing materia This repair method and its potential generic use remains unresolved pending review by a specialist inspector (50-272/90-13-02).
During further evaluations and repair activities on number 12 charging pump the licensee identified that the pump alignment lug and slide shoe welds were not within the design basi Investigation by the engineering department has determined that the alignment lug and slide shoe welds to the pedestals supporting charging pumps No. 11, 12, 21, and 22 would not withstand the nozzle and seismic load criteria given to PSE&G by Westinghous This was apparently due to vendor installation deficiencie The licensee performed corrective weld repairs on the Unit 1 and 2 charging pumps to meet the Westinghouse criteri The ltcensee reported this information on an ENS call at 5:00 p.m. on May 7, 199 A Part 21 notification call was made on May 16, 1990 and a followup letter dated May 22, 1990 was issue Unit 1 LER 90-017 also discussed this occurrenc No inadequacies were noted with the LER or Part 21 repor (Also, see section 8.1.B.)
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25 Unit 2 Core Barrel Indications On May 8, 1990, the licensee identified 5 linear indications in the reactor core barrel during visual inservice inspection (ISI) examination Three indications were observed in the area of the upper to lower core barrel circumferential wel Two indications were observed in the area of the number 24 reactor coolant hot leg nozzle to core barrel wel These indications ranged from 3/8 11 to 1 1/2 11 in lengt The licensee attempted to remove these indications by buffin However, they were unsuccessfu Additional attempts to check the indications by ultrasonic examination were also unsuccessfu A conference call with NRC regional, site, and Headquarter's personnel was conducted on May 9, 199 The licensee stated that.a vendor analysis concluded that the Unit 2 core could be reloaded into the reactor vesse Also, they concluded that the unit could operate for 18 months or one cycle, and that the unit was bounded by the loss of coolant accident and safe shutdown earthquake analyse This was based on a 2 11 through wall crack and a$sociated stress loads that were postulated to occur during these accident The licensee further stated that the Unit 2 core barrel was due for its ten year ISI next outage (fall of 1991).
During this outage, these indications would be examined and repaired as necessar The inspector participated in the conference call and reviewed the licensee's safety analysi The inspector had no further questions at this tim CFR Part 21 Regarding ECCS Flow Orifice Plates At 11:15 a.m. on May 18, 1990, the licensee informed Region I of a 10 CFR Part 21 report regarding ECCS flowrate measurement orifice plate A formal notification letter was dated May 24, 199 The 11 K 11 factors used for converting measured differential pressure to flow rate that were supplied by Westinghouse were found to be different values when recently tested by the license The affected systems include high head safety injection (charging).
and intermediate head safety injectio These flow elements include cold leg injection, hot leg injection, reactor coolant
- pump seal and charging flow The licensee has determined that the as found (tested)
11 K
factor value resulted in exceeding Technical Specification maximum flow rates for the ECCS The ECCS pumps could potentially reach runout conditions and/or have inadequate net positive suction head.
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- On May 25, 1990, the 12 residual heat removal (RHR) pump (low head safety injection) failed its inservice test due to low differential pressur During licensee review, it was found that the PSE&G supplied flow orifices (4) for the RHR system were not in accordance with design drawing This condition effects the 11 K 11 factor and therefore flow rate dat Corrective actions included fabrication of replacement orifice plates, laboratory testing of a sample of plates, installation of new plates into the affected ECCSs, and performance of special and surveillance testing using the new orifice The inspector reviewed the Part 21 letter and discussed it with licensee engineer The inspector questioned the measuring and test equipment requirements for these flow rate orifice Further discussions were held during a conference call on June 4, 199 The inspector concluded that the licensee 1 s review of these flow measurement devices was initially wea A narrowly focused review of the initial safety injection problem missed the inadequacies with the RHR flow orifice However, subsequent events did result in licensee identification of the RHR proble (Also, see section 8.1.B.).
Boric Acid Transfer Pump Capacity Outside Design Basis On May 24, 1990, the licensee made an ENS call that engineering review of plant pump design and performance determined that boric acid transfer pumps numbers lZ, 21 and the 22 (3 of 4 total for both units) had less than the required flow capacit The actual flow rates were 49-72 gpm and the required flowrate was 75 gp The licensee changed the pump design objective to 50 gpm in a 10 CFR 50.59 Safety Evaluation conducted on May 25, 199 In this analysis the licensee determined that the safety related function of the BAT pumps would not be compromised by reducing the required flow to 50 gp The NRC will review the technical analysis within the 10 CFR 50.59 evaluation in a future inspection and followup in a future repor The inspector will monitor future BAT pump surveillance test For additional discussion of this event, see NRC Inspection Report 50-272/90-81; 50-311/90-8 Main Steam Isolation Valves (MSIVs) Operatiori Outside Design Basis On May 25, 1990, while in Mode 5 (Cold Shutdown), the licensee identified that a condition outside the design basis of the plant existed by which only two of the four Unit 2 MSIVs may have tlosed under a postulated event and single failure conditio..
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The design basis assumes that three of the four MSIVs close Fast closure is provided for each MSIV by two solenoid operated vent valves (MS169 and MS171).
Each environmentally qualified solenoid valve is housed in a local cabine Each cabinet is provided with a vent path to prevent collapsing the cabinet and damaging the solenoid valves upon a steam line ruptur The licensee found that two of the cabinets associated with MS169 vent valves for two different MSIVs did not have the required vent An assumed electrical power (common to all four) failure associated with the MS171 solenoid vent valves, combined with the failure of these MS169 valves to function, would prevent fast closure actuation of two MSIV This event was reported to the NRC in accordance with 10CFR50.72 reporting requirement This condition was identified during a followup to a previous NRC identified concern regarding protective screens on some of the cabinet vents (NRC Maintenance Team Inspection N /90-200; 50-311/90-200).
Followup review identified that only Unit 2 was affecte The vents were subsequently provided in the two affected cabinet The licensee event report will be reviewed by the inspector upon submitta The inspector had no further questions at this tim Boron Injection Tank (BIT) Socket Weld Failures A Unit 2 BIT socket weld failed on January 17, 1990 (reference NRC Inspection 50-311/90-04) resulting in an unisolable leak and a Unit 2 shutdow A specialist inspector reviewed the metallurgical report entitled 11Metallurgical Investigation of Cracking in the BIT Bypass Line Socket Weld at Salem 2 Station.
The report was prepared by Westinghous The investigation indicated that the failure initiated at the root of the socket weld (an area of stress concentration due to lack of penetration) and progressed by a fatigue mechanism as evidenced by the presence of fatigue striation No metallur-gical deficiencies or anomalies were observe The stress concentration effects at the root were assisted by a stress corrosion cracking mechanism as evidenced by corrosion and m~ltiple crackin The material involved as austenitic stainless steel, type 31 Similar joints were inspected and found to be free of defect In addition, the licensee initiated an engineering analysis of the subject system On the basis of the evidence present, the inspector concurred with the conclusions stated in the report.
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28 Residual Heat Removal (RHR) Pumps At 2:30 p.m. on June 1, 1990 while in Mode 5, PSE&G determined and made a four hour report that both Unit 1 RHR pumps were inoperable for Modes 1 through The basis for this conclusion was degraded RHR pump pe~formance at higher flow Subsequent investigation by the licensee and vendor personnel determined that when initial testing inaccuracies were corrected, both RHR pumps were actually operabl The differential pressure (DP)
drop across the discharge check valve had to be subtracted from the pump D When this correction was made, the RHR pumps were evaluated to be operating within their pump curve charact~ristic A conference call was conducted on June 4, 1990 to review the details of the identified testing inaccuracie In a letter dated June 5, 1990, the licensee withdrew the four hour repor The inspector determined that full flow testing of the RHR pumps was not routinely performed during refueling outage Typical pump tests were performed quarterly and at m1n1mum flow condition During this shutdown, full flow tests were performed at multiple flow points on the pump curv The licensee stated that they intend to conduct similar multiple point full flow testing during each refueling to demonstrate continued RHR pump operability, and the results will be trended by the Performance and Reliability Grou The inspector reviewed RHR pump curve data, discussed the licensee's analysis with engineering and management personnel, and participated in the conference cal The inspector will continue to monitor RHR pump performance during periodic inspection Reactor Trip Breaker Bypass Breaker Failure During a refueling outage on June 12, 1990, the Unit 2 11811 reactor trip bypass breaker (DB-50) failed to open using the shunt trip mechanism after being racked-in following a semiannual functional tes The as-found test results, including checks of the undervoltage trip device, for this breaker had been satis-factor All other recent reactor trip breaker tests have been satisfactor The licensee determined that the failure occurred because the electrical contact between the breaker and the cabinet for the shunt trip coil was damaged such that electrical continuity was los One of the electrical contactors was damaged when the breaker was racked into its cabinet during the test sequenc Unit 2 did not enter a Technical Specification action statement because the shunt trip feature was not required in the present mode (Hot Shutdown).
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immediate corrective actions include licensee inspections of the electrical contacts for both reactor trip and bypass breakers for Unit 2 and the bypass breakers for Unit The reactor trip breakers for Unit 1 will be inspected during the upcoming monthly functional tes The inspector observed the inspections of the Unit 2 breakers, discussed the event with system engineering and maintenance personnel, and reviewed related documentatio System engineering response to the event was determined to be timely and effectiv The inspector will review the reactor trip breaker testing ih a future inspectio.2 Hope Creek Hope Creek Reactor Recirculation System instrumentation Line Socket Weld Failures On December 31, 1989 a Hope Creek reactor recirculation instrument line failed while shutdown (reference NRC Inspection 50-354/89-26 and. LER 89-26).
A specialist inspector reviewed the metallurgical report entitled 11Metallurgical investigation of Cracking in the Instrument Line Socket Weld at Hope Creek Station
- The report was prepared by Westinghous The investigation indicated that the failure initiated at the root of the socket weld (an area of stress concentration due to lack of penetration) and progressed by a fatigue mechanism as evidenced by the presence of fatigue striation No metallurgical deficiencies or anomalies were observe The materials involved were austenitic stainless steel, type 30 Similar joints were inspected and found to be free of defect In addition, the licensee initiated an engineering analysis of the subject system On the basis of the evidence presented, the inspector concurred with the conclusions stated in the repor.
SAFETY ASSESSMENT/QUALITY VERIFICATION Salem Missed Surveillance Tests Several surveillance tests have been missed due to various reasons for the past several year Some reasons include inadequate Technical Specification Amendment implementation, defective procedures, and various types of administrative
control deficiencie Licensee reviews and evaluations had been ~ompleted, however, continuing problems are being identified (Section 9 - LERs).
Additional reviews, currently being conducted by the licensee (Section 4.3.l.B) are expected to identify and resolve any outstanding issue To date, and for an extended period of time, licensee followup and response to the individual and programmatic weaknesses has been ineffective as evidenced by recurring problems in this are The inspectors will closely monitor the licensee 1s continuing corrective effort Emergency Core Cooling System (ECCS) Operability During the report period, the licensee completed a detailed review of the Salem ECCS Initial response to the Westinghouse December 4, 1989 letter was not aggressiv Once, the surveil-lance problems associated with the charging and safety injection pumps w~re identified, the licensee performed a thorough review of the ECCS operabilit Repairs and retest activities were adequately conqucte An initially narrowly focused review of flow measurement devices missed problems associated with the RHR syste Once identified, the licensee was aggressive in certifying flow measurement device Unit 2 Refueling Activities Unit 2 refueling activities were effectively coordinated and conducted during the perio Plant management was noted as being involved in all of these activities on a daily basi The licensee was aggressive in followup to a loss of AC power event (see section 2.2.1.D).
Midloop operation (see section 2.2.1.E) and core reload activities (see section 2.2.1.F) were conducted effectively and in a safe manne Periodic outage meetings were efficiently conducted and were effective in managing outage activitie.2 Hope Creek Management Oversight Plant management was noted as being involved in daily activities as evidenced by followup to operational events, LER quality and improvements to overall plant housekeeping.
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31 LICENSEE EVENT REPORTS (LER), PERIODIC AND SPECIAL REPORTS, AND OPEN ITEM FOLLOWUP LERs and Reports PSE&G submitted the following special and periodic reports and licensee event reports which were reviewed for accuracy and the adequacy of the evaluation:
Salem and Hope Creek Monthly Operating Reports for April 199 Salem LERs Unit 1 LER 89-030-01 This report revised LER 89-030 and* addressed the inspector 1 s concerns as identified in NRC Inspection Report No. 50-272/90-04; 50-311/90-0 The revised LER was found to be acceptabl LER 90-006 This LER concerns two ESF actuations (containment ventilation isolation) which occurred on March 2, 199 These actuations were discussed in NRC Inspection Report No. 50-272/90-05; 50-311/90-0 No inadequacies were identified relative to this LER.
. LER 90-007 This LER concerns the failure to historically perform periodic surveillance testing on the output contact (XK71) for automatic containment spray (CS)
star Both trains of CS were declared inoperable and Technical Specification 3.0.3 was immediately entere The test procedure was revised and the output contact was satisfactorily tested within one hou The licensee identified this issue on March 21, 199 The root cause was determined to be past inadequate administrative controls (1978) in that the affected surveillance procedure was not revised following implementation of a design change which added test switches for the CS automatic actuation logi This is considered to be a non-cited violation because the criteria in Section V.G of the Enforcement Policy were satisfied (NON 50-272/90-13-03).
The licensee currently plans to perform detailed technical reviews of procedures, including surveillance tests, as part of the long term Procedure Upgrade Project to identify procedural technical deficiencie Additionally, a Technical Specification surveillance verification audit is underway and expected to be
LER 90-008 LER 90-009 LER 90-010 LER 90-011 LER 90-012
completed by December 199 See Sections 4.3.1.B and 8.1.A for further discussion on previous and current licensee actions on this issu No inadequacies were identified relative to this LE This LER discussed events related to 11 lA
Safeguards Equipment Control~ Cabinet (SEC) problems, including an ESF actuation (diesel generator automatic start) and a controlled plant shutdown in accordance with Technical Specification requirement This event is discussed in NRC Inspection Report N /90-11; 50-311/90-1 The quality of this LER was generally good, however, two concerns were *
identifie Selected SEC components suspected of failure were sent to the manufacturer for investigatio Since causes for the actuations were not identified, a supplemental LER should be submitted when the results are received (the LER stated that no supplemental report is planned).
Additionally, the original SEC chassis, when reinstalled, sustained an additional failur This was not addressed in the LER tex There were no further questions relative to this LE This LER discussed automatic main steam system isolations during surveillance testing activities due to procedural inadequacie This event was discussed in NRC Inspection Report N /90-11; 50-311/90-11.. This LER was found to be adequat The LER describes a Reactor Protection System actuation while in Mode 3 (Hot Standby) on April 3, 199 This event is discussed in NRC Inspection Report No. 50-272/90-11; 50-311/90-1 This LER was determined to be adequat The LER discussed an April 6, 1990 ESF actuation (feedwater system isolation) while operating at 7% reactor power (NRC Inspection Report
.. No. 50-272/90-11; 50-311/90-11).
No inadequacies were identified relative to this LE This LER described a reactor trip that recurred from 90% power on April 9, 1990 (NRC Inspection Report No. 50-272/90-11; 50-311/90-11).
This LER was found to be adequate.
.,
LER 90-013 Unit 2 LER 89-15, Revision 1 LER 90-011 LER 90-012 LER 90-013
The LER discussed an April 10, 1990 ESF actuation (containment purge/pre~sure-vacuum relief system isolation).
This event was described in NRC Inspection Report No. 50-272/90-11; 50-311/90-1 The LER was found to be adequate~
See section 4.3,1.A of this repor This* LER described an ESF actuation (containment ventilation isolation) which occurred on March 1, 199 The actuation was attributed to an equipment failure due to a frayed AC power lea This LER was determined to be acceptabl This report addressed an ESF actuation (containment ventilation isolation) which occur.red on April 3, 1990 when an operator performing a breaker tagout inadver-tentl~ bumped an infeed breaker associated with the affected radiation monito This event is discussed in NRC Inspection Report 50-272/90-11; 50-311/90-1 The report noted that a supplemental report will be submitted by June 30, 1990 addressing the root cause of the even This LER was determined to be adequat This LER concerned a Technical Specification (TS) noncompliance during the fourth refueling outage (September 1988) due to inadequate administrative contro Specifically, during the unit shutdown to Mode 6 (Refueling) on April 16, 1990, the licensee identified that procedures did not require reducing the actuation setpoints for containment radiation monitors 2RllA and 2Rl2A as required by TS 3.3. During the recent shutdown, the setpoints were properly adjusted prior to entry into Mode 6 as require The licensee's followup review identified that the setpoints had not been adjusted (reduced) during the previous outage (September 1988).
Unit 2 TS Amendment (No. 53) was issued in 1987, which incorporated the radiation monitor setpoint reduction requirement However, the appropriate operations procedure (Cold Shutdown to Refueling) and the Mode 6 channel functional surveillance test procedures were not revised to reflect the new requirement See section 4.3.1.B for further discussion in this are This is a non-cited violation because the criteria in Section V.G of the Enforcement policy were satisfied (NON 50-311/90-13-02).
There were no inadequacies noted with respect to this LE *,
LER 90-016 LER 90-17 LER 90-18 LER 90-019 &
LER 90-020 Hope Creek LERs LER 89-026
This LER discussed an unmonitored containment venting to atmosphere on April 20, 1990, while in Mode 6 (Cold Shutdown).
This event was due to personnel error in that neither of the two radiation monitors was verified to be operable during the release (one of the two was required).
The licensee stated that several other radiation monitors, used to corroborate the required monitors, did not indicate any abnormal activity during the containment ventin This event was discussed with the applicable Operations Department personnel and the applicable procedures will be revised to prevent recurrenc This is a non-cited violation because the criteria in Section V.G of the Enforcement "policy was satisfied (NON 50-311/90-13-03).
There were no inadequacies identified relative to this LE See section 2.2.1.A of this repor See section 2.2.1.B of this repor These LERs concern Unit 2 containment purge isolations while in Mode 6 caused by the radiation monitoring syste No inadequacies were noted relative to these LER This LER concerns a leak in a weld on a one-inch reactor recirculation system elbow tap flow transmitter instrument line join The leak was discovered on December 31, 1989, while the plant was in operational condition 3 and was originally discussed in Hope Creek Inspection Report 50-354/90-01 (paragraph 7.2).
The licensee forwarded the affected instrument line to Westinghouse labs for a failure analysis of the failed wel The analysis indicated that a weld defect led to the initiation of a crack at the elbow-base metal interface, and the primary cause of the defect has been classified as an equipment failure due to a deficient installation during original plant construc-tio In addition to the Westinghouse analysis, PSE&G retained a separate contractor to perform an independent review of the existing small bore reactor recirculation system piping stresse This review determined that existing stresses are within allowable limits and continued operation is acceptabl In the LER, PSE&G committed to perform a detailed analysis to determine appropriate monitoring requirements for small bore
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LER 90-004
LER 90-005 LER 90-006
p1p1ng and to have the instrumentation installed during the station 1 s third refueling outage, scheduled for January 199 The inspector reviewed the corrective actions taken by the licensee in response to the original event, found then to be appropriate, and will followup on the analysis and installation of the instrumentation intended to monitor small bore piping in the futur This LER reported the Reactor Protection System (RPS)
motor generator set (MG set) trip of April 18, 1990, which was described in NRC Inspection Report 50-354/
90-0 The MG set trip resulted in a* 11 B11 RPS half scram and various chanriel 11 8 11 and 11 0 11 Nuclear Steam Supply Shutoff System isolation The licensee determined that the MG set trip was caused by a spurious ground fault that tripped the Motor Control Center feeder breaker which supplies the MG se A definitive cause for the ground fault in the feeder breaker could not be determined, but Hope Creek System Engine~ring intends to track any similar failures under the station performance monitoring program and take further action if a trend develops.
The inspector identified no problems with the LER and, as stated in Inspection Report 50-354/90-08, will followup on the event as additional information becomes availabl This LER reported the omission of a Liquid Radwaste Discharge Monitor (LRDM) inoperability from the most recent Radioactive Effluent Release Report (RERR-8, dated March 31, 1990).
This event was also discussed in NRC Inspection Report 50-354/90-0 The licensee attributed the cause of the omission to a procedural deficiency in monitoring the operability of the LRDM, and corrective actions taken included submitting a revision to RERR-8 and modifying the methods used to track and review LRDM operability for future RERR purpose The inspector reviewed the LER and the proposed corrective actions and found them to be satisfactory in reporting and resolving the identified proble This LER described an instance where the 11 E11 Filtration, Recirculation and Ventilation System (FRVS) recirculation fan was discovered running, despite the fact that there were no existent plant conditions which would cause an automatic start of
...
LER 90-007 9.2 Open Items
the fa Spurious actuations of FRVS fans has been a recurring problem at Hope Creek, and this event is discussed in further detail in paragraph 2.2.2 of this repor The LER stated that Hope Creek System Engineering has initiated work orders to inspect the flow switches on all FRVS ventilation trains at the first available opportunit No inadequacies were noted relative to this LE This LER reported a half scram and isolation of the inboard reactor water cleanup isolation valve which occurred as~ result of a loss of the power supply.to the Channel 11A 11 Reactor Protection System (RPS)
electrical bu The loss of the power supply and its cause are documented in paragraph 2.2.2 of this repor The licensee states in the LER that the problem encountered is similar to that described in General Electric Service Information Letter (SIL) 496 and that corrective actions include scheduling of the modifications described in that SI The inspector
- noted no inadequacies _in the form or. content of the LE The following previous inspection items were followed up during this inspection and are tabulated below for cross reference purpose Site Salem Hope Creek 354/89-80-02 354/89-80-03 354/89-80-04 354/89-80-07 354/89-80-09 354/89-80-10 1 EXIT INTERVIEW 10.1 Resident Section 4.3..3..3..3..3..3. Status Closed Closed Closed Closed Closed Closed The inspectors met with Mr. L. K. Miller and Mr. J. J. Hagan and other PSE&G personnel periodically and at the end of the inspection report period to summarize the scope and findings of their inspection activities.
...
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.2 Specialist Date(s)
5/1-4/90 5/14-18/90 5/14-25/90 6/11-15/90 Subject Radcon In service Inspection Integrated Performance Assessment Team Engineering 10.3 Salem Management Meeting Inspection Report N /90-14; 311/90-14 272/90-15; 311/90-15 272/90-81; 311/90-81 272/90-17; 311/90-17; 354/90-11 Reporting Inspector Nimitz Chaudhary Beall Cheung A management meeting was held on May 2, 1990 in Region I office with PSE& Topics discussed included ECCS operability, recent equipment issues, personnel errors and procedural inadequacies; Technical
.. Specification surveillance, and other item Attachment 1 is a list of meeting attendee Attachment 2 is a copy of the licensee's handout.
"
Attachment 1 Salem Management Meeting May 2, 1990 List of Attendees Nuclear Regulatory Commission J. Wiggins, Deputy Director, Division of Reactor Projects W. Hodges, Director, Division of Reactor Safety P. Swetland, Section Chief, Division of Reactor Projects T. Johnson, Senior Resident Inspector J. Durr, Chief, Engineering Branch, Division of Reactor Safety L. Kolonauski, Project Engineer, Division of Reactor Projects G. Tracy, Reactor Engineer, Division of Reactor Projects J. Carrasco, Reactor Engineer, Division of Reactor Safety S. Chaudhary, Senior Reactor Engineer, Division of Reactor Safety L. Briggs, Senior Operations Engineer, Division of Reactor Safety H. Kaplan, Senior Reactor Engineer, Division of Reactor Safety Jai R N Rajan, Mechanical Engineer, NRR J. Caldwell, Regional Coordinator, DEDO M. Thadani, Project Manager, NRR Public Service Electric and Gas Company T. Crimmins, Vice President - Nuclear Engineering S. LaBruna, Vice President - Nuclear Operations L. Miller, General Manager - Salem Operations B. Preston, Manager - Nuclear Licensing and Regulation M. Danak, Senior Staff Engineer M. Morroni, Technical Engineer M. Bandeira, Nuclear Engineering Standards Manager J. Ronafalvy, Manager - Nuclear Engineering Design R. Drewnowski, Nuclear Mechanical Engineering Manager F. Thomson, Assistant General Manager - Salem J. Perrin, Nuclear Projects Engineering Consultant R. Binz, IV, Specialist Supervisor D. Dodson, Nuclear Licensing Supervisor Other D. Zannoni, New Jersey Department Environmental Protection, Nuclear Engineer T. Morabito, Radiation Control Specialist - State of Delaware T. Robb, Director - Joint Owner Affairs, Philadelphia Electric Co.
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NRC MANAGEMENT MEETING MAY 2, 1990
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ECCS OPERABILITY ASSURANCE REVIEW PRES-ENTED BY:
M. BANDEIRA
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NUCLEAR ENGINEERING STANDARDS MANAGER
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ECCS OPERABILITY REVIEW
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IOU-13'.
MISSION STATEMENT REVIEW ECCS SYSTEM AND EQUIPMEN DESIGN AND OPERATIONAL DATA TO.ASSURE THAT ALL TECHNICAL SPECIFICATION AND
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WESTINGHOUSE LOCA ANALYSIS REQUIREMENTS AAE*~ATI~~l~b SUCH THAT THE.SALEM ECCS
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SYSTEMS ARE CAPABLE OF MEETING THEIR DESIGN BASIS PRIOR TO RESTART OF SALEM UNIT 1 *AND '!""*
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INTERLOCKS CV41l,41 W/ SJl.~J2 SJ67,b0 W/ SJ45 SJ45 W/ ntll,flH2 SJ44 W/ RH4 CS36 W/ RHl,flH2
& SJ44
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eve----- 2052W**A-H761 RllR--*--- 21l52J2**A-8761 SI-------- 21l52J4-A-B761 cs-------21l52J5**A-B761 l!1IE FOR ru::cmc. HOLE 81'-J' OR 70i!
RW!lT 41lll,000 GAL USJ[51 SJbq SJ/6 I
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eves rOMPC1~;1 rr M.11. lll\\NAK Wt1!10f1
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CHRONOLOGY 12/19/89 RECEIVED WESTINGHOUSE NOTICE PERTAINING TO ECCS FLOW INCONSISTENCIES (PSE-89-759)
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INITIATED INTERN.AL. REVIEW ACTIVITIES 1/4/90 SURVEILLANCE TEST DATA REVIEW CONCLUDES UNIT 2:*r /S HIGH FLOW LIMIT EXCEEDED BY APPROX. * 6 GPM 4/11/90
~*NRC NOTIFIED AND EMERGENCY LICENSE AMENDMENT REQUESTED
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WESTINGHOUSE CONTACTED TO ANALYZE PSE&G FLOW DATA FOR 12/19/89 NOTICE IMPACT NRC NOTIFIED OF UNIT 1 & 2 SI-FLOW
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CALCULATION ERRORS
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MANAGEMENT DIRECTS CONTINUATION OF UNIT 1 FORCED OUTAGE TO RESOLVE ECCS ISSUES
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TECHNICAL TEAM FORMED TO INVESTIGATE ALL ECCS ISSUES 4/23/90 TECHNICAL TEAM EFFORT SUBDIVIDED TO ADDRESS SERT AND TECHNICAL REVIEW INDEPENDENTLY
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RE,lIEW TEAM MEMBERS e RESTART ISSUES
- M. BANDEIRA J. MORRISON J. WEBSTER *..
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J. MUSUMECI J. WRAY P. OTT H. BERRI CK
- SERT
- p. MOELLER M. GROSS J. PANTAZES H. ONORATO V. GADZINSKI
- TEAM LEADER
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NU'cLEAR-. ENGI°NEERING STANDARDS MANAGER MAINTENANCE ENGINEER PROJECT MANAGER-SALEM PLANNING OPERATING ENGINEER=SALEM PRINCIPAL ENGINEER-RAD PRO TECHNICAL ENGINEER-SALEM
._:.PRINCIPAL ENGINEER
=MECHANICAL
'MANAGER-SITE PROTECTION SENIOR STAFF ENGINEER-SALEM GA PRINCIPAL ENGINEER-ENGINEERING STANDARDS LEAD ENGINEER-LICENSING SENIOR NUCLEAR MAINTENANCE SUPERVISOR
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11111-.0.:
REVIEW SCOPE e EQUIPMENT PERFORMANCE e INTERNAL ITEMS e OPERATING.EXPERIENCE FEEDBACK
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NRC
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INPO.
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e ACCIDENT* ANALYSIS CRITERIA FA.OM_l1 LETTER e TECHNICAL SPECIFICATION REQUIREMENTS
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FINDINGS
- PROCEDURES
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- HUMAN F*ACTORS ISSUES
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- TECHNICAL ISSUES
- EQUIPMENT
- PUMPS
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- ~ PERFORMANCE CRITERIA-FLOW MEASUREMENT METHODOLOGY
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ECCS PROCEDURES
- HUMAN FACTORS ISSUE-FORMAT AND ORGANIZATION
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- CHARGING PUMP FLOW TEST
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- . !t-. SE-AL *INJECTION, FLO SAFETY INJECTION PUMP FLOW TEST
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A"RECIRCULATION FLOW
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- TECHNICAL REQUIREMENTS
- INJECTION FLOW* rMBALANCE
- LESS THAN 5 GPM DIFFERENCE BETWEEN LOOPS
- SYSTEM RESISTANCE
- PUMP DEGRADATION
- NO GAEA TEA THAN 5%
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ECCS PUMPS
W ANALYTICAL ASSUMPTION AND T/S CAPABILITY
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- 11 & 12:CHARGING PUMPS
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- 2{ ~ 22 CHARGING ~UMPS
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- 21 & 22 SAFETY INJECTION PUMPS
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CHARGING PUMP INSPECTIONS SALEM 1 1980 NO INDICATIONS
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1987 NO INDICATIONS (F.D. INSPECTlON)
1990
. '..* "#12 INDICATIONS & REPAIR INDICATIONS &
CASE REPLACEMENT NOTE:
- 12 ELEMENT CHANGED OUT IN 1984 DUE TO RESIN INTRUSION
CHARGING PUMP INSPECTIONS 1980 1988
1988
11111-aa SALEM 2
- 21
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INDICATIONS (F.D. INSPECTION)
- -. NO INDICATIONS (F.D. INSPECTION}
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ECCS:
FLOW INDICATION e
EXISTING FLOW ORIFICE PLATES.
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FLOW CONSTANT
- AS FOUND vs SPECIFIED e
NEW FLOW ORIFICE PLATES
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CHARGING
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SAFETY INJECTION
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OTHERS BASED ON SUPPLIER lDl1-24r
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~I ECCS I1fPACT ON PLANT SAFETY e
~EVALUATION OF COMBINED CHARGING AND SI FLOW C.ONDITION WHICH EXISTED 1/90
PEAK CLAD TEMPERATURE ANALYSI LARGE :BREAK LOCA NO IMPACT
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SMALL *BREAK LOCA 188~F *PENALTY
- PRESENT DESIGN *BASIS 1794 * F PENALTY 188 * F
- REVISED PCT
. 1982 * F PCT DESIGN LIMIT 2200 * F
- REVISED PCT 1982 * F MARGIN 218 * F I\\ I I
I r-...1 !,.-..,
"J ~-/ SArETY SIGNirICANCE MK1-MA
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ECCS REQUIRED ACTIONS TO SUPPORT RESTART e
SYSTEM PERFORMANCE DEMONSTRATION
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UPGRADE SURVEILLANCE TEST PROCEDURES 9"'
PUMP REPAIR/REPLACEMENT
~ NEW FLOW ORIFICE PLATES
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PUMP PERFORMANCE TESTS e
COMPLETE OEF REVIEWS e
OTHER ISSUES
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PUMP SUPPORT WELD
~ FLOW MEASUREMENT INACCURACY
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MA*NAGEMENT ME*ETING
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MAY 2, 1990
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AGENDA SALEWNRC MANAGEMENT MEETING MAY 2, 1990 INTROOUCTION
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ECCS OPERABILITY: ISSUES
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SUMMARY OF RECENT: ISSUES EQUIPMENT ISSUES PERSONNEL ERRORS PROCEDURAL INADEQUACIES OVERALL CONCLUSIONS.
TECHNICAL SPECIFICATION SURVEILLANCES CURRENT AND FUTURE INITIATIVES CLOSING COMMENTS
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S. LaBRUNA M. BANDEIRA L. K. MILLER L. K. MILLER S. LaBRUNA S. LaBRUNA
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NRC MANAGEMENT MEETING MAY 2, 1990 PSE&G MANAGEMENT ANALYSIS OF SIGNIFICANT PLANT EVENTS PRESENTED BY:
L. K. MILLER GENERAL MANAGER - SALEM OPERATIONS
IOll-Z'r-
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RECENT ISSUES S..\\LE),f GE~ER~.\\TING STATION IOU-l
- UNIT 1 SAFEGUARDS EQUIPMENT CONTROL (SEC)
CABINET FAILURE. 3/28/90
- UNIT 2 MSIV FAST CLOSURE> 5 SEC. (T/S LIMIT), 3/31/90
- REACTOR TRIP. 4/9/90
- SERVICE WATER VALVE FAILURES, 4/19/90
- RPS ACTUATION (MODE 3) ON 4/3/90
- SOLID STATE PROTECTION SYSTEM (SSPS)
FUNCTIONAL TEST 3/31/90
- ECCS FLOW RATES OUTSIDE TECHNICAL SPECIFICATION LIMITS
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- ESF ACTUATION, 3/28/90
- 2R12A RADIATION MONITOR ALARM SETPOINT e TWO YEAR REVIEWS
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SUMM~.\\RY OF RECE:\\T ISSUES EQUIPMENT ISSUES *
e UNIT 1 SAFEGUARDS EQUIPMENT CONTROL (SEC)
- CABINET FAILURE
- U/1 CONTROLLED SHUTDOWN
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SEC CHASSIS FAILED/REPLACED
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FAILED CHASSIS SENT TO VENDOR FOR ADDITIONAL INVESTIGATION e UNIT 2 MSIV FAST CLOSURE > 5 SEC. (T/S LIMITS)
3/31/90
- DESIGN DEFICIENCY
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SAFETY ANALYSIS DEMONSTRATED SAFETY LIMITS NOT VIOLATED
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DESIGN MODIFICATIONS UNDER INVESTIGATION e REACTOR TRIP, 4/9/90
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SGFP LINKAGE FAILURE
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SERT INVESTIGATION CONDUCTED
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ENHANCED PREVENTATIVE MAINTENANCE REQUIRED KMl-3
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SUMMARY OF RECENT ISSUES EQUIPMENT ISSUES (CONT)
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e SERVICE WA IER VAL VE FAILURES, 4/ 19/90 -
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DESIGN DEFICIENCY
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IMPLEMENTING DESIGN CHANGE PRIOR TO START-UP e UNIT 2 RMS - INDUCED ESF ACTUATIONS
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DESIGN DEFICIENCY
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ACTION PLAN UNCERWA Y-TO RESOLVE (NEAR-TERM DESIGN ENHANCEMENT, FUTURE EQUIPMENT REPLACEMENT)
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SUMMARY OF RECENT ISSUES PERSONNEL ERROR ISSUES e
RPS ACTUATION (MODE 3) ON 4/3/90.
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NO. 12 S/6 LOW~LOW LEVEL SIGNAL
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EVENT REVIEWED WITH OPERATIONS PERSONNEL
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UNDER REVIEW BY NTC FOR POTENTIAL TRAINING ENHANCEMENTS e SOLID STATE PROTECTION SYSTEM (SSPS)
FUNCTIONAL TEST 3/31/90
- SELF-REPORTED (NEAR MISS)
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TECHNICAL SPECIFICATION NOT VIOLATED
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HPES INVESTIGATION UNDERWAY
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SUMMARY OF RECENT ISSUES PROCEDURAL INADEQUACIES
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- ESF ACTUATION, 3/28/90
- MAIN STEAM ISOLATION DURING INSTRUMENTATION CALIBRATION
- INADEQUATE CALIBRATION PROCEDURE-PROCEDURE REVISIONS REQUIRED
- 2R12A RADIATION MONITOR ALARM SETPOINT-PROCEDURES NOT CORRECTLY UPDATED FROM 1987 UNIT 2 T/S AMENDMENT-TECHNICAL SPECIFICATION CONDITIONAL SURVEILLANCE NONCOMPLIANCE-SETPOINT CHANGE COMPLETED FOR THE CURRENT U/2 OUTAGE-PROCEDURE REVISED TO PREVENT RECURRENCE
- ECCS FLOW TESTING MISCALCULATION
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SU~f~I~-\\RY OF RECE:\\T ISSUES PROCEDURAL INADEQUACIES (CONT)
Mlll-5A
- TWO YEAR PROCEDURE REVIEWS-BEHIND ON TWO YEAR PROCEDURE REVIEW REQUIREMENT-ALL PROCEDURES UNDERGOING DETAILED REVIEW AND UPGRADE VIA PROCEDURE UPGRADE PROJECT (PUP)
-ACTION PLAN IN PLACE TO ACCELERATE TWO YEAR REVIEWS
- ALL REVISION REQUESTS REVIEWED FOR ANY SIGNIFICANT DEFICIENCIES
+MAINTENANCE PROCEDURES TO RECIEVE 2 YEAR REVIEW PRIOR TO BEING EXERCISED
~OPERATIONS PROCEDURES UNDERGOING 2 YEAR REVIEW ON EXPEDITED BASIS
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SU1\\f3I~~RY OF RECENT ISSUES
liDl1-6
- SEVERAL (5) EQUIPMENT PROBLEMS HAVE OCCURED RECENTLY:
-NO COMMON CAUSE FOUND (3 DESIGN DEFICIENCIES, 1 EQUIPMENT FAILURE; 1 IMPROPER p. M)
-THOROUGH, DELIBERATE INVESTIGATIONS PERFORMED TO IDENTIFY ROOT CAUSE AND APPROPRIATE CORRECTIVE ACTIONS
- TWO PERSONNEL ERRORS SELF IDENTIFIED
- NO COMMON CAUSE FOUND-PERSONNEL ERRORS DECREASED IN THE PAST TWO YEARS (1988 - 281 OF LEA'S)
(1989 - 231 OF LEA'S)
(1990 (YTD) - 161 OF LEA'S)
- THREE PROCEDURAL INADEQUACIES RECENTLY IDENTIFIED-PROCEDURE UPGRADE PROJECT (PUP) UNDERWAY TO CORRECT DEFICIENCIES/UPGRADE PROCEDURES-ALL THREE PROCEDURES HAO NOT UNDERGONE PUP REVIEW/UPGRADE-PROCEDURE-RELATED ERRORS HAVE DECREASED IN THE PAST TWO YEARS ( 1988 - 151 OF LEA'S)
(1989 - 111 OF LEA'S)
(1990 (YTD) - 71 OF LEA'S)
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CORRECTIVE ACTIONS e GM=SALEM OPERATIONS LETTER ISSUED TO DEPARTMENT SUPERVISORS TO BRIEF STATION PERSONNEL e GM-SALEM OPERATIONS DISCUSSED ALL EVENTS WITH STATION MANAGEMENT e SECURED ADDITIONAL MANAGEMENT RESOURCES TO SUPPORT EXTERNALLY DRIVEN ISSUES lillU-U
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KK1-7B OVERALL CONCLUSION e EQUIPMENT PROBLEMS NEED TO BE ADDRESSED IN A MORE TIMELY MANNER e ENVIRONMENTAL FACTORS DO NOT APPEAR TO HAVE*
INFLUENCED RECENT PROBLEMS e INCREASED ATTENTION TO FOLLOWUP ON CORRECTIVE ACTIONS AND COMMITMENTS e PROCEDURAL IMPROVEMENTS MUST CONTINUE AS A HIGH PRIORITY e PAST WEAKNESSES RELATIVE TO INATTENTION-TO-DETAIL CONTINUE TO SURFACE *
NO COMMON CAUSES FOUND POINTING TO ANY PROGRAMMATIC BREAKDOWN
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TECHNI~AL SPECIFICATION SURVEILLANCE* ISSUES e 2Ri2A SETPOINT ERROR
ECCS FLOW TESTING MISCALCULATIONS
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TECHNICAL SPECIFIC.~ TIO~
Sl~R\\TEILL.. ~~CE ISSUES CORRECTIVE ACTIONS e T/S AUDIT PROJECT UNDERWAY
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INITIAL AUDIT TO ENSURE.TIS SURVEILLANCES (W/>7 DAY FREQ.) ARE CAPTURED *IN MMIS (COMPLETED 2/89, REVERIFICATION IN PROGRESS)
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NO SURVEILLANCE SCHEDULING PROBLEMS SINCE JULY 1989
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REVIEW T/S AMENDMENTS TO ENSURE PROPER IMPLEMENTATION (COMPLETED BACK TO 10/88)
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REVIEW UNDERWAY OF ALL T/S SURVEILLANCE PROCEDURES TO ENSURE CORRECT SETPOINTS/
INCLUSION OF REQUIRED EQUIPMENT
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SORC REVIEW OF ALL INCOMING AMENDMENTS TO ENSURE EFFECTIVE IMPLEMENTATION (EG, PROCEDURES, ETS)
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LERs RELATED TO TIS SURVEILLANCES SHOWING DECREASING TREND IN PAST TWO YEARS (1988 - 13 LERs)
( 1989 -
7 LEAs)
(1990 YTD - 2 LERs)
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TECHNICAL SPECIFICATION SURVEILLAt~CE ISSUES CORRECTIVE ACTIONS (CONT)
e PUP PROGRAM PROVIDES IN-DEPTH REVIEW OF T/S SURVEILLANCE PROCEDURES FOR TECHNICAL ACCURACY
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795 OF 1587 SURVEILLANCE PROCEDURES REVIEWED TO DATE WITH NO T/S DISCREPANCIES FOUND
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DEFICIENT PROCEDURES IDENTIFIED NOT YET REVIEWED BY PUP
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NRC MA~JAGEivIENT MEETING MAY 2, 1990.
PSE&G MANAGEMENT. ANALYSIS OF SIGNIFICANT PLANT EVENTS PRESENTED BY:
S. LaBRUNA VICE PRESIDENT - NUCLEAR OPERATIONS
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01-10 Cl!RRENT Il'~ITIATI\\TE S
ATTENTION TO DETAIL FOCUS e
IMPROVED ROOT CAUSE ANALYSIS/HPES EVALUATION e
SERT PROCESS e
PROCEDURE UPGRADE PROJECT (PUP)
e RELIABILITY CENTERED MAINTENANCE PROGRAM e T/S AUDIT PROJECT PROGRAM e
UNIFORM WORK STANDARDS/PROCEDURE USE GUIDELINES e
MANAGEMENT/SUPERVISORY INVOLVEMENT FOCUS e SEPARATE UNIT 1 ORGANIZATION DURING UNIT 2 OUTAGE e
MANPOWER RESOURCES CONTINUALLY UNDER REVIEW
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OPERATING ENGINEER FOR EACH UNIT OTHER ADDITIONAL PERSONNEL ADDED IN PAST YEAR
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NEW INITIATIVES e
EVALUATION OF SALEM ORGANIZATIONAL STRUCTURE FOR TWO UNIT STATION e
FOCUSED APPROACH FOR MATERIAL CONDITION UPGRADE e FOCUSED COMMITMENT COORDINATION BACKLOG REDUCTION PROGRAM e CLARIFICATION OF ROLES/RESPONSIBILITIES BETWEEN SYSTEM ENGINEERS AND E&PB ENGINEERS e IMPLEMENTATION OF ENHANCED WORK PRIORITIZATION SYSTEM FOR NUCLEAR DEPARTMENT e REASSESS GC SUPPORT FOR MECHANICAL MAINTENANCE PROCEDURES e DEDICATED EFFORT TO IMPROVE PROCUREMENT AND MATERIAL CONTROL e CONTINUE REINFORCEMENT OF WORK STANDARDS/
VALUES
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RESULTS ACHIEVED e
SALEM PLANT OPERATIONS SIGNIFICANTLY IMPROVED OVER PAST YEAR
- ~ ZERO REACTOR TRIPS FOR 10 MONTHS
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IMPROVED ROOT CAUSE EVALUATIONS
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HIGHER FOCUS ON FINDING AND CORRECTING PROBLEMS e INPO RECOGNIZED IMPROVEMENT
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WORK STANDARDS
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ATTITUDE AND DESIRE TO IMPROVE
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SUPERVISORY OVERSIGHT
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PROVEN.RADIATION PROTECTION PROGRAM
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OPERATING EXPERIENCE PROGRA~
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