IR 05000354/1986047
| ML20213E581 | |
| Person / Time | |
|---|---|
| Site: | Hope Creek  |
| Issue date: | 11/06/1986 |
| From: | Norrholm L NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I) |
| To: | |
| Shared Package | |
| ML20213E549 | List: |
| References | |
| 50-354-86-47, NUDOCS 8611130221 | |
| Download: ML20213E581 (34) | |
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{{#Wiki_filter:. U. S. NUCLEAR REGULATORY COMMISSION
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REGION I
050354-860703 050354-860725 Report N /86-47 050354-860729 050354-860739 Docket 50-354 050354-860801 050354-860801 License NPF-57 050354-860803 050354-860804 Licensee: Public Service Electric and Gas Company 050354-860804 050354-860805 Facility: Hope Creek Generating Station 050354-860808 050354-860808 Conducted: September 9, 1986 - October 13, 1986 050354-860808 050354-860814 I Inspectors: R. W. Borchardt, Senior Resident Inspector 050354-860816 D. K. Allsopp, Resident Inspector 050354-860820 R. J. Summers, Project Engineer 050354-860822 050354-860828 ( 050354-860831 050354-860906
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// 6 L. N@r,hpIm, Chief, Reactor Projects / Dste SedtiVn 2B Inspection Summary:
Inspection on September 9, 1986 - October 13, 1986 (Inspection Report . Number 50-354/86-47) Areas Inspected: Routine onsite resident inspection of the following areas: operational safety verification, surveillance testing, maintenance activities, inspection of General Electric type AK-F-2-25 breakers, engineered safety feature system walkdown, licensee event report followup, and loss of offsite power testin This inspection involved 283 hours by the inspector Results: Review of the Loss of Offsite Power (LOP) test conducted on September 11, 1986 identified a number of design errors and equipment malfunctions that were of significant concern to the NRC. As a result of these concerns, an Augmented Inspection Team (AIT) was dispatched to the site to assess the anomalies related to the LOP tests. The results of AIT , ' inspection will be documented in Inspection Report 50-354/86-50. Of particular concern was the design error which caused the safety relief valve acoustic monitors to be powered from a non-reliable source. This error caused the unit to be operated in apparent violation of Technical Specifications in that the acoustic monitors would not have functioned in a loss of offsite power condition. Further details on this apparent violation can be found in section 2.3 of this repor This matter will be discussed at an Enforcement Conference.
l l 8611130221 861107 gDR ADOCK 05000354 PDR
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Details 1. Persons Contacted
. Within this report period, interviews and discussions were conducted I with members of the licensee management and staff and various contractor personnel as necessary to support inspection activit . Operational Safety Verification 2.1 Documents Reviewed
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Selected Operator's Logs
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Senior Shift Supervisor's Log
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Jumper Log
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Radioactive Waste Release Permits (liquid & gaseous) Selected Radiation Work Permits (RWP)
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Selected Chemistry Logs
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Selected Tagouts
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Health Physics Watch Log 2.2 The inspectors periodically toured the plant during regular and backshift periods. These tours included the control room, reactor, auxiliary, turbine and service wat~r buildings, and the drywell (when access is possible). During the inspection, discus-sions were held with operators, technicians (HP & I&C), mechanics, i supervisors, and plant management. The purpose of the inspection was to affirm the licensee's commitments and compliance with 10 CFR, i Technical Specifications, and station procedure (1) On a daily basis, particular attention was directed to the following areas: i
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Instrumentation and recorder traces for abnormalities;
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Adherence to LCO's directly observable from the control room;
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Proper control room shift manning and access control;
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Verification of the status of control room annunciators that are in alarm;
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Proper use of procedures;
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Review of logs to obtain plant conditions; and,
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Verification of surveillance testing for timely completio ._ ---_ ~ _ .- .
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(2) On a weekly basis, the inspectors confirmed the operability of selected ESF trains by: -
Verifying that accessible valves in the flow path were in the correct positions;
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Verifying that power supplies and breakers were in the correct positions;
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Visually inspecting major components for leakage,
, lubrication, vibration, cooling water supply, and general operating conditions; and, -
Visually inspecting instrumentation, where possible, for proper operabilit (3) On a biweekly basis, the inspectors:
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Verified the correct application of a tagout to a safety-related system;
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Observed a shift turnover;
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Reviewed the sampling program including the liquid and gaseous effluents;
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Verified that radiation protection and controls were properly established;
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Verified that the physical security plan was being implemented;
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Reviewed licensee-identified problem areas; and,
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Verified selected portions of containment isolation lineu .3 Inspector Comments / Findings: The unit entered this report period in operational condition 1 with reactor power at approximately 35% while conducting power ascension testin On September 11, 1986, a " Loss of Offsite Power" (LOP) Test (TE-SU.ZZ-311(Q) Revision 2) was commenced as part of the power ascension test program. This test simulates a total loss of offsite power by simultaneously opening the appropriate circuit breakers on the 13.2 KV ring bus and tripping the main turbin The plant's automatic response is then evaluated, including the fast transfer of selected buses to emergency DC power, the starting and loading of all four emergency diesel generators
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(EDG), and the automatic sequencing of loads needed to respond to the resulting scram. At 8:06 p.m. the LOP test was initiated from approximately 20% reactor power. The reactor plant's response to the resulting transient was within design limits. However, because cooling water flow to the drywell coolers was lost, the Senior Nuclear Shift Supervisor (SNSS)
aborted the test at 8:10 p.m. and had offsite power restored to the site distribution syste Cooling water flow was lost due to the tripping of the reactor auxiliary cooling system (RACS) pumps. In addition to the loss of RACS, other problems identified during the test include: the failure of the "C" EDG output breaker to automatically close and supply power to the "C" 1E bus, the sustained loss of power to the safety relief valve acoustic monitor panel, the failure to receive a " full-in" indication for 17 control rods on the full core display, the failure of the "B" safety auxiliary cooling system (SACS) pump to restart, and the loss of reactor building ventilation. A description of this event and the actions taken to correct the noted discrepancies is detailed in Augmented Inspection Team Inspection Report 50-354/86-5 During the investigation into the identified LOP test discrepancies, it was determined that the safety relief valve acoustic monitor panel was powered from a Non-1E, non-uninterruptible power supply source. This is contrary to operability requirements of Technical Specifications, Regulatory Guide 1.97 " Instrumentation for Light Water-Cooled Nuclear Power Plants to Assess Plant and Environs Conditions During and Folicwing an Accident", and Table 7.5-1 of the Final Safety Analysis Report (FSAR). The acoustic monitoring system provides position indication of individual safety relief valves (SRV) based upon the noise level in the SRV tail pipe. When an r SRV is open, the resulting steam flow causes an increase in noise , level, sending the acoustic monitoring channel inte alarm and provi-ding an open SRV indication. The acoustic monitor is designated in ! Technical Specifications as a post accident monitoring instrument and therefore must be operable under a loss of offsite power condition in order to perform its intended function. Table 3.3.7.5-1 of Technical Specification 3.3.7.5 requires the acoustic monitors to be operable in operational conditions 1, 2, and Contrary to this requirement, the acoustic monitor was incapable of performing its intended func-tion under a LOP condition. This condition had existed from opera-
- ting license issuance until September 17, 1986. The licensee was informed that this constituted an apparent violation. (86-47-01)
Additional information on the loss of offsite power test and the subsequent retests can be found in paragraph 8 of this report, and Inspection Reports 50-354/86-46 and 50-354/86-50.
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The unit remained shut down from September 12 to October 9, 198 During this outage, the licensee conducted an investigation into the causes for the LOP discrepancies and took corrective action In addition to the LOP related activities, the service water pipe elbows at the safety auxiliary cooling system heat exchangers were replaced and routine short outage activities were conducte At 6:50 p.m. on October 2, 1986, the control room ventilation radiation monitor power supply breaker tripped which caused the
"B" train of control room emergency filtration (CREF) to initiat Power was restored to the radiation monitor and all ventilation systems returned to norma On October 4,1986, two post accident sampling system (PASS)
valves failed their local leak rate tests (LLRT). The licensee's inve:tigation determined that valves, 0-RC-SV-0707 A and B, were improperly heat traced such that the 150 degrees F design temperature was exceeded. The valves were actually maintained at temperatures as high as 300 degrees F. The excessive temperatures caused a deterioration of the valve seals which in turn caused the valves to fail the LLRT. Further review determined that a total of 8 PASS valves had been subjected to excessive temperatures. The licensee completed repairs to the subject valves, corrected the heat trace problems, and successfully conducted LLRTs on all 8 valves. The inspector witnessed portions of these activities as documented in paragraph At 11:00 a.m. on October 5, 1986, the "B" train of control room emergency filtration automatically started during I&C troubleshooting of a control room ventilation radiation monito The isolation was reset and an ENS notification made at 1:40 p.m.
l l At 3:25 p.m. on October 5, 1986, the "B" emergency diesel generator started for an unknown reason. Because the B vital bus remained energized from offsite power the diesel generator was not loaded. After assuring proper operation of the diesel generator, it was secure The licensee investigated the cause of the spurious start, but was unable to determine the caus Special monitoring equipment was installed to monitor the diesel start circuit but a spurious start has not recurre At 6:03 p.m. on October 9, 1986, the reactor was taken critical in preparation for performing the critical loss of power (LOP) test. The LOP test was delayed when the 12 inch, startup feed-water control valve actuator required replacement. The valve had failed open when a positioner failed which caused a 60 ir.h reactor vessel water level increase.
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At 1:30 a.m. on October 10, the reactor water cleanup (RWCU) system isolated when flashing occurred in the reference leg of the pump suction flow transmitter causing the differential flow rate meters to peg high. The isolation was reset and the RWCU system returned to normal. The inspectors will review the licensee's determination of the cause of this event when the LER is submitte A loss of offsite power (LOP) test was conducted from approximately 20% power on October 11. All Level 1 and Level 2 acceptance criteria were met and although a number of observations were made, the licensee determined that no problems were due to Bailey 862 logic modules. The test was witnessed, and results reviewed by resident and region based inspector After successful completion of the LOP test, NRC Region I authorized a plant restart for test condition - 3 power ascension testin The unit was brought critical at 9:23 a.m. on October 12, and placed in operational condition 1 at 3:00 p.m.. The plant was operating at 20% power while conducting pressure regulator control valve testing at the conclusion of this report perio . Surveillance Testing During this inspection period the inspector performed detailed technical procedure reviews, and reviewea: in progress surveillance testing, as well as, completed surveillance packages. The inspector also verified that the surveillance tests were performed in accordance with licensee approved procedures and NRC regulations. The inspector also verified that the instruments used were within calibration tolerances and that qualified technicians performed the surveillance tests.
, The following surveillance tests were reviewed, with portions witnessed by the inspector:
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IC-CC.BF-005 Channel Calibration of the Scram Discharge Volume
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MD-ST.PK-003 Service Test on 125 VDC Batteries (IE)
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IC-FT.BB-005 Division Three Level One Trip Test on Residual Heat Removal and Core Spray Systems No violations were identifie . Maintenance Activities During this inspection period the inspector observed selected maintenance activities on safety related equipment to ascertain that l these activities were conducted in accordance with approved procedures, Technical Specifications, and appropriate industrial codes and standard __ .
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Portions of the following activities were observed by the inspector: Work Order Procedure Description 86-09-21-014-6 1C-GP.ZZ-031 Verification of 86-09-21-016-2 Bailey 862 logic modules 86-09-29-178-2 M9-ILP-302 Type "B" Local Leak 86-09-29-175-8 Rate Testing on 86-09-29-174-0 Electrical Penetra-86-09-29-170-7 tion 10C240 86-09-29-169-3 86-09-29-168-5 86-09-29-167-7 86-09-29-166-9 86-09-29-165-1 86-09-29-137-5 .
, 86-09-29-121-9 86-10-04-095-0 DR-HMD-86-570 Repair to Post Accident Sample System Return Line to the Suppression Pool Isolation Valv (0-RC-RV.0707 B)
No violations were identifie . Inspection of General Electric Typ_e__AK-F-2-25 Breakers (Region I Temporary Inspection Instruction RI-86-02) , Pilgrim Generating Station has experienced four failures of General I Electric (GE) type AK-F-2-25 breakers to open upon demand during the last three years. At Pilgrim, these breakers are used as the recirculation pump motor generator exciter field breakers. These l breakers trip to satisfy the recirculation pump trip (RPT) feature needed to mitigate the anticipated transient without scram (ATWS).
The inspector was requested to provide information relating to the RPT , function at Hope Creek and to determine if the GE AK-F-2-25 breakers i are used at Hope Creek.
l A review of the licensee's procurement records and a check of installed equipment indicates that the only application of a GE type AK-F-2-25 breaker at Hope Creek is for the main generator field control breaker. This is not a safety related function. The ATWS - RPT system at Hope Creek provides a method of mitigating the con-sequences of a failure of the control rods to scram in response to an anticipated transient. The recirculation pump motors are tripped by the redundant reactivity control system (RRCS) logic, which reduces core l
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flow and creates core voids thereby decreasing reactor power level The recirculation system pumps are tripped immediately upon a high reactor pressure signal or 9 seconds after a level 2 low water level signal is received. The RPT function is accomplished by tripping the two recirculation pump main power breakers that are located between the motor generator sets and each recirculation pump motor. These breakers are 4.16 KV SHK350 Brown Boveri Electric, Inc. breakers and designated as 1AN205, 1BN205, ICN205 and IDN20 These Brown Boveri breakers have 2 independent trip coils, one of which is actuated by the RPT function from the RRCS and the other tripped by the manual trip function and the end of cycle recirculation pump trip feature. The licensee has not experienced any failures of these breakers during their short operating period. The licensee has established preventative maintenance procedures MD-PM.PB-001 "4.16 KV Breaker Cleaning and P.M." and MD-PM.PB-002 "4.16 KV Breaker Time Response" which are scheduled for performance at least once per 60 month ~ Technical Specification 3.3.4.1 requires the instrumentation associated with the RPT function to be periodically tested and a logic system functional test to be performed at least once per 18 month This requirement is implemented by surveillance tests OP-ST.BB-003
"ATWS - RPT Simulated Auto Actuation - 18 Month" and IC-FT.ZZ-007 " Master Logic System Functional Test ATWS Recirculation Pump Trip".
These tests were successfully completed prior to initial criticalit . Engineered Safety Feature (ESF) System Walkdown The inspectors verified the operability of the 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 configuration. This 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 During the inspection of the safety auxiliary cooling system, the inspector identified a concern pertaining to the accuracy of the system P&ID. In particular, for some branch connections, the as-built configuration did not agree with the P&ID. This concern will be followed up during the next inspectio No violations were identifie . Licensee Event Report Followup The licensee submitted the following event reports during the inspection period. All of the reports were reviewed for accuracy and timely submission. The asterisked reports received additional followup by the inspector for corrective action implementatio _ . _
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LER 86-033-01 Inadvertent "B" Channel LOCA Signals During Instrument Calibration Performance
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LER 86-044-00 Reactor Scram on Low Level Resulting From an EHC Transient LER 86-047-00 Actuation of the Control Room Emergency Filtration System Due to Radiation Monitor Spike LER 86-048-00 Full Reactor Scram on Low Water Level LER 86-049-00 Missed Response Tine Surveillance Due to Procedure Inadequacy LER 86-050-00 Reactor Water Cleanup System Isolation on High Differential Flow LER 86-051-00 Reactor Water Cleanup Isolation on Spurious High Temperature Trip LER 86-052-00 Violation of the Surveillance Requirements for the Suppression Pool Temperature Monitoring System
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LER 86-053-00 "A" Channel LOCA Logic Actuation
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LER 86-054-00 "A" Channel LOCA Logic A:tuation and Full Reactor Scram !
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LER 86-055-00 Primary Containment Isolation Due to Procedure Inadequacy j
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LER 86-056-00 Inoperable Reactor Building to Torus Vacuum Breakers LER 86-057-00 Inadvertent Actuation of the "A" Channel NSSSS Isolation Logic LER 86-058-00 Failure to Sample Resulting in Technical Specification Violation
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LER 86-059-00 "B" Channel ESF Logic Actuation LER 86-060-00 Violation of Suppression Pool level Technical Specification
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LER 86-063-00 ASCO Solenoid Valve Air Supply Pressure Rating
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l LER 86-064-00 Reactor Scram on Low Level
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LER 86-065-00 Full Reactor Scram on Low Reactor Water Level 3 LER 86-44 describes I&C testing on the main turbine stop valve which resulted in all main turbine bypass valves going full open and a subsequent reactor scram. Details of this event are discussed in Paragraph 3.3 of NRC Inspection Report 86-36 LER 86-53 describes an inadvertent actuation of the "A" Channel Loss of Coolant Accident (LOCA) logic from an invalid reactor vessel low water level signal. All Emergency Core Cooling Systems (ECCS) and Engineered Safety Feature (ESF) equipment initiated and performed as designed. The root cause of this event was personnel error on the part of the I&C technician when he improperly performed a valve position check during a time response test of a level transmitte The licensee's corrective actions include training for the individual I&C technician involved, and a review for adequacy of I&C training for determining valve positio , LER 86-54 details the events which resulted in a full reactor scram while backfilling reactor level instrument sensing lines to reduce oxygen content. The scram occurred when a "81" Channel scram signal from surveillance testing was coupled with an "Al" Channel scram signal which was generated while backfilling the wrong instrument sensing lire. All ECCS and ESF equipment performed as designed. The root cause of this event was personnel error on the part of the I&C Planning Group and an I&C Supervisor in that the proper precautions and prerequisites were not included in the procedure special instructions. The licensee's corrective action included counseling
- the I&C personnel involved. Since this was a "one-time only" procedure, no procedural changes were necessary.
~ LER 86-55 describes an "A" Channel Primary Containment Isolation. The , licensee's corrective action include a specific step to be added to existing procedures to reset the low level seal-in menary prior to ' procedure performance. Also, a Design Change Package (DCP) has been requested to provide an indication in the control room of memory set statu Details of this event are discussed in Paragraph 3.3 of NRC Inspection Report 86-36.
l LER 86-56 outlines the events which resulted in the reactor building to torus vacuum breaker being inoperable. This event is discussed in detail in NRC Inspection Report 86-4 LER 86-59 describes an inadvertent actuation of the "B" Channel i Engineered Safety Feature (ESF) logic and the "B1" Channel Scram
- logic. All operable ESF equipment associated with this channel
, performed as designed. No water was injected into the vessel during l this event. The root cause for this event is unknown. This is the ! first unexplained level actuation to occur since implementation of I corrective actions detailed in LER 86-39-00. The licensee is !
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installing equipment to monitor all LOCA logic channels to determine if other factors should be addressed to preclude recurrence. Since prior spurious ESF actuations resulted in an NRC followup item, this event will be included as part of that ite LER 86-61 describes a spurious high pressure coolant injection system level 2 initiation signal from the "A" Channel reactor vessel level instrumentation. All auxiliary equipment actuated as designed, but no water was required to inject into the reactor vesse The root cause has been identified as a hydraulic transient within the common reference sensing line initiated by the drawing of a reactor coolant sample from the post accident sample system (PASS). The licensee's corrective action was to revise the PASS sampling procedure to include valving out a reactor level transmitter connected between the sample line and common reference line prior to taking a sampl LER 86-63 describes the inoperability of 12 ASCO air operated solenoid valves used in the containment atmosphere control system and the
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safety auxiliary cooling syste This event is discussed in detail in Paragraph 2.3.7 of NRC Inspection Report 86-4 LER 86-64 details the events which resulted in a reactor scram which occurred from a valid level 3 signa The low reactor water level was the result of a level 8 feedpump trip which resulted from starting a second secondary condensate pump. Details of this event are discussed in Paragraph 2.3.8 of NRC Inspection Reoort 86-40.
' LER 86-65 describes a full reactor scram from a valid reactor low water level 3 signal while placing the "C" reactor feedpump (RFP) in service and removing the "A" RFP from service. The root cause of this event was unstable control of the "C" RFP because tuning of the associated controller had not been completed. Details of this event are discussed in Paragraph 2.3.9 of NRC Inspection Report 86-4 During the LER review, it was noted that four LER events (86-049, 86-052, 86-058, and 86-060) constitute Technical Specification violation However, these LERs are not being cited as violations as they meet the following 10 CFR 2 Appendix C criteria: 1) The events were licensee identified; 2) The events fit severity level four or five; 3) The events were reported; 4) The events were or will be corrected, including measures to prevent recurrence, within a reasonable time; and 5) The events were not a violation that could reasonably be expected to have been prevented by the licensee's corrective action for a previous violatio _ __.____
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12 Loss of Offsite Power Testing On September 11, 1986, the licensee conducted a loss of offsite power (LOP) test (TE-SU.ZZ-311(Q) Revision 2) in accordance with the power ascension test program. As stated in section 2.3 of this report, this test simulates a total loss of offsite power by simultaneously opening the appropriate circuit breakers on the 13.2 KV ring bus and tripping the main turbine from an initial condition of 20% reactor power. The plant's automatic response is then evaluated, including the fast transfer of selected buses, the starting and loading of all four emergency diesel generators (EDG), and the automatic sequencing of loads needed to respond to the resulting scram. As a result of this test, a number of observations were made by control room operators and test observers that required evaluation, and in some cases corrective actions by the license On September 19, 1986, a meeting was held between Public Service Electric anc Gas Company, the NRC Region I staff, and representatives from Inspection and Enforcement and Nuclear Reactor Regulation at the Hope Creek Generating Station site at Hancocks Bridge, New Jerse The purpose of the meeting was for PSE&G to discuss test results and corrective actions generated as a result of the loss of offsite power (LOP) test conducted on September 11. The more sigr.ificant problems identified during the LOP included:
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A design error resulting in the reactor building supply and exhaust fan damper drives not being supplied from a IE power sourc A design error resulting in the acoustic monitors not being supplied from a 1E or uninterruptible power sourc A design error allowing the reactor auxiliary cooling system (RACS) to pump water to the chill water system until the RACS pump tripped on low head tank level, and a subsequest loss of cooling water to the emergency instrument air compressor after the RACS pump trippe The "C" emergency diesel generator output breaker failed to automatically shut on receipt of a LOP signal after the diesel was ready to receive loa During the evening of September 19, the licensee condt:cted a LOP test from a reactor shutdown initial condition and identified a number of additional observations. The majority of these new observations were not identified during the initial LOP test because the September 11 LOP was terminated after only 4 minutes. The September 19 test was run for approximately 30 minutes which allowed for a more thorough review of plant respons .__ _ _ _ _ _ . . _ _ _ _ _
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On September 24, 1986, a Confirmatory Action Letter (CAL No. 86-12) was issued to the licensee to inform them that an Augmented Inspection Team (AIT) was being dispatched to the Hope Creek site to assess the anomalies related to the LOP tests. The CAL also confirmed that the licensee would take the following actions:
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Defer any additional LOP integrated testing until the NRC AIT team leader determines that such testing can continu Provide any LOP test procedures to the NRC AIT for their review prior to implementatio Make available to the NRC AIT relevant written material related to deficiencies identified during the LOP tests conducted on September 11 and 19, 1986, including: preoperational test results surveillance test results
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Provide a written report to the Regional Administrator prior to restart that includes an analysis of the LOP testing conducted on September 11 and 19, 198 Receive Regional Administrator authorization for Unit startu The AIT conducted their inspection from September 24 - October 3 and
- documented the findings in Inspection Report 50-354/86-5 .
After receiving authorization from the AIT team leader, a second non-critical LOP test was conducted on October 2, 198 TE-SU.ZZ-313(Q) Revision 1, "Non-Critical Loss of Offsite Power Test" was successful in that it satisfied all level 1 and level 2 acceptance criteri In addition to the original LOP test scope, the October 2 test verified the proper operation of a sample of Bailey 862 logic module functions not previously tested. Based upon the satisfactory test results, on October 7, 1986, the CAL was modified and the NRC authorized a plant startup in order to conduct a
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reactor critical LOP tes On October 11, 1986, a LOP test was conducted from approximately 20% reactor power. Witnessing of the test and a review of the test results indicated that all level 1 and level 2 acceptance criteria were met. Although thirteen observations were recorded during this test, the inspector's review determined that these comments were generally of minor significance and did not impact the acceptability of the test results. The licensee submitted an October 11, 1986 letter to Region I, requesting that, based upon the satisfactory test results obtained, the CAL be further modified to authorize a plant restart to permit continuation of the power ascension program. The specific tests to be conducted were outlined in this submittal. On i !
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October 16, 1986, a second modification was made to the CAL which authorized a plant startup to conduct the power ascension tests described in the PSE&G October 11 lette On October 15, 1986, a meeting was held between the NRC and PSE&G at the Region I headquarters. The purpose of this meeting was to discuss the results of the LOP test and to develop a mutual understanding relative to the licensee's plans for testing of the Bailey 862 modules. The list of attendees and handouts provided by the licensee at this meeting are provided as enclosure 1 to this repor In an October 15, 1986 letter, the licensee detailed the following commitments made during the Region I meeting:
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Provide an in-house data assessment program which includes a review of each in plant module failure and a determination by the manufac-turer of the individual component which failed and, to the degree possible, the cause of the failur Conduct an assessment, by the manufacturer, of module failures at installations of other user Complete an accelerated aging and cycling test program, with a final reliability analysis report by the end of the second quarter of 198 Trend by month and provide a report bi-monthly indicating: the number of module failures having an adverse affect on system function; resulting time in an LC0; and the number of failures determined by surveillance. This program will apply to both IE and non-1E system Provide a report of Bailey's recommendations to improve module reliability based upon their observations at Hope Creek of site environment, handling, and testing technique Modify the existing module test equipment and procedures to permit module testing without staple jumper removal by mid-November 198 l
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Develop and procure a test rig capable of bench testing modules for all utilized functions prior to November 1987. Testing would be conducted without removing staple jumpers or the FPL Determine the feasibility and implications of mcdifying the existing Bailey system to permit in-situ testing.
' Conclusion Based upon the above committments and discussions between NRC Region I and PSE&G on October 17, 1986, a letter terminating the Confirmatory Action , Letter was issued on October 21, 1986. This allowed normal operations and power ascension testing to resume in accordance with the licens _ _ _ _ _ _- . -
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The design errors, apparent during the initial LOP, had been corrected by the licensee. An enforcement conference will be held in Region I to discuss this and similar ' design implementation problems identified previously (reference NRC Special Inspection Report 50-354/86-41). Exit Interview The inspectors met with licensee and contractor personnel periodically and at the end of the inspection report to summarize the scope and findings of their inspection activities. Written material was not provided to the licensee during the exi Based on Region I review and discussions with the licensee, it was determined that this report does not contain information subject to I 10 CFR 2 restrictions.
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Enclosure 1 October 15, 1986 Meeting Between PSE&G and NRC Region I List of Attendees . Name Title Organization T. Murley Regional Administrator NRC Region I W. Kane Director, Division of Reactor Projects NRC Region I S. Collins Deputy Director, Division of Reactor NRC Region I Projects , S. Ebneter Director, Division of Reactor Safety NRC Region I L. Norrholm Chief, Reactor Projects Section 2B NRC Region I R. Gallo Chief, Reactor Projects Branch 2 NRC Region I J. Wiggins Chief, Material & Processes Section NRC Region I L. Bettenhausen Chief, Operations Branch NRC Region I R. Borchardt Senior Resident Inspector, Hope Creek NRC Region I R. Summers Project Engineer NRC Region I T. Koshy Reactor Engineer NRC Region I H. Garg Electrical Engineer NRC/NRR/EICSB M. Srinivasan Chief EICSB/ BBL /NRR R. Green Nuclear Engineer N.J. Dep Bureau of Nuclear Engineering C. A. McNeill Vice President - Nuclear PSE&G R. Burricelli General Manager-Engineer & Plant PSE&G Betterment l S. Funsten I&C Engineer PSE&G l J. Hagan PS - Maintenance Manager - HC0 PSE&G l G. Tenenbaum Principal Engineer PSE&G i B. Preston Manager - Licensing & Regulation PSE&G l R. Drewnowski Manager-Nuclear Systems Engineering PSE&G
- J. Nichols Technical Manager - Hope Creek PSE&G l M Farschon Power Ascension Manager - Hope Creek PSE&G M. Massaro Nuclear Systems Engineer PSE&G G. Peet Single Point Contact Engineer PSE&G l
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Enclosure 1 3
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to Report 50-354/86-47-AGENDA-NRC/ REGION I/PSEEG - HOPE CREEK GENERATING STATION MEETING OCTOBER 15, 1986 i SECOND CRITICAL LOP I BAILEY SOLID STATE LOGIC MODULES APPLICATION AND FUNCTION COMPARISON TO RELAY APPLICATIONS FAILURE ANALYSIS TOTAL RELAY EQUIVALENT ' STAPLE ANALYSIS RECOMMENDATIONS MONITOR RELAY EQUIVALENT FAILURE -
- SHORT TERM TESTER LONG TERM TESTER POTENTIAL FOR ON-LINE TESTING RELIABILITY PROGRAMS I II STATUS OF CONFIRMATORY ACTION LETTER
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BAILEY SOLID STATE LOGIC MODULE TOPICS
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APPLICATION AND FUNCTION OF SSLM
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COMPARISON OF EQUIVALENT RELAY APPLICATION RELIABILITY ANALYSIS TO DATE .,
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RELIABILITY PROGRAM
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IMPROVED SSLM TESTING PROGRAM
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862 SOLID STATE SYSTEM ENHANCEMENTS
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MOV OVERLOAD / POWER FAILURE PROVIDES: VARIOUS INDICATION ON RSP TAKE-DVER, CONTROL POWER, DVERLOAD, AND BUS POWER FAILURE 170 CLASS 1E MODULES
---
MOTOR MALFUNCTION DETECTION PROVIDES: FLASHING STOP LIGHT ON UNCOMMANDED EQUIPMENT STOP FLASHING PROCESS VARI ABLE LIGHT FLASHING START LIGHT ON AUTO START FAILURE 103 TOTAL, 37 CLASS 1E
--- CIRCUIT BREAKER MALFilNCTION PROVIDES:
STEADY OR FLASHING DVLD BUS POWER FAILURE LIGHT ON BPF' OR PHASE FLASHING INOP LIGHT ON BREAKER OPEN WITH NO UPERATING STATUS (BREAKER CONTROL POWER OPERATING POSITION AND TESTSWITCHPOS1110N)ANDSPRINGCHARGEDINPUT FLASHING INOP LIGHT ON BREAKER CLOSED WITH NO TRIP COIL CONTINUITY 125 MODULES, 44 CLASS 1E
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BAILEY 862 SSLM RELIABILITY ANALYSIS
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REVIEW ALL ON SITE MODULE FAILURE
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TRACK PLANT APPLICATION
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--- VERIFY RELIABILITY OF SSLM IN LONG TERM --. COMPLETION SCHEDULE 2ND QUARTER 1987 l
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HARD COPY DOCUMENTATI0!4 0F RESULTS
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% - - - , . - . - - - - - . ,.. - . - . , . . , , - - - - . , .- - . , - - - . - , - - - ,, -,--n.- - - , - , , , . - - -
_ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ . _-.
.
.
BAILEY LOGIC MODULE RELAY EQUIVALENT 1988 Data 0.9 - 0.8 -
- ' % '
0 0.6 -
*
a 0.5 -
g 0.4 - b 3 0.3 - .2 - i , , i i i i i i i , , , i i i i i i JAN FEB MAR APR MAY JUN JUL AUG SEPT OCT
-
O TOTAL OF ALL CABS
. _ _ _ _ _ _ _ _ _ _ _ _ _ _ _
~~
. p ,O
-
.
BAILEY LOGIC MODULE RELAY EQUIVALENT
'
ACCUMUIATED FAILURES PER THOUSAND - 17 + + + + + + + + + + , 16 -
i 15 - l l 14 - l 13 - 12 - $o 11 -
- -
i\ 10 -
- r) '
-
- ;O
'" 8 -
t il ,
, 7 - >
j 8 -
- $ 5 - -
.
!* 4 - i j 3 - ,
- 2 - {
- 1 -
! 0 , , , , , , , , , , , , , , , , , , , MAR APR MAY JUN JUL AUG SEPT OCT NOV DEC i I
* PER IEEE 500 1984 FOR GEN REIAYS f O BAILEY LOGIC MODULE + GEN RELAY FAILURE
.
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