IR 05000293/1993015
| ML20059B341 | |
| Person / Time | |
|---|---|
| Site: | Pilgrim |
| Issue date: | 10/15/1993 |
| From: | Eugene Kelly NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I) |
| To: | |
| Shared Package | |
| ML20059B331 | List: |
| References | |
| 50-293-93-15, NUDOCS 9310280148 | |
| Download: ML20059B341 (23) | |
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U. S. NUCLEAR REGULATORY COMMISSION
REGION I
Docket No.: 50-293 Report N Licensee: Boston Edison Company 800 Boylston Street Boston, Massachusetts 02199 Facility: Pilgrim Nuclear Power Station Location: Plymouth, Massachusetts Dates: August 17 - September 27,1993 Inspectors: J. Macdonald, Senior Resident Inspector '
A. Cerne, Resident Inspector D. Kern, Resident Ins ector Approved by: W E. Kelly, f Date Reactor Pr cts Section 3A /
Scope: Resident safety inspections in the areas of plant operations, radiological controls, maintenance and surveillance, emergency preparedness, security, safety assessment and quality verification, and engineering and technical support. Initiatives selected for inspection included detailed evaluation of six LER's, corrective actions and multi-disciplinary team (MDAT)
recommendations to address recirculation pump speed runbacks, configuration control (including locked valve status) of the standby liquid control system, and BECo preparations for hurricanes, inspections were performed on backshifts during August 18, 23-26 and September 2, 7, 9,13, ;
14,16, 21-23, and 27. " Deep" backshift inspections were performed on August 28 (10:50 p.m. - 12:00 midnight), and August 29 (00:01 - 4:05 a.m.), September 19 (5:30 - 9:30 p.m.),
September 20 (00:05 - 5:00 a.m.), and September 24 (00:01 - 5:30 a.m.).
Findings: Performance during this six week period is summarized in the Executive Summar .
9310280148 931020 W
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EXECUTIVE SUMMARY Pilgrim Inspection Report 93-15 Plant Operations: The fire watch report of smoke in the upper switchgear room and operator actions in response to a shorted 4 KV switchgear bus indicating po::ntial transformer were excellent. Prempt action and assessment ensured that safety related power supplies were not damage Maintenance, operations, and system engineers effectively communicated to coordinate repair and inspection of the switchgear, and completion of other maintenance activities during the subsequent shutdow Operator response to the September 10th lightning strike that caused a loss of 345 KV off-site power was excellent. The Nuclear Watch Engineer demonstrated a strong safety perspective in _
delaying the transfer of safety related buses A5 and A6 to the startup transformer until the second 345 KV power supply had been restore Maintenance and Surveillance: Replacement of the leaking pilot valve for safety relief valve RV-203-3 A was well controlled. The post-work test, including validation and training on a new procedure, was thorough and well coordinate Engineering: Unanticipated recirculation pump speed runbacks had been experienced since startup from refueling outage No. 9. Several temporary modifications were installed and a multi-disciplined analysis team (MDAT) was established to assess the root cause. The MDAT methodically identified a causal component (the GEMAC speed limiter module) using systematic troubleshooting and thorough root cause analysi Licensee event reports continue to be excellent, including detailed documentation of root cause evaluations and corrective actions. Engineering support of follow-up corrective actions was typically of high quality. However, on several occasions this past year, field wiring was found to be inconsistent with controlled reference electrical drawings. This has in some cases resulted in safety related components being declared inoperabl Plant Support: Comprehensive security preparations and close monitoring were employed during a rally staged near the site on August 21. Licensee procedures, equipment, and training were found to fully support station operations in the event of a hurrican ii
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' SUMMARY OF FACILITY ACTIVITIES . .... .........
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PLANT OPERATIONS (71707,40500,90702,92701) ....... ...... 2 .......... .
. .2 Plant Operations Review . . . . Reactor Shutdown ...
4 to Repair Fa 4 ~ M AINTEN ANCE AND SURVEILLANCE ..............(62703,61726)
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5 ....... .2 Replacement of Leaking Safety Relief .
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ENGINEERING (37828, 71707, 927(X)) . . . .
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7 Recirculation Pump Speed Oscillations ...........
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Licensee Event Report Review 13 .....
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PLANT SUPPORT (71707, Tl 2500/28). . . ........ 13
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... Security Preparations
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Hurricane Preparations . . . . . . . . . . . .
Employee Concerns Program 16 IES (30702) .......
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..... .... MANRoutineAGEMENT Meetings . .
MEETINGS AND OTHER
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Management Meetings ................ . . . . . . . Other NRC Activities . . . . . . . .
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TABLE OF CONTENTS EXECUTIVE SUMMARY ,........,............................ ii TABLE OF CO.NTENTS .......................................iii SUMMARY OF FACILITY ACTIVITIES ........................ 1 PLANT OPERATIONS (71707,40500,90702,92701) ................ 1 Plant Operations Review . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1 Reactor Shutdown to Repair Failed Potential Transformer . . . . . . . . . . . 2 MAINTENANCE AND SURVEILLANCE (62703, 61726) . . . . . . . . . . . . . . 4 Replacement of Leaking Safety Relief Pilot Valve ............... 4 Standby Liquid Control (SLC) System Con 6guration Control ........ 5 ENGINEERING (37828, 71707, 92700) . ..... ........ ....... 6 Recirculation Pump Speed Oscillations ... . .. ............. 6 Licensee Event Report Review . ... . . .. ............. 7 PLANT SUPPORT (71707, TI 2500/28) ........................ 13 Security Preparations ................................ 13 Hurricane Preparations . . . . . . . . . . ....... ............ 13 Employee Concerns Program ........... ............... 15 MANAGEMENT MEETINGS AND OTHER ACTIVITIES (30702) .... .. 16 Routine Meetings .................... ............. 16 Management Meetings ... ....... ................... 16 Other N RC Activities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .. . . 1 ,
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DETAILS
1 SUMMARY OF FACILITY ACTIVITIES At the start of the report period Pilgrim Nuclear Power Station was operating at approximately ;
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100% of rated power. On August 22, the "B" main steam line outboard isolation valve (MSIV)
failed a surveillance test. The reactor was shutdown to a Hot Standby condition (< 1 % reactor power) in order to establish conditions for repairing the MSIV. The associated four-way air control valve was replaced, and the reactor was restarted on August 25. The MSIV was successfully retested and full power was reached on August 2 .
On August 30, an indicating potential transformer (PT) on the A5 safety related 4160 volt bus failed. The reactor was shutdown on August 31 to replace the PT (see Section 2.3). The reactor was restarted on September 2 and achieved full power on September 4 On September 10, repeated lightning strikes on the 345 KV electrical distribution grid in the vicinity of the switchyard resulted in a turbine generator load reject and reaclor trip. Following a post trip review, the reactor was restarted and reached full power on September 1 Assessment of recirculation pump performance during this period identified the electronic speed limiter control modules as the cause of the speed runback events that had been experienced since June. The speed limiter modules were replaced, and no unanticipated runbacks have occurred since replacement. The reactor was at full power at the close of this perio .0 PLANT OPERATIONS (71707, 40500, 90702, 92701) i
, Plant Operations Review The inspector observed the safe conduct of plant operations (during regular and backshift hours)
in the following areas:
Control Room Fence Line Reactor Building (Protected Area)
Diesel Generator Building Turbine Building Switchgear Rooms Screen House Security Facilities Control room instruments were independently observed by NRC inspectors and found to be in correlation amongst channels, properly functioning and in conformance with Technical Specifications. Alarms received in the control room were reviewed and discussed with the operators; operators were found cognizant of control board and plant conditions. Control room and shift manning were in accordance with Technical Specification requirements. Posting and control of radiation contamination, and high radiation areas were appropriate. Workers complied with radiation work permits and appropriately used required personnel monitoring device ,
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Plant housekeeping, including the control of Dammable and other hazardous materials, was ]
observed. During plant tours, logs and records were reviewed to ensure compliance with station procedures, to determine if entries were correctly made, and to verify correct communication of equipment status. These records included various operating logs, turnover sheets, tagout, and l lifted lead and jumper logs, j Reactor Shutdown to Repair Failed Potential Transformer At 9:06 p.m. on August 30,1993 with the reactor at 100% power, a fire watch person observed smoke coming from a potential transformer (PT) cabinet in the A5 safety related 4160 volt j switchgear. Concurrently, the control room received an undervoltage alarm. The fire brigade ;
was dispatched and the Plymouth Fire Department was notified as required by station l procedures, but no assistance was requested. The cause of the smoking was suspected to be a short to ground in the electrical circuitry associated with the PT and protective fuses in the cabinet. The A5 bus remained energized throughout the event. However, as a precautionary -
measure, the "A" core spray pump circuit breaker was opened by operator action because ofits proximity to the PT cabinet. The fire brigade was secured at 10:08 p.m. No actual fire fighting actions were taken. Subsequent inspection determined that one 4160/120 volt instrument PT had shorted and quickly self deeriergized when the protective fuses for the PT sensed overcurrent and _j opened. The failed PT affected indications only and did not cause any Technical Specification required components to become inoperable. Prompt reporting by the fire watch person an .i actions taken by operations personnel provided timely assessment of the damage and ensured that a fire did not develo '
Full inspection of the surrounding switchgear and replacement of the failed PT required deenergization of the A5 bus and deenergization of several safety related components. Technical v Specifications require restoration of the safety systems within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />. Operators commenced a reactor shutdown at 1:22 a.m. on August 31. The shutdown was considered to be voluntary, as the switchgear repair was considered achievable within the 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> allowable outage time governed by Technical Specifications. The licensee considered the time necessary to conduct ,
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repairs, other work that could be accomplished during shutdown, and the impending approach of Hurricane Emily in its decision to voluntarily shutdown rather than implement corrective action with the plant on line. This decision demonstrated sound safety judgemen ,
The inspector observed inspection and replacement of the failed PT. The licensee inspected and cleaned adjacent electrical cabinets, meggered the A5 electrical bus, and replaced the failed P Following a material history review and discussion with the vendor, the licensee concluded that this was a random isolated failure. The inspector found the licensee's failure determination to )
i be technically sound. The licensee effectively used this opportunity to complete other ,
conditional repairs including replacement of a leaking safety-relief pilot valve on the "A" main .j steam line, replacement of five aged sets of scram inlet / outlet valve diaphragms, and l reconditioning of the actuator for the residual heat removal system torus suction valve (MO-1001-7C). Maintenance, operations and system engineers demonstrated excellent coordination of effort to complete these repairs during the unplanned shutdow .. - , . ~
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I Partial Loss of Offsite Power J On September 10,1993, successive lighting strikes on the 345 KV electrical grid and switchyard caused a partial loss of offsite power, with a resultant reactor scram due to a main turbine generator load reject. As expected, main steam line (Group I), drywell (Group H), and reactor
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water cleanup (Group VI) system isolations were automatically initiated and the safety relief valves (SRV) provided the initial reactor coolant system (RCS) pressure control. Within one minute of the scram, reactor operators manually initiated the reactor core isolation cooling (RCIC) system for RCS water level control and the high pressure coolant injection (HPCI)
system for RCS pressure control. Within eleven minutes of the reactor scram, one switchyard air circuit breaker (ACB 102)was closed, providing 345 KV offsite power to the plant startup l transformer, and restoring normal offsite power to the site. The 23 KV offsite power supply J to the plant shutdown transformer remained available throughout this even The inspector observed licensee response and plant recovery activities in the control room from the initial operator recall alarm to the re-establishment of the preferred offsite power supply to !
the 4.16 KV safety buses. The " A" emergency diesel generator (EDG) had been running as part ,
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of a planned surveillance test prior to the partial loss of offsite power (LOOP) while the "B" EDG remained in its normal standby mode. Upon receipt of the LOOP signal, the "B" EDG started and both EDG output breakers automatically closed to carry their respective safety-related power loads on buses A-5 and A-6. During subsequent recovery operations, the inspector ,
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witnessed the operations briefing and sequential transfer of buses A-5 and A-6 from their emergency power supplies to the startup transformer. The inspector noted that the Nuclear Watch Engineer (NWE) had decided to delay transfer of these safety buses off emergency power until after an additional switchyard breaker (ACB 103) was closed. The NWE's action ensured :
two 345 KV sources of offsite electrical power for the plant safety-related loads. This consideration of existing grid conditions and stability demonstrated a strong safety perspectiv The inspector also observed other post-trip recovery evolutions (e.g., securing RCIC, re-opening the main steam isolation valves and establishing RCS pressure control through the turbine bypass valves, securing HPCI), and noted appropriate operator actions relative to anomalous equipment ;
indications For example, because of a dual valve position indication for the "A" outboard main steam isolation valve (MSIV), the "A" steam line was maintained in an isolated status with the other three steam line MSIVs opened to provide flow to the condenser. Subsequently, and prior to plant restart, this dual indication on the "A" outboard MSIV was repaired during an entry into the steam tunnel to repair a limit switch proble ;
The inspector also noted proper control room operator entry into and exit from the applicable emergency operating procedures for RCS (EOP-1) and containment / torus cooling (EOP-3) :
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controls; observed the telephonic notification to the NRC duty officer in accordance with 10 CFR 50.72; and verified licence initiation of post-trip review activities, as governed by PNPS procedure 1.3.37. Overall, rood operator control and communications and timely response to ,
alarms and equipment problems were observed during this event. Subsequently, the inspector reviewed the Scram Report 93-03, including classification of this event as a Type 1 trip,
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allowing preparation for plant restart without the need for further investigation. The post-trip review process was concluded on the afternoon of September 11,1993, the mode switch was .
placed in startup, the reactor was taken critical that evening, and the plant was restored to 100% l power on September 12, 199 The inspector con 5rmed that the operator logs accurately reflected the observed sequence o events and that recorder traces (e.g., SRV tailpipe temperatures) and measured variable plots *
(e.g., reactor pressure vessel cooldown rate) provided evidence of plant response within acceptable limits. The inspector also independently veri 6ed that the licensee had either t
dispositioned or corrected all anomalous equipment problems (identified during this event) prior to authorizing plant restart. The inspector concluded that operator response to and recovery-from this event was excellen ,
j MAINTENANCE AND SURVEILLANCE (62703,61726)
A1 Replacement of Leaking Safety Relief Pilot Valve On August 30,1993 the inspector noted that the control room operators were tracking elevated tailpipe temperatures downstream of main steam safety relief valve (SRV) RV-103-3A. The .
inspector confirmed that the peak temperature indicated on temperature recorder TR-260-20 was below the 212 degrees F documented in the technical speci6 cations as a benchmark for additional monitoring and action. The inspector was informed by the operators on shift that the temperature was currently varying within a band of 195 to 205 degrees F, depending upon plant evolutions. This would indicate a minor leak in the pilot valve for RV-203-3A which warrants operator attention, but no formal action After the plant was shutdown on August 31,1993 for unrelated reasons (see section 2.2 of this inspection report), the licensee decided to make a drywell entry and replace the leaking pilot .!
valve for RV-203-3A. This valve had been installed in December 1992, (refer to NRC .
I Inspection Report 50-293/92-28), and was not replaced during refuel outage (RFO) No. 9, as were the pilot valves for the other three main steam line SRVs. The decision to replace the leaking pilot valve was based upon the opportunity provided during the plant shutdown, as well as the technical judgement that the leak wa likely to increase during subsequent operatio On September 2,1993, the inspector witnes'ed the conduct of post-maintenance testing (PMT)
on RV-203-3A, with the operations staff using newly revised procedure No. 8.5,6.2, which cycled the SRV at 950 psig vice 350 psig. This procedure had been validated at the PNPS simulator and made effective on September 1,1993. The inspector reviewed the new revision 15 to procedure No. 8.5.6.2, observed the pre-test briefing of the operations staff, and checked various plant component and control room instrument initial conditions to confirm proper position for the test conduct. Operations personnel performed a " walk-thru" before procedural implementation and adequate communications were verified to exist. The test was successfully completed with the opening and immediate closure of RV-203-3A upon verification of turbine
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bypass valve partial closure. As was expected from the simulator validation run, only one bypass valve began to close upon initiation of the test, and indicated reactor water level showed little chang The inspector noted excellent communications among the operations staff both before and during the conduct of this test, and effective contingency planning for the test abort criteria and the precautionary plant response. The inspector determined that appropriate caution was taken by the operators in the first-time implementation of the revised procedure No. 8.5.6.2, and concluded that the newly installed SRV pilot valve met all PMT and technical specification criteria for restoration of the plant to full powe .2 Standby Liquid Control (SLC) System Configuration Control The inspector examined the status and condition of components in the SLC system, including the pumps, squib valves, in-line manual and check valves, and instrumentation associated with the SLC tanks and discharge piping accumulators. The SLC controls on panel C905 in the control room were also checked relative to the field observations and the proper position of the SLC inboard isolation valve was confirmed. The inspector discussed with cognizant operations and technical section personnel the locked component controls for various SLC valves. These locked valve criteria are delineated in PNPS procedure No. 8.C.13 and in the piping and instrumentation (P&lD) legend, PNPS drawing M200, sheet 2. With respect to manual small-bore vent and drain line valves, the inspector determined that some inconsistencies may exist (between Procedure 8.C.13 and P&lD legends) in the interpretation of the various locked valve criteria. Specifically, four drain valves were found without locks. However, all the SLC valves examined by the inspector were found to be correctly positione The inspector reviewed PNPS Procedure No. 8.C.13. " Locked Component Lineup Surveillance," and a supporting Engineering Service Request Response Memorandum (ERM 90-468) which establishes the guidelines and bases for specific locked valve criteria. The inspector also examined the SLC system electrical elementary and functional control diagrams and compared cable routing for the SLC components, as observed in the field, with the design requirements and the FSAR provisions for cable " intermixing". Specifically, the nonsafety-related space heater cables for the redundant SLC pumps were traced electrically to their power supplies and checked for compliance with the routing of nonsafety-cables. No deviations or safety concerns were identifie With respect to the inspector's questions regarding the applicability of the PNPS k>cked valve criteria to certain vent, drain and test valves in the SLC system, the licensee initiated problem report (PR) 93.0609 to determine the appropriate factors which govern the locked valve controls in these cases. The inspector noted that the engineering resolution of PR 93.0609 provides additional guidance for operational implementation of similar locked component lineups. Since no SLC valves were found mispositioned, and all components appeared capable of performing their safety functions from the standpoint of power supply, configuration and material conditions, the inspector had no safety concern regarding the observed SLC system statu ..
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6 .0 ENGINEERING (37828, 71707, 92700) Recirculation Pump Speed Oscillations The "A" and "B" recirculation pumps have been subject to several unanticipated speed runbacks since plant restart from refueling outage No. 9 in May 1993. The first speed runback occurred on June 10th, went from 100 percent power the 'A' recirculation pump speed lowered to 75 percent and returned to the previous speed with no operator action. Subsequent perturbations in July included runbacks to a recirculation pump minimum speed of 20 percent. Initial troubleshooting indicated that the cause of the runback was associated with the recirculation motor generator (MG) system speed controls. Temporary modifications (TM 93-52 and TM 93-53) were developed and strip chart recorders were installed to continuously record the speed control signal at five discrete points within both the "A" and "B" MG speed control circuit The licensee established a Multi-Disciplined Analysis Team (MDAT) to further assess the cause of the runback events and developed a corrective action plan to preclude recurrenc The MDAT used a Kepner-Tregoe Analysis technique to categorize the identified recirculation pump speed control problems. The majority of the speed control system anomalics were grouped into the following two categories: (1) 'A' recirculation pump speed runback with ~ *
subsequent return to original speed (six times) and (2) 'B' recirculation pump speed runback with scoop tube lockup (twice). Strip chart recorders captured random signal spiking on the rate limiter output and a corresponding sustained low speed limiter output signal during a runback of the 'B' recirculation pump on July 31. Chart recordings (TM 93-52 and 93-53) during subsequent runbacks, visual inspection, and bench testing of MG speed limiter modules provided additional data to support MDAT evaluation. Detailed analysis indicated that the most probable cause of the speed runbacks was internal component malfunctions within the GEMAC speed ,
limiter modules of the speed control circuits. An industry vendor who routinely refurbishes this type of speed limiter module confirmed that the limiter failures observed at Pilgrim were ,
characteristic of a capacitor or zenor diode fault within the module. The capacitors within the speed limiter modules at Pilgrim are approximately 20 years old. The vendor stated that typical life duration for capacitors was 5-10 years and recommended that the existing speed limiters be refurbished with new capacitor One of the speed limiter modules was removed from service and subjected to as-found bench testing. Each of the capacitors demonstrated satisfactory capacity and leakage. Intentional shorting of the C4 capacitor resulted in a module output signal similar to that recorded during ;
recirculation nmback failures. Repeated rapid energization and deenergization of the module l did not result in component failures. Heat was applied to individual module components )
(capacitors and diodes) to determine whether they would cause module failure if subjected to 'l elevated ambient temperatures of 120 to 135 degrees fahrenheit. The limiter did not fail. In addition the limiter did not fail when the entire module was subjected to elevated temperatures for an extended period of time. Nor did the module fail when heat was cyclicly applied without allowing the module to reach ambient temperature. However, technicians observed that after allowing the speed limiter module to cool for one hour and then reapplying heat to the entire
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module, the module failure could be recreated. Troubleshooting was detailed, but the specific component that failed within the speed limiter module was not conclusively determined. The inspector questioned what initiating condition caused the large number of speed limiter failures and associated recirculation pump speed runbacks to occur in such a short period of ti following refueling outage No. 9. The MDAT review identified no apparent initiating event other than component age. Additional testing at an off-site electrical laboratory is planned to better define the root cause of the speed controller faults and validate corrective actions. Short term corrective action included replacement of both speed limiter modules within each .
recirculation pump speed control circuit. Long term corrective action included the establishment
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of a preventive maintenance item to replace the recirculation pump speed limiter modules with newly refurbished modules at Dve year intervals. The inspector monitored MDAT activities and concluded that systematic troubleshooting and thorough root cause analysis were applie Potential failure mechanisms were clearly identined and individually evaluated to an end conclusio ,
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The MDAT conducted a review of plant equipment to determine whether GMAC limiter modules were used in other system applications at Pilgrim Station. No safety-related applications were identiGed. Two nonsafety-related applications, the recirculation MG set
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master controller and reactor water level control system steam Dow limiter, were identifie Neither of these features are currently used, and therefore do not affect plant operation. The MDAT recommended removal of these two GEMAC limiters via the plant design change process. This recommendation is currently under review by the engineering department. The licensee informed the industry of their recirculation pump speed control problems and causal analysis via the Nuclear Networ .2 Licensee Event Report Review The inspectors reviewed Licensee Event Reports (LERs) submitted to the NRC to verify accuracy, description of cause, previous similar occurrences and effectiveness of corrective action The inspectors considered the need for further information, possible generic implications, and whether the events warranted further onsite followup. The LERs were also >
reviewed with respect to the requirements of 10 CFR 50.73 and the guidance provided in !
NUREG 102 * LER 93-11 LER 93-11, "Setpoint of Target Rock Relief Valves Found Out of Tolerance During Testing,"
documents the test results of three pilot valves for main steam safety relief valves (SRV),
indicating initial popping pressures outside the limits of the technical specifications. These SRV pilot valves were removed from service during refuel outage (RFO) No. 9 and tested in accordance with surveillance requirements. While all three pilot valves exhibited test popping -
pressures in excess of the one percent tolerance above the setpoint pressure allowed by the ,
technical specifications, only one of the three valves had a test result in excess of three percent ]
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allowance generally considered as a better indicator of actual valve conditions. This particular _
valve is newer than the other two valves, having just been subjected to its first cycle of j operatio The inspector discussed this LER with cognizant licensee personnel both at PNPS and in the ,
nuclear engineering division (NED). The inspector also reviewed a General Electric (GE)
Company report on a setpoint drift investigation for this type of Target Rock Two-stage SRV ,
and the result of other GE sensitivity studies for SRV failures on peak pressure demand. These _
GE analyses indicate that even if the opening pressure setpoint for all four ir, stalled SRVs drifts ;
to the ten percent above the nominal setpoint, design and ASME Code criteria for over pressure l protection of the reactor coolant system are still met during the design-basis, limiting event for i peak plant pressure. Thus, the NED assessment of the safety consequences of LER 93-11 i provided evidence of considerable pressurization margins to both the reactor pressure vessel j safety limit and the fuel thermal operating limit j
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Although not a significant safety concern for overpressurization events at PNPS, SRV setpoint drift and related leakage problems represent a recurrent issue from the standpoint of technical specification compliance and reportability in accordance with 10 CFR 50.73. The inspector verified that the licensee had a copy of a "Special Study - Safety and Safety / Relief Valve )
Reliability," published in April 1992 by the USNRC Office for Analysis and Evaluation of Operational Data. This report documents performance problems of SRVs throughout the .
industry and suggests continued licensee review of the design requirements and operating history j of these valves at each plan The inspector conGrmed that the SRV and safety valve j replacement, test results and identiGed problems have been tracked at PNPS since 198 :
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The inspector also examined previous LERs documenting SRV pilot valve test problems and checked recent SRV pilot valve replacement activities (see section 3.1 of this inspection report
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for greater detail). The inspector questioned whether any anomatics in the performance of any speci6c SRV pilat valves would be identiDed by the current licensee method of tracking performance and whether statistical techniques of analysis could be used to aid the SRV trending program. The licensee plans to evaluate the practicality of such an approach, as well as the basis for the range of nominal SRV setpoint pressure settings, provided in Technical Specification 3.6.D.l .
While the inspector had no additional questions specific to LER 93-11 and has no unresolved safety concerns regarding the licensee's controls for SRV surveillance and maintenance, additional licensee attention to the individual pilot valve performance trends and the evaluation of setpoint requirements may lead to further enhancements in SRV reliability and/or the climination of the need for LERs with minimal safety inpac l
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- LER 93-12 LER 93-12, " Group 1 Isolation During Startup While Opening Main Steam Isolation Valve",
dated June 25, 1993 describes the May 29 unplanned primary containment isolation system
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l (PCIS) actuation which occurred while opening the "C" outboard main steam isolation valve l (MSIV) during reactor startup. Opening of the MSIV with approximately 140 pounds per square l
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inch differential pressure (psid) across the seat caused reactor vessel water level to swell and rise to 48 inches which initiated the PCIS actuation. The main steam lines, main steam drain lines, and sample system lines isolated as designed. The purpose of the Group 1 isolation is to protect ;
downstream turbine components from water damage in the event that water would carryover in j
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the steam lines. The reactor was at approximately 1 percent power and the Group 1 PCIS actuation was of minimal safety significanc Licensee evaluation of this event concluded that the root cause was licensed operator error. The primary cause was a communications error between the Nuclear Watch Engineer and the Reactor Operator which resulted in keeping the "C" outboard MSIV open, instead of closing it, while reactor vessel level swelled. Contributing causes were (1) initial opening of the MSIV with reactor water level above that specified by procedure, and (2) three mispositioned valves which prevented operators from reducing differential pressure across the MSIV to 50 psid as recommended in the procedure. Long term corrective actions included revision of procedure 2.2.92 " Main Steam isolation and Turbine Bypass Valves", counselling of operations personnel to stress the importance of clear communications and procedural adherence, and discussion of the event at operator requali0 cation training. The inspector reviewed the procedure revision and training lesson plan and determined that these actions were properly implemented to preclude recurrenc The LER accurately documented the event and corrective actions. The LER described the safety ;
purpose of the RV high water level isolation as protection against rapid depressurization due to '
malfunction of the pressure regulator system during startup. Vendor documentation states that the purpose of the high water level Group 1 isolation is to protect downstream turbine equipment from water carryover damage. The inspector requested clarification by the licensee as to what components the Group i isolation was designed to protect. The licensee confirmed that the components protected by the high water level Group 1 isolation were downstream turbine equipment and not components internal to the reactor vessel. The inspector had no further questions regarding this LE i
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- LER 93-13 LER 93-13, " Reactor Core Isolation Cooling (RCIC) System Declared Inoperable Due to !
Turbine Speed Oscillations During Surveillance Testing", dated June 25, 1993 documents the May 30 RCIC turbine speed oscillations observed during the 1000 psig post-startup surveillance testing. The RCIC system satisfactorily passed 150 psig operability testing during power ascension and had exhibited stable speed control for 13 minutes before speed oscillations i
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occurred during the 1000 psig test. The licensee declared RCIC inoperable, verified the high pressure coolant injection system operable, and continued power operations as permitted by )
Technical Specification l Problem report (PR) 93.9282 was initiated to determine the cause of the RCIC turbine speed oscillations. Troubleshooting concluded the most likely cause to be mechanical failure of the speed control system hydraulic actuator (EG-R). Inspection of the failed EG-R identified a grit residue film present on the inner surfaces of the EG-R, which could cause mechanical binding and wear. The licensee continued to investigate the source of the grit as of the date of this LE The EG-R was replaced, RCIC retested, and successfully returned to service on June 4. The LER properly addressed all reporting criteria in accordance with 10 CFR 50.7 A similar failure of the RCIC turbine was documented in LER 91-20. The inspector questioned the results of root cause analysis from that eent and whether there were similarities to this EG-R failure. Vendor failure analysis of the earlier failure (LER 91-20) had determined that the EG-R pilot plunger assembly was excessively worn, but could not identify the cause. The EG-R was refurbished and returned to the licensee. This EG-R unit (serial No. 2277086) was the same EG-R unit that was in service and failed more recently on May 30,1993. Detailed root cause evaluation (PR 93.9282) concluded that the EG-R failed due to intrusion of foreign material in the hydraulic system. System engineers observed black grit on the mating surfaces of the pilot ,
piston which clearly interfered with free motion between the pilot cylinder and the piston. The :
most probable cause of the grit is the design of the RCIC turbine lube oil filter system which has a 38 micron filter. The EG-R vendor recommends no larger than a 20 micron filter and the high pressure coolant injection (HPCI) lube oil system contains a 5 micron filter. Additional
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foreign material may have been introduced to the EG-R during refueling outage No. 9 "
maintenance on the RCIC syste Corrective actions recommended by PR 93.9282 included a design review of the adequacy of the RCIC lube oil filtration system, revision of maintenance controls to prevent use of pipe dope on EG-R hydraulic fittings (HPCI and RCIC), and review of the post maintenance HPCI and i RCIC hydraulic oil system Hush procedures. In addition, the licensee decided to permanently remove the failed EG-R unit (serial No. 2277086) from inventory and will not have this unit refurbished for reinstallation. Notwithstanding the recurrent failure of the EG-R unit, the ,
inspector concluded that the more recent licensee root cause evaluation was more comprehensive, and the broader maintenance actions for both the HPCI and the RCIC systems were appropriate ;
to pieclude recurrenc * LER 93-14 l
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LER 93-14, " Automatic Scram Resulting From Operation of Auxiliary Transformer (UAT)
Differential Relay During Power Ascension", dated June 30,1993 describes the May 31 reactor ,
scram which was initiated by actuation of the UAT phase 'C' differential transformer relay. The '!
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event is documented in detail in NRC Inspection Report 50-293/93-0 Safety systems responded as designed during the event. The LER accurately described the event, corrective actions, and addressed all reporting criteri * LER 93-15 LER 93-15, "High Pressure Coolant Injection (HPCI) System Made Inoperable Due to Indicated Flow During Surveillance," dated July 28,1993, describes the declaration ofinoperability of the ,
HPCI system on June 30,1993 because the flow rate achieved during a surveillance test did not j meet established criteria. NRC follow-up inspection of the system inoperability is documented j in Inspection Report 50-293/93-13 (section 2.3). A restricting orifice in the HPCI full flow test line used to conduct the subject surveillance was found to be partially blocked with debris. With the ori0cc clean and reinstalled, the HPCI system was successfully tested and declared operable on July 1,199 At the time of the discovery of the ori0ce blockage, the inspector questioned the possible impact !
upon other safety systems, which take suction on the supply of water in the condensate storage tanks, (the suspected source of the debris). As is analyzed and documented in LER 93-15, both the HPCI and reactor core isolation cooling (RCIC) system flow paths which actually inject water into the reactor vessel, as well as the HPC1/RCIC auxiliary systems, were determined to have not been degraded by the conditions identi0ed in the partially blocked HPCI full flow test line. It appears that only the affected HPCI test line has the type of conical, perforated orifice that would likely become blocked by the small debris that was found. Further, only the HPCI and RCIC systems take suction from the bottom of the CST's where any debris would
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accumulate. All the safety system piping taking suction on the suppression pool of the containment is protected by inlet strainer Although this condition was analyzed to have no actual adverse safety system performance consequences (i.e. would not have prevented functional capability in its design configuration),
licensee corrective action was directed to the prevention of recurrence by a periodic removal and ;
inspection of the subject HPCI test line orifice (RO-2301-59), with such activity scheduled in the preventive maintenance program. Furthermore, the licensee plans a visual inspection of at least one condensate storage tank for any foreign material during a plant outage in the futur )
The details of these corrective actions, as well as the details of this event, are appropriately documented in LER 93-15, which also addresses all relevant reporting criteria. The inspector !
has no further questions on this LER or in this technical area at this tim * LER 93-16 LER 93-16, "High Pressure Coolant injection System Pump Low Discharge Pressure Alarm inoperable," dated August 18,1993, describes the discovery on July 19 of the inoperable status of the HPCI pump discharge header low pressure alarm. At the time that this problem was identified, NRC follow-up inspection verified that the HPCI system remained available to perform its safety function. As documented in Inspection Report 50-293/93-14 (section 2.4),
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the licensee decision to declare the HPCI system inoperable was conservatively based upon the interpretation of Technical Specification 4.5.H.4, addressing the functionality of pressure switch PS-9090, which generates the alarm signal. The HPCI system was restored to operable status on July 20,199 i During this inspection, the inspector confirmed that the root cause of the inoperable alarm was j traceable to a re-configuration error in the implementation of a plant design change, PDC 92-29, !
involving control room alarm panels C-903, C-904 and C-905. As part of the corrective action process, the licensee functionally re-checked all the alarm circuits for these panels and identified >
no additional discrepancies. Since the inoperable alarm directly resulted from a missing electrical jumper (i.e., in this case, a Eeld common connector link), the inspector reviewed additional problem reports (e.g., PR 93.9213, PR 93.9320 and PR 93.9397) with similar missing jumper wire, electrical configuration or alarm connection discrepancies to evaluate. causal linkage. As follow-up, the inspector also reviewed the PNPS Procedure No.1.5.9.1 for " Lifted Leads and Jumpers" to determine the relevance of the current event to the adequacy of corrective ;
action for an unresolved item (90-07-03) involving the failure to properly reconnect a component electrical lead. The inspector concluded that the facts reported in LER 93-16 are ielated to modification activities on the control room alarm panels, as controlled by PDC 92-29. Licensee ,
analysis of the identified wiring discrepancy, its cause and safety consequences, and the >
implementation of corrective measures, appear to have been comprehensive relative to the electrical wiring problem which was reported. Therefore, the inspector had no additional ;
questions uniquely related to LER 93-1 ;
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However, since this event involved the misinterpretation of a Panalarm electrical drawing regarding field connections, the inspector noted some similarity to other cases of electrical i configuration discrepancies, as documented in NRC Inspection Reports 50-293/92-08,92-14,92- ;
21, and 93-13 as well as one recently identined by the licensee in BECo problem report, (PR) <
93.9397. All of these documented electrical wiring discrepancies, while differing in safety significance and technical applicability, appear 'a relate to one common characteristic, i.e., the ,
identi0 cation of field wiring that is inconsistent with electrical drawing details. The inspector -
acknowledged that each pmblem has been ar is being analyzed and corrected, (as necessary),
independent of the other ideMified deficicacies. However, the apparent commonality of these problems, representing examples of electrical drawing mismatch, may warrant additionallicensee ;
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The planned PNPS program for the reconstitution of design basis information does not include i verification activities to the level of detail provided by electrical wiring diagrams. Furthermore, any safety-signincant problems with wiring that affects component operability would be expected to be identified by post-work and surveillance tests. Nevertheless, from the standpoint of proper ,
electrical con 0guration management and the correctness ofinterpretive information provided by the plant electrical drawing details, the inspector was concerned by the lack of a collective analysis of the electrical wiring discrepancies identified at PNPS over the recent past.' The ,
licensee recently initiated corrective actions to address the concern ,
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13 PLANT SUPPORT (71707, TI 2500/28) Security Preparations On August 21, the Greenpeace organization staged a rally in opposition to the operation of nuclear power plants in a hurricane zone. The rally had been publicized, with participation from both local and national interest groups anticipated. Published comments also indicated a potential for disruptive activities. The licensee contacted rally organizers to discuss planned logistics and activities. Event organizers stated that no acts of civil disobedience were planned, and a " focal location" outside of the contractor gate entrance to the station was agreed upon for the demonstratio ;
The licensee reviewed the Station Security Plan in advance of the demonstration and implemented additional precautionary security measures as appropriate. Areas reviewed included access control to owner-controlled property, security force staffing levels, use of additional video cameras at the demonstration site, and communications with the Coast Guard regarding vesse1 control in the waterfront area. The inspector discussed advance preparations with the station Security Manager and determined that contingency planning had been thorough and that appropriate precautionary measures were in place. A relatively small number of people subsequently participated in the rally. The demonstration was conducted in an orderly manner, !
with no arrests or property damag .2 IIurricane Preparations Pilgrim Station is located in an area that is susceptible to the effects of hurricanes and severe northeaster storms. Following the severe effects of hurricane " Andrew" along the Florida coast in 1992, many nuclear power plants reviewed their susceptibility and procedures to be used in the event of a hurricane. The inspector reviewed station procedures and facilities that would be implemented in the event of hurricane weather conditions to determine whether the effects of severe weather were properly addresse Station procedure 5.2.2 "High Winds (Hurricane)", :'escribes advance plant preparations and actions during high wind conditions. The procedure requires Operations personnel to coordinate site walkdowns to secure loose equipment, materials, and staging. Procedure 5.2.2 does not require plant shutdown, but does direct that the safety related 4KV electrical busses be supplied from the station emergency diesel generators if hurricane force winds are anticipated. If winds reach 175 mph near the site or a station load reject is imminent, REMVEC (the off-site i
distribution grid load dispatcher) is notified and power is reduced to main turbine load rejection capabilities (130 Mwe gross). Provisions for securing radwaste containers based upon curie l content are described-in procedure 6.1.207, " Radiological Controls of Vehicles and Material."
The inspector reviewed safety evaluation No. 2555 and calculation ERHS-XIII.Q-44 and concluded that provisions for staging and securing radwaste containers was technically soun The inspector interviewed operations and radiological protection personnel and determined them i to be highly knowledgeable on implementation of these hurricane procedure l
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Diverse communications equipment is employed to support off-site communications in the event of a hurricane. Pilgrim nuclear power station (PNPS) has installed two primary notification systems. The digital notification system (DNN) is a computerized, private network ringdown notification system consisting of leased telephone data lines, BECo owned and maintained telephone instruments, an IBM model 80 computer and a facsimile network that provides a notification link from BECo to each offsite agency. The backup notification system is the Bos;ou Edison Community Offsite Notification System (BECONS) which is a dedicated VHF high band radio repeater system. To improve availability in storm conditions, BECo installed redundant repeater sites as well as backup power for both DNN and BECON In addition BECo has installed the following non telephone communication links:
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Massachusetts Emergency Management Agency Radios
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PNPS Radiological Monitoring Team Radio
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State Police Radio
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Pilgrim Alert Radio
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Cellular telephones in control room Technical and Operation Support Centers, and main gatchous The primary transmission tower is the pine hills tower located on a hill top about I mile inland from the site. The backup transmission tower is the primary meteorological tower which is h>cated adjacent to the main exhaust stack near the shorefront at Pilgrim Statio The transmission towers were erected to commercial standards. No specinc seismic considerations were made. The backup transmission tower was initially constructed to withstand wind speeds of 90 mph. Additional antennas mounted on the tower since original construction are unlikely to have significantly altered the ability of the tower to withstand high winds. The transmission towers remained intact without signi0 cant degradation during previous storms (Hurricane BOB -
1991, and the 1993 Northeaster) which introduced wind gusts in excess of 90 mph and sustained w 's of approximately 65 mp However, it is likely that significant damage to the co. munications towers could occur if a Force 5 hurricane, similar to Hurricane Andrew, directly hit the sit Power to the communication tower sites is available from redundant sources, including:
Pine Hills Tower
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normal supply is street power
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backup supply is natural gas generator at Pine Hills, open to elements
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normal supply is street power
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l Offsite communications equipment is maintained under a preventive maintenance and surveillance testing progra Emergency related communication equipment other than i telephones are tested on a monthly basis. A documented maintenance trouble report program j is used to identify and track corrective repairs to completion. All communication capabilities ;
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are currently operable, improvements such as installation _of private microwave and fiber optic network, and installation of state of the art telephone switching equipment are ongoin Offsite support services are available to assist site recovery from a hurricane if needed. Offsite support requests are requested through logistics personnel assigned to the Emergency Operations Facility (EOF) per EP-1P-252, " Facilities Support". The logistics staff in the EOF uses the corporate support emergency organization as defined in the Corporate Radiological Emergency
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Plan and Implementing Procedures to process these requests. The Corporate Radiological Emergency Plan contains more than 30 additional resource support procedures to aid Pilgrim Station in response to a declared emergency such as a hurricane. These additional procedures address concerns such as insurance and financial support, procurement and purchasing support, transportation, stores and delivery support as well as personnel processing support. Additional ;
personnel are obtained through mutual assistance agreements with other regional utilities (PNPS Emergency Plan Appendix 3) and through industry contacts by the Corporate Support Cente Personnel are then processed through the Personnel Processing Center at Mass Ave per -
L implementing procedures EP-CP-110 through EP-CP-11 The inspector concluded that licensee procedures, equipment, and training fully support station ,
operations in the event of a hurricane. The licensee is experienced in responding to hurricane weather conditions. Their implementation of procedure 5.2.2 and subsequent plant restoration 4 was excellent during Hurricane Bob in August 1991 and the Hundred Year storm in March '
199 .3 Employee Concerns Progrnm The inspector reviewed BECo Nuclear Policy C.l.03, regarding the reporting of nuclear safety concerns, and a draft version of the Nuclear Organization Procedure, NOP93A, concerning a ,
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Nuclear Safety Concern Program (NSCP) currently under development. Procedure NOP92Al, governing the Problem Report Program, was also checked to confirm that a process currently exists at PNPS to identify, evaluate and correct several types of problems. This process is available for use by all PNPS personnel, and could be used to document and address nuclear safety concern While Nuclear Policy C.l.03 clearly establishes the organizational reporting structure (i.e., "the chain of command") as the preferred path for the reporting and resolution of nuclear safety concerns, the development of the NSCP demonstrates BECo management's resolve for providing P
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an alternative path for handling safety concerns that cannot be adequately dispositioned by other j site procedures. The inspector evaluated the draft NOP93A with regard to plans for ensuring l
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independence, confidentiality, concern followup, feedback and training. Resource allocation and implementation plans were discussed with cognizant management and QA personnel. While the effectiveness of such a program can only be measured after it is implemented, the inspector noted that previous NRC inspections (e.g.,50-293/89-13) had verified acceptable management controls in place at PNPS to deal with employee concerns and recommendation ,
The inspector has no further questions regarding the Nuclear Safety Concerns Program at the present time. A survey questionnaire from NRC Temporary Instruction 2503/028 is attached, which responds to the recently instituted program under procedure NOP93 .0 MANAGENIENT SIEETINGS AND OTIIER ACTIVITIES (30702) Routine Meetings l
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At periodic intervals during this inspection, meetings were held with senior BECo plant management to discuss licensee activities and areas of concern to the inspectors. At the :
conclusion of the reporting period, the resident inspector staff conducted an exit meeting on :
October 8, summarizing the preliminary findings of this inspection. No proprietary information was identified as being included in the repor .2 Manngement Meetings On September 16, senior NRC management met with senior licensee personnel (Thomas May - ,
President & Chief Operating Officer, George Davis - Executive Vice President, and Thomas l
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Boulette - Senior Vice President, Nuclear) at NRC headquarters in Rockville, Maryland to
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discuss various industry and regulatory issue .3 Other NRC Activities
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On August 30 - September 3, an NRC Region I a radiation protection specialist conducted an inspection of radiological practices and controls, inspection report results will be documented in NRC Inspection Report 50-293/93-1 l
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On August 'O - September 3, two NRC Region I effluent radiation protection specialists conducted an inspection of licensee radiological environmental monitoring program. Inspection i report results will be documented in NRC Inspection Report 50-293/93-1 f
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NITACIIMENT A EMPLOYEE CONCERNS PROGRAMS PLANT NAME: Pilgrim NPS LICENSEE: Boston Edison Company DOCKET #: 50-293 NOTE: Please circle yes or no if applicable and add comments in the space provide PROGRAM: Does the licensee have an employee concerns program? (Yes at No/ Comments)
N Currently a Nuclear Safety Concern Program is under development with the intent to be implemented in CY 199 . Has NRC inspected the program? No. Ilowever, an earlier program which could handle employee concerns, i.e., the Corrective Action Clear llouse was inspected in 1990, as documented in IR 50-293/89-1 I SCOPE: (Circle all that apply) Is it for: Technical? (Yes, No/ Comments) Ye Industrial safety or nuclear quality concern Administrative? (Yes, No/ Comments) N Unless related to industrial safety or nuclear qualit Personnel issues? (Yes, No/ Comme- ",. Unless related to industrial safety or nuclear qualit . Does it cover safety as well as non-safety issues? (Yes at No/ Comments) Yes ! Is it designed for: 4 Nuclear safety? (Yes, No/ Comments) Yes Personal safety? (Yes, No/ Comments) Yes .
I Personnel issues - including union grievances? (Yes at No/ Comments) l
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No. Unless related to a or b abov Lssue DattLO7/29/93 A] ' 2100/028 Attachment
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. Contractors? (Yes g No/ Comments) Yes Does the licensee require its contractors and their subs to have a similar program?
(Yes u No/ Comments) No
' Does the licensee conduct an exit interview upon terminating employees asking if they have any safety concerns? (Yes a No/ Comments) No INDEPENDENCE: What is the title of the person in charge? Nuclear Safety Concern Program (NSCP) Administrato . Who do they report to? The office of the Senior Vice President, Nuclear (may be a technical assistant.)
, Are they independent of line management? Yes Does the ECP use third party consultants? Yes. If necessar ' How is a concern about a manager or vice president followed up? Senior VP, Nuclear makes that determinatio RESOURCES: What is the size of the staff devoted to this program? Currently planned for one person (may be part time).
. What are ECP staff qualifications (technical training, interviewing training, investigator training, other)? Undetermined at presen , REFERRALS: Who has followup on concerns (ECP staff, line management, other)? NSCP administrator routinely will followup or assign followup to an individual on line organizatio , CONFIDENTI A LITY: Are the reports confidential? (Yes a No/ Comments) Ye . Who is the identity of the alleger made known to (senior management, ECP staff, line management, other)? (Circle, if other explain) ECP staff. Possibly also the Senior VP, Nuclear if his involvement is require ,
issue Date: 07/29/93 A-2 2500/028 Attachment
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4 Can employees be: ;
i Anonymous? (Yes, No/ Comments) Yes l Report by phone? (Yes, No/ Comments) Ye FEEDBACK: Is feedback given to the alleger upon completion of the followup? (Yes Dr No -
If so, how?) Yes. NSCP Administrator will contact or attempt to contact the concern initiator with a respons . Does program reward good ideas? Not part of concerns progra !
improveirrnt or savings may result in a cash reward of from $100.00 to l
$2,000.0 l Who, or at what level, makes the final decision of resolution? Generally,, the responsible Department Manage . Are the resolutions of anonymous concerns disseminated? Not in current provision . Are resolutions of valid concems publicized (newsletter, bulletin board, all hands meeting, other)? Not in enrrent provision I EFFECTIVENESS: l How does the licensee measure the effectiveness of the program? NSCP Administrator tracking and reporting to Senior VP, Nuclea . Are concerns: Trended? (Yes or No/ Comments) No. No current histor Used? (Yes or No/ Comments) No. No current histor . In the last three years how many concerns were raised? =6 Of the concerns raised, how many were closed? What percentage were substantiated? N/A Ilow are followup techniques used to measure effectiveness (random survey, interviews, other)? No current histor . How frequently are internal audits of the ECP conducted and by whom?
Undetermine Issue Date: 07/29/93 A-3 2500/028 Attachment l
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t AD311NISTRATION/ TRAINING: Is ECP prescribed by a procedure? (Yes nr No/ Comments) Yes. Currently in draft for . How are em1M oyces, as well as contractors, made aware of this program (training, newsletter, bulletin board, other)? Postings, periodic employee communications, General Employee trainin A.DDITIONAL CO3151ENTS: (including characteristics which make the program especially effective, if any.)
Review of the Corrective Action Clearing house program in the 1989/90 time frame (as documented in IR 50-293/89-13) revealed very few concerns that would be characterized as " allegations." Therefore, the need for a Nuclear Safety Concern program has been determined by llECo management to be a prudent action from a programmatic standpoint, rather than a need from a historical perspectiv NA31E: TITI.E: PIIONE #: DATE A. Cerne Resident Inspector 508-747-0565 9/10/93
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Issue Ilate: 07/29/93 A-4 2500/028 Attachtnent ,
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