IR 05000458/1989007

Insp Rept 50-458/89-07 on 890201-0314.No Violations or Deviations Noted.Major Areas Inspected:Plant Events, Emergency Preparedness Exercise,Operational Safety Verification & Surveillance Test Observation

ML20248K525
Person / Time
Site:	River Bend
Issue date:	04/05/1989
From:	Constable G NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION IV)
To:
Shared Package
ML20248K504	List: IR 05000458/1989007 ML20248K501
References
50-458-89-07, 50-458-89-7, NUDOCS 8904170367
Download: ML20248K525 (12)

Text

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APPENDIX

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U.St. NUCLEAR REGUL TORY COMMISSION.

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NRC~ Inspection Report:

50-958/89-07'

Operating License:

NPF-47

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Docket

'50-458'

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' Licensee: Gulf, States: Utilities Company (GSU)

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P.O. Box 220

- - V St. Francisville,' Louisiana 70775'

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'(River Bend Station (RBS)

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Inspection At:

River Bend' Station, St. Francisville,' Louisiana L

IInsp2ction Conduc'.ed:

February 1 through March 14, 1989-

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cInspectors:

E..J.' Ford, Senior Resident Inspector k. B Jones, Resident: Inspector

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Approved:

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.G7 r Constable, Unief, Project Section C Ddte C Division of Reactor Projects Inspection' Summary

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Inspection'Conducte'd -(Report 50-458/89-07)

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Areas Inspected:

Routine, unannounced inspection of plant' events, emergency preparedness exercise, operational safety verifications, surveillance test

' observation, maintenance observation and previous inspcction findings.

Results: Operations personnel.were cognizant of alarms in the main ~ control'

area and shift turnovers were conducted in a complete and professional manner.

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Operating procedures' were properly utilized.

The' unplanned reactor shutdowns-were well controlled and the plant maintained'in a safe condition during the

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. recovery from.each event.

An emergency pr.e'paredness exercise conducted on March 1, 1989, revealed a

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-weakness in communications betwee.n'the control room and the technical support center (TSC) staff:that~ limited the effectiveness of'the TSC.

No violations.or deviations were identified.

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8904170367 890410 PDR ADOCK 05000458

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DETAILS 1.

Persons Contacted J. E. Booker, Manager, Oversight E. M. Cargill, Supervisor, Radiation Programs J. W. Cook, Lead Environmental Analyst, Nuclear Licensing I

• J. C. Deddens, Senior Vice President,' River Bend Nuclear Group

• L. A. England, Director, Nuclear Licensing A. O. Fredieu, Supervisor, Operations P. E. Freehill, Outage Manager

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J. R. Hamilton, Director, Design Engineering l

D. E. Jernigan, Instrumentation and Control Superviror R. J. King, Supervisor, Nuclear Licensing V. J. Normand, Supervisor, Administrative Services

• T. F. Plunkett, Plant Manager J. P. Schippert, Operations Engineer J. Venable, Assistant Operations Supervisor R. G. West, Supervisor, General Maintenance The NRC inspectors also interviewed additional licensee personnel during the inspection period.

• Denotes those persons that attended the exit interview conducted on

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March 23, 1989.

2.

Plant Status Maximum reactor thermal power output decreased from 83 to 73 percent, as expected, during this inspection period because of the end of cycle fuel depletion. Three unplanned reactor shutdowns were experienced during February 1989. The first shutdown which was manually initiated on February 17, 1989, was required by the Technical Specifications (TS)

because of the inability to determine the unidentified leak rate. The

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subsequent two reactor shutdowns were automatically initiated by the

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reactor protection system because of equipment failures. On February 20, 1989, with the reactor at 2 percent thermal power, the startup regulating l

valve responded erratically causing a cold water transient and suF aquent j

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intermediate range monitor upscale trips. The second equipment

.. lure on February 25, 1989, occurred with the reactor at 78 percent thertel power.

j A relay associated with the main turbine thrust bearing high vibration i

signal failed to open which caused a control valve fast closure and

subsequent reactor scram. These events are described in more detail in

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paragraph 3 below, On March 14, 1989, the licensee began manually shutting down the reactor in preparation for the second refueling outage scheduled to begin March 15, 1989. The outage is presently scheduled to last 50 days.

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3.

Event Followup (93702)

A.

Reactor Core Isolation Cooling (RCIC) System Isolation (LER 89-04)

On December 9,1988,'while performing an RCIC isolation calibration of the RCIC steam flow transmitter, the I&C technician in the field mistakenly hooked up to the Division 11 steam flow transmitter. When the transmitter was calibrated it caused a Division II RCIC isolation on high steam flow. - The RCIC system was already out of service for preplanned maintenance. This ESF actuation was discovered at approximately 3:10 a.m.

The licensee initiated a 10 CFR 50.74 4-hour ESF actuation report to the NRC at 5:45 a.m. and contacted the SRI at 6:50 a.m.

The isolation was masked by expected annunciators until the time of discovery. The RCIC system had been previously isolated to perform required to 18-month calibrations.

To evaluate this event, the NRC inspector reviewed Licensee Condition Reports (CR) 88-0904 and 88-0905, NRC event notification form (Form EIP-2-006), Surveillance Test Procedure STP-207-4236, "RCIC Isolation-RCIC Steam Line Flow-High 18-month CHCAL," and Temporary Change Notice (TCN) 88-0774, and held discussions with various I

licensee personnel.

The I&C technicians performing the aforementioned STP calibration on RCIC Steam Flow Transmitter E31-RDTN083A noted that the as-found data and the STP data table disagreed. They stopped further testing and consulted their supervisors.

Investigation showed the data table didn't agree with either the loop calibration report (LCR) or the last revision of the STP. Further i

investigation showed that a modification which relocated the i

transmitter also caused the LCR to be correctly updated (during the previous outage). The licensee, therefore, concluded that the data table wasn't properly changed during the last STP revision and that an independent STP review also failed to find the incorrect

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information. The licensee's program for review and approval of I

I surveillance procedures was identified as a weakness in the previous Systematic Assessment of Licensee Performance (50-458/87-32).

NRC management personnel met with the licensee on January 11, 1989, to i

discuss the findings of the SALP report. The licensee's actions to eliminate errors in surveillance test p w.edures will be reviewed

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during subsequent NRC inspections.

B.

Drywell Drain Sump Pumps Degradation On February 3,1989, licensee representatives from licensing operations and engineering presented the status of the drywell sump pumps and their management's interpretation of certain TS to the NRC inspector. The drywell sump pump

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information presented concerned the degraded status of drywell sump pump capability and potential for an increase in drywell leakage into the floor drains.

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The drywell has two sumps, one for identified leakage (the equipment drains sump) and one for unidentified leakage (the floor drains sump).

Each sump has two pumps associated with it. At.the time of the discussions, one pump in each sump was out of service because of equipment problems. Because the unit was at power, drywell entries had not been made to ascertain the nature of the pump problems, but motor-pump coupling failures were suspected. The NRC inspector had been tracking this problem because of its potential for a TS required shutdown.

The unit is in its end-of-cycle coastdown, therefore, it is not unusual to have a small amount of unidentified leakage because of valve packing leaks, clean cooling water leaks, etc., as well as identified le akage into the floor and equipment sumps, respectively.

For several weeks the licensee had been monitoring and trending this leakage and had charted a nominal 3 gpm for each sump.

RBSTS(TSLC0'3.4.3.2.6) requires unidentified leakage to be limited to 5 gpm and total leakage to 25 gpm in Operational Conditions 1, 2, or 3.

The. associated action statement (b) states that leakage greater than these limits requires that the leakage be reduced to within the limits, within 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br />, or commence shutting down. The licensee stated there was an administrative limit of 4 gpm (vs the 5 gpm.of TS) which would trigger the shutdown actions. The floor drains trend had increased by approximately i gpm. There was reason to believe that this increase was " clean water" leakage since there were no indications of increased activity in the drywell. Thus, the sump leakage rate was only i gpm from triggering shutdown actions.

Further, the loss of either of the remaining single pumps would cause a loss of pump down capability for the affected sump. This sump would then fill'and overflow to the remaining sump which would result in the inability to differentiate identified from unidentified i

leakage.

To be conservative, the total leakage would have to be considered unidentified, thus triggering the TS action statement (AS)

which prohibits greater than 5 gpm unidentified leakage.

The licensee was considering reducing power and making a drywell entry to determine source of leakage and evaluate feasibility of repairing the inoperative sump pumps.

However, the ability to make the entry without a shutdown was complicated by the fact that a l

drywell air lock door (one of two) had failed its surveillance in October and the TS (3.6.2.3-Drywell Air Locks) action statement (a.1)

requires the operable door to be closed and locked.

The licensee explained their intended actions to the NRC inspector.

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between the NRC inspector, NRR Project Manager, and other members of the NRR and RIV staff were held to formulate a position. The NRC inspector reviewed the licensee's procedure for entering the

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g drywell:

RSP-0212, "Drywell Entry," Revision 3, dated August 19, l

1987. The procedure's purpose is to provide instructions including

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precautions and limitations for performing a single or initial entry into the drywell. The procedure may be applied to any confined space (unventilated) containing radioactive fluid systems or radioactive i

solids. The NRC inspector noted the following prerequisites were required by the procedure prior to drywell entry.

(1) Chemistry is to obtain drywell air samples and analyze for radioisotopes and oxygen concentration; (2) A prejob entry briefing is to be performed to include:

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(a) Location for entry and actions to be performed during the

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entry.

(o) Anticipated total exposures, exposure rates, and radiological hazards that may be encountered during the

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entry.

(c) The need to minimize time in the area and to' Jnaintain visual contact with each other during the entire entry.

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(d) Review the DRMS readings for the drywell postaccident monitors (1RM-RE 20A and -208) and Drywell Atmosphere Monitor 1RM-RE112.

(e) Ti.e two standby individuals (backup team) informed of their responsibilities as search and rescue personnel for emergencies during the drywell entry; (3) A radiation work permit (RWP) will be required for entry unless I

waived by the Shift Supervisor for an Emergency Entry; l

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Insure that at least one individual on the entry team is a i'

Radiation Protection Technician, with equipment for performing radiation, contamination surveys, and air sampling;

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(5) Verify that the transverse incore probe (TIP) drive system is

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tagged out with the TIP's in the Lower Plenum area; and

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(6) Verify that the drywell has been vented for at least I hour.

On February 17, 1989, the licensee received an alarm which indicated

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that excessive drywell floor drain sump pump run times were being

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experienced. At 7:15 a.m. (CST) the licensee determined that the remaining drywell floor drain sump pump was not transferring water to the radiological water collection tanks and thus the rate of unidentified leakage could not be determined. The licensee began reducing power at 15 percent per hour from 53 percent thermal power.

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1 At 11:15 a.m. the licensee manually shut down the reactor from 20 percent thermal power. The reactor plant responded as expected to the manual reactor scram, c

The licensee requested and was subsequently granted enforcement discretion to unlock the drywell personnel airlock with the reactor plant in hot shutdown (0perational Condition 3) to allow for the drywell personnel entry. After entering into the drywell, the licensee discovered a small leak at the "A" recirculation line flow control valve high point vent butt weld. Although this did not constitute a pressure boundary leakage because the flow control valve can be isolated from the-primary system, a mode change to cold shutdown (Operational Condition 4) was required to repair the weld.

The licensee ground out the affected weld and rewelded the vent pipe utilizing an approved procedure and a qualified welder. All four of the failed drywell drain sump motor-pump couplings were replaced and tested in accordance with the maintenance work order. On February 19, 1989, the reactor mode switch was placed to startup to allow control rod withdrawl to criticality and subsequent power operations.

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Reactor Scram Because of Intermediate Range Monitor (IRM) Upsqle, Trip On February 20, 1989, at 1:53 a.m. (CST), with the reactor at 2 percent thermal power, a reactor scram occurred because of IRM upscale trip:. With the reactor steam dome pressure at 850 psig and the pressure regulator set at 930 psig, the licensee was opening main steam line drains to control the reactor vessel heatup rate. As each drain was opened, pressure was allowed to steady out before proceeding. When the last valve before the scram was opaned, pressure and reactor thermal power decreased as expected. The licensed reactor operator down ranged the IRMs to maintain them on scale and to clear the rod blocks, thus a. lowing the withdrawal of additional control rods to restore thermal power. During this transient, the startup feedwater regulating valve responded to a large demand signal, causing a large influx of relatively cold water into the reactor vessel. This resulted in a positive reactivity insertion from the moderator temperature. The operator attempted to uprange the IRMs; however, the IRM upscale trips occurred before this could be accomplished. The IRM upscale trips actuated the reactor protection system (RPS) and the expected reactor scram occurred.

The licensee and the NRC inspector reviewed the scram data information from the emergency response information system (ERIS) and strip chart records -in the main control room. This review indicated that the startup regulating valve was not responding to small demand signals as expected. The licensee subsequently identified an air leak on the startup regulating valve controller which was causing the valve to respond to only large demand signal *

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Prior to restart of the reactor' plant on February 20, 1989, the

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licensee repaired the startup feedwater regulating valve controller

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and required the operating crew that would be initiating criticality a

to startup the simulator through low power operations. Additionally,

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the General Operating Procedure G0P-001, " Plant Startup," was revised to require one bypass valve to be open at least 50 percent before opening a drain line to ensure adequate reactor vessel pressure control.

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Reactor SCRAM Because of Mr.in Turbine Control Valve Closure On February 25, 1989, with the reactor at 78 percent thermal power, a i

reactor scram occurred because of a main turbine control valve fast closure. The main turbine trip resulted during a test of the turbine thrust bearing wear detector. When the test switch was initiated in i

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accordance with the procedure, the associated relay failed to open resulting in a false thrust bearing high vibration signal. The RPS actuated as expected with reactor power greater than 40 percent after detecting the control valve fast closure. All systems responded as expected following the reactor scram. An automatic initiation of the reactor core isolation cooling (RCIC) system occurred on a sensed Level 2 signal'despite the actual level remaining approximately 45 inches above the Level 2 actuation setpoint. The RCIC system

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initiated because the pressure surge resulting from the control valve fast closure was sensed by the reference leg prior to the variable

leg. The momentary increase in pressure on the reference leg side of l

the Rosemont 1154 delta pressure transmitter caused the sensed low

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vessel level and actuation of the RCIC system. Similar actuations of i

f both the RCIC'and high pressure core spray (HPCS) system following l

control valve fast closures is described in NRC Inspection i

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Report 50-458/88-19. The licensee has completed a modification to

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the HPCS trip unit, effectively dampening out the momentary pressure i

spike. Review of the vessel water. level traces for the HPCS system

reproduced the actual vessel level transient. This modification had not been completed on the RCIC system at the time of the event. The NRC inspectors will Sview the licens'ee's actions to modify the

Rosemont 1154 transmitters with a dampening circuit during the second

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refueling outage.

No violations or deviations were identified in this area of the inspection.

4.

Emergency Preparedness Exercise (82310)

On March 1,1989, the licensee held an emergency preparedness exercise to demonstrate their ability to assess, control and recover from a postulated accident. The drill involved initial assessment of the event in the control room with subsequent activation of the technical support

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center (TSC),operationalsupportcenter(OSC),emergencyoperations

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facility (E0F), and establishing communications with offsite local and state authorities. The NRC inspectors observed the emergency exercise from the main control room and TSC.

Activities within the control room were carried out in a professional manner. One example was noted where the failure to have the reactor operator repeat an order given by the shift supervisor resulted in a 15-minute delay-in implementing the cruer. The TSC was activated within 55 minutes of the emergency director ordering the TSC and OSC to be activated.

The NRC inspector noted that, once the TSC was activated, the TSC staff was unable to provide the control room with technical support i

because of a failure to adequately disseminate current plant status to the TSC staff. The results of the emergency drill are described further in NRC Inspection Report 50-458/89-09.

No violations or deviations were identified in this area of the inspection.

5.

Surveillance Test Observation (61726)

STP-250-4501, "Six Month Fire Detection Instrumentation Functional Test,"

Revision 7, dated June 24, 1988. This test demonstrates the fire detection instruments operable by performance of a channel functional test as required by TS 4.3.7.8.1 and 4.3.7.8.2.

The fire detection instruments for each zone listed in a tabular listing shall be operable whenever equipment protected by the fire detection instrument is required to be operable. The TS surveillance requirements (SR) state that:

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Each of the required fire detection instruments which are accessible during unit operation shall be demonstrated operable at least once per 6 months by performance of a channel functional test.

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Fire detectors which are not accessible during unit operation shall be demonstrated operable by the performance of a channel functional test during each cold shutdown exceeding 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> unless performed in the previous 6 months.

Item 1 is addressed by this STP.

Item 2 is addressed by STP-250-4202,

" Inaccessible Fire Detector Instrumentation Functional Test." Precautions and Limitations, paragraph 5.7 of STP-250-4501 states:

"For radiological conditions a general dose rate of greater than 500 mrem /hr will be an inaccessible area. When a fire detection instrument is determined to be inaccessible it will be removed from this STP and added to Reference 2.10 (i.e.STP250-4202)."

The NRC inspector observed portions of the testing in progress and discussed duties and functions with each of the individuals at the following work stations:

Fire control console; Control Room Panel (IN13-P861); remote data acquisition and control (RDAC) panel; and maintenance technicians at the detectors (heat and smoke sensors).

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NRC inspector noted that the performers were knowledgeable of what was

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required and had an understanding of the circuitry involved, procedural adherence was in effect, and lifted / landed leads and jumpers were in accordance with GMP-0042 in that appropriate prerequisite steps had been signed.

No violations or deviations were identified in this area of the inspection.

6.

Maintenance Observation (62703)

The NRC inspectors observed the maintenance activity conducted under Maintenance Work Order (MWO) R120238 which implements Modification Request (MR) 87-0719 and the associated field change notices. This MR was initiated to modify the control building chillers to upgrade each chiller to 100 percent capacity. The present configuration requires both chillers within one division to be operational for that division to be considered operable during the summer months.

The modification includes enlarging the chilled water pump impeller, modifying the associated service water valves, and changing the control circuitry at the chiller units and in the main control room.

The NRC inspectors observed work activities associated with running the control cables and modifying the control board. The shift supervisor or control room foreman strictly controlled the work activity to ensure that associated maintenance activities did not render the chilled water system inoperable. The maintenance personnel were noted to be following the maintenance work instructions, however, each step was not being signed off as it was completed. This observation was identified to the maintenance foreman.

Subsequent maintenance activities will be observed by the NRC inspectors for completion of MR 87-0719.

No violations or deviations were identified in this area of the inspection.

7.

Operational Safety Verification (71707)

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.The NRC inspectors observed operational activities throughout the

inspection period and closely monitored operational events.

Control room activities and conduct were generally observed to be well controlled.

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Proper control room sr ffing was maintained and access to the control room operational areas was controlled. Selected shift turnover meetings were observed and it was found that detailed information concerning plant status was being covered in each of these meetings. Several control board walkdowns were conducted by the NRC inspectors.

In all cases, the i

responsible reactor operators were cognizant as to why an alarm was lit

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and the reason for each plant configuration. Operational conditions and events, identified through discussions with the reactor operators and review of the shift turnover logs, were identified in the main control

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room log.

Inoperable equipment identified during the main control board walkdowns were identified by the applicable limiting condition for operation.

The NRC inspector observed the manual reactor shutdown on February 17, 1989, and the shutdown for the start of the second refueling outage ec March 14, 1989.

Preparations for restart from each of the unplanned reactor shutdowns were also observed.

In each case, the operators remained in control of each evolution and were cognizant of the rapidly changing plant status. The operators for the March 14, 1989, reactor shutdown received specific training on the simulator to cover the shutdown evolution.

The NRC inspectors conducted several tours of accessible areas of the facility during this inspection period.

General housekeeping practices were found to be good. Walkdowns of the low pressure core spray (LPCS),

low pressure coolant injection (LPCI), and high pressure core spray (HPCS)

i systems were conducted. Major flow paths were verified to be in the required standby position. The associated power supply for each major flow path valve and pump was observed to be available. No conditions were noted which would indicate the associated system would not perform its intended safety function.

The NRC inspectors verified that selected activities of the' licensee's radiological protection program were implemented in conformance with facility policies, procedures, and regulatory requirements.

Radiation and/or contaminated areas were properly posted and controlled. Radiation work permits contained appropriate information to ensure that work could be performed in a safe and controlled manner.

Radiation monitors were properly utilized to check for contamination. During plant tours, the NRC inspectors frequently checked calibration stickers on various radiological monitoring equipment and physically verified that selected very high radiation area access control doors were locked and closed.

The NRC inspectors observed security personnel perform their duties of vehicle, personnel, and package search.

Vehicles were properly authorized and controlled or escorted within the protected area (PA).

Personnel access was observed to be controlled in accordance with established procedures. The NRC inspectors conducted site tours to ensure that compensatory measures were properly implemented as required due to equipment failure or degradation. One event involving compensatory measures was identified by the licensee. The proper 10 CFR 73.71 notification was made to the NRC and the NRC inspector was notified. The PA barrier had adequate illumination a the isolation zones were free of transient materials. The licensee operated the plant in a safe, controlled manner during this inspection period.

This event will be further reviewed during an NRC safeguards inspection.

No violations or deviations were identified in this are _ _ _ _ _ _ _ _ _

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8.

Licensee Action on Previous Inspection Finding (Closed) Violation (458/8813-01):

Inadequate shift turnover resulting in the at-the-controls (ATC) operator not being aware why main control board Annunciator P863-75A-C02 was lit.

The NRC inspectors have observed several shift turnovers and questioned the responsible reactor operators on the status of lit annunciators and plant operating conditions. The NRC inspectors have found the operators to be cognizant of each alarm. An example where several shift turnovers failed to identify a TS required system being inoperable was identified in NRC Inspection Report 50-458/88-22 as a violation. The corrective actions implemented by the licensee because of the latest violation has enhanced the operators cognizance of each system's status and added additional controls to ensure each system is restored to its required lineup following manipulation of a system's controls.

This violation is closed.

9.

Exit Interview An exit interview was conducted with licensee representatives on March 23, 1989 (identified in paragraph 1).

During this interview, the NRC inspector reviewed the scope and findings of the report.

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