ML20045F538
| ML20045F538 | |
| Person / Time | |
|---|---|
| Site: | River Bend  |
| Issue date: | 07/02/1993 |
| From: | Gagliardo J NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION IV) |
| To: | |
| Shared Package | |
| ML20045F533 | List: |
| References | |
| 50-458-93-19, NUDOCS 9307080009 | |
| Download: ML20045F538 (18) | |
See also: IR 05000458/1993019
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APPENDIX
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U.S. NUCLEAR REGULATORY COMMISSION
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REGION IV
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Inspection Report:
50-458/93-19
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Operating License:
Licensee:
Gulf States Utilities
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P.O. Box 220
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St. Francisville, Louisiana 70775-0220
Facility Name:
River Bend Station
Inspection At:
St. Francisville, Louisiana
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Inspection Conducted: April 25 through June 5, 1993
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Inspectors:
W. F. Smith, Senior Resident Inspector
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D. P. Loveless, Resident Inspector
lE. T. Baker, Senior Project Manager,
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9 ear Reactor Regulation, Project Directorate IV-2
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Approved:(
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{.E(pagi24rdo, Chief,ProjectSectionC
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Inspection Summary
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Areas Inspected:
Routine, unannounced inspection of onsite response to
events, operational safety verification, maintenance and surveillance
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observations, water level instrumentation errors during and after
depressurization transients, followup on corrective actions for violations,
and other followup.
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Results:
The inspectors found that the licensee's activities in determining and
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correcting the causes of air leakage into the service water system were
appropriate (Section 2.1).
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The licensee's identification of logic system functional test
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discrepancies demonstrated excellent attention to detail (Section 2.2).
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The licensee's corrective actions and analyses regarding the heat
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capacity temperature limit for the suppression pool following a control
room fire with a loss of offsite power were_ appropriate _(Section 2.3).
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During control room observations, the inspectors noted an increase in
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operator formality and the controls over nonoperator visitors. The
9307080009 930702
ADDCK 05000458
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startup on May 31 and the shutdown on June 1, 1993, were conducted in a-
deliberate and careful manner (Section 3.2).
The conduct of the pressure test of Reactor Recirculation Pump B seal to
troubleshoot the' failure was poorly planned resulting in ineffective
communications that were established (Section 4.1).
Work instructions to assure proper assembly of recirculation pump seals
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appeared to be weak and contributed to the seal failure on June 1,1993.
The corrective actions appeared to prevent appropriate recurrence
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(Section 4.1).
The inspector observed conduct of a monthly channel functional test of
the Channel A main steam isolation on low main steam line pressure. . The
results of the test were satisfactory, and the licensee's administrative
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requirements were met, as were regulatory requirements (Section 5.1).
The inspector conducted the survey required by NRC Temporary
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Inst uction (TI) 2515\\l19, " Water Level Instrumentation Errors During
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and After Depressurization Transients," and found that the licensee had
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adequately trained the operators to deal with the phenomenon, should it
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occur (Section 6).
Summary of Inspection Findings:
Violation 458/92021-1 was closed (Section 7.1).
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Violation 458/92021-2 was closed (Section 7.2).
Inspection followup Item 458/93010-2 was closed (Section 8.1).
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Attachments:
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Attachment 1 - Persons Contacted and Exit Meeting
Attachment 2 - NRC Survey for Evaluating Operator Guidance (TI 2515/119)
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DETAILS
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1 PLANT STATUS
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At the beginning of this inspection period, the plant was in a cold shutdown
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condition, since April 18, 1993, for the replacement of both reactor
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recirculation pump seals.
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The plant remained in cold shutdown until June 1, because of additional
maintenance activities in response to a main steam isolation valve that failed'
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to close.
This issue was documented in NRC-Inspection Report 50-458/93-18.
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On June 1, the reactor was taken critical. While heating up, with the reactor.
at about 4 percent power, the outboard seal failed on Reactor Recirculation
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Pump B.
Later that afternoon, the operators shut down and cooled the plant to
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correct the problem.
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At the end of this inspection period,'the plant was in a cold shutdown
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condition to replace the f ailed reactor recirculation pump seal.
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2 ONSITE RESPONSE TO EVENTS (93702)
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2.1
Instrument Air Inleakage to Service Water System
On April 30, 1993, the licensee was troubleshooting a problem which was
identified by the closed loop plant normal service water (SW) system surge
tank level increasing at varying rates from approximately 2 to as much as
20 gpm. After several days of troubleshooting the system, the SW pumps began
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to cavitate.
Large amounts of air had apparently entered the system, and the
air inleakage was displacing the water volume in the system, causing a level
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increase in the surge tank.
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In the reactor building, there are two air accumulators, each connect to a
high point on the safety-related Division I and 11 standby SW loops.
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system was designed so that when SW pressure was lost, target rock solenoid
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operated valves (S0Vs) would open, injecting air into the SW piping to prevent
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water hammer when the standby SW pumps started.
Standby SW pumps were
programmed to start 45 seconds after the normal SW pumps stopped.
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The licensee's inspection of the seating surfaces on the check valves and the
SOVs found good seating surfaces as evidenced by the wear patterns.
Corrosion
products were found in the bottom of Accumulator ISWP*TKlA.
Based on an
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analysis of the corrosion products found, which included cobalt-60 and
manganese-54, and an internal inspection of the tank, the licensee concluded
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that SW had backed up into the accumulator tank and deposited the corrosion
products.
The licensee also concluded that the cause of the air leaking into
the SW system was corrosion particles trapped on the seat of one of the SOVs
which allowed air to be continuously injected into the SW system.
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The licensee cleaned the S0Vs and accumulator tanks.
The licensee also
implemented daily checks of SW chemistry for oxygen content. Oxygen content
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and SW surge tank level increases would be a good indication of air
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in-leakage, so the operators could take timely action. The inspector reviewed
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the licensee's actions to resolve this problem and concluded that they were
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approp,riate.
2.2 Continued Discrepancies Found in Logic System Functional Tests (LSFTs)
NRC Inspection Reports 50-458/93-05 and -93-10 documented licensee-identified
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discrepancies found in certain LSFT surveillance test procedures.
In each
case the problem was a failure to maintain testing continuity or overlap on
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LSFTs to assure that all logic components, from the sensor through the
actuated device were tested to verify operability.
The components in question
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were found to be operable in every case after testing.
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As of the end of this inspection period, the licensee was over 50 percent
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complete on their reviews of surveillance tests, and the following additional
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discrepancies were identified:
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On April 26, 1993, the licensee identified sections of wiring and
contacts associated with the seal-in logic for high pressure core spray
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(HPCS) injection Valve lE22A*MOVF004. Also, contacts that closed the
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HPCS test return valves upon initiation of HPCS were not tested.
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addition, the surveillance test procedure assumed that a Level 8
condition existed in the reactor during the test, when there should have
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been a specific prerequisite to that effect.
The licensee ~ verified
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operability of the circuits through continuity checks, and planned to
correct the test procedure in support of the next time the surveillance
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became due, which would be Refueling Outage 5.
The details were
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documented in Condition Report (CR) 93-0228.
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On May 11, during LSFT reviews of the main turbine trip system, five
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discrepancies were identified by the licensee. The discrepancies
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involved reactor Level 8 trips of the main turbine and reactor feedwater
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pumps. Certain wires and contacts were not tested, and there were no
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checks done on the reactor feedwater pump trips which were to occur on a
Level 8 signal.
The licensee subsequently verified these circuits to be
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operable and indicated plans to correct the applicable surveillance test
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procedures.
This problem was documented in CR 93-0267.
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On June 1, while reviewing the anticipated transient without scram
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system, the licensee discovered that there was no test to verify that
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Reactor Recirculation Pump Breakers 2A, 28, 5A, and SB tripped on
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reactor Level 2 and on high reactor pressure vessel pressure.
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wiring from the control room panels was not tested. The discrepancy was
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limited only to the breakers themselves.
The rest of the logic,
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including relays, trip units, and transmitters, had been tested.
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should be noted that these breakers were opened and closed for control
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purposes during each startup and shutdown evolution.
The licensee _
revised the surveillance test procedures and, as of the end of this_
inspection period, was in the process of conducting the tests. The
inspectors verified completion prior to the reactor startup. This
problem was documented in CR 93-0329.
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On June 3, while performing an LSFT review of the automatic
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depressurization system (ADS), the licensee identified a discrepancy
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where certain contacts and wiring associated with the sealing in of the
high drywell pressure signal were not tested. The seal-in feature was
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tested, but the procedure did not verify that the signal-stayed in until
reset. Also, sections of wire associated with the ADS initiation
signals from high drywell pressure and reactor level 1.
In addition,
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contacts for the low pressure emergency core cooling system pump' running
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permissive were not tested by the LSFT. These problems were documented
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in CR 93-0336.
The licensee's reviewer also discovered that there were no channel
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functional or channel calibration surveillance tests established for the
drywell high pressure bypass timers.
The licensee corrected the surveillance procedures and tested the
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circuits satisfactorily prior to startup. The inspector reviewed the.
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"as-found" channel calibration data taken on the ADS "A"
& "B" drywell
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pressure bypass timers and confirmed that both were within the Technical
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Specification allowable values. All of the other functions tested were
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found to be operable.
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The inspectors questioned the number of discrepancies found in safety-related
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LSFT surveillance test procedures. The licensee indicated that the Human
Performance Enhancement System Engineer was developing a root cause analysis
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and assessment which would be reviewed by plant management for any additional.
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corrective actions and/or expansion of the scope of the reviews to other
surveillance procedures. The inspectors concluded that these actions were
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appropriate and also directed the licensee's attention to NRC Information Notice 93-38, " Inadequate Testing of Engineered Safety Features Actuation
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Systems," which addressed similar problems at pressurized water reactors. The
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root cause will be reviewed under Licensee Event Report 93-002.
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2.3 Procedure for Shutdown from Outside Main Control Room
On May 21, 1993, the licensee identified, during a review of Abnormal
Operating Procedure A0F-0031, Revision 8A, " Shutdown from Outside Main Control
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Room," that the potential existed for exceeding the heat capacity temperature
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limit for the suppression pool within approximately 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> from initiating
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shutdown measures for a fire in the main control room. The licensee
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documented the issue, and the actions taken, on CR 93-0294.
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The concern was related to Design Criterion 240.201 which addressed a main
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control room fire with a loss of offsite power, failure of the Division II
emergency diesel generator, and failure of the high and low pressure core
The Safe Shutdown Analysis assumed that reactor core isolation
spray pumps.
cooling would be used for reactor level control, residual heat removal Pump A
would be available for suppression pool cooling until shutdown cooling could
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be achieved, and reactor pressure would be controlled by three available
safety relief valves, one of which was in the ADS.
The design criterion also
assumed " repairs," such as electrical jumpers to restore control air to the
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ADS would not be necessary until late in the 72-hour postfire period.
Based on preliminary calculations and the guidance provided in the emergency
operating procedures, the licensee found that the operator would need to take
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control of reactor pressure using safety relief valves within the first hour.
Therefore, an electrical jumper would need to be installed much earlier than
was assumed in the design criterion.
The licensee concluded that the existing procedures provided adequate guidance
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to achieve safe shutdown within the assumptions used in Design
Criterion 240.201, for a main control room fire. Therefore, the concern was
determined to not be reportable under 10 CFR Sections 50.72 and 50.73.
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However, to respond to the discrepancies between assumptions made in Design
Criterion 240.201 and the approved procedures for operating the plant in an
emergency, the licensee made the following improvements:
A modification was made to install a switch on Motor Control
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Center IEHS*MCC2L to replace the jumper that would be installed in
accordance with Procedure A0P-0031. This would provide backup air for
the ADS using permanent plant equipment.
Minor changes were made to Procedure A0P-0031 to improve the guidance
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for the above scenario.
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Training of the plant operators was implemented to cover the changes to
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Procedure A0P-0031.
The inspectors reviewed the disposition of the CR, verified completion of the
above items, and noted that all but the training had been. completed for
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startup.
The licensee's response to the concern, and actions taken, were
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considered appropriate.
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2.4 Conclusions
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The licensee's actions to determine the cause and correct air in-leakage to
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the SW system were appropriate.
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The licensee's findings of overlap or continuity problems demonstrated
excellent attention to detail.
The licensee's determination of the root
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causes will be reviewed as followup to the licensee event report.
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The licensee's resolution of the procedure for shutdown from outside the main
control room during a fire in the control room, combined with a loss of
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offsite power, was appropriate.
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3 OPERATIONAL SAFETY VERIFICATION (71707)
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The objectives of this inspection were to ensure that this facility was being
operated safely and in conformance with regulatory requirements.
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3.1
Review of Startup Issues
During liquid penetrant testing of reactor control rod hydraulic control unit
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piping welds, a linear indication was found on Hydraulic Control Unit 40-09.
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CR 93-0209 was generated to document the linear indication. Maintenance Work
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Order (MWO) R158892 was generated to repair and reinspect the weld.
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Approximately 10 thousandths of- an inch (mils) of material was removed and a
penetrant test was performed that determined the indication was a surface
fl aw. Minimum wall thickness was maintained per design.
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As a result of a " weak link" calculation performed for motor-operated valves,
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it was determined that the stem on Valve 1G33*MOVF004 had been overstressed
due to an error in calculating closing torque for the valve. MWO R173872 was
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written to replace the valve stem, stroke time test the valve, conduct
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signature tracing, and perform an local leak rate test. The testing was
performed satisfactorily after the valve was reassembled with a new stem.
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3.2 Control Room Observations
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The inspectors observed control room operations on a sampling basis.
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Operations management had informed the inspectors that efforts had been
underway to continue improvement of control room professionalism and demeanor.
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During this inspection period, the inspector noted an_ increase in control room
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formal ity. Nonoperator access constraints were apparent.
On May 31, the inspector performed back shift (night) observations of the
reactor startup.
The operators were withdrawing reactor control rods on_the
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approach to criticality following the outage.
The operator at the reactor
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controls exhibited careful and deliberate communication with the reactor
engineer by repeating back rod selections.
On June 1, the inspector was in the control room during low power operation at
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about 4 percent reactor power.
The operators were heating up the plant at
less than 30 F per hour to minimize thermal stresses on the leaking fuel
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assembly (see NRC Inspection Report 50-458/93-10, Section 2.1).
The Reactor
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Recirculation Pump B seal failed suddenly, the shift supervisor evaluated the
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condition and, with the support of plant management, decided to shut down and
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repair the seal.
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The shift supervisor briefed all of the operators that were to be involved in -
the shutdown, assigned specific stations, and made sure they were
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knowledgeable of expected plant responses. When everybody was ready and on
station, he directed the reactor operator to scram the reactor as part of the
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normal shutdown process. When the scram was executed, all systems responded
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normally, and the operators responded well to the annunciators.
3.3 Plant Tours
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The inspectors toured 'Se areas of the plant, including the drywell.
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Particular attention
given to the potential of fibrous material clogging
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emergency core cool
sfetem suction strainers during accident conditions, as
described in NRC E
3-02, " Debris Plugging of Emergency Core Cooling
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Suction Strainers.'
spectors noted that there was no such material on
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the drywell coolers,
,a the filters were not installed for this' outage.
The inspectors noted _ e examples of damaged metal covers on fiberglass
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insulation in the drywell.
The damaged insulation was repaired.
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During an evening tour on May 5, the inspectors noted that the Division I
emergency diesel generator fuel oil day tank level was reading slightly below
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55 percent on Level Indicator 1EGF-LIl6A. The inspector questioned a nuclear
equipment operator (NEO) because the level appeared lower than normal. The
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NE0 stated that he was not aware of the required Technical Specification level
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nor was the level indicated for evaluation on his daily rounds log.
During the next morning, the inspector reviewed Surveillance Test
Procedure STP 309-0201, " Diesel Generator Division I Operability Test."
Step 7.12.9 required the operator to verify that the day tank contained a
minimum of 316.3 gallons of fuel, equivalent to a level of 56.5 percent, as
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indicated by Level Indicator 1EGF-LIl6A on Local Panel 1EGS*PNL3A.
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inspector then immediately reverified that the level indicator still read
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approximately 55 percent.
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The inspector called the control room and notified the control operating
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foreman.
The foreman declared the diesel generator inoperable and initiated
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CR 93-0258 to review the problem.
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System engineers developed calculations to evaluate the fuel oil level
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required to meet the minimum requirements of Technical
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Specification 3.8.1.1.b.l.
This specification required that the day tank
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contain a minimum of 316.3 gallons of fuel. The inspector reviewed the
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calculation, which indicated that 44.9 percent indicated level was equivalent
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to 316.3 gallons in the tank.
Additionally, the licensee determined that,
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even with worst-case instrument error, the minimum volume would be assured
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with an indicated tank level of 52.3 percent,
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The inspector independently verified the actual position of the fuel oil
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suction tap on the tank and the relative position of the level transmitter
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sensing line tap. The inspector also independently performed calculations to
verify the licensee's statement that the Technical Specification number of
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316.3 gallons included the unusable volume of the tank.
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The inspector concluded that on May 5 and 6,.1993, the day tank had contained
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more than the minimum usable volume of fuel oil required by Technical
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Speci fication 3.8.1.1.b.1.
The licensee also found that the automatic fuel oil transfer pump was
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programmed to refill the day tank at a level below the minimum required by
Procedure STP 309-0201. The low level alarm was also below this value. The
licensee implemented Modification Request 93-0001 to change the fuel transfer
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pump start and the low level alarm to above the conservative 56.5 percent
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minimum indication required by Procedure STP 309-0201.
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The inspector discussed the NE0's performance with the assistant plant manager
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for operations. He stated that the NE0 should have followed up on the
inspector's original question. He also stated that this was an additional
example of the lack of questioning attitude by plant workers previously
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identified by the licensee and that corrective actions were in progress.
Additionally, the licensee revised Operations Section Procedure OSP-0012,
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" Daily Log Report," to include a verification of the day tank level in the NE0
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daily rounds log.
Overall, the inspectors found that housekeeping and plant equipment' condition
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had improved.
A few minor exceptions were noted and brought to the attention
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of the licensee. The cleanliness and material condition of all- three
emergency diesel generators was not good.
In an effort to improve these
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areas, the licensee implemented cleaning outages on each diesel generator, one
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at a time, during this outage.
3.4 Security Observations
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The inspectors observed security operations at the primary access point as the
security officers processed people into the protected area.
The officers
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appeared to be alert and responsive to all alarms and made sure that people
used the various detection equipment properly
3.5 Radiation Protection Activities
The inspectors noted emphasis on the part of radiation protection technicians
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for minimizing exposures as they processed people into the radiologically
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controlled area.
The licensee's "As Low As Reasonably Achievable (ALARA)"
programs appeared to be given high priority.
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On May 3, 1993, the licensee's radiation protection engineer published an
internal report showing the benefits gained in exposure reduction for this
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outage as a result of the Refuel 4 decontamination of the reactor coolant
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system and the reactor water clean up piping replacement. The inspectors
reviewed the report and noted that significant dose reduction factors were
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developed. On the drywell 82-foot elevation, comparing average dose rates
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prior to Refuel 4 decontamination with average dose rates during this outage,
dose rates had been reduced by a factor of 3.7.
Similarly, for the drywell
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95-foot elevation, dose rates had been reduced by a factor of 2.1.
3.6 Conclusions
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During the outage, the licensee showed careful work controls, conservative
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approaches to system breaches, and a slow and deliberate approach to the
May 31 startup.
Radiation Protection's emphasis on keeping worker doses as
low as reasonable achievable was appropriate.
4 MONTHLY MAINTENANCE OBSERVATIONS (62703)
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The station maintenance activities addressed below were observed and the
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documentation of the activities was reviewed to ascertain that the activities
were conducted in accordance with the licensee's approved maintenance
programs, the Technical Specifications, and NRC regulations.
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4.1 Reactor Recirculatino Pump Seal Failure
On June 1, 1993, during the startup from Forced Outage 93-01, the outboard
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seal for Reactor Recirculating Pump B promptly failed. The plant was at
approximately 4 percent reactor power, and reactor pressure was approximately
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400 psig. The outboard seal cavity pressure had deteriorated from
approximately 220 psig to zero.
Concurrently, drywell unidentified leakage
increased from zero to approximately 0.4 gallons per minute. Within about
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2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br />, the operators commenced a normal shutdown and cooldown to repair the
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seal.
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The licensee's maintenance planners and engineers developed and implemented a
work instruction to pressurize the seal with a hydrostatic test pump while the
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recirculating pump was isolated. The licensee was not able to pressurize the
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seal because of excessive leakage of the recirculation pump isolation
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valve (s) . MWO R175034 was developed to use the control rod drive pump as a
higher volume pressure source.
The inspector reviewed the MWC and questioned
whether the test should have been prepared as a special test procedure. The
MWO format did not appear to include sufficient step-by-step instructions and.
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precautions, and adequate technical reviews may not have been performed to
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assure a safe test designed to preclude equipment damage or personnel injury.
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The licensee's representatives revised the MWO and indicated that the facility
Review Committee had reviewed the MWO.
The licensee's definition of "Special
Test Procedures" in Administrative Procedure ADM-0003, " Development, Control
and Use of Procedures," was sufficiently general to allow the licensee to use
the MWO for pressure tests in conjunction with General Maintenance
Procedure GMP-0070, " General Maintenance Pressure Testing Procedure."
However, this was considered nonconservative based on the reason discussed
above,
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The inspector observed the test on June 3.
Appropriate briefings were held
and the shift supervisor appeared well informed of the planned test details.
Radiation Protection was actively ensuring that radiation exposures were
minimized.
However, test communications were poor.
The test director was in
the drywell, using the gaitronics telephone and paging system to communicate
with a person in the reactor building, who in turn used hand signals to the
operator at the test gauges, who also used hand signals to the operator who
was throttlir.g the control rod drive system valves.
Noise levels in this area
were high, so personnel were required to wear ear plugs. After the test was
started, the control rod drive system was incapable of developing sufficient
flow to overcome recirculating pump isolation valve leakage.
The seal was
only pressurized to approximately 150 psig, which provided inconclusive test
results. The test was terminated and the licensee decided to disassemble the
reactor recirculation pump seal.
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On June 4, while checking the dimension (referred to as the "D" dimension)
between the throttle sleeve nut of the seal and the motor coupling, the
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repairmen noted that the gap was 0.355 inches; it was recorded at 0.176 inches
during installation in early May.
The "D" dimension was set as a function of
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critical seal internal clearances, which in turn affected the clearances and
spring tensions for the sealing surfaces.
Examination of the seal components
upon disassembly in the shop revealed a single crack in the outboard rotating
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seal that went completely through the tungsten carbide element.
Both the
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inboard and the outboard carbon faces were scored.
In addition, the metal at
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the lower end of the keyway in the shaft sleeve was scored indicating that the
sleeve may have been forced against the key.
The licensee concluded that the sleeve failed to go all the way down on the
pump shaft when the seal was installed. The assembly procedure assumed the
sleeve assembly was fully seated and, as such, set up a "D" dimension that was
to establish proper seal clearances and spring tension.
By not going all the
way in, the sleeve was pulled up too high (by 0.355 minus 0.176 inches).
As a
result, the seal springs were compressed too tightly.
This caused excessive
sealing surface forces and, as reactor pressure increased to about 400 psig, a
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ridge on the rotating sleeve contacted the outboard rotating element, creating
abnormal stresses and breaking the element.
As corrective action to prevent recurrence, the licensee developed a series of
specific inspections and measurements to assure that the pump shaft sleeve
would fit freely over the shaft without interference.
These measurements'and
inspections included verification of proper motor end play. Specific internal
clearance dimensions were specified to be taken in the shop when the seal was
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assembled and, as the cartridge was being assembled in the pump, to verify
that internal clearances and rotating element spring tensions would be
correct.
This would assure valid "D" dimension establishment during the final
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stages of assembly.
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At the end of this inspection, the licensee had made the decision to check the
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seal on Reactor Recirculation Pump A, but the scope of that work had not yet
been determined.
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4.2 Conclusions
Performance of the troubleshooting pressure test was poor, in that
communications established between the pressure source control station and the
equipment being tested were crude and could have caused problems if quick
action to mitigate a rupture or a spray had occurred.
The licensee's-
application of the administrative definition of when to implement the more-
formal special test procedure for unusual evolutions aopeared to be
nonconservative.
Work instructions to assure proper assembly of the seal in the pump appeared
to be weak and contributed to the seal failure on June 1.
The corrective
actions to prevent a recurrence of the seal failure that occurred on June 1
appeared sound.
5 BIMONTHLY SURVEILLANCE OBSERVATIONS (61726)
The inspectors observed the surveillance testing of safety-related systems and
components addressed below to verify that the activities were being performed
in accordance with the licensee's approved programs and the Technical
Specifications.
5.1 Main Steam Line Pressure Channel Functional Test
On June 4,1993, the inspector observed instrument and control technicians as -
they performed the channel functional test of the Channel A main steam line
isolation on low main steam line pressure. Thi: test was a monthly
surveillance required by Technical Specification 4.3.2.1.
The test was
performed in accordance with Surveillance Test Procedure STP-051-4514,
Revision 4, " Isolation Actuation /MSLI-Main Steam Line Pressure - Low Monthly
Chfunct; (B21-N676A)."
The technicians performed the test in a deliberate, step-by-step manner, and
the acceptance criteria were met.
Independent verification of leads lifted
and restored was accomplished as required by the licensee's administrative
requirements.
The appropriate approvals were obtained from the operators as
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required by the procedure.
6 WATER LEVEL INSTRUMENTATION ERRORS DURING AND AFTER DEPRESSURIZATION
The objective of this TI was to verify licensee implementation of operator
guidance and training to ensure required operator actions concerning reactor
vessel water level following rapid depressurization transients and, also, to
ensure that this guidance and training was consistent with plant Emergency
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Operating Procedures.
Attachment 2 of this inspection report is the completed survey form provided
as Appendix A, "NRC Survey for Evaluating Operator Guidance," to TI 2515/119.
The survey results are documented by the survey form.
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1he inspector reviewed the licensee's response of September 28, 1992, to the
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generic letter and noted that they were aware of BWR owners group activities
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and guidance provided on this issue.
Based on that guidance, the licensee
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incorporated the effects of noncondensible gases on reference leg reactor
pressure vessel water lever instrumentation in Lesson Plan Number REQ-501-0.
The licensed operators were trained in the classroom on the phenomena, how to
recognize it, and how to deal with it through use of the emergency operating
procedures.
This training was completed on February 19, 1993.
In addition,
the general operating procedure for startup was revised in the fall of 1992 to
make it mandatory to fill reference legs during startup.
The licensee did not have a scenario programmed into the plant simulator where
the operators would be challenged to respond to an unannounced rapid plant
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depressurization concurrent with reactor water level instrument failures due
to gases coming out of solution, nor did they indicate any plans to procure
such a program at the time of this inspection.
In summary, the licensee appeared to adequately train the operators to be
prepared to respond to inaccuracies in reactor pressure vessel level
indications during rapid depresurrizations, and with the aid of a video tape,
clearly explained the phenomenon.
As of the end of this inspection, the
licensee was in the process of expanding the training on this issue based on
receipt of additional information from the BWR Owners Group, and Emergency NRC
Bulletin 93-03, " Resolution of Issues Related to Reactor Vessel Water Level
Instrumentation in BWRs."
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7 FOLLOWUP 0F CORRECTIVE ACTIONS FOR VIOLATIONS (92702)
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8.1
(Closed) Violation 458/9221-01:
Failure to Comoly with ASME Code
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Requi rement s
Established measures did not assure that reactor pressure vessel feedwater
nozzle safe end and feedwater system elbow replacements complied with
ASME Code requirements for, respectively, test specimen location and wall
thickness.
The inspector verified that Procedure EDP-E0-22, " Items With Special
Considerations for Procurement, Transfer or Upgrade," Revision 0, included
committed actions for identification of test specimen locations in
ASME Class 1 forged materials and verification of wall thickness in ASME large
bore elbows.
The inspector also confirmed that the feedwater system elbow had
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been rejected and that the final mechanical testing of the safe-end material
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was in conformance with ASME Section Ill Code requirements.
7.2 1 Closed) Violation 4S8/9221-02:
f ailure to litilize Qualified Welding
Procedure Specification
The welding procedure specification (WPS) for welding the reactor vessel
feedwater nozzle safe end replacement material, WPS W3-16-AGT, Revision 0, was
not qualified in accordance with the requirements of MME Code,Section IX.
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Specifically, supplementary essential variables QW-405.2 and-QW-409.1,
pertaining, respectively, to a change in position to the vertical position
uphill progression and an increase in heat input over that which was
qualified, were not supported by appropriate procedure qualification records.
The inspector verified that the committed training of the licensee welding
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group had been performed and that the-additional procedure qualifications
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tested by the licensee brought WPS W3-16-AGT into conformance with ASME Code,
Section IX, qualification requirements.
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8 FOLLOWUP (92701)
8,1 IClosed) Inspection Followup Item 458/9310-02: Adeauacy of
Pp;.saintenance Testing Specified for Replacement Relays
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On May 4,1993, the inspector reviewed the process for establishing the retest-
for the MDR relays used in the circuits for the Main Steam Line Isolation,-
Main Steam Line Radiation High feature. The planners selected a surveillance
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test procedure and verified, from the elementary schematic, that the relay
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circuits were tested. The system engineer performed a second verification of
the testing.
In some cases a specific continuity check would be specified in
the retest portion of the MWO to supplement the surveillance test procedure or
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simplify the retest. The inspector concluded that the process used to specify
retesting of MDR relays was comprehensive and thorough.
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ATTACHMENT 1
1 PERSONS CONTACTED
1.1 Licensee Personnel
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- R. L. Biggs, Supervisor, Quality Control
- J. B. Blakley, Assistant Plant Manager, System Engineering
- J. E. Booker, Manager, Safety Assessment and Quality Verification
B. R. Burke, Chemistry Supervisor
- M. E. Crowell, Maintenance Support Supervisor
- W. L. Curran, Cajun Site Representative
D. R. Derbonne, Assistant Plant Manager, Operations, Radwaste & Chemistry
L. L. Dietrich, Supervisor, Nuclear Licensing
R. G. Easlick, Radwaste Supervisor
L. A. England, Director, Nuclear Licensing
A. O. Fredieu, Supervisor, Maintenance Services
- P. E. Freehill, Assistant Plant Manager - Outage Management
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J. Giadrosich, Director, Quality Assurance
P. D. Graham, Vice President (RBNG)
J. R. Hamilton, Manager-Engineering (RBNG)
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- W. C. Hardy, Radiation Protection Supervisor
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R. T. Kelly, Instrument and Controls Supervisor
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G. R. Kimmell, General Maintenance Supervisor
- R. W. Koffman, Nuclear Security Representative
- R. P. Lacour, Employee Relations Administrator
- D. N. Lorfing, Supervisor, Nuclear Licensing
- R. C. Lundholm, Supervisor, Mechanical Process Systems
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- I. M. Malik, Supervisor, Quality Operations
- C. R. Maxson, Supervisor, Performance Assessment
J. F. Mead, Supervisor, Control Systems
- Q. V. Nguyen, P,eliability Engineer
W. H. Odell, Director, Radiological Programs
- S. R. Radebaugh, Assistant Plant Manager - Maintenance
R. L. Roberts, Electrical Maintenance Supervisor
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- L. W. Rougeux, Senior ISEG Engineer
- J. P. Schippert, Plant Manager
B. R. Smith, Mechanical Maintenance Supervisor
M. A. Stein, Director - Plant Engineering
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- K. E. Suhrke, Manager, Site Support
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W. J. Trudell, Assistant Operations Supervisor
J. E. Venable, Operations Supervisor
S. L. Woody, Director, Nuclear Station Security
- Denotes personnel that attended the exit meeting.
In addition to the
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personnel listed above, the inspectors contacted other personnel during this
inspection period.
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2 EXIT MEETING
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An exit meeting was Lunducted On Jena 8. 1993. During this meeting, the
inspectors reviewed the scope and findings of the' report.
The licensee did
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not identify as proprietary any information provided to, or reviewed by, the
inspectors.
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ATTACHMENT 2-
APPENDlX A TO TI 2515/119
NRC Survey for Evaluating Operator Guidance
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Docket Number:
50-458
Plant Name:
River Bend Station
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Date Completed:
May 31, 1993
Inspector: Ward F. Smith
Yes
1.
Are licensed operators knowledgeable and capable of executing the
guidance discussed in the August 19, 1992, and October 16, 1992
letters from B. T Williamson II, Chairman of the BWROG Emergency
Procedures Committee (EPC) to all plant operations superintendents
(references 3 and 4)?
No
2.
Have licensed operators been provided other guidance in addition
to or in place of the above letters concerning this issue?
If
yes, provide discussion below.
Yes
3.
Have all licensed operators received classroom training on this
guidance?
If not, when will it be completed? February 19, 1993
.
No
4.
Have all licensed operators received simulator training on this
guidance?
If not, when will it be completed?
The operators have had simulator scenarios where upon loss of RPV
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level indication, the E0P contingency for RPV ficoding was
entered.
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No
5.
Does the licensee's plant simulator adequately model the failure
of reactor water level instrumentation to lead the operators to
enter the E0P contingency for RPV flooding?
No
6.
Have the contents of the above letters or similar guidance
consistent with this guidance been permanently incorporated into
licensee training programs for licensed operators?
If not, when
will this be completed?
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The guidance was incorporated into the 2-year cycle
requalification training programs, and all existing licensed
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operators were trained by February 19, 1993. The licensee had not
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incorporated the guidance into initial training, as of this
inspection, but indicated plans to do so in time to support the
next initial training sequence which was scheduled to start in
June 1993.
No
7.
Does the licensee's continuing training program for licensed
operators include a dynamic simulator scenario for rapid plant
depressurization concurrent with reactor water level instrument
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failures?
Yes
8.
Has the licensee checked the Emergency Operating Procedures (EOPs)
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for inconsistencies with the above guidance?
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No
9.
Wert any inconsistencies found by the licensee between the E0Ps
and the guidance?
If yes, what were the inconsistencies and have
they been resolved?
Yes
10.
Has the licensee taken or planned any actions to minimize the
likelihood of level indication errors, such as minimizing leakage
from the level instrumentation?
If yes, provide discussion below.
The licensee is considering a modification which would provide a
constant vent coming off the condensing pot to the main steam
This is the most favored alternative at this time;
however, others are being looked at.
No
11.
Has the licensee experienced any level instrumentation anomalies
during depressurization?
If yes, provide discussion below.
A