IR 05000458/1999012
| ML20217L785 | |
| Person / Time | |
|---|---|
| Site: | River Bend  |
| Issue date: | 10/19/1999 |
| From: | NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION IV) |
| To: | |
| Shared Package | |
| ML20217L771 | List: |
| References | |
| 50-458-99-12, NUDOCS 9910270072 | |
| Download: ML20217L785 (23) | |
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ENCLOSURE U.S. NUCLEAR REGULATORY COMMISSION
REGION IV
Docket No.:
50-458 License No.:
NPF-47 Report No.:
50-458/99-12
- Licensee:
Entergy Operations, Inc.
~ Facility:
. River Bend Station Location:
5485 U.S. Highway 61 St. Francisville, Louisiana Dates:
August 22 through October 2,1999 Inspectors:
' T. W. Pruett, Senior Resident inspector N. P. Garrett, Resident inspector Approved By:
William D. Johnson, Chief, Project Branch B Division of Reactor Projects Attachment:
SupplementalInformation 9910270072 991019 PDR ADOCK 050%458 G
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EXECUTIVE SUMMARY l
River Bend Station NRC Inspection Report No. 50-458/99-12 This routine announced inspection included aspects of licensee operations, engineering, maintenance, and plant support. The report covers a 6-week period of resident inspection.
Operations The inspectors identified four examples where main control room operators were not
aware of temperature and pressure indications associated with the suppression pool, containment, and drywell parameters. Specifically, operations personnel were not aware of deviations associated with computer points for suppression pool temperature and drywell temperature and strip chart recorder deviations for containment temperature and pressure. These instances of a lack of plant status awareness represented a failure to meet the requirements of Procedure ADM-0022," Conduct of Operations." This was a violation of Technical Specification 5.4.1.a. This Severity Level IV violation is being treated as a noncited violation, consistent with Appendix C of the NRC Enforcement Policy. This item was entered into the licensee's corrective action program as Condition Report 1999-1448 (Section 01.1).
Operations personnel demonstrated good use of three-way communications, peer
checks, and annunciator response. Nuclear equipment operators demonstrated a good understanding of plant equipment (Section 01.2).
Enaiqeerina The inspectors found that the licensee had not tested the time retention feature of the
standby service water vacuum release solenoid valves. Subsequent testing by the licensee determined that there had not been any degradation of the retention relay setting since installation. This Severity Level IV violation of Criterion XI of Appendix B to 10 CFR Part 50 is being treated as a noncited violation, consistent with Appendix C of the NRC Enforcement Policy. This item was entered into the licensee's corrective action program as Condition Report 1999-1510 (Section E2.1).
The inspectors found that the licensee performed an inadequate technical evaluation for
isolating Division I standby service water supply motor-operated Valve SSW MOV-077A to the Division ill jacket water cooler. Specifically, the evaluation did not include an assessment of the impact on Division til emergency diesel generator operability, the motor-operated valve operating charreteristics, and operator actions to reopen Valve SSW MOV-077A. This Severity Level IV violation of Criterion V of Appendix B to 10 CFR Part 50 is being treated as a noncited violation, consistent with Appendix C of the NRC Enforcement Policy. This item was entered into the licensee's corrective action program as Condition Report 1999-1475 (Section E2.1).
The inspectors identified six examples where the licensee had not correctly translated
design information into standby service water documents involving the time retention feature of the vacuum release solenoid valves, a modification which changed normal
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-2-service water from an open to a closed system, reduced standby service water flow to the residual heat removal heat exchangers, isolation of the normal service water system within 20 minutes of a failure of a divisio1 of standby service water, and Updated Safety Analysis Report sampling requirements for the suppression pool and residual heat
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removal system not performed or specified in chemistry sampling procedures. In addition, the licensee identified that filters had not been rer'ioved from containment fan coolers as described in the Updated Safety Analysis Report. The circumstances addressed in Licensee Event Report 50-458/99-02 are addressed in the licensee's corrective action program as Condition Report 1999-0137. This Severity LevelIV violation of Criterion til of Appendix B to 10 CFR Part 50 is being treated as a noncited I
violation, consistent with Appendix C of the NRC Enforcement Policy. These items were entered into the licensee's corrective action program as Condition Reports 1999-0137, -
1488, -1489, -1493, -1500, and -1510 (Sections E2.1, E8.2, and R3.1).
Plant Support j
The licensee conducted effective postexercise critiques which identified several
performance issues and adequate overall cerformance during the September 21,1999,
emergency exercise (Section P1.1).
The licensee identified several deficiencies during the September 21,1999, emergency
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exercise. These included an incorrect event declaration, poor emergency response J
organization communications, slow dispatch of field teams, poor site evacuation of personnel, and slow activation of the technical support center. Additional issues identified by inspectors included not using the off-site fire department to combat the fire and the technical support center not considering the use of standby service water as an alternate injection source (Section P1.1).
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Report Details Summarv of Plant Status The facility operated at essentially 100 percent power during the inspection period. On September 3,1999, operations personnel reduced reactor power to approximately 60 percent to complete suppression testing in order to locate a leaking fuel assembly.
l. Operations O1.1 Operator Awareness of Main Control Room Panels J
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insoection Scope (71707)
The inspectors conducted frequent walkdowns of main control room panels and questioned operations personnel on instrument deviations.
b.
Observations and Findinas Technical Specification 5.4.1.a requires, in part, that written procedures' be established, implemented, and maintained covering the applicable procedures recommended in Regulatory Guide 1.33, Revision 2, Appendix A, February 1978. Section 2 of Appendix A of Regulatory Guide 1.33 requires the licensee to have general plant operating procedures for power operation and process monitoring. Section 4.2 of Procedure ADM-0022. " Conduct of Operations," specified that the operations shift superintendent, control room supervisor, and plant operators on shift must be aware of,
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and responsible for, the plant status at all times. Between August 25 and September 7, 1999, the inspectors identified four exampics where main control room operators were
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not aware of indications affecting suppression pool temperature, containment j
temperature, drywell temperature, and containment /drywell differential pressure.
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Suppression Pool Temperature Indication On August 25,1999, the inspectors observed that seven of the eight suppression pool temperature computer point indications were reading between 84 and 88 F while the computer point indication associated with RTD-24E appeared abnormally high with a reading of 93*F. The inspectors determir ed that main control room operators were unaware of the deviation and were unable to explain the cause of the deviation.
Tne licensee and inspectors subsequently determined that the strip chart recorder and the analog trip module indication for RTD-24E indicated 86*F. Based on the alternaie indications, operations personnel determined that the plant computer point for RTD-24E was suspect and initiated a maintenance action item (MAI) to investigate and repair the abnormal indication. The inspectors determined that the failure of plant operators to be aware of the suspect suppression pool temperature indication was a violation of Technical Specification 5.4.1.a. This Severity Level IV violation is being treated as a noncited violation, consistent with Appendix C of the NRC Enforcement Policy (NCV 50-458/9912-01). This violation is in the licensee's corrective action program as Condition Report (CR) 1999-144 w, s-
-2-Containment Temperature indication On September 1,1999, the inspectors observed that 9 of the 10 containment temperature strip chart recorder instruments displayed readings between 74 to 85*F while containment temperature Instrument CMS-RTD42D indicated a reading of 95.2*F.
The inspectors determined that the main control room operators were unaware of the deviation and could not explain whether the indication was valid or invalid.
Operations personnel subsequently determined that the instrument had been the subject of CR 1995-0738. Specifically, due to the location in containment, CMS-RTD42D consistently displayed a value greater than the other containment temperature indications. The licensee subsequently discontinued log keeping requirements using the instrument because the parameter provided an umoalistic containment average temperature derivation. The corrective action for CR 1995-0738 included a revision to the Technical Requirements Manual to delete the iristrument from the containment average temperature surveillance requirement. Nevertheless, the inspectors determined that the failure of plant operators to be aware of the containmert temperature indication was a second example of the violation of Technical Specification 5.4.1.a.
Drywell Temperature On September 3,1999, the inspectors observed that the data for drywell temperature computer point DRS-TA01 indicated invalid (white) data and displayed a temperature of 104*F. The inspectors determined that main control room operators were unsure what the white color meant and why the reading was white. During subsequent discussions, operations personnel determined that the drywell unit cooler outlet temperature indication did not have a milliamp input signal, which was the cause for the invalid (white) data, and initiated MAI 328017 to correct the deficiency. The inspectors determined that the failure of plant operators to be aware of the suspect drywell temperature indication was a third example of the violation of Technical Specification 5.4.1.a.
The inspectors noted that the temperature indications for the drywell unit coolers were reading between 95 and 106*F. The inspectors then questioned the at-the-controls reactor operator about the temperature difference. The at-the-controls operator could not explain the reason for this temperature range; however the unit operator informed the inspectors that a drywell unit cooler had been secured which resulted in the high
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local temperature indication.
Drywell and Containment Differential Pressure On September 7,1999, the inspectors observed that drywell pressure indicated -0.4 psi,
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that containment pressure indicated -0.1 psi, and that the containment /drywell differential pressure indicated 0.01 psi. The inspectors questioned main control room operators to determine why the differential pressure indicated 0.01 psi instead of l
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-3-0.30 psi. The main control room operators were unaware of the discrepancy and questioned whether the instrument was responding correctly. The control room supervisor subsequently referred the question to system engineering personnel.
On September 8,1999, system engineering personnel informed the inspectors that each of the indications was derived from a separate transmitter. The inspectors reviewed the ellowable instrument tolerances and determined that the main control room indications were responding appropriately. Nevertheless, the inspectors determined that the failure of plant operators to be aware of the containment /drywell differential pressure indication was a fourth example of the violation of Technical Specification 5.4.1.a.
Licensee Corrective Actions I
Following the inspectors' observations, the licensee initiated CR 1999-1448 to document the issue. As an interim corrective action, the operations manager discussed the
observations with the shift superintendents with the understanding that they would question operatione personnel on main control room instrument indications.
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_Qonclusions The inspectors identified four examples where main control room operators were not aware of temperature and pressure indications associated with the suppression pool, containment, and drywell parameters. Specifically, operations personnel were not aware of deviations associated with computer points for suppression pool temperature and drywell temperature and strip chart recorder deviations for containment temperature and pressure. These instances of a lack of plant status awareness represented a failure to meet the requirements of Procedure ADM-0022," Conduct of Operations." This was a violation of Technical Specification 5.4.1.a. This Severity Level IV violation is t'eing treated as a noncited violation, consistent with Appendix C of the NRC Enforcement Policy. This item was entered into the licensee's corrective action program as Condition Report 1999-1448.
01.2 Control Room and Nuclear Eauipment Operator Observations a.
Inspection Scope (71707)
The inspectors performed frequent observations of main control room and nuclear equipment operato activities.
b.
Observations and Findinas in most instances, the inspectors observed frequent use of three-way communications during evolutions in the main control room. Peer checks were typically requested and provided for control panel switch manipulations. Operations personnel promptly responded to annunciator alarms.
The inspectors accompanied nuclear equipment operators on tours of building assignments. The nuclear equipment operators demonstrated a good understanding of
e d-4-equipment associated with the assigned watch station. Radio and gaitronics communications with the main control room utilized three-way communication techniques, c.
Conclusions Operations personnel demonstrated good use of three-way communications, peer l
checks, and canunciator response. Nuclear equipment operators demonstrated a good l
understanding of plant equipment.
Operational Status of Facilities and Equipment O2.1 Identification of Fuel Leak l
On August 21,1999, reactor power was reduced to approximately 60 percent to conduct l
suppression testing of the core in order to locate a potential leaking fuel assembly. The suppression test was performed on one-half of the core and no leaking fuel assemblies
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were identified. On September 3,1999, reactor power was again reduced to approximately 60 percent to complete suppression testing of the core. During the test, a leaking fuel assembly was located in the vicinity of Control Blade 20-25. Operations personnel inserted the control blade in the core to suppress the leaking assembly.
Engineering personnel preliminarily determined, through a review of chemistry data, that the leaking fuel pin was h3w GE-11 fuel from Batch IGE.
Miscellaneous Operations issues (92700)
08.1 Violation Closure The inspectors performed an in-office review of outstanding violations in the operations area. The Severity Level IV violations listed below were issued in a Notice of Violation prior to March 11,1999. On this date, the NRC changed the policy for treatment of Severity Level IV violations (Appendix C of the Enforcement Policy). Because these
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l violations would have been treated as noncited violations in accordance with l
Appendix C, they are being closed out in this report, consistent with the new l
Enforcement Policy for Severity Level IV violations. The inspectors venfied that the l
licensee had included these violations in their corrective action (CA) program. The CA program references for the violations are listed below.
r Violation Number Description CA Program Reference 50-458/9812-01 Failure to operate plant breakers in CR 98-0707,98-0675 accordance with clearance order t
l requirements 50-458/9719-01 Failure to follow procedures addressing CR 97-2080 l
electrical separation criteria l
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5-II. Maintenance M1 Conduct of Maintenance M1.1 General Comments a.
Inspection Scone (62707 and 61726)
The inspectors observed all or portions of the following maintenance and surveillance activities:
- Surveillance Test Procedure (STP)-255-6302, Division 11 Positive Leakage
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Control System Quarterly Valve Operability Test STP-209-6310, Reactor Core isolation Cooling Quarterly Pump and Valve
Operability Test STP-256-6304, Division I Standby Service Water Quarterly Valve Operability
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Test
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MAI 323296, EGS-PNL3B, Calibrate EGS-PSX378, EGS-PS39B, EGS-PS40B,
EGS-PS418, EGS-PSX74B, and EGS-PSY74B MAI 323295, EGS-PNL3B, Calibrate EGS-PSX30B, EGS-PSX86B,
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EGS-PSY308, and EGS-PSY86B b.
Observations and Findinas Observed activities were performed with the work package or surveil!ance procedure in active use. When applicable, appropriate radiological control measures were
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implemented. No deficiencies were identified by the inspectors during the conduct of the above activities.
l M8 Miscellantrous Maintenance issues (92902)
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M8.1 yiolation Closure l
The violations listed below are closed consistent with the guidance previously provided i
in Section 08.1 of this report.
Violation Number Description CA Program Reference 50-458/9804-02 Failure of containment isolation damper CR 98-0015 l
50-458/9719-03 Failure to maintain postaccident CR 98-0036 l
sampling system operable
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6-50-458/9717-04 Failure to comply with Technical CR 97-1944 Specification Action after airlock surveillance failed Ill. EnaineeAng E2 Engineering Support of Facilities and Equipment E2.1 Review of Standby Service Water (SSW) System a.
Insoection Scoce (37551 and 61726)
The inspectors conducted walkdowns, reviewed selected design and licensing basis j
documents, and assessed corrective actions for issues involving the SSW system.
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Observations and Findinas Operation of Vacuum Relief Valves Updated Safety Analysis Report (USAR) Section 9.2.7.3 specified that automatic
vacuum release equipment was provided by solenoid valves which open automatically
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on loss of normal service' water pressure to admit air into the SSW lines. On September 7,1999, the inspectors questioned engineering personnel on the basis for the timing of the solenoid valves to open and the length of time the solenoid valves
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On September 15, engineering personnel initially stated that the SSW line vacuum release solenoids, Valves SSW-SOV522A, -522C,- 523A, and-525C, opened automatically after a 30 second time delay as specified in SSW system design criteria and logic diagram LSK-9-10.3Y. The inspectors determined that the first SSW pump l
started approximately 42 seconds following a loss-of-offsite-power (LOOP) event and l
questioned whether the SSW system could refill with sufficient air to minimize a hydraulic event. The inspectors also questioned engineering personnel on the type of testing conducted to verify the time delay response of the vacuum release solenoid valves.
l On September 22, engineering personnel provided sufficient design basis documentation (Set-point Data Sheet 12210-lA-62-1SWPA71, " Set-point Calculation for l
Timers 62-1SWPA71; 62-1SWPB71 for Service Water Line Vacuum Release Valves,"
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i and Calculation 228.800-PX-1006-0, " Transient Cavitation [ Column Separation and Rejoining] in Service Water System") to demonstrate that the rotenoid valves had a 42 second time retention relay and not a 30 second time delay relay. However, during the review, the licensee determined that sevr ral documents did not contain correct I
information regarding the configuration of the SSW system. Specifically:
The control system descripion for " Auxiliary Water Systems Service
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Water-Standby, Diagram Number 9-10.3," Section LSK-9-10.3Y, item 54, indicated, in part, that the vacuum release solenoid valves are energized to open
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Set-point Data Sheet 12210-IA-62-1SWPA71 was not revised to reflect a
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modification which changed the normal service water system from an open to closed system.
Calculation 228.800-PX-1006-0 was not revised to reflect a modification which
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changed the normal service water system from an open to closed system.
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Criterion lll of Appendix B to 10 CFR Part 50 requires, in part, that measures shall be established to assure that applicable regulatory requirements and the design basis for l
structures, systems, and components are correctly translated into specifications, drawings, procedures, and instructions. The inspectors determined that the failure to ensure SSW system requirements were correctly translated into set-point sheets, calculations, and control system descriptions represented three examples of a violation of Criterion 111 of Appendix B to 10 CFR Part 50. This Severity Level IV violation is being treated as a noncited violation, consistent with Appendix C of the NRC Enforcement Policy (NCV 50-458/9912-02). This violation is in the licensee's corrective action
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program as CRs 1999-1493 and 1999-1510.
Criterion XI of Appendix B to 10 CFR Part 50 requires, in part, that a test program shall be established to assure that all testing required to demonstrate that structures, systems, and components will perform satisfactorily in service is identified and performed in accordance with written test procedures. On September 22, engineering personnel informed the inspectJrs that documentation which demonstrated the ca'
ility of the 42 second time retention feature of the vacuum release solenoid valves co act be identified. Engineering personnel reasoned that operational testing of the time retention relays had not been specified or conducted. The inspectors determined that the failure to perform testing of the vacuum relief solenoid valve time retention relays was a violation of Criterion XI of Appendix B to 10 CFR Part 50. This Severity LevelIV violation is being treated as a noncited violation, consistent with Appendix C of the NRC Enforcement Policy (NCV 50-458/9912-03). This violation is in the licensee's corrective action program as CR 1999-1510.
The licensee initiated MAls 328436 and 328437 to perform testing of the time retention relays. On September 24, maintenance personnel verified that the time retention relays had been set within the allowable tolerances for the circuit.
Procedural Discrepancies USAR Section 9.2.5.3 specified, in part, that, in order for the standby cooling tower basin water temperature to be maintained at or below 95*F and to ensure the SSW system pumps provide sufficient flow to the safety-related components during a LOOP / Loss of Coolant Accident (LOCA), procedures require the following: Throttle the SSW flow to the residual heat removal (RHR) heat exchangers from 5,800 gpm to approximately 3,000 gpm when the standby cooling tower water level drops to an
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elevation of 90 feet. USAR Table 9.2-15," Standby Service Water System Major Component Design Data," also specified that SSW flow to the RHR heat exchangers will be throttled to 3,000 gpm when the standby cooling tower basin water level drops to an i
elevation of 90 feet follo' wing a LOOP /LOCA.
The decrease in flow to the RHR heat exchangers was evaluated by the licensee in CR 1995-0167. The licensee's investigation determined that the SSW system is operable and will provide sufficient flow to the safety-related components for the full 30 days following a LOOP /LOCA provided that the SSW flow is throttled to the RHR I
heat exchangers from 5800 gpm to 3000 gpm when the standby cooling tower basin water level drops to an elevation of 90 feet.
The inspectors determined that Procedure ARP P870-55 for Alarm Number 1066, i
Standby Service Water Cooling Tower Minimum Level," specified that, if the standby cooling tower level drops below 90 feet, "then consider" throttling SSW flow to the RHR heat exchangers to 3,000 gpm or less. The inspectors determined that the phrase "then consider" could result in operations personnel not throttling SSW flow when required.
The licensee agreed with the inspectors' assessment and initiated CR 1999-1489. In addition, the licensee initiated a procedure revision to require throttling of SSW flow to the RHR heat exchangers if standby cooling tower basin dropped below 90 feet. The inspectors determined that the failure to translate design basis information regarding the reduction of flow to the RHR heat exchangers in the alarm response procedure for the standby cooling tower level was a fourth example of the violation of Criterion 111 of Appendix B to 10 CFR Part 50.
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USAR Section 9.2.7.3 specified that operator action to close the nonsafety-related SSW return valve will be required after 20 minutes to limit water loss from the unisolated subsystem to the nonsafety-related normal service water system. Procedure AOP-0016, " Loss of Standby Service Water," Section 5.1.7, specified, in part, that "if necessary" to isolate normal and SSW to limit water loss from the unisolated A/B i
subsystem to the rensafety-related normal service water subsystem, then within 20 minutes, close tha supply and return header isolation valves. The inspes. tors determined that the phrase "If necessary" could result in operations personnel not I
isolating the faulted subsystem within 20 minutes. The licensee agreed with the inspectors assessment and initiated CR 1999-1488. In addition, the licensee initiated a i
procedure revision to require isolation of the affected subsystem within 20 minutes.
The inspectors determined that the failure to translate design basis information regarding the isolation of a faulted SSW subsystem into abnormal response procedures was a fifih example of the violation of Criterion lli of Appendix B to 10 CFR Part 50.
Failure of SSW Check VLive SSW-135 On March 16,1999, the licensee initiated CR 1999-0318 to document and evaluate the failure of the Division 111 emergency diesel generator (EDG) jacket water cooler supply Check Valve SSW 135. Specifically, during the performance of STP-000-6802,
" Miscellaneous Check Valves Cold Shutdown Radiography Test," the licensee determined that Valve SSW-135 was not close.
Valve SSW-135 provided one of two SSW supply check valves to the Division lil EDG.
The two divisions of SSW are connected at the supply and return from the Division lli EDG. The supply check valves function to prevent the diversion of flow from one operational SSW division to the other. Valve SSW-135 is b the Division i service water supply line in series with the Division ill EDG jacket water c >oler supply motor-operated Valve MOV-077A. The motor-operated valves in series with the check valves allow for isolation of one division of SSW to the Division lll EDG if one division of SSW is lost.
USAR Section 9.2.7.3, " Safety Evaluation," specified that the two redundant SSW systems merge to supply a single component in two locations, the Division ill EDG Jacket water cooler and the high pressure core spray pump room unit cooler. In these locations, cooling water supply lines are provided with motor-operated valves and check valves, while return lines are provided with motor-operated valves. These valves can be
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closed by operator action, either to isolate the component should a failure occur, or to isolate an operating SSW system from the inoperable redundant system.
I Between March 16 and 31,1999, the licensee determined that it was acceptable to close normally open Valve MOV-077A until repairs to Valve SSW-135 could be completed. The licensee determined that a safety evaluation was not required in that the new alignment (maintaining SSW MOV-077A closed) did not create a different situation that required operator action because Procedure AOP-016," Loss of Standby
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Service Water," provided direction to close the Division ll motor-operated valves and open the Division I motor-operated valves in the event that Division ll SSW failed.
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Tne inspectors determined that, for a loss of Division ll, Section 5.2.5 of Procedure AOP-016 directed operations personnel to close the Division 11 valves and open the Division i valves. However, the inspectors determined that a more thorough evaluation should have been performed since the normal operating configuration of the SSW j
system, as described in the USAR, was with Valve MOV-077A aircady open. The inspectors reviewed the licensee's evaluation for operating the facility with Valve MOV-077A closed and identified several issues. Specifically:
With the Division l SSW supply isolated, a failure of the Division 11 SSW system
could render the Division lli EDG inoperable due to no SSW being supplied to the EDG jacket water cooler. Normally, the Division l SSW supply would be in service; therefore, no interruption of cooling water flow would occur following a loss of the Division ll SSW system.
With Valve SSW MOV-077A closed, the differential pressure across '.ae valve
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seat would increase to approximately 110 psid on a failure of the Wision ll SSW r
system. However, Calculation G13.2.3*289," Generic Letter 95-10 Design Basis Review for SSW MOV 506A/B & 077A/B," specified a 4.0 pf.d differential pressure across Valve MOV-077A.
With Valve SSW MOV-077A closed, the potenti;; existed for both divisions of
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SSW supply and return valves to the Division ill EDG to be isolated before restoration of the Division I Sc'W system. Calculation G13.2.3'289 specified that no requirements were noted 6 Sosing of the supply ano return valves
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-10-(SSW-MOV 506A/B & 077A/B) for both divisions, indicating that the supply and return valves for at least one SSW division will always remain open.
The evaluation did not consider the amount of time required for operators to
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recognize a failure of the Division ll SSW system and take action to open Valve SSW MOV-077A to restore cooling water flow to the Division 111 EDG Jacket water cooler.
Criterion V of Appendix B to 10 CFR Part 50 requires, in part, that activities affecting quality shall be prescribed by procedures and be accomplished in accordance with procedures. Section 6.4.4 of Procedure RBNP 078," Operability Determinations,"
specified, in part, that a CR corrective action be initiated requiring a technical evalur. Son of the degraded or nonconforming condition. The inspectors determined that the failure to consider all aspects of closing Valve SSW MOV-077A in the technical evaluation, including the impact on Division lli EDG operability, the motor-operated valve operating characteristics, and operator actions to reopen Valve SSW MOV-077A, was a violation of Criterion V of Appendix B to 10 CFR Part 50. This Severity Level IV violation is being treated as a noncited violation, consistent with Appendix C of the NRC Enforcement Policy (NCV 50-458/9912-04). This violation is in the licensee's corrective action program as CR 1999-1475.
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On September 22, engineering and operations personnel concurred with the inspector's assessment that the technical evaluation for closing Valve SSW MOV-077A was inadequate. On an interim basis, the licensee issued Standing Order 169, " Operability of Division til Diesel Generator and Ventilation-Reactor Plant * Unit Cooler 5," to require that the Division ll! EDG and/or high pressure core spray pump room unit cooler be declared inoperable if any of the associated SSW supply or return valves are closed.
The licensee also initiated CR 1999-1475 to review the lack of sufficient discussion and consideration of system interactions in the technical evaluation, c.
Conclusions i
The inspectors identified five examples of a violation of Criterion ill of Appendix B to 10 CFR Part 50 involving the f ailure to ensure regulatory requirements were correctly translated into specifications, drawings, procedures, and instructions. Specifically, the licensee had not correctly translated information into SSW documents involving the time ietention feature of the vacuum release solenoid valves, a modification which changed normal service water from an open to a closed system, reduced SSW flow to the RHR heat exchangers, and isolation of the normal service water system within 20 minutes of a f ailure of a division of SSW. This Severity Level IV violation is being treated as a noncited violation, consistent with Appendix C of the NRC Enforcement Policy. These items were entered into the licensee's corrective action program as CRs 1999-1488,-
1489, -1493, and -1510.
The inspectors identified one violation of Criterion XI of Appendix B to 10 CFR Part 50 which involved the failure to perform testing of the time retention feature of the SSW vacuum release solenoid valves. Subsequent testing by the licensee determined that there had not been any degradation of the retention relay setting since installation. This
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-11-Severity Level IV violation is being treated as a noncited violation, consistent with Appendix 0 of the NRC Enforcement Policy. This item was entered into the licensee's corrective action program as CR 1999-1510.
The inspectors identified one violation of Criterion V of Appendix B to 10 CFR Part 50 for the failure to perform an adequate technical evaluation for isolating the Division l SSW supply motor-operated valve to the Division lli jacket water cooler. Specifically the evaluation did not include an assessment of the impact on Divisk.1 lll EDG operability, the motor-operated valve operating characteristics, and operator actions to reopen Valve SSW MOV-077A. This Severity Level IV violation is being treated as a noncited violation, consistent with Appendix C of the NRC Enforcement Policy. This item was entered into the licensee's corrective action program as CR 1999-1475.
l E8 Miscellaneous Engineering lasues (92902)
i E8.1 Violation Closure The below violations are closed consistent with the guidance previously provided in Section 08.1 of this report.
Violation Number ' Description CA Program Reference 50-458/9816-04 Failure to consider increase CR 99-1398 dose consequences to be an unreviewed safety question
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50-458/9805-01 Failure to control changes to CR 98-0230 environmental design criteria 50-458/9719-05 Inadequate corrective actions to CR 97-2010,97-2112 address air instrument sensing lines
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E8.2 (Closed) Licensee Event Report (LER) 50-458/99-02: Discovery of unanalyzed air filters on containment unit coolers. This LER documented the licensee's discovery that unanalyzed filters were in place on the safety-related containment unit coolers during operation. During an engineering review of NRC Information Notice 99-01,
" Deterioration of High-Efficiency Particulate Air Filters in Pressurized Water Reactors,"
licens9e personrel discovered that dust filters were installe,d on the safety-related containment unic coolers in violation of the requirements of USAR Section 9.4.6.2. The installation of filters is allowed by the USAR during construction and periods of maintenance to prevent fouling of the coolers. However, the filters are required to be removed during plant operation.
The licensee's immediate corrective actions involved declaring the containment unit coolers inoperable and removing the filters. The licensee completed a root cause
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12-analysis to determine the cause for and safety significance of leaving the filters in place during operation. The licensee determined the filters remained in place during operations because station personnel failed to recognize that unqualified filters were in place on safety-related containment unit coolers. The licensee's analysis determined that the degradation due to leaving the filters L1 place was not safety significant in that the worst case condition, a loss of heat removal capability of both containment unit coolers, would not result in containment pressure exceeding design limits.
The failure to translate design requirem,nts into procedures to ensure filters were removed from the safety-related containment unit coolers during operation is a sixth example of the violation of 10 CFR Part 50, Appendix B, Criterion Ill. The circumstances addressed in the LER are addressed in the licensee's corrective action program as CR 1999-0137. The licensee's immediate corrective actions are acceptable and, although containment unit coolers were degraded with the filters installed, they were determined to be operable.
E8.3 (Closed) Inspector Follow-up Item (IFI) 50-458/0714-02: Long-term plans to address RHR heat exchanger biofouling. This item was initially opened in NRC Inspection Report 50-458/97-14 to determine the licensee's long-term corrective actions to prevent biofouling in the RHR heat exchangers. The issue was reinspected during Refueling Outage 8 and documented in NRC Inspection Report 50-458/99-03. As a result of the followup inspection, noncited Violation 50-458/9903-07 documented an inadequate engineering evaluation intended to determine the design fouling rate for the RHR heat exchangers. The issue was entered into the licensee's corrective action system as CR 1999-0560.
IV. Plant Support R3 Radiological Protection and Chemistry Procedures and Documentation R3.1 Inadeauate Chemistry Procedures a.
Inspection Scoce (71750_)
The inspectors compared chemistry requirements for the suppression pool and RHR system specified in the USAR to the requirements in chemistry department implementing procedures.
b.
Observation and Findinas USAR Section 3.11.1.2.3, " Chemical Environment," specified that the water chemistry in the suppression pool and RHR system during layup will meet specified chemistry controls. The suppression pool water maximum limits included, in part, a pH of 5.3 to 8.6 at 25'C and a total suspended solid limit of s 5 ppm. The RHR system limits included, in part, a pH of 5.3 to 7.5 at 25*C. The inspectors determined that Procedure CSP-0006," Chemistry Surveillance and Scheduling System," did not require a pH or total suspended solids sample for the soppression pool or a pH sample for the
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-13-RHR system. As an immediate corrective action, the licensee performed water chemistry samples to verify that the water in the suppression pool and RHR system meet the required USAR specifications.
The failure to include the suppression pool and RHR chemistry sampling requirements
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in Procedure CSP-0006 and perform the required samples to verify that water chemistry j
is maintained within specification is a seventh example of the violation of Criterion lli of Appendix B to 10 CFR Part 50. This example of the violation is in the licensee's l
corrective action program as CR 1999-1500.
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c.
Conclusion
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The inspectors identified an additional example of a 10 CFR Part 50, Appendix B, Criterion Ill, violation for the failure to include the USAR sampling requirements for the
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suppression pool and RHR system in chemistry sampling procedures. The example of the violation met the criteria for a noncited violation and is in the licensee's corrective
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action program as CR 1999-1500.
R8 Miscellaneous Radiological Protection and Chemistry issues R8.1 Violation Closure The below violations are closed consistent with the guidance previously provided in Section 08.1 of this report.
Violation Number Description CA Program Reference 50-458/9820-01 Failure to ensur.e containers were not CR 98-1383 contaminated prior to release 50-458/9803-01 Failure to maintain records of radiation CR 98-0693 protection program reviews 50-458/9803-02 Failure to follow radiation protection CR 98-0224 procedures 50-458/9714-04 Failure to maintain a locked CR 97-1442,97-1492 high radiation area barricaded and posted 50-45W9714-05 Failure to maintain a locked high CR 97-1442,97-1492 radiation area door locked
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-14-P1 Conduct of Emergency Preparedness Activities P1.1 Evaluation of Emeraency Exercise a.
Inspection Scope (71750)
The inspectors observed the implementation of an emergency exercise from the simulator main control room and technical support center on September 21,1999.
b.
Observations and Findinas Scenario Description The emergency exercise commenced at approximately 8 a.m. The event scenario included:
An explosion and fire in a main power transformer which resulted in a turbine trip
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and reactor scram. The explosion damaged the turbine building. The fire eventually contributed to a loss of offsite power.
A weld failure on the main steam positive leakage control system resulted in an
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unmonitored release pathway to the environment via the damaged turbine building.
A'50 gpm leak developed in the drywell. Due to maintenance and the event,
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normal injection sources to the reactor vessel were lost. The inability to makeup to the reactor vessel resulted in a loss of level control and core damage.
The exercise was terminated following the recovery of injection sources to the
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vessel.
Simulator Main Control Room Observations The inspectors determined that the licensee identified several issues during the emergency exercise. The more significant issues involved:
. The shift supervisor incorrectly determined that a Notice of Unusual
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Event (NOUE) existed 19 minutes into the event. The NOUE was based on a fire in the protected area lasting greater than 10 minutes per the station emergency action levels. Prior to declaring the N,tice of Unusual Event, a drill controller prompted the shift supervisor to reexm.nine the event classification. As a result of miscommunications in the simulator main control room, the shift supervisor was unaware of the explosion and extent of damage to the station.
The shift supervisor reexamined the emergency action levels and declared an ALERT based on a known explosien at the facility resulting in damage to major equipmen \\
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l-15-The activation of the emergency response organization (ERO) was net timely.
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The simulator main control room communicator was newly qualified in the position and not fully processed into the position. As a result, the communicator was unable to access the primary Dialogics/pager system. The backup system was then used to activate the ERO. The codes that were entered into the system by the communicator were incorrect. The incorrect codes resulted in a nonresponse by many of the ERO members.
j Communication problems identified during the event included a
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miscommunication between the at-the-controls operator and the control room supervisor resulting in the c;ntrol room supervisor directing actions for an anticipated transient without a scram when a scram had occurred, the transfer of control from the simulator main control room to the technical support center not being announced, and the simulator main control room being unaware that a General Emergency had been declared.
An additional item observed by the inspectors and not assessed during the critique process involved the control room supervisor holding the off-site fire department at the helicopter landing pad by the training center instead of using the extra resources to combat the fire. Additionally, even after the technical support center had assumed control, the control room supen/isor continued to control the priorities for the station, including the initial setting of priorities, ranking the priorities, and attempting to control dispatched teams from the operations support center in response to these priorities.
Technical Support Center Observations The inspectors detsrmined that the licensee identified several issues during the emergency exercise. The more significant issues involved:
Slow activation of the technical support center. The technical support center
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achieved minimum staffing at 9:09 a.m. but did not activate until 9:42. The delay in activation was attributed to difficulty in establishing communications with the simulator main control room and staffing the dose assessment function.
Security was unable to account for 22 personnel following the site evacuation.
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The licensee subsequently determined that 15 personnel did not hear announcements to evacuate,5 personnel participated in the drill and did not use a card reader, and 2 personnel believed they were exempt from participation in the site evacuation. The licensee initiated CRs 1999-1507 and 1999-1508 to document and review the accountability deficiencies.
Communications between facilities and within the technical support center were
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poor. This was identified by the licensee as a repetitive weakness. Specific examples included delays in communicating the status of the fire, radiation protection staff not being aware of the plant configuration, status boards for out-of-service equipment not being complete, not announcing that the emergency operations facility was operational, and slow establishment of the operations link between the technical support center and the simulator main control room.
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-16-Delays in dispatching field teams in response to plant priorities. One notable
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example involved a priority to restore high pressure core spray injection to the vessel. The priority was recognized at 10:21 a.m.; however, at 10:51 a.m. the operations support center was still briefing the field team.
The technical support center reacted to requests from the simulator main control
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room and did not attempt to look ahead to evaluate upcoming needs and resources.
Additional technical support center performance issues observed by the inspectors and not assessed during the critique process included no discussion on the use of SSW as an alternate injection source to the reactor vessel and no dose assessments to project radiological conditions on a failure of containment.
Licensee Critique of Exercise The inspectors observed the postexercise critiques in the simulator main control room and technical support center. The inspectors also observed the controller debrief on September 22,1999. The inspectors determined that a critical assessment of the emergency exercise occurred and several performance issues were identified.
The licensee did not observe any strengths during the emergency exercise. One deficiency involving pager activation was identified. Four weaknesses were identified by the licensee which involved the scenario and drill control, emergency response organization communications, classification of events, and accountabimy.
c.
Conclusions The inspectors determined that the licensee demonstrated adequate performance during the September 21,1999, emergency exercise. The licensee conducted effective postexercise critiques which identified several performance issues. The more significant issues identified by the licensee included an incorrect event declaration, poor emergency response organization communications, slow dispatch of field teams, poor site evacuation of personnel, and slow activation of the technical support center.
Additional issues identified by inspectors included not utilizing the off-site fire department to combat the fire and the technical support center not considering the use of SSW as an alternate injection source.
P8 Miscellaneous Emergency Preparedness issues I
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P8.1 Violation Closure The below violation is closed consistent with the guidance previously provided in Section 08.1 of this report.
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-17-Violation Number - Description CA Program Reference 50-458/9812-02 Failure to maintain sirens operable CR 98 0693 V. Manaaement Meetinas X1 Exit Meeting Summary The exit meeting was conducted on October 5,1999. The licensee did not express a position on any findings in the report. None of the material discussed in the exit meeting was considered proprietary.
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ATTACHMENT PARTIAL LIST OF PERSONS CONTACTED Licensee -
' R. Edington, Vice President-Operations T. Hildebrandt, Manager, Maintenance J. Holmes, Manager Radiation Protection and Chemistry R. King, Director, Nuclear Safety and Regulatory Affairs D. Mims, General Manager, Plant Operations J. McGhee, Manager, Operations
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D. Pace, Director, Engineering M. Bakarich, Manager, Emergency Preparedness INSPECTION PROCEDURES USED IP 37551:
'Onsite Engineering IP 61726:
Surveillance Observations IP 62707:
Maintenance Observations IP 71707:
Plant Operations IP 71750:
Plant Support IP 92901:
Followup-Operations IP 92901:
Followup-Maintenance
' iP 92903:
Followup-Engineering IP 92904:
Followup-Plant Support ITEMS OPENED AND CLOSED Open and Closed 50-458/9912-01 NOV Failure of operating personnel to be aware of plant indications 50-458/9912-02 NCV Failure to translate information into specifications and procedures
50-458/9912-03 NCV Failure to test service water time retention relays 50-458/9912-04-NCV Failure to perform adequate technical evaluations Closed 50-458/99-02 LER Discovery of unanalyzed air filters on containment unit coolers 50-458/9820-01 NCV Failure to ensure containers were not contaminated prior to release
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-2-50-458/9816-04 NOV Failure to consider increase dose consequences to be an unreviewed safety question 50-458/9812-01 NCV Failure to operate plant breakers in accordance with clearance order requirements 50-450/9812-02 NCV Failure to maintain sirens operable
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I 50-458/9805-01 NCV Failure to control changes to environmental design j
criteria J
50-458/9804-02 NCV Failure of containment isolation damper 50-458/9803-01 NCV Failure to maintain records of radiation protection program reviews 50-458/9803-02 NCV Failure to follow radiation protection procedures 50-458/9719-01 NCV Failure to follow procedures addressing electrical separation criteria l
50-458/9719-03 NCV Feilure to maintain postaccident sampling system opercble 50-458/9719-05 NCV Inadequate corrective actions to address air instrument sensing lines 50-458/9717-04 NCV Failure to comply with Technical Specification
Action after airlock surveillance failed 50-458/9714-02 IFl Long-term plans to address RHR heat exchanger biofouling I
50-458/9714-04 NCV Failure to maintain a locked high radiation area barricaded and posted 50-458/9714-05 NCV Failure to maintain a locked high radiation area door locked i
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-3-LIST OF ACRONYMS USED CA corrective actions CR condition report
.EDG emergency diesel generator ERO emergency response organization-IFl-inspection followup item LER-licensee event report LOCA loss of coolant accident LOOP loss of offsite power MAI maintenance action item NCV noncited violation NOUE notice of unusual event RHR residual heat removal SSW standby service water STP-surveillance test procedure USAR Updated Safety Analysis Report
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