IR 05000334/1997006
| ML20211C006 | |
| Person / Time | |
|---|---|
| Site: | Beaver Valley |
| Issue date: | 09/18/1997 |
| From: | NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I) |
| To: | |
| Shared Package | |
| ML20211B991 | List: |
| References | |
| 50-334-97-06, 50-334-97-6, 50-412-97-06, 50-412-97-6, NUDOCS 9709260090 | |
| Download: ML20211C006 (33) | |
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U. S. NUCLEAR REGULATORY COMMISSION
REGION I
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Report Nos, 50 334/97 06, 50 412/97 06 License Nos.
DPR 66, NPF 73 Docket Nos.
50 334, 50-412
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Licensee:
Duquesne Light Company (DLC)
Post Office Box 4 Shippingport, PA 15077
Facility:
Beaver Valley Power Station, Units 1 and 2 Inspection Period:
July 20,1997 through August 30,1997 Inspectors:
D. Kern, Senior Resident inspector F, Lyon,_ Resident Inspector
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. G. Dentel, Resident inspector P Bissett, Senior Operations Engineer, DRS Approved by:
P. Eselgroth, Chief Reactor Projects Branch 7
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EXECUTIVE SUMMARY Beaver Valley Power Station, Units 1 & 2 NRC Inspection Report 50 334/97 06 & 50-412/97 06 This integrated inspection included aspects of licensee operations, engineering, maintenance, and plant support. The report covers a 6 week period of resident inspection; in addition, it includes the results of an announced inspection of the licer sed operator requalification training program by regional inspectors.
Operations Operators responded appropriately to the Unit 1 reactor trip on August 7, and the e
plant responded as designed. Maintenance technicians conducted thorough troubleshooting and located the root cause of the trip, a ground in the feedwater flow controller module. The Event Review Team (ERT) conducted a rigorous and disciplined root cause analysis of the trip and provided reesonable recommendations for corrective actions to be completed prior to plant restart. There were good communications and teamwork between operations and maintenance staffs and the ERT in determining the root cause, and good interaction between the ERT and the
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Nuclear Safety Review Board during review of the event and corrective action recommendations. (Section 01.2)
Operators and maintenance technicians responded promptly and effectively to the e
failure of a refueling ~ water storage tank level transmitter that caused the initiation of a plant shutdown as required by Technical Specification (TS) 3.0.3. During the entry into TS 3.0.3, there were some plant staff discussions on the interpretation of TS 3.0.3 requirements which were resolved in a manner consistent with an existing operations and licensing approved TS interpretation. This occurrence highlighted the need for greater awareness of existing TS interpretations and their applicability, e
Inspectors noted several discrepancies during a routine review of the Bases for Continued Operation (BCOs) filed in the control rcoms. These indicated weak administrative control of BCOs and a lack of rigor in maintaining control room drawings and System Status Print Sheets up-to-date. The discrepancies were brought to the attention of licensee manageme? and operators and subsequently corrected. (Section O3.1)
e The licensed operator requalification training program was implemented acceptably.
Annual licensed operator exams were administered appropriately, however, the inspector identified an area for improvement regarding documenting the results of the exams. The facility also corrected an inspector identified concern on exam security. (Section 05)
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Weaknesses were noted in the administrative controls applied to BCOs and TS o
Interpretations and had previously been noted in Special Operating Orders and
- Standing Night Orders. Considered together, the adrninistrative deficiencies indicated a lack of rigor in maintaining some of the documents provided in the control room as guidance or reference for operators. Additional management attention may be needed in this area. (Section 06)
Maintenance
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o Inspectors noted good management oversight and good coordination between operators, maintenance technicians, and system engineers during the planning and l
recovery of Unit 2 main turbine governor valve #4 (Section M1.1)
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inspectors reviewed the engineering evaluation for an unresolved item identifying e
that main steam bypass valve closure time was slower than the time required by-technical specifications for main steam isolation. The evaluation was techniaally sound and adequately resolved the issue. Engineers displayed a good questioning attitude in identifyi'ig the issue. (Section E1.1)
o Engineers identified that non-seismically qualified fire protection system switches
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and relays resulted in the Unit 1 Emergency Diesel Generators and Unit 1 & 2 supplemental leak collection and release systems being vulnerable to failure under seismic conditions since original plant operation. The discovery of these deficiencies demonstrated a thorough extent of condition review of the Unit 1 EDG fire protection non-seismic actuation relays, as described in NRC inspection Report
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50 334 and 412/97-05. NRC enforcement discretion wa exercised, and no violations were issued, because the proLlems were licensee-identified as part of-corrective action for a previous escalated (nforcement action (EA 97 375) that had a similar root cause, did not substantially change the safety significance or character of the regulatory concern of the initial violation, and would be corrected within a reasonable time. (Section E1.2)
Plant Suoco.c j
e Inspectore reviewed the fire suppression capability for the control room and concluded that it and emergency breathing systems for control room personnel were
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Safety Assessment and Quality Verification e
The Event Review Team (ERT) conducted a rigorous and disciplined root cause analysis of the Unit 1 trip on August 7 and provided reasonable recommendations for corrective actions to be completed prior to plant restart. There was good interaction between the ERT and the Nuclear Safety Review Board in review of the event and corrective action recommendations. (Section 01.2)
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Inspectors noted good management oversight and good coordination between operators, maintenance technicians, and system engineers during the planning and recovery of Unit 2 turbine governor valve 44. The recovery was conducted in accordance with the requirements of Administrative Procedure 8.23, " Infrequently Performed Tests and Evolutions." (Section M1.1)
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TABLE OF CONTENTS E X 8? C U T I V E S U M M A R Y............................................. il T A B L E O F C O NT E NT S..............................................
v 1. Operations
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Conduct of Operations.................................... 1 01.1 General Comments (71707)........................... 1 01.2 Unit 1 Automatic Reactor Trip on August 7................ 1 01.3 Unit 1 TS 3.0.3 Entry on August 5...................... 4
Operational Status of Facilities and Equipment................... 5 02.1 Engineered Safety Feature System Walkdowns (71707)....... 5
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Operations Procedures and Documentation
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03.1 Bases for Continued Operation (BCOs).................... 5
Operator Train'ng and Qualifications.......................... 7 05.1 General Scopo (71001)
.............................. 7 05.2 Ex a m C o n t e nt..................................... 7 05.3 Exam Administration and Evaluation..................... 8 05.4 Continuing Training................................. 9 05.5 Remedial Training
................................. 10 05.6 License Reactivation
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Operations Organization and Administration (71707)
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Quality Assurance in Operations............................ 11 07.1 Of f site Review Committee (71707)..................... 11
Miscellaneous Operations issues (92700)
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08.1 (Closed) Licensee Event Report (LER) 50 412/97 01......... 11 08.2 (Closed) LER 50 412/97 02
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08.3 (Closed) Violation (VIO) 50 334 and 412/96-07-03.................... 12 08.4 (Closed) LER 50 3 3 4 /9 7-0 5 01........................ 12 ll. M a in t e n a nc e.................................................. 13 M1 Conduct of Maintenance
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M1.1 Routine Maintenance Observations (62707)............... 13 M1.2 Routine Surveillance Observations (61726)
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M8 Miscellaneous Maintenance issues (92700).................... 14 M8.1 (Closed) Licensee Event Report (LER) 50-412/96 010........ 14 lll. 8 g in e e ring.................................................. 14 El Conduct of Engineering
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t!1.1 (Closed) Unresolved item (URI) 50 334/97-02 10.......,,,. 14 E1.2 Non-Seismically Qualified Fire Protection System Adversely Affects Safety Related Equipment..................,,.. 15 E8 Miscellaneous Engineering issues........................... 18 E8.1 (Closed) Licensee Event Report (LER) 50 334/97-019........ 18 E8.2 (Updated) LER 5 0 3 3 4/9 7 018........................ 18 v
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4 E8.3 (Updated) LER 50 334/97 021
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E8.5 (Closed) Unresolved item (URI) 50 334/96 06 01........... 18
E8.6 (Closed) LERs 50 334/96 009 and 96 009 01
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E8.7 (Closed) LER 5 0 3 3 4/9 6 010......................... 20-
IV. Pl a n t S u p p o rt................................................. 20 L1 Review of FS AR Commitments............................. 20
F1 Control of Fire Protection Activitles.......................... 20 F1.1 Control Room Fire Suppression........................ 20
y V. M anagem ent Me e ting s........................................... 22
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X1 Exit Meeting Summary................................... 22 i
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l X3 Management Meeting Summary................................. 22
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PARTIAL LIST OF PERSONS CONTACTED............................... 23
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l lNSPECTION PROCEDURES USED..................................... 24
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ITEMS OPENED, CLOSED AND DISCUSSED.............................. 25 i
LIST O F AC RO NYM S U SED......................................... 27
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Etnort. Details Summarv of Plant Status Unit 1 began this inspection period in Mode 6 (cold shutdown) in a forced outage. Major work included installation of a median selector switch to resolve main feedwater flow transmitter seismic qualification concerns, modifications to piping supports on the normal and excess letdown lines, and modifications to three containment isolation check valves.
Following completion of forced outage work, Unit 1 returned to power operation on July 31. On August 5, operators initiated a shutdown required by Technical Specification 3.0.3 due to the failure of one refueling water storage tank level transmitter while another transmitter was out of service. Load was held at 99% power and restored following the replacement of one of the transmitters (see Section 01.3). On August 7, Unit 1 tripped from full puwer due to high water levelin the "A" steam generator (see Section 01.2).
The event was caused by a gmund in a feedwater flow controller. Operators stabilized the unit In Mode 3 (hot standby). Following root cause analysis and corrective action for the trip, Unit 1 returned to power operation on August 10.
Unit 2 began this inspection in Mode 5 in a forced outage. Major work included replacement of the "A" and "C" reactor coolant pump seals. Following completion of forced outage work, Unit 2 returned to power operation on July 23.
l. Operations
Conduct of Operations 01.1 General Comments (7170W Using Inspection Procedure 71707, the inspectors conducted frequent reviews of ongoing plant operations. In general, the conduct of operations was professional and safety-conscious; specific events and noteworthy observations are detailed in the sections below.
01.2 Unit 1 Automatic Reactor Trio on Auaust 7 a.
Inspection Scoce (71707. 93702,92901)
On August 7, Unit 1 had an automatic reactor trip from full power following a turbine trip caused by high water levelin the "A" steam generator inspectors responded to the plant and observed the post trip critique and subsequent licensee Event Review Team (ERT) activities.
Topical headings such a 01, M8, etc., are used in accordance with the NRC standardized reactor inspection report outline. Individual reports are not expected to address all outline topic V
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b.
Observations and Findinos Background During the midnight shift on August 7, operators noted that the "A" steam generator level was being automatically controlled about 4% higher than the programmed level setpoint. Later in the day, the level slowly varied at slightly higher values causing occasional intermittent level deviation alarms. The level deviations began to increase in frequency and duration.
Instrumentation & Controls (l&C) technicians investigated and identified an apparent discrepancy in the readings on the current to voltage converter (LC 478 B/R 1/V input module) in comparison to other modules in the flow control circuit. They initially concluded that the cause could be a loose lead or degraded internal resistors. A work order was prepared to tighten the resistor block leads, retake electrical readings, and, if necessary, replace the resistor block. Technicians and operators were properly briefed on the work, in order to prevent any adverse effect on plant operations, fe,edwater control for flow control valve FCV FW 478 was placed in manual, which electrically isolated the area of work, i
No loose leads were found by the l&C technicians, and they lifted leads to replace the resistor block Coincident with lifting the leads, FCV FW 478 failed to the full open position. Operators were unable to reduce feedwater flow with the manual benchboard controls. A turbine trip and feedwater isolation occurred at the " steam generator high high water level" setpoint, which caused a reactor trip.
Plant Response The plant responded as designed to the trip. A tast bus transfer on the 4kV system from the unit transformers to the system transformers occurred. As a result of the voltage reduction on the "A" and "D" 4kV buses, both emergency diesel generators (EDGs) automatically started on degraded bur voltage. The voltage reduction was not low enough to require load shedding and EDG sequencing. Bus voltages on the normal 4kV system recovered as designed without the shedding of major loads.
Operators stabilized the unit in Mode 3 (hot standby). The licensee formed an Event Review Team (ERT) to validate plant response, determine roct causes for the trip, and recommend required corrective actions for restart. Potentially suspect equipment was " quarantined" until as found information could be gathered. The trip was documented in Condition Report 971364.
Root Cause t
The ERT determined that the root cause of the trip was a ground in the FC 478 (Hagen Model 124 Rev. R) feedwater flow controller in the "A" steam generator feedwater control system. The ground was from an oversized solder connection which contacted the module bracket. This was confirmed by physical evidence and follow up testing. The controller was new and had only been in service since the plant startup on July 31. The ground had apparently progressed from a weak
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electrical connection to a hard connection during the course of the day on August 7. The ground was not detectable during receipt inspection or routino pre-and post installation testing. The work being done by I&C technirlans was electrically isolated from the controller and was coincident to the controller failure.
The controller module was replaced with a new one prior to unit restart.
Licensee Investigation Inspectors observed the post trip critique, portions of the ERT investigation, and the ERT presentation to the Nuclear Safety Review Board (NSRB). The ERT was conducted in accordance with Nuclear Power Division Administrative Procedure (NPDAP) 5.0, Rev.0, " Processing of Condition Reports," and NPDAP 5.8, Rev.0,
" Root Cause Analysis." The ERT conducted a rigorous and disciplined root cause analysis of the trip and provided reasonable recommendations for corrective actions to be completed prior to plant restart, inspectors noted good communications and teamwork between operations and maintenance staffs and the ERT in determining the root cause, and good interaction between the ERT and the NSRB in review of
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the event and corrective action recommendations. Inspectors noted that the ERT maintained a clear focus on their responsioliities. There was little of the confusion
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over ERT roles and interface with the NSRB that was seen following some previous events (for example, see NRC Inspection Report 50 334 and 412/97 02, Section 01.21. Inspectors assessed that the improvement was due to a strong focus by the ERT manager and leader and the relatively uncomplicated nature of the event, since no program changes had been implemented. inspectors reviewed the ERT report (NPDMOS:1302) and ISEG analysis 'NDISEG:1134) and assessed them to be thorough dispositions of issues from the event. The " anomaly matrix" in the ERT report was a useful method of tracking issues requiring additional investigation, follow-up, or corrective action, c.
Conclusions l
Operators responded appropriately to the event, and the plant responded as designed. Maintenance technicians conducted thorough troubleshooting and located the root cause of the trip, a ground in the feedwater flow controller module.
The ERT conducted a rigorous and disciplined root cause analysis of the trip and provided reasonable recommendations for corrective actions to be completed prior to plant restart. Inspectors noted good communications and teamwork between operations and maintenance staffs and the ERT in determining the root cause, and good interaction between the ERT ant) the NSRB during review of the event and corrective action recommendations.
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j 01.3 Unit 1 TS 3.0.3 Entrv on Auaust 5
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Insoection Scoos (71707,93702. 92901)
On August 5, Unit 1 entered TS 3.0.3 and began a plant shutdown due to the i
failure of one refueling water storage tank (RWST) level transmitter while a second transmitter was out of service for scheduled replacement, inspectors observed the
operators' response to the event and subsequent licensee recovery actions.
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Observations and Findinas I
Sequence of Events
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Maintenanch technicians were replacing RWST level transmitter LT OS 1000 in accordance with MWR 63665 (TER 10485, replacement of obsolete transmitters).
j Operators had confirmed that the work was permissible from a probabalistic risk
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perspective and entered the appropriate TS for having one of the four RWST level
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channels out of service (TS 3.3.2.1.b, Table 3.3 3, Actions 16 and 18). At 1:30
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p.m., about three hours into the work, control room operators noted during a review of computer alarms that LT OS 1000 had failed high at 1:14 p.m. Operators
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applied TS 3.0.3 and initiated a plant shutdown at 2:12 p.m. The load reduction
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was halted at 99% power, since there was a high degree of confidence that the
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LT OS 100C was replaced, tested satisfactorily, and returned to service at 3:41 p.m. TS 3,0.3 was exited at that time. Unit 1 remained in TS 3.3.2.1 action 16 ~
since LT OS 100B was still out of service. Operators returned Unit 1 to full power;
LT-OS 1008 was subsequently replaced and returned to service. The NRC was notified of the initiation of a plant shutdown required by TS in accordance with 10CFR50.72.
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TS 3.0.3 Interpretation t
During the entry into TS 3.0.3, there were some plant staff discussions on the interpretation of TS 3.0.3 requirements which were resolved in a manner consistent
1 with an existing Operations and Licensing approved interpretation. This occurrence
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highlighted the need for greater awareness of existing TS interpretations and their
applicability. The issue was documented on Condition Report 971392. Inspectors discussed the issue with management and operators. The Director, Safety &
Licensing, stated that the licensee intended to review all of the existing TS i
Interpretations by the end of the year to verify their applicability.
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c.
Conclusions Operators and maintenance technicians responded promptly and effectively to the failure of an RWST level transmitter that caused the initiation of a plant shutdown as required by TS 3.0.3. Plant staff initial uncertainties about the appropriate
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interpretation of TS 3.0.3 highlighted the need for greater awareness of existing TS interpretations and their applicability.
Operational Status of Facilities and Equipment 02.1 Enaineered Safetv Feature Svstem Walkdowns (71707)
The inspectors walked down accessible portions of selected systems to assess equipment operability, material condition, and housekeeping. Minor discrepancies were brought to DLC staff's attention and corrected. No substantive concerns were identified. The following systems were walked down:
Unit 2 Charging Pumps
Unit 2 Service Water System
Unit 2 Auxiliary Feedwater System
Unit 1 River Water System
Operations Procedures and Documentation 03.1 Bases for Continued Ooeration (BCOs)
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Insoection Scone (71707)
Inspectors reviewed the BCO files and logs maintained in the Unit I and 2 control rooms. The review included Nuclear Power Division Aaministrative Procedure (NPDAP) 5.7, Rev.0, " Basis for Continued Operation Determinat.... " operating procedure 1/20M 48.3.D, Rev.17, " Administrative Control of Valves and Equipment," and a sample of the contingency and compensatory measures in place taken for BCOs.
b.
Observations and Findinas.
Inspectors reviewed the BCO logs and files for both units and noted the following discrepancies:
(1) The log comments for BCO 196 007, Rev.1, stated that a type C test would be required if leakage exceeded 3 gph. This was the requirement of the original BCO; however, Rev.1 had changed the requirement to 5 gph.
(2) Several of the control room valve operating number diagram (VOND) drawings did not match the System Status Print Sheet deviation numbers. The print sheet
- deviation number reflects the clearance (tagout) number on a valve or component which is out of its normal system alignment. For example, the print sheet for OM Figures 341 and 2 (Station Air and Instrument Air) showed deviations F, W, J 1,01, and R 1, but these deviations were not reflected on the drawing. Valve 1SA 14 was labeled as deviation R, but deviation R was closed on the print sheet (the correct label was R 1).
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6 (3) The Unit 2 log status summary indicated that there were 5 active BCOs as of July 31, but there were 6 BCOs listed as open in the log. BCO 194 005 (which applied to both units) was not in the file. It had been closed prior to the last Unit 2 startup, but the log had not been updated. The log was later changed to reflect that the BCO was closed by Safety & Licensing Department letter ND3NSM:7804 dated July 29,1997, but the letter only closed the BCO for Unit 1. The closeout letter for Unit 2 was subsequently generated on August 25 (ND3NSM:7834),
though the actual work had been completed in July before Unit 2 restart.
(4) BCO 2 97 000 was closed but was stillin the file.
(5) Two document copies, each labeled BCO 2 97 004, were in the Unit 2 file.
Each referenced a different Condition Report, one from January (CR 970077) and one from July (CR 971140). Neither document copy had all of the approval signatures required by NPDAP 5.7. Upon further review, the inspectors found that the July document had never completed the BCO approval process, because it had been rejected by the OSC. The January BCO 2 07 004 had been approved by the OSC, but the control room copy did not have the OSC approval on it, inspectors assessed that these discrepancies indicated weak administrative control of BCOs and a lack of rigor in maintaining the control room VOND drawings and System Status Print Sheets up to-date. The discrepancies were discussed with operations management. Operators subsequently audited and updated the control room VOND drawings and System Status Print Sheets and updated the BCO logs and files.
Inspectors made the following observations:
(1) NPDAP 5.7 did not clearly specify the organization responsible or the process to be used for closing a BCO.
(2) NPDAP 5.7 requires that periodic reviews of open BCOs be performed by System & Performance Engineering (SPED) cnd Nuclear Licensing Departments.
These reviews were not documented. NPDAP 8.13, Rev.0, " Nuclear Safety Review Board (NSRB)," required the NSRB to review BCOs. The NSRB reviews of BCOs were documented in the NSRB meeting minutes, but were not noted on the BCO approval form. The Plant Manager was not required by NPDAP 5.7 to approve BCOs, (3) Inspectors noted that several valves were caation tagged as compensatory measures for BCOs. However, in some cases the clearances did not refer to the BCO, for example, Clearance 661902 for 1SA 14 and Clearance 661900 for 1BR 16 and 17. The potential existed for a clearance to be removed without recognizing that it was fulfilling a BCO compensatory actio.
Inspectors discussed the observations with operations, SPED, and licensing staff.
The Director, Safety & Licensing, stated that NPDAP 5.7 was being evaluated and that a revision was expected by mid-October to strengthen the program. The revision was being tracked under Condition Reports 970941 and 971222.
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Conclusions inspectors noted several discrepancies during a routine review of BCOs and otSer files in the control rooms. These indicated weak administrative control of BCOc and a lack of rigor in maintaining control room VOND drawings and System Status Print Sheets up to-date. The discrepancies were brought to the attention of licensee management and operators and subsequently corrected.
Operator Training and Qualifications 05.1 General Scoce (71001)
A scheduled inspection of the Beaver Valley Power Station (BVPS) Unit 1 & 2 licensed operator requalification program was conducted from July 28 -
August 1,1997, using NRC Inspection Procedure 71001. The scope of the inspection included the observation of the annual operating exams administered to one crew of licensad operators, the review of prev!ously completed annual exams for both units, remedial actions taken for exam failures, and reactivation of inactive licensec.
05.2 Exam Content a.
insoection Scoce The inspector reviewed annual written exams for the current and past year and also weekly training quizzes. Operating exams, which included simulator scenarios and job performance measures (JPMs), were also reviewed for both units, b,
Qbservations and Findinas The inspector reviewed several written exams, simulator scenarios and job performance measures that were part of the annual licensed operator requalification exams administered to senior reactor operators and reactor operators. The inspector found the written exams, Parts A and B, to be adequately constructed with an appropriate number of questions at the comprehension level. The simulator scenarios were diverse and included a wide spectrum of the emergency operating procedures. JPMs were also of good quality, c.
Conclusions The facility had developed annual licensed operator requalification exams that indicated whether or not licensed operators were maintaining an acceptable knowledge level of plant operatio. _ _ _ _ _ _ _ _ _ _ _ _ _ _ _. _ _ _ _ _ _ _ _ - _ _ _ _ _ _ _ _ _ _ - _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ - _ _ _ _ _ _ _ _ _ _ _
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05.3 Exam Administration and Evaluation a.
Insoection Segp_g The inspector observed one crew complete two sections of the written examination, perform two simulator scenarios, and perform five JPMs. The inspector also reviewed the facility evaluation of the crew and individual performance.
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Observations and Findinag The crew and individuals, observed by the inspector, passed their operating examinations; however, one individual failed the written examination.
Crew and individual operator performance was good during the conduct of the two simulator scenarios. Also, performance of JPMs was acceptable in allinstances for those observed by the inspector, which included both simulator and inplant JPMs.
The evaluations by training and operations department evaluators were effective for those portions of the exam observed by the inspector. A review of previously completed exam packages, however, indicated that, in a few instances, documentation was not as detailed or complete as it should have been. This concern applied to both the crew performance documentation for the simulator scenario portion of an exam and to individual performance during the conduct of JPMs. BVPS management was made aware of the inspector's concern and agreed to make the necessary improvements to address and correct this concern.
The inspector also noted during the written exam briefing that individuals were permitted, one at a time, to take unescorted trips to the rest room. Based on the potential for compromise of the exam, the inspector stated that individuals should not be allowed unescorted passage since the rest room facilities were not located within the confines of the proctored exam room or examination area. The facility agreed and ceased the practice. The facility noted that this practice had occurred very infrequently in the past due to the relatively short exam period (< 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br />) and that exam compromise had been unlikely due to specific instructions prohibiting use of non exam materials or assistance. Further, BVPS management initiated program changes to prevent any future unescorted or unproctored rest room visits, c.
Conclusions The annual licensed operator requalification exams were administered and evaluated acceptably; however, program enhancements were warranted in evaluation documentation, and an exam security concern was corrected.
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05.4 Continuina Trainina a.
InsoectiorLSspan
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The inspector reviewed portions of the BVPS licensed operator requalification training program to ensure that a continuous two year training program was in place and had been implemented as required by 10 CFR 55.50.
b.
Observations and Findinas The inspector observed the conduct of classroom training given to licensed operators as part of their annual requalification training and found this training acceptable. Lesson plans were also reviewed and found to be well structured along with detailed enabling and terminal objectives. The inspector specifically attended the conduct of two classroom training sessions, one of which included a review of plant and industry events, and the other which dealt with upcoming plant
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modifications. Classroom interaction was very good, with the instructors handing out detailed lesson plans and using visual aids, as necessary, to further describe the subject matter.
The inspector also reviewed individual study guides for licensed operators for both units. Licensed operators had recently experienced some difficulty in identifying applicable technical specification (TS) requirements under actual operating plant -
conditions. As a result of thls ptoblem, the training department utilized the individual study guide process as one of the interim corrective measures until formalized classroom and simulator training could be accomplished. These study guides reviewed several BVPS plant condition reports in which TSs were missed or misinterpreted. Also included within this study guide were several scenario questions with various plant conditions in which the individuals had to identify the applicable TS along with other TS-related questions. The licensed operators'
answers to these scenario questions were then to be forwarded to the training department for reslew and subsequent onshift discussion.
The inspector also reviewed several BVPS licensee event reports (LERs) in whicti the facility committed to additional training as part of the corrective action for a given problem that had occurred at either of the two units. The inspector verified that the training commitments had been completed as designated in the various LERs reviewed by the inspector, c.
Concluill0DA The BVPS training facility had implemented a continuing licensed operator training program that met administrative and regulatory requirements. Classroom training was found to be very good in the development and distribution of lesson plans, u:.e of visual aids, and classroom interaction, r
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05.5 Remedial Trainina a.
insoection Scoce The inspector assessed the adequacy and effectiveness of remedial training _
conducted during the examination cycle, including training provided to licensed operators to correct deficiencies that resulted in a failure of their annual operating exam.
b.
Observations and Findinas The inspector reviewed remedial actions taken for those licensed individuals who had f ailed their annual licensed operating exam. In this instance, the inspector reviewed the failure of the written exam for three different individuals during three different exam weeks. The inspector noted that appropriate notifications were made, which included informing operations that the individuals would be precluded from performing watchstanding duties until they successfully passed a retake exam for those sections which they had failed. Documentation of remediation included a review of areas of weakness with the individuals and a retake of a completely different exam, in all three instances, the individuals passed their retake written.
examination.
c.
Conclusigm The inspector concluded that the BVPS training department had taken appropriate action in regard to those individuals who had failed any portion of their annual licensed operator exam. For those failures reviewed by the inspector, appropriate remedial action had been taken, and documentation was acceptable.
05.6 License Reactivation a.
Inspection Scope The inspector reviewed the program requirements for reactivation of licenses from inactive to active status, b.
Observations and Findinas The inspector reviewed the facility's program for restoration of active operator license status following inactivation and found the program to be acceptably documented and administered. The records of two licensed operators, whose licenses had been recently reactivated, were reviewed. The inspector noted that the records were complete and reactivation requirements had been met in accordance with administrative and 10 CFFI 55.53(f) requirements.
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c.
Conclusions The inspector determined that the facility had adequately implemented the program requirements for reactivation of licenses for operators at BVPS Unit 1 and 2.
Operations Organization and Administration (71707)
inspectors noted weaknesses in the administrative controls applied to BCOs and other control room files, as noted in Section 03.1, and TS Interpretations, as noted in Section 01.3. In NRC Inspection Report 50 334 and 412/97 04, Section 03.1, deficiencies were noted in the control of Special Operating Orders and Standing Night Orders, which resulted in a Non Cited Violation. Considered together, however, the administrative deficiencies indicated a lack of rigor in maintaining some of the documents provided in the control room as guidance or reference for operators. Periodic reviews appeared to be ineffective in identifying and correcting administrative deficiencies and ensuring quality. Additional management attention may be needed in this area.
Quality Assurance in Operations 07.1 Offsite Review Committee (71707)
Inspectors observed portions of the Offsite Review Committee (ORC) meeting on -
August 6 and portions of the Safety Evaluation Subcommittee and Maintenance and Engineering Subcommittee meetings on August 4 and 5. Inspectors verified the ORC met the quorum and membership requirements of TS 6.5.2. Reviews of station activities were thorough and self critical with a focus on nuclear safety, with good participation by all members, inspectore assessed that the committee was effective in providing the independent review of activities required by TSs.
Miscellaneous Operations issues (92700)
08.1 (Closed) Licensee Event Report (LER) 50 412/97-01: Reactor Trip Due to Main Transformer Ground Protection Relay.
This event was discussed in NRC Inspection Report 50 334 and 412/9610. No new issues were revealed by the LER. The inspectors verified that the corrective actions described in the LER were completed and that the reporting criteria required by 10CFR50.73 were properly addressed.
08.2 [ Closed) LER 50-412/97-02: Technical Specification Required Shutdown Due to Missing or Degraded Recirculation Spray System Pump Flood Seats.
This event was documented in NRC inspection Report 50 334 and 412/9610. No new issues were revealed by the LER. The inspectors verified that the corrective actions described in the LER were completed and that the reporting criteria required by 10CFR50.73 were properly addresse.
08.3 (Closed) Violation (VIO) 50-334 and 412/06 07 03: Failure to Perform Audit of Onsite Saf6ty Cornmittee (OSC) Activities.
The licensee failure to conduct quality assurance audits of the OSC was a violation and was cited / discussed in NRC Inspection Reports 50 334 and 412/9010 and 50 334 and 412/96-05. The licensee response to the violation was received by letter dated December 9,1996. The inspectors examined the root cause evaluation and corrective actions to prevent recurrence of the violation.
The licensee investigation concluded that a misinterpretation of audit requirements was the root cause, in 1992. Quality Services Unit (QSU) management decided to implement performance based auditing techniques. At this time, licensee management deleted the OSC audit. The QSU review of the OSC responsibilities was considered to be already covered in other audits (such as Operations, Maintenance, and various other audits). The justification fer this decision was not documented. Corrective actions to address the root r ause and NRC concerns were completed as listed:
A self assessment of the QSU's overview of the OSC and Section 6 of the Technical Specifications (TS) was conducted.
- Quality Service Procedure (OSP) 18.1 " Audit Schedules" was revised to include biennial audits of Section 6 of the TSs including sPe oversight groups (OSC, NSRB, ISEG, and the ORC).
The inspectors independently verified that the corrective actions were complet6J and reviewed the completed audit of the site oversight groups. The corrective actions adequately addressed the root cause and the violation. The violation is closed.
08.4 LClosed) LER 50-334/97 05-01: Inadvertent Operation of 345kV Bus Backup Timer Relay Results in Dual Unit Reactor Trips.
The issue was reviewed and documented in NRC Inspection Report 50 334 and 412/97 02. The LER update reflected the 10CFR21 notification made subsequent to the event regarding the auxiliary feedwater check valve failure. The check valve failure and 10CFR21 determination were documented in the NRC report, Section E.
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il. Maintanente M1 Conduct of Mainter.snce i
M1.1 Routine Maintenance Observations (62707)
l The inspectors observed selected maintenance activities on important systems and components. Some of the maintenance work request (MWR) activities observed and reviewed are listed below.
MWR 065703 " Unit 2 Turbine Governor Valve #4 Repositioning"
MWR 065704 " Install Temporary Modification 2 9715 on 2TMS GV4"
The activities observed and reviewed were performed safely and in accordance with proper procedures. Inspectors noted that an appropriate level of supervisory attention was given to the work depending on its priority and difficulty. Particulaily good work was noted during the recovery of Unit 2 main turbine governor valve #4 lGV4) (MWRs 065703 and 065704). During routine surveillance testing, operators noted that the valve position did not indicate as expected during the test.
Investigation revealed that the limit switch linkage rod had become unthreaded from j
the valve stem coupling. Since the rod also serves as the anti rotation device, the valve stem had rotated about 60 degrees. A temporary collar was Installed to prevent further rotation and restore position Indication.--The work was properly
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controlled. Inspectors noted good management oversight and good coordination between operators, maintenance technicians, and system engineers during the planning and recovery af GV4. The recovery was conducted in accordance with the requirements of Administrative Procedure 8.23, " Infrequently Performed Tests and Evolutions."
M1.2 Routine Surveillance Observations (6) Z201 The inspectors observed selected surveillance tests. Operational surveillance tests
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(OSTs) reviewcd and observed by the inspectors are listed below, 20ST 1.11C "E Jeguards Protection System Train A ClB/ Spray Actuation e
Test," Rev. 6
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e 20ST 36.1
" Emergency Diesel Generator [2EGS'EG211 Monthly Test,"
Rev.8 e
10ST-7.5
" Centrifugal Charging Pump Test [1CH P 18)," Rev.11 e
10ST 36.2
" Diesel Generator No.2 Monthly Test," Rev.19 -
e 10ST 30.6
" Reactor Plant River Water Pump 1C Test," Rev.13 e
10ST 30.4
"Rea:: tor Plant River Water System Valve Test for A Header,"
Rev.11 l
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e 20ST.1.12C ' Safeguards Protection System Train B CIB/ Spray Actuation Test," Rev. 8 e
20ST 20.1
" Turbine Throttle, Governor, Reheat Stop and Intercept Valve Test," Rev.13 The surveillance testing was performed safely cnd in accordance with proper procedures. Additional observations regarding surveillance testing are discussed in
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the following sections. The inspectors noted that an appropriate level of supervisory attention was glven to the testing, depending on its sensitivity.
M8 Miscellaneous Melntenance issues (92700)
M8.1 (Closed) Licensee Event Report (LER) 50 412/96 010: Migration of Leak Sealant
Materialinto the Reactor Head Vent System.
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The lasue was reviewed and documented in NRC Inspection Report 50 334 and
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412/96 08 and 96 09. A Notice of Vinfation was issued on March 10,1997.
Additional review by inspectors will be documented in the closeout of the violation.
l lit. Ennineerinn E1 Conduct of Engineering
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E1.1 1 Closed) Unresolved item (URll 50 334/97 02 10: Acceptability of MSIV Bypass Valve Closure Time, a.
Insoection Scooe (375511 DLC identified that main steam insolation bypass valve closure time was slower than the technical specification (TS) time required for main steam isolation. The l
Immediate corrective action was technically sound in addressing the issue. This item, described in Inspec'lon Report 50 334 and 412/97 02, remained unresolved pending determination of whether the existing MSIV bypass valve closure time vlotated the TS requirements, b.
Observations and Findingg inspectors reviewed the Updated Final Safety Analysis Review (UFSAR), TSs, and engineering evaluations by the Nuclear Steam Supply System (NSSS) vendor and the licensee, inspectors also discussed MSIV bypass valve design basis assumptions with DLC engineering and licensing staff.
The review of the UFSAR and the TSs showed that there was not a clear indication of whether or not the MSIV bypass valve was assumed to be included in the TS requirement, The TS requirement is for main steam isolation within 8 seconds of an Engineered Safety Feature (ESF) signal. The MSIV bypass valves receive an ESF
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signal to close but reach the closed position between 11 and 18 seconds later. The
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bypass valves are normally closed and are used during startup to equalize the
pressure acress the MSIVs prior to opening. The MSIV bypass valves have an
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l automatic mechanical interlock that allows only one bypass valve to be open at a j
specific time.
l.
DLC engineers and the NSSS vendor determined that having one MSIV bypass valve i
l failed open is encompassed by design basis calculations. Therefore, DLC engineers i
determined that the main steam isolation described in the TS does not apply to the j
MSIV bypass valves. The UFSAR was updated to reflect the findings and to update
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the description of the MSIV bypass valves. Previous administrative controls on the
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valves were also removed, h
The inspectors reviewed the calculations and the determination by DLC engineers.
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The inspectors observed that the licensee appropriately evaluated the issue and
documented their determination. The inspectors assessed that no regulatory
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requirements were violated.10CFR50.59 safety analyses were appropriately
performed for the UFSAR changes. The original identification of the lasue by DLC i
engineers demonstrated a good questioning attitude.
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Conclusion
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DLC engineers displayed a good questioning attitude in identifying a possible non-
compliance with technical specification. The inspectors determined that the i
evaluations addressing the issue were technically sound. The inspectors assessed that no regulatory requirements were violated.
E1.2 Non Seismically Qualified Fire Protection System Adverselv Affects Safetv Related Eauloment
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insoection Scooe (37561_ )
j On July 24,1997, engineers determined that non seismically qualified pressure switches in the Unit 1 emergency diesel generator (EDG) ventilation system could
make the EDCs inoperable during a selsmic event. On July 26, engineers
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determined that non seismically qualified relays in the Unit 1 supplemental leak collection snd release system (SLCRS) water deluge fire suppression systems could j
make both trains of SLCRS inoperable during a seismic event. On August 21, engineers identified that the Unit 2 SLCRS also had non seismically qualified relays
that could make both trains inoperable during a seismic event. The inspectors Interviewed engineers, reviewed design documents, and performed system
walkdowns to assess the evaluation of these issues.
I b.
Observations and Findinas On July 5,1997, engineers determined that non seismically qualified relays installed in the Unit 1 Emergency Diesel Generator (EDG) room carbon dioxide (CO2) fire suppression systems could make both EDGs inoperable during a seismic event as
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documented in NRC Inspection Report No. 50 334 & 412/97 05. During the extent of condition review, the engineers identified that Unit 1 and Unit 2 SLCRS fire suppression systems nad similar vulnerabilities, in addition, the Unit 1 EDG ventilation system also had non seismically qualified switches which could result in loss of power to the EDG room fans following a seismic event.
The engineering group " extent of condition review" following the initial discovery of the EDG inoperability evaluated the following areas:
All Unit 1 fire protection systems were reviewed to ensure that inadvertent e
'oeration of the fire protection system would not impair the safety capability o. structures, systems, or components important to safety.
All Jni: 2 automatically operated l ire protection systems were reviewed to e
en: ure that inadvertent operation of the fire protection system would not l
imi air the rafety capability of :tructures, systems, or components important l
to safety. The review of manually actuated systems is scheduled for l
completion on October 31,1997.
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The other outliers in the Unit 1 Seismic Qualification Upgrade program
l database were reviewed for any additional potential common failure modes, t
A detailed review of the fire protection subsystems at both units (water
deluge, CO2, halon, and fire detection) to verify that there were no other instances where QA Category F devices were designed into QA Category I electrical circuits. This review is scheduled to be complete by November 9, 1997.
EDG toom fire protection pressure switches PS FP CDL1 A & B were purchased as part of the fire protection system which is not procured to the same quality standards as safety related equipment. By design, upon sensing a CO2 discharge within the EDG room, the normally closed pressure switch contact in the EDG ventilation system control circuit opens, stopping the ventilation fan for that EDG room and keeping the CO2 from being removed from the room. Engineers determined that without the required quality assurance level category, the pressure switch contacts must be assumed to fail open during a seismic event. This would result in a loss of EDG room ventilation, if the EDG had been called on to operate during this event, the EDG room temperature would gradually increase above design operating temperatures and the EDG would become unable to perform its safety function. Qualified replacern at switches were installed and the EDGs weie declared operable on July 27. The inspectors noted that recent improven.ents hav6 been made to the station's industry operating experience review program and extent of condition review processes to increase the likelihood that issues such as this will be identified more promptly.
On July 26, engineers identified that the Unit 1 SLCRS water deluge fire suppression system actuation relays could inadvertently operate during a seismic event. Since the Unit 1 SLCRS fire protection system is an automatic initiation
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system with non seismically qualified actuation relays, the postulated seismic event could cause the actuation relays to chatter and actuate. The water deluge would saturate the SLCRS emergency filters. With the filters saturated, the Unit 1 SLCRS system would be inoperable.
I The engineers identified that the Unit 2 GLCRS water deluge fire suppression system could inadvertently operate during a seismic event. The Unit 2 SLCRS fire
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protection system is a manualinitiation system with a non seismic sealin relay for a push button switch. The postulated seismic event would cause the sealin relay to chatter and actuate. The actuation would cause a water delugs of the SI.CRS emergency filters. With the filters saturated, the Unit 2 SLCRS would be inoperable.
Unit 1 UFSAR, Section 9.10 and Unit 2 UFSAR, Section 9.5.1.1, state that the fire protection system is designed on the basis that a rupture or inadvertent operation will not significantly impair the safety capability of structures, systems, or components important to safety or designed to seismic category I requirements.
Upon discovery of the discrepancies in both the Unit 1 and Unit 2 SLCRS, the licensee took prompt compensatory measures to manually isolate the fire headers to the SLCRS fire protection system and to conduct hourly fire tours. The inspectors determined that the operability determination and compensatory measures were both prompt and appropriate. As long term corrective actions, the licensee in evaluating replacing the non seismic relays with seismically qualified relays or qualifying the existing relays.
The inspectors determined that Unit 1 EDGs and the Unit 1 & 2 SLCRS had been vulnerable to failure Lnder seismic conditions since original plant operation. The licensee failed to recognize the EDG and SLCRS condition
.d therefore failed to implement the TS required actions. These were violations of regulatory requirements. The deficiencies were identified by the licensee as part of the corrective actions in response to the EDG fire protection deficiency. The NRC exercised enforcement discretion (EA 97 375) for the EDG fire protection deficiency in NRC Inspection Report 50 334 and 412/97 05. The new deficiencies had the same root cause as the previous deficiency. The violations did not change tne safety significance or the character of the regulatory concern arising out of the initial violation, and the immediate and long term corrective actions are comprehensive and reasonable. These violations of NRC requirements will not be cited in accordance with Section Vll.B.4 of the NRC Enforcement Policy (eel 50 334 and 412/97 06 01).
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Conclusions Engineers identified that non seismically qualified fire protection system switches and relays resulted in the Unit 1 EDGs and Unit 1 & 2 SLCRS being vulnerable to failure under seismic conditions since original plant operation. The discovery of these deficiencies demonstrated a thorough extent of condition review of the Unit 1 EDG fire protection non seismic actuation relays. In recognition of the licensee self.
Identification and comprehensive extent of condition review, the NRC is exercising discretion and not citing this violation in accordance with the NRC Enforcement Policy.
ER Miscellaneous Engineering issues (92700)
E8.1 (Closed) Licensee Event Report (LER) 50 334/97 012: Contaltiment Penetration Check Valves Not in Accordance with the Design Basis.
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The issue was reviewed and documented in NRC Inspection Report 50 314 and 412/97 05, Section E1.4, Corrective actions were completed or were being tracked in the licensee's corrective action system.
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E8.2 (Undated) LER 50 334/97 018: Potential for Spurious Seismically Induced Fire Protection System Activation Affecting Emergency Diesel Generators.
The issue was reviewed and documented in NRC Inspection Report 50 334 and 412/97 05, Section E1.3. The licensee findings from the extent of condition review are the subject of Section E1.2 above. The LER will remain open pending completion of lict,nsee corrective actions.
E8.3 fUodated) LER_50GA/22 011,: Potential for Seismic Event to Result in Both Trains of Supplementasy Leak Collection and Release System to Become Inoperable.
The issue was reviewed and documented in Section E1.2 above. The LER will remain open pending completion of licensee corrective actions.
E8.4 (Closed) LER 50-334/97-009: Main Steam Isolation Bypass Valves Do Not Meet Technical Specification Engineered Safety Feature Response Time Requirements.
The issue was reviewed and documented in Section E1.1 above. Corrective actions were completed.
E8.5 (Cleaed) Unresolved item (URI) 50-334/96-06 01: Containment Penetrations Not in Accordance With the Design Basis.
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The issue arose after a licensee engineering review revealed that some Unit 1 and 2
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liquid filled lines passing through containment were not designed to compensate for
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the effects of liquid thermal expansion during a design basis accident (DBA). This
could result in pressures exceeding the system design pressure and jeopardize the l
f structuralintegrity of the associated containment penetrations during a DBA. The
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issue was documented in NRC Inspection Reports 50 334 and 412/96 06 and 96 07 and was an unresolved item pending completion of licensee evaluation and NRC review. The licenset reported the issue to the NRC in Licensee Event Reports (LERs) 50 334/96 009 and 96 009 01.
Nuclear Engineering staff completed a comprehensive review of 145 Unit 1 and 128 Unit 2 containment penetrations utilized for piping and access to verify and document their adequacy. Penetrations for electrical equipment, which are gas-filled, were designed against the concern of overpressure due to entrapped fluids and were excluded from the review. The licensee reviews were documented in
"BVPS Unit 2 Containment Penetrations Overpressure Protection Analysis / Review Report" (ND1 DEA:0016, dated October 28,1996) and "BVPS Unit 1 Containment Penetrations Overpressure Protection Analysis / Review Report" (ND1 DEA:0021, dated November 27,1996). Containment penetrations were grouped into separate review categories depending on their design. The valve configuration of each penetration was reviewed and verified in the field. The reviews were summarized on individual penetration review sheets, which included such information as design requirements, r,verpressure protection / justification, corrective actions, and validation of orientation and pressure relief path and references, inspectors reviewed the design basis documents and the action plans developed to limit pressures in the penetrations subject to the effects of liquid thermal expansion. The analyses were thorough and adequately justified the conclusion that the Unit 1 and 2 containment penetrations were in compliance with applicable design codes after appropriate compensatory measures were implemented. Short term corrective actions were complete, such as administrative controls to ensure penetrations are drained after use, valve line up controls to maintain vent paths, and relief valve setpoint adjustments, as appropriate. Long term corrective actions (per letter ND3MNE:7669, dated February 7,1997) were tracked in the Commitment Action
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Tracking System (CATS items 970134A K and 970135A L), such as implementing permanent administrative controls or installing relief valves as permanent repairs.
Long term items were scheduled to be complete by the end of each unit's next refueling outage (1R12 and 2R7).
Unit i UFSAR section 5.3.3 and Unit 2 UFSAR section 6.2.4.2 require that lines passing through containment that may contain trapped liquid be protected against the effects of liquid thermal expansion and piping overpressurization during a DBA.
Failure to provide overpressure protection in accordance with the design basis is a violation of 10CFP50, Appendix B, Criterion lil, " Design Coatrol." This non-repetitive, licensee identified and corrected violation is bi.ng treated as a Non-Cited Violation, consistent with Section Vll.B.I of the NRC Enforcement Policy (NCV 50 334 and 412/97 06 02).
E8.6 (Closed) LERs 50-334/96-009 and 96 009 01: Containment Penetrations Not in Accordance With the Design Basis.
The LERs were reviewed as documented in Section E8.5. Corrective actions were completed or were being tracked in the licensee's corrective action system.
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E8.7 (Closed) LER 50 334/96-010: Containment Piping Supports Not in Accordance With the Design Basis.
The issue was identified by the licensee as part of their engineering evaluation to assess the ability of containment penetration lines to withstand the effects of thermal expansion, as documented in Section E8.5. The pipina supports were on lines associated with containment penetrations 26 (component cooling water from reactor coolant pump 1 A thermal barrier),29 (primary drain transfer pump discharge), and 38 (containment sump pump discharge). Unit 1 was in cold shutdown at the time of discovery, and the piping supports were modified to meet UFSAR stress requirements before startup. Corrective actions for the LER were completed. An additional sample of small bore piping was inspected and no other deficiencies were identified. The failure to maintain the piping supports in accordance with the UFSAR design reqmrements and 10CFR50, Appendix B, Criterion lil, " Design Control," constitutes a violation of minor significance and is being treated as a Non Cited Violation, consistent with Section IV of the NRC Enforcement Policy (NCV 50 334/97 06-03).
IV. Plant Support L1 Review of FSAR Commitments (37551)
A recent discovery of a licensee operating their facility in a manner contrary to the Updated Final Safety Analysis Report (UFSAR) description highlighted the need for a special focused review that compared plant practices, procedures and/or parameters to the UFSAR description.
While performing the inspections discussed in this report, the inspectors reviewed the applicable parts of the UFSAR that related to the areas inspected. The inspectors verified that the UFSAR wording was consistent with the observed plant practices, procedures and/or parameters with the exceptions noted in Sections E8.5 and E8.7.
F1 Control of Fire Protection Activities F 1.1 Control Room FireJucoression a.
Insoection Scone t71750)
In response to a recent industry operating event (ENS 32736), inspectors reviewed the fire suppression capability for the control room. The review included applicable sections of the operating license, UFSAR, QA Plan, and administrative and operating procedures for both units. Inspectors also discussed the issue with operators, the fire protection engineer, and radiation technician.
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b.
Observations and Findinos The control room (including both the Unit 1 and Unit 2 sides) at Beaver Valley does not have an automatic fire suppression system. Fire suppression in the control room is accomplished by portable extinguisher and hose.
The most specific requirements for the use of emergency breathing apparatus for the control room are in the UFSARs. Unit 1 UFSAR Section 0.13, Ventilation Systems, states that, "A portable, self contained breathing apparatus (SCBA)is provided for control room personnel. Each self contained unit will provide 6 to 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> of air to the user. Four units will be provided for every three people normally in the control room. Additionally, six hours of bowed ait will be stored on site for each member of the emergency crew." Unit 2 UFSAR section 6.4, Habitability l
Systems, states that, "A control room air manifold system which consists of flexible hose connections to air storage bottles is provided to ensure chlorine free air for up to 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br />...in addition, a sufficient quantity of portable SCBA...are provided for operators who are located in the control room." Other sections of the UFSARs also refer to the SCBAs and bottled air, generally without specifying quantitles.
The emergency breathing systems would be used in accordance with procedures 1/20M 53C.4A.44A.1, " Chlorine / Toxic Gas Release," and 1/20M 53C.4A.44A.2,
" Emergency Breathing Air System Operation." In general, those procedures require entry when control room environmental conditions or outside air sources have deteriorated, based on the Nuclear Shift Supervisor's discretion.
Eight MSA Ultravue Aktine respirators, hoses and regulators are provided for control room operators to use the Control Room Emergency Breathing Air System (CREBAS), a supply of bottled air. The system is designed to provide air for eight people for from 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> (light activity) to 3 hours3.472222e-5 days <br />8.333333e-4 hours <br />4.960317e-6 weeks <br />1.1415e-6 months <br /> (heavy work).
Also, SCBA units are provided for operators. These are located in areas adjacent to or near the control room and are checked during performance of inspection procedure RP 10.22, " Emergency SCBA Weekly Surveillance." The acceptance criteria for the surveillance is 117 BioPak units and 123 MSA Air Mask units with 140 spare air cylinders. From the most recent inspection,17 BloPaks,35 MSA Air Masks, and 47 spare cylinders were available. The minimum number of SCBAs was calculated to provide 5 hours5.787037e-5 days <br />0.00139 hours <br />8.267196e-6 weeks <br />1.9025e-6 months <br /> of air to the control room crew (13) plus four additional members of the emergency squad outside the control room, in accordance with Regulatory Guide (RG) 1.78, " Assumptions for Evaluating the Habitability of a Nuclear Power Plant Control Room During a Postulated Hazardous Chemical Release." The minimum number was also calculated to meet the requirements of 10CFR50 Appendix R, section ll.H. An additional one hour of air would be supplied to the control room by the Control Room Emergency Bottled Air Pressurization System (CREBAPS, not to be confused with CREBAS) to meet the remainder of the RG 1.78 six hour requirement, inspectors reviewed the basis for the minimum SCBA requirements as documented in ISEG letter NDISEG:1097 dated January 22,1997.
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Cgag)Msigns Inspectors concluded that fire suppression capability for the control room and emergency breathing systems for control room personnel were provided in accordance with design requirements.
LEleDDgemerit Meetlogt X1 Exit Meeting Summary An exit meeting to discuss the inspection of the licensed operator requalification program was conducted on August 1,1997, with Mr. J. Cross and members of his staff. At the meating, the inspector reviewed the scope and findings of the inspection, which were acknowledged by facility management present. Facility management stated that concerns identified by the inspector, and not already corrected, would be addressed and corrected.
None of the information review 7d during the inspection was identified as being proprietary information.
The inspectors presented the remainder of the integrated inspection results to Mr. B. Tuite and other roembers of licensee management at the conclusion of the inspection on September 5,1997. The licensee acknowledged the findings presented.
The inspectors asked the licensee whether any materials examined during the inspection should be considered proprietary. No proprietary information was identified.
X3 Management Meeting Surnmary On July 31 to Aupast 1, Mr. W. Axelson, NRC Region I Deputy Regional Administrator, Mr.
P. Eselgroth, CNef, DRP Branch 7, and Mr. D. Brinkman, NRR Senior Project Manager, conducted picnt tours and interviewed site personnel. The NRC management team discussed their observations with plant management at the conclusion of the site visi.
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PARTIAL.tl8T OF PERSON 8 CONTACTED D.kQ J. Cross, President, Generation Group R. LeGrand, Vice President, Nuclear Operations / Plant Manager S. Jain, Vice President, Nuclear Services K. Ostrowski, Manager, Quality Services Unit B. Tulte, General Manager, Nuclear Operations C. Hawley, General Manager, Maintenance Programs Unit R. Vento, Manager, Health Physics D. Orndorf, Manager, Chemistry F. Curi, Manager, Nuclear Construction J. Matsko, Manager, Outage Management Department T. Lutkehaus, Manager, Maintenance Planning & Administration T. McGhee, Coordinator, Onsite Safety Committee
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J.-Macdonald, Manager, System & Performance Engineering
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i K. Beatty, General Manager, Nuclear Support Unit
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J. Arias, Director, Safety & Licensing
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W. Kline, Manager, Nuclear Engineering Department R. Brosl, Manager, Management Services
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O. Arredondo, Manager, Nuclear Procurement NEC
D. Kern, SRI
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G. Dentel, RI F. Lyon, RI
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INSPECTION PROCEDURES USED IP 37651:
Onsite Engineering IP 61726:
Surveillance Observation IP 62707:
Maintenance Observation IP 71001:
Licensed Operator Requalification Program Evaluation IP 71707:
Plant Operations IP 71750:
Plant Support IP 92700:
Follow up Onsite Follow up, Written Reports of Nonroutine Events IP 92901:
Follow up Operations IP 92902:
Follow up Maintenance / Surveillance IP b3702:
Prornpt Onsite Response to Events at Operating Power Reactors
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ITEMS OPENED, CLOSED AND DISCUSSED Onened/ Closed 50 334 and 412/97-06 01 eel Inoperable SLCRS (Section E1.2)
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50 334 and 412/97 06 02 NCV Containment Penetrations Not in Accordance With the Design Basis (Section E8,5)
50-334 and 412/97 06 03 NCV Containment Piping Supports Not in Accordance With the Design Basis (Section E8.7)
QQ1ttd 50-334 and 412/96-07 03 VIO Failure to Perform Audit of OSC Activities (Section 08.3)
50 334/97 02 10 URI Acceptability of MSIV Bypass Valve Closure Time (Section E1.1)
50-334/96 06-01 URI Containment Penetrations Not in Accordance With the Design Basis (Section E8.5)
50-412/97-01 LER Reactor Trip Due to Main Transformer Ground Protection Relay (Section 08.1)
50-412/97 02 LER Technical Specification Required Shutdown Due to Missing or Degraded Recirculation Spray System Pump Flood Seals (Section 08.2)
50-412/96 010 LER Migration of Leak Sealant Materialinto the Reactor Head Vent System (Section M8.1)
50 334/97 019 LER Containment Penetration Check Valves Not in Accordance with the Design Basis (Section E8.1)
50 334/97-009 LER Main Steam Isolation Bypass Valves Do Not Meet Technical Spec:fication Engineered Safety Feature Response Time Requirements (Section E8.4)
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i 50 334/97 005 01 LER Inadvertent Operation of 345kV Bus
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Backup Timer Relay Results in Dual Unit i
Trips (Section 08.4)
l 50 334/96 009 t.ER Containment Penetrations Not in i
Accordance With the Design Basis
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(Section E8.6)
50 334/96 009 01 LER Containment Penetrations Not in Accordance With the Design Basis (Section EB.6)
50 334/96 010 LER Containment Piping Supports Not in Accordance With the Design Basis (Section E8.7)
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Discusse_d 50 334/97 018 LER Potential for Spurious Selsmically induced Fire Protection System Activation
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Affecting Emergency Diesel Generators (Section E8.2)
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50 334/97 021 LER Potential for Seismic Event to Res'Jit in Both Trains of Supplementary Leak Collection and Release System to Become Inoperable (Section E8.3)
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LIST OF ACRONYMS USED BCO Basis for Continued Operation BVPS Beaver Valley Power Station CATS Commitment Action Tracking System
CFR Code of Federal Regulations CO2 Carbon Dioxide
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CR Condition Report CREBAPS Control Room Emergency Bottled Air Pressurization System CREBAS Control Room Emergency Breathing Air System
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DBA Design Basis Accident
DLC Duquesne Light Company EDG Emergency Diesel Generator eel Escalated Enforcement item ERT Event Review Team ESF Engineered Safety Feature l&C Instrument & Control ISEG Independent Safety Evaluation Group JPM Job Performance Measure LER Licensee Event Report MWR Maintenance Work Request NCV Non-Cited Violation NPDAP Nuclear Power Division Administrative Procedure NRC Nuclear Regulatory Ccmmission NSRB Nuclear Safety Review Board NSS Nuclear Shift Supervisor NSSS Nuclear Steam Supply System MSIV Main Steam isolation Valve ORC Offsite Review Committee OSC Onsite Safety Committee OST Operational Survcillance Test-PDR Public Document Room OSP Quality Service Procedure QSU Quality Service Unit RP&C Radiological Protection & Control RWST Refueling Water Storage Tank SCBA Self Contained Breathing Apparatus SLCRS Supplemental Leak Collection and Release System SPED System & Performance Engineering Department
_TER Technical Evaluation Report TS Technical Specification UFSAR Updated Final Safety Analysis Report URI Unresolved item VOND Valve Operating Number Diagram c
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