IR 05000334/1998003
| ML20236X868 | |
| Person / Time | |
|---|---|
| Site: | Beaver Valley |
| Issue date: | 08/05/1998 |
| From: | NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I) |
| To: | |
| Shared Package | |
| ML20236X857 | List: |
| References | |
| 50-334-98-03, 50-334-98-3, 50-412-98-03, 50-412-98-3, NUDOCS 9808100333 | |
| Download: ML20236X868 (55) | |
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U. S. NUCLEAR REGULATORY COMMISSION l
REGION I
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License Nos.
Report Nos.
50-334/98-03,50-412/98-03 Docket Nos.
.50-334,50-412 I
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Licensee:
Duquesne Light Company (DLC)
Post Office Box 4 Shippintport, PA 15077
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- Facility: -
Beaver Valley Power Station, Units 1 and 2 i
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Inspection Period:
April 26,1998 through June 27,1998
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inspectors:
D. Kern, Senior Resident inspector F. Lyon, Resident inspector G. Dentel, Resident inspector -
D. Coe, Senior Reactor Analyst, NRR l
l J. Furia, Senior Radiation Specialist
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L. James, Reactor Engineer l
N. Perry, Project Engineer, DRP i
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Approved by:
M. Evans, Chief I
Reactor Projects Branch 7 i
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i 9008100333 980805
'E PDR ADOCK 05000334
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EXECUTIVE SUMMARY Beaver Valley Power Station, Units 1 & 2 NRC Inspection Report 50-334/98-03 & 50-412/98-03 This integrated inspection included aspects of licensee operations, engineering,
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maintenance, and plant support. The report covers a 9-week period of resident inspection; i
in addition, it includes the results of announced inspections by regional inspectors in the areas of health physics and engineering, and a risk informed engineering and maintenance backlog assessment performed by a senior risk analyst from the office of Nuclear Reactor Regulation.
Operations
The licensee experienced an increase in the number of perscnnel performance problems. The partial stop work order issued by the plant manager was important to focus workers on proper attention to detail. Although some improvement was noted, human performance errors continued after the stop work order was lifted.
The errors resulted in additional out-of-service time for safety related equipment, and failure of operations personnel to be aware of plant conditions including inoperability of safety related equipment. (Section 01.3)
e The licensee review of alarm response procedures generally identified all Technical Specification (TS) related issues and improved operator awareness of TS 3.0.3 entry conditions. The alarm response procedures were adequate for proper operator response. (Section O3.1)
The controls instituted for the TS 3.0.6 amendment, including procedure changes and training, were sufficient and in place prior to implementation. (Section 04.1 and O1.2)
e On April 7,1998, a Unit 2 quench spray (OS) pump experienced a significant water
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hammer event. Several process barriers failed including the corrective actions for similar previous events, system restoration procedures, planning, and scheduling.
The final barrier failed when operations personnel did not fully resolve valid safety concerns prior to performing a surveillance test during which the water hammer occurred. Although the QS system was not damaged, this condition represented a failure of the licensee corrective action program. The event critique and Multi-discipline Analysis Team (MDAT) assessments were excellent. The MDAT recommended comprehensive corrective actions to address this event. (Section 04.2)
Implementation of several TS amendments, and communication of approved changes to the UFSAR for use by the station's staff were poor. (Section 08.1)
e During review of a previous event, the licensee identified three instances during which TS required shutdown margin determinations were not performed. The identification of this issue and subsequent corrective actions were good. Corrective ii i
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actions for a previous violation associated with configuration control for a Unit 1 pressurizer power operated relief valve (PORV) were properly implemented to preclude recurrence of a similar event. (Sections 08.2 and 08.5)
Maintenance Surveillance were generally conducted safely. In some cases marginal procedure o
quality challenged operators and equipment. One example of operator inconsistent use of available indications resulted in a violation of procedure. (Section M1.2)
Posting and control of equipment deficiency tags continued to be poor. (Section e
M1.3)
e Evaluation, scheduling, and management oversight of Unit 2 periodic inservice test (IST) program requirements frorn February through May was poor. (Section M4.1)
e Maintenance and engineering personnel identified that high energy line break actuation system capacitor replacements, performed five years ago, resulted in the system being non-seismically qualified. Identification of this issue demonstrated a
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good questioning attitude and corrective actions were properly implemented in a timely manner. (Section M8.1)
Enaineerina e
in response to an NRC violation, the licensee identified over twenty additional instances where the station TS were not sufficient to ensure the station would operate'within the existing UFSAR accident analysis. These discrepancies affected l
the reactor protection system, engineered safety features, and various safety related i
system requirements. Licensee actions from approximately 1990 to 1C97 were inadequate, in that station design was not properly maintained, conditions adverse i
to quality were not corrected, and TS were not properly maintained. (Section E1.1)
l The licensee's staff exhibited an approp"iate questioning attitude resulting in the e
identification of many questions regarding interpretation of TS requirements and the l
adequacy of p! ant procedures to meet them. Risk insights were cenerally integrated l
into the backlog prioritization process as evidenced by about 80 percent of the identified top risk significant backlog items being less than two years old. However, risk insights w~ not fully utilized for design change requests and pending design change packages. These items constitutect the majority of the risk significant backlog items greater than two years old. (Section E1.2)
Engineers and maintenance personnel took appropriate actions to address the concerns identified in four mode hold condition reports and to prevent recurrence.
Further, the licensee adequately identified and addressed related emergent issues I
which arose during resolution of the condition reports. {Section E2.1)
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The normal practice of venting the high head safety injection pumps prior to surveillance testing without the assurance that adverse conditions will be detected iii
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and corrected was a violation. Previous corrective actions to address this issue were comprehensive.
The licensee conducted a comprehensive review of testing of safety related logic
circuits for Unit 1,in response to NRC Generic Letter 96-01. Identified deficiencies were tested successfully, procedures were revised to include the testing, and the conditions were properly repor' id. (Section E8.2)
Plant Support The licensee established and implemented effective radiological protection programs
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Radiological controls in the containment were effectively established, implemented,
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and maintained; and radiological work involving the Unit 1 PORV was effectively
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monitored and controlled. (Section R1)
The licensee has established an effer.tive initial and continuing training program for radiation protection technicians. (Section R5)
The fire brigade responded effectively to a reported fire within the protected area.
Subsequent investigation confirmed that no fire existed. (Section F1.1)
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TABLE OF CONTENTS Page EX EC UTIVE S U M M ARY............................................. ii TA B LE O F C O NT ENTS.............................................. v l. Operations
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Conduct of 0perations.................................... 1 01.1 General Comments (71707)
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01.2 Unit 2 Pressurizer Power Operated Relief Valve Testing........ 1 01.3 General Comments and Operator Performance Observations..... 2 O2 Operational Statos of Facilities and Equipment
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02.1 Engineered Safety Feature System Walkdowns (71707)........ 4
Operations Procedures and Documentation...................... 4 03.1 Alarm Response Procedure Review
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Operator Knowledge and Performance......................... 5 04.1 TS 3.0.6 implementation
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04.2 Unit 2 Quench Spray Pump (2OSS-P21B) Water Hammer Event
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Miscellaneous Operations issues (71707,92700,92901)
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08.1 Technical Specification Amendment implementation Process.... 9 08.2 (Closed) Licensee Event Reports (LERs) 50-334/97-12-01 and 97-12-02............................................
08.3 (Closed) LER 5 0-3 3 4/9 7-2 3...........................
08.4 (Closed) LERs 50-412/97-03 and 50-412/97-03-01..........
08.5 (Closed) VIO 50-334/EA 96-462.......................
08.6 (Closed) LER 5 0-3 3 4/9 7-15........................... 13 08.7 (Closed) LER 5 0-3 3 4/9 7-16........................... 13 08.8 (Closed) LER 5 0-3 3 4 /9 7-2 2........................... 13 11. M a i n t e n a n c e.................................................. 13 M1 Conduct of Maintenance.................................. 13 M 1.1 Routine Maintenance Observations
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M1.2 Routine Surveillance Observations..,................... 14 M1.3 Material Deficiency Tags
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M4 Maintenance Staff Knowledge and Performance.................
M4.1 Scheduling of Refueling Interval inservice Testing...........
M8 Miscellaneous Maintenance issues (90712,92700,92902).........
M8.1 (Closed) LER 5 0-3 3 4/9 8-12...........................
M8.2 (Closed) VIO 50-334(412)/9 6-10-04.................... 19 M8.3 (Closed) LER 5 0-3 3 4/9 7-17........................... 20 M8.4 (Closed) LER 5 0-3 3 4/9 7-0 8-01........................ 20 l
111. E ngi n e e ri n g.................................................. 20 E1 Conduct of Engineering................................... 20 E1.1 Resolution of Station Conditions Outside of Station Accident Analysis
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E1.2 Prioritization of Engineering and Maintenance Backlogs (Units 1 and 2)
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E2 Engineering Support of Facilities and Equipment
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i E2.1 Review of Mode Hold Condition Reports.................. 26
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E8 Miscellaneous Engineering Issues............................ 27 E8.1 (Closed) Unrescfved item (URI) 50-334 and 50-412/97-08-03.... 27 E8.2 (Closed) Unit 1 LERs Associated With Generic Letter 96-01 Review
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E8.3 (Closed) LER 5 0-3 3 4/9 7-18........................... 30 E8.4 (Closed) LER 5 0-3 3 4/9 7-2 0........................... 30 l
E8.5 (Closed) LER 50-334/97-21,50-334/97-21-01
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E8.6 (Closed) LER 5 0-3 3 4/9 7-0 9-01........................ 31 I V. Pl a n t S u p p o rt................................................. 31 R1 Radiological Protection and Chemistry (RP&C) Controls............ 31
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R5 Staff Training and Qualification in RP&C....................... 34 j
R8 Miscellaneous RP&C issues................................ 34 l
R8.1 Procedure Evaluations
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R8.2 Updated Final Safety Analysis Report.................... 35 F1 Control of Fire Protection Activities.......................... 35 F1.1 Fire Brigade Response to a Reported Fire
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V. M a nagem ent Meeting s........................................... 36 X1 Exit Meeting Sum m ary................................... 36 X2 Management Meeting Summary............................. 36 PARTIAL LIST OF PERSONS CONTACTED............................... 37 INSPECTIO N PROCEDU RES USED.................................... 38 lTEMS OPENED, CLOSED AND DISCUSSED.............................. 39
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LI ST O F AC R O N YM S U S E D.......................................... 42
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Summarv of Plant Status Both Units continued in Mode 5 (cold shutdown) in forced outages to resolve Technical Specification Surveillance Requirement compliance issues.
1. Operations
Conduct of Operations l
01.1 General Comments (71707)
i 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 sectiens below.
01.2 Unit 2 Pressurizer Power Operated Relief Valve Testina a.
Insoection Scope (71707)
The inspectors observed testing conducted on the Unit 2 pressurizer (PZR) power l
operated relief valves (PORVs). The inspectors reviewed the controls and oversight
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utilized in the test and required by Technical Specification (TS) 3.0.6 entry. The l
.following procedures were reviewed:
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2 TOP-98-02, " Administrative Control for Testing PZR PORVs," Rev. 2
l 20ST-6.8,
" Pressurizer PORV Stroke Test," Rev. 4
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Observations ar f AnWnm l
On May 1,1998, the licensee conducted post-maintenance stroke testing on the l
Unit 2 POR\\'s. The testing required use of TS 3.0.6 to allow pressurization to j
stroke the s alves. The Generil Manager of Nuclear Operations led the infrequently j
performed test or evolution (IPTE) briefing which reviewed the procedure i
requirements, contirigency actions, communications, and management expectations. The IPTE briefing was thorough and appropriately conducted during l
each shift while the work was ongoing.
l The inspectors observed good procedural adherence and proper communication among the operating crews. Maintenance personnel addressed several minor problems effectively and timely. The PORVs successfully met the test acceptance l
criteria and were declared operable for overpressure protection at low temperature.
System engineer involvement was appropriate and continued tracking of PORV performance was planned prior to Unit 2 startup.
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Conclusions The post-maintenance testing of the pressurizer power operated relief valves was conducted safely in accordance with procedures and proper management controls.
Technical Specification 3.0.6 was properly utilized during the testing.
l 01.3 General Comments and Operator Performance Observations a.
Inspection Scoce (71707. 37551)
l The inspectors conducted frequent reviews of ongoing plant operations through control room walkdowns, attendance at shift turnover, and observations of surveillance testing. The inspectors also reviewed condition reports for applicability to operator performance.
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Observations and Findinas
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During the period, inspectors observed an increase in the numbci of licensee human performance problems. Most of the problems were li ensee identified and were being tracked in the corrective action programs. On May 30, the Plant Manager issued a partial Etop work order for activities at the site. After a detailed briefing, only selected work activities, necessary to support the plant in its current mode, were conducted. The partial stop work order was in response to an unexpected pressure transient in the service water system. Several other issues relating to deficiencies in attention to detail in performance of daily tasks were contributors to the partial stop work order. The order was lifted after each department completed briefings during which the events which led to the partial stop work order were communicated. The inspectors noted that the partial stop work order was important to focus workers on proper attention to detail; however, significant human performance errors continued after the stop work order was lifted.
The human performance events pertained to tagout and clearance work, removal of temporary jumpers, restoration of equipment, conduct of surveillance, and conduct of maintenance. The issues represented breakdowns in the performance of everyday tasks and demonstrated poor self-checking, insufficient reviews, and weak attention to detail. The errors resulted in additional out-of-service time for safety related equipment, and caused operational personnel to be unaware of the inoperability of safety related equipment. The errors were significant in that safety related equipment was inoperable without operator knowledge; however, at all times TS action requirements were met.
l There were many examples of failures to follow procedures due to human performance problems. The most significant are described below:
Procedure 20ST-30.13A," Train A Service Water System Full Flow Test,"
Rev. 8, requires that the service water system be returned to the desired configuration as directed by the nuclear shift supervisor / assistant nuclear shift supervisor. On May 29, after conducting the service water test
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service water to the "A" high head safety injection pump. This condition, not recognized by operators, made the pump inoperable. The "A" high head safety injection pump was considered operable and considered to be part of an operable boration flow path on June 2. On June 3, the redundant train i
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"B" boration flow path was inoperable for 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br />. Therefore, both boration flow paths were inoperable. At this time TS 3.1.2.1 should have been
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entered. On June 8, a licensed operator identified that service water was aligned to the "C" high head safety injection pump and not the "A" pump.
Previous operator rounds failed to identify that the service water was isolated to "A" pump. Management expectation is that this issue should have been identified during operator rounds.
Procedure 1/2 OM-48,1.D, " Operations Shift Rules of Practice," Rev. 25,
requires that if an instrument provides an apparent improper indication, the operator should believe the instrument and respond conservatively to prevent damage to station equipment unless the instrument indicatic, is demons *ated to be false by checking against at least two redundant instruments. On May 22, operators did not respond conservatively when the branch flow line flow data for the high head full flow test indicated pump runout conditions. Testing continued without proper assessment of the indication of runout flow and the potential adverse affects on the high head safety injection pump. Reviews of this condition were not conducted until after NRC inspectors questioned the condition. (See Section M1.2)
Procedure NPDAP 3.4, " Clearance /Tagout Procedure," Rev. 9, requires a
senior reactor operator to verify that the tagout is properly prepared. On June 3, the clearance for exhaust fan 222-B was posted. The clearance or tagout deenergized fan 222-B; however, the clearance also disabled the two emergency diesel generator room ventilation fans 270 and 271. This was not recognized by the clearance or by the control room operators. Unknown to the control room staff, emergency diesel generator (EDG) 2-2 was inoperable for approximately four hours until operators attempted to start an emergency ventilation fan and it failed to start.
Procedure 2MSP-1.14B-1," Train B Reactor Trip and Bypass Breaker Time
Response Test," Rev.1, step K.1.b requires the removal of the jumper that disabled the Unit 2 general warning trip. On May 10, operators discovered that the jumper was stillinstalled in the solid state protection system. The technicians failed to remove the jumper on April 28 as required in the procedure, despite requirements for double verification.
The above examples are violations of TS 6.8.1.a, which requires that, " written procedures shall be established, implemented and maintained covering... the applicable procedures recommended in Appendix "A" of Regulatory Guide 1.33, Rev. 2, February 1978." (VIO 50-334(412)/98-03-01)
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The inspectors noted additional self-revealing examples of poor human performance related to a river water surveillance, electrical breaker clearances, and ernergency diesel generator maintenance. These issues, as well as the issues described above, are currently being tracked and evaluated through the licensee's corrective action
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program.
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Conclusions
The licensee experienced an increase in the number of personnel performance j
problems. The partial stop work order issued by the plant manager was important l
to focus workers on proper attention to detail. Although some improvement was i
noted, human performance errors continued after the stop work order was lifted.
l The errors resulted in additional out-of-service time for safety related equipment, and failure of operations personnel to be aware of plant conditions including inoperability of safety related equipment.
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O2 Operational Status of Facilities and Equipment O2.1 Enaineered Safetv Feature System Walkdowns (71707)
The inspectors walked down accessible portions of selected systems to asses.s equipment operability, material condition, and housekeeping. Minor discrepancies
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were brought to DLC staff's attention and corrected. No substantive concerns were l
identified. The following systems were walked down-
1 Unit 1 Auxiliary Feedwater
Units 1 & 2 Quench Spray
Operations Procedures and Documentation O3.1 Alarm Rescolse Procedure Review a.
Inspection 1qoce (61700. 71707)
The inspectors independently reviewed over 30 Unit 2 alarm response procedures pertaining to the reactor coulant system, the chemical and volume control system, and the emergency diesel generator system. The inspectors examined the procedures for TS applicability and for overall content and accuracy. The inspectors also evaluated the licensee's review of the procedures. Previous inspectors'
assessment of the procedure reviews were documented in NRC Integrated Inspection Report 50-334 and 50-412/98-02.
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Observations and Findinas l
Operations department personnel conducted an extensive review of alarm response procedures, abnormal operating procedures, operating manual procedures, and operating surveillance procedures to determine whether the procedures could result in conditions prohibited by TS. The inspectors did not identify any conditions that l
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were prohibited by TS that were not already in the licensee's corrective action program. The alarm response procedures reviewed generally referenced applicable TS. In most cases where the TS was not referenced, the licensee had identified the discrepancies and planned to correct the procedures through their procedure change process.
The inspectors observed some inconsistencies in the format and content in the alarm response procedures. The format of the procedures has been changed
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several times and not all procedures have been changed to the new format. An
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example of the discrepancies was inconsistent placement of some shift technical advisor (STA) administrative requirements. The STA supervisor issued a change request to revise the procedures. The inspectors also noted some human factors l
weaknesses. In one instance, the alarm response procedure was confusing based i
on the placement of the steps. The inspectors discussed these issues with appropriate licensee staff and corrective actions were planned to address the specific deficiencies. The inspectors did not identify any examples that would
cause the operator to take an incorrect action.
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Conclusions The licensee review of alarm response procedures generally identified all Technical Specification related issues and improved operator awareness of TS 3.0.3 entry conditions. The alarm response procedures were adequate for proper operator response.
Operator Knowledge and Performance
04.1 TS 3.0.6 Implementation
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Inspection Scoce (71707)
The inspectors reviewed the implementation of TS amendment 213 and 90 for Unit 1 and Unit 2 respectively. The inspectors evaluated the controls instituted for the
amendment, including procedure changes and training. In addition, the inspectors examined the licensee evaluation of a Cst of potentialissues that may require use of the new amendment. The following procedures were reviewed:
1/2 OM-48.1.1, " Technical Specification Compliance," Rev.1
NPDAP 2.15, " Administrative Controls," Rev. 4
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Observations and Findinas l
j The amendment, approved April 15,1998, incorporated TS 3.0.6 and allows equipment previously removed from service, or declared inoperable (to comply with I
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TS action statements) to be returned to service to demonstrate its operability or the operability of other equipment. Administrative controls must be in place to perform the testing to ensure the time period in which the equipment is returned to service, is limited to the time necessary to perform the allowed testing. TS 3.0.6 does not I
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allow for other preventive or corrective maintenance except minor corrections such j
as adjustments to limit switches to' correct position indication anomalies.
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NPDAP 2.15 and 1/2 OM-48.1.1 stated that the administrative controls should L
include an approved procedure or temporary procedure to support the testing and a
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pre-job briefing prior to entry into TS 3.0.6. The pre-job briefing should ensure that all personnel involved are aware of TS 3.0.6 purpose, sequence of events, any contingency actions (including any manual actions), and the need for timely l
procedure completion. The inspectors determined that the procedure guidance and requirements for administrative controls were sufficient to meet the requirements for TS 3.0.6. The inspectors observed that TS 3.0.6 and administrative controls were properly implemented during post-maintenance testing of the Unit 2 pressurizer PORVs (see Section 01.2).
The inspectors examined a list of potentialissues that may require use of the new amendment. The inspectors determined that the licensee's review was detailed and appropriate. The inspectors questioned senior reactor operators on applicability of TS 3.0.6. Generally, the operators and senior reactor operators within the planning and scheduling department had a good understanding of the specification entry requirements. Normally the TS 3.0.6 entry would be identified during planning and i
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scheduling of the work items with the final barrier being the control room operators.
Operators initial review of a condition report regarding TS 3.0.6 revealed potential weaknesses in their understanding of the amendment. Corrective actions in response to that condition report were under development. These issues notwithstanding, the inspectors concluded the barriers in place were adequate to identify.TS 3.0.6 issues.
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Conclusions The controls instituted for the TS 3.0.6 amendment,-including procedure changes
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and training, were sufficient and in place prior to implementation.
04.2 Unit 2 Quench Sorav Pumo (2OSS-P21B) Water Hammer Event a.
Insoection Scope (71707,92901,92903)
l While performing periodic surveillance testing on the Quench Spray system, I
operators reported a water hammer event. The inspectors attended the event i
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critique, reviewed records, and observed post event inspections to assess the
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safety significance and licensee evaluation of this event.
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Observations and Findinas On April 7,.1998, operators performed 20ST-13.11, Quench Spray (QS) System Operability Test, Rev. 9. This once per 18 month test, had been scheduled to be performed a week earlier, but was not performed due to other work conflicts and resource limitations.'.The test was not specifically scheduled for or discussed at the April 7 morning planning meeting. During the pre-evolution brief, control room
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operators questioned several aspects of the test inciuding the initial configuration which required the pump suction valve to be shut. Operators recalled that there had been a previous issue regarding excessive QS pump vibration and questioned whether it had been properly resolved. The operating crew reviewed the completed test procedures from the last three times the test was run and found no problems documented. After attempting unsuccessfully to contact the system engineer, the assistant nuclear shift supervisor (ANSS) contacted the procedure writer, but failed to resolve the questions raised by the control room staff regarding the suction valve position. The ANSS and procedure writer concluded that engineering was preparing l
a related design change, but that no additional actions were needed prior to performance'of the surveillance test.
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About 5 seconds after starting 2OSS-P21B, operators heard three loud bangs and observed a large (6-8 inch) pipe movement in the QS pump discharge piping.
Following completion of this portion of the test, operators reported their i
observations to the ANSS. The test was stopped, the pump was declared l
inoperable pending evaluation, and condition report (CR) 980693 was written to document the event. Although the CR was written, the licensee concluded that the operations organization was slow to notify plant management. An event critique was held on April 8, but the meeting failed to provide adequate information to
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evaluate and assess the event. A second critique, with the Plant Manager, l
Engineering management, and Operations management present, was held on April 10. By this time, engineers realized this was a repeat water hammer event.
Management then recognized the significance of this event and formed a Multi-
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discipline Analysis Team (MDAT) to evaluate the event and recommend corrective actions.
The inspectors observed that important f actual information was clearly discussed at
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the second critique. The critique highlighted that severalimportant barriers and I
station processes had broken down and provided appropriate detail for the MDAT to evaluate. A previous water hammer event on the same pump on September 28, 1990, had not been resolved in that recommended corrective actions had not been
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completed. The critique following the 1998 QS water hammer event also noted L
that the schedules for work activities were unreliable and questions raised during the pre-evolution briefing had not been properly resolved. Based on the critique, the General Manager of Nuclear Operations (GMNO) directed that no surveillance tests with a frequency of quarterly or longer be pe'rformed until after corrective action was identified and implemented for this event. The critique was good and the inspectors determined this interim action was appropriate. Engineers directed disassembly and inspection of 2OSS-P218to assess operability in support of the MDAT. Based on this inspection and piping inspections, the licensee concluded that the QS pump remained operable following the water hammer event.
The inspectors reviewed the problem report (PR) and CR history files and identified
several related events. PR 1-95-049 (February 7,1995) reported that the Unit 1 i
"A" quench spray pump (OS-P-1 A) tripped on over current due to significant air voids in the discharge header prior to pump start. This PR also reported air voids found in QS-P-1B discharge piping as well. PR 2-96-575 (September 28,1996)
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l reported excessive pump vibration and water hammer when 2OST-13.11 was j-performed to test 2OSS-P21B. The cause was attributed to the procedure requiring the suction valve to be shut when the pump was started. Corrective actions were i
initiated to revise the procedure, but we.re not complete prior to the April 7,1998, water hammer event. PR 1-96-802 (September 30,1996) reported excessive QS-P-
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1 A pump vibrations due to throttling the discharge valve excessively during the j
surveillance test. CR 972133 (November 12,1997) reported air voids in the QS-P-
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1 A pump discharge header high point following performance of the fill and vent procedure. The inspectors determined that these previous events were clearly related to the April 7,1998, event and tha't previous corrective actions were not I
comprehensive and in some cases not completed. Although the QS system was not
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damaged by the events described above, the inspectors concluded that failure to l
correct this recurring condition represented a failure of the corrective action program, and had significant potential safety consequences.
. The MDAT performed a comprehensive review of related operational events, corrective action databases, material history, procedures, and external industry experience. They determined the primary root cause for the events to be l
inadequate system restoration controls (e.g.. fill and vent) following testing (e.g.
l valve leakage tests). They also identified the contributing causes to be (1)
Inadequate corrective action for PR 1-95-049 described above, and (2) Inadequate causal analysis and incomplete corrective actions for M 2-96-575.
l The MDAT further reviewed the existing station process barriers which should have prevented this event. Barriers evaluated included work planning, scheduling, clearance posting, maintenance work activity performance, clearance pickup, system restoration for turnover, and system return to standby. Twenty-nine
!
associated corrective actions were identified and discussed with assigned acGon departments to ensure proper understanding for resolution. Corrective actions ranged from revisions in the work planning process, to positive controls for verifying system fill and vent activities, to improved sensitivity by the operations department personnel to the safety significance of water hammer events. The inspectors reviewed the recommended corrective actions and determined that the MDAT's evaluation was thorough and the recommended actions were comprehensive. This l
was very important considering that previous assessments of several related events and implementation of corrective actions were inadequate. Before the MDAT was formed, licensee event analysis focussed primarily on the suction valve configuration. The inspectors determined that the MDAT process was instrumental i
in identifying the programmatic system restoration (fill and vent) issue.
10 CFR 50, Appendix B, Criterion XVI " Corrective Action" requires in part that
significant conditions adverse to quality be promptly identified and corrected,
)
including determination of the cause of the condition and corrective action to preclude repetition. Failure to adequately determine the cr.
and implement appropriate corrective actions for QS pump events on Febr ;..y 7,1995, and l
September 28,1996, directly contributed to the April 7,1998 QS water hammer event and was a violation. This non-repetitive, licensee-identified and corrected 1w________-____-
.
.
violation is being treated as a Non-Cited Violation, consistent with Section Vll.B.1 of the NRC Enforcement Policy. (NCV 50-334 (412)/98-03-02).
c.
Conclusions On April 7,1998,2OSS-P218 experienced a water hammer event. Several process barriers failed including inadequate corrective actions for similar previous events, system restoration procedures, planning, and scheduling. The final barrier failed when operations personnel did not fully resolve valid safety concerns prior to performing a surveillance test during which the water hammer occurred. Although the QS system was not damaged, this condition represented a failure of the licensee corrective action program. The event critique and Multi-discipline Analysis Team assessments were excellent. The MDAT recommended comprehensive corrective -
actions to address this event.
Miscellaneous Operations issues (71707,92700,92901)
08.1 Technical Specification Amendment Implementation Process a.
Inspection Scope (71707)
The inspectors reviewed recent difficulties experienced by the licensee in implementing TS amendments, b.
Observations and Findinas TS Amendment No. 212 Unit 1 TS Amendment No. 212, which lowered the undervoltage start setpoint limits of the emergency diesel generators to prevent inadvertent starts, was issued by the NRC on February 11,1998. The implementation of the amendment was weak with respect to coordinating actualin-field undervoltage setpoint changes with updating the controlled copies of the TS. As a result, the TS amendment was inserted into the TS, removed from the TS, and subsequently reinserted in the.TS.
The licensee concluded that the cause of the confusion was a lack of ownership and coordination of the amendment implementation process by the licensing staff.
Safety & Licensing Administrative Manual Vol.II,~ Chapter 5, " License Amendment Request and Licensing Requirements Manual Control," Rev.13 was developed to l
clarify the license amendment implementation process and associated personnel
!
responsibilities. The inspectors determined that the procedure revision was
[
adequate anJ verified that no TSs were violated as a result of the confusion during I
the implementation of TS Amendment No. 212.
TS Amendments Nos. 209 and 87: and Nos. 210 and 88 On December 10,1997, the NRC issued Unit 1 TS Amendment No. 209 and Unit 2 TS Amendment No. 87. These amendments relocated certain administrative control requirements from the Unit 1 and 2 TSs to the operational quality assurance l
_ _ _ _ _ _ _ _ _ _ _ _ _ _ - -__- -__ _ -_ -_
.
.
program description, which is presented in Section 17.2 of the Unit 2 Updated Final Safety Analysis Report (UFSAR). Section 17.2 of the Unit 2 UFSAR contains the Quality Assurance program description for both units.
On January 20,1998, the NRC issued Unit 1 TS Amendment No. 210 and Unit 2 TS Amendment No. 88. These amendments relocated certain reactor trip system
,
(RTS) and engineered safety feature actuation system (ESFAS) response time limits
'
from the Unit 1 and 2 TSs to the Licensing Requirements Manual (LRM) as an appendix to the UFSAR.
'
In March, the inspectors noted that the administrative control requirements for the Offsite Review Committee (ORC) had been removed from the TSs, but had not been l
relocated to the UFSAR. During a TS procedure verification review, the licensee
!
noted that the LRM directed the user to Section 15A (Unit 1) and 16A (Unit 2) of the UFSAR. No such sections existed, and the LRM was not described as an appendix to the UFSAR. Licensing supervisors informed the inspectors tnat the UFSAR revisions were documented on a pending UFSAR change log, but that the actual UFSAR revision would not be made until the next annual UFSAR update in accordance with 10 CFR 50.71(e). The inspectors further reviewed various station implementing procedures and determined that some procedures (e.g. NPDAP 8.10,
"On-site Safety Committee," Rev. 3; QSP 20.1, " ORC Committee Charter," Rev. 0; OP-15, " Quality Assurance Records," Rev. 5 were not properly updated to reflect the TS amendment. The inspectors discussed these weaknesses with licensing and quality assurance personnel who initiated appropriate procedure revisions.
The inspectors expressed concern that while station personnel performing licensed activities such as operability determinations and safety evaluations normally review
.the controlled copy of the UFSAR as part of their related reference information, they were not aware of pending UFSAR updates (such as the TS amendments discussed
!
l above), which could affect the outcome of their evaluation. The inspectors further noted, that while the "pending UFSAR change log" was maintained in a computerized format, it was approximately 8 months out of date. The inspectors did not identify any specific instance where the failure to review the approved l
pending UFSAR updates resulted in violation of TS or failure to identify a unreviewed safety question. Licensing engineers acknowledged that the method of communicating approved pending UFSAR changes was ineffective and additional corrective actions were initiated based upon the inspectors' findings.
c.
Conclusions Implementation of several TS amendments, and communication of approved changes to the UFSAR for use by the station's staff were poo _ _. _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _
.
.
08.2 (Closed) Licensee Event Reports (LERS) 50-334/97-12-01 and 97-12-02: Technical Specification 3.0.3 Entry Due to Two Analog Rod Position Indicator (ARPI) Channels Inoperable.
The original issue was discussed in NRC Integrated Inspection Report 50-334 and 412/98-02, Section E8.3. These LER supplements were submitted to provide additional information identified through the licensee corrective action follow-up to this event.
As part of the licensee's TS surveillance review effort, the licensee determined that a shutdown margin determination should be completed within one hour of detection of an inoperable control rod (s), in accordance with TS surveillance requirement (TSSR) 4.1.1.1.1.a. The issue was documented on condition report 971622. As part of the condition report response, the licensee reviewed operating procedures and recent control rod mispositioning events. Following control rod movements on April 14, April 15, and May 15,1997, rod positions as indicated on ARPl were found outside the TS allowable band. The licensee concluded that the control rods involved should have been declared inoperable, which requires that a shutdown margin determination be performed within one hour. While shutdown margin determinations were made during the events, they were not made within one hour j
as required by TSSR 4.1.1.1.1.a. The failure to perform shutdown margin
{
determinations within one hour was reported to the NRC in revision 01 to LER 97-
'
12.
The events were all caused by calibration drift of the ARPI system due to system design limitations. All of the control rods were subsequently determined to be in their expected position. The licensee concluded that the applicable TSs were not correctly applied and that procedures associated with rod mispositioning events
lacked sufficient detail. As immediate corrective actions, the events and the I
applicable TSs and TSSRs were reviewed with all operators, and additional guidance i
on how to monitor and respond to ARPl malfunctions was issued. As long-term corrective actions, the licensee implemented an upgrade (DCP 2209, "ARPI Electronics Upgrade") to the ARPI system during refueling outage 1R12. In i
addition, permanent changes to strengthen procedures associated with rod mispositioning events were being tracked in the corrective action program. Revision 02 to LER 97-12 reported the completion of modifications to the ARPl system and revised the date for completion of procedure changes associated with the event.
The inspectors conducted an in-office review of the LER supplements and assessed that licensee response to the rod position indication problem was appropriate.
Failure to perform a shutdown margin determination within one hour of detection of an inoperable control rod (s) in accordance with TS 4.1.1.1.1.a was a violation of NRC requirements. This non-repetitive, licensee-identified and corrected violation is being treated as a Non-Cited Violation, consistent with Section Vll.B.1 of the NRC Enforcement Policy (NCV 50-334/98-03-03). The LERs are close __.
. _ _ _
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08.3 (Closed) LER 50-334/97-23: Technical Specification 3.0.3 Entry Due to Two Analog Rod Position Indicator (ARPI) Channels inoperable.
I The issue was similar to LER 50-334/97-12, discussed in NRC Inspection Report
)
50-334 and 412/98-02,Section E8.3, and in Section 08.1 above. ARPI for control
rod H-02 had been declared inoperable following evaluation of an earlier event on May 15,1997. During rod positioning on August 1, rod P-08 indicated outside its TS allowable band due to ARPI calibration drift. Operators took appr:opriate action to confirm rod P-08 was in its correct position. The ARPl returned to within the allowable band in about 28 minutes. Operators determined that TS 3.0.3 applied from the time that rod P-08 position indication went outside the allowable band until the rod was confirmed to be in its expected position. The inspectors conducted an in-office review of this LER and assessed that operators took appropriate action for rod P-08 ARPl outside its TS allowable band. Corrective actions for the event are l
discussed in Section 08.1. No new issues were revealed in this event.
!
08.4 (Closed) LERs 50-412/97-03 and 50-412/97-03-01: Technical Specification 3.0.3 Entry Due to inoperability of Both Trains of the Supplemental Leak Collection and Release System.
The inspectors conducted an onsite review of the LER. The inspectors interviewed the system engineer, licensing engineers, and other licensee personnel, and reviewed a sample of the corrective actions documented in the LER.
The issue was previously documented in NRC Inspection Report 50-334(412)/97-05. The event and causal assessment were properly documented in the LER.
Corrective actions were completed and adequately addressed the causes of the event The LER supplement appropriately updated the LER to capture additional examples of past entries into TS 3.0.3 due to inoperability of the Supplemental Leak Collection and Release System. The licensee event report was properly documented and corrective actions adequately addressed the causes of the event.
08.5 (Closed) VIO 50-334/EA 96-462: Unit 1 Pressurizer (PZR) Power Operated Relief Valve (PORV) Block Valve Configuration Contrary to UFSAR This violation pertained to Unit 1 operating over 13 years with two PZR PORV block valves shut, contrary to the configuration described in the UFSAR. This configuration was a significant contributor to the station's total core damage frequency and the licensee failed to correct the condition despite several opportunities to do so. The licensee response to this violation was documented in Duquesne Light Company (DLC) letter dated April 9,1997. The inspectors determined that the response appropriately addressed the violation and conducted on-site interviews, document reviews, and in field verifications to determine i
l whether corrective actions were properly implemented. The inspectors concluded that the corrective actions were properly implemented to preclude recurrence of a similar event.
l u___-___
_
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l
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08.6 (Closed) LER 50-334/97-15: Proceduralized Voluntary Entry into T.S. 3.0.3 by Allowing Bypass of Both Source Range Channels input to High Flux Trip.
l This issue was previously documented in NRC Integrated Inspection Report 50-334 l
and 412/97-05, Section 04.1, and resulted in Non-Cited Violation 50-334 and 412/97-05-01. Therefore, the inspectors performed an in-office review of the LER.
No new issues were revealed.
08.7 (Closed) LER 50-334/97-16: Unit 1 Shutdown Required by T.S. 3.0.3 Due to Inoperable Steam Generator Low-Low Level Reactor Protection System Trip.
This issue was documented in NRC Integrated Inspection Report 50-334 and 412/97-05, Sections 01.2, and E1.1, and resulted in Non-Cited Violation 50-334/97-05-07. Revision 01 to this LER (50-334/97-16-01)was reviewed and closed out in NRC Integrated Inspection Report 50-334 and 412/97-07, Section 08.3. Therefore, the inspectors performed an in-office review of the LER. No new I
issues were revealed.
08.8 (Closed) LER 50-334/97-22: Engineered Safety Feature Actuation of the P-12 Interlock Due to Decreasing Water Temperature.
This issue was not previously reviewed in any NRC Inspection Raport. The inspectors performed an in-office review of the LER. The event's root cause was determined to be operator unfamiliarity with the steam generator level controller response, and a contributing cause was procedure weakness. Corrective actions focused on training of operations personnel; additionally, affected procedures were to be reviewed and revised as necessary. The inspectors concluded that the LER properly identified the root cause and corrective actions were appropriate, and the LER met the requirements of 10 CFR 50.73.
ll. Maintenance M1 Conduct of Maintenance M 1.1 Routine Maintenance Observations a.
Inspection Scoce (62707)
The inspectors observed portions of selected maintenance activities on important systems and components. The activities observed and reviewed are listed below.
- MWR 059101 Support CERPI Monitoring
- MWR 071874 Rewire Inverter SSW-VITBUS-2
- MWR 071225 Replace Degraded Stu& on MOV-RH-700in accordance with 1 CMP-10RH-MOV-7001 M
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1 LCP-9-L107A, Rev.1 L-DG107A, Primary Drain Transfer Tank 1 Level Loop
Calibration
- MWR 070597 Boric Acid Cleanup and Inspection of RH-10
- MWR 070596 Boric Acid Cleanup and inspection of RH-9
- MWR 071639 MOVATS Testing on 2SWS-MOV-102C1 b.
Observations and Findinas MWR 071225 activity was conducted as an infrequently performed test or evolution (IPTE) due to the sensitivity of performing work activities on the residual heat removal (RHR) platform while the RHR system was in service. A responsible test manager was assigned and a pre-evolution brief was conducted to discuss the procedure, work responsibilities, radiological controls, communications, and contingency plans. Applicable department representatives involved in the work attended the brief. The inspectors assessed that the evolution was properly controlled.
c.
Conclusions The activities observed and reviewed were perforrned 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.
M1.2 Routine Surveillance Observations a.
Insoection Scope (61726)
The inspectors observed selected surveillance tests. Tests reviewed and observed by the inspectors are listed below.
- 10ST-43.1
"TS Required Area and Process Monitor Channel Functional Test," Rev.3 e 10ST-11.2
" Safety injection Pump [1SI-P-18] rest," Rev. 8
- 10ST-10.1
" Residual Heat Removal Pump Performance Test," Rev.10
- 10ST-13.1
" Quench Spray Pump [10S-P-1 A1 Test / Itev.18
- 10ST-36.1
" Emergency Diesel Generator (EDG) No.1 Monthly Test," Rev.
- 10ST-30.5
" Reactor Plant River Water (RPRW) System Valve Test for B Header," Rev.12 l
l
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.
+ 10ST-30.3
"RPRW Pump 18 Test," Rev 17
- 20ST-30.8B
" Standby Service Water System Test Using (2SWE*P21B],"
Rev.2
+ 2 TOP-98-05
" Quench Spray Pump and Line Fill and Vent," Rev. 0
- 2OST-30.13A
" Train A Service Water System Full Flow Test," Rev. 8
- 20ST-30.13B
" Train B Service Water System Full Flow Test," Rev. 7
- 20ST-11.14B
"High Head Safety injection (HHSI) Full Flow Test," Rev. 5 b.
Observations and Findinas The surveillance were generally performed safely and in accordance with procedures; however, several weaknesses were noted. For example, some procedures were of marginal quality and challenged operators and equipment, in 2OST-11.14B,the procedure required operators to obtain HHSI flow between 545 and 550 gpm; however, the instrument used had markings at 25 gpm increments.
This issue combined with instrument inaccuracies resulted in operators having difficulty determining accurate readings, in 20ST-30.138,during preparation for establishing full flow conditions, operators noted approximately 108 psig service water header pressure on the "B" train. The system engineer present stated that they should remain at greater than a 100 psig for only a short time period (system design pressure is 124 psig). This caution and/or steps to reduce the pressure were not in the procedure. During 2OST-30.13A,the service water system experienced several pressure transients on the system while valve testing was performed. The pressure transients were not expected nor were personnel properly located to detect the transients until the fourth one occurred. The pressure transients are being evaluated by the licensee under condition report 981174.
T.'.a inspectors also noted weaknesses associated with operator communication, usage of instrument indication, and self-checking techniques. During 20ST-11.14B, operators appropriately questioned the accuracy of full HHSI flov. based on their review of control board indication and an associated computer point. The nuclear shift supervisor (NSS) directed that branch flow readings be obtained. During testing of the "A" HHSI pump, the branch flows indicated a total flow greater than the runout limit of the pump (567 gpm versus 560 gpm). However, the NSS did not properly assess his instrumentation for the "A" HHSl pump and resumed the test even though runout conditions were indicated by the branch flows. The NSS determined that these flow instrument indications had a tendency to bounce around
,
and were not accurate. These same instruments were later used in the procedure to obtain flows within 3 gpm for each branch and were considered accurate to within that measurement. Continuing the test without taking precautions may have resulted in the "B" pump also exceeding pump runout conditions (branch flow i
values were not obtained). Corrective actions to address this issue were being planned under condition report 981251. The licensee planned to re-perform 2OST-l t
-..
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1
,
11.148 after completing corrective actions to resolve a separate issue regarding sticking check valves.
The inspectors noted that the observed "A" HHSl pump flow of 567 gpm was not
recorded in the procedure and was not immediately communicated to the team
'
conducting a review of the full flow test. After the NRC's questioning the licensee fully evaluated the runout conditions exp?rienced by the HHSl pumps. Based on reviews of pump data and discussions with the vendor, system engineers concluded that the pumps were not damaged. Failure to take appropriate action in ~ response to an out of specification indication was an additional example of the violation for failure to implement procedures which is addressed in Section 01.3 of this report.
i Other minor discrepancies were noted and brought to the attention of the appropriate licensee supervisor. For the full flow test, the inspectors discussed their observations with the General Manager of Nuclear Operations (GMNO) and the Technical Assistant to the GMNO. The Technical Assistant to the GMNO discussed j
these issues with the crews involved, l
During 10ST-36.1, operators responded appropriately to a smallleak (1 drop /sec)
on 1EE-FL-10A, the engine-mounted duplex fuel filter. The system engineer was present to aid the ANSS in evaluating the leak. The fuel filter was shifted to the redundant filter and the leak was significantly reduced. The leak had previously been documented on material deficiency tag 04885, but had degraded since originally discovered. The system engineer stated that the work priority of the leak repair would be raised due to its degrading condition. The EDG system was already being monitored under paragraph (a)(1) of the Maintenance Rule.
During the pre-evolution brief on May 12 for 20ST-30.8B,a refueling outage frequency test, operators raised questions concerning the availability of personnel necessary to perform the test, the operability of reactor coolant system (RCS) core cooling sources during the test, the capability of operating valve 2SWE-220 according to the test procedure without creating a hydraulic lock, and a lack of a procedure to operate with only one service water pump in service (question previously raised by Condition Report 981035). Operators appropriately postponed the test until the questions were resolved.
c.
Conclusions Surveillance were generally conducted safely. In some cases marginal procedure quality challenged operators and equipment. One example of operator inconsistent use of available indications resulted in a violation of procedure.
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M1.3 Material Deficiencv Taas a.
Insoection Seboe (62707)
The inspectors observed licensee assessment and control of existing deficiency tags in the control room.
l l
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_
,
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b.
Observations and Findinas During a review, Quality Services Unit inspectors noted 64 Material Deficiency Tags posted in the Unit 2 ccatrol room. Of the 64 tags,21 were for conditions where the work had been completed, but the tags had not been removed, in addition,11 tags did not have maintenance work requests (MWRs) associated with them. These observations were documented on Condition Reports 981246 and 981247.
The inspectors discussed the issue with the Director, Fix-It-Now (FIN) Team. The licensee initiated an audit of material deficiency tags in the Unit 1 control room and a review of the material deficiency tag process. Corrective actions under
consideration included changes to the MWR and work control processes to ensure that all of the material deficiency tags were removed from the field and the control room after completion of work.
!
In NRC Integrated Inspection Report 50-334 and 412/98-01,Section M2.1, NRC l
inspectors had previously documented an error rate of about 1/3 in the Material Deficiency Tag system and noted that the high error rate had the potential to mask equipment deficiencies or adverse trends. The NRC observations were documented on Condition Reports 980474 and 980475, but corrective actions were not yet complete. A licensee self-assessment of the deficiency tag process was scheduled to be completed by July 30, with results to be entered in the corrective action system.
c.
Conclusions Li:ensee posting and control of equipment deficiency tags continued to be poor.
M4 Maintenance Staff Knowledge and Performance M4.1 Schedulina of Refuelina Interval inservice Testina a.
Insoection Scooe (61726. 71707. 92903)
l The current Unit 2 extended forced outage caused the licensee to postpone the next refueling outage and reevaluate schedules for certain TS required periodic surveillance testing. The inspectors interviewed personnel, reviewed records, and evaluated inservice test (IST) program activities to assess licens< 1 evaluation and scheduling of the required TS surveillance testc.
b.
Observations and Findinas Unit 2 shut down on December 16,1997, to resolve a design deficiency, and Unit 1 shut down on January 31,1998, to resolve various TS surveillance testir.g program deficiencies. TS surveillance tests with an 18 month periodicity, normally performed during scheduled RFOs, were due for completion prior to the September RFO. Senior management directed the Operations Support Group to evaluate those TS surveillance test requirements which had an 18 month or refueling cycle
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periodicity and reschedule them for performance during the current forced outage as outage duration, operations department resources, and plant conditions permitted.
As the current forced outage extended through March, April, and May, the majority of the 18 month interval surveillance tests were completed. The licensee developed regulatory relief request justifications for those remaining TS surveillance test requirements which they believed were inappropriate to perform without detensioning the reactor vessel head. On May 6, the Nuclear Safety Review Board (NSRB) reviewed the proposed TS amendment request, for relief from six sets of TS surveillance test requirements. The NSRB determined that the bases presented for the TS amendment request were inadequate. Most justifications failed to sufficiently address historical test data, lacked risk insights, inaccurately addressed current plant conditions for testing, incorrectly interpreted TS or American Society of Mechanical Engineers (ASME)Section XI requirements, or relied heavily on the increased operational burden or outage delays which would be associated with performing the tests within the required test interval. The inspectors determined that the NSRB review was good. However, the On-site Safety Committee review of the TS amendment request was poor, in that the above stated deficiencies were not
. identified and resolved prior to forwarding the issue to the NSRB, The inspectors observed that several of the NSRB members had direct responsibilities for evaluating and managing the 18 month surveillance testing issue since February, yet had not reviewed the relief justifications sufficiently prior to the NSRB meeting. Based on interviews and document reviews, the inspectors determined that the results of the technical reviews which supported the TS amendment relief request, were ineffective.ly communicated and acted upon.
Consequent 8y, assessment and scheduling of TS surveillance testing requirements was untimely. Several additional TS required surveillance tests were added to the outage work schedule following NSRB rejection of the proposed TS amendment request.
c.
Conclusions l
Evaluation, scheduling, and management oversight of Unit 2 periodic inservice test (IST) program requirements from February through May was poor.
M8 Miscellaneous Maintenance issues (90712,92700,92902)
M8.1 (Closed) LER.50-334/98-12: Replacement Capacitors Purchased from Fluid l
Components, Inc. (FCl).
While replacing capacitors on temperature switch circuit boards in accordance with p;eventive maintenance procedures, the licensee discovered that the capacitors could mc be pdranteed to withstand the consequences of a seismic event without being flush mounted to the circuit board. The temperature switches provide input signals for valve isolation of piping during a high energy line break (HELB) in the
'
steam generator blowdown (SGB) system and auxiliary steam (AS) supply system.
Failure of these temperature switches during a seismic event in conjunction with a
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.
HELB would have disabled the input signals for automatic valve isolation in the SGB and AS systems. No safety-related functions are provided by the systems except the valve isolation functions, which are designed to maintain the environmental qualification envelope for vital equipment in the Safeguards and Auxiliary Building areas in case of a HELB.
The capacitors were to be replaced every 5 years in accordance with the vendor manual. The vendor manual detailed installation of the capacitors flush mounted to the circuit board in order to maintain seismic qualification of the temperature switch. During recent replacement of the capacitors in accordance with regularly scheduled preventive maintenance, technicians discovered that the capacitors had not been previously installed correctly and initiated Condition Report 980219.
When the capacitors were replaced 5 years ago, the replacements were physically larger than the previous capacitors and could r;ot be flush mounted to the boards.
The licensee promptly consulted with the vendor. The vendor responded that the
!
capacitors could maintain seismic qualification as long as silicon sealant was i
injected between the capacitor and the circuit board and the capacitors were no more than 3/8 inch off the board.
The cause of the event was inadequate implementation of vendor instructions to adhere to equipment qualification requirements. As immediate corrective actions, the licensee verified that none of the capacitors were more than 3/8 inch off the circuit board and injected silicon sealant between the capacitors and the board. The inspectors monitored the corrective maintenance; no deficiencies were noted. The issue did not apply to Unit 2. The issue was reviewed with maintenance personnel and adherence to procedural requirements was re-emphasized. Based on field observations, interviews, and document reviews, the inspectors concluded that maintenance personnel demonstrated a good questioning attitude in identifying the equipment qualification deficiency and corrective actions were appropriate.
Failure to maintain equipment qualification in accordance with the design basis was a violation of 10 CFR 50, Appendix B, Criterion ill, " Design Control." This non-
,
repetitive, licensee-identified and corrected violation is being treated as a Non-Cited Violation, consistent with Section Vll.B.1 of the NRC Enforcement Policy (NCV 50-334/98-03-04).
M8.2 (Closed) VIO 50-334(4121/96-10-04: Failure to Properly Certify Vendor for Safety Related Work in Accordance with Qualified Suppliers List This violation addressed licensee failure to properly certify vendors to appropriate quality standards for work on two safety related leak injection repair activities. The inspectors previously field verified the effectiveness of interim corrective actions as documented in NRC Integrated Inspection Report 50-334(412)/96-10. During this period, the inspectors conducted interviews, reviewed strJ orocedures, and l
I reviewed completed condition reports to assess licensee comctive actions to f
preclude recurrence. Procedures reviewed included:
_ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ - _ _ _ _ _ - _ _ - _ _ _ _ _ _ _ _ - _ _ _ _ _ - _ _ _ - _ _ _ _ _ _ _ _ - _ _ _ _ _ - _ _ _ _ _ _ _ _ _ _ _ _ _
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i
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Quality Services Procedure (QSP) 7.4, " Vendor Selection, Evaluation, and (
OSL," Rev. 5 l
Nuclear Power Division Administrative Procedure (NPDAP) 9.5, " Service l
Contract Administration," Rev. 3 l
NPDAP 9.8, " Request for Contracted Services," Rev. 4 NPDAP 9.1, " Material Management," Rev 6 The procedures listed above were properly revised and training was conducted to l
ensure vendors would be properly certified prior to performing safety related work activities. No additionalinstances of failure to properly certify vendors have been j
identified since implementation of the relevant procedure revisions. The inspectors l
determined that corrective actions specified in the licensee response to notice of j
l violation dated March 24,199',, were appropriate and were effectively
!
implemented.
M8.3 (Closed) LER 50-334/97-17: Engineered Safety Feature Actuation of the P-12
)
Interlock Due to Decreasing Reactor Water Temperature.
'
This issue was documented in NRC Integrated Inspection Report 50-334 and 412/97-05, Section M1.2, and resulted in Violation 50-334/97-05-05. Since that violation rernains open pending review of DLC's actions regarding operations review concerns, the inspectors performed an in-office review of the LER. No new issues were revealed.
M8.4 1 Closed) LER 50-334/97-08-01: Missed Technical Specification Surveillance -
l Monthly Position Check of Valves in the Boron Injection Flowpath.
The inspectors conducted an in-office review of this LER revision. The issue was originally documented in NRC Inspection Report 50-334 and 412/97-02, Section M8.2. The original LER was reviewed and closed out in NRC Inspection Report 50-334 and 412/97-02,Section M8.8. The revision provided additionalinformation
concerning electrical power verification for the same valves and did not change the previous inspection assessments.
l 111. Enaineerina E1 Conduct of Engineering E1.1 Besolution of Station Conditions Outside of Station Accident Analysis l
a.
insoection Scope (37551. 71707. 92901,92903)
While preparing a response to violation 50-334(412)/98-01-03, the licensee identified several additional instances where the station TSs were not sufficient to ensure the station would operate within the existing UFSAR accident analysis. The inspectors conducted on-site interviews, reviewed design documents and station L___ _ _____.___
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records, and observed licensee evaluation of this issue to assess both the scope of the problem and licensee corrective actions.
b.
Observations and Findinqs NRC Integrated Inspection Report 50-334(412)/98-01 documented an issue where existing TS degraded voltage setpoints were non-conservative, in that the setpoints were not sufficient to maintain minimum voltage requirements for safety related equipment under certain design accident conditions. The licensee's procedure changes to address this issue were inadequate and the licensee failed to submit a TS amendment request. While preparing the violation response the licensee
,
identified similar conditions with other TS requirements involving reactor protection I
system (RPS) setpoints, limiting safety system setting (LSSS) setpoints, and engineered safety feature (ESF) setpoints. A Multi-disciplined Analysis Team j
(MDAT) was formed to determine the extent of the problem and Uentify appropriate i
corrective actions.
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The inspectors noted that several issues identified over the past year appear to have similarities with the above described items. Those related issues resulted from (1)
incomplete licensee resolution of technical information received from vendors or industry events, (2) informal administrative controls and processes to assure corrective actions are properly implemented, and/or (3) deficiencies associated with TS interpretations and processing of TS amendments. Examples are listed below:
- Unit 1 emergency diesel generator (EDG) unnecessary auto starts due to improper TS 4 kV bus undervoltage setpoint. (NRC IR Nos. 50-334(412)/97-02 & 97-07)
- Unit 1 forced shutdown for two inoperable RPS trip functions. (NRC IR Nos.
50-334(412)/97-05)
- Unit 2 EDG autostart response time on 4 kV bus undervoltage was incorrect.
Inadequate administrative controls resulted in both EDGs being inoperable.
(NRC IR 50-334(412)/97-11)
- Unit 1 & Unit 2 degraded 4kV bus voltage EDG start setpoints were outside of design. (NRC IR Nos. 50-334(412)/98-01)
- On numerous occasions station personnel have incorrectly interpreted TS and/or relied on incorrectly written TS interpretations. (Various NRC irs)
- Four TS amendments were not properly implemented. (Section 08.4 of this report)
The inspectors considered these recent events when evaluating MDAT proceedings to determine whether the extent of conoition and causal factor analysis were appropriate.
The MDAT reviewed over 10,000 engineering, licensing, industry or vendor technical notices, corrective action documents, procedure, and maintenance documents. Based on this initial review, including various industry technical information (received 1990-1995),the MDAT determined that existing TS were non-conservative and did not assure the plant would remain within UFSAR accident
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analysis for several issues. For most of the issues, appropriate administrative j
controls were implemented to address the issue, but TS amendment requests were
not submitted. In other instances, the administrative controls were not properly l
implemented and the facility may have operated outside of the LSSS setpoints.
l The most significant of the TS issues involved licensee evaluation of vendor design documentation in 1994 regarding the RPS trip and ESF actuation setpoints and allowable values contained in TS tables 2.2-1 and 3.3-4. The licensee determined the existing TS trip setpoints and allowable values for several design functions were inadequate. Preliminary MDAT reviews determined that appropriate procedure revisions (administrative controls) were implemented for the trip setpoints.
However, station processes broke down and the allowable actuation values, established to ensure the protective functions would actuate within the UFSAR design accident analysis assumptions, were not changed. Affected protective functions included:
Unit 1:
RPS( TS Table 2.2-1)
Overtemperature Delta Temperature Overpower Delta Temperature Reactor Coolant Pump (RCP) Undervoltage Auto Stop Oil Pressure Turbine Trip ESF (TS Table 3.3-4)
Containment Pressure - High High (Spray)
Containment Pressure - High High (Isolation B)
4kV Emergency Bus Undervoltage (Trip breaker)
Auxiliary Feedwater Start on RCP Undervoltage Unit 2:
RPS(TS Table 2.2-1)
Pressurizer Pressure - Low Pressurizer Pressure - High Loss of Reactor Coolant System Flow
. ESF (TS Table 3.3-4)
Containment Pressure - High (Safety injection and Feedwater Isolation)
Main Steamline (MSL) Pressure - Low (Safety injection and Feedwater Isolation)
Refueling Water Storage Tank Level - Extreme Low Containment Pressure - High High (Spray)
Containment Pressure - High High (Isolation B)
Containment Pressure - Intermediate High High (MSL lsolation)
Steamline Pressure - Low (MSL isolation)
Steamline Pressure Rate-High Negative (MSL lsolation)
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Preliminary MDAT findings identified about a dozen additional instances where the TS may not be sufficiently conservative to satisfy station design analysis. These issues involved EDG frequency, EDG fuel oil storage tank volume, EDG largest load, control rod insertion limit monitor, refueling water storage tank volume, main steam safety valve lift setpoints, PZR PORV lift setpoints, control room ventilation, auxiliary river water operability, -nd auxiliary feedwater pump availability. The MDAT determined that certain nistorical process, tracking, and accountability weaknesses existed and current process revisions were needed. Further, preparation and submittal of TS amendment requests typically received low priority relative to other station activities. The MDAT continued its work in three parallel parts:
- Perform operability assessments and resolve known issues through TS amendments.
- Assess and revise associated station processes.
- Identify extent of condition.
The MDAT effort involved over 50 licensee personnel and close involvement with various vendors and contractors. Based on initial observations, the inspectors noted good communication between members of the MDAT and timely designation of resources to address the expanding scope of activities. Historical assessment to determine whether either unit operated outside of the recalculated LSSS and associated event deportability remained under MDAT review at the close of the inspection period.
The inspectors observed that the MDAT was moving forward with implementing corrective actions, but had not yet performed an encompassing causal analysis for the observed discrepancies. The inspectors discussed this observation with the MDAT manager and questioned how the team could be certain that the appropriate corrective actions were identified and implemented without having done a complete causal analysis. This same question was discussed with the licensee during subsequent conference calls between the NRC Region I and NRR staffs and the -
licensee. The Senior Vice President - Nuclear Support Group responded that an encompassing causal assessment would be performed and corrective actions validated as applicable, prior to unit restart. In addition, the licensee initiated an
- additional independent review to evaluate organizational and human performance issues associated with the longstanding and repeated failures to submit TS amendment requests to the NRC. Both the MDAT and the independent issue review remained in progress at the close of the inspection period. Both units remained in
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cold shut cown pending licensee resolution of the pertinent issues.
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10 CFR 50, Appendix B, Criterion ill " Design Control," requires in part that measures be established to assure that applicable regulatory requirements and the design basis for safety related structures, systems, and components be correctly
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translated into specifications, drawings, procedures, and instructions.10 CFR 50, Appendix B, Criterion XVI " Corrective Action," requires in part that measures be established to assure that conditions adverse to quality are promptly identified and corrected.10 CFR 50.36(b) requires in part that TS be properly derived from the UFSAR accident analysis and amendments thereto.10 CFR 50.36(c)(1)(ii)(A)
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requires in part that the TS LSSS be chosen such that automatic protective action l
will correct the abnormal situation before a safety limit is exceeded.
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Actions to resolve the technicalissues described in this section, from approximately
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1990 to 1997, were inadequate in that station design was not properly maintained, conditions adverse to quality were not corrected, and TS were not properly maintained. The longstanding pattern of performance appeared to violate the above stated regulatory requirements. The safety and regulatory significance of these
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issues as well as the adequacy of current licensee actions to address them remained under NRC review at the close of this inspection period. Additional NRC inspection, as well as assessment of licensee investigations and corrective actions are necessary. (EE150-334(412)/98-03-05).
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c.
Conclusions
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In response to an NRC violation, the licensee identified over twenty additional (
instances where the station TS were not sufficient to ensure the station would l
operate within the existing UFSAR accident analysis. These discrepancies affected
.the reactor protection system, engineered safety features, and various safety related system requirements. Licensee actions from approximately 1990 to 1997 were l
inadequate, in that station design was not properly maintained, conditions adverse to quality were not corrected, and TS were not properly maintained.
l E1.2' Prioritization of Enoineerina and Maintenance Backloas (Units 1 and 2)
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i a.
Inspection Scooe (37551 and 62700)
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The inspectors examined backlogged items that would not be completed prior to l
scheduled plant restarts for the following programs: Design Change i
Packages / Requests (DCP/R), Engineering Memorandums (EM), Condition Reports
,
l (CR), Maintenance Work Requests (MWR), Temporary Modifications (TM), and
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Commitment Action Tracking System (CATS). Eighty-three DCP/Rs,86 ems,48
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l CATS item summaries,24 TMs, and over 200 CR and 100 MWR summary i
descriptions were examined. The licensee's current probabilistic risk analysis (PRA)
results were used to characterize the importance of the backlog items. In addition, i
engineering judgement was used to categorize each backlog item as having high, j
l medium, or low potential to change the reliability assumptions in the licensee's l
PRA.
b.
Observations and Findinas i
Four systems in Unit 1 and six systems and one initiating event in Unit 2 were identified as having a total of 57 risk significant engineering and maintenance backlog items at the time of this insp6ction (see Attachment A). To assess the licensee's prioritization of backlog items, the inspectors considered the age of these items as indicated below.
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Ace of Too Risk Significant Backloo items Unit 1
.I);1it 2 Total Total number of top risk items considered
35 57'
Number of items more than 2 years old* *
6
Number of items less than 2 years old * *
26 35*
- (2 items are common to both units)
- *(not including MWRs)
l The inspectors did not identify any Technical Specification or other regulatory requirement items for which resolution was inappropriately deferred. Nearly 80 percent of the 57 risk-significant backlog iteir s were less than two years old with about half of these scheduled for completion in 1998. Also, among the backlog items examined, the licensee had identified issues related to the adequacy of plant testing procedures to meet the intent of Technical Specification surveillance requirements, including those identified by a program to address NRC Generic Letter 96-01 " Testing of Safety Relate <1 Circuits." The licensee attributed identification of many of these issues to recent training on Technical Specifications given to most of its technical staff. Finally, two Condition Reports were noted which identified incomplete or inadequate prior corrective actions. These latter two findings suggest j
a questioning attitude on the part of the licensee's staff.
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As noted,13 risk-significant backlog items out of 57 (about 22 percent) are greater I
than two years old. A majority of the backlog items greater than two years old were DCP/Rs which had not been implemented. Ten of these are design changes, six of which have not yet been scheduled. For the remaining backlog items that j
were less than two years old, about 40 percent were scheduled for 1999 or l
beyond. The inspectors concluded that risk insights were not fully utilized for design change requests and pending design change packages. DLC management l
determined that additional reviews of the process may be warranted.
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c.
Conclusions The licensee's staff exhibited an appropriate questioning attitude resulting in the identification of many questions regarding irsterpretation of TS requirements and the
adequacy of plant precedures to meet them. Risk insights were generally integrated into the backlog prioritization process as evidenced by about 80 percent of the identified top risk significant backlog items being less than two years old. However, risk insights were not ful:y utilized for design change requests and pending design change packages. These items constituted the majority of the risk significant backlog items greater than two yedrs old.
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E2 Engineering Support of Facilities and Equipment E2.1 Review of Moce Hold Condition Reports a.
Insoection Scooe (37551)
The inspectors reviewed four of approximately 69 (as of April 23,1998) mode hold condition reports (CRs) to evaluate the effectiveness of licensee's actions in resolving and preventing problems. As applicable, the review examined resolution documentation which included cause analysis summaries, deportability determinations, technical evaluation reports, the UFSAR, controlled system drawings, equipment histories, revised procedures, r.od engineering memorandums.
The four CRs reviewed are discussed below, b.
Observations and Findinas Ooerabi!ity Requirements for Nuclear instrumentation System (NIS) Power Ranae Hiah Flux Low Setooint Reactor Trio does not Match the Accident Analysis (CR 980314)
The potential existed for erroneous NIS indications to reinstate the P-10 interlock which would de-energize the source range detectors while in the shutdown mode.
The licensee assessed that the TS operability requirements were not in conflict with the UFSAR Accident Ana!ysis. During the resolution of the CR, the licensee j
identified that if two power range NIS detectors were out of service during shutdown conditions, the potential existed for erroneous indications to reinstate the P-10 interlock which would de-energize the source range detectors. The immediate corrective actions revised procedures for closing reactor trip / bypass breakers to ensure that at least 3 power range detectors are operable below P-10 when the rod cluster control assembly banks ere capable of withdrawal. Further corrective actions included investigating the need for the P-10 block of the source range trip.
Thw inspectors concluded thct the licensee took appropriate action in resolving l
concerns regarding the operability requirements of the NIS power range setpoint and
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in identifying and resolving the additional P-10 concerns raised.
Potential Sinale Failure to Disable Safety Ir.iection (SI) System (CR 980329)
The potential existed to transfer the SI pumps to recirculation phase pricr to sufficient water was accumulated in the containment sump. The licensee determined the existing tap configuration was acceptable with respect to the single failure criterion based on NRC guidance that pipe failures are passive single failures and are not considered during the short term, injection phase, of an event. The inspectors verified that according to Standard Review Plan 3.6.1, Plant Design for Protection Against Postulated Piping Failures in Fluid Systems Outside f
Containment," passive failures, such as the tap failure, need not be postulated i
during the initial phase of an event. Therefore, the inspectors concluded that the licensee had adequately addressed the concern regarding the potential single failure of the RWST pipe taps.
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Hiah Leakaae Measured for 2CCP-290. Thermal Barrier Check Valve (CR 980686)
Due to the high leakage measured for 2CCP-290, the potential existed to have reactor coolant pass back through the component coolant system's low pressure piping following e tube leak in one of the thermal barrier coolers. The initial corrective action was to clean and reassemble the check valves. The final corrective action identified by system engineering was the replacement of these valves prior to Martup following 2R7 refueling outage. Other corrective actions, such as adding a side system filtration unit, were also being considered. The licensee acknowledged the commitment required to complete the engineering and procurement activities needed to support the replacement of these valves during the 2R7 refueling outage and had begun to expedite the procurement process. The inspectors concluded that the initial corrective actions u ken and final corrective actions planned were appropriate.
Hiah Back Leakaae Measured for Main Steam Sucolv (MSS) Check Valves to the Auxiliarv Feedwater Turbine (AFW) (CR 980727)
The potential existed to feed a steam line break from the supply steam lines, thus drawing steam away from the AFW Turbine and potentially causing the AFW turbine-driven pump to be inoperable. Based upon the history of the valves and the immediate availability of the replacement parts, the licensee replaced the six MSS check valves during the 1998 forced outage. The inspectors concluded that the licensee actions were appropriate.
c.
Conclusions Engineers and maintenance personnel took appropriate actions to address the concerns identified in four mode hold condition reports and to prevent recurrence.
Further, the licenseo adequately identified and cddressed related emergent issues'
which arose during resolution of the condition reports.
E8 Miscellaneous Engineering issues E8.1 (Closed) Unresolved item (URI) 50-334 and 50-412/97-08-03: Test Control - High Head Safety !njection Pumps.
a, inspection Scope (92903)
The inspectors cor ducted an onsite review of an unresolved item pertaining to preconditioning of the high head safety injection (HHSl) pumps prior to surveillance testing. The issue was originally identified in NRC Inspection Report 50-334 and 412/37-08.
l b.
Observations and Find!nas Based on review of the surveillance procedure and discussions with system engineers and operations management, the inspectors determined that HHSI pump
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suction lines eiere routinely vented prior to performing manual pump starts, including the periodic surveillance test. The procedures allowed venting the HHSI pump prior to starting the pump at the nuclear shift supervisor's discretion. Unit 1 and Unit 2 operators typically vented the HHSI pumps prior to performing the quarterly surveillance, safeguards protection system testing, and 18-month full flow testing. Venting prior to pump start was done to eliminate any gas in the
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system to enhance pump long-term reliability.
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l From 1988 to September 1997, the amount of gas vented and the effectiveness of
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the vent were not assessed. In addition, engineers failed to determine a maximum l
acceptable void fraction and the established maximum gas accumulation limit was
later determined to be inaccurate. Based on these three points, the operability of the pump was unknown and adverse conditions were eliminated and not assessed prior to conducting surveillance test. In January 1998, the NRC issued a SL lli Violation (EA 97-517) regarding failure to take adequate corrective actions to prevent gas binding of the HHSI. However, the issue of preconditioning of the HHSI pumps prior to surveillance testing was not addressed by that enforcement action.
With gas accumulation present, venting the suction lines immediately prior to i
performing the surveillance testing changed the as-found condition of the system fmm that which would normally be present if the system was automatically called upon to perform its safety function. Changing the as-found conditions prior to performing periodic surveillance tests without detecting and assessing adverse conditions (in this example the evaluation of the effects of the gas accumulation in the HHSl pump suction lines) interfered with the licensee's ability to properly assess the operability of the system. Therefore, the tests were invalid with respect to determining pump operability for conditions that were likely to exist wder automatic pump start demands.
10 CFR 50, Appendix B, Criterion XI, " Test Control," requires, in part, that "... the test is performed under suitabla environmental conditions." Suitable environmental conditions include conditions representative of the expected conditions when the equipment is required to perform its safety function. The normal practice of venting prior to surveillance testing without proper controls to evaluate the amount of gas vented and the effects of the gas on the system was a violation of 10 CFR 50, Appendix B, Criterion XI (VIO 50-334(412)98-03-06)
The inspectors determined that corrective actions associated with EA 97-517 addressed issues associated with this violation. The corrective actions included:
engineering evaluations and model testing to determine a maximum gas
accumulation limit for operability; additional surveillance procedure steps requiring ultrasonic testing (UT)
examinations of the suction piping prior to pumps starts and after pump shutdown; and engineering evalNtions of the UT data
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The system engineers also reviewed all system engineering procedures and verified that the procedures did not adversely affect the accuracy of the testing. The inspectors determined that the violation has been addressed and comprehensive corrective actions have been completed. This violation is closed.
c.
Conclusions The normal practice of venting the high head safety injection pumps prior to surveillance testing without the assurance that adverse conditions will be detected and corrected was a violation. Previous corrective actions to address this issue were comprehensive.
E8.2 (Closed) Unit 1 LERs Associated With Generic Letter 96-01 Review a.
Insoection Sem J92700. 90712)
in early 1998, DLC completed reviews in response to Generic Letter (GL) 96-01, Testing of Safety Related Logic Circuits, for Unit 1. LERs were submitted, as appropriate, for conditions that were prohibited by the plant's Technical Specifications. The inspectors conducted an in-office review of the LERs, and reviewed a sampling oi the conditions with DLC personnel, to understand the issues and the corrective actions taken. Various electrical prfnts and procedures were reviewed. Licensee reviews for Unit 2 are expected to be 0.ompleted by August 1998, with LF.Rs submitted as appropriate; NRC review for Unit 2 actions will be completed after all LERs are submitted.
b.
Observations and FNinas in response to GL 96-01, DLC performed detailed reviews of circuit testing, through the efforts of a team of engineering personnel. The team cor.centrated on Unit 1 first, and allidentified deficiencies were reviewed and corrected. Corrective actions included performing the appropriate testing, and revising the appropriate procedures to include the testing. In all cases no adverse conditions were identified. The deficiencies were reported to the NRC via LERs, as deviations from the plant's technical specifications.
The following LERs and supplements, associated with GL 96-01, were reviewed :
LERs 96-04-00,01,02,03, and 04 Generic Letter 96-01, Incorrect Testing of Safety-Related Logic Circuits LERs 97-01-00,01,02,93,04, and 05 Generic Letter 96-01 Inadequate Surveillance Testing of Safety Related Logic Circuits LER 97-31 Inadequate Testing of thef.ngineered Safety Feature Function, Loss of Power -
4.16 kV Bus, Loss of Voltage (Start Diesel)
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The inspectors reviewed the conditions for each LER and revision, and verified that the stated coirective actions adequately addressed each condition. A sampling of
. four conciitions 'Nas reviewed in more detail, by meeting with DLC personnel, and ret'iewing electrical prints and procedures to ensure that the identified deficiencies were adequateiy corrected. All corrective actions reviewed adequately addressed the identified conditions.
Failure to comply with technical specification surveillance requirements in several instances was a violation of NRC requirements. The NRC is exercising discretion in accordance with Section Vll B.3 of the Enforcement Policy and is not issuing a Notice of Violation for these Severity Level IV violations involving inadequate
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surveillance testing. Discretion is warranted because: (1) the inadequacies were
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self-identified as a result of an initiative in response to generic Letter 96-01,(2)
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corrective actions were timely and effective, (3) the testing deficiencies were not likely to be identified by routine efforts, and (4) the actions that caused the testing j
deficiencies were dated and not reflective of current performance. (NCV 50-
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334/98-03-07)
c.
Conclusions The licensee conducted a comprehensive review of testing of safety related logic circuits for Unit 1, in response to Generic Letter 96-01. Identified deficiencies were tested successfully, procedures were revised to include the testing, and the conditions were properly reported.
E8.3 (Closed) LER 50-334/97-18: Potential for Spurious Seismically Induced Fire Protecti v System Activation Affecting Emergency Diesel Generators.
This issue was documented in NRC Integrated inspection Report 50-334 and 412/97-05, Section E1.3, and resulted in Non-Cited Violation 50-334/97-05-08.
Therefore, the inspectors performed an in-office review of the LER. No new issues were revealed.
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E8.4 (Closed) LER 50-334/97-20: Unqualified Component in Safety Related Ventilation Circuits Affects the Emergency Diesel Generators' Design Basis.
This issue was documented in NRC Integrated Inspection Report 50-334 and 412/97-06, Section E1.2, and resulted in Non-Cited Violation 50-334/97-06-01.
Tlierefore, the inspectors performed an in-office review of the LER. No new issues were revealed.
E8.5 (Closed) LER 50-334/97-21.50-334/97-21-01: Potential for Seismic Event to Result in Both Trains of Supplementary Leak Collection and Release System to Become Inoperable.
This issue was documented in NRC integrated inspection Report 50-334 and 412/97-06, Sections E1.2, and resulted in Nor.-Cited Violation 50 334/97-06-01.
This LER was discussed in NRC Integrated Inspection Report 50-334 and 412/97-
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06, Section E8.3. Therefore, the inspectors performed an in-office review of the LER. No new issuas were revoated.
E8.6 (Closed) LER 50-334/97-09-01: Main Steam isolation Bypass Valves Do Not Meet Technical Specification Engineered Safety Feature Rc.ponse Time Requirements.
The inspectors conducted an in-office review of this LER revision. The issue was originally documented in NRC Inspection Report 50-334 and 412/97-06,& Won E1.1. The original LER was reviewed and closed out in NRC Inspection Rg a 50-334 and 412/97-06, Section E8.4. The revision provided minor updated t.orrt,ctive action information and did not change the previous inspection assessments.
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IV. Plant Support R1 Radiological Protection and Chemistry (RP&C) Controls l
a.
Insoection Scoce (83750)
The inspectors reviewed the licensee's programs for: (1) the calibration and repair of hand-held radiological survey instrumentation, portal monitors and electronic dosimeters; (2) inventory and leak testing (where applicable) of radiological sources; and, (3) review of certain radiological work, in the area of instrument calibration and repair, the inspectors examined records for:
(1) the calibration and repair of portable field radiological survey instrumentation; (2) calibration and repair of portal monitoring instrumentation; (3) calibration and repair of electronic dosimeters; (4) traceability of calibration standards; and (5) calibration and repair of air analysic field instrumentation. The inspection was conducted via direct observation of calibration facilities, review of records and procedures, and interviews with cognizant plant psaonnel.
In the area cf source inventory and leak testing, the inspectors reviewed the licensee's data bases of radioactive sources and randomly verified a sample population of sources to verify storage location, physical description, marking and labeling of sources. The inspectors also verified that the licensee was conducting leak testing of certain sources, as specified in plant Technical Specification 3/4.7.9.
In the area of radiological work, the inspectors conducted direct inspection of radiological work being performed in the Unit 1 containment. This aspect of inspection also included a review of work controls, including briefings, radiation work permit, health physics control of work activities and maintaining occupational exposures for this work as low as reasonably achievable (ALARA).
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b.
Observations and Findinas Calibration of Radiological Survev instruments The licensee maintains an inventory of radiological portable field survey instrumentation for use by health physics personnel. Instruments are radiologically calibrated by dedicated health physics personnel, while electronic calibration (as needed) and instrument repairs are conducted by the instrument and Calibration (l&C) Department. Based on a review of the inventory of instruments in the licensee's possession, the inspectors concluded that sufficient instrumentation existed for the licensee to perform adequate surveys of plant areas, equipment and workers.
Radiologhal calibration of survey instruments is conducte.: on a semi-annual basis utilizing a variety of calibration sources and standards maintained by the licensee.
The principle radiological calibration standards in use are a pair of cesium-137 irradiators wheh are maintained by the licensee as tertiary standards to the National institute of Star dards and Technology (NIST) through the use of a transfer standard which is calibratt.d annually by a vendor, in accordance with plant procedure (RIP 1.7, Revision 2, Precision Electrometer - Model 500). Appropriate documentation for verifying traceability and for the development of calibration curves was maintained by the licensee in accordance with plant procedure (RIP 1.9, Revision 2, Model 89-400, Gamma Calibration System). Other calibration standards utilized had associated with them appropriate source calibration certificates.
Field instrumentation was source checked for appropriate response on a daily basis, in accordance with plant procedure (RIP 1.10, Revision 1, Response Check Range Determination). Portal monitors were source checked on a week;y basis, while survey instruments utilized for transportation work were checked coth prior to use and upon return. The inspectors independently verified a random sampling of instruments in use as having documentation to support their calibration within the past six months and their daily source check. Air sampling equipment was calibrated by I&C, while air samples were analyzed utilizing small field-type counting instrumentation or gamma spectroscopy systems maintained by the Chemistry Department.
Electronic dosimeters utilized for personnel dosimetry (but not dose of record) are calibrated on a semi-annual basis using a panoramic air irradiator maintained by the licensee as a quaternary standard to NIST Extensive licensee documentation exists on the development of celebration correction factors for each of the 30 available calibration rders in this device, which are updated on an annual basis. The inspectors reviewed the most recent traceability test data for this irradiator, and a randomly selected sample of calibration results for t" electronic dosimeters and determined that the licensee's program was in accordance with applicable licensee
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l proccoures and industry standards.
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Source Accountabii;tv and Leak Testina l
The licensee's program for control of radioactive sources includes all sources
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purchased from vendors and the subdividing of purchased sources (typically in the chemistry laboratory) as described in plant procedures (RP 1.1, Revision 3,
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Radioactive Source Accountability; and, RP 1.6, Revision 3, Accountability -
l Subdivision of Radioactive Standards). The inspectors reviewed both paper and
computer-based records associated with this program, and also selected, at random,
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a number of sources and conducted independent field verification of source I
location, storage configuration, posting and marking of sources and source storage locations, in accordance with 10 CFR 20.1801.
The inspectors reviewed the leak test data from the testing conducted in April 1998,in accordance with plant procedure (RP 1.3, Revision 3, Source Leak Testing
and Inventory). Although not required, the licensee conducts semi-annualleak i
testing of all sources, to the sensitivity required under plant Technical Specification
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3/4.7.9. Source inventory is conducted by the licensee on a quarterly basis.
Conduct of Radiological Work The inspectors reviewed work being performed in the Unit 1 containment on May 7, 1998. Principally, work was being performed in and around the pressurizer cubicle j
on the th'ee pressurizer PORVs. The inspectors reviewed the radiation work j
permits being utilized to provide radio!ogical control of the work, and confirmed that i
the worke;s were appropriately dressed out for work in a posted contaminated area, I
were wearing the required personnel monitoring devices, and were aware of the
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radiological conditions in their work area. The inspectors also observed a health l
physics technician providing periodic direct job coverage for this task.
Additionally, the inspectors toured accessible areas of the containment and verified I
that applicable postings and administrative controls were in place at identified high and locked high radiation areas. The inspectors also noted that the iicensee had identified discrete areas on each level of the containment as ALARA areas (Iow dose
waiting areas), and posted these with both signs and flashing lights.
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A review of licensee exposure data through April 1998 indicated that the licensee i
has accumulated approximately 18 person-rem. This was above licensec
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projections for year-to-date exposure; however licensee projections did not l
anticipate extended unplanned shutdowns at both units.
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Conclusions
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The licensee established and implemented effective radiological protection programs l
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Radiological controls in the containment were ef fectively established, implemented,
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and maintained; and radiological work involving the Unit 1 PORV was effectively
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monitored and controlled.
R5 Staff Training and Qualification in RP&C a.
Insoection Scone (83750)
The inspectors reviewed the licensee's continuing training program for radiological technicians, including a review of selected training documents and lesson plans.
The inspectors also interviewed cognizant health physics and training personnel, b.
Observations and Findinas The licensee has developed a training program for radiological technicians which incorporates both initial and continuing training. The training program is based upon the identification of pertinent technical tasks and the subsequent development of lesson plans, on-the-i'b training and review of associated plant procedures. The licensee has established a health physics technician training committee, chaired by the Radiation Protection Manager (RPM), which includes representatives from both the Health Physics and Technical Training Departments. This committee identifies training to be given during the continuing training cycle, and approves and reviews training modules and their presentation.
During the past ten years, no new radiological technicians have been hired by the licensee, so the initial training program has not been utilized in that time. The inspectors reviewed certain documents related to the program, however, and determined that they were adequately maintained.
Continuing training is provided several times each calendar year. For 1998, three training cycles have been identified. The first cycle was completed at the time of the specialist insper tors review, and the second cycle was scheduled to begin in mid-May. The inspectors reviewed the lesson plans and training objectives for this upcoming two-day cycle of training, and determined them to be appropriate with regards to subject scope and depth of presentation.
c.
_ Conclusions The licensee has established en cffective initial and continuing training program for radiation protection technicians.
R8 Miscellaneous RP&C lssues (83750)
R8.1 Procedure Evaluations i
The inspectors examined the licensee's efforts to review health physics procedures for potential conflicts with plant TS. This is a portion cf a larger plant-wide ef fort to review all plant procedures for potential TS conflicts. Within the health physics
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effort, four senior departmental members were provided specific training in procedure evaluation and then conducted a screening of the approximately 500 procedures contained in the Health Physics Manual. The results of this effort identified four procedures with potential conflicts. Short-term corrective actions for the four identified procedural deficiencies were made utilizing the Health Physics Manual Change Number process. Change numbers 98-07 through 98-10 addressed the four procedural deficiencies identified. The inspectors reviewed the licensee's efforts and the changes made to the four procedures, and determined the results to be acceptable.
R8.2 Updated Final Safety Analvsis Report While performing the health physics inspections discussed in this rer, ort, the inspectors reviewed the applicable portions of the Updated Final Safety Analysis Report (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 as contained in: (1) Unit 1 UFSAR, Section 11.4.1.2 (Byproduct Material); (2) Unit 1 UFSAR, Section 11.5.4.8 (Instrumentation); and, (3) Unit 2 UFSAR, Section 12.5.2.2.3 (Portable Equipment and instrumentation).
F1 Control of Fire Protection Activities F1.1 Fire Briaade Resoonse to a Reported Fire a.
Insoection Scone (71750. 71707)
The inspectors observed the fire brigade response to a reported fire on the south office and shops building (SOSB) roof.
b.
Observations and Findinas On May 4,1998, the Unit 1 assistant nuclear shift supervisor received a call from a j
maintenance supervisor of a fire on the SOSB roof. The fire brigade was activated and the SOSB was evacuated. Within a short time period, the fire brigade reached I
the roof and determined that there was not a fire. A fire watch was established and the roof was continuously manned for the next 30 minutes. It was later concluded
!
that the individual, who reported the fire, may have mistakenly identified the smoke coming from the auxiliary Soiler as an indication of a fire.
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The inspectors observed the quick response to the reported fire. Communication between the fire brigade, control room, and security was effective. The post-event briefing was critical and :imely, c.
Conclusions The fire brigade responded effectively to a reported fire within the protect.. area.
Subsequent investigation confirmed that no fire existed.
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V. Management Meetinos X1 Exit Meeting Summary The inspectors presented the inspection results to members of licensee management at the conclusion of the inspection on July 1,1998. The licensee acknowledged the findings l
presented.
The inspectors asked the licensee whether any materials examined during the inspection should be considered proprietary. No proprietary information was identified.
X2 Management Meeting Summary On May 19,1998, Mr. H. Miller, NRC Region i Administrator, and members of the NRC staff held a management meeting with Mr. J. Cross, President, Gerteration Group, and members of his staff to discuss the NRC's Systematic Assessment of Licensee
~
Performance (SALP) for the Beaver Valley Power Station (NRC SALP Report 50-334.end j
412/98-99)for the period September 29,1996, through March 21,1998. The meeting l
was open to the public.
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PARTIAL LIST OF PERSONS CONTACTED DLC i
J. Cross, President, Generation Group I
R. Brandt, Vice President, Nuclear Operations R. LeGrand, Vice President, Nuclear Operations / Plant Manager t
S. Jain, Vice President, Nuclear Services M. Pergar, Acting Manager, Quality Servit.es Unit i
B. Tuite, General Manager, Nuclear Operations l
R. Hansen, General Manager, Maintenance Programs Unit l
R. Vento, Manager, Health Physics D. Orndorf, Manager, Chemistry F. Curl, Manager, Nuclear Construction J. Matsko, Manager, Outage Manarment Department T. Lutkehaus, Manager, Main %ance Planning & Administration T. Cosgrove, Coordinator, Onsite Safety Committee J. Macdonald, Manager, Systen: & Performance Engineering K. Beatty, General Mana;,er, Nuclear Support Unit S. Hobbs, Director, Safety & Licensing W. Kline, Manager, Nuclear Engineering Department R. Brosi, Manager, Management Services O. Arredondo, Manager, Nuclear Procurement NRC D. Kern, SRI G. Dentel, RI F. Lyon, RI l
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INSPECTION PROCEDURES USED IP 37551:
Onsite Engineering IP 61700:
Surveillance Procedures and Records IP 61726:
Surveillance Observation IP 62700:
Maintenance implementation IP 62707:
Maintenance Observation IP 71707:
Plant Operations
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IP 71750:
Plant Support i
IP 83750:
Occupational Exposure IP 90712:
In-Office Review of Written Reports of Nonroutine Events at Power Reactor Facilities IP 92700:
Onsite Follow-up of Written Reports of Nonroutine Events at Power Reactor Facilities IP 92901:
Follow-up - Operations IP 92902:
Follow-up - Maintenance IP 92903:
Follow-up - Engineering I
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ITEMS OPENED, CLOSED AND DISCUSSED Opened 50-334(412)/98-03-01 VIO Failure to Adequately implement and Follow Procedures Caused by Human Performance Errors (Section 01.3)
50-334(412)/98-03-05 eel Failure to implement Adequate Administrative Controls and Submit TS Amendment Requests for Conditions Outside of Station Accident Analysis (Section E1.1)
Opened and Closed 50-334(412)/98-03-02 NCV ineffective Corrective Actions Lead to Repeat Quench Spray System Water Hammer Events (Section 04.2)
50-334/98-03-03 NCV Failure to Perform TS Required Shutdown Margin Determination (Section 08.2)
50-334/98-03-04 NCV Failure to Maintain High Energy Line Break Equipment Qualification in Accordance with the Design Basis (Section M8.1)
50-334(412)/98-03-06 VIO Inadequate Test Control-High Head Safety in%: tion Pumps (Section E8.1)
50-334/98-03-07 NCV ' L 96-01 issues, Inadeqtcte Technical
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(also EA 98-359)
Specification Testing (Section E8.2)
Closed 50-334/EA 96-462 VIO Unit i Pressurizer Power Operated Relief Valve Block Valve Configuration Contrary to UFSAR (Section 08.5)
50-334(412)/96-10-04 VIO Failure to Properly Certify Vendor for Safety Related Work in Accordance with Qualified Suppliers List (Section M8.2)
50-334 and 50-412/97-08-03 URI Test Control - High Head Safety injection Pumps
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(Section E8.1)
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50-334/96-04:
LER Inconect Testing of Safety-Related Logic Circuits
. 50-334/96-04-01; (Section E8.2)
50-334/96-04-02; 50-334/96-04-03;and 50-334/96-04-04 50-334/97-01; LER Generic Letter 96-01 -Inadequata Surveillance 50-334/0'-01-01; Testing of Safety Related Logic Circuits (Section 50-334/97-01-02; E8.2)
50-334/97-01-03; 50-334/97-01-04;and 50-334/97-01-05 50-412/97-03 and LER Technical Specification 3.0.3 Entry Due to 50-412/97-03-01 Inoperability of 80th Trains of the Supplemental leak Collection and Release System (Section 08.4)
50-334/97-08-01 LER Missed Technical Specification Surveillance -
Monthly Position Check of Valves in the Boron injection Flowpath. (Section M8.4)
50-334/97-09-01 LER Main Steam isolation Bypass Valves Do Not
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Meet Technical Specification Engineered Safety R
Feature Response Time Requirements. (Section E8.6)
50-334/97-12-01 and LER TS 3.0.3 Entry Due to Two Analog Rod Position 50-334/97-12-02 indicator (ARPI) Channels inoperable (Section 08.2)
50-334/97-15 LER Proceduralized Voluntary Entry into T.S. 3.0.3 by Allowing Bypass of Both Source Range Channels Input to High Flux Trip. (Section 08.6)
50-334/97-16 LER Unit 1 Shutdown Required by T.S. 3.0.3 Due to inoperable Steam Generator Low-Low Level Reactor Protection System Trip. (Section 08.7)
50-334/97-17 LER Engineered Safety Feature Actuation of the P-12 Interlock Due to Decreasing Reactor Water
!.
Temperature. (Section M8.3)
50-334/97-18 LER Potential for Spurious Seismically induced Fire Protection System Activation Affecting Emergency Diesel Generators. (Section E8.3)
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50-334/97-20 LER Unqualified Component in Safety Related Ventilation Circuits Affects the Emergency Diesel Generators' Design Basis. (Section E8.4)
50 334/97-21 and LER Potential for Seismic Event to Result in Both i
50-334/97-21-01 Trains of Supplementary Leak Collection and Rel?ase System to Become Inoperaole. (Section E8.5)
50-334/97-22 LER Engineered Safety Feature Actuation of the P-12 Interlock Due to Decreasing Water Temperature.
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(Section 08.8)
50-334/97-23 LER TS 3.0.3 Entry Due to Two Analog Rod Position Indicator (ARPI) Channels inoperable (Section 08.3)
50-334/97-31 LER Inadequate Testing of the Engineered Safety
!
Feature Function, Loss of Power - 4.16 kV Bus, i
Loss of Voltage (Start Diesel) (Section E8.2)
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50-334/98-12 LER Replacement Capacitors Purchased from Fluid i
h 2mponents, Inc. (Section M8.1)
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LIST OF ACRONYMS USED
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AFW Auxiliary Feedwater ALARA As Low as Reasonably Achievable ANSS Assistant Huclear Shift Supervisor ARPl Analog Rod Position Indicator AS Auxiliary Steam ASME American Society Mechanical Engineers BVPS Beaver Valley Power Station CATS Commitment Action Tracking System CR Condition Report DCP/R Design Change Package / Requests
DCP Design Change Package DLC Duquesne Light Company EA Enforcement Action i
EDG Emergency Diesel Generator
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EM Engineering Memorandum
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ESF Engineered Safety Feature ESFAS
- Engineered Safety Feature Actuation System FCI Fluid Components, Inc.
FIN Fix-It-Now GL Generic Letter GMNO General Manager of Nuclear Operations HELB High Energy Line Break i
HHSI High Head Safety Injection I&C Instrumentation & Control IPTE Infrequently Performed Test or Evolution j
IST inservice Test
LER Licensee Event Report LHSI Low Head Safety injection LRM Licensing Requirements Manual i
LSSS Limiting Safety System Setting MDAT Multi-Discipline Analysis Team MSL Main Steamline MSS Main Steam Supply MWR Maintenance Work Request NCV Noncited Violation NIS Nuclear Instrumentation System NIST National Institute of Standards and Technology NPDAP Nuclear Power Division Administrative Procedure NRC Nuclecr Regulatory Commission NSA Normal System Alignrnent NSRB Nuclear Safety Review Board NSS Nuclear Shift Supervisor ORC Offsite Review Committec OST Operational Surveillance Test PDR Public Document Room PORV Power Operated Relief Valves
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PR Problem Report PRA Probabilistic Risk Assessment PZR Pressurizer QS Quench Spray QSP Quality Services Procedure QSU Quality Services Unit RCP Reactor Coolant Pump RCS Reactor Coolant System RFO Refueling Outage RHR Residual Heat Removal RP&C Radiological Protection and Chemistry RPM Radiation Protection Manager RPRW Reactor Plant River Water RPS Reactor Protection System RTS Reactor Trip System RWST Refueling Water Storage Tank SALP Systematic Assessment of Licensee Performance SGB Steam Generator Blowdown SI Safety injection SOSB South Office and Shops Building SPED System and Performance Engineering Department
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STA Shift Technical Advisor TM Temporary Modification TS Technical Specification TSSR.
Technical Specification Surveillance Requirement UFSAR Updated Final Saf.ny Arialysis Report URI Unresolved item UT U trasonic Test VfD Violation l
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