IR 05000334/1996009
| ML20138H779 | |
| Person / Time | |
|---|---|
| Site: | Beaver Valley |
| Issue date: | 01/02/1997 |
| From: | NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I) |
| To: | |
| Shared Package | |
| ML20138H762 | List: |
| References | |
| 50-334-96-09, 50-334-96-9, 50-412-96-09, 50-412-96-9, NUDOCS 9701060230 | |
| Download: ML20138H779 (39) | |
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i U. S. NUCLEAR REGULATORY COMMISSION !
REGION I i
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Report No /96-09, 50-412/96-09 Docket No , 50-412
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Licensee: Duquesne Light Company (DLC)
Post Office Box 4 i Shippingport, PA 15077 ,
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Facility: Beaver Valley Power Station, Units 1 and 2 i
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i l Inspection Period: November 17,1996 through December 21,1996
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inspectors: D. Kern, Senior Resident inspector F. Lyon, Resident inspector G. Dentel, Resident inspector '
( G. Hornseth, Materials Engineer, NRR i D. Brinkman, Project Manager, NRR !
Approved by: P. Eselgroth, Chief Projects Branch 7 i
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9701060230 970102 I PDR ADOCK 05000314 l G PDR I .
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l EXECUTIVE SUMMARY Beaver Valley Power Station, Units 1 & 2
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NRC Inspection Report 50-334/96-09 & 50-412/96-09
This integrated inspection included aspects of licensee operations, engineering, maintenance, and plant support. The report covers a 5-week period of resident inspectio l l Ooerations
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4 * Unit 2 operators demonstrated good command and control of startup evolutions on December 3. The prebrief was thorough and effective and the startup was conducted aafely. Reactor engineering personnel provided effective support (Section 01.2).
- Operators properly identified and quantified reactor coolant leakage from the head vent system (HVS) on November 29. The management decision to delay reactor startup pending further HVS operability assessment was appropriato. However, the i decision to startup the reactor on December 3 was premature because the leak )
integrity of certain valves was unknown. Subsequent leak rate test results provided assurance that various HVS valves were tight and that the RCS pressure boundary had not shifted to the downstream valves. The inspectors concluded that the test was well written and implemented. Plant cooldown and full assessment of a HVS valve position anomaly was important in identifying an adverse, safety significant condition which would have otherwise remained unknown. If not identified and corrected, the improper leak injection repair on 2RCS-624 could have caused the HVS to be inoperable the entire operating cycle (Section 01.3).
- Operators dernonstrated a good questioning attitude when performing a control room ventilation isolation system functional test. Engineers provided good support in resolving the operator's questions (Section 04.1).
- The Offsite Review Committee meetings were conducted in accordance with TS. A broad-based questioning attitude was displayed by the independent committee members. ORC subcommittee composition and processes were being reviewed for potential changes to improve effectiveness (Section 08.1).
Maintenance
- Operators identified three examples of poor painting practices during emergency diesel generator (EDG) refurbishment that had the potential to affect EDG operability. As a result of the painting control issues, the Plant Manager issued a temporary stop work order for all painting. There were no adverse safety consequences as a result of the poor painting on the EDGs. However, this represented a weakness in the licensee's control of contractor work. The inspectors assessed that actions taken to address the issue of painting control were j adequate. Operator identification of the p6cting discrepancies demonstrated j ii l
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l Executive Summary (cont.)
i excellent attention to detail during operator periodic tours of the EDG rooms (Section M1.1).
- Several programmatic controls and performance weaknesses on the part of engineering, maintenance, and QA personnel directly resulted in unintended migration of leak sealant material to portions of the HVS and adverse effects on the operation of two HVS valves. This poor control of a leak sealant injection repair l was safety significant. NRC safety concerns related to HVS integrity were addressed by conducting supplemental HVS leak testing, during which a valve position indication problem was investigated. Had the licensee not pursued this indication problem, the operability of the HVS would have been questionable for the entire operating cycle, a condition which would have remained unknown to the operating staff. Immediate corrective actions were appropriate (Section M1.2).
5 HVS piping and valve replacements were properly performed with appropriate planning and oversight (Section M1.3).
- Both units have a history of control room annunciator failures and although some corrective actions are in place, no formal preventive maintenance program currently exists to address the problem. Repeated control room annunciator failures were a l distraction to operators. Current initiatives to address the problem are considered appropriate, but have not been fully implemented. Failure to fully address continued annunciator failures was a weakness (Section M2.1).
Enoineerino
- Maintenance personnel demonstrated excellent awareness of plant design when they identified that the proposed heavy load lift path in the intake structure required a safety evaluation. In addition, engineers identified that several safety related i heavy load lift paths contained within station procedures differed from those i specified in the UFSAR. Corrective actions to determine the scope of the problem )
and update the UFSAR were appropriate. These discoveries indicated a good '
questioning attitude regarding maintaining plant design. However, compensatory measures to prevent using three proceduralized lift paths for which safety
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evaluations could not be found, were not implemented until questioned by the ;
inspectors. This item remains unresolved pending determination of whether the l three indeterminate lift paths have been used and whether they wera properly evaluated (Section E1.1).
- System engineers had a strong technical understanding of the 1 A steam generator i isolation valve's design and safety function. The assessment of likely causal factors l for inconsistent opening operation was good. Recommended actions including placing this valve on the forced outage work list were appropriate (Section E2.1).
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- Sefety analysis performed to support two recently submitted licensee amendment i requests were incomplete (Section E8.2).
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Executive Summary (cont.)
l * Engineers specified an incorrect temperature for application of leak sealant to a l portion of the reactor vessel HVS, which resulted in using an inappropriate material that degraded HVS operability (Section M1.2).
l Plant Suocort
- On December 21, operations personnel observed a power supply breaker in the Unit ,
1 cooling tower pump house out of its correct position. Security promptly initiated l l procedures for potential tampering. The component did not have safety significance I
and was not a likely tampering target. Security and operations personnel conducted '
an indepth assessment of this event. The inspectors concluded that the licensee has a low threshold concerning potential tampering events and that their response was thorough (Section S1.1).
Safety Assessment and Quality Verifice .on l
! * An unresolved item was identified regarding proper verification of vendor qualifications from the Quality Services List. Station procedures may not clearly specify a method to ensure recent changes to the approved QSL list are reviewed l before using vendor services, including those for which current blanket purchase orders are already approved. The vendor used for the HVS leak repair may not have been properly certified (Section M1.2).
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TABLE OF CONTENTS E X EC UTI VE S U M M A RY . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ii TA B L E O F C O NT E NTS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . v 1. Operations ................ ................................... 1 01 Conduct of Operations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1
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01.1 General Comments (71707) . . . . . . . . . . . . . . . . . . . . . . . . . . . 1 01.2 Unit 2 Reactor Startup . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1 01.3 Unit 2 Reactor Vessel Head Vent System (HVS) Leakage ...... 2 O2 Operational Status of Facilities and Equipment . . . . . . . . . . . . . . . . . . . 5 O2.1 Engineered Safety Feature System Walkdowns (71707) . . . . . . . 5 04 Operator Knowledge and Performance . . . . . . . . . . . . . . . . . . . . . . . . . 5 04.1 Control Room Emergency Breathing Air Pressurization System (CREBAPS) Timer (71707) ..................... ...... 5 08 Miscellaneous Operations issues . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6 08.1 Offsite Review Committee Meeting . . . . . . . . . . . . . . . . . . . . . . 6 11. M a i nt e n a n c e . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7 M1 Conduct of Maintenance .................................. 7 M1.1 Control of Painting on Emergency Diesel Generators (EDGs) .... 7 M1.2 Inadequate Unit 2 Reactor Vessel Head Vent System (HVS)
Repair........................................... 8 M1.3 Replacement of Unit 2 HVS Piping and Valves . . . . . . . . . . . . . 13 M 1.4 Routine Surveillance Observations (61726) ............... 14 M2 Maintenance and Material Condition cf Facilities and Equipment ..... 14 M 2.1 Annu nciator Alarm s . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 14 Ill . Eng ine e rin g . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 16 El Conduct of Engineering .................................. 16 E1.1 Heavy Load Lifts Near Safety Related Equipment in the Intake Structure ....................................... 16 ,
E2 Engineering Support of Facilities and Equipment . . . . . . . . . . . . . . . . . 17 '
E2.1 Unit 1 Steam Generator (SG) Blowdown isolation Valve Operation....................................... 17 E8 Miscellaneous Engineering issues . . . . . . . . . . . . . . . . . . . . . . . . . . . 18 E (Closed) Unresolved item 50-334/94-26-01; 50-412/94-27-01 (92903) ........................................ 18 E8.2 Engineering Basis for Recent Operating License Amendment Requests (37551) ................................. 19 j I V . Pl a n t S u p p o rt . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 19 l
P8 Miscellanenus EP Issue .................................. 19 '
P8.1 Licensee On-Shift Dose Assessment Capabilities - NRC Tl 2515/134 (71750) ................................ 19 S1 Conduct of Security and Safeguards Activities . . . . . . . . . . . . . . . . . . 19 v
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S1.1 Potential Tampering Review; Coolant Tower Pump Supply I Breaker (71750) .................................. 19 i L1 Review of UFSAR Commitments . . . . . . . . . . . . . . . . . . . . . . . . . . . . 20 ,
V. Man agement Meetings . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 20 l X1 Exit Meeting Summ ary . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 20 l
X2 SALP Management Meeting . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 20 ;
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REPORT DETAILS
! Summarv of Plant Status
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Unit 1 operated at full power for the entire inspection period.
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l i Unit 2 began this irispection period in Mode 6 (refueling) conducting repairs on the residual l heat removal system. On November 20 the reactor was fueled and the unit entsred Mode j 5 (cold shutdown). Reactor coolant system heatup to Mode 3 (hot standby) we.s
! completed on November 27. During the Mode 3 containment walkdown, operators
- discovered a small leak on a reactor vessel head vent system (HVS) flange. On December
{ 2, a temporary leak sealant repair was performed to stop the leak. On December 3, Mode j 2 (startup) testing was in progress when DLC decided to return to Mode 3 to perform j additional HVS leak tests to verify system integrity (Section 01.3). The unit was i subsequently returned to Mode 5 to complete permanent repairs to the HVS (Section M1.2}. Following reoairs, reactor startup was performed and the unit was synchronized to ,
the grid on Decembs,r 16, the official end of a 108 day refueling outage. The unit was at i 67% reactor power at the end of the inspection period.
i I r I. Operations 01 Conduct of Operations 01.1 General Comments (71707)'
Using Inspection Procedure 71707, the inspectors conducted frequent reviews of l ongoing plant operations. In general, the conduct of operations was professional and safety-conscious; specific events and noteworthy observations are detailed in the sections belo :
.01.2 Unit 2 Reactor Startuo Inspection Scone (71707)
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The inspectors observed startup activities in the Unit 2 control room on j December 3,1996. The startup was terminated after reaching criticality and during physics testing due to licensee management's decision to perform additional testing on the reactor head vent valves. The inspectors observed very good communications between operations and reactor engineering staff and proper procedural adherence. The procedures reviewed included:
o 2 OM-50.4.D, " Reactor Startup from Mode 3 to Mode 2," Rev. 23 e 2 RST-2.1, " initial Approach to Criticality After Refueling," Rev. 2 e 1/2 NPDAP 8.23, " Infrequently Perfo.t ied Tests and Evolutions," Rev. 2
' Topical headings such a 01, M8, etc., are used in accordance with the NRC standardized reactor inspection report outline. Individual reports are not expected to address all outline topic ._, _ ,,- _ __ - _ - _ _ . - - _
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) Obser.ations and Findinas On December 3,1996, DLC conducted a reactor startup on Unit 2. The prebrief
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conducted by the General Manager of Operations covercd the precautions and limitations, industry and in-house lessons learned, conditions expected and actions in response to exceeding limiting parameters, and command and control (
- responsibilities. During the actual startup evolution, distractions to the reactor i
operators were effectively kept to a minimum. Reactor engineering support and communications to the operating staff were very good. Independent checks of reactor engineering by the shift technical advisor demonstrated sound work practices.
. Conclusions
The inspectors noted good command and control of the startup evolution by l operations staff. The prebrief was thorough and effective. Reactor engineering l I
personnel provided effective support. The inspectors concluded that overall startur activities were conducted safely.
01.3 Unit 2 Reactor Vessel Head Vent System (HVS) Leakaae
- Inspection Scoce (71707. 92901)
On November 29, operators identified a smallleak from the HVS during a mode 3 containment walkdown in preparation for reactor startup. The leak raised questions concerning HVS operability which required resolution prior to reactor startup. The l inspectors conducted interviews, observed testing, and participated in conference calls between NRC Region I, NRC NRR, and the licensee to assess the licensee resoluthI of HVS operabilit Findinas and Observations i Leak identification
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Operators identified a 15 drop per rninute (dpm) leak from a blind flange downstream of a normally shut one inch isolation valve, 2RCS-624, in a dead-leg portion of the HVS. Valve 2RCS-624 is not required to be repositioned for HVS system operation. After consultation with the valve vendor, the closure torque on 2RCS-624 was increased from 55 foot-pounds to 65 foot-pounds. Leakage at the downstream flange decreased to 6 dpm which was less than the TS permitted value for identified reactor coolant system (RCS) leakage. However, the continued leakage indicated that leakage existed past three normally shut HVS valtes ,n series (2RCS-SOV-200A(B), 2RCS-SOV-201 A(B), and 2RCS-624). Station management directed that a temporary leak injection repair be performed to 2RCS-624 to eliminate the identified leakage prior to reactor startup, in addition, the plant manger informed the inspectors that further evaluation was necessary to determine !
whether the existing leakage made the HVS inoperabl )
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Decision to Perform Temocrarv Leak Repair on 2RCS-624 The inspectors reviewed TM 2-96-23 and a completed / approved 50.59 safety evaluation in the control room which were developed for the leak seal repair. The repair was intended to inject leak sealant materialinto the valve body cavity on the upstream side of the valve disk to stop any leakage past the closed valve seat. The 50.59 concluded that the repair did not create an unreviewed safety question, and stated that the sealant does not take the place of the RCS pressure boundary, but vts as a gasket on the valve disk. 2RCS-624 was not considered an RCS pressure boundary since the upstream HVS valves (2RCS-SOV-200A(B) and 2RCS-SOV-201 A(B)) are normally shut and serve as the boundary. The specified drill and tap injection location was through the valve body into the valve cavity upstream of the valve disk. The inspectors noted that this was not a confined space and no weakening of the valve bonnet or botting would be involved. Sealant injection volume was discussed in the safety evaluation and was to be controlled using appropriate maintenance procedures. The inspectors determined that TM 2096-23 and the supporting safety evaluation provided adequate review to conclude that an USQ did not exist.
Concerns for HVS Operability and System Intearity The injection repair was completed on December 2 and the leakage from the blind flange was stopped. Station management determined that based on satisfactory Type B leak test results on HVS valves the previous month and stopping the leakage from the blind flange, the HVS now satisfied operability requirements as described in TS 3.4.12. Reactor startup was initiated at 8:46 am on December 3.
Later that day conference calls were conducted between the NRC and the licensee to discuss NRC safety concerns regarding HVS integrity. Three issues were identified; (1) The leak tightness of 2RCS-SOV-200A(B) and 2RCS-SOV-201 A(B) is unknown which may have shifted the RCS pressure boundary to downstream valves. (2) Would the temporary leak repair to 2RCS-624 perform adequately for the entire operating cycle if the RCS pressure boundary has now shifted to the
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2RCS-624 valve? (3) Thermal fatigue issues regarding the HVS elbow tap from the reactor vessel and down steam piping have arisen, but have not been completely resolved. The licensee provided substantial information to address the third issue for the duration of this operating cycle, but the first two concerns were not fully addressed.
Station management directed that the reactor be promptly shutdown and additional leak testing on the HVS be performed. Due to the existing control rod configuration for low power physics testing, the shift supervisor directed that the reactor be manually tripped. The inspectors determined that the decision to manually trip the reactor rather than to delay shutdown several hours to restore a normal control rod configuration was conservative and appropriate. A 10 CFR 50.72 notification was properly completed to report the manual reactor tri .
HVS Valve Leak Rate Testina Engineers developed 2 TOP-96-11, "RCS Head Vent SOV Leak Test", revision 0, to perform more detailed leak testing on the HVS than is required by routine Type B test programs. The inspectors discussed development of the test procedure with engineers and monitored procedure approval by the Nuclear Safety Review Boar Appropriate safety precautions and initial conditions were established in the procedure. The control room briefing for the test was clear and a pre-evolution walkthrough was performed. No increase in pressure relief tank level was observed during the test which resulted in the conservative determination that leakage was 10.08 gallons per minute per valve. The test results indicated that upstream HVS valves maintained appropriate leak tightness. The inspectors concluded that the test was well written and implemented. In addition, the test results provided assurance that the 2RCS-SOV-200A(B) and 2RCS-SOV-201 A(B) valves were tight and that the RCS pressure boundary had not shifted to the downstream valve Based on the leak test results and additional information presented on the thermal fatigue issue, the NRC had no further safety concerns which would preclude Unit 2 startu i Downstream Valves Fouted with Leak Seal Materia] l Late on December 4, operators observed that 2RCS-HCV-250A failed to indicate fully closed at the end of the test. The valve indicated 22% open which corresponded to about 0.05 inches open. Licensee investigation included vendor consultation, additional leak tests, and repeated operation of the valve. Technicians determined that the valve position indication was most likely correct, and that the I
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valve would not fully close for some unknown reason. On December 6, station ,
management directed that the plant be cooled down to mode 5 to disassemble and )
- evaluate 2RCS-HCV-250A. The inspectors determined that this decision was appropriate because with the valve's condition unknown, the TS 3.4.12 action !
statement to close the valve could not be verifie j On December 7-8, maintenance personnel found leak sealant materialin portions of both 2RCS-HCV-250A & B valves. This material had prevented 2RCS-HCV-250A ,
from fully shutting as described above. The inspectors reviewed these findings with j operations and maintenance personnel. Subsequent investigation determined that i the leak sealant material had been introduced into the HVS on December 2, during )
the 2RCS-624 leak seal repair. A significant portion of the HVS piping and the 2RCS-HCV 250A & B valves were replaced (see Section M1.2). The inspectors assessed the HVS as found condition and the previous leak test results and determined that the December 4 leak rate test data for the 2RCS-SOV-200A(B) and :
2RCS-SOV-201 A(B) valve:, remained valid. The HVS cystem was declared operable )
on December 14 and reactor startup was performed on December 1 l l
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. Conclusions Operators properly identified and quantified reactor coolant leakage from the HVS
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, on November 29. The management decision to delay reactor startup pending further HVS operability assessment wr.s appropriate. However, the decision to startup the reactor on December 3 was premature because the leak integrity of certain valves was unknown. Subsequent leak rate test results provided assurance that various HVS valves were tight and that the RCS pressure boundary had not shifted to the downstream valves. The inspectors concluded that the test was well written and implemented. Plant cooldown and full assessment of a HVS valve position anomaly was important in identifying an adverse, safety significant condition which would have otherwise remained unknown. If not identified and corrected, the improper leak injection repair on 2RCS-624 would have caused the operability of the HVS to be questionable for the entire operating cycl O2 Operational Status of Facilities and Equipment O2.1 Enoineered Safety Feature System Walkdowns (71707)
The inspectors walked down accessible portions of selected systems to assest equipment operability, material condition, and housekeeping. Minor discrepancies were brought to DLC staff's attention and corrected. No substantive concerns were identified. The following systems were walked down: ,
- Unit 1 Emergency Diesel Generator (EDG) Air Start system
- Unit 1 River Water system
- Unit 1 & 2 EDG Fuel Oil systems
- Unit 2 Reactor Protection System 04 Operator Knowledge and Performance 04.1 Control Room Emeroency Breathino Air Pressurization System (CREBAPS) Timer (71707)
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The inspectors reviewed operations and engineering response to a problem identified in operations surveillance procedure 1/2 OST-44A.12, "CIB Actuation of Control Room Isolation /CREBAPS System Functional Test," Rev. 7. A Unit 2 operator performing the procedure noted that the timer dial on the relay was indicating a different value than referenced in the procedure. After investigation by l relay engineers, they found that the pointer on the timer dial face gave a different reading (54 minutes) than the actual internal relay reading (60 minutes). The full dial face indication span of 54 minutes (as received from the manufacturer)
corresponded to a relay setting of 60 minutes. Engineers confirmed that the pointer's only function was to provide positive indication that the timer was operatin Engineers had previously determined that components within this type of relay may wear out with repeated operation over time and had initiated a work request to
replace this relay. The relay was replaced and calibrated to its correct setpoint of 60 minutes. The procedure was revised to clarify that only the movement of the pointer should be checked as one of the acceptance criteria, not its actual readin The actual reading of the timer came from the relay. The inspectors noted that this demonstrated a good questioning attitude by the operators and effective engineering support.
08 Miscellaneous Operations issues 08.1 Offsite Review Committee Meetina Insoection Scoce (71707)
Inspectors attended the Offsite Review Committee (ORC) meeting and the ORC Operating Experience Subcommittee (OES) meeting. The inspectors evaluated the effectiveness of the independent oversight, and verified whether Technical Specification (TS) requirements were me Observations and Findinas On November 21,1996, the OES meeting was held and on November 22,1996, the periodic full ORC meeting was conducted. The inspectors verified the TS quorum was present and that TS requirements for independence from the line organization were satisfied. The inspectors noted a good questioning attitude and ;
significant va!ue added by the broad-based comments of the independent ORC l mernbers. During the OES subcommittee meeting, the external ORC member raised excellent questions which demonstrated clear independent issue review. However, '
the inspectors noted that contribution by onsite OES subcommittee members was limited, focusing for the most part on answering questions rather than contributing independence to the issue reviews. Management informed the inspectors that the j subcommittee composition and processes were being reviewed for potential i changes to improve effectivenes I Conclusions '
The Offsite Review Committee meetings were conducted in accordance with TS. A broad-based questioning attitude was displayed by the independent committee members. ORC subcommittee composition and processes were being reviewed for potential changes to improve effectivenes l l
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11. Maintenance
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l M1 Conduct of Maintenance
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M 1.1 Control of Paintina on Emeraency Diesel Generators (EDGs)
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, Insoection Scope (92902)
i L DLC experienced several problems with control of painting during refurbishment of ,
the EDGs this period. The inspectors reviewed the licensee's problem identification, !
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l operability ascessment, and corrective actions.
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! Findinas and Observations i
! ' On October 30, an operator noted that a vent hole for one of the EDG 1-1 cylinders
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j Problem Report 1-96-872. Engineers determined the EDG was still operable i
- because other vent holes were available to vent the cylinder during rollover. On a
November 24, an operator conducting a routine tour of EDG 2-1 found paint on the shaft of the overspeed trip mechanism where the shaft penetrates the overspeed ;
mechanism housing. DLC declared the EDG inoperable until an evaluation was '
completed that concluded the overspeed trip mechanism would have functioned as
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designed. On November 25, another operator found that a bearing oil sight glass on !
EDG 2-2 had been painted over. Inspectors reviewed the painting control issue due ,
to the potential safety consequences to safety-related equipmen !
As a result of the painting control issues, the Plant Manager issued a stop. work )
order on November 25 on all painting until an evaluation of painting control was I
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completed and corrective actions were implemented. The evaluation was to include a review of painting standards, training, pre-job briefings, and supervisory oversigh With the exception of some painting on static components (such as lumber and structural steel), the stop work order was stillin effect at the end of the perio Inspectors monitored the operability evaluation on EDG 2-1 and reviewed the instructions in the work order for painting, which stated that " care should be taken, especially with QA Category I equipment, not to coat or contaminate surfaces such as valve stems, linkages, injectors, metering rods on diesels or any other surface that is required to move during operation." DLC's preliminary investigation concluded that the pre-job briefing and work instructions were satisfactory and that the poor painting was due to personnel error. DLC was developing long-term corrective actions to improve painting control, at the end of the period. In addition, the inspectors observed maintenance personnel clean paint from 2EGS-EG2-1 overspeed trip mechanism using MWR 059045. This work was performed properly under close supervisio I 2 _ _ _ - _ _, , _ .. ., _ _. _ _ _ a
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I Conclusions ;
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- The inspectors concluded that there were no adverse safety consequences as a l
- result of the poor painting on the EDGs. However, this represented a weakness in , the licensee's control of contractor work. The inspectors assessed that actions j taken to address the issue of painting control were adequate. Operator I
! identification of the painting discrepancies demonstrated excellent attention to detail during operator periodic tours of the EDG rooms.
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M1.2 Inadeauste Unit 2 Reactor Vessel Head Vent System (HVS) Reoair
i Inscection Scone (92902) !
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On December 4,2RCS-HVC-250A failed to shut following a HVS valve leakage test, j Subsequent investigation by the licensee determined that leak sealant material injected to stop seat leakage on 2RCS-624 had traveled further than intended and !
was fouling the 2RCS_-HCV-250A & B valves (see Section 01.3). The inspectors !
performed an independent follow-up investigation to determine the original leak .
repair deficiencies and to assess the licensee's evaluation of this same even !
! Findinas and Observations ;
t inspector Review l
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Prior to observing 2RCS-HCV-250A closure problems, the inspectors reviewed !
MWR 059169 used to perform the 2RCS-624 leak injection repair. . Engineering i memorandum (EM) 113494 which supported this work package had appropriate calculations to support the intended maximum sealant injection volume and the 1 maximum injection pressure. 'The drill and tap location for the injection valve was I clearly identified on the valve drawing included in the work package. Engineers !
were able to comprehensively discuss all engineering aspects of the repair with the exception of the processes used for sealant material selection. The engineers who .
approved the material were able to discuss the material selection criteria in general !
terms but were not familiar with the specific criteria used for material selectio l The inspectors identified several potential weaknesses in the MWR, including insufficient procedure detail for controlling injection hole drill depth and absence of proceduralized methods or QC hold roints to verify the quantity of sealant injected and the injection pressure use On December 9, after the licensee determined that leak sealant material was found fouling the 2RCS-HCV-250A(B) valves, the inspectors met with leak repair vendors and maintenance personnel to discuss the 2RCS-624 repair in more detail. Several problems were identified- First, mechanics informed the inspectors that an incorrect sealant material was specified and used due to an incorrectly specified repair location temperature. This resulted in the sealant failing to promptly harden at the injection location and subsequent sealant material migration to downstream valve seats. The inspectors agreed that this was the primary cause of the even Through further discussions and inspection of the sealant material storage container and the leak seal repair equipment the inspectors identified several additional problems including the following:
(1) The amount of sealant materialinjected was not adequately controlled. The methods used by the vendor to measure / control volume were inadequate, as was the absence of licensee independent oversight to verify the sealant volume loaded into the injection gun and taken to the job sit (2) Quality Control (QC) oversight and hold points for this job were inadequate and did not meet the intent of those required by 1/2 CMP-75-LEAK REPAIR-1M, " General Leak Repair Procedure", Rev. 2. OC verified the '
specified sealant material was present at the material storage freezer, but did not witness the materialloaded into the injection gun. In addition, QC provided no oversight at the actual repair location to monitor such parameters as the injection port dri!! & tap location or the injection pressure -
use (3) Procedure 1/2 CMP-75-LEAK REPAIR-1M and the specified vendor procedure NP-2139, Engineering Repair Procedures", used for the repair were too general. In addition, the procedures don't require any maintenance oversight of the leak repair implementatio (4) The two procedures identified above may not have been properly reviewed by the Onsite Safety Committee and approved by the General Manager Nuclear Operations or a predesignated alternate assigned in writing as required by TS 6. (5) The vendor failed to properly identify the drill and tap location shown in i drawings attached to the work package as specified in procedure NP-213 The vendor made three containment entries and expended numerous drill bits before successfully drilling and tapping the injection port. The third entry had seven people present. On the first two attempts the vendor was drilling i into the stellate seat on the valve. The initial drill location indicated that maintenance oversight at the job site was inadequat l
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(6) The findings listed above indicate that the pre-evolution briefing was inadequate.
These problems were communicated to maintenance and en0 ineering personnel for assessment and resolution. The licensee had already initiated three independent investigations to assess the event and determine corrective actions.
Two additional subjects which the leak repair procedures don't currently address were discussed. The licensee indicated these would be reviewed and, if appropriate, would be incorporated into the pertinent procedures. However, these two subjects did not contribute to this event:
(1) Methods to provide positive control over the depth of drill hol (2) Measures to assess the effect of the operating environment (especially borated solutions encountered in primary systems) upon bolt materials when flange and body to bonnet gaskets are leak sealed. Often this process results in the bolt materials being contact with the working fluid of the system. Even though the bolt circle of a flange connection is not generally in contact (after sealing) with the bulk fluid of the system, it must be assumed that the fastener bodies are wetted by a thin film of residual solution. Many of the common bolting materials are susceptible to either general corrosion or stress corrosion cracking when wetted. The volume of water is immaterial (i.e., exposure to bulk fluid of the system versus trapped fluid within a crevice) since both of these corrosion processes are self propagating and can proceed (usually more aggressively) when in an enclosed environment.
Based on the numerous problems listed above, the inspectors were concerned that other safety related equipment may currently be adversely affected by previously implemented leak seal repairs. The inspectors reviewed all existing leak seal repairs in Units 1 and 2 and their associated work packages. The licensee independently reviewed each of the seven additional leak seal repairs. All seven are on secondary components, one of which is safety related. No safety concerns were identified with the other laak seal repairs.
The inspectors reviewed Quality Assurance (QA) assessment 94-6, "On-Line Leak Repair Assessment.' The assessment contained several good findings which were incorporated in 1994 and 1995. However, the inspectors noted that while actual field assessment of six leak repairs was included, the findings for the actual repair '
implementation were very general. The findings stated that the vendor was l conservative and had good work practices. The inspectors discussed these l observations with the QA manager who informed the inspectors that additional QA l and OC training was being developed to address lessons learned from this event.
The inspectors determined this action was appropriat The inspectors reviewed procedure QSF 7.4, " Vendor Selection, Evaluation, and l Qualified Suppliers List", Rev. 4, the two most recent third party audits for the !
vendor, and verified this vendor was on the licensee's approved Quality Services l List (OSL). In reviewing the audits the inspectors observed that vendor products and services at their own facility are audited. However, the field implementation of their services are not covered by the third party audit scope. QA auditors informed the inspectors this is common. In addition, the inspectors noted that the latest QA review of this vendor (November 7,1996) had made use of this vendor's services as a QSL-approved vendor conditional upon the vendor providing documented resolution to one of the third party audit identified vendor weaknesses. Although this weakness did not contribute to this event, the inspectors questioned whether the licensee had properly verified this condition was met prior to using the vendor
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for this leak seal repair on December 1-2. The vendor services had previously been approved for use through December 31,1996, on a blanket purchase order.
Station procedures may not clearly assign responsibility and specify a method to l
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ensure recent changes to the approved OSL list are reviewed before using vendor l services, including those for which current blanket purchase orders are already approved. Proper verification of OSL prior to using vendor services remains an unresolved issue pending further evaluation (URI 50-334(412)/96009-01).
Licensee Event Review and Self Assessment Maintenance personnel conducted an exploratory evaluation of the HVS to identify all potential degradation due to sealant materialintrusion. They determined that leak sealant material had migrated from 2RCS-624 to 2RCS-HCV-250A & 250B. No leak sealant material was found downstream of the 250A or 250B valves, or in the line upstream of 2RCS-624 to the head vent valves 2RCS-SOV-200A(B) and 201 A(B). As immediate corrective action, 2RCS-HCV-250A,2508, and the piping contaminated with leak sealant were replaced. 2RCS-624 and its associated piping ;
were permanently remove I The Vice President - Nuclear Operations issued a stop work order on any further i leak sealant activities and initiated investigations of the event by an engineering I Event Response Team (ERT), the Inu'ependent Safety Evaluation Group (ISEG), and j by the Maintenance department. Preliminary results identified several weaknesses '
in the existing leak sealant repair program and inadequate control of vendor work )
which contributed to the event. Engineering assessments concluded that the seven !
remaining leak seal repairs at the site were acceptabl (1) The leak sealant material (Sealant 18X) was selected by the vendor based on incorrect injection conditions provided to the vendor by the licensee engineering staff. The data sheet provided to the vendor indicated that system conditions were 610 degrees F and 2235 psig. These parameters were also specified in the 10 CFR 50.59 evaluation conducted by DLC and reviewed by the OSC to support the modification. While these could be the conditions in the piping during a design basis, accident use of the system, normal conditions in the piping are near atmospheric pressure and the ambient temperature of containment. As a result, the vendor selected a sealant for high temperature /high pressure conditions. The sealant failed to set (harden) atter injection at valve 2RCS-62 (2) The vendor calculated an injection amount of 6.32 cubic inches of sealant and engineers specified that the maximum sealant volume injected be limited to 16 cubic inches. The injection gun used had a 31.9 cubic inch caniste There was no measured control of the amount of sealant loaded into the
- injection gun by the vendor, however. The actual sealant material selected i and amount loaded was not monitored by the licensee. The vendor used l skill-of-the-craft judgement to quantify the amount of sealant loaded into the injection gun. After the contaminated piping and valves were removed from the system, the licensee accounted for between 11 and 12 cubic inches of sealant material that had been injecte (3) The vendor suggested the general location to dril and tap the injection location on the upstream side of 2RCS-624. Licensee engineers specified an exact drill and tap location on a valve drawing attached to the work packag The location was chosen close to the seat area, because the vendor did not want to risk a high pressure leak by drilling near the socket welded joint at the valve body. The vendor made several attempts at the initiallocation and was unable to drill through. Engineers subsequently determined that the vendor was unable to drill through the initial location because they were i drilling into the stellate valve seat. After consultation w !!censee l personnel, the vendor then selected a different location and successfully completed the drill and tap for the injection valve. The drilling procedure was a training procedure memorized by the vendor technicians but not issued to the field. It was considered skill-of-the-craf (4) NPDAP 2.15, " Administrative Controls", Rev. 2 specifies requirements for control of vendor services. Several requirements were not satisfied. The degree of supervision was not commensurate with the safety importance of the work. The work was not performed under the same procedural controls as would be required if the licensee personnel were performing the wor The procedures used by the vendor may not have received the proper level of revie In addition to the licensee's observations listed above, the inspectors reviewed the licensee's preliminary self assessment findings and noted that the findings were consistent with those identified by the inspector On December 11, the station conducted an engineering stand down day, to discuss issues of vendor control, ownership, accountability and signature authority, and complacer'cy with the engineering staff. The intent was to initiate improvements in ,
engineering process contro )
Station management informed the inspectors that the leak seal program would be I significantly revised to incorporate their self assessment findings. The engineering department will be assigned as program owne I I
C. Conclusions The inspectors concluded that several programmatic controls and performance weaknesses on the part of engineering, maintenance, and QA personnel directly resulted in the unintended migration of leak sealant material to other portions of the HVS, adversely affecting the operation of two HVS valves. This poor example of leak sealant injection repair was safety significant. NRC safety concerns related to HVS integrity caused the licensee to corduct supplemental HVS leak testing, during which a minor valve position indication anomaly was investigated. Had the licensee not pursued this anomaly, HVS operability would have been in an undetected questionable status. Immediate corrective actions implemented by the licensee including a clear focus on vend r oversight responsibilities and a stop work order on further leak injection repairs were appropriat l
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TS 6.8.1 requires written procedures be established and implemented covering activities recommended in Appendix A of NRC RG 1.33, revision 2. Leak seal injection procedures were weak and were not properly implemented. This resulted in an incorrect quantity and type of leak seal material being injected into the RC This material subsequently migrated to de' grade operation of the RCS head vent system flove path (specifically valve 2RCS-HCV-250A). In addition, existing procedure NPDAP 2.15 for vendor oversight was not properly implemente TS 6.8.2 requires each procedure specified in TS 6.8.1 to be reviewed by the Onsite Safety Committee and be approved by the General Manager, Nuclear Operations or a predesignated alternate. This issue is indeterminate pending further inspector follow-up (URI 50-412/96009-02).
Multiple 10 CFR 50, Appendix B criteria including Criterion 11 (QA Program),
Criterion 111 (Design Control), Criterion V (Instructions, Procedures, and Drawings),
and Criterion XVI (Corrective action) specify certain appropriate controls be implemented to properly perform safety related work activities. Multipl . weaknesses observed in the leak seal work activities included incorrect material specification, inadequate procedural instructions for the work, possible failure to review and approve the vendor supplied and used procedures, and inadequate oversight of vendor work activity during critical stages of work. The licensee failed to assure that conditions adverse to quality were promptly identified and corrected prior to this self identifying even .The deficiencies described above including vendor oversight, leak injection repair procedure content and approval, and QA oversight are an apparent violation of 10 CFR 50, Appendix B, Criteria 11, Ill, V, and XVI, TS 6.8.1, and TS 6. M1.3 Replacement of Unit 2 HVS Pioina and Valves Inspection Scope (62707. 92902)
Portions of the Unit 2 HVS became contaminated with leak repair sealant material due to poor work practices. The inspectors monitored portions of the replacement maintenance and post maintenance testing to verify the system was properly restore Findinas and Observations The inspectors monitored portions of and reviewed the following completed work packages, evaluations, and testing associated with the repair of the reactor head vent syste ST- Reactor Vessel Head (RVH) Vent System Test of 12/13/9 TOP-96-11 Reactor Coolant System SOV Leak Test of ' 2.13/96 MWR 059300 Install / Remove Nitrogen Purge Rig on RVH Vent Syste MWR 059267 Install Controller of 2RCS-HCV-250A (including procedure 1/2 CMP-75-Target Rock-12MI, " Target Rock Style 1033110-1 and 1033110-2 Modulating SOV Globe Valve Overhaul").
MWR 059296 Inspect 2RCS-HCV-250A for Binding Following Failure to Stroke Fully During 2 TOP 96-1 MWR 059314 Replace Controller on 2RCS-HCV-250 MWR 059350 Test Valve Received from Calloway as Replacement for 2RCS-HCV-250 MWR 059340 Replace RHV Piping Lines 2-RCS-001-307-2 and 2-RCS-001-283-2 and _ Valves 2RCS-HCV-250A and 250 TER 10771 Removal of 2RCS-624,2RCS-FG200, and Associated Piping Modifications (including associated 10CFR50.59 Evaluation).
MWR 059339 Replace RHV Piping Lines 2-RCS-001-285-4 and 2RCS-001- '
286- MWR 059386
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Disassemble Pipe Support 2RCS-PSR163C ,
t Conclusions i
The HVS piping and valve replacements were properly performed with appropriate I planning and oversight.
M1.4 Routine Surveillance Observations (61726) l l
The inspectors observed selected surveillance tests. Operational surveillance tests l
(OSTs) reviewed and observed by the inspectors are listed belo * 10ST-3 " Reactor Plant River Water Pump IC test," Rev. 9
- 10ST-3 " Diesel Generator No.1 Monthly Test"
- 20ST-2 " Steam Turbine Driven Auxiliary Feed Pump [2FWE*P22]
Test," Rev. 25 The surveillance testing was performed safely and in accordance with proper procedures. Additional observations regarding surveillance testing are discussed in the following sections. The inspectors noted that an appropriate level of supervisory attention was given to the testing, depending on its sensitivity.
M2 Maintenance and Material Condition of Facilities and Equipment M 2.1 Annunciator Alarms l Insoection Scoce (71707. 62707)
During the Unit 2 refueling outage, inspectors observed numerous invalid control room alarms. The inspectors discussed the cause of the inadvertent alarms with control room operators, Instrumentation and Control technicians, and engineering personnel. The inspectors further expanded the investigation to include a historical review of annunciator problems for both unit I
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- Observations and Findinas
' While conducting Unit 2 control room walkdowns, the inspectors noted several
- control room annunciators flashing in alarm. Discussions with operators revealed i
that the alarms were invalid, as confirmed by the absence of corresponding !
computer alarms. Several of the alarms were on systems that were not in operation >
j during the outage. Work requests were found to be written in most circumstances, ,
j however, one instance of a steam generator level high/ low invalid alarm did not i i have a work request submitted. Operators had believed the work request was already submitted. Further discussions with various operators indicated that it was ;
[ not clear whether they would receive a valid alarm signal via the computer point i with the corresponding annunciator failur ;
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Maintenance planning reviews revealed annunciator failures of greater than 100 for
Unit 1 and greater than 50 for Unit 2 over a 6-year period. The majority of failures
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for both units were attributed to the logic card in the annunciator system. For .!'
Unit 1, the lamp driver transistors on the logic card were the most common component to fail. Instrumentation and Control (l&C) personnel indicated that the
!- transistors were most likely to fail after a discrete number of annunciator alarm i cycles. For Unit 2, the electrolytic capacitors were the most common component to fail. l&C personnel ' indicated that an 8 to 10 year service life was expected for the :
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electrolytics. A work request was written in March 1995 to address this problem, l but has not yet been worked. During corrective maintenance, l&C personnel !
indicated that they had replaced multiple cards in addition to the failed card. The !
inspectors observed that there was not a formal preventive maintenance program in ;
place to address either unit's logic card failures, l&C personnel indicated that the . I operator would receive computer point indications for valid alarms even with a failed !
logic car l l
The maintenance planning department had reviewed the annunciator problems and proposed corrective actions to enhance the systems reliability. The proposed l corrective actions include establishing a preventive maintenance program, review of i further upgrades to the systems, and developing better troubleshooting procedures !
and vendor drawing l l Conclusions )
Both units have a history of control room annunciator failures. Some corrective actions are in place but the inspectors noted no formal preventive maintenance program currently exists to address the problem. The communication between Operations and l&C staff was not effective in providing operators with information on computer point indications. The repeated control room annunciator failures were a distraction to operators. Current initiatives to address the problem are considered to be adequate. The inspectors concluded that the licensee's failure to address continued annunciator failures was a weakness; however, the inspectors noted that initiatives were under way to address the proble ~ . . -_ _ _ _ . _ - _ - _
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111. Enaineerina
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l E1 Conduct of Engineering i
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i E Heavy Load Lifts Near Safety Related Eauipment in the Intake Structure ;
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' Insoection Scope (37551)
J Design change package (DCP) 2152 was implemented to install a chemical
treatment injection system at the intake structure for the river and service water
} systems. This system upgrade was designed to reduce marine fouling in the river and service water lines. Part of this DCP involved installing two heavy chemical 1 j storage tanks above the safety related pump motor cubicles within the intake structure. Maintenance personnel recognized that the work plan had requested
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- these heavy loads be lifted over a different load path than documented in the Unit 2 j Updated Final Safety Analysis Report (UFSAR). The inspectors discussed the work j activity with engineers and reviewed the safety evaluation to modify the approved l l intake structure safe load path to assess whether the heavy load was properly
- planned and implemented.
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' Observations and Findinas '
i Engineers prepared a safety evaluation to revise the intake structure heavy load path in the vicinity of safety related equipment. The two chemical storage tanks'
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l empty weights were 3895 pounds and 5710 pounds respectively. Stated safety l' concerns were that if either tank were dropped while being transported by the i' intake structure crane, it could damage the pump motor cubicles' concrete roof, j with the potential to damage safety related piping and pumps installed in the motor i cubicles below. A second concern was that the station fire header could be
, damaged which could cause flooding in the safety related motor cubicle !
! The inspectors reviewed load path drawings and discussed the safety evaluation f with the engineers. Applicable considerations discussed in NRC NUREG-0612, i " Heavy Loads", and NRC Bulletin 96-02, " Movement of Heavy Loads Over Spent !
- Fuel, Over Fuel in the Reactor Core or Over Safety-Related Equipment", were l properly addressed in the safety evaluation and maintenance procedure MPUAM ,
4.10, " Handling of NUREG-0612, Heavy Loads", Rev.1. The inspectors noted that 2
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{ the lift had the potential to damage the station fire header ' supply from both fire l pumps at the same time. After discussing this with engineers, the safety evaluation j was updated to ensure operators were aware of this potential and that appropriate j compensatory measures were established, i ,
i While preparing the safety evaluation, engineers determined that several of the
- approved heavy load paths contained in MPUAM 4.10 differed from those
- documented in the Unit 2 UFSAR. Problem report (PR) 2 96-796 was initiated to j further review this issue. The inspectors met with engineers and licensing i representatives and questioned whether approved safety evaluations existed for l each of the safety related heavy load lift paths currently approved for use in
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1MPUAM 4.10. Licensing engineers conducted a document review and located approved safety evaluations for all but three of the approved lift paths. The lift cranes used for these three safety related heavy load lift paths.were promptly -
tagged out and the operations shift supervisors were notified in writing that these '
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load paths were not authorized for use until further notice. Engineers are continuing to review documentation to verify whether 10 CFR 50.59 safety evaluations were i performed to support using the three load paths in question. Additionally, the
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licensee is reviewing maintenance documents to determine whether the three load paths in question have ever been used. The inspectors determined these actions >
were appropriat ;
Engineers and licensing persor.nel identified a list of heavy load lift path drawings i and tables in Unit 2 UFSAR 9.1 which had not been properly updated. PR 2-96-796 -
investigation and corrective actions remained in progress at the end of the >
inspection period. The inspectors verified that NPDAP 8.18, "10.CFR 50.59 Evaluations", Rev. 3 required the safety evaluation initiator to process a UFSAR !
change sheet to capture changes initiated throughout this process. The licensee i informed the inspectors that appropriate UFSAR updates identified through PR 2-96-796 would be submitted with the next annual UFSAR updat * Conclusions
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Maintenance personnel demonstrated excellent awareness of plant design when they identified that the proposed heavy load lift path in the intake structure required ,
a safety evaluation. In addition, engineers identified that several safety related }
heavy load lift paths contained within station procedures that differ from those specified in the UFSAR.' Corrective actions to determine the scope of the proble and update the UFSAR were appropriate. These discoveries indicated a good ;
questioning attitude regarding maintaining plant design. However, compensatory measures to prevent using three proceduralized lift paths for which safety evaluation could not be found and were not implemented until questioned by the ;
inspectors. This item remains unresolved pending determination of whether the three indeterminate lift paths have been used and whether they were properly j evaluated (URI 50-334(412)/96009-03). :
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E2 Engineering Support of Facilities and Equipment ;
E Unit 1 Steam Generator (SG) Blowdown Isolation Valve Operation l Insoection Scope (37551)
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On December 16,1996, the 1 A SG blowdown isolation valvs (TV-1BD-101 A1)
failed to reopen following valve closure during performance of a periodic surveillance test. Initial investigation revealed that the valve would close when .
called upon, but would not reliably open each time operators attempted to open the velve. The inspectors reviewed the engineering assessment of this problem.
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' Observations and Findinas i .
b l The inspectors discussed PR 1-96-977, valve design, and likely causes with system
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engineers. During normal operation TV-1BD-101 A1 provides a blowdown flow path
- . for the 1 A SG. The safety function of this valve is to close to isolate blowdown in L the event of a high energy line break. The inspectors reviewed UFSAR 10.3. {
t l and verified performance criteria for valve closure continued to be consistently met.
Engineers discussed five potential causes which could result in the observed valve i
operation and presented recommendations for further investigation to assess each potential cause. The valve is located in containment in a high radiation area which
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limited access to the valve for further investigation under current operating ;
conditions. Engineers presented test information and based on valve design, '
explained why the. valve would continue to close reliably. The inspectors determined that this assessment was technically sound. Specific recommendation i
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for further investigation were clearly documented in a memorandum for engineering i and operations personne '
, Conclusions-The inspectors concluded that the system engineers had a strong technically understanding of the valve's design and safety function. The assessment of likely causal factors for inconsistent opening operation was good Recommended actions including placing this valve on the forced outage work list were appropriat E8 Miscellaneous Engineering issues E (Closed) Unresolved item 50-334/94-26-01: 50-412/94-27-01 (92903)
Inspectors had previously noted inconsistencies and potential inadequacies in the testing of safety-related ventilation systems, as documented in NRC Inspection Report 50-334/94-26 and 50-412/94-27.- The issue was an unresolved item pending further review by the NRC and DL DLC reviewed safety-related ventilation system functional testing for consistency and 'adequacy as documented in Maintenance Engineering and Assessment Department (MEAD) memorandum ND3 MEA:0870 dated March 23,1995. Safety-related systems reviewed by MEAD included the Unit 1 and 2 diesel generator buildings, the emergency switchgear rooms, the intake structures, the Unit 2 control building, and the Unit 1 SLCRS (supplemental leak collection recovery system).
MEAD determined that additional functional testing was required in the intake
.. structures and the Unit 2 control building to ensure that the system air flows do not
' degrade, since the required equipment qualification (EQ) air flows were slightly less that the actual performance of the systems. Inspectors reviewed the test results
- concluded to date and noted that additional testing was properly scheduled. No additional concerns were noted. Inspectors assessed that the issue had been adequately addressed by DL !
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? E3.2 Enaineerina Bas for Recent Operatina License Amendment Reauests (37551) ! ;
During review of Proposed Operating License Amendment Request Nos. 234 and l 107 (dated September 9,1996), the NRC Project Manager (PM) noted that the i licensee's safety analysis for parts of the proposed changes was inadequate. The submittal proposed several changes to the Design Features section (Section 5.0) of the BVPS-1 and BVPS-2 Technical Specifications (TSs). The stated purpose of the !
proposed changes was to make the Design Features section of the BVPS-1. and . ;
BVPS-2 TSs consistent with the four criteria specified in the Commission's Policy 1 Statement on TSs (58 FR 39132) and with the guidance provided in the NRC's Standard Technical Specifications, Westinghouse Plants (NUREG 1431, Revision 1). l The PM's review determined that the licensee's safety analysis for several of the j proposed changes simply noted what the proposed changes were but did not provide an evaluation of the safety significance and acceptability of these~ proposed changes. The PM discussed these inadequacies with licensee representatives who agreed with the need for such evaluations. The PM also noted to the licensee !
representatives that statements in the safety analysis indicating that proposed i changes would make the BVPS TSs like those in NUREG-1431, Revision 1, are not ;
sufficient by themselves; the safety analysis muct provide an evaluation of why the !
proposed change is acceptable for BVP l t
IV. Plant Suncort l P8 Miscellaneous EP lasue l
P Licensee On-Shift Dose Assessment Capabilities - NRC Tl 2515/134 (71750)
!
During the week of October 7,1996, a region-based inspector conducted an )
in-office telephone interview with the licensee in order to carry out the NRC's 1 Temporary Instruction (TI) 2515/134, " Licensee On-Shift Dose Assessment i Capabilities." The goal of the Tl was to gather information on the licensee's !
capabilities to perform on-shift dose assessment. The inspector determined !
that the licensee has on-shift dose assessment capability, supported by !
appropriate procedural guidance, and that on-shift personnel were trained to perform the function. Therefore, the licensee' met NRC requirements to be ;
able to perform dose assessment at all times. The results of the evaluation l were forwarded to NRC Headquarters personne j S1 Conduct of Security and Safeguards Activities ;
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I S1.1 Potential Tamoerina Review: Coolant Tower Pumo Sucolv Breaker (71750)
l On December 21,1996, operations personnel notified security that a 480V breaker ,
which supplied power to a Unit 1 cooling tower pump supply valve I (MOV-CW-101 A) was found in the off position with the panel hold down screws l backed off. The breaker and pump were located outside of the protected area and )
had no safety significance. The valve associated with the breaker was in the proper i alignment (open) and has been in the noted position for an undetermined period of I
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! time. Once notified, security implemented their procedures associated with
! potential tampering. The inspectors noted that the licensee procedures were consistent with NRC guidance. Security immediately posted a guard near the breaker to preserve the scene and initiated an investigation.
l Operations personnel performed a walkdown of all cooling tower breakers and were
! unable to identify any additional discrepancies. Based on these observations, security secured the posted guard and continued periodic tours of the affected areas. The tours were discontinued on December 23,1996, because the investigations did not indicate any evidence of tampering. The inspectors i interviewed operations and security personnel, reviewed logs, toured the affected
! areas, and observed power supply breaker operation within the cooling tower pump l house. The inspectors noted that it was unlikely that the power supply breaker had "
been inadvertently bumped to change its position. The inspectors consider that this component does not have safety significance and was not a likely tampering targe :
Security and operations personnels' assessment of this event was appropriate
!
including the ongoing review of historical work activities related to the affected breaker. The inspectors concluded that the licensee has a low threshold concerning potential tampering events and their response was thoroug L1 Review of UFSAR Commitments '
l A recent discovery of a licensee operating their facility in a manner contrary to the Updated Final Safety Analysis Report (UFSAR) description highlighted the need for a
- special focused review that compared plant practices, procedures and/or parameters i to the UFSAR descriptio !
While performing the inspections discussed in this report, the inspectors reviewed the applicable parts of the UFSAR that related to the areas inspected. The inspectors verified that the UFSAR wording was consistent with the observed plant !
practices, procedures and/or parameters except as discussed in Section E V. Manaaement Meetinas X1 Exit Meeting Summary The inspectors presented the inspection results to members of licensee management at the conclusion of the inspection on December 27,1996. The licerisee acknowledged the findings presented, j The inspectors asked the licensee whether any materials examined during the inspection should be considered proprietary. No proprietary information was l identified.
l X2 SALP Management Meeting On November 20, a public meeting was held between DLC and NRC management at the Beaver Valley Power Station Emergency Response Facility to discuss the results l
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of the NRC Systematic Assessment of Licensee Performance (SALP Report 50-334/96-99 and 50-412/96-99) for the period June 4,1995 to September 28,199 W. Kane, Deputy Regional Administrator, R. Crienjak, Acting Deputy Director, Division of Reactor Projects (DRP), P. Eselgroth, Chief, DRP Branch 7, and Brinkman, Senior Project Manager, NRR, attended from NRC Region I and Headquarters. A copy of the slides presented at the meeting is included in Attachment >
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PARTIAL LIST OF PERSONS CONTACTED DLC
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S. Jain, Vice President, Nuclear Services
T. Noonan, Vice President, Nuclear Operations / Plant Manager K. Grada, Technical Assistant to Vice President, Operations R. Brosi, Manger, Nuclear Safety Department R. Snowden, Quality Control Supervisor .
F. Curi, MPU Construction Manager R. Hansen, Director, Plant Mechanical / Structural Engineering D. Szucs, Senior Engineer, Nuclear Safety
J. Belfiore, Program Auditor, Quality Services Unit NRC i
D. Kern, SRI G. Dentel, RI F. Lyon, RI G. Kelly, Region I, DRS
P. Eselgroth, Region 1, DRP INSPECTION PROCEDURES USED
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IP 37551: Onsite Engineering IP 61726: Surveillance Observation IP 62707: Maintenance Observation IP 71707: Plant Operations IP 92901: Follow-up, Operations ;
IP 92902: Follow-up, Maintenance '
IP 92903: Follow-up, Engineering ITEMS OPENED, CLOSED AND DISCUSSED l Opened
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50-334(412)/96009-01 URI Proper verification of OSL prior to using vendor !
services (Section M1.2) l 50-412/96009-02
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URI Inadequate 2RCS-624 Leak Seal Repair (Section M1.2).
50-334(412)/96009-03 URI Heavy Load Lift Program, Failure to Update FSAR and indeterminate 50.59 evaluations (Section E1.1).
Closed 50-334/94026-01 URI Safety Related Ventilation System inconsistencies (Section E8.1).
50-412/94027-01 URI Safety Related Ventilation System inconsistencies Section E8.1).
Tl 2515/134 Tl Licensee On-Shift Dose Assessment Capabilities (Section P8,1).
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LIST OF ACRONYMS USED !
BVPS Beaver Valley Power Gtation CFR Code of Federal Regulations t CRDM Control Rod Drive Mechanism CREBAPS Centrol Room Emergency Breathing Air Pressurization System f
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DCP Design Change Package DLC Duquesne Light Company
'dpm Drop per Minute !
.DRP Division of Reactor Projects EDG Emergency Diesel Generator l EM Engineering Memorandum i EQ Equipment Qualification i ERT Event Response Team ESF Engineered !!afety Feature ;
HVS Head Vent System !'
I&C Instrument & Control ISEG Independent Safety Evaluation Group MEAD Maintenance Engineering and Assessment Department MWR Maintenance Work Request :
NRC Nuclear Regulatory Commission NRR Office of Nuclear Reactor Regulation l NUREG Nuclear Regulatory Guidance ,
OES Operating Experience Subcommittee ORC- Offsite Review Committee OST Operational Surveillance Test !
PDR Public Document Room :
PM Project Manager PR Problem Report ]
QA Quality Assurance OC - Quality Control QSL - Quality Services List RCS Reactor Coolant System I
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RG Regulatory Guide RP&C Radiological Protection and Chemistry RVH Reactor Vessel Head SALP Systematic Assessment of Licensee Performance SG Steam Generator SLCRS Supplemental Leak Collection Recovery System Tl Temporary Instruction TS Technical Specification UFSAR Updated Final Safcty Analysis Report URI Unresolved item
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UNITED STATES NUCLEAR REGULATORY COMMISSION D IA s
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Systematic Assessment of Licensee Performance (SALP)
BEAVER VALLEY POWER STATION I Assessment Period: June 4,1995 - September 28,1996 Board Meeting: October 17,1996 Management TAeeting: November 20,1996 A-1
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i AGENDA
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i NRC Introductory Remarks: William F. Kane )
Deputy Regional
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BVPS Introductory Remarks: James E. Cross !
President l l Generation Group j l \
! NRC SALP Process and Results: Richard V. Crienjak Acting Director Division !
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of Reactor Projects l
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BVPS Closing Remarks: James E. Cross !
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President Generation Group NRC Closing Remarks: William F. Kane Deputy Regional Administrator i
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, PERFORMANCE ANALYSIS AREAS
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t l o PLANT OPERATIONS '
o MAINTENANCE
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Radiological Controls t
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Fire Protection
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l Performance Category Ratings CATEGORY 1: SUPERIOR PERFORM'ANCE
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Programs and Procedures Provide Effective Controls
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Self-Assessment Efforts are Effective
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Corrective Actions are Comprehensive
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Minimum inspections to Verify Safety CATEGORY 2: GOOD PERFORMANCE
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Programs and Procedures Normally Provide Controls
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Self-Assessment Efforts are Good - Emerging issues
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Recurring Issues
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Additional Inspection to Assess Performance CATEGORY 3: ACCEPTABLE PERFORMANCE
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Programs and Procedures are baak
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Self-Assessment Efforts are Reactive
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Corrective Actions are Weak
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Significant NRC and Licensee Attention Required A-5
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OPERATIONS
- SHIFT SUPERVISOR FIELD OPERATOR
! COMMUNICATIONS o FUEL HANDLING OPERATIONS
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o SELF-CHECKING PRACTICES
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O SRO AND STA STAFFING LEVELS i
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o EVENT AND OCCURRENCE REVIEWS i
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MAINTENANCE
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STAFFING AND TRAINING o RISK ASSESSMENT
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O WORK AND BACKLOG CONTROL
o EQUIPMENT INSPECTIONS AND MONITORING o EVENT AND OCCURRENCE REVIEWS o PROCUREMENT SUPPORT l
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SURVEILLANCE AND OTHER TESTING l
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ENGINEERING
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O MANAGEMENT ATTENTION TO FUNCTIONS AND IMPROVEMENTS O QUALITY OF TECHNICAL WORK AND ENGINEERING PRODUCTS ;
O RESPONSE TO EMERGENT ISSUES AND IDENTIFIED i PROBLEMS O QUESTIONING APPROACH TO PLANT DESIGN AND CONFIGURATION i
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O ENGINEERING PROCEDURES AND PROGRAMS l
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4 PLANT SUPPORT
RADIOLOGICAL AND EFFLUENT CONTROLS A STRENGTH OVERALL
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e IN-PLANT CONTROLS e OUTAGE ALARA PERFORMANCE o WORKER SUPPORT OF CONTROLS NEEDS e EFFLUENT AND PROCESS RAD MONITORING CALIBRATION SECURITY PROGRAM AND MEASURES WERE GENERALLY EFFECTIVE o HARDWARE IMPROVEMENTS e SECURITY FORCE TRAINING e REDUCTION IN BACKLOG OF EQUIPMENT WORK e CONTROL OF A-9
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l l EMERGENCY PREPAREDNESS PROGRAM PERFORMANCE j WAS MIXED !
- i e PROBLEM IDENTIFICATION AND SELF- i
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ASSESSMENT ll l * STAFFING, ORGANIZATION, STATE LIAISON
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EP EXERCISE PERFORMANCE i
i FIRE PROTECTION PROGRAM PERFORMANCE GENERALLY GOOD
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(* MAINTENANCE OF EQUIPMENT
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