IR 05000272/2010003
| ML102980477 | |
| Person / Time | |
|---|---|
| Site: | Salem  |
| Issue date: | 08/10/2010 |
| From: | Arthur Burritt Reactor Projects Branch 3 |
| To: | Joyce T Public Service Enterprise Group |
| References | |
| FOIA/PA-2010-0334 IR-10-003 | |
| Download: ML102980477 (77) | |
Text
- Ii UNITED STATES ,
NUCLEAR REGULATORY COMMISSION
REGION I
X 475 ALLENDALE ROAD KING OF PRUSSIA, PA 19406-1415
August 10, 2010 Mr. Thomas President and Chief Nuclear Officer PSEG Nuclear LLC - N09 P.O. Box 236 Hancock's Bridge, NJ 08038 SUBJECT: SALEM NUCLEAR GENERATING STATION, UNIT NOS. 1 AND 2 -
NRC INTEGRATED INSPECTION REPORT 05000272/2010003 and 05000311/2010003
Dear Mr. Joyce:
On June 30, 2010, the U.S. Nuclear Regulatory Commission (NRC) completed an inspection at the Salem Nuclear Generating Station, Unit Nos. 1 and 2. The enclosed integrated inspection report documents the inspection results discussed on July 8, 2010, with Mr. Fricker and other members of your staff.
The inspection examined activities conducted under your license as they relate to safety and compliance with the Commission's rules and regulations and with the conditions of your license.
The inspectors reviewed selected procedures and records, observed activities, and interviewed personnel.
The report documents one NRC-identified finding and one self-revealing finding of very low significance (Green). One of these two findings was determined to involve a violation of NRC requirements. Additionally, one licensee-identified violation of very low safety significance is listed in this report. However, because of the very low safety significance of these two violations and because they were entered into your corrective action program (CAP), the NRC is treating these findings as non-cited violations (NCVs) consistent with Section VI.A.1 of the NRC Enforcement Policy. If you contest any NCV in this report, you should provide a response within 30 days of the date of this inspection report, with the basis for your denial, to the Nuclear Regulatory Commission, ATTN: Document Control Desk, Washington, DC 20555-0001; with copies to the Regional Administrator, Region I; the Director, Office of Enforcement, United States Nuclear Regulatory Commission, Washington, DC 20555-0001; and the NRC Resident Inspector at the Salem Nuclear Generating Station. In addition, if you disagree with the cross-cutting aspect assigned to any finding in this report, you should provide a response within 30 days of the date of this inspection report, with the basis of your disagreement, to the Regional Administrator, Region I, and the NRC Resident Inspector at Salem Nuclear Generating Station. In accordance with 10 CFR 2.390 of the NRC's "Rules of Practice," a copy of this letter, its enclosure, and your response (if any) will be available electronically for public inspection in the NRC Public Document Room or from the Publicly Available Records (PARS) component of NRC's document system (ADAMS). ADAMS is accessible from the NRC Web site at http://www.nrc..qov/readinq-rm/adams.html (the Public Electronic Reading Room).
Sincerely, Arthur L. Burritt, Chief Projects Branch 3 Division of Reactor Projects Docket Nos: 50-272; 50-311 License Nos: DPR-70; DPR-75 Enclosure: Inspection Report 05000272/2010003 and 05000311/2010003 w/Attachment A: Supplemental Information Attachment B: TI 172 MSIP Documentation Questions Salem Unit I cc w/encl: Distribution via ListServ
SUMMARY OF FINDINGS
,
IR 05000272/2010003, 05000311/2010003; 04/01/2010 - 06/30/2010; Salem Nuclear Generating Station -Unit Nos. I and 2; Inservice Inspection and Maintenance Effectiveness.
The report covered a three-month period of inspection by resident inspectors, and announced inspections by a regional radiation specialist and reactor engineers. One Green non cited violation (NCV) and one Green finding were identified. The significance of most findings is indicated by their color (Green, White, Yellow, or Red) using Inspection Manual Chapter (IMC)0609, "Significance Determination Process" (SDP) and the cross-cutting aspect of a finding is determined using IMC 0310, "Components Within the Cross-Cutting Areas." Findings for which the SDP does not apply may be Green or be assigned a severity level after NRC management review. The NRC's program for overseeing the safe operation of commercial nuclear power reactors is described in NUREG-1649, "Reactor Oversight Process," Revision 4, dated December 2006.
Cornerstone: Initiating Events
- Green.
A self-revealing finding of very low safety significance was identified on January 21, 2010, because a control system short circuit caused the 21 steam generator feed pump (SGFP) to trip. This caused a turbine runback and ultimately an automatic Unit 2 reactor trip due to low water level in one of four steam generators (SGs). The short circuit occurred because technicians did not use the correct procedure to repair degraded insulation on the barrel of a connector lug that was identified in the 21 SGFP control system in November 2009. PSEG repaired the short circuit prior to restart of Unit on January 23, 2010. The issue was entered into the corrective action program as notification 20448229. PSEGs immediate corrective actions for this issue included repairing the degraded insulation, fixing lug alignment and performing extent of condition inspections on the other Unit 2 SGFP panels for degraded insulation. No other deficiencies were identified.
This performance deficiency is more than minor because it is associated with the human performance attribute of the Initiating Events cornerstone, and it adversely affected the cornerstone objective to limit the likelihood of events that upset plant stability and challenge critical safety functions. Specifically, not following PSEG procedure SC.DE-TS.ZZ-2039 on November 11, 2009, caused the 21 SGFP trip and subsequent automatic reactor trip due to low SG water level on January 21, 2010. The finding was evaluated under IMC 0609, Attachment 4. The inspectors determined that the finding is of very low safety significance because it does not contribute to both the likelihood of a reactor trip and the likelihood that mitigation equipment or functions will not be available.
The inspectors determined that this finding has a cross-cutting aspect in the area of human performance because PSEG personnel did not follow procedure requirements while repairing plant equipment. Specifically, technicians applied electrical tape to the 21 SGFP pressure switch connector lug barrel on November 11, 2009, which did not meet PSEG procedure SC.DE-TS.ZZ-2039 requirements. (H.4 (b)) (Section 1R12)
Cornerstone: Mitigating Systems
- Green.
The inspector identified an NCV of very low safety significance for PSEG's failure to perform auxiliary feedwater (AFW) discharge piping system pressure tests on buried piping components as required by 10 CFR 50.55a(g)(4) and the referenced American Society of Mechanical Engineers Code (ASME), Section Xl, paragraph IWA-5244 for Salem Unit 1. The required tests are intended to demonstrate the structural integrity of the buried piping portions of the system. PSEG entered this condition into the corrective action program (notification 20459689) and replaced the affected Unit 1 AFW piping.
This performance deficiency is more than minor, because, if left uncorrected, it would have resulted in a more significant safety concern. Specifically, the inspectors determined that based on the degraded condition of the coating and piping discovered during excavation on Unit 1, without performance of the required pressure test, an undetected failure of the piping would have resulted due to continued, undetected corrosion. The finding impacts the Mitigating Systems cornerstone. Using IMC 0609,
Attachment 4, the finding was determined to be of very low safety significance because it was not a design or qualification deficiency, did not result in an actual loss of safety function, and was not potentially risk significant for external events. No cross cutting Aspect is assigned to this violation because this condition began in 1988, more than 3 years ago, and is not indicative of current performance. (Section 1 R08)
Other Findings
One violation of very low safety significance was identified by PSEG and has been reviewed by the inspectors. Corrective actions taken or planned by PSEG have been entered into PSEG's corrective action program (CAP). This violation and its corrective action tracking numbers are listed in Section 40A7 of this report.
REPORT DETAILS
Summary of Plant Status
Salem Nuclear Generating Station Unit 1 (Unit 1) began the period at full power. On April 2, operators reduced power to 89 percent because heavy river water detritus prevented adequate cooling of the main condenser. On April 3, operators shut down Unit 1 to begin the twentieth refueling outage (RFO) (S1R20). On April 29 the RFO ended when operators synchronized the main generator to the grid. On May 1, operators returned Unit 1 to full power. On June 15, operators reduced power to 3 percent and removed the main turbine from service due to erratic operation of the 13 steam generator (SG) feed regulating valve (FRV). Operators synchronized Unit 1 to the grid again on June 16, but because the 12 SG FRV was not adequately controlling 12 SG water level, operators removed the main turbine from service on June 17. Operators synchronized Unit 1 to the grid on June 17 and returned the unit to full power on June 18. Unit 1 remained at or near full power for the remainder of the inspection period.
Salem Nuclear Generating Station Unit 2 (Unit 2) began the period at full power. On April 1, operators reduced power to 83 percent because heavy river water detritus prevented adequate cooling of the main condenser. On April 2, operators reduced power to 69 percent because heavy river water detritus prevented adequate cooling of the main condenser. On April 5, operators began power ascension and reached full power on April 7. Unit 2 remained at or near full power for the remainder of the inspection period.
REACTOR SAFETY
Cornerstones: Initiating Events, Mitigating Systems, Barrier Integrity and Emergency Preparedness
1R01 Adverse Weather Protection (71111i:01 - 1 sample)
.1 Summer Readiness of Offsite and Alternate AC Power Systems
a. Inspection Scope
The inspectors completed one adverse weather inspection sample to evaluate the readiness of offsite power to the Salem units prior to the summer season when electrical grid stability can be most challenged. The inspectors verified that PSEG provided procedure requirements or guidance to monitor and maintain availability and reliability of the offsite AC Power (OSP) system prior to and during adverse weather conditions.
Specifically, the inspectors verified that the procedures addressed:
" The actions to be taken when notified by the electrical system operations center (ESOC) of the PJM interconnection that the post-trip voltage of the OSP system at Salem will not be acceptable to assure the continued operation of the safety-related loads without transferring to the emergency diesel generators (EDGs);
" The compensatory actions to be performed if ESOC cannot predict the post-trip voltage;
- The re-assessment of plant risk for maintenance activities that could affect grid reliability or OSP system availability to the Salem units; and
,, Communication requirements between Salem and the ESOC regarding plant changes that could impact the transmission system, or the capacity of the transmission system to provide adequate OSP.
The inspectors also reviewed PSEG's seasonal readiness preparations for the summer season specific to the main power transformers and the OSP system. The inspectors interviewed engineering and work control personnel and reviewed work orders and completed portions of WC-AA-107, Seasonal Readiness, to verify that PSEG took measures to ensure the reliability of the main transformers and the OSP system during the summer season. The documents reviewed during this inspection are listed in the A.
b. Findings
No findings of significance were identified.
1R04 Equipment Aliginment (71111.04 - 3 samples;
==71111.04S - 1 sample)
.1 Partial Walk down
a. Inspection Scope
==
The inspectors completed three partial system walk down inspection samples. The inspectors walked down the systems listed below to verify the operability of redundant or diverse trains and components when safety equipment was inoperable. The inspectors focused their review on potential discrepancies that could impact the function of the system and increase plant risk. The inspectors reviewed applicable operating procedures, walked down control systems components, and verified that selected breakers, valves, and support equipment were in the correct position to support system operation. The inspectors also verified that PSEG properly utilized its corrective action program to identify and resolve equipment alignment problems that could cause initiating events or impact the capability of mitigating systems or barriers. Documents reviewed are listed in the Attachment A.
" Unit 1, 12 service water (SW) header while hardened to support planned unavailability of the 11 SW header;
" Unit 2, 2B and 2C EDG with 2A EDO OOS.
.2 Complete Walk down
a. Inspection Scope
The inspectors conducted one complete walk down inspection sample of the Unit 1 safety injection (SI) system on June 28 through 30, 2010. The inspectors independently verified the alignment and status of SI pump and valve electrical power, labeling, hangers and supports, and associated support systems. The walk down also included evaluation of system piping and equipment to verify pipe hangers were in satisfactory condition, oil reservoir levels were normal, pump rooms and pipe chases were adequately ventilated, system parameters were within established ranges, and equipment deficiencies were appropriately identified. The inspectors interviewed engineering personnel and reviewed corrective action evaluations associated with the system to determine whether equipment alignment problems were identified and appropriately resolved. Documents reviewed are listed in the Attachment A.
b. Findings
No findings of significance were identified.
I
R05 Fire Protection
- 1 Fire Protection - Tours
a. Inspection Scope
The inspectors completed six fire protection quarterly inspection samples. The inspectors walked down the systems listed below to assess the material condition and operational status of fire protection features. The inspectors verified that combustibles and ignition sources were controlled in accordance with PSEG's administrative procedures; fire detection and suppression equipment was available for use; that passive fire barriers were maintained in good material condition; and that compensatory measures for out of service (OOS), degraded, or inoperable fire protection equipment were implemented in accordance with PSEG's fire plan. Documents reviewed are listed in the Attachment A.
- Unit 1, auxiliary building, 84' elevation inside the charging pipe alley;
- Unit 1, electrical penetration, 78' elevation;
- Unit 1, AFW pumps area, 84' elevation;
- Unit 1, diesel fuel oil storage area, 84' elevation;
- Unit 2, diesel fuel oil storage area, 84' elevation; and
- Unit 1, containment during the RFO.
b. Findings
No findings of significance were identified.
1R07 Heat Sink Performance
a. Inspection Scope
The inspectors completed one annual heat sink performance inspection sample. The inspectors reviewed performance data and interviewed the NRC Generic Letter (GL) 89-13 program manager to verify that potential HX or heat sink deficiencies were identified and PSEG adequately resolved heat sink performance problems. Specifically, the inspectors reviewed 12B component cooling water (CCW) HX data. Inspectors evaluated trending data and verified that equipment would perform satisfactorily under design basis conditions. The method of performance monitoring was compared to the guidance provided in NRC GL 89-13, "Service Water System Problems Affecting Safety-Related Equipment," and Electric Power Research Institute NP 7552, "HX Performance Monitoring Guidelines." Documents reviewed are listed in the Attachment A.
b. Findings
No findings of significance were identified.
1
R08 Inservice Inspection (ISI)
a. Inspection Scope
The inspector observed a selected sample of nondestructive examination (NDE)activities in process. Also, the inspector reviewed the records of selected additional samples of completed NDE and repair/replacement activities. The sample selection was based on the inspection procedure objectives and risk priority of those components and systems where degradation would result in a significant increase in risk of core damage.
The observations and documentation reviews were performed to verify that the activities inspected were performed in accordance with the American Society of Mechanical Engineers (ASME) Boiler and Pressure Vessel Code requirements.
The inspector reviewed the licensee's performance of a visual inspection (VT) of the Unit 1 reactor vessel closure head (RVCH) and the installed upper head penetrations. The inspector reviewed the visual procedure, the qualifications of the personnel and reviewed the inspection report documenting the inspection results. The inspector also reviewed the data sheets for the penetrant tests completed on three of the penetration welds of the RVCH.
The inspector reviewed records for ultrasonic testing (UT), visual testing (VT), penetrant testing (PT) and magnetic particle testing (MT) NDE processes. PSEG did not perform any radiographic testing (RT) during this outage. The inspector reviewed inspection data sheets and documentation for these activities to verify the effectiveness of the examiner, process, and equipment in identifying degradation of risk significant systems, structures and components and to evaluate the activities for compliance with the requirements of ASME Code, Section Xl.
Steam Generator Inspection Activities The inspectors reviewed a sample of the Unit 1 steam generator eddy current testing (ECT) tube examinations, and applicable procedures for monitoring degradation of steam generator tubes to verify that the steam generator examination activities were performed in accordance with the rules and regulations of the steam generator examination program, Salem Unit 1 steam generator examination guidelines, NRC Generic Letters, 10CFR50, technical specifications for Unit 1, Nuclear Energy Institute 97-06, EPRI PWR steam generator examination guidelines, and the ASME Boiler and Pressure Vessel Code Sections V and XI. The review also included the Salem Unit 1 steam generator degradation assessment and steam generator Cycle 21 and 22 operational assessment. The inspector also verified the individual certifications for personnel participating in the SG ECT inspections during the 1 R20 refueling outage. The inspector reviewed PSEG's efforts in identifying wear degradation to the tubing in the four SGs at Unit 1. The majority of the identified wear indications were attributed to anti vibration bar (AVB) wear in the u bend regions of the four SGs. The inspector reviewed the analyses and evaluations that determined that a total of 14 SG tubes would be removed from service by plugging.
Boric Acid Corrosion Control Progiram Activities The inspector reviewed the PSEG boric acid corrosion control program. The resident inspectors observed PSEG personnel performing boric acid walkdown inspections, inside containment, and in other affected areas outside of containment, at the beginning of the Unit 1 refueling outage. The inspectors reviewed the notifications generated by the walkdowns and the evaluations conducted by Engineering to disposition the notifications. Additionally, the inspector reviewed a sample of notifications and corrective actions completed to repair the reported conditions.
Section XI Repair/Replacement Samples:
AFW System Piping, Control Air & Station Air: The inspectors reviewed PSEG's discovery, reporting, evaluation and the repair/replacement of Unit 1 AFW piping that was excavated for inspection during the April 2010 Unit 1 refueling outage (1R20).
PSEG conducted this inspection in accordance with PSEG's Buried Piping Inspection Program. Additionally, the inspectors reviewed the UT testing results performed to characterize the condition of the degraded Unit 1 buried AFW piping.
The inspector also reviewed the repair/replacement work orders and the 50.59 screening and evaluation for the AFW, CA and SA piping. The inspectors reviewed the fabrication of the replacement piping, reviewed the documentation of the welding and NDE of the replacement piping and reviewed the pressure tests used to certify the replacement piping. Additionally, the inspector reviewed the specified replacement coating, the application of the replacement coating and the backfill of the excavated area after the piping had been tested.
The inspector reviewed the finite element analysis (FEA) results from PSEG's past operability analysis on the affected Unit 1 buried AFW piping completed by the licensee in order to demonstrate past operability at a reduced system pressure of 1275 psig. The design pressure of the AFW system is 1950 psig.
The inspector also reviewed the UT testing results (approximately 400) performed on portions of the Unit 2 AFW buried piping, in response to the conditions observed on Unit 1 AFW buried piping to determine if degradation existed on the Unit 2 buried AFW piping.
Reiectable Indication Accepted For Service After
Analysis:
The inspector reviewed the Notification and the UT data report of a rejectable wall thickness measurementon the #11 SG feedwater elbow during 1R20. The inspector reviewed the additional wall thickness data taken to further define the condition and reviewed the finite element analysis (FEA) which verified that sufficient wall thickness remained to operate the component until the next refueling outage when it will be replaced.
b. Finding
Introduction.
The inspector identified a Green non-cited violation (NCV) of 10 CFR 50.55a(g)(4) and the referenced American Society of Mechanical Engineers (ASME)
Code,Section XI, paragraph IWA-5244 for PSEG's failure to perform required pressure tests of buried AFW components for Salem Unit 1.
Description.
Portions of the Unit 1 and Unit 2 AFW system piping is buried piping and has not been visually inspected since the plant began operation in 1977 for Unit 1 and since 1979 for Salem Unit 2. This piping is safety related, 4.0" ID, ASME Class 3, Seismic Class 1 piping. In April 2010, approximately 680 ft. (340 ft. of the #12 SG AFW supply and 340 ft. of the #14 SG AFW supply) of piping between the pump discharge manifold and the connection to the main feedwater piping to the affected SGs was discovered to be corroded to below minimum wall thickness (0.278") for the 1950 psi design pressure of the AFW System. The discovery was noted by PSEG during a planned excavation implementing their buried pipe inspection program. The lowest wall thickness measured in the affected piping was 0.077". The affected Unit 1 piping was replaced. Although no leakage was evident as a result of the corrosion, the inspector questioned PSEG about whether the IWA-5244 periodic pressure tests had been conducted on this underground piping.
10 CFR 50.55(a)(g)(4)(ii) requires licensees to follow the in-service requirements of the ASME Code,Section XI. Paragraph IWA-5244 of Section Xl requires licensees to perform system pressure tests on buried components to demonstrate the structural integrity of the tested piping. The system pressure test required by IWA-5244 is considered to be an inservice inspection and is part of Section Xl. Section Xl and IWA-5244 do not specify other non-destructive examinations (NDE) on buried components to demonstrate structural integrity other than a flow test ifthe system pressure test cannot be performed. PSEG had not performed the required tests for Unit 1 since 1988. Thus, PSEG did not perform the inservice inspection provided by the ASME Code, Section Xl, intended to demonstrate the structural integrity of this safety related buried piping.
PSEG was aware of the need to perform these required tests because they sought relief, from the NRC, from the previous Code required pressure testing in 1988 for Unit 1 only.
Relief was granted to PSEG, by the NRC, to perform an alternate flow test in 1991 for Unit 1. However, PSEG did not perform the proposed alternate flow tests for Unit I since 1988. Thus, PSEG had a chance to foresee and correct this performance deficiency, but missed the opportunity at the time of processing the final results of the relief request. PSEG replaced the affected Unit 1 buried piping during the refueling outage in April/May 2010. The required pressure tests were successfully completed after the replacement of the Unit 1 buried piping. PSEG determined that the buried portions of AFW maintained structural integrity because the AFW system functioned as required during the plant shutdown prior to the start of 1R20 (April 2010) and based upon the results of a finite element analysis PSEG conducted using as-found UT readings of excavated portions of the Unit 1 piping.
As part of the extent of condition for the testing issue identified on Unit 1, PSEG reviewed the status of ISI testing for Unit 2 AFW and determined that the testing had not been performed since 2001. PSEG currently plans to excavate the Unit 2 buried piping for inspection during the Unit 2 refueling outage scheduled for the spring of 2011. PSEG also completed an operability determination and risk assessment to justify continued operation until the next refueling outage. These evaluations determined that the condition was acceptable for continued operation until spring 2011. At present, it was not feasible to conduct the system pressure test or alternate flow test while at power, and to date there has been no detected degradation of the coating or piping on the Unit 2 buried AFW piping.
Analysis.
Visual inspections and UT measurements completed by PSEG on Unit 1 AFW buried piping in April 2010 identified degraded pipe coating and wall thinning on a portion of the excavated pipe. Considering the effect of this identified degradation, not performing the ASME Code,Section XI, paragraph IWA-5244 required pressure test at the required frequency for this normally inaccessible buried piping would result in an undetected loss of structural integrity for buried Unit 1 AFW discharge piping. The inspectors determined this was a performance deficiency.
This performance deficiency was more than minor because, if left uncorrected, it would have resulted in a more significant condition. Specifically, in light of the as-found degraded conditions of the coating and the piping discovered during excavation in Unit 1, an undetected failure of the piping would have resulted due to further continued, undetected corrosion, and continued pipe wall degradation eventually resulting in the loss of structural integrity and inoperability of the Unit 1 AFW system.
The inspector screened this performance deficiency using IMC 0609, Attachment 0609.04, "Phase 1 Initial Screening and Characterization of Findings." This finding impacts the Mitigating Systems cornerstone by adversely affecting the secondary, short term decay heat removal capability. Because the finding was not a design or qualification deficiency, did not result in an actual loss of safety function, and was not potentially risk significant for external events, the inspector determined that the finding screened to Green, very low safety significance for Unit 1.
The inspector determined that a cross cutting aspect did not exist because the issue was not indicative of current performance because the condition existed since 1991, more than 3 years ago. Specifically, the failure to perform these pressure tests began in 1988 when PSEG requested relief from the requirement and did not incorporate the actions of the relief into the plant inservice inspection program when it was granted in 1991.
Enforcement.
10 CFR 50.55a(g)(4) states, in part: "Throughout the servicelife of a boiling or pressurized water-cooled nuclear power facility, components which are classified as ASME Code Class 1, Class 2 and Class 3 must meet the requirements, set forth in Section XI of editions of the ASME Boiler and Pressure Vessel Code".
Paragraph IWA-5244, Buried Components, of Section Xi says, in part:
"(b) For buried components where a VT-2 visual examination cannot be performed, the examination requirement is satisfied by the following:
- (1) The system pressure test for buried components that are isolable by means of valves shall consist of a test that determines the rate of pressure loss. Alternatively, the test may determine the change in flow between the ends of the buried components. "
Contrary to these requirements, PSEG did not perform the required pressure tests of the buried AFW piping to the #12 SG and #14 SG at Salem Unit 1. Specifically, from February 1988 to April 2010 the required pressure tests were not performed to demonstrate structural integrity on the affected buried Unit 1 AFW piping during the 2nd In Service Inspection Interval (2/27/88 to 5/19/01 ) and during the 1t (5/19/01 to 6/3/04)and 2n (6/24/04 to 5/20/08) periods of the Td 3 In Service Inspection Interval (5/19/01 to 5/19/11).
Because PSEG entered this condition for Salem Unit 1 into the corrective action process (Notification 20459686) and because it is of very low safety significance (Green), it is being treated as a non-cited violation consistent with Section VI.A.1 of the NRC Enforcement Policy. NCV 50-27212010003-01, Buried AFW Discharge Piping Not Tested In Accordance With 10 CFR 50.55a.
1R11 1 Licensed Operator Requalification Program
.1 Requalification Activities Review by Resident Staff
a. Inspection Scope
The inspectors completed one quarterly licensed operator requalification program inspection sample. Specifically, the inspectors observed a scenario administered to a single crew during an emergency preparedness drill on May 18, 2010. The scenario included a crane damaging the AFW storage tank, a small reactor coolant leak, a rod ejection that resulted in a small break loss-of-coolant accident, and a rupture to containment spray piping that resulted in a loss of containment integrity.
The inspectors reviewed operator implementation of the abnormal and emergency operating procedures. The inspectors examined the operators' ability to perform actions associated with high risk activities, the Emergency Plan, previous lessons learned items, and the correct use and implementation of procedures. The inspectors observed and verified that deficiencies were adequately identified, discussed, and entered into the CAP, as appropriate. Documents reviewed are listed in the Attachment A.
b. Findings
No findings of significance were identified.
1R12 Maintenance Effectiveness (7111
.12 Q - 3 samples)
a. Inspection Scope
The inspectors completed three quarterly maintenance effectiveness inspection samples. The inspectors reviewed performance monitoring and maintenance effectiveness issues for the three systems listed below. The inspectors reviewed PSEG's process for monitoring equipment performance and assessing preventive maintenance effectiveness. The inspectors verified that systems and components were, monitored in accordance with the Maintenance Rule Program requirements. The inspectors compared documented functional failure determinations and unavailability hours to those being tracked by PSEG to evaluate the effectiveness of PSEG's condition monitoring activities and to determine whether performance goals were being met. The inspectors reviewed applicable work orders, corrective action notifications, and preventive maintenance tasks. The documents reviewed are listed in the Attachment A.
- Unit 1 and Unit 2, radiation monitors;
- Unit 2, steam generator feed pumps; and
- Unit 1, service water.
b. Findings
Introduction:
A self-revealing finding of very low safety significance was identified on January 21, 2010, because a control system short circuit caused the 21 SGFP to trip.
This caused a turbine runback and ultimately an automatic Unit 2 reactor trip due to low water level in one of four SGs. The short circuit occurred because technicians did not use the correct procedure to repair degraded insulation on the barrel of a connector lug that was identified in the 21 SGFP control system in November 2009. PSEG repaired the short circuit prior to restart of Unit 2 on January 23, 2010. The issue was entered into the corrective action program as notification 20448229.
Description:
On January 21, 2010, the 21 SGFP tripped due to a short circuit between the normally closed and normally open terminals for the 21 SGFP low suction pressure trip switch. The short circuit caused a false low suction pressure trip signal that'tripped the 21 SGFP, which caused a turbine runback to 66%. This runback was designed to lower the steam flow demanded from the SGs to within the capacity of the SGFP that did not trip. However, on January 21, the reduction in power was not rapid enough and Salem Unit 2 automatically tripped from 78% power due to low steam generator water level.
Following the trip technicians identified that the electrical short that caused the trip had developed between a connector lug barrel and an adjacent wire terminal due degraded wire insulation on the lug barrel. The technicians also determined that this same short was previously identified as the cause of the difficulty that operators had resetting the 21 SGFP on November 11, 2009, during the Unit 2 startup after the S2R17 refueling outage. To address the.condition identified in November 2009, the technicians covered the affected connector lug barrel with electrical tape. This allowed operators to restore the 21 SGFP to service and continue the Unit 2 start-up. The reset problems for the 21 SGFP repeated again on January 5, 2010, during the Unit 2 plant startup after the January 3, 2010 plant trip. However, troubleshooting in early January did not identify a cause for the trip and the 21 SGFP was ultimately successfully reset and restored to service with no corrective actions completed.
PSEG conducted a root cause investigation after the January 21, 2010, trip and determined the root cause was poor work practices during initial component installation and subsequent maintenance activities. Specifically, improper orientation of the lug put the lug barrel and wire terminal in contact with one another, which subsequently caused the lug barrel insulation to degrade ultimately resulting in the short circuit.
The inspectors determined that the corrective actions taken by technicians when they originally identified the short between the lug barrel and wire terminal in November 2009, were not adequate. As stated above, to correct the short, technicians covered the affected insulation with electrical tape. The inspectors reviewed PSEG procedure SC.DE-TS.ZZ-2039, "Cable Termination Methods at Salem Generating Station," and determined that applying tape to the barrels of lugs was not permitted. Therefore, the corrective actions taken by technicians to address the degraded condition identified in November 2009, did not meet PSEG procedure requirements and resulted in the 21 SGFP trip that cause the Unit 2 reactor trip on January 21, 2010.
PSEGs corrective actions following the January 21, 2010 included performing extent of condition inspections on the other Unit 2 SGFP panels for degraded insulation no other deficiencies were identified. Following completion of the root cause analysis additional extent of condition inspections for connector lug orientation were specified. Unit 1 inspections were completed in April 2010 and no deficiencies were identified. Unit 2 inspections are scheduled for the next refueling outage in 2011. PSEG entered corrective action issues for this event into the corrective action program as NOTF 20448229.
To improve the reliability of the plant operations in response to a single SGFP trip, PSEG installed an automatic plant runback feature in the 1990s. The inspectors confirmed that this feature was not credited in the plant's accident analysis, and therefore, determined that the failure of the runback to prevent a reactor trip after the 21 SGFP tripped on January 21 was not a safety concern. PSEG's plans to review the causes of the ineffective runback as part of the response to correction action program NOTF 20448229.
Analysis:
Not performing repairs to the affected 21 SGFP pressure switch lug barrel in accordance with PSEG SC.DE-TS.ZZ-2039, "Cable Termination Methods at Salem Generating Station," resulted in a short circuit that caused a 21 SGFP trip that resulted in a Unit 2 reactor trip due to low SG water level. This was a performance deficiency. The inspectors determined that the performance deficiency was more than minor because it was associated with the human performance attribute of the Initiating Events cornerstone, and it adversely affected the cornerstone objective to limit the likelihood of events that upset plant stability and challenge critical safety functions. Specifically, not following PSEG procedure SC.DE-TS.ZZ-2039 on November 11, 2009, caused the 21 SGFP trip and subsequent automatic reactor trip due to low SG water level on January 21, 2010. The finding was evaluated under IMC 0609, Attachment 4, "Phase 1 - Initial Screening and Characterization of Findings." The inspectors determined that the finding is of very low safety significance because it does not contribute to both the likelihood of a reactor trip and the likelihood that mitigation equipment or functions will not be available.
The inspectors determined that this finding has a cross-cutting aspect in the area of human performance because PSEG personnel did not follow procedure requirements while repairing plant equipment. Specifically, technicians applied electrical tape to the 21 SGFP pressure switch connector lug barrel on November 11, 2009, which did not meet PSEG procedure SC.DE-TS.ZZ-2039, "Cable Termination Methods at Salem Generating Station," requirements. (H.4 (b))
Enforcement:
Enforcement action does not apply because the performance deficiency did not involve a violation of a regulatory requirement: FIN 0500031112010003-02, 21 Steam Generator Feed Pump Trip.
R13 Maintenance Risk Assessments and Emerqent Work Control
a. Inspection Scope
The inspectors completed five maintenance risk assessment and emergent work control inspection samples. The inspectors reviewed the maintenance activities listed below to verify that the appropriate risk assessments were performed as specified by 10 CFR 50.65(a)(4) prior to removing equipment for work. The inspectors reviewed the applicable risk evaluations, work schedules, and control room logs for these configurations. PSEG's risk management actions were reviewed during shift turnover meetings, control room tours, and plant walkdowns. The inspectors also used PSEG's on-line risk monitor (Equipment OOS workstation) to gain insights into the risk associated with these plant configurations. The inspectors reviewed notifications documenting problems associated with risk assessments and emergent work evaluations. Documents reviewed are listed in the Attachment A.
- Unit 1 and Unit 2, planned unavailability of Unit 1 control room emergency air conditioning system to support planned maintenance on the 1A 125 VDC electrical bus on April 7;
- Unit 1, planned unavailability of the IA EDG and 14 station power transformer during a RFO on April 8;
- Unit 1, contingency measures to provide alternate power to the 12 spent fuel pool (SFP) pump during unavailability of the 1B 4kV vital bus on April 12;
- Unit 1, unplanned unavailability of the 1C 4kV vital bus concurrent with planned unavailability of the 1B EDG and 11 SW header on April 16;
" Unit 2, planned unavailability of the 2A EDG with station blackout Unit 3 out of service on May 27.
b.
Findingis No findings of significance were identified.
R15 Operability Evaluations
a. Inspection Scope
The inspectors completed eight operability evaluation inspection samples. The inspectors reviewed the operability determinations for degraded or non-conforming conditions associated with:
" Unit 1 and Unit 2 EDGs given potential degradation of shutdown relays SDR, SR and SRA;
- Unit I boration flowpath following unplanned unavailability of the 1C 4kV vital bus while in Mode 6;
- Unit 1 SW system given early installation of restraints on pipe support SWPS-5;
- Unit 1 CCW system during planned unavailability of the 11 CCW HX and biofouling of the 12A/B CCW HX;
- Unit 1 AFW piping following discovery of wall thinning of buried piping;
The inspectors reviewed the technical adequacy of the operability determinations to ensure the conclusions were justified. The inspectors also walked down accessible equipment to corroborate the adequacy of PSEG's operability determinations.
Additionally, the inspectors reviewed other PSEG identified safety-related equipment deficiencies during this report period and assessed the adequacy of their operability screenings. Documents reviewed are listed in the Attachment A.
b. Findings
No findings of significance were identified.
1R18 Plant Modifications
.1 Permanent Modifications
a. Inspection Scope
The inspectors completed two permanent plant modification inspection samples by reviewing the key characteristics associated with the two permanent plant modifications described below. The inspectors' review verified that the design bases, licensing bases, and performance capability of the affected systems were not degraded by the modifications. The inspectors verified the new configuration was accurately reflected in the design documentation and that the post-modification testing was adequate to ensure the structures, systems, and components affected would continue to function properly.
t The inspectors' also interviewed plant staff and reviewed issues that were entered into the CAP to assess whether PSEG was effective at identifying and resolving problems associated with the modification process. The 10 CFR 50.59 screening associated with these permanent plant modifications were also reviewed. The documents reviewed are listed in the Attachment A.
" The inspectors reviewed the modification package used to replace the section of buried Unit 1 AFW discharge header piping located between the Unit 1 auxiliary and containment buildings. PSEG replaced this section of piping because significant coating degradation and external corrosion and wall thinning was identified on the piping during inspections conducted in preparation for license renewal.
" The inspectors reviewed the modification package used to replace the Unit 1 PS-1 pressurizer spray valve internals. The purpose of the new design was to provide better flow control characteristics and reduce the valve's susceptibility to sticking.
b. Findings
No findings of significance were identified.
.2 Temporary Modifications
a. Inspection Scope
The inspectors completed two plant modification inspection samples by reviewing the key characteristics associated with the two temporary plant modifications described below. The inspectors verified that the design bases, licensing bases, and performance capability of the affected systems were not degraded by the temporary modifications.
The 10 CFR 50.59 screen associated with each modification were also reviewed.
Documents reviewed for this inspection are listed in the Attachment A.
" The inspectors reviewed the modification package used to supply temporary power to the 12 SFP pump. The modification moved the 12 SFP pump power supply from the 1B 460 VAC vital bus to the IA 460 VAC vital bus to provide SFP cooling capacity from both the 11 and 12 SFP pumps while the 1 B 460 VAC vital bus was de-energized for planned maintenance.
" The inspectors reviewed the modification package used to plug a Unit 1 feedwater flow control valve (1 3BF1 9) air supply regulator weep hole in order to ensure that full pressure was used to position the air-operated valve.
b. Findings
No findings of significance were identified.
1R19 Post-Maintenance Testing
a. Inspection Scope
The inspectors completed six post-maintenance testing (PMT) inspection samples. The inspectors observed portions of and/or reviewed the PMT results for the maintenance activities listed below. The inspectors verified that the effect of testing on the plant was adequately addressed by control room and engineering personnel; testing was adequate for the maintenance performed; acceptance criteria were clear, demonstrated operational readiness and were consistent with design and licensing basis documentation; test instrumentation calibration was current and the appropriate range and accuracy for the application; tests were performed, as written, with applicable prerequisites satisfied; and equipment was returned to an operational status and ready to perform its safety function. Documents reviewed are listed in the Attachment A.
- Work order (WO) 30156599, preventive maintenance of the 1A vital instrument bus inverter;
- WO 30171818, planned overhaul of the 1B EDG during Unit 1 RFO;
- WO 60090348, replacement of shaft and pins on 21 CCW HX inlet valve, 21 SW 122;
- WO 60090391, replacement of shaft and pins on 22 CCW HX inlet valve, 22 SW 122;
- WO 30152753, preventive maintenance of the 22 AFW pump; and
, WO 60088790, temporary repair of an oil leak on 21 SI pump outboard bearing.
b. Findings
No findings of significance were identified.
1R20 Refueling and Other Outage Activities
a. Inspection Scope
Unit 1 RFO (S1 R20). The inspectors completed one refueling outage activity inspection sample. The inspectors observed or reviewed the following RFO activities to verify that operability requirements were met and that risk, industry experience, the fatigue rule, and previous site specific problems were considered. Documents reviewed are listed in the Attachment A.
The inspectors reviewed the schedule and risk assessment documents associated with S1R20 to confirm that PSEG appropriately considered risk, operating experience, and site specific problems in developing and implementing a plan that ensured maintenance of defense-in-depth systems and barriers. Prior to S1 R20, the inspectors reviewed PSEG's outage risk assessment to identify risk significant equipment configurations and determine whether planned risk management actions were adequate. During S1R20, the inspectors verified that PSEG managed the outage risk in accordance with the outage plan.
The inspectors observed portions of the shutdown and cool down processes and monitored PSEG controls over the outage activities. The inspectors also verified that cool down rates were within technical specification (TS) limitations. The inspectors entered containment at the start of the refuel outage to check for evidence of previously unidentified reactor coolant leakage. Throughout S1 R20, the inspectors made additional containment entries to inspect for indications of unidentified leakage, damaged equipment, foreign material control, radiation worker work practices and fire prevention.
The inspectors observed portions of refueling activities from the refueling bridge in containment and the SFP to verify refueling gates and seals were properly installed and verify that foreign material exclusion boundaries were established around the reactor cavity. Core offload and core reload activities were periodically observed from the control room and refueling bridge to verify operators adequately controlled fuel movements in accordance with approved procedures.
The inspectors verified that tagged equipment was properly controlled and equipment configured to safely support maintenance work. Specifically, inspectors observed the control of work activities in the auxiliary building during reduced inventory to verify that the risk of unplanned equipment unavailability was minimized. Equipment work areas were periodically observed to determine whether foreign material exclusion boundaries were adequate.
During control room tours, the inspectors verified that operators maintained adequate reactor coolant system (RCS) level and temperature and that indications were within the expected range for the operating mode.
The inspectors verified that offsite and onsite'electrical power sources were maintained in accordance with TS requirements and consistent with the outage risk assessment.
Periodic walk downs of portions of the on-site electrical buses and the EDGs were conducted during risk significant electrical configurations.
The inspectors verified through routine plant status activities that the decay heat removal safety function was maintained with the appropriate redundancy as required by TS and consistent with PSEG's outage risk assessment. During core offload, the inspectors periodically verified that the fuel pool cooling system was performing in accordance with plant design parameters and consistent with PSEG's risk assessment for the RFO.
The inspectors observed the Unit I RCS draining to a reduced inventory condition on April 19, 2010. RCS inventory controls and contingency plans were reviewed by inspectors to verify that they met TS requirements and provided for adequate inventory control. The inspectors reviewed procedures and observed portions of activities in the control room when the unit was in reduced inventory modes of operation. The inspectors verified that level and core temperature measurement instrumentation were installed and operational. Calculations that provided time to boil information were also reviewed for RCS reduced inventory conditions as well as the SFP during increased heat load conditions.
Inspectors verified that PSEG managed fatigue of outage workers by reviewing a sampling of waiver requests, self declarations, and fatigue assessments that were available near the end of the RFO. PSEG scheduled covered workers such that minimum days off for individuals working on outage activities were in compliance with the fatigue rule. In addition, control room staff for Unit 2 remained on operating unit work hour controls.
Containment status and procedural controls were reviewed by the inspectors during fuel offload and reload activities to verify that TS and procedure requirements were met for containment. Specifically, the inspectors verified that during fuel movement activities, personnel, materials, and equipment were staged to close containment penetrations as specified in the licensing basis.
The inspectors conducted a thorough walk down of containment prior to reactor startup.
Areas of containment whe're work was completed were inspected for evidence of leakage and to ensure debris that could block containment sump screens was removed.
The condition of equipment used for fire detection, prevention, and suppression were inspected for operability and functionality. Portions of mode changes and reactor startup were observed and reviewed for compliance with applicable procedures and TS.
b. Findings
No findings of significance were identified.
1
R22 Surveillance Testing
a. Inspection Scope
The inspectors completed nine surveillance testing inspection samples. The inspectors observed portions of and/or reviewed results for the surveillance tests listed below to verify, as appropriate, whether the applicable system requirements for operability were adequately incorporated into the procedures and that test acceptance criteria were consistent with procedure requirements, the TS requirements, the updated final safety analysis report (UFSAR), and American Society of Mechanical Engineers (ASME)
Section XI for pump and valve testing. Documents reviewed are listed in the Attachment A.
- S1.OP-ST.RHR-0005, Residual Heat Removal Valves and Orifices;
- S1.OP-ST.MS-0003, Steam Line Isolation and Response Time Testing;
- S1.OP-ST.TRB-0002, Turbine Protection System - Full Functional Test;
- Si.OP-ST.SJ-001 5, Intermediate Head Hot Leg Throttling Valve Flow Balance Verification;
- SC.MD-DC.RC-0003, Calibration of Pressurizer Safety Relief Valve Indicating Switches;
- S1.OP-ST.AF-0007, 13 AFW Pump Full Flow Test;
- S2.OP-ST.SJ-0001, Inservice Testing of 21 Safety Injection Pump;
- S1.OP-LR. FP-0001, Type C Leak Rate Test for 1FP147 and 1FP148; and
- S1.OP-LR.CVC-0003, Type C Leak Rate Test for 1CV116, 1CV284, and 1CV296.
b. Findings
No findings of significance were identified.
1
EP6 Drill Evaluation
a. Inspection Scope
The inspectors completed one drill evaluation inspection sample. On May 18, 2010, the inspectors observed a drill from the control room simulator during an evaluated emergency preparedness drill. The inspectors evaluated operator performance relative to developing event classifications and notifications. The inspectors referenced Nuclear Energy Institute (NEI) 99-02, "Regulatory Assessment Performance Indicator (PI)
Guideline," Revision 6, and verified that PSEG correctly counted the evaluated scenario's contribution to the NRC PI for drill and exercise performance.
b. Findings
No findings of significance were identified.
RADIATION SAFETY
Cornerstone: Radiation Safety - Public and Occupational
2RS1 Radiological Hazard Assessment and Exposure Controls
a. Inspection Scope
Radiological Hazard Assessment The inspectors reviewed any changes to plant operations that may result in a significant new radiological hazard for onsite workers or members of the public. The inspectors verified PSEG had assessed the potential impact of thesechanges and implemented periodic monitoring, as appropriate, to detect and quantify the radiological hazard.
The inspectors reviewed a sample of two completed radiological surveys of selected plant areas. The inspectors verified that the thoroughness and frequency of the surveys were appropriate for the given radiological hazard.
The inspectors conducted walk downs of the plant that included radioactive waste processing, storage, and handling areas to evaluate material conditions and potential radiological conditions.
The inspectors selected radiological risk-significant work activities that involved exposure to radiation and were performed during Unit l's RFO. Activities selected included: primary steam generator work including eddy current testing, secondary steam generator work including foreign object search and retrieval, and replacement of the #14 reactor coolant pump motor. The inspectors verified that appropriate pre-work surveys were performed and were appropriate to identify and quantify the radiological hazard and to establish adequate protective measures.. The inspectors evaluated the radiological survey program to determine if the following hazards were properly identified:
- Identification of hot particles;
- The presence of alpha emitters;
- The potential for airborne radioactive materials, including the potential presence of transuranics and/or other hard-to-detect radioactive materials;
- The hazards associated with work activities that could suddenly and severely increase radiological conditions; and
- Severe radiation field dose gradients that can result in non-uniform exposures to the body.
The inspectors selected three to five air sample survey records and verified that samples were collected and counted in accordance with PSEG procedures. The inspectors observed work in potential airborne areas and verified that air samples were representative of the breathing air zone. The inspectors verified that PSEG has a program for monitoring levels of loose surface contamination in areas of the plant with the potential for the contamination to become airborne.
Radiological Hazards Control and Work Coverage During tours of the facility and review of ongoing work selected in Section 2 (above), the inspectors evaluated ambient radiological conditions. The inspectors verified that existing conditions were consistent with posted surveys, radiation work permits (RWPs),and worker briefings, as applicable.
During job performance observations, the inspectors verified the adequacy of radiological controls, such as required surveys, radiation protection job coverage, and contamination controls. The inspectors evaluated PSEG's means of using electronic pocket dosimeters in high noise areas as high radiation area (HRA) monitoring devices, The inspectors verified that radiation monitoring devices were placed on the individual's body consistent with the method that PSEG has employed to monitor dose from external radiation sources:. The inspectors verified that the dosimeter was placed in the location of highest expected dose or that PSEG was properly employing an NRC-approved method of determining effective dose equivalent.
For high-radiation work areas with significant dose rate gradients (a factor of 5 or more), the inspectors reviewed the application of dosimetry to effectively monitor exposure to personnel. The inspectors verified that PSEG's controls were adequate.
The inspectors reviewed three to five RWPs for work within airborne radioactivity areas with the potential for individual worker internal exposures. The inspectors evaluated airborne radioactive controls and monitoring, including potentials for significant airborne contamination. For these selected airborne radioactive material areas, the inspectors verified barrier integrity and temporary high-efficiency particulate air ventilation system operation.
The inspectors examined PSEG's physical and programmatic controls for highly activated or contaminated materials stored within spent fuel and other storage pools.
The inspectors verified that appropriate controls were in place to preclude inadvertent removal of these materials from the pool.
The inspectors conducted selective Inspection of posting and physical controls for HRAs and very high radiation areas, to the extent necessary to verify conformance with the Occupational PI.
b. Findingjs No findings of significance were identified.
2RS2 Occupational As- Low As Reasonably Achievable (ALARA) Planning and Controls
a. Inspection Scope
Radiological Work Planning The inspectors obtained from PSEG a list of work activities ranked by actual or estimated exposure that were in progress and selected three work activities of the highest exposure significance (listed in Section 2RS1 above).
The inspectors reviewed the ALARA work activity evaluations, exposure estimates, and exposure mitigation requirements. The inspectors determined that PSEG had reasonably grouped the radiological work into work activities, based on historical precedence, industry norms, and/or special circumstances.
The inspectors verified that PSEG's planning identified appropriate dose mitigation features, considered alternate mitigation features, and defined reasonable dose goals.
The inspectors verified that PSEG's ALARA assessment had taken into account decreased worker efficiency from use of respiratory protective devices and or heat stress mitigation equipment. The inspectors determined that PSEG's work planning considered the use of remote technologies as a means to reduce dose and the use of dose reduction insights from industry operating experience and plant-specific lessons learned.
The inspectors verified the integration of ALARA requirements into work procedure and RWP documents.
The inspectors compared the results achieved with the intended dose established in PSEG's ALARA planning for these work activities. The inspectors compared the person-hour estimates provided by maintenance planning and other groups to the radiation protection group with the actual work activity time requirements, and evaluated the accuracy of these time estimates. The inspectors determined the reasons for any inconsistencies between intended and actual work activity doses. The inspectors focused on those work activities with planned or accrued exposure greater than 5 person-rem.
The inspectors determined that post-job reviews were performed and that identified problems were entered into PSEG's CAP.
b. Findings
No findings of significance were identified.
OTHER ACTIVITIES
40A1 Performance Indicator (PI) Verification (71151 - 6 samples)
a. Inspection Scope
,The inspectors reviewed 'PSEG submittals for the Unit I and Unit 2 initiating events cornerstone performance indicators discussed below. To verify the accuracy of the PI data reported during this period the data was compared to the PI definition and guidance contained in NEI 99-02, "Regulatory Assessment Performance Indicator Guideline,"
Revision 5.
Cornerstone: Initiating Events
- Unit 1 and Unit 2 unplanned scrams;
- Unit 1 and Unit 2 unplanned scrams with complications; and
- Unit 1 and Unit 2 unplanned power changes.
The inspectors verified the accuracy of the data by comparing it to CAP records, control room operators' logs, the site operating history database, and key performance indicator summary records.
b. Findings
No findings of significance were identified.
40A2 Identification and Resolution of Problems (71152 - 1 annual sample; 1 trend sample)
Review of Items Entered into the Corrective Action Prociram As required by Inspection Procedure 71152, "Identification and Resolution of Problems,"
and in order to help identify repetitive equipment failures or specific human performance issues for follow-up, the inspectors performed a daily screening of all items entered into PSEG's CAP. This was accomplished by reviewing the description of each new notification and attending daily management review committee meetings. Documents reviewed are listed in the Attachment A.
.2 Semi-Annual Review to Identify Trends
a. Inspection Scope
As required by Inspection Procedure 71152, "Identification and Resolution of Problems,"
the inspectors performed a review of PSEG's CAP and associated documents to identify trends that could indicate the existence of a more significantsafety issue. The inspectors' review was focused on repetitive equipment and corrective maintenance issues, but also considered the results of daily inspector CAP item screening discussed in Section 40A2.1. The review included issues documented in system health reports, corrective maintenance WOs, component status reports, site monthly meeting reports and maintenance rule assessments. The inspectors' review nominally considered the six-month period of December 2009 through May 2010, although some examples expanded beyond those dates when the scope of the trend warranted. The inspectors compared and contrasted their results with the results contained in PSEG's latest integrated quarterly assessment report. Corrective actions associated with a sample of the issues identified in PSEG's trend report were reviewed for adequacy. The inspectors also evaluated the trend report specified in SPP-3.1, Corrective Action Program.
Documents reviewed are listed in the Attachment A.
b. Assessment and Observations No findings of significance were identified.
The inspectors noted a trend of low level issues entered into the CAP related to equipment reliability. There were multiple issues with service water flow control valves and issues with the Unit I steam generator flow control regulating valves. The inspectors also noted deficiencies with the scope, planning, and implementation of long term equipment preventive maintenance. Some of the preventive maintenance deficiencies have been corrected through implementation of a performance centered maintenance plan. PSEG is aware of the issues identified through this trend review and is appropriately addressing these issues.
.3 Annual Sample: Transformer Load Tap Changer Failures
a. Inspection Scope
The inspectors reviewed PSEG's actions to investigate and identify the cause of the 12 station power transformer load tap changer failure that resulted in a reactor trip on December 28, 2007. The inspectors also reviewed PSEG's action towards identification and completion of corrective actions. The inspectors reviewed PSEG's procedures, vendor documents, notifications, orders, corrective actions, and root cause evaluations to understand the equipment functions and operational history, as well as the identification, evaluation, and corrective actions associated with the load tap changer failures. System engineers and other PSEG staff were interviewed to gain additional insights on the failures. Documents reviewed are listed in the Attachment A.
b. Findings and Observations
No findings of significance were identified.
The inspectors found that PSEG appropriately identified degraded conditions associated with load tap changer failures and entered them into the CAP. PSEG's root cause investigation determined the cause of the load tap changer failure to be inadequate scope of maintenance procedures on load tap changer internal components and insufficient performance monitoring of degraded load tap changer conditions. The investigations revealed severe coking of the selector switch components, which included damage to four of the six collector rings, and melted contacts. Inspectors determined that the evaluations of degraded conditions were thorough and included considerations for extent of condition. The inspectors reviewed PSEG's corrective actions and determined that they were appropriate to adequately address identified deficiencies.
40A3 Event Follow-up (71153- 1 sample)
.1 (Closed) LER 05000311/2010-002-01, Automatic Reactor
Trip Due to 21 Steam Generator Feedwater Pump (SGFP) Trip and Steam Generator Low Level On January 21, 2010, at 1818 hours0.021 days <br />0.505 hours <br />0.00301 weeks <br />6.91749e-4 months <br />, the 21 SGFP tripped. A turbine runback automatically initiated as expected and steam generator level in all four steam generators (SG) lowered. The 22 SG reached the SG low level reactor trip setpoint at 1820 hours0.0211 days <br />0.506 hours <br />0.00301 weeks <br />6.9251e-4 months <br /> resulting in an automatic reactor trip. The turbine runback function initiated by the loss of 21 SGFP did not prevent a reactor trip as designed; however, this feature was not credited in the Salem accident analysis and, therefore, was not required to operate to maintain plant safety. All control rods fully inserted on the trip. All three AFW pumps started in response to the low SG water level and decay heat was removed by the steam dumps to the main condenser. Operators entered the emergency procedures for the plant trip and stabilized the plant in Mode 3.
The cause of the 21 SGFP trip was an internal wiring short in the SGFP control circuit that resulted in a false low suction pressure trip signal. The cause for the wiring short was the result of poor work practices. Corrective actions consist of lug inspections, document changes, training analysis, and evaluation of the integrated plant response to a SGFP from full power and implementing changes as appropriate. The inspectors completed a review of this LER and identified one finding of very low safety significance as documented in Section 1R12. This LER is closed.
b. Findings
The finding for this event is documented in Section 1 R1 2.
40A5 Temporary Instruction (TI) 2515/172
a. Inspection Scope
The Temporary Instruction (TI), 2515/172 provides for confirmation that owners of pressurized-water reactors (PWRs) have implemented the industry guidelines of the Materials Reliability Program (MRP) -139 regarding nondestructive examination and evaluation of certain dissimilar metal welds in the RCS containing nickel based Alloys 600/82/182.
During 1R20 PSEG inspected the dissimilar metal weld on the 1" reactor vessel drain piping with no detected indications. Salem Unit 1 has dissimilar metal welds in the eight reactor coolant system piping to reactor vessel nozzle safe end welds. No additional inspections or MSIP applications were performed during 1R20.
This TI requires documentation of specific questions in an inspection report. The questions and responses are included in this report as Attachment B.
b. Findings
No findings of significance were identified.
'27 40A6 Meetincqs, Including Exit The inspectors presented the inspection results to Mr. C. Fricker and other members of PSEG management at the conclusion of the inspection on July 8, 2010. The inspectors asked PSEG whether any materials examined during the inspection were proprietary.
No proprietary information was identified.
40A7 Licensee Identified Violations The following violation of NRC requirements was identified by PSEG. It was determined to have very low significance (Green) and to meet the criteria of Section VI of the NRC Enforcement Policy, NUREG-1600, for being dispositioned as a non-cited violation.
PSEG identified general corrosion that reduced the wall thickness of the safety related piping to less than the design minimum wall thickness of 0.278" for the system design pressure of 1950 psig. The lowest measured wall thickness was 0.077"; however, a finite element analysis for the degraded piping demonstrated past operability at a reduced operating pressure of 1275 psig.
10 CFR 50, Appendix B, Criterion Ill, Design Control requires in part that measures shall be established to assure that applicable regulatory requirements and design bases are correctly translated into specifications, drawings, and instructions and that these measures shall include provisions to assure the proper selection and review for suitability of application of materials, parts, equipment, and processes. During pipe excavation and inspections conducted as part of PSEGs buried piping program PSEG identified that it did not provide an effective protective coating for the buried section of AFW piping on Unit 1.
This finding was associated with the mitigating systems cornerstone, specifically the short term decay heat removal capability. The finding was determined to be Green because it was a design or qualification deficiency that was confirmed not to result in loss of operability of the AFW system. PSEG entered this condition into the corrective action program as notification 20456999.
ATTACHMENT A:
SUPPLEMENTAL INFORMATION
KEY POINTS OF CONTACT
Licensee personnel
- C. Fricker, Site Vice President
- E. Eilola, Plant Manager
- L. Rajkowski, Engineering Director
- R. DeSanctis, Maintenance Director
- J. Garecht, Operations Director
- R. Gary, Radiation Protection Manager
- J. Higgins, System Engineer
- F. Hummel, System Engineer
LIST OF ITEMS OPENED, CLOSED, AND DISCUSSED
Opened/Closed
- 05000272/2010003-01 NCV Buried AFW Discharge Piping Not Tested In Accordance With 10 CFR 50.55a (Section 1 R08)
- 05000311/2010003-02 FIN 21 Steam Generator Feed Pump Trip.
(Section 1R12)
Closed
- 05000311/2010-002-01 LER Automatic Reactor Trip Due to 21 SGFP Trip and Steam Generator Low Level (Section 40A3.2)