IR 05000354/2014005
| ML15036A006 | |
| Person / Time | |
|---|---|
| Site: | Hope Creek  |
| Issue date: | 02/05/2015 |
| From: | Glenn Dentel Reactor Projects Branch 3 |
| To: | Joyce T Public Service Enterprise Group |
| DENTEL, GT | |
| References | |
| IR 2014005 | |
| Download: ML15036A006 (39) | |
Text
February 5, 2015
SUBJECT:
HOPE CREEK GENERATING STATION UNIT 1 - NRC INTEGRATED INSPECTION REPORT 05000354/2014005
Dear Mr. Joyce:
On December 31, 2014, the U.S. Nuclear Regulatory Commission (NRC) completed an inspection at your Hope Creek Generating Station (HCGS). The enclosed inspection report documents the inspection results, which were discussed on January 20, 2015, with Mr. P.
Davison, Site Vice President of Hope Creek, and other members of your staff.
The inspection examined activities conducted under your license as they relate to safety and compliance with the Commissions rules and regulations and with the conditions of your license.
The inspectors reviewed selected procedures and records, observed activities, and interviewed personnel.
This report documents one self-revealing finding of very low safety significance (Green). The finding was determined to involve a violation of NRC requirements. However, because of the very low safety significance, and because it was entered into your corrective action program (CAP), the NRC is treating the finding as a non-cited violation (NCV) consistent with Section 2.3.2 of the NRC Enforcement Policy. If you contest this NCV, 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 HCGS. In addition, if you disagree with the cross-cutting aspect assigned to the finding, you should provide a response within 30 days of the date of this inspection report, with the basis for your disagreement, to the Regional Administrator, Region I, and the NRC Resident Inspector at HCGS. In accordance with Title 10 of the Code of Federal Regulations (10 CFR) 2.390 of the NRCs Rules of Practice, a copy of this letter, its enclosure, and your response (if any) will be available electronically for public inspection in the NRCs Public Document Room or from the Publicly Available Records component of the NRCs Agencywide Documents Access and Management System (ADAMS). ADAMS is accessible from the NRC website at http://www.nrc.gov/reading-rm/adams.html (the Public Electronic Reading Room).
Sincerely,
/RA/
Glenn T. Dentel, Chief Reactor Projects Branch 3 Division of Reactor Projects
Docket No.
50-354 License No:
Enclosure:
Inspection Report 05000354/2014005
w/Attachment: Supplementary Information
REGION I==
Docket No.
50-354
License No.
Report No.
Licensee:
Public Service Enterprise Group (PSEG) Nuclear LLC
Facility:
Hope Creek Generating Station (HCGS)
Location:
P.O. Box 236
Hancocks Bridge, NJ 08038
Dates:
October 1, 2014, through December 31, 2014
Inspectors:
J. Hawkins, Senior Resident Inspector
S. Haney, Resident Inspector J. Brand, Reactor Inspector A. DeFrancisco, Project Engineer M. Draxton, Project Engineer T. Fish, Senior Operations Engineer T. Hedigan, Operations Engineer R. Nimitz, Senior Health Physicist D. Orr, Senior Reactor Inspector
Approved By:
Glenn T. Dentel, Chief
Reactor Projects Branch 3
Division of Reactor Projects
Enclosure
SUMMARY
IR 05000354/2014005; 10/01/2014 - 12/31/2014; Hope Creek Generating Station; Operability
Determinations and Functionality Assessments.
This report covered a three-month period of inspection by resident inspectors and announced inspections performed by regional inspectors. One finding of very low safety significance (Green) was identified. The finding was determined to be a violation of NRC requirements.
The significance of most findings is indicated by their color (i.e., greater than Green, or Green,
White, Yellow, Red) and determined using Inspection Manual Chapter (IMC) 0609, Significance Determination Process (SDP), dated June 2, 2011. Cross-cutting aspects are determined using IMC 0310, Components Within Cross-Cutting Areas, dated December 4, 2014. All violations of NRC requirements are dispositioned in accordance with the NRCs Enforcement Policy, dated January 28, 2013. The NRCs program for overseeing the safe operation of commercial nuclear power reactors is described in NUREG-1649, Reactor Oversight Process,
Revision 5.
Cornerstone: Initiating Events
- Green.
A self-revealing Green non-cited violation (NCV) of Title 10 of the Code of Federal Regulations Part 50 (10 CFR) Part 50, Appendix B, Criterion XVI, Corrective Action, was identified when PSEG did not promptly identify and correct a condition adverse to quality.
Specifically, PSEG did not initiate a notification (NOTF) or perform an evaluation of a potential cold spring condition found in the H safety relief valve (SRV) discharge piping during the valves replacement in 2012. This condition caused a leak to develop on the main seat of the new SRV that proceeded to degrade during the operating cycle, ultimately causing Hope Creek to shut down on September 5, 2014. PSEGs corrective actions included replacing the H SRV, providing training to all maintenance crews responsible for SRV work, and adding steps to the SRV removal and installation procedure to: 1) generate a notification for the identification of any piping misalignment; and 2) pin the discharge piping spring can prior to SRV removal.
The finding was more than minor because it was associated with the procedure quality attribute of the Initiating Events cornerstone and adversely affected the cornerstone objective to limit the likelihood of an event that upsets plant stability. Also, if left uncorrected, the performance deficiency had the potential to lead to a more significant safety concern. The inspectors determined that this finding was of very low safety significance (Green) using Exhibit 1 of IMC 0609, Appendix A, The Significance Determination Process (SDP) for Findings At-Power, dated June 19, 2012, because the finding did not cause both a reactor trip and the loss of mitigation equipment relied upon to transition the plant from the onset of the trip to a stable shutdown condition. This finding has a cross-cutting aspect in the area of Problem Identification and Resolution,
Identification, because PSEG did not identify this issue completely, accurately, and in a timely manner in accordance with the corrective action program (CAP). [P.1] (Section 1R15)
REPORT DETAILS
Summary of Plant Status
The Hope Creek Generating Station began the inspection period at full rated thermal power (RTP). On November 21, Hope Creek performed a planned down power to 92 percent power to support offsite power line maintenance. The unit was returned to full RTP later the same day.
On December 27, Hope Creek performed a planned down power to 50 percent power to perform control rod testing and main turbine valve testing. The unit was returned to full RTP on December 28. On December 28, Hope Creek performed a planned down power to 85 percent power to perform a control rod pattern adjustment. The unit was returned to full RTP on December 29, and remained at or near full RTP for the duration of the inspection period.
REACTOR SAFETY
Cornerstones: Initiating Events, Mitigating Systems, and Barrier Integrity
1R01 Adverse Weather Protection
Readiness for Seasonal Extreme Weather Conditions
a. Inspection Scope
The inspectors performed a review of PSEGs readiness for hurricane season. The review focused on the station service water and screen and backwash systems and the Hope Creek switchyard. The inspectors reviewed the Updated Final Safety Analysis Report (UFSAR), technical specifications (TSs), control room logs, and the corrective action program (CAP) to determine what temperatures or other seasonal weather could challenge these systems, and to ensure PSEG personnel had adequately prepared for these challenges. The inspectors reviewed station procedures, including PSEGs seasonal weather preparation procedure and applicable operating procedures. The inspectors performed walkdowns of the selected systems to ensure station personnel identified issues that could challenge the operability of the systems during hurricane conditions. Documents reviewed for each section of this inspection report are listed in the Attachment.
b. Findings
No findings were identified.
==1R04 Equipment Alignment
Partial System Walkdowns (71111.04 - 4 samples)
a. Inspection Scope
==
The inspectors performed partial walkdowns of the following systems:
250 volts direct current (VDC) Class 1E batteries during the week of October 15
125 VDC Class 1E batteries during the week of October 15 Condensate storage tank heat trace while in manual during the week of November 20 (NOTF 20653110)
B standby liquid control (SLC) loop during A SLC pump discharge relief valve replacement on November 25 (Work Order (WO) 50161173)
The inspectors selected these systems based on their risk-significance relative to the reactor safety cornerstones at the time they were inspected. The inspectors reviewed applicable operating procedures, system diagrams, the UFSAR, TSs, work orders, condition reports, and the impact of ongoing work activities on redundant trains of equipment in order to identify conditions that could have impacted system performance of their intended safety functions. The inspectors also performed field walkdowns of accessible portions of the systems to verify system components and support equipment were aligned correctly and were operable. The inspectors examined the material condition of the components and observed operating parameters of equipment to verify that there were no deficiencies. The inspectors also reviewed whether PSEG staff had properly identified equipment issues and entered them into the CAP for resolution with the appropriate significance characterization.
b. Findings
No findings were identified.
==1R05 Fire Protection
==
.1 Resident Inspector Quarterly Walkdowns
a. Inspection Scope
The inspectors conducted tours of the areas listed below to assess the material condition and operational status of fire protection features. The inspectors verified that PSEG controlled combustible materials and ignition sources in accordance with administrative procedures. The inspectors verified that fire protection and suppression equipment was available for use as specified in the area pre-fire plan (PFP), and passive fire barriers were maintained in good material condition. The inspectors also verified that station personnel implemented compensatory measures for out of service, degraded, or inoperable fire protection equipment, as applicable, in accordance with procedures.
FRH-III-715, Hope Creek PFP, Security Center, Revision 5, during the week of October 15
Review of compensatory hourly firewatches with the fire protection CO2 storage tank inoperable on October 21
FRH-II-561, Hope Creek PFP, Control Equipment, Heating, Ventilation and Air Conditioning (HVAC), Inverter and Battery Rooms, Revision 7, on November 10
FRH-II-542, Hope Creek PFP, Control Equipment Mezzanine, Revision 9, on November 10
FRH-II-512, Hope Creek PFP, Battery Rooms, Revision 5, on December 16
b. Findings
No findings were identified.
.2 Fire Protection - Drill Observation
a. Inspection Scope
The inspectors observed two Hope Creek UAFDs. The inspectors observed an unannounced fire brigade drill scenario conducted on November 10, 2014, that involved a fire in the diesel HVAC equipment area, room 5606. The inspectors also observed an unannounced fire brigade drill scenario conducted on December 16, 2014, that involved a fire in the reactor core isolation cooling (RCIC) electrical equipment area, room 5130.
The inspectors evaluated the readiness of the plant fire brigade to fight fires. The inspectors verified that PSEG personnel identified deficiencies, openly discussed them in a self-critical manner at the post-drill debrief, and took appropriate corrective actions as required. The inspectors evaluated specific attributes as follows:
Proper wearing of turnout gear and self-contained breathing apparatus
Proper use and layout of fire hoses
Employment of appropriate fire-fighting techniques
Sufficient fire-fighting equipment brought to the scene
Effectiveness of command and control
Search for victims and propagation of the fire into other plant areas
Smoke removal operations
Utilization of pre-planned strategies
Adherence to the pre-planned drill scenario
Drill objectives met
The inspectors also evaluated the fire brigades actions to determine whether these actions were in accordance with PSEGs fire-fighting strategies.
b. Findings
No findings were identified.
==1R07 Heat Sink Performance (711111.07A - 2 samples)
a. Inspection Scope
==
The inspectors reviewed the A and B residual heat removal (RHR) heat exchangers to determine their readiness and availability to perform their safety functions. The inspectors reviewed the design basis for the components. The inspectors reviewed the results of tests performed to validate flow through the heat exchangers. The inspectors also discussed heat exchangers maintenance history with PSEG engineering staff. The inspectors reviewed a sample of notifications and condition reports for the past three years related to this system to ensure that PSEG appropriately identified, characterized and corrected problems related to these components performance.
b. Findings
No findings were identified.
==1R11 Licensed Operator Requalification Program
==
.1 Quarterly Review of Licensed Operator Requalification Testing and Training (71111.11Q
- 1 sample)
a. Inspection Scope
The inspectors observed licensed operator simulator training on November 12, that included an A SLC automatic initiation, jet pump failure, B loss of coolant accident (LOCA) sequencer inadvertent initiation, and reactor recirculation pump (RRP) high vibrations, followed by a small break LOCA. The inspectors evaluated operator performance during the simulated event and verified completion of critical tasks, and risk significant operator actions, including the use of abnormal and emergency operating procedures. The inspectors assessed the clarity and effectiveness of communications, implementation of actions in response to alarms and degrading plant conditions, and the oversight and direction provided by the control room supervisor. The inspectors verified the accuracy and timeliness of the emergency classification made by the shift manager.
Additionally, the inspectors assessed the ability of the training staff to identify and document crew performance problems.
b. Findings
No findings were identified.
.2 Quarterly Review of Licensed Operator Performance in the Main Control Room
(71111.11Q - 1 sample)
a. Inspection Scope
The inspectors observed performance of RCIC surveillance testing, D vital bus degraded voltage surveillance testing, and scram discharge volume level switch maintenance and calibration on November 18. The inspectors observed pre-job briefings to verify that the briefings met the criteria specified in OP-AA-101-111-1004, Operations Standards, Revision 4 and HU-AA-1211, Pre-Job Briefings, Revision 11.
Additionally, the inspectors observed test performance to verify that procedure use, crew communications, and coordination of activities between work groups similarly met established expectations and standards.
b. Findings
No findings were identified.
.3 Licensed Operator Requalification
a. Inspection Scope
The following inspection activities were performed using NUREG-1021, "Operator Licensing Examination Standards for Power Reactors," Revision 9, Supplement 1, and Inspection Procedure Attachment 71111.11, Licensed Operator Requalification Program and Licensed Operator Performance.
Examination Results
Requalification exam results for year 2014 were reviewed to determine if pass/fail rates were consistent with the guidance of NRC Manual Chapter 0609, Appendix I, and Operator Requalification Human Performance Significance Determination Process (SDP).
The review verified the following:
Individual pass rate on the dynamic simulator scenarios was greater than 80 percent. (Pass rate was 100 percent.)
Individual pass rate on the job performance measure (JPM) part of the operating exam was greater than 80 percent. (Pass rate was 97.8 percent.)
Individual pass rate on the comprehensive written examination was greater than 80 percent. (Pass rate was 100 percent.)
More than 80 percent of the individuals passed all portions of the requalification exam. (Pass rate was 97.8 percent.)
Crew pass rate was greater than 80 percent. (Pass rate was 100 percent.)
Written Examination Quality
The inspectors reviewed a sample of comprehensive written exams that PSEG staff administered to the operators in November and December 2014.
Operating Test Quality
The inspectors reviewed the operating tests (scenarios and JPMs) associated with the onsite examination week.
Licensee Administration of Operating Tests
The inspectors observed PSEG training staff administer dynamic simulator exams and JPMs during the week of October 6. These observations included facility evaluations of crew and individual operator performance during the simulator exams and individual performance of JPMs.
Exam Security
The inspectors assessed whether facility staff properly safeguarded exam material, and whether test item repetition guidelines were met.
Conformance with License Conditions
License reactivation and license proficiency records were reviewed to ensure that 10 CFR 55.53 license conditions and applicable program requirements were met. The inspectors also reviewed a sample of records for requalification training attendance and a sample of medical examinations for compliance with license conditions and NRC regulations.
Simulator Performance
Scenario-based tests and simulator performance tests were reviewed for conformance and fidelity to the plant control room. A sample of simulator deficiency reports was also reviewed to ensure facility staff addressed any identified modeling problems.
Problem Identification and Resolution
The inspectors reviewed recent operating history documentation found in inspection reports, licensee event reports, the licensees corrective action program, NRC End of Cycle and Mid Cycle reports, and the most recent NRC plant issues matrix. The inspectors focused on events associated with operator errors that may have occurred due to possible training deficiencies.
b. Findings
No findings were identified.
1R12 Maintenance Effectiveness
a. Inspection Scope
The inspectors reviewed the samples listed below to assess the effectiveness of maintenance activities on structure, system, or component (SSC) performance and reliability. The inspectors reviewed corrective action program documents (notifications),maintenance work orders (orders), and maintenance rule basis documents to ensure that PSEG was identifying and properly evaluating performance problems within the scope of the maintenance rule. As applicable, the inspectors verified that the SSC was properly scoped into the maintenance rule in accordance with 10 CFR 50.65 and verified that the (a)(2) performance criteria established by PSEG staff was reasonable; for SSCs classified as (a)(1), the inspectors assessed the adequacy of goals and corrective actions to return these SSCs to (a)(2); and, the inspectors independently verified that appropriate work practices were followed for the SSCs reviewed. Additionally, the inspectors ensured that PSEG staff was identifying and addressing common cause failures that occurred within and across maintenance rule system boundaries.
Hole discovered in A station service water (SSW) strainer inner drum on September 29 (NOTF 20663818)
Reactor building drain system maintenance rule program scoping and monitoring on November 4 (NOTF 20668427)
b. Findings
No findings were identified.
1R13 Maintenance Risk Assessments and Emergent Work Control
a. Inspection Scope
The inspectors reviewed station evaluation and management of plant risk for the maintenance and emergent work activities listed below to verify that PSEG performed the appropriate risk assessments prior to removing equipment for work. The inspectors selected these activities based on potential risk significance relative to the reactor safety cornerstones. As applicable for each activity, the inspectors verified that PSEG personnel performed risk assessments as required by 10 CFR 50.65(a)(4) and that the assessments were accurate and complete. When PSEG performed emergent work, the inspectors verified that operations personnel promptly assessed and managed plant risk.
The inspectors reviewed the scope of maintenance work and discussed the results of the assessment with the stations probabilistic risk analyst to verify plant conditions were consistent with the risk assessment. The inspectors also reviewed the technical specification requirements and inspected portions of redundant safety systems, when applicable, to verify risk analysis assumptions were valid and applicable requirements were met.
Emergent B reactor feedwater pump elevated vibrations and shaft seizure on September 5 (NOTF 20665627/WO 70168970)
Planned 00-K-107 service air compressor maintenance on October 17 (NOTF 20665690)
Planned D SSW system and scram discharge volume level switch maintenance and reactor core isolation cooling surveillance testing on November 18
Emergent fire protection computer maintenance on November 23 (NOTF 20670790)
Emergent trip of the 4B feedwater heater on December 8 (NOTF 20672263)
b. Findings
No findings were identified.
1R15 Operability Determinations and Functionality Assessments
a. Inspection Scope
The inspectors reviewed operability determinations for the following degraded or non-conforming conditions:
SRV leakage torus noise and cold spring concern (Order 70168360)
Circulating water dewatering line leak extent of condition (Order 70168162)
H SRV high delay time (NOTF 20670004)
The inspectors selected these issues based on the risk significance of the associated components and systems. The inspectors evaluated the technical adequacy of the operability determinations to assess whether TS operability was properly justified and the subject component or system remained available such that no unrecognized increase in risk occurred. The inspectors compared the operability and design criteria in the appropriate sections of the TSs and UFSAR to PSEGs evaluations to determine whether the components or systems were operable. Where compensatory measures were required to maintain operability, the inspectors determined whether the measures in place would function as intended and were properly controlled by PSEG. The inspectors determined, where appropriate, compliance with assumptions in the evaluations.
b. Findings
Introduction.
A self-revealing Green NCV of 10 CFR Part 50, Appendix B, Criterion XVI, Corrective Action, because PSEG did not promptly identify and correct a condition adverse to quality. Specifically, PSEG did not initiate a NOTF or perform an evaluation of a cold spring condition found in the H SRV discharge piping during the valves replacement in 2012. This condition that occurred during installation was determined to be the cause of a leak on the main seat of the newly installed SRV. The leak proceeded to degrade during the operating cycle and ultimately caused Hope Creek to shut down and replace the SRV on September 5, 2014.
Description.
The target rock model 7567F two-stage, pilot-operated SRV consists of two assemblies: a pilot stage assembly and a main stage assembly. These two assemblies are directly coupled to provide a unitized, dual function SRV. The pilot stage assembly is a pressure-sensing and control element, and the main stage assembly is a system fluid-actuated reverse seated angle globe valve which provides for the pressure relief function or system depressurization at full rated flow. This model SRV has a set pressure range of 1025 to 1190 psig and weighs approximately 1100 pounds. The main stage disc is tightly seated by the combined forces exerted by the preload spring and the system internal pressure acting over the area of the valve disc.
On August 12, 2014, an equipment operator on reactor building rounds noted a loud banging noise emanating from the torus room area between the 54 and 77 elevations.
Further investigation by operations within the torus room revealed the noise to be loudest around azimuth 340 degrees, with a pattern of a loud bang followed by several softer, quieter bangs. The loud bangs occurred at a frequency of every 5 seconds.
PSEG conducted a review of plant parameters and correlated the noise with an increased frequency in the need to run suppression pool cooling and torus letdown due to increases in torus heat input and level since February 2014.
PSEG initiated an investigation to determine the potential causes of the noise. As part of this investigation, PSEG developed a failure mode causal team (FMCT) with input from subject matter experts throughout the industry to identify potential causes of the noise. Industry operating experience (OE) was also reviewed, indicating similar events at Hatch and Millstone. The FMCT determined that the two most likely causes of the noise were either cycling of the H SRV tailpipe vacuum breakers (VBs) inside primary containment (elevation 112) or H SRV leak-by resulting in a water chugging event within the SRV discharge pipe T-quencher located inside the torus. OE from Hatch and Millstone indicated that if the VBs were cycling, failure of the VBs could occur within 30 days of the appearance of the noise, causing a potential direct pathway of any steam flow through H SRV to the drywell instead of being dissipated by the water volume of the torus. Due to this potential failure mode, PSEG made the decision on August 25, 2014, to conduct a planned maintenance outage on September 5, 2014, to further troubleshoot and repair the source of the noise.
After shutting down the plant on September 5, 2014, PSEG refuted the cycling SRV VB potential cause by conducting walk downs at rated pressure inside the drywell and performing inspections of the H SRV VBs to verify they had not been cycling. After completing detailed visual inspections inside the drywell and torus, PSEG concluded that the most probable cause of the torus noise was excessive leakage past the H SRV main seat inducing a water chugging event within the T-quencher. This water chugging event occurred when significant quantities of steam reached the water in the T-quencher initiating a repeating condensate induced water hammer inside the T-quencher. PSEG removed and replaced the H SRV main and pilot valve assemblies, and had both assemblies tested offsite. The results of the testing yielded 0.05 gpm and 2.35 gpm leakage past the pilot and main seats, respectively, totaling approximately 2.4 gpm or 1200 lbm/hr at 1000 psig.
PSEGs investigation of the H SRV main seat leakage identified the main disc as being severely steam cut. The apparent cause evaluation determined the most likely cause of the steam cutting to be the existence of cold spring in the tailpipe of the H SRV during the last replacement of the valve in RF17 (April 2012) under WO 60097071. This WO documented that the H SRV tailpipe was misaligned and discussion with maintenance found that a come-along was used to adjust for piping misalignment following removal of the valve. PSEG determined that a large moment force was applied to the SRV main during installation, causing the initial leak on the SRV main seat, which then degraded during the operating cycle. During the removal of the H SRV main assembly in September 2014, the misalignment of the discharge piping was documented in NOTF 20661387 as off by 1.5 horizontally and 1.25 vertically. PSEG found that the H SRV discharge piping spring can was not pinned during the removal process in 2012, and if it had been pinned prior to removal, it could have prevented any cold spring or piping misalignment during reinstallation of the new SRV. PSEGs apparent cause evaluation (ACE) determined that the SRV installation and removal procedure does not include steps to pin the spring can prior to SRV piping disassembly.
The inspectors reviewed PSEGs ACE, SRV work history, procedures and previous CAP evaluations and determined that PSEGs conduct of maintenance in WO 60097071 should have generated a NOTF to document and evaluate the discharge piping misalignment found when removing the H SRV in RF17. The inspectors also identified a note in Section 5.2.3 of MA-AA-734-458, Pressure Relief Device Removal and Installation, which states that discharge piping should not cause any bending or apply any cold spring to the relief valve. Any cold spring or pipe distortion should be brought to the attention of supervision. The inspectors determined that PSEG should have evaluated the misaligned SRV discharge piping as a potential condition adverse to quality.
Analysis.
The inspectors determined that the inadequate identification and evaluation of the conditions adverse to quality associated with H SRV discharge piping misalignment found during valve replacement in 2012, was a performance deficiency that was within PSEGs ability to foresee and correct. The finding was more than minor because it was associated with the procedure quality attribute of the Initiating Events cornerstone and adversely affected the cornerstone objective to limit the likelihood of an event that upsets plant stability. Also, if left uncorrected, the finding had the potential to lead to a more significant safety concern. The inspectors determined that this finding was of very low safety significance (Green) using Exhibit 1 of IMC 0609, Appendix A, The Significance Determination Process (SDP) for Findings At-Power, dated June 19, 2012, because the finding did not cause both a reactor trip and the loss of mitigation equipment relied upon to transition the plant from the onset of the trip to a stable shutdown condition.
Specifically, the H SRV safety-related function, relied upon for accident mitigation and pressure relief, remained operable.
This finding has a cross-cutting aspect in the area of Problem Identification and Resolution, Identification, because PSEG did not identify this issue completely, accurately and in a timely manner in accordance with the CAP. [P.1]
Enforcement.
10 CFR 50, Appendix B, Criterion XVI, Corrective Action, requires in part, that measures shall be established to assure that conditions adverse to quality, such as failures, malfunctions, deficiencies, deviations, defective material and equipment, and non-conformances are promptly identified and corrected. Contrary to the above, PSEG failed to promptly identify and correct a condition adverse to quality.
Specifically, PSEG did not initiate a NOTF or perform an evaluation of a cold spring condition found in the H SRV discharge piping during the valves replacement in 2012.
This condition was determined to be the cause of an initial leak on the main seat of the new SRV during installation, which then proceeded to degrade during the operating cycle and ultimately caused PSEG to shut down and replace the SRV on September 5, 2014. PSEGs corrective actions included replacing the H SRV, providing training to all maintenance crews responsible for SRV work, and adding steps to the SRV removal and installation procedure to: 1) generate a notification for the identification of any piping misalignment; and 2) pin the discharge piping spring can prior to SRV removal.
Because this finding was of very low safety significance and because it was entered into PSEGs CAP as NOTF 20661387, this violation is being treated as an NCV, consistent with the NRC Enforcement Policy. (NCV 05000354/2014005-01, Failure to Identify and Correct a Condition Adverse to Quality Associated with Safety Relief Valve Discharge Piping Misalignment)
1R19 Post-Maintenance Testing
a. Inspection Scope
The inspectors reviewed the post-maintenance tests for the maintenance activities listed below to verify that procedures and test activities ensured system operability and functional capability. The inspectors reviewed the test procedure to verify that the procedure adequately tested the safety functions that may have been affected by the maintenance activity, that the acceptance criteria in the procedure was consistent with the information in the applicable licensing basis and/or design basis documents, and that the procedure had been properly reviewed and approved. The inspectors also witnessed the test or reviewed test data to verify that the test results adequately demonstrated restoration of the affected safety functions.
A SSW strainer inner drum repair on October 4 (Order 30263015)
00K107 service air compressor planned preventive maintenance on November 14 (Orders 30171642 and 30259173)
B station service water strainer backwash arm thrust collar repair on November 14 (Order 60120359)
A SLC pressure safety valve replacement on November 25 (Order 50169460)
Reactor building ventilation supply fan breaker repairs on December 4 (Order 60120667)
A emergency diesel generator (EDG) jacket water leak repair on December 29 (Order 60120557)
b. Findings
No findings were identified.
1R22 Surveillance Testing
a. Inspection Scope
The inspectors observed performance of surveillance tests and/or reviewed test data of selected risk-significant SSCs to assess whether test results satisfied TS, the UFSAR, and PSEG procedure requirements. The inspectors verified that test acceptance criteria were clear, tests demonstrated operational readiness and were consistent with design documentation, test instrumentation had current calibrations and the range and accuracy for the application, tests were performed as written, and applicable test prerequisites were satisfied. Upon test completion, the inspectors considered whether the test results supported that equipment was capable of performing the required safety functions. The inspectors reviewed the following surveillance tests:
HC.OP-IS.BC-0003, B RHR Pump In-service Test on October 15 (in-service test)
HC.OP-DL.ZZ-0026, Drywell floor drain leakage monitoring during the week of October 15 (reactor coolant system leakage)
HC.MD-ST.PJ-0002, 250 volt Quarterly Battery Surveillance on October 28
HC.OP-IS.BC-0104, RHR Subsystem D Valves - Inservice Test on November 1 (in-service test)
HC.OP-ST.KJ-0001, A EDG Monthly Operability Test on November 24
b. Findings
No findings were identified.
OTHER ACTIVITIES
4OA1 Performance Indicator Verification
.1 Safety System Functional Failures (1 sample)
a. Inspection Scope
The inspectors sampled PSEGs submittals for the Safety System Functional Failures performance indicator for Hope Creek for the period from January 1, 2013, through September 30, 2014. To determine the accuracy of the performance indicator data reported during those periods, inspectors used definitions and guidance contained in the Nuclear Energy Institute (NEI) Document 99-02, Regulatory Assessment Performance Indicator Guideline, Revision 7, and NUREG-1022, Event Reporting Guidelines 10, CFR 50.72 and 10 CFR 50.73." The inspectors reviewed PSEGs licensee event reports (LER) to validate the accuracy of the submittals.
b. Findings
No findings were identified.
.2 Radiological Controls Perfomance Indicators (2 samples)
a. Inspection Scope
The inspectors reviewed licensee submittals for the occupational radiological occurrence PI and the radiological effluent TS/Offsite Dose Calculation Manual (ODCM) occurrence PI for the past four quarters. The inspector used PI definitions and guidance contained in the Nuclear Energy Institute Document 99-02, Regulatory Assessment Performance Indicator Guideline, Revision 7, to determine the accuracy of the PI data reported during those periods.
Occupational Exposure Control Effectiveness
The inspectors reviewed: electronic personal dosimetry accumulated dose alarms, dose reports, and dose assignments for any intakes that occurred during the time period reviewed to determine if there were potentially unrecognized PI occurrences. The inspectors conducted walk-downs of various Locked High and Very High Radiation Area entrances to determine the adequacy of the controls in place for these areas.
Radiological Effluent TS/ODCM Radiological Effluent Occurrences
The inspectors reviewed the PSEG issue report database to identify any potential occurrences such as unmonitored, uncontrolled, or improperly calculated effluent releases that may have impacted offsite dose. The inspectors reviewed gaseous and liquid effluent summary data and the results of associated offsite dose calculations for the past four quarters to determine if indicator results were accurately reported.
b. Findings
No findings were identified.
4OA2 Problem Identification and Resolution
.1 Routine Review of Problem Identification and Resolution Activities
a. Inspection Scope
As required by Inspection Procedure 71152, Problem Identification and Resolution, the inspectors routinely reviewed issues during baseline inspection activities and plant status reviews to verify that PSEG entered issues into the CAP at an appropriate threshold, gave adequate attention to timely corrective actions, and identified and addressed adverse trends. In order to assist with the identification of repetitive equipment failures and specific human performance issues for follow-up, the inspectors performed a daily screening of items entered into the CAP and periodically attended notification screening meetings.
b. Findings
No findings were identified.
.2 Semi-Annual Trend Review
a. Inspection Scope
The inspectors performed a semi-annual review of site issues, as required by Inspection Procedure 71152, Problem Identification and Resolution, to identify trends that might indicate the existence of more significant safety issues. In this review, the inspectors included repetitive or closely-related issues that may have been documented by PSEG outside of the CAP, such as trend reports, performance indicators, major equipment problem lists, system health reports, maintenance rule assessments, and maintenance or CAP backlogs. The inspectors also reviewed PSEGs CAP database for the third and fourth quarters of 2014 to assess notifications written in various subject areas (equipment problems, human performance issues, etc.), as well as individual issues identified during the NRCs daily condition report review (Section 4OA2.1). The inspectors reviewed PSEGs quarterly trend reports for the third through fourth quarters of 2014, conducted under LS-AA-125, to verify that PSEG personnel were appropriately evaluating and trending adverse conditions in accordance with applicable procedures.
b. Findings and Observations
No findings were identified.
The inspectors determined that any performance deficiencies associated with the trends discussed below were of minor significance in accordance with IMC 0612, Appendix B, or were documented as findings in other sections of this report, as referenced below.
Maintenance Rule
The inspectors identified a trend in maintenance preventable functional failures (MPFFs)and repeat MPFFs (RMPFFs) documented in PSEGs CAP for the Maintenance Rule program. PSEG documented zero RMPFFs in both 2012 and 2013, but as of December 15, 2014, three RMPFFs have been documented since January 1, 2014.
The RMPFFs were documented for water tight doors failing to inflate (70167109),lowering instrument air pressure (70169492) and service water intake structure ventilation dampers failing to operate (70168881). The inspectors also challenged PSEGs failure to scope building and equipment drains into the maintenance rule.
As a result, PSEG initiated NOTF 20668427 to properly scope the building and equipment drain system into the maintenance rule. Although both of these issues exist, the inspectors determined that PSEGs evaluation and corrective actions are appropriate for each issue given the safety significance of the systems. PSEGs Maintenance Rule Focused Area Self-Assessment completed in September 2014, in Order 70162305, was reviewed by the inspectors. The assessment continued to highlight observations from the inspectors including timeliness of maintenance rule products and screenings, inadequate justifications for MPFFs and RMPFFs, and the level of documentation included for functional failure determinations. The inspectors dispositioned these observations as minor issues because they did not adversely impact PSEGs application of the maintenance rule program.
Fire Protection Unannounced Drill Performance
The inspectors have observed multiple unannounced fire drills (UAFDs) conducted by PSEG at both Hope Creek and Salem during the last six months due, in part, to a previously documented Green non-cited violation, NCV 05000311/2013005-01, Inadequate Assessment of Fire Brigade Performance during an Unannounced Drill, in the 2013 Salem fourth quarter inspection report (Hope Creek and Salem share a common site fire department). The NCV documented several NRC-identified deficiencies that were not captured in PSEGs drill assessment, including: 1) use of fire protection equipment and pre-fire plans (PFPs); 2) coordination and communication between the FBL, the OFBL, the fire brigade, the first responder and the MCR; 3)qualifications of the OFBL, and; 4) UAFD critiques.
PSEG entered these issues into the CAP as NOTF 20632422, which performed an apparent cause evaluation (ACE 70161457) completed by PSEG in February 2014. PSEGs corrective actions included revising the fire protection procedures to ensure current NRC fire protection inspection guidelines were incorporated, and making improvements in fire brigade training, the fire drill process, and drill performance and grading by benchmarking other utilities.
Since the completion of these corrective actions by PSEG, the inspectors have observed UAFDs on April 7, October 1, November 10, and December 16, 2014. The April UAFD was graded as unsatisfactory due, in part, to inadequate communications between the OFBL and the MCR, inadequate fire brigade member knowledge of firefighting strategy, non-conformance with the PFP, and non-compliance with station firefighting procedures. Specifically, concerning the performance of the OFBL, PSEG documented NOTF 20646330 stating that the drill was complicated by the assignment of a new equipment operator (EO) to the OFBL position who was not familiar with the expectations of the OFBL position. PSEG also documented NOTF 20646361 citing an adverse trend in OFBL training, expectations, and duties.
On October 1 and November 10, 2014, the inspectors observed two UAFDs at Salem and Hope Creek. The inspectors noted the following areas of concern during these drills: 1) OFBL proficiency, responsibilities, training, and level of knowledge; 2) fire brigade (FB) and controller use of the PFPs; FB communications with the MCR; 3) the lack of UAFD observations by PSEG nuclear oversight and management; and, 4) FB use of PPE and elevators. For the October drill, PSEG graded the performance as satisfactory and documented only a few minor areas of concern. The inspectors developed a separate list of observations not contained in PSEGs drill critique. After discussing the inspectors list of issues with PSEG, multiple NOTFs were generated by PSEG to document the additional inspector concerns. The inspectors dispositioned these observations as minor issues because they did not adversely impact PSEGs overall assessment of fire brigade performance.
After the drill in November, PSEG documented NOTF 20669366 grading the drill performance as unsatisfactory due to a lack of communications during the size-up of the fire, a lack of communications for the actions taken to secure energized equipment, and the lack of action by the OFBL to communicate with the MCR during the drill. The inspectors developed a comprehensive list of observations, but the majority of these were contained in PSEGs drill assessment and critique. The inspectors also dispositioned these observations as minor issues because they did not adversely impact PSEGs overall assessment of fire brigade performance.
On December 16, 2014, the inspectors observed an UAFD involving a simulated class C fire in the Hope Creek Control building involving the RCIC battery charger. The inspectors observed the post-drill critique and then reviewed the completed drill assessment (#53674950) where the inspectors noted that the fire brigade passed the drill despite the drill assessment noting multiple missed opportunities by the fire brigade, IC, MCR and other drill participants to correct inaccurate communications regarding the location of the fire and the use of the wrong PFP. PSEGs drill assessment evaluated these issues as non-consequential delays to fire extinguishment, having no impact on the outcome of the fire scenario. PSEGs drill assessment did not document any supporting information to validate these conclusions nor did the drill assessment document any issues related to fire development based on the time delays in suppressing the fire. In a similar UAFD conducted on November 10, 2014, PSEG failed the fire brigades performance because it took them 14 minutes to assemble and 20 minutes to commence fighting the fire, which was less than half of the December drills time of 43 minutes.
PSEGs Fire Drill Performance procedure, FP-AA-024, Section 4.2.6, Fire Drill Scenarios, states that fire drill scenarios should include, in part, expected response times for the IC and fire brigade members and suppression activities initiated within expected times. It also states that the fire drill scenario should simulate the size and arrangement of a fire that could reasonably occur in the area selected, allowing for fire development due to the time required to respond, obtain equipment, and organize for the fire. Section 4.4.3, Fire Drill Performance and Assessment, states that fire drill performance as a minimum shall include, in part, timeliness of the fire brigades assembly and response. Attachment 4 of this procedure, Additional Fire Drill Performance Aspects, includes timeliness of the start of the fire attack.
The inspectors observed that miscommunications in the fire location resulted in a delayed response in the brigades ability to fight the fire. The inspectors also noted the following repeat areas of concern with the drill, including: 1) equipment operator knowledge, specifically room numbering, and OFBL training; 2) inappropriate hose flaking and the use of out-of-date PFPs; 3) the use of radios in a radio free (RF) zone; and, 4) poor drill controller simulation and positioning.
Although the inspectors concluded that fire brigade assembly time and the time for initial fire attack and suppression was not completely assessed by PSEGs drill critique, the inspectors dispositioned these observations as minor issues because they did not adversely impact PSEGs overall assessment of fire brigade performance. This conclusion is based mainly on the limited fire loading in the area of the fire and the fact that the fire brigade staged and was ready to control the fires growth with a CO2 extinguisher 15 minutes into the drill.
Overall, the inspectors determined that adverse trends have developed with the performance of UAFDs with regards to OFBL training for responding to fires, the use of radios in RF zones, PFP inadequacies, and overall communication and coordination between those involved. PSEGs CAP has captured these adverse trends. The inspectors also determined that an adverse trend exists with PSEGs assessment of fire brigade performance at Salem and Hope Creek, which requires self-criticality and depth to ensure that the common PSEG fire department both identifies and corrects UAFD issues in accordance with their fire protection program procedures. These issues have been entered into PSEGs CAP as NOTF 20674128.
Equipment Reliability
The inspectors reviewed multiple events involving un-demanded system initiations involving potential circuit card issues. This review included the B RRP un-demanded speed change that occurred on May 14, 2014. PSEGs review of the event identified that the B RRP speed controller output oscillated as its output increased. PSEG entered this into the corrective action program as NOTF 20652621, and performed an ACE 70166490 which determined that the only viable failure mechanism was erratic performance of the Bailey speed controller card. This controller card had been replaced in 2013, with a refurbished and bench tested spare. The Bailey speed control cards with a material master of Y315645 (Model 721002AAAA1) were procured from another station under a non-safety related inter-utility purchase order (PO) for installation in Hope Creeks B RRP under work order 60114166.
Because of the potential differences with another stations refurbishment process, the inspectors questioned the history of the Bailey speed control cards installed into Hope Creeks RRP system in November 2013. These circuit cards are governed by the refurbishment and replenishment process of vital circuit cards in MA-AA-746-1001, Electronic Circuit Card Refurbishment / Replenishment Process. This procedure requires PSEG to maintain information regarding failure history as well as maintain the vital circuit card database. The procedure also requires that all age sensitive components shall be replaced with new components.
The inspectors determined that these cards had been manufactured in 1985 and 1986 (29 and 28 years old), and that both were refurbished in 2008 by another station. The inspectors determined that this information was not provided to PSEG at the time of sale because the components were not classified as safety-related or purchase class (PC) 1.
As a result of the inspectors questions, PSEG documented NOTF 20672682 and is in the process of evaluating procedure SM-AA-4026, Section 5.2.1, Inter-utility Sale Criteria, to ensure ordered items history from the other utility is documented. Currently, PSEGs procedure applies to safety-related or PC1 POs. PSEG is also creating guidance in their procedures to drive improvements in parts quality. The inspectors dispositioned these observations as minor issues because they did not adversely impact PSEGs operation of the RR system.
.3 Annual Sample:
High Pressure Coolant Injection (HPCI) Relay Failures
a. Inspection Scope
The inspectors performed an in-depth review of PSEGs ACE and corrective actions associated with order 70152218. The notification associated with this order (20603740)was reviewed by the management review committee on April 10, 2013 and documented that two safety-related TYCO model FGPDC750 control relays failed to properly operate prior to their scheduled periodic replacement. One relay failure challenged the reliable operation of the HPCI pump on April 8, 2013, and was the subject of LER 05000354/2013-001-00, High Pressure Coolant Injection System Inoperable Due to Control Relay Failure. The other relay failure challenged the reliable operation of the containment isolation system, specifically the HV-F002, HPCI turbine inboard steam isolation valve, and occurred on April 9, 2013, during surveillance testing. These issues were discussed and the LER closed out in NRC Inspection Report 05000354/2013003 (ADAMS Accession Number ML13212A010) issued on July 31, 2013.
The inspectors assessed PSEGs problem identification threshold, causal analyses, technical analyses, extent of condition reviews, and the prioritization and timeliness of corrective actions to determine whether PSEG was appropriately identifying, characterizing, and correcting problems associated with this issue. The inspectors reviewed the circumstances of these and earlier relay issues and operating experience to ascertain the appropriateness of corrective actions. Previous opportunities for PSEG to have identified and corrected the relay issues were reviewed by the inspectors and documented in NRC Inspection Report 05000354/2013003 and a self-revealing Green NCV of Technical Specification 6.8.1, Procedures, was documented. The inspectors also assessed PSEGs corrective actions to prevent recurrence. The inspectors compared the actions taken to the requirements of PSEGs corrective action program and 10 CFR Part 50, Appendix B, Criterion XVI, Corrective Action. In addition, the inspectors reviewed documentation associated with this issue, including condition and failure analysis reports, and interviewed engineering personnel to assess the effectiveness of the planned and implemented corrective actions.
b. Findings and Observations
No findings were identified.
The two failed control relays were replaced and PSEG promptly chartered an evaluation team on April 18, 2013, to perform an equipment ACE. The ACE was presented to a Management Review Committee in a timely matter on May 21, 2013.
The failed relays were inspected by Exelon PowerLabs. The inspections identified that the HPCI auxiliary oil pump relay had an open coil which prevented the relay from operating, and the HV-F002 isolation valve relay had extremely high contact resistance on two of the normally open contacts. The equipment ACE determined that the failures were age-related and that a 2007 preventive maintenance (PM) change evaluation that created relay replacement PMs for normally de-energized relays (extended replacement interval from 22 years to 40 years), did not consider all applicable references [vendor information and industry operating experience]. The failed relays were both normally de-energized. The vendor stated the qualified life for normally de-energized relays was 10 years and was established by initial product testing completed in 1980. The relays were manufactured in 1980 and installed prior to initial plant startup in 1986. The relays failed 23 years after manufacture, much less than the scheduled replacement at 40 years.
PSEG established timely corrective actions to address the apparent and contributing causes. Corrective actions included:
evaluations to review the replacement periodicity for safety-related relays that are:
o normally energized and provide electronic timing and control; o normally de-energized and provide electronic timing and control; o normally energized and provide pneumatic timing; and, o normally de-energized and provide pneumatic timing
implement new relay replacement PM templates once issued by Electric Power Research Institute (EPRI).
replace relays at the new replacement periodicity established by the aforementioned evaluations and promptly replace existing relays that are overdue.
The inspectors noted the evaluations for relay replacement periodicity appropriately considered vendor information and site-specific and industry operating experience.
Where intervals were beyond the vendor qualified life, consistent with vendor and EPRI guidance (EPRI Technical Report 102067, Maintenance and Application Guide for Control Relays and Timers), the periodicity was justified with technical and supporting data. For the case of the failed HPCI relays, which were normally de-energized relays that provide electronic timing and control, PSEG determined the relays should be replaced at about 19.2 years and are overdue at 24 years from date of manufacturing, not the date of installation.
Within the corrective action program documentation, the inspectors noted a conflict between schedule dates for the overdue relay replacements. Operation 0305 in Order 70152218 stated that relay groups 1A, 1B, and 2 should complete by refuel outage 19 (Spring of 2015) but operation 184 stated these relay replacements would complete by August 2014. (Group 1A included relays which could result in an emergency core cooling system being inoperable, Group 1B included relays which could result in an instrument technical specification limiting condition for operation entry, Group 2 included relays which could result in system inoperability if in a test mode, and Group 3 included relays without any control function.) PSEG completed the Group 1A, 1B, and 2 relay replacements by the more conservative date established in operation 184. This is a minor issue administrative in nature.
.4 Annual Sample: Follow-up of Selected Issues for Operator Performance
a. Inspection Scope
The inspector performed an in-depth review of PSEG staffs evaluations and the effectiveness of the corrective actions associated with several station events in 2013 and 2014. The focus of the inspection was operator performance during these events.
The events reviewed were the June 2013 reactor scram due to a circulating water pump trip, two December 2013 reactor scrams due to high moisture separator level, and the August 2014 power reduction due to a safety relief valve indicating open.
The inspector performed an in depth review of the root cause evaluations and other evaluations, and assessed the following attributes: identification of the root and contributing causes; extent of condition reviews; and previous occurrences. The inspector also assessed the timeliness of corrective actions and whether they will preclude repetition of the events. The inspector performed reviews of the documents noted in the Attachment to this report to assess the effectiveness of the planned, scheduled, and completed corrective actions to resolve the identified deficiencies.
b. Findings and Observations
The inspector determined that PSEG appropriately identified, characterized, and implemented corrective actions associated with the operator performance issues identified during these events.
.5 Annual Sample:
A Safety Auxiliary Cooling System (SACS) Relief Valve Lift During Pump Starts Following Refueling Outages 1R17 and 1R18
a. Inspection Scope
This inspection reviewed PSEG's identification, evaluation, and resolution of inadvertent lifting of the A SACS relief valve 1EGPSV-6220A during pump starts following refueling outages 1R17 and 1R18. The inspectors reviewed the associated notifications 20626749 and 20557271 and applicable corrective actions, the SACS system design and drawings, the UFSAR, Technical Specifications, a list of associated SACS system deficiencies and notifications, and work practices, to assess the number of times the subject relief valves had lifted and to assess the potential consequence of an inadvertent lift of a SACS relief valve while the plant is operating at full power. The inspectors also performed field walkdowns and inspections of both trains of the SACS relief valves to visually assess the material condition of both valves and the associated pipe supports.
The inspectors assessed PSEGs staffs problem identification, cause analysis, extent-of-condition reviews, compensatory actions, and the prioritization and timeliness of applicable corrective actions to evaluate whether the Hope Creek staff was appropriately identifying, characterizing, and correcting problems associated with this issue and whether the planned or completed corrective actions were adequate.
The inspectors also used the guidance in NUREG-1022 to evaluate PSEG's event reporting, as required by 10 CFR 50.73, associated with the SACS relief valves lifts. The inspectors reviewed applicable procedures to ensure that testing was being performed in accordance with the current licensing basis requirements. Additionally, the inspectors reviewed calculations, as-found and as-left relief valve test reports, and engineering evaluations to evaluate the adequacy of PSEG's administrative controls for the SACS relief valves. The inspectors also interviewed engineering, licensing, operations, and design engineering staff and management personnel to discuss the relief valves and SACS system performance issues and associated corrective actions.
b. Findings and Observations
No findings were identified.
The inspectors noted that inadvertent lifts of the SACS relief valves had occurred two times while the system was returned to service after refueling outages 1R17 and 1R18.
PSEG engineers determined the cause was inadequate venting of the SACS piping after the system was drained for refueling outage activities. The inspectors also noted PSEG staff had reviewed the filling and venting procedure, the potential impact that water leaking from the relief valves may have on the system flow requirements, and the potential effects of water accumulation in the A and B RHR rooms where the relief valves are located.
The inspectors determined that PSEG staff appropriately identified, characterized, implemented, and/or had planned adequate corrective actions to properly vent the SACS system piping and pumps after the system is drained for refueling outages. The corrective actions included: reinforcing operator crew awareness and training; revising the filling and venting procedure by December 2014 to ensure adequate time for venting; and verifying the SACS pump discharge valve is fully opened upon placing the SACS loop in service. The inspectors also determined that PSEG had performed adequate extent-of-condition reviews and adequately evaluated reportability in accordance with 10 CFR 50.73. Furthermore, the inspectors determined that inadvertent lifting of the subject SACS relief valves while the plant is at full power operation is unlikely to occur and that based on the system design and redundancy, piping arrangements, operating procedures, and design bases flow requirements, an inadvertent lift of one of the relief valves would not affect system operability or prevent the SACS system from performing its intended safety function.
4OA5 Other Activities
Temporary Instruction 2515/190 - Inspection of the Proposed Interim Actions Associated with Near-Term Task Force Recommendation 2.1 Flooding Hazard Evaluations.
Inspectors verified that PSEGs interim actions will perform their intended function for flooding mitigation.
The inspectors independently verified that the licensees proposed interim actions would perform their intended function for flooding mitigation.
Visual inspection of the flood protection feature was performed. External visual inspection was conducted for indications of degradation that would prevent its credited function from being performed.
Reasonable simulations of flood mitigation actions, to verify they could be executed as specified, were reviewed
Flood protection feature functionality was determined using either visual observation or by review of other documents.
The inspectors verified that issues identified were entered into Hope Creeks CAP.
4OA6 Meetings, including Exit
On January 20, 2015, the inspectors presented the inspection results to Mr. P. Davison, Site Vice President of Hope Creek, and other members of the Hope Creek staff. The inspectors verified that no proprietary information was retained by the inspectors or documented in this report.
ATTACHMENT:
SUPPLEMENTARY INFORMATION
KEY POINTS OF CONTACT
Licensee Personnel
- P. Davison, Site Vice President
- E. Carr, Plant Manager
- J. Baker, Fukushima Project Operations Specialist
- M. Biggs, Maintenance Rule Program Coordinator
- B. Booz, Technical Specialist, Component Maintenance Optimization
- D. Boyle, Plant Engineering
- R. Chan, Nuclear Oversight Manager
- S. Connelly, System Manager
- M. Conroy, Senior Program Engineer
- B. Daly, Manager, Sustainability, Environmental Affairs
- M. DeBeaumont, Fire Protection Supervisor
- D. Denelsbeck, Radiation Protection Support
- S. Dennis, Hope Creek Nuclear Simulator Training Instructor
- T. Devik, Hope Creek Fukushima Design Manager
- P. Duca, Regulatory Assurance Compliance Engineer
- D. Dunn, System Engineer
- S. English, Mechanical Maintenance Supervisor
- D. Fisher, Nuclear Oversight
- T. Fowler, Hope Creek Operations Training Manager
- C. Geiger, Fukushima Project Engineering
- J. Halstead, Design Engineer
- W. Hicks, Reactor Operator
- A. Kraus, Manager, Nuclear Environmental Affairs
- R. Kocher, System Engineer
- W. Kopchick, Operations Director
- F. Leeser, Chemistry Manager
- T. MacEwen, Principle Nuclear Engineer, Regulatory Assurance
- E. Martin, Senior Program Engineer
- C. Minarich, Operations Shift Supervisor
- M. Ouellette, Reactor Operator
- M. Pace, Operator
- C. Payne, System Engineer
- P. Possessky, Regulatory Assurance Manager
- J. Priest, Hope Creek Nuclear Shift Operations Manager
- M. Roman, Reactor Operator
- M. Rooney, Plant Engineer
- G. Ruf, Fukushima Project Engineering Manager
- M. Shaefer, Hope Creek Nuclear Simulator Training Instructor
- R. Shindel, Fukushima Project Training and Strategy
- M. Simpson, Fukushima Project Operations Specialist
- S. Simpson, Regulatory Assurance Manager
- J. Southerton, Shift Manager
- A. Tramontana, Program System Engineer
- H. Trimble, Radiation Protection Manger
- B. Wallace, Fukushima Project Operations Specialist
- C. Wend, Superintendent, Radiation Protection
- J. Witinski, Operations Shift Supervisor
- M. Wolk, Fukushima Project Operations Specialist
LIST OF ITEMS OPENED, CLOSED, DISCUSSED, AND UPDATED
Opened/Closed
- 05000354/2014005-01 NCV Failure to Identify and Correct a Condition Adverse to Quality Associated with Safety Relief Valve Discharge Piping Misalignment (Section 1R15)