IR 05000354/2017002
| ML17220A023 | |
| Person / Time | |
|---|---|
| Site: | Hope Creek  |
| Issue date: | 08/07/2017 |
| From: | Fred Bower Division Reactor Projects I |
| To: | Sena P Public Service Enterprise Group |
| References | |
| IR 2017002 | |
| Download: ML17220A023 (39) | |
Text
T. Joyce UNITED STATES NUCLEAR REGULATORY COMMISSION
REGION I
2100 RENAISSANCE BLVD., SUITE 100 KING OF PRUSSIA, PA 19406-2713 August 7, 2017 Mr. Peter P. Sena, III President and Chief Nuclear Officer PSEG Nuclear LLC - N09 P.O. Box 236 Hancocks Bridge, NJ 08038 SUBJECT: HOPE CREEK GENERATING STATION UNIT 1 - INTEGRATED INSPECTION REPORT 05000354/2017002
Dear Mr. Sena:
On June 30, 2017, the U.S. Nuclear Regulatory Commission (NRC) completed an inspection at Hope Creek Generating Station (HCGS). On July 13, 2017, the NRC inspectors discussed the results of this inspection with Mr. Edward Casulli, Plant Manager, and other members of your staff. The results of this inspection are documented in the enclosed report.
No NRC-identified or self-revealing findings were identified during this inspection. NRC inspectors documented one licensee-identified violation which was determined to be of very low safety significance (Green) in this report. The NRC is treating this violation as a non-cited violation (NCV) consistent with Section 2.3.2.a of the Enforcement Policy.
If you contest the violation or significance of the 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; and the NRC Resident Inspector at HCGS.
This letter, its enclosure, and your response (if any) will be made available for public inspection and copying at http://www.nrc.gov/reading-rm/adams.html and the NRC Public Document Room in accordance with 10 CFR 2.390, Public Inspections, Exemptions, Requests for Withholding.
Sincerely,
/RA/
Fred L. Bower, III, Chief Reactor Projects Branch 3 Division of Reactor Projects Docket No. 50-354 License No. NPF-57
Enclosure:
Inspection Report 05000354/2017002 w/Attachment: Supplementary Information
REGION I==
Docket No. 50-354 License No. NPF-57 Report No. 05000354/2017002 Licensee: PSEG Nuclear LLC (PSEG)
Facility: Hope Creek Generating Station (HCGS)
Location: Hancocks Bridge, NJ 08038 Dates: April 1, 2017 through June 30, 2017 Inspectors: J. Hawkins, Senior Resident Inspector S. Haney, Resident Inspector P. Boguszewski, Resident Inspector (Acting)
E. Burket, Senior Reactor Inspector N. Floyd, Reactor Inspector J. Furia, Senior Health Physicist Approved By: Fred L. Bower, III, Chief Reactor Projects Branch 3 Division of Reactor Projects Enclosure
SUMMARY
Inspection Report (IR) 05000354/2017002; 04/01/2017 - 06/30/2017; Hope Creek Generating
Station (HCGS).
This report covered a three-month period of inspection by resident inspectors and announced inspections performed by regional inspectors. 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 October 28, 2016. All violations of NRC requirements are dispositioned in accordance with the NRCs Enforcement Policy, dated November 1, 2016. The NRCs program for overseeing the safe operation of commercial nuclear power reactors is described in NUREG-1649, Reactor Oversight Process, Revision 6.
Other Findings
A violation of very low safety significance that was identified by PSEG was reviewed by the inspectors. Corrective actions (C/As) taken or planned by PSEG have been entered into PSEGs corrective action program (CAP). This violation and C/A tracking number are listed in Section 4OA7 of this report.
REPORT DETAILS
Summary of Plant Status
Hope Creek Generating Station began the inspection period at full rated thermal power (RTP).
On June 2, 2017, operators reduced power to approximately 76 percent RTP to support planned main turbine valve testing, control rod scram time and settle testing, control rod sequence exchange, and plant repairs. The unit was returned to 100 percent RTP on June 3, 2017. The unit remained at or near full 100 percent RTP for the remainder of the inspection period.
REACTOR SAFETY
Cornerstones: Initiating Events, Mitigating Systems, and Barrier Integrity
1R01 Adverse Weather Protection
.1 Readiness for Seasonal Extreme Weather Conditions
a. Inspection Scope
The inspectors reviewed PSEGs readiness for the onset of seasonal high temperatures during the week of May 15. The review focused on the station service water system (SSWS) and the emergency diesel generators (EDGs). The inspectors reviewed the Updated Final Safety Analysis Report (UFSAR), technical specifications (TSs), control room logs, and the 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 hot weather conditions. Documents reviewed for each section of this inspection report are listed in the Attachment.
b. Findings
No findings were identified.
.2 Summer Readiness of Offsite and Alternate Alternating Current Power Systems
a. Inspection Scope
The inspectors reviewed plant features and procedures for the operation and continued availability of the offsite and alternate alternating current (AC) power system to evaluate readiness of the systems prior to seasonal high grid loading on June 15. The inspectors reviewed PSEGs procedures affecting these areas and the communications protocols between the transmission system operator and PSEG. This review focused on changes to the established program and material condition of the offsite and alternate AC power equipment. The inspectors assessed whether PSEG established and implemented appropriate procedures and protocols to monitor and maintain availability and reliability of both the offsite AC power system and the onsite alternate AC power system. The inspectors evaluated the material condition of the associated equipment by interviewing the responsible system manager, reviewing condition reports and open work orders (WOs), and walking down portions of the offsite and AC power systems including the 500 kilovolt (kV) and 13.8 kV switchyards.
b. Findings
No findings were identified.
1R04 Equipment Alignment
.1 Partial System Walkdown
a. Inspection Scope
The inspectors performed partial walkdowns of the following systems:
- Reactor core isolation cooling (RCIC) system following overhead alarms for the turbine steam supply drain pot high level and potential moisture build up on April 10
- Station service water (SSW) service water intake structure (SWIS) during the week of April 20
- B and D SSW with C SSW inoperable on June 6 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, WOs, notifications (NOTFs), and the impact of ongoing work activities on redundant trains of equipment in order to identify conditions that could have impacted the systems performance of its 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.
.2 Full System Walkdown
a. Inspection Scope
During the week of June 26, the inspectors performed a complete system walkdown of accessible portions of the high pressure coolant injection (HPCI) system to verify the existing equipment lineup was correct. The inspectors reviewed operating procedures, surveillance tests, drawings, equipment line-up check-off lists, and the UFSAR to verify the system was aligned to perform its required safety functions. The inspectors also reviewed electrical power availability, component lubrication and equipment cooling, hanger and support functionality, and operability of support systems. The inspectors performed field walkdowns of accessible portions of the systems to verify as-built system configuration matched plant documentation, and that system components and support equipment remained operable. The inspectors confirmed that systems and components were aligned correctly, free from interference from temporary services or isolation boundaries, environmentally qualified, and protected from external threats. The inspectors also examined the material condition of the components for degradation and observed operating parameters of equipment to verify that there were no deficiencies.
For identified degradation the inspectors confirmed the degradation was appropriately managed by the applicable aging management program. Additionally, the inspectors reviewed a sample of related NOTFs and WOs to ensure PSEG appropriately evaluated and resolved any deficiencies.
b. Findings
No findings were identified.
1R05 Fire Protection
Resident Inspector Quarterly Walkdowns (71111.05Q - 5 samples)
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, 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-II-541, Class 1E switchgear rooms on April 4
- FRH-II-412 , RCIC pump and turbine room, residual heat removal (RHR) pump and heat exchanger (HX) rooms and electric equipment room during the week of April 11
- FRH-II-713, SWIS during the week of April 20
- FRH-II-424, Motor control center area during the week of April 20
- FRH-II-532, Lower control equipment room during the week of May 1
b. Findings
No findings were identified.
1R06 Flood Protection Measures
Annual Review of Cables Located in Underground Bunkers/Manholes
a. Inspection Scope
The inspectors conducted a review of the inspection of underground bunkers/manholes subject to flooding that contain cables whose failure could affect risk-significant equipment, specifically manholes for the AX501 and BX501 transformers. When applicable, the inspectors verified proper sump pump operation and verified level alarm circuits were set in accordance with station procedures and calculations to ensure that the cables will not be submerged. The inspectors also ensured that drainage was provided and functioning properly in areas where dewatering devices were not installed.
b. Findings
No findings were identified.
1R07 Heat Sink Performance
Triennial Review (71111.07T - 3 samples)
a. Inspection Scope
Based on PSEGs risk ranking of safety-related HXs, a review of past triennial heat sink inspections, recent operational experience, and NRC resident inspector input, the inspectors selected the following two HXs for detailed review: HPCI room cooler; and A EDG jacket water HX. The inspectors also selected the SSWS as an ultimate heat sink sample.
For the samples selected, the inspectors reviewed program and system health reports, self-assessments, and PSEGs methods (inspection, cleaning, maintenance, and performance monitoring) used to ensure heat removal capabilities for the HCGS safety-related HXs and compared them to PSEGs commitments made in response to NRC Generic Letter 89-13, Service Water System Problems Affecting Safety-Related Equipment. The inspectors verified that the methods and acceptance criteria were consistent with the accepted industry practices.
Ultimate Heat Sink The inspectors reviewed the SSWS at HCGS, which takes suction from the Delaware River, functioning as the ultimate heat sink. The SSWS then provides the river water to cool the reactor auxiliary cooling system HXs and the safety auxiliary cooling system (SACS) HXs, where SACS is the system designed to cool the safety-related components throughout the plant. The SSWS and the ultimate heat sink are required to be operable during all modes of operation. The inspectors reviewed the system design and operation to evaluate the impact of modifications and age-related changes that have the potential to adversely impact the function of the system. The inspectors reviewed design drawings, calculations, and operating procedures to verify they were consistent with the design and licensing basis. The inspectors also reviewed HCGSs abnormal operating procedures related to service water abnormal operation and verified that instrumentation relied upon for decision making was available and functional. The inspectors verified that PSEG conducted maintenance and chemistry programs to adequately control, detect, and prevent system degradation due to micro- and macro-fouling in the system, and that results were trended and evaluated.
The inspectors performed a walk down of the SWIS (including the trash racks, traveling water screens (TWSs), service water pumps and strainers, spray booster pumps, and structural supports), and the accessible areas of the Reactor Building containing SSWS piping to assess the material condition of the associated system components. The inspectors verified that intake structure pump bay silt accumulation was monitored, trended, and maintained at an acceptable level. The inspectors interviewed the responsible PSEG engineering personnel, reviewed silt deposition inspection documentation, and the results of past completed bay silt cleaning WOs.
The inspectors reviewed a sample of SSWS performance testing of pumps and valves as part of the inservice testing (IST) program to verify that any potential adverse trends in component performance were detected. The inspectors noted that PSEG does not perform flow balancing of the SSWS at HCGS. The inspectors reviewed non-destructive examination records and photographs, including recent inspections of the buried portions of the service water piping, to verify structural integrity and to ensure that any component or piping degradation was appropriately identified and dispositioned by PSEG staff. The inspectors observed that there were no recent history of through-wall pipe leaks since the last NRC triennial inspection and that the system had been available to perform its ultimate heat sink safety function.
Heat Exchangers Directly Cooled by a Closed Loop Cooling Water System The inspectors reviewed the programs and procedures for maintaining the safety functions of the HPCI room cooler and the A EDG jacket water HX, which are both cooled by SACS. The SACS at HCGS supplies cooling water to safety-related components, which are required for normal operation, safe shutdown, and/or to mitigate the consequences of an accident. For the HXs selected, the inspectors reviewed the vendor design specifications and verified that the condition and operation were consistent with design assumptions in the heat transfer calculations. Neither of the two HXs were monitored by thermal performance testing or cleaning and inspection because they are part of a closed-loop cooling water system.
The inspectors reviewed the results from chemistry monitoring of the SACS system to verify that programs for corrosion control were consistent with industry standards and were controlled, tested, and evaluated to prevent degradation of components cooled by SACS. The inspectors reviewed pictures from a recent HX visual inspection of another component cooled by SACS to verify the effectiveness of the chemical treatment program and to verify no other degradation was present. The inspectors also reviewed completed preventative maintenance, surveillance tests, and monitoring of system parameters to verify that the HXs are appropriately maintained to perform their design function. The inspectors interviewed PSEG staff and walked down accessible portions of piping, pumps, valves, and HXs to assess the material condition of the components.
Problem Identification and Resolution The inspectors reviewed a sample of HCGSs C/A reports related to the ultimate heat sink and HXs selected for this inspection. The inspectors verified that non-conforming conditions were properly identified, characterized, evaluated, and that C/As were identified and entered into the CAP for resolution.
b. Findings
No findings were identified.
1R11 Licensed Operator Requalification Program
.1 Quarterly Review of Licensed Operator Requalification Testing and Training
a. Inspection Scope
The inspectors observed licensed operator simulator training on April 17, which included a loss of the BD481 inverter, flooding in the SWIS, loss of stator water cooling coincident with a failure of the reactor recirculation pumps to runback, a loss of offsite power with a failure of the B EDG and a break of a downcomer resulting in a loss of coolant accident.
The inspectors evaluated operator performance during the simulated event and verified completion of 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 classifications made by the shift manager and the TS action statements entered by the shift technical advisor.
Additionally, the inspectors assessed the ability of the crew and 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
a. Inspection Scope
The inspectors observed and reviewed a planned reduction in power on June 2, to approximately 76 percent RTP to support planned main turbine valve testing, control rod scram time and settle testing, control rod sequence exchange, and plant repairs. The unit was returned to 100 percent RTP on June 3. The inspectors observed operator 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.
1R12 Maintenance Effectiveness
a. Inspection Scope
The inspectors reviewed the samples listed below to assess the effectiveness of maintenance activities on structure, system, and component (SSC) performance and reliability. The inspectors reviewed system health reports, CAP documents, maintenance WOs, and maintenance rule basis documents to ensure that PSEG was identifying and properly evaluating performance problems within the scope of the maintenance rule (MR). For each sample selected, the inspectors verified that the SSC was properly scoped into the MR in accordance with Title 10 of the Code of Federal Regulations (10 CFR) 50.65 and verified that the (a)(2) performance criteria established by PSEG staff was reasonable. As applicable, for SSCs classified as (a)(1), the inspectors assessed the adequacy of goals and C/As to return these SSCs to (a)(2).
Additionally, the inspectors ensured that PSEG staff was identifying and addressing common cause failures that occurred within and across MR system boundaries.
- B channel instrument rack not vented on November 9, 2016
- Redundant reactivity control system three year review performed the week of April 24
- Review of seismic switch unexpected alarm during the week of April 20
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 TS requirements and inspected portions of redundant safety systems, when applicable, to verify risk analysis assumptions were valid, and applicable requirements were met.
- Protected equipment and risk assessment for performance of a troubleshooting plan (17-069) to energize relay 10G on April 13
- A SACS pump breaker troubleshooting on June 13
- CX501 transformer and D EDG planned maintenance on June 22
- D EDG speed switch replacement on June 23
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 based on the risk significance of the associated components and systems:
- A EDG past operability review on April 2
- Review of degraded SSW structural supports during the week of April 20
- Review of RCIC turbine steam line drain pot and condensate backup and potential water migrating into the turbine oil during the week of April 26
- Review of insulation missing from HPCI and RCIC pumps during the week of May 1 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. The inspectors confirmed, where appropriate, compliance with bounding limitations associated with the evaluations.
b. Findings
No findings were identified.
1R18 Plant Modifications
Permanent Modifications
a. Inspection Scope
The inspectors evaluated a modification to the cable vault dewatering and oily waste system implemented by engineering change package 80120219. The inspectors verified that the design bases, licensing bases, and performance capability of the affected systems were not degraded by the modification. In addition, the inspectors reviewed modification documents associated with the upgrade and design change. The inspectors also interviewed engineering and operations personnel.
b. Findings
No findings were identified.
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 adequately tested the safety functions that may have been affected by the maintenance activity, that the acceptance criteria in the procedure were consistent with the information in the applicable licensing basis and/or design basis documents, and that the test results were properly reviewed and accepted and problems were appropriately documented. The inspectors also walked down the affected job site, observed the pre-job brief and post-job critique where possible, confirmed work site cleanliness was maintained, and witnessed the test or reviewed test data records to verify quality control hold points were performed and checked, and that results adequately demonstrated restoration of the affected safety functions.
- Unplanned flow decrease and repair during A reactor recirculation flow unit channel A troubleshooting an on April 7 (WO 50189285)
- A reactor water cleanup (RWCU) pump motor replacement on April 19 (WO 60133899)
- A recirculation motor generator set ventilation fan (AV107) troubleshooting noise/high vibrations, breaker and belt replacement during the week of April 25 (WOs 60134555 and 60134392)
- A RWCU gasket repair on May 1 (WO 60133923)
- B SSW TWS repairs on June 15 (WO 60135339)
- D EDG speed switch replacement on June 25 (WO 80119127)
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 TSs, 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.BE-0101, A core spray system valves IST on April 3
- HC.OP-IS.BH-0003, A standby liquid control pump IST on June 1
b. Findings
No findings were identified.
Cornerstone: Emergency Preparedness
1EP2 Alert and Notification System Evaluation
a. Inspection Scope
An onsite review was conducted to assess the maintenance and testing of the alert and notification system (ANS). During this inspection, the inspectors conducted a review of the Artificial Island siren testing and maintenance programs. The inspectors reviewed the associated ANS procedures and the Federal Emergency Management Agency approved ANS Design Report to ensure PSEGs compliance with design report commitments for system maintenance and testing. Title 10 CFR 50.47(b)(5) and the related requirements of 10 CFR Part 50, Appendix E, were used as reference criteria.
b. Findings
No findings were identified.
1EP3 Emergency Response Organization Staffing and Augmentation System
a. Inspection Scope
The inspectors conducted a review of HCGSs Emergency Response Organization (ERO) augmentation staffing requirements and the process for notifying and augmenting the ERO. The review was performed to verify the readiness of key PSEG staff to respond to an emergency event and to verify PSEGs ability to activate their emergency response facilities (ERFs) in a timely manner. The inspectors reviewed: the PSEG Nuclear LLC Emergency Plan for ERF activation and ERO staffing requirements; the ERO duty roster; applicable station procedures; augmentation test reports; the most recent drive-in drill reports; and C/A reports related to this inspection area. The inspectors also reviewed a sample of ERO responder training records to verify training and qualifications were up to date. Title 10 CFR 50.47(b)
- (2) and related requirements of 10 CFR Part 50, Appendix E, were used as reference criteria.
b. Findings
No findings were identified.
1EP5 Maintaining Emergency Preparedness
a. Inspection Scope
(71114.05 - 1 sample)
The inspectors reviewed a number of activities to evaluate the efficacy of PSEGs efforts to maintain the HCGSs emergency preparedness (EP) program. The inspectors reviewed: memoranda of agreement with offsite agencies; the 10 CFR 50.54(q)
Emergency Plan change process and practice; PSEGs maintenance of equipment important to EP; records of emergency planning zone population estimates; and provisions for, and implementation of, primary, backup, and alternative emergency response facility maintenance.
The inspectors further evaluated PSEGs ability to maintain the HCGS EP programs through their identification and correction of EP weaknesses, by reviewing a sample of drill reports, self-assessments, and 10 CFR 50.54(t) reviews. Also, the inspectors reviewed a sample of EP-related condition reports initiated at HCGS from July 2015 through May 2017. Title 10 CFR 50.47(b) and the related requirements of 10 CFR Part 50, Appendix E, were used as reference criteria.
b. Findings
No findings were identified.
1EP6 Drill Evaluation
Emergency Preparedness Drill Observation
a. Inspection Scope
The inspectors evaluated the conduct of a routine PSEG emergency drill on May 23, to identify any weaknesses and deficiencies in the classification, notification, and protective action recommendation development activities. The inspectors observed emergency response operations in the simulator, technical support center, and emergency operations facility to determine whether the event classification, notifications, and protective action recommendations were performed in accordance with procedures. The inspectors also attended the station drill critique to compare inspector observations with those identified by PSEG staff in order to evaluate PSEGs critique and to verify whether the PSEG staff was properly identifying weaknesses and entering them into the CAP.
b. Findings
No findings were identified.
RADIATION SAFETY
Cornerstones: Occupational and Public Radiation Safety
2RS6 Radioactive Gaseous and Liquid Effluent Treatment
a. Inspection Scope
The inspectors reviewed the treatment, monitoring, and control of radioactive gaseous and liquid effluents. The inspectors used the requirements in 10 CFR Part 20; 10 CFR Part 50, Appendix I; TS; Offsite Dose Calculation Manual (ODCM); applicable industry standards; and procedures required by TSs as criteria for determining compliance.
Inspection Planning
The inspectors conducted in-office reviews of the HCGS 2015 and 2016 annual radioactive effluent and environmental reports, radioactive effluent program documents, UFSAR, ODCM, and applicable event reports.
Walkdowns and Observations (1 sample)
The inspectors walked down the gaseous and liquid radioactive effluent monitoring and filtered ventilation systems to assess the material condition and verify proper alignment according to plant design. The inspectors also observed potential unmonitored release points and reviewed radiation monitoring system surveillance records and the routine processing and discharge of gaseous and liquid radioactive wastes.
Calibration and Testing Program (1 sample)
The inspectors reviewed gaseous and liquid effluent monitor instrument calibration, functional test results, and alarm setpoints based on National Institute of Standards and Technology calibration traceability and ODCM specifications.
Sampling and Analyses (1 sample)
The inspectors reviewed radioactive effluent sampling activities, representative sampling requirements, compensatory measures taken during effluent discharges with inoperable effluent radiation monitoring instrumentation, the use of compensatory radioactive effluent sampling, and the results of the inter-laboratory and intra-laboratory comparison program, including scaling of hard-to-detect isotopes.
Instrumentation and Equipment (1 sample)
The inspectors reviewed the methodology used to determine the radioactive effluent stack and vent flow rates to verify that the flow rates were consistent with TS/ODCM and UFSAR values. The inspectors reviewed radioactive effluent discharge system surveillance test results based on TS acceptance criteria. The inspectors verified that high-range effluent monitors used in emergency operating procedures are calibrated and operable and have post-accident effluent sampling capability.
Dose Calculations (1 sample)
The inspectors reviewed changes in reported dose values from the previous annual radioactive effluent release reports, several liquid and gaseous radioactive waste discharge permits, the scaling method for hard-to-detect radionuclides, ODCM changes, land use census changes, public dose calculations (monthly, quarterly, annual), and records of abnormal gaseous or liquid radioactive releases.
Problem Identification and Resolution (1 sample)
The inspectors evaluated whether problems associated with the radioactive effluent monitoring and control program were identified at an appropriate threshold and properly addressed in HCGSs CAP.
b. Findings
No findings were identified.
OTHER ACTIVITIES
4OA1 Performance Indicator Verification
.1 Unplanned Scrams, Unplanned Power Changes, and Unplanned Scrams with
Complications (3 samples)
a. Inspection Scope
The inspectors reviewed PSEGs submittals for the following Initiating Events (IE)
Cornerstone Performance Indicators (PIs) for the period of January 1, 2016 through March 31, 2017:
- Unplanned Scrams (IE01)
- Unplanned Power Changes (IE03)
- Unplanned Scrams with Complications (IE04)
To determine the accuracy of the PI data reported during those periods, the inspectors used definitions and guidance contained in Nuclear Energy Institute (NEI) Document 99-02, Regulatory Assessment Performance Indicator Guideline, Revision 7. The inspectors also reviewed HCGSs operator narrative logs, NOTFs, event reports, and NRC integrated inspection reports to validate the accuracy of the submittals.
a. Findings
No findings were identified.
.2 Reactor Coolant System Specific Activity and RCS Leak Rate (2 samples)
a. Inspection Scope
The inspectors reviewed PSEGs submittal for the reactor coolant system (RCS) specific activity and RCS leak rate PIs for the period of April 1, 2016, through March 31, 2017.
To determine the accuracy of the PI data reported during those periods, the inspectors used definitions and guidance contained in NEI Document 99-02, Regulatory Assessment Performance Indicator Guideline, Revision 7. The inspectors also reviewed RCS sample analysis and control room logs of daily measurements of RCS leakage, and compared that information to the data reported by the PI.
b. Findings
No findings were identified.
.3 Emergency Preparedness Performance Indicators (3 samples)
a. Inspection Scope
The inspectors reviewed data for the following three EP PIs:
- (1) drill and exercise performance;
- (2) ERO drill participation; and,
- (3) ANS reliability. The last NRC EP inspection at HCGS was conducted in the second calendar quarter of 2016. Therefore, the inspectors reviewed supporting documentation from EP drills and equipment tests from the second calendar quarter of 2016 through the first calendar quarter of 2017 to verify the accuracy of the reported PI data. The review of the PIs was conducted in accordance with NRC Inspection Procedure 71151. The acceptance criteria documented in NEI 99-02, Regulatory Assessment Performance Indicator Guidelines, Revision 7, was used as reference criteria.
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 PSEG entered issues into their CAP at an appropriate threshold, gave adequate attention to timely C/As, 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 their CAP and periodically attended condition report screening meetings. The inspectors also confirmed, on a sampling basis, that, as applicable, for identified defects and non-conformances, PSEG performed an evaluation in accordance with 10 CFR Part 21.
b. Findings
No findings were identified.
.2 Semi-Annual Trend Review
a. Inspection Scope
The inspectors performed a semi-annual review of site issues to identify trends that might indicate the existence of more significant safety concerns. As part of this review, the inspectors included repetitive or closely-related issues documented by PSEG included repetitive or closely-related issues that may have been documented by PSEG outside of the CAP, such as trend reports, PIs, major equipment problem lists, system health reports, MR assessments, and maintenance or CAP backlogs. The inspectors also reviewed PSEG CAP database for the third and fourth quarters of 2016 and first and second quarters of 2017 to assess NOTFs written in various subject areas (equipment problems, human performance issues, etc.), as well as individual issues identified during the inspectors daily condition report review (Section 4OA2.1). The inspectors reviewed the PSEG CAP trending data, 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.
Service Water Intake Structure Material Condition The HCGS SWIS houses four SSW pumps, TWS, strainers, piping, ventilation, and other necessary support equipment. The SWIS has areas of identified deterioration due to exposure to brackish and corrosive river water. PSEG is planning to improve the condition of the SWIS and related systems as recommended by the SWIS Improvement Project. The inspectors reviewed NOTFs, ensured the completion and progress of C/As, performed walkdowns of equipment areas and the building exterior and shoreline, conducted interviews of engineering personnel, reviewed calculations, and reviewed evaluations of identified adverse conditions.
Shore protection is required in the vicinity of the SWIS, and consists of sheet pile cellular cofferdams (cofferdams). In 2009, PSEG identified degradation to the cofferdams resulting in loss of the aggregate stone fill material. The operability screening performed for NOTF 20422947 determined that the fill does not provide structural support for the gantry crane or SWIS, and that service water remained operable. The cofferdams were walked down by engineering in 2014 under order 60085042 and determined that a repair was not required at that time. Engineering noted corrosion to the cofferdam sheet steel structure, and requested a re-inspection to reassess the condition and recommend a repair plan. The re-inspection would entail divers to evaluate the condition of the cofferdam below the low tide water level. The inspectors identified this re-inspection was never performed. NOTF 20768443 was generated to plan and perform the re-inspection.
The inspectors also noted that while the operability screening evaluated the structural stability of SWIS as it related to SSWS operability, the functionality of the cofferdams was not addressed. Section 2.4.10 of the HCGS UFSAR describes the design of the SWIS shoreline protection and the cofferdams, and also states that they will be stable under the design seismic event and design flood (probable maximum hurricane). NOTF 20770923 was generated and determined that the degradation and loss of the aggregate stone fill material did not affect the cofferdams function to protect and stabilize the shoreline.
The inspectors evaluated these issues above in accordance with the guidance in IMC 0612, Appendix B, Issue Screening, and Appendix E, Examples of Minor Issues, and determined the issues of concern were of minor significance because the structural stability of the SWIS was maintained and cofferdams maintained their ability to perform their UFSAR required function.
4OA3 Follow-Up of Events and Notices of Enforcement Discretion
.1 Plant Events
a. Inspection Scope
For the plant events listed below, the inspectors reviewed and/or observed plant parameters, reviewed personnel performance, and evaluated performance of mitigating systems. The inspectors communicated the plant events to appropriate regional personnel, and compared the event details with criteria contained in IMC 0309, Reactive Inspection Decision Basis for Reactors, for consideration of potential reactive inspection activities. As applicable, the inspectors verified that PSEG made appropriate emergency classification assessments and properly reported the event in accordance with 10 CFR Parts 50.72 and 50.73. The inspectors reviewed PSEGs follow-up actions related to the events to assure that PSEG implemented appropriate C/As commensurate with their safety significance.
- Seismic monitor panel was declared non-functional when operators received an unexpected alarm which normally indicates an actuation of the HCGS operational basis earthquake seismic switch with no other indications of seismic activity on April 20 (EN 52698)
b. Findings
No findings were identified.
.2 (Closed) Licensee Event Report (LER) 05000354/2015-005-00: Reactor Scram Due to
Invalid RRCS Actuation On September 28, 2015, a human error during surveillance testing resulted in the actuation of the redundant reactivity control system (RRCS), and subsequently an automatic reactor scram on a valid low reactor water level signal. At the time of the transient, a surveillance test of division 1 of the RRCS system was in progress. The test simulates a high reactor pressure signal. Plant data shows the signal was entered in both channels of division 1 of the RRCS system. The resulting system actuation caused a trip of both reactor recirculation pumps and the actuation of the alternate rod insertion function of the RRCS system. As a result of these two actuations, reactor power lowered, causing reactor water level to lower to the reactor protection system (RPS) trip set point of +12.5 inches, and initiated an automatic reactor scram.
This condition was reported under 10 CFR 50.73(a)(2)(iv)(A) as an event that resulted in an automatic actuation of the RPS system. The inspectors reviewed PSEGs LER, root cause evaluation report (70180315), supporting documentation, station procedures, and interviewed several members of station staff and management regarding the event. No new findings were identified during this inspection. A Severity Level III Notice of Violation was previously issued to PSEG on May 3, 2017 (ML17122A282). This LER is closed.
4OA6 Meetings, Including Exit
On July 13, 2017, the inspectors presented the inspection results to Mr. Edward Casulli, Plant Manager, and other members of the PSEG staff. The inspectors verified that no proprietary information was retained by the inspectors or documented in this report.
PSEG management acknowledged and did not dispute the findings.
4OA7 Licensee-Identified Violations (994OA7 - 1 sample)
The following violation of very low safety significance (Green) was identified by PSEG and is a violation of NRC requirements which meets the criteria of the NRC Enforcement Policy, for being dispositioned as a non-cited violation (NCV):
On February 27, 2017, during power ascension after completing a rod pattern adjustment, HCGS exceeded the fuel conditioning limit specified in their Boiling Water Reactor (BWR) Fuel Conditioning procedure, NF-AB-440. Specifically, when all of the control rods were at their target positions, with reactor power at 89 percent RTP, the on-shift Reactor Engineer ran a core monitor predictor case which showed three percent more margin to the fuel conditioning limit than the predictions used in the written reactivity management plan. The Reactor Engineer then ran core predictions using this result. With these results, the Reactor Engineer recommended to the Control Room Supervisor to proceed to 100 percent RTP with no ramp rate restrictions. PSEG completed power ascension to 100 percent RTP and then a subsequent core monitor predictor case showing the fuel conditioning limit had been exceeded (maximum nodal power of 0.55 kilowatt/foot which exceeded the maximum allowed value of 0.450 kilowatt/foot). PSEG determined that weaknesses in the reactivity maneuver (ReMA)process and the application of the ReMA process allowed the on-shift Reactor Engineer to make a knowledge-based decision and implement a change to the ReMA without increased monitoring requirements.
Failure to operate within the procedurally specified limits was a performance deficiency.
TS 6.8.1.a requires, in part, that written procedures be established and implemented covering the procedures recommended in Regulatory Guide 1.33, Revision 2, Appendix A, February 1978. OP-AB-300-1003, BWR Reactivity Maneuver Guidance, states in step 4.2.11.4, the high limit should be set at the limit specified in NF-AB-440.
In Attachment 5 of NF-AB-440, operators are directed to maintain the fuel conditioning limits within the specified maximum allowable threshold of 0.45 kilowatt/foot. Contrary to the TS 6.8.1.a requirements specified above, PSEG did not implement their ReMA in accordance with their procedures for reactivity maneuvers.
Shortly after reaching 100 percent RTP power, PSEG identified that the fuel conditioning limit had been exceeded and took immediate actions to reduce power per procedure, categorize the issue as a level 3 reactivity management event, and analyze off-gas and reactor coolant samples to ensure no indications of a fuel defect existed as a result of the event. The issue was entered into PSEGs CAP as NOTF 20757793, and the operating department implanted prompt action to communicate the cause of the error to all operators and qualified reactor engineers. In addition, procedural reviews and additional management observations of power maneuvering activities were put in place.
The inspectors determined this issue was more than minor because the performance deficiency impacted the Human Performance attribute of the Barrier Integrity Cornerstone and adversely impacted the cornerstone objective to provide reasonable assurance that the physical design barrier (fuel cladding) protect the public from radionuclide releases caused by accidents or events. Specifically, PSEG not adhering to the fuel conditioning limits specified in their procedures could result in fuel clad damage (increased probability of fuel failure as a result of pellet-clad interaction) and adversely impact nuclear safety. The inspectors determined that the issue was of very low safety significance (Green) because no apparent fuel damage occurred.
ATTACHMENT:
SUPPLEMENTARY INFORMATION
KEY POINTS OF CONTACT
Licensee Personnel
- E. Carr, Site Vice President
- E. Casulli, Plant Manager
- S. Barr, Manager, Emergency Preparedness
- D. Bedford, System Engineer
- K. Culver, Chemistry Supervisor
- A. Ghose, Principal Nuclear Engineer
- T. Gingerich, System Engineer
- A. Hak, System Engineer
- R. Heathwaite, Chemistry
- J. Krall, Reactor Engineering Manager
- D. Mannai, Senior Director Regulatory Operations
- T. MacEwen, Regulatory Assurance
- A. Ochoa, Regulatory Affairs
- A. Preston, Senior Nuclear Engineer
- J. Priest, Nuclear Shift Operations Manager
- K. Torres, Programs Supervisor
- G. Zeiger, Chemistry Supervisor