IR 05000272/2015001
| ML15118A818 | |
| Person / Time | |
|---|---|
| Site: | Salem  |
| Issue date: | 04/28/2015 |
| From: | Glenn Dentel Reactor Projects Branch 3 |
| To: | Braun R Public Service Enterprise Group |
| dentel, gt | |
| References | |
| IR 2015001 | |
| Download: ML15118A818 (33) | |
Text
T. Joyce UNITED STATES NUCLEAR REGULATORY COMMISSION
REGION I
2100 RENAISSANCE BLVD., SUITE 100 KING OF PRUSSIA, PA 19406-2713 April 28, 2015 Mr. Robert Braun President and Chief Nuclear Officer PSEG Nuclear LLC - N09 P.O. Box 236 Hancocks Bridge, NJ 08038 SUBJECT: SALEM NUCLEAR GENERATING STATION, UNIT NOS. 1 AND 2 -
NRC INTEGRATED INSPECTION REPORT 05000272/2015001 AND 05000311/2015001
Dear Mr. Braun:
On March 31, 2015, the U.S. Nuclear Regulatory Commission (NRC) completed an inspection at your Salem Nuclear Generating Station, Units 1 and 2. The enclosed inspection report documents the inspection results, which were discussed on April 16, 2015, with Mr. John Perry, Salem Site Vice President, 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 two NRC-identified findings of very low safety significance (Green).
Both of these findings were determined to involve violations of NRC requirements. However, because of the very low safety significance, and because they are entered into your corrective action program, the NRC is treating these findings as non-cited violations, consistent with Section 2.3.2.a of the NRC Enforcement Policy. If you contest the non-cited violations in this report, you should provide a response within 30 days of the date of this inspection report, with the basis for your denial, to the Nuclear Regulatory Commission, ATTN: Document Control Desk, Washington, DC 20555-0001; with copies to the Regional Administrator, Region I; the Director, Office of Enforcement, United States Nuclear Regulatory Commission, Washington, DC 20555-0001; and the NRC Resident Inspector at Salem Nuclear Generating Station. In addition, if you disagree with the cross-cutting aspect assigned to any finding, or a finding not associated with a regulatory requirement in this report, 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 Salem Nuclear Generating Station.
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 Nos. 50-272, 50-311 License Nos. DPR-70, DPR-75
Enclosure:
Inspection Report 05000272/2015001 and 05000311/2015001 w/Attachment: Supplementary Information
REGION I==
Docket Nos. 50-272, 50-311 License Nos. DPR-70, DPR-75 Report Nos. 05000272/2015001 and 05000311/2015001 Licensee: PSEG Nuclear LLC (PSEG)
Facility: Salem Nuclear Generating Station, Units 1 and 2 Location: P.O. Box 236 Hancocks Bridge, NJ 08038 Dates: January 1, 2015 through March 31, 2015 Inspectors: P. Finney, Senior Resident Inspector A. Ziedonis, Resident Inspector E. Burket, Emergency Preparedness Inspector R. Barkley, Senior Project Engineer L. Dumont, Reactor Inspector T. Hedigan, Operations Engineer Approved By: Glenn T. Dentel, Chief Reactor Projects Branch 3 Division of Reactor Projects Enclosure
SUMMARY
Inspection Report (IR) 05000272/2015001, 05000311/2015001; 01/01/2015 - 03/31/2015;
Salem Nuclear Generating Station Units 1 and 2; Operability Determinations and Functionality Assessments, Post-Maintenance Testing.
This report covered a three-month period of inspection by resident inspectors and announced inspections performed by regional inspectors. Inspectors identified two non-cited violations (NCVs) of very low safety significance (Green). 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, Aspects Within the Cross-Cutting Areas, dated December 19, 2013. All violations of NRC requirements are dispositioned in accordance with the NRCs Enforcement Policy, dated July 9, 2013. The NRCs program for overseeing the safe operation of commercial nuclear power reactors is described in NUREG-1649, Reactor Oversight Process, Revision 5, dated February 2014.
Cornerstone: Mitigating Systems
- Green.
Inspectors identified a Green NCV of 10 CFR 50, Appendix B, Criterion XVI,
Corrective Action, when PSEG did not implement adequate corrective actions from a previous Green NCV in a timeframe commensurate with its safety significance. Specifically, inadequate corrective actions resulted in high energy line break (HELB) and moderate energy line break (MELB) barriers being unsecured without implementing the associated station process. PSEG immediate corrective actions were to secure the affected barriers and enter these examples in their CAP as notifications 20677643, 20683127, 20680283, and 20680680.
The issue was evaluated in accordance with IMC 0612, Appendix B, and determined to be more than minor since it was associated with the configuration control attribute of the Mitigating Systems cornerstone and adversely affected its objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. Using IMC 0609, Appendix A, it screened to Green since it was not associated with a design or qualification deficiency or loss of system or function. The issue had a cross-cutting issue in Problem Identification and Resolution, Evaluation, in that organizations thoroughly evaluate issues to ensure that resolutions address causes and extent of conditions commensurate with their safety significance. Specifically, PSEG did not thoroughly investigate and evaluate the previous NCV issues in order to understand the bases for staff decisions and the underlying organizational and safety culture contributors.
[P.2] (Section 1R19)
Cornerstone: Barrier Integrity
- Green.
The inspectors identified a Green NCV of TS 3.9.12, Fuel Handling Area Ventilation System, when PSEG did not suspend Unit 1 fuel movement operations when the fuel handling area ventilation system was inoperable. Specifically, differential pressure exceeded its alarm setpoint, and at times, was positive during irradiated fuel movements.
Once aware of the issue, PSEG immediately suspended fuel movement, placed fuel assemblies in a safe condition, and entered the issue in their CAP as notifications 20677427 and 20678063.
The issue was determined to be more than minor since it affected the configuration control/barrier performance attribute of the Barrier Integrity cornerstone and adversely affected its objective to provide reasonable assurance that physical design barriers protect the public from radionuclide releases caused by accidents or events. The finding was screened using IMC 0609, Attachment 4 and Appendix A, Exhibit 3.C for Barrier Integrity screening questions involving the spent fuel pool building. Since the finding only represented a degradation of the radiological barrier function provided for the spent fuel pool, the finding screened to
- Green.
This finding had a cross-cutting aspect in Human Performance, Procedure Adherence, in that individuals follow processes, procedures, and instructions. Specifically, PSEG operators did not follow alarm response and general operating procedures, did not use human error reduction techniques with respect to receipt of multiple low FHB D/P alarms, and manipulated irradiated fuel when not appropriately authorized and directed by procedures. [H.8] (Section 1R15)
REPORT DETAILS
Summary of Plant Status
Unit 1 began the inspection period at 100 percent. On March 7, the unit was reduced to 50 percent power in support of 12 steam generator feedpump (SGFP) corrective maintenance.
The unit returned to 100 percent power on March 10. On March 12, the unit was reduced to approximately 60 percent power in response to a control oil leak on the 12 SGFP. On March 15, the unit was shut down to comply with Technical Specifications (TSs) for the 14 containment fan coil unit (CFCU) that had exceeded its allowed outage time. A reactor startup was commenced on March 22. The unit reached 98 percent power at the end of the inspection period.
Unit 2 began the inspection period at 100 percent. On February 4, Unit 2 was reduced to 60 percent power in response to a main condenser tube leak. The unit returned to 100 percent power on February 7. The unit remained at or near 100 percent power for the remainder of the inspection period.
REACTOR SAFETY
Cornerstones: Initiating Events, Mitigating Systems, and Barrier Integrity
1R01 Adverse Weather Protection
.1 Readiness for Impending Adverse Weather Conditions
a. Inspection Scope
The inspectors reviewed PSEGs preparations during impending extended cold conditions the week of January 5 and an impending blizzard on January 26. The inspectors reviewed the implementation of adverse weather preparation procedures before the onset of and during these adverse weather conditions. The inspectors walked down the service water (SW) intake structure, circulating water intake structure, Unit 3 gas turbine engine and control house, SW accumulators, freshwater pumphouse, effluent radiation monitors, and Unit 1 and 2 auxiliary buildings. The inspectors verified that operator actions defined in PSEGs adverse weather procedure maintained the readiness of essential systems. The inspectors discussed readiness and staff availability for adverse weather response with operations and work control personnel.
Documents reviewed for each section of this inspection report are listed in the
.
b. Findings
No findings were identified.
.2 Readiness for Seasonal Extreme Weather Conditions
a. Inspection Scope
During the week of February 3, the inspectors performed a review of PSEGs readiness for the onset of seasonal grassing. The review focused on the SW intake structure.
The inspectors reviewed the Updated Final Safety Analysis Report (UFSAR), 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 system to ensure station personnel identified issues that could challenge the operability of the systems during grassing conditions.
b. Findings
No findings were identified.
1R04 Equipment Alignment
Partial System Walkdowns (71111.04Q - 3 samples)
a. Inspection Scope
The inspectors performed partial walkdowns of the following systems:
Unit 2, auxiliary feedwater (AFW) during degraded conditions associated with 24 steam generator level control valve on January 26 Unit 2, steam dumps during megawatt recovery on February 9 Common, AFW backup supply water on February 24 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 Updated Final Safety Analysis Report (UFSAR), TSs, work orders, notifications, 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.
.2 Full System Walkdown
a. Inspection Scope
On March 18, the inspectors performed a complete system walkdown of accessible portions of the Unit 1 CFCU 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 system components and support equipment were aligned correctly and operable. The inspectors examined the material condition of the components and observed operating parameters of equipment to verify that there were no deficiencies. Additionally, the inspectors reviewed a sample of related condition reports and work orders to ensure PSEG appropriately evaluated and resolved any deficiencies.
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, 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 and discussed with station personnel the repair plans for degraded equipment.
Unit 1, Auxiliary building auxiliary area (Fire Zones 125 and 126) on January 16 Unit 1, Service water intake structure, (Fire Zones 147 and 149) on February 19 Unit 1, Diesel fuel oil storage tank area (Fire Zones 85 through 87) on February 25 Unit 1, Containment during forced outage (Fire Zones 103 and 104) on March 19 Unit 2, Battery rooms (Fire Zone 118) on January 12 Unit 2, 2B and 2C emergency diesel generator (EDG) rooms (Fire Zones 70, 89, and 90) on February 27
b. Findings
No findings were identified.
.2 Fire Protection - Drill Observation
a. Inspection Scope
The inspectors observed a fire brigade drill scenario conducted on January 28, that involved a fire in Unit 2, Fire Zone 145. 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 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.
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 January 27 and February 10, which included a requalification examination and a scenario covering the following major events: reactor coolant system leak and 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 classification 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 the emergent downpower for Unit 2 main condenser tube leakage on February 4. Additionally, 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 work orders, and maintenance rule (MR) basis documents to ensure that PSEG was identifying and properly evaluating performance problems within the scope of the MR. For each sample selected, the inspectors verified that the SSC was properly scoped into the MR in accordance with 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 corrective actions 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.
Common, 10 CFR 50.65(a)(3) evaluation on February 19
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.
Unit 1, Yellow risk for 11 component cooling water heat exchanger planned maintenance on January 20 Unit 1, Yellow risk for demineralized water storage tank isolation for non-safety-related AFW suction piping tie-in on March 2 Unit 1, 12 SGFP elevated vibration and adverse condition monitoring during planned load reduction on March 7 Unit 2, Emergent troubleshooting of erratic main generator automatic voltage regulator on January 5 Unit 2, Overpower event during 26 feedwater heater tuning on January 13 Unit 2, Yellow risk for 2A EDG planned maintenance on February 29
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:
Unit 1, Fuel moves with fluctuating building differential pressure on January 16 Unit 1, 13 CFCU operable but degraded evaluation on March 20 Unit 2, 25 SW traveling water screen following valve misposition on January 29 Unit 2, Auxiliary alarm system failure on February 2 Common, control room emergency air conditioning system during 1B vital instrument bus failure on February 2 Common, Quadrant power tilt ratio (QPTR) alarm setpoint control on February 19 Common, Baldor EDG performance testing on February 19 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 bounding limitations associated with the evaluations.
b. Findings
Introduction.
The inspectors identified a Green NCV of TS 3.9.12, Fuel Handling Area Ventilation System, when PSEG did not suspend Unit 1 fuel movement operations when the fuel handling area ventilation system was inoperable. Specifically, differential pressure exceeded its alarm setpoint and, at times, was positive during irradiated fuel movements.
Description.
During the week of January 12, 2015, PSEG was moving irradiated fuel assemblies in the Unit 1 Fuel Handling Building (FHB) in support of fuel sipping to identify fuel leaks. On January 15, PSEGs nuclear services department wrote notification 20675874 documenting that they continued to experience differential pressure (D/P) issues in the Salem 1 FHB, that three delays had occurred that day due to swings from approximately -0.1 to 0 inches water, and that fuel handling is conservatively halted until D/P settles and permission is granted by the control room supervisor. It finished stating due to the nature of the D/P instability, fuel handling is less than predictable. On the morning of January 16, inspectors went to the FHB during irradiated fuel movements and observed D/P gauge 1PD6531 fluctuate between
-0.1 and 0 water and also become positive for a brief period. After contacting the Operations shift manager and while still on the phone, both the inspectors and the shift manager observed FHB D/P fluctuate and become positive again. The shift manager immediately contacted the FHB supervisor and suspended irradiated fuel movements.
The inspectors then went to the control room and noted that the control room supervisor was monitoring FHB D/P gauge on a computer via a camera in the FHB since the FHB D/P alarm was in. The inspectors confirmed with operators that the FHB low D/P alarm had come in and out during the shift. Subsequent to this suspension, operators returned two irradiated fuel assemblies to their safe, original pool location. PSEG stopped further fuel movements until the low D/P alarm could be restored to service and other sources of the low FHB D/P were identified and corrected. PSEG captured this issue in their CAP as 20677427 and 20678063.
TS 3.9.12 covers fuel handling area ventilation system operability and requires that it be capable of maintaining slightly negative pressure in the FHB during movement of irradiated fuel within the FHB. Non-compliance requires that all operations involving movement of fuel within the storage pool be suspended until the fuel handling area ventilation system is restored to operable status.
Alarm response procedure S1.OP-AR.ZZ-0011, Control Console 1CC1, Revision 53, for the FHB low air D/P uses 1PD6531 with a setpoint of -0.160 water. Step 3.3 states that If FHB D/P cannot be maintained at a slight negative pressure with respect to atmospheric pressure (valid alarm), then the Fuel Handling Building Ventilation System is inoperable, refer to TS 3.9.12. Step 3.4 states if the FHB Ventilation System is inoperable then ensure that there is no movement of irradiated fuel within the Fuel Handling Building.
S1.OP-IO.ZZ-0010 (IOP-10), Spent Fuel Manipulations, Revision 23, step 3.17 states, in part, Operations involving movement of fuel within the storage pool are required to be suspended for any of the following: the Fuel Handling Area Ventilation System becomes inoperable. Step 3.7 states that the Fuel Handling Building is maintained at a slight negative pressure with respect to atmosphere pressure (T/S 4.9.12.a). The BLDG AIR D/P LO Alarm Bezel OR local indicator 1PD6531 may be used to continuously monitor xFHB D/P. Step 3.1 states that this procedure shall be in effect when Spent Fuel Pool Manipulations (movement of irradiate fuel) are initiated and shall remain in effect until all Spent Fuel Pool Manipulations are completed. Attachment 3 step 1.2(c) requires that BLDG AIR D/P LO alarm is clear OR the local indicator 1PD6531 is being used to continuously monitor FHB D/P. Given that the low D/P alarm came in and out during the shift, continuous monitoring of the D/P gauge was required. Inspector observations support that this continuous monitoring was not in effect. Since FHB D/P was not maintained at a slight negative pressure, the inspectors concluded that the fuel building area ventilation system was inoperable and that operations involving movement of fuel within the storage pool should have been suspended.
The inspectors determined that given the D/P observations during irradiated fuel movements, operator confirmation that the low D/P alarm had come in and out during the shift, the procedural requirements of both the alarm response and IOP-10 for D/P, and the inability of the control room supervisor to continuously monitor FHB D/P, that Unit 1 fuel handling area ventilation system was inoperable the predominant amount of the day and, therefore, the TS 3.9.12 requirement to immediately cease fuel movement was applicable but not followed.
Analysis.
Failure to adhere to TS 3.9.12 was a performance deficiency. The issue was determined to be more than minor since it affected the configuration control / barrier performance attribute of the Barrier Integrity cornerstone and adversely affected its objective to provide reasonable assurance that physical design barriers (fuel cladding, reactor coolant system, and containment) protect the public from radionuclide releases caused by accidents or events. Specifically, the radiological barrier functionality of the fuel handling building was degraded based on D/P challenges. The finding was screened using IMC 0609, Attachment 4 and Appendix A, Exhibit 3.C for Barrier Integrity screening questions involving the spent fuel pool building. Since the finding only represented a degradation of the radiological barrier function provided for the spent fuel pool, the finding screened to Green.
This finding had a cross-cutting aspect in Human Performance, Procedure Adherence, in that individuals follow processes, procedures, and instructions. Specifically, PSEG operators did not follow alarm response and general operating procedures, did not use human error reduction techniques with respect to receipt of multiple low FHB D/P alarms, and manipulated irradiated fuel when not appropriately authorized and directed by IOP-10. (H.8)
Enforcement.
TS 3.9.12 states, in part, that the fuel handling area ventilation system shall be [and] capable of maintaining slightly negative pressure in the Fuel Handling Building during movement of irradiated fuel within the Fuel Handling Building. With no Fuel Handling Area Ventilation System OPERABLE, suspend all operations involving movement of fuel within the storage pool until the Fuel Handling Area Ventilation System is restored to OPERABLE status. Contrary to this, on January 16, 2015, PSEG conducted fuel movements with the fuel handling area ventilation system not maintaining slightly negative pressure. Once aware of the issue, PSEG immediately suspended fuel movement and placed fuel assemblies in a safe condition. Because this issue was of very low safety significance and was entered in PSEGs CAP as notifications 20677427 and 20678063, this violation is being treated as an NCV in accordance with section 2.3.2 of the NRCs Enforcement Policy. (05000272/2015001-01, Failure to Ensure Adequate Negative Differential Pressure During Fuel Movements)
1R18 Plant Modifications
.1 Permanent Modifications
a. Inspection Scope
The inspectors evaluated a modification to install a non-safety related, diesel-driven AFW pump, implemented by design change packages 80106028, Unit 1 and 2 Spare Non Safety-Related Auxiliary Feedwater System, and 80109929, NSR Auxiliary Feedwater Pump for MSPI Recovery. 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 walked down portions of the system piping and components, and interviewed engineering personnel to understand the intended margin improvements in the station PRA model MSPI associated with the AFW system.
b. Findings
No findings were identified.
1R19 Post-Maintenance Testing
a. Inspection Scope
The inspectors reviewed the post maintenance tests (PMTs) 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.
Unit 1, 12 SGFP after shim removal and wire repairs on March 10 Unit 1, 14 CFCU following motor replacement on March 19 Unit 1, 12 auxiliary building ventilation exhaust backdraft damper failure to close on March 26 Unit 2, 25 CFCU low speed breaker after failure to close on January 15 Unit 2, Valve 22AF21 pressure override after indication discrepancy on February 6 Unit 2, Valve 25SW58 stroke timing following corrective maintenance on March 11 Common, DWST following substation #4 failure on February 23
b. Findings
Introduction.
Inspectors identified a Green NCV of 10 CFR 50, Appendix B, Criterion XVI, Corrective Action, when PSEG did not implement adequate corrective actions from a previous Green NCV in a timeframe commensurate with its safety significance.
Specifically, inadequate corrective actions resulted in HELB and MELB barriers being unsecured without implementing the associated station process.
Description.
In NRC Inspection Report 2013-005, inspectors documented a Green NCV of TS 6.8.1 when PSEG had not properly implemented HELB barrier controls in accordance with CC-AA-201, Plant Barrier Control, Revision 4, during maintenance activities that affected the performance of safety-related equipment. One of the examples involved maintenance on a valve inside a Unit 1 service water vault. During that activity, technicians had left a watertight door opened without a dedicated attendant.
When questioned, the technicians explained that since they were doing maintenance, they were exempt from requirements associated with barrier control. A review of the evaluation cited on a door placard revealed that the door had two design functions: to protect equipment outside the vault from a MELB of the service water piping inside the vault, and to protect equipment inside the vault from an outside HELB event.
During the first quarter of 2015, there were four examples of HELB/MELB doors being left open without implementing the associated station process. On February 2, during a walkdown of the same Unit 1 mechanical penetration area, inspectors identified a service water vault door fully open without an attendant or plant barrier impairment (PBI).
Two maintenance technicians inside the bay were actively engaged in valve mainte-nance. The inspectors observed this condition for over seven minutes before reporting it to Operations. The posting on the door, revised after the previous NCV, requires Operating Shift permission to ensure compliance with OP-SA-108-115-1001, Operability Assessment and Equipment Control Program, before the door can be maintained open.
In this case, permission had not been obtained. When the technicians were questioned on why they had left the door open, they replied that it was allowed to be open for maintenance activities. This was the same response that had been obtained in the previous NCV. PSEG closed and latched the door and entered this in their CAP as notification 20677643. On March 2, a PSEG fire protection operator identified the HELB door between the Unit 2 mechanical and electrical penetration areas was unlatched and ajar. PSEG closed and latched the door and entered this in their CAP as notification 20680283. On March 4, inspectors discovered a Unit 2 service water vault with its HELB/MELB door fully open. A PBI had originally been incorporated in the work but had since been removed. When inspectors questioned the sole technician working in the room, he was not aware of the barrier requirements. PSEG closed and latched the door and entered this in their CAP as notification 20680680. Finally, on March 26, inspectors felt air blowing out of an access panel on the 13 turbine-driven auxiliary feedwater HELB enclosure. When informed, an equipment operator identified that two latches were not in the closed position, repositioned them to secure the panel, and entered this in their CAP as notification 20683127.
The inspectors reviewed the CAP items associated with the 2013 NCV. Notification 20635656 revised OP-SA-108-115-1001, Exhibit 6, to align with NRC RIS 2001-09.
Specifically, the revision prohibited the blocking open of HELB/MELB barriers without implementing compensatory measures to provide equivalent protection or by removing the hazard. Notification 20633614 resulted in a crew clock reset and reviewed and confirmed that the service water HELB door signage and planning package were adequate. Notification 20635652 included two corrective actions: an extent of condition review for the previous three years and the same procedural revision discussed in notification 20635656 above. There were also two completed action items: a site-wide communication to ensure staff awareness of the HELB/MELB barrier issue and to examine the sites implementation of NRC RISs. While the site-wide communication discussed the turbine-driven auxiliary feedwater HELB example from the 2013 NCV, it did not discuss the service water vault example. Overall, the inspectors determined that PSEG had not implemented adequate corrective actions that would ensure adherence to the existing HELB barrier process as evidenced by continuance of staff behaviors and assumptions.
Through inspector review of CAP products associated with the previous NCV, the highest level of evaluation completed had been a work group evaluation, defined by PSEG as a low-level evaluation. LS-AA-120, Issue Identification and Screening Process, Attachment 3, says to consider performing at least an apparent cause evaluation for all externally identified significance level 3 or above issues, and consider a quick human performance investigation for conditions that involve an active Human Performance error. Attachment 2 identifies an NRC NCV as a significance level 3 issue. The inspectors noted that neither an apparent cause evaluation nor a quick human performance investigation had been completed.
Analysis.
Inadequate corrective actions in accordance with 10 CFR 50, Appendix B, Criterion XVI, was a performance deficiency. The issue was evaluated in accordance with IMC 0612, Appendix B, and determined to be more than minor since it was associated with the configuration control attribute of the Mitigating Systems cornerstone and adversely affected its objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences.
Specifically, improper barrier controls could potentially affect the operating equipment lineup in the case of a HELB. The issue was then evaluated using IMC 0609, Appendix A, where it screened to Green since it was not associated with a design or qualification deficiency, did not represent a loss of system or function, or represent an actual loss of function. Specifically, redundant trains were not impacted by the conditions.
The issue had a cross-cutting issue in Problem Identification and Resolution, Evaluation, in that organizations thoroughly evaluate issues to ensure that resolutions address causes and extent of conditions commensurate with their safety significance.
Specifically, PSEG did not thoroughly investigate and evaluate the previous NCV issues in order to understand the bases for staff decisions and the underlying organizational and safety culture contributors. [P.2]
Enforcement.
10 CFR 50, Appendix B, Criterion XVI, Corrective Action, states, in part, that measures shall be established to assure that conditions adverse to quality are promptly identified and corrected. Contrary to this, PSEG did not implement adequate corrective actions from a Green NCV in the fourth quarter of 2013 associated with HELB/MELB barrier control as evidenced by similar barriers being uncontrolled in the first quarter of 2015. PSEG immediate corrective actions were to secure the affected barriers and enter these examples in their CAP as notifications 20677643, 20683127, 20680283, and 20680680. Because the finding was of very low safety significance and was entered in PSEGs CAP, this violation is being treated as an NCV consistent with Section 2.3.2 of the NRCs Enforcement Policy. (NCV 05000272;311/2015/001-02, Inadequate Corrective Actions for HELB Barrier Controls)
1R20 Refueling and Other Outage Activities
a. Inspection Scope
On March 15, Salem Unit 1 was shutdown to comply with TS 3.6.2.3 regarding the allowed outage time for the 14 CFCU. During the outage that ended March 23, the inspectors observed portions of the shutdown process, repair activities, and immediate corrective actions and monitored controls associated with the following outage activities:
Configuration management, including maintenance of defense-in-depth, commensurate with the outage plan for the key safety functions and compliance with the applicable technical specifications when taking equipment out of service Status and configuration of electrical systems and switchyard activities to ensure that technical specifications were met Monitoring of decay heat removal operations Reactor water inventory controls, including flow paths, configurations, alternative means for inventory additions, and controls to prevent inventory loss Activities that could affect reactivity Maintenance of secondary containment as required by technical specifications Tracking of startup prerequisites, walkdown of the primary containment to verify that debris had not been left which could block the emergency core cooling system suction strainers, and startup and ascension to full power operation Identification and resolution of problems related to outage activities
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:
Unit 1, 13 AFW pump quarterly (IST) on January 30 Unit 2, Axial flux difference and overtemperature delta temperature on January 27 Unit 2, 2B EDG monthly on February 2 Unit 2, Quadrant power tilt ratio on February 5 Unit 2, 23 overtemperature delta temperature channel calibration on March 10 Unit 2, Reactor coolant system leakage (RCS) on March 30 Common, Dose equivalent iodine on March 30
b. Findings
No findings were identified.
Cornerstone: Emergency Preparedness
1EP4 Emergency Action Level and Emergency Plan Changes
a. Inspection Scope
PSEG implemented various changes to the Salem Emergency Action Levels (EALs),
Emergency Plan, and Implementing Procedures. PSEG had determined that, in accordance with 10 CFR 50.54(q)(3), any change made to the EALs, Emergency Plan, and its lower-tier implementing procedures, had not resulted in any reduction in effectiveness of the Plan, and that the revised Plan continued to meet the standards in 50.47(b) and the requirements of 10 CFR 50 Appendix E.
The inspectors performed an in-office review of all EAL and Emergency Plan changes submitted by PSEG as required by 10 CFR 50.54(q)(5), including the changes to lower-tier emergency plan implementing procedures, to evaluate for any potential reductions in effectiveness of the Emergency Plan. This review by the inspectors was not documented in an NRC Safety Evaluation Report and does not constitute formal NRC approval of the changes. Therefore, these changes remain subject to future NRC inspection in their entirety. The requirements in 10 CFR 50.54(q) were used as reference criteria.
b. Findings
No findings were identified.
1EP6 Drill Evaluation
Emergency Preparedness Training Observations
a. Inspection Scope
The inspectors observed a simulator training evolution for licensed operators on January 12 and February 10, which required emergency plan implementation by an operations crew. PSEG planned for this evolution to be evaluated and included in performance indicator data regarding drill and exercise performance. The inspectors observed event classification and notification activities performed by the crew. The inspectors also attended the post-evolution critique for the scenario. The focus of the inspectors activities was to note any weaknesses and deficiencies in the crews performance and ensure that PSEG evaluators noted the same issues and entered them into the corrective action program.
b. Findings
No findings were identified.
OTHER ACTIVITIES
4OA1 Performance Indicator Verification
.1 Safety System Functional Failures (2 samples)
a. Inspection Scope
The inspectors sampled PSEGs submittals for the Safety System Functional Failures performance indicator for both Unit 1 and Unit 2 for the period of January 1, 2014 through December 31, 2014. To determine the accuracy of the performance indicator data reported during those periods, inspectors used definitions and guidance contained in 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 operator narrative logs, operability assessments, MR records, maintenance work orders, condition reports, event reports and NRC integrated inspection reports to validate the accuracy of the submittals.
b. Findings
No findings were identified.
.2 RCS Specific Activity and RCS Leak Rate (4 samples)
a. Inspection Scope
The inspectors reviewed PSEGs submittal for the RCS specific activity and RCS leak rate performance indicators for both Unit 1 and Unit 2 for the period of January 1, 2014 through December 31, 2014. To determine the accuracy of the performance indicator 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 performance indicator. Additionally, the inspectors observed surveillance activities that determined the RCS identified leakage rate, and chemistry personnel taking and analyzing an RCS sample.
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 condition report screening meetings.
b. Findings
No findings were identified.
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 50.72. The inspectors reviewed PSEGs follow-up actions related to the events to assure that PSEG implemented appropriate corrective actions commensurate with their safety significance.
Unit 2, downpower to 60 percent power following main condenser tube leaks on February 4
b. Findings
No findings were identified.
.2 (Closed) Licensee Event Report (LER) 05000311/2014-002-00: Manual Reactor Trip
Due To A Partially Dropped Rod
a. Inspection Scope
On January 31, 2014, during the performance of monthly control rod surveillance, a power cable to control rod drive mechanism 1D2 experienced a short to ground while inserting control bank D fifteen steps. The short to ground caused a movable gripper fuse to open and 1D2 dropped from 220 to 166 steps. Operations entered TS 3.1.3.1.c for an inoperable control rod, which requires a power reduction to 75 percent within one hour, and compliance with TS 3.1.1.1 within one hour. Operations commenced a boration to reduce reactor power. During boration activities, the shutdown margin (SDM)was determined to be below the TS limit, thereby requiring a rapid boration. During rapid boration activities, operations subsequently determined that a manual trip was warranted, due to RCS average temperature approaching the minimum temperature for criticality. During the manual reactor trip, all the control rods fully inserted, therefore verifying control rod 1D2 was, in fact, trippable. PSEG determined that a 4-hour event report was required pursuant to 10 CFR 50.72(b)(2)(iv)(B) for an unplanned reactor protection system actuation. The inspectors reviewed the LER, the associated causal analysis and corrective actions, interviewed PSEG staff, and walked down associated components. This LER is closed.
b. Findings
Inspectors documented a Green NCV of TS 6.8.1 associated with this issue in NRC Inspection Report 05000272;311/2014-003. The inspectors did not identify any new performance deficiencies during the LER review.
4OA6 Management Meetings
Exit Meeting Summary
On April 16, 2015, the inspectors presented the inspection results to Mr. John Perry, Salem Site Vice President, and other members of the PSEG 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
- J. Perry, Site Vice President
- L. Wagner, Plant Manager, Salem
- C. Banner, Emergency Preparedness Manager
- P. Williams, Nuclear Simulator Training Instructor
- S. Thomassen, Emergency Preparedness Station Manager
- R. Cordrey, Operations Shift Manager
- Z. Crawford, Nuclear Shift Supervisor
LIST OF ITEMS
OPENED, CLOSED AND DISCUSSED
Open and
Closed
- 05000272/2015001-01 NCV Failure to Ensure Adequate Negative Differential Pressure During Fuel Movements (Section 1R15)
Closed
- 05000311/2014002-00 LER Manual Reactor Trip Due to a Partially Dropped Rod (Section 4OA3)