IR 05000272/2014005

IR 05000272-14-005, 05000311-14-005; 10/01/2014 - 12/31/2014; Salem, Units 1 and 2; Operability Determinations and Functionality Assessments, Refueling and Other Outage Activities, Radiological Hazard Assessment

ML15030A400
Person / Time
Site:	Salem
Issue date:	01/30/2015
From:	Glenn Dentel Reactor Projects Branch 3
To:	Joyce T Public Service Enterprise Group
Dentel G
References
IR 2014005
Download: ML15030A400 (68)

Text

UNITED STATES NUCLEAR REGULATORY COMMISSION

REGION I

2100 RENAISSANCE BLVD., SUITE 100 KING OF PRUSSIA, PA 19406-2713 January 30, 2015 Mr. Thomas 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 05000272/2014005 AND 05000311/2014005

Dear Mr. Joyce:

On December 31, 2014, 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 January 20, 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 four NRC-identified findings and one self-revealing finding of very low safety significance (Green). All 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 (CAP), the NRC is treating these findings as non-cited violations (NCVs), consistent with Section 2.3.2.a of the NRC Enforcement Policy. If you contest any NCV in this report, you should provide a response within 30 days of the date of this inspection report, with the basis for your denial, to the Nuclear Regulatory Commission, ATTN:

Document Control Desk, Washington, DC 20555-0001; with copies to the Regional Administrator, Region I; the Director, Office of Enforcement, United States Nuclear Regulatory Commission, Washington, DC 20555-0001; and the NRC Resident Inspector at 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 05000272/2014005 and 05000311/2014005 w/Attachment: Supplementary Information

REGION I==

Docket Nos. 50-272, 50-311 License Nos. DPR-70, DPR-75 Report Nos. 05000272/2014005 and 05000311/2014005 Licensee: PSEG Nuclear LLC (PSEG)

Facility: Salem Nuclear Generating Station, Units 1 and 2 Location: P.O. Box 236 Hancocks Bridge, NJ 08038 Dates: October 1, 2014 through December 31, 2014 Inspectors: P. Finney, Senior Resident Inspector A. Ziedonis, Resident Inspector R. Barkley, Senior Project Engineer E. Burket, Emergency Preparedness Inspector C. Cahill, Senior Reactor Analyst H. Gray, Senior Reactor Inspector A. DeFrancisco, Project Engineer M. Draxton, Project Engineer R. Nimitz, Senior Health Physicist T. OHara, Reactor Engineer D. Silk, Senior Operations Engineer Approved By: Glenn T. Dentel, Chief Reactor Projects Branch 3 Division of Reactor Projects Enclosure

SUMMARY

Inspection Report (IR) 05000272/2014005, 05000311/2014005; 10/01/2014 - 12/31/2014;

Salem Nuclear Generating Station Units 1 and 2; Operability Determinations and Functionality Assessments, Refueling and Other Outage Activities, Radiological Hazard Assessment and Exposure Controls, Problem Identification and Resolution, Follow-up of Events and Notices of Enforcement Discretion.

This report covered a three-month period of inspection by resident inspectors and announced inspections performed by regional inspectors. Inspectors identified four NRC-identified findings and one self-revealing finding 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: Initiating Events

SLIV. Inspectors identified a Severity Level IV (SLIV) NCV of 10 CFR 50.72(b)(2)(iv)(B)when PSEG failed to make the required event notification within four hours for a valid actuation of the reactor protection system (RPS) when the reactor was critical. Inspectors determined that a manual reactor trip on October 19, 2014, was not in accordance with PSEGs preplanned documented procedural sequence and, therefore, reportable. PSEG entered this in their CAP (20668967) and reported this RPS actuation by updating a previous report (EN 50550) on November 24, 2014.

Failing to submit an event notification in accordance with 10 CFR 50.72 within the required time was a performance deficiency that was reasonably within PSEGs ability to foresee and correct, and should have been prevented. Since the failure to submit a required event report impacts the regulatory process, traditional enforcement applied and the violation was assessed using Section 2.2.4 of the NRCs Enforcement Policy. Using the example listed in Section 6.9.d.9, A licensee fails to make a report required by 10 CFR 50.72, the issue was determined to be a Severity Level IV violation. The inspectors reviewed the condition for reactor oversight process significance and concluded there was no associated finding.

Because this violation involves the traditional enforcement process and does not have an underlying technical violation that would be considered more-than-minor, a cross-cutting aspect is not assigned to this violation in accordance with IMC 0612. (Section 4OA3)

Green.

The inspectors identified a Green NCV of TS 6.8.1, Procedures and Programs, when PSEG operators did not implement the procedure steps to trip the main turbine, and manually initiate auxiliary feedwater (AFW), during shutdown for a refueling outage on October 19, 2014. Consequently, operator response to degrading equipment conditions resulted in an unplanned manual reactor trip and coincident AFW actuation. PSEGs immediate corrective actions included conducting crew performance reviews documented as part of the post-trip review by the sites Plant Operations Review Committee (PORC), and subsequent coaching of operator performance.

The inspectors determined PSEGs failure to trip the main turbine and establish AFW flow on October 19, in accordance with (IAW) abnormal and shutdown procedures, constituted a performance deficiency. The finding was more than minor because it was associated with the Human Performance attribute of the Initiating Event cornerstone, and adversely affected its objective to limit the likelihood of events that upset plant stability and challenge critical safety functions during shutdown as well as power operations. Specifically, not following procedures in response to the 1B main power transformer (MPT) challenges resulted in an unplanned manual reactor trip and coincident Engineered Safety Features (ESF) AFW system actuation. In accordance with IMC 0609, Attachment 4, and Exhibit 1 of Appendix A, the inspectors determined that this finding is of very low safety significance, or Green, because the finding did not cause both a reactor trip and the loss of mitigation equipment relied upon to transition the plant from the onset of the trip to a stable shutdown condition.

The inspectors determined that this finding had a cross-cutting aspect in the area of Human Performance, Procedure Adherence, because PSEG operators did not follow procedures in response to degrading 1B MPT conditions during shutdown for a refueling outage on October 19. [H.8] (Section 1R20)

Cornerstone: Mitigating Systems

Green.

The inspectors identified a Green NCV of 10 CFR 50, Appendix B, Criterion XVI,

Corrective Action, because PSEG staff did not promptly correct a condition adverse to quality related to failed Unit 2 reactor coolant pump (RCP) turning vane bolts. Specifically,

PSEG staffs use as is evaluation in 2012 was not technically adequate to support their conclusion that contact between the pump turning vane and rotating impeller was acceptable in the event all turning vane bolts failed. As a result, PSEG did not complete corrective actions to perform a pump specific technical analysis or replace the bolts until this issue was identified in July 2014. PSEG completed corrective actions to replace all Unit 2 RCP turning vane bolts with an improved material and measured pump internal dimensions to determine that, for each pump, turning vane to impeller contact would not have prevented proper RCP coast down, invalidate their locked rotor analysis, or result in debris that could impact the reactor coolant system. PSEG staff entered this issue into their CAP (notifications 20660176, 20660177, 20660191, 20660175 and 20660173).

Failure to promptly correct a condition adverse to quality was a performance deficiency. The finding was evaluated in accordance with IMC 0612, Appendix B, and determined to be more than minor because it affected the equipment performance 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, the dropped turning vanes adversely affected the operating RCP lineup, and the supporting documentation errors brought into question their effect on the RCP locked rotor accident analysis and resulted in additional field work. The finding was then evaluated using IMC 0609, Attachment 4 and Appendix A, where it was screened to Green because it was a qualification deficiency of a mitigating component, the RCP as related to its coast down capability that ultimately retained its functionality. The finding was determined to have a cross-cutting aspect in the area of Problem Identification and Resolution, Evaluation, because PSEG, in addition to prior operating experience-related reports, had two opportunities in 2011 and 2012 when broken bolts were discovered, to thoroughly evaluate the technical basis for their conclusion that RCP turning vane dislodgement and contact with rotating pump components was acceptable. When PSEG thoroughly considered the problem in 2014, they determined that there was not adequate pump specific internal clearance information to support their prior technical conclusions that turning vane contact was acceptable. [P.2] (Section 4OA2)

Cornerstone: Barrier Integrity

Green.

A self-revealing, Green NCV of TS 6.8.1, Procedures and Programs, was identified when PSEG did not correctly implement procedures associated with Safeguard Equipment Control (SEC) surveillance testing during solid reactor coolant system (RCS) operations.

Consequently, this resulted in lifting a low temperature over-pressure protection valve during solid pressurizer operations. PSEG immediately stabilized reactor pressure, completed a prompt investigation and an apparent cause evaluation, submitted a Special Report to the NRC in accordance with TS 6.9.2, and entered this in their CAP (20665897).

Non-compliance with TS 6.8.1 procedures was a performance deficiency. This issue was determined to be more than minor because it was associated with the human 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. It was also similar to IMC 0612, Appendix E, example 4.b, in that not accomplishing activities in accordance with procedures is more than minor if it results in a trip or transient. Specifically, not following procedures resulted in an RCS pressure transient that caused a protective relief valve to lift. Since the finding was not associated with a freeze seal, nozzle dam, criticality drain-down path, leakage path, or safety injection actuation, and did not involve or result in PORV unavailability or a setpoint issue, it screened to

Green.

The finding had a cross-cutting aspect in the area of Human Performance, Procedure Adherence, in that individuals are expected to follow processes, procedures, and work instructions. Specifically, PSEG operators did not follow procedures nor review procedures before work to validate appropriateness and timing. [H.8] (Section 1R15)

Cornerstone: Occupational Radiation Safety

Green.

The inspectors identified NCV of very low safety significance (Green) associated with failure to implement TS 6.12.2 access controls for a High Radiation Area (HRA)exhibiting accessible radiation dose rates exceeding 1 rem/hr at 30 cm. Specifically, on October 28, 2014, NRC inspectors found the access door to the Unit 1 Containment Regenerative Heat Exchanger Room unlocked and unguarded, and the area exhibited accessible radiation dose rates of up to 1.4 rem/hr at 30 cm. PSEG immediately locked access to this area and entered this issue into its CAP (Notification 20667323).

The failure to establish and implement TS 6.12 HRA access controls is a performance deficiency (PD) which was within PSEGs ability to foresee and correct and should have been prevented. The PD was determined to be more than minor because, if left uncorrected, the PD had the potential to lead to a more significant safety concern if personnel were exposed to elevated radiation dose rates. Further, the PD was related to the programs and process attribute of the Occupational Radiation Safety cornerstone, and adversely affected the cornerstone objective to ensure adequate protection of worker from radiation exposure. The finding was assessed using IMC 0609, Appendix C, Occupational Radiation Safety Significance Determination Process, and was determined to be of very low safety significance (Green) because the finding did not involve: (1) As-Low-As-Reasonably

Achievable (ALARA) planning and controls; (2) a radiological overexposure; (3) a substantial potential for an overexposure; or (4) a compromised ability to assess dose. This finding was associated with the Resolution aspect of the Problem Identification and Resolution cross-cutting area in that PSEG did not take effective corrective actions to address issues in a timely manner commensurate with their safety significance. Specifically, PSEG did not repair a long standing broken High Radiation Area access door lock resulting in extended use of an alternate lock and chain remedy that could not be readily verified in the locked condition and led to human error in not successfully locking the door from prior egress. [P.3]

(2RS1)

REPORT DETAILS

Summary of Plant Status

Unit 1 began the inspection period at 100 percent power. On October 19, the unit was shut down for refueling and maintenance outage number 23 (1R23). Operators commenced a reactor startup on November 21 and the unit reached 100 percent power on November 26.

On the following day, the unit was reduced to approximately 61% in response to a leak on the control oil supply line to the 12 Steam Generator Feedpump (SGFP) low pressure steam supply stop valve. PSEG conducted repairs, restored the SGFP to service, and 100 percent power was reached on November 28. The unit remained at or near 100 percent power for the remainder of the inspection period.

Unit 2 began the inspection period at 100 percent power. On October 28, the unit was reduced to 55 percent power in support of maintenance on the 12 service water (SW) return header.

The unit was restored to 100 percent power on October 29. On November 7, the unit was reduced to 80 percent power in support of restoration from maintenance on the 12 SW return header. The unit reached 100 percent the following day and remained at or near that power level 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

During the week of October 12, inspectors performed a review of PSEGs readiness for the hurricane season. The review focused on the SW intake structure, the circulating water intake structure, and auxiliary building penetrations. The inspectors reviewed the Updated Final Safety Analysis Report (UFSAR), Technical Specifications (TSs), control room logs, and the corrective action program to determine what temperatures or other seasonal weather could challenge these systems, and to ensure PSEG personnel had adequately prepared for these challenges. The inspectors reviewed station procedures, including PSEGs seasonal weather preparation procedure and applicable operating procedures. The inspectors performed walkdowns of the selected systems to ensure station personnel identified issues that could challenge the operability of the systems during hurricane conditions. Documents reviewed for each section of this inspection report are listed in the Attachment.

b. Findings

No findings were identified.

.2 Readiness for Impending Adverse Weather Conditions

a. Inspection Scope

The inspectors reviewed PSEGs preparations for the onset of freezing temperatures and heavy rain on December 8. The inspectors reviewed the implementation of adverse weather preparation procedures before the onset of and during this adverse weather condition. The inspectors walked down the inner and outer steam penetrations and the SW intake structure. 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.

b. Findings

No findings were identified.

.3 External Flooding

a. Inspection Scope

During the week of September 17 and November 24, the inspectors performed an inspection of the external flood protection measures for the Salem Unit 2 electrical penetration area. The inspectors reviewed TSs, procedures, design documents, and the UFSAR, which depicted the design flood levels and protection areas containing safety-related equipment to identify areas that may be affected by external flooding. The inspectors conducted a general site walkdown of all external areas of the plant to ensure that PSEG erected flood protection measures in accordance with design specifications.

The inspectors also reviewed operating procedures for mitigating external flooding during severe weather to determine if PSEG planned or established adequate measures to protect against external flooding events.

b. Findings

No findings were identified.

1R04 Equipment Alignment

.1 Partial System Walkdowns

a. Inspection Scope

The inspectors performed partial walkdowns of the following systems:

Unit 1, containment lineup to support core reload on November 5 Unit 2, SW system following restoration from a valve mispositioning event on October 29 Common, control area ventilation in accident pressurized mode during a 1B vital instrument bus failure on October 29 The inspectors selected these systems based on their risk-significance relative to the Reactor Safety cornerstones at the time they were inspected. The inspectors reviewed applicable operating procedures, system diagrams, the UFSAR, TSs, work orders (WOs), 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 October 2 and December 18 respectively, the inspectors performed a walkdown of accessible portions of the Unit 1, 11 safety injection system, and the Unit 2, component cooling water system, to verify the existing equipment lineup was correct.

The inspectors reviewed operating procedures, 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, 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 notifications and WOs 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, containment (multiple fire zones) on October 27 Unit 1, 12 residual heat removal (fire zones 142 and 143) on November 2 Unit 1, spent fuel and component cooling heat exchanger and pump area (fire zone 77) on December 30 Unit 2, mechanical penetration area (fire zones 124 and 146) on December 5

b. Findings

No findings were identified.

.2 Fire Protection - Drill Observation

a. Inspection Scope

The inspectors observed a fire brigade drill scenario conducted on October 1 that involved a simulated fire in the Unit 2 A emergency diesel generator (EDG) room. 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.

1R07 Heat Sink Performance

.1 Annual Heat Sink Performance

a. Inspection Scope

The inspectors reviewed the Unit 1, 11 component cooling heat exchanger, on October 24, to determine its readiness and availability to perform its safety functions.

The inspectors reviewed the design basis for the component and verified PSEGs commitments to NRC Generic Letter 89-13. The inspectors discussed the results of the most recent inspection with engineering staff and reviewed the as-found and as-left conditions. The inspectors verified that PSEG initiated appropriate corrective actions for identified deficiencies. The inspectors also verified that the number of tubes plugged within the heat exchanger did not exceed the maximum amount allowed.

b. Findings

No findings were identified.

1R08 In-service Inspection Activities

a. Inspection Scope

From October 10 to 14 and from October 27 to 31, 2014, the inspectors conducted a review of PSEGs implementation of in-service inspection (ISI) program activities for Salem Unit 1. These activities monitor the reactor coolant system pressure boundary, risk significant piping and components and the containment to identify degradation, complete evaluations and make repairs or replacements as required. Sample selection was based on the inspection procedure objectives and risk priority of those pressure retaining components in systems where degradation could result in a significant increase in risk. The inspectors observed in-process non-destructive examinations (NDE),reviewed documentation records, and interviewed inspection personnel to verify that the NDE activities performed as part of Period 2 of the fourth 10 year Interval of the Salem Unit 1 In-Service Inspection Program during refueling outage 1R23 were conducted in accordance with the requirements of the ASME Boiler and Pressure Vessel Code Section XI, 2004 Edition, No Addenda.

02.01 Nondestructive Examination (NDE) and Welding Activities The inspectors performed direct observations of NDE activities in process and/or reviewed records of nondestructive examinations listed below. During observation and review of records for each activity, the inspectors determined whether the activities were completed and documented in accordance with the applicable ASME Code and PSEG procedures.

ASME Code Required Examinations The inspectors observed the equipment calibration verification, the performance of the magnetic particle (MT) examination and reviewed the completed inspection data sheet for the examination of the pressurizer lower head to support skirt weld (1-PZR-1VS). There were no recordable indications from this examination.

The inspectors observed the equipment calibration, and inspection scanning of the UT examination of the pressurizer nozzle weld (6-PRN-1103-IRS). The inspectors reviewed the inspection data sheet for the extent of the weld volume achieved (67.7%). There were no recordable indications from this examination.

The inspectors reviewed the equipment calibration sheets and the inspection data sheets from the UT examination of pipe to pipe weld 4-SJ-1194-8. There were no recordable indications from this examination.

The inspectors reviewed the inspection data sheets from the dye penetrant testing (PT) examination of pipe-to-pipe weld 4-SJ-1194-8. There were no recordable indications from this examination.

The inspectors reviewed the inspection calibration and the inspection data sheets from the UT examination of pipe-to-elbow weld 8-SJ-1162-12. There were no recordable indications from this examination.

The inspectors reviewed the equipment calibration sheets and the inspection data sheets from the ultrasonic (UT) examination of pipe-to-pipe weld 6-CV-2112-10.

There were no recordable indications from this examination; 100% coverage was not achieved due to the presence of a weld crown and outside diameter mismatch.

The inspectors reviewed the equipment calibration sheet and the inspection data sheets from the ultrasonic (UT) examination of the SG nozzle to pipe weld (RC-E-11A 2B-NZ). There were no recordable indications from this examination.

The inspectors reviewed the equipment calibration sheets and the inspection data sheets from the ultrasonic (UT) examination of elbow-to-pipe weld 8-CS-2123-3.

There were no recordable indications from this examination.

The inspectors reviewed the inspection data sheets from the dye penetrant testing (PT) examination of the coupling-to-pipe weld 1.5-SJ-1112-48. There were no recordable indications from this examination.

The inspectors reviewed a sample of five ASME IWE visual examination data sheets from the carbon steel containment liner. These examinations were also performed to satisfy Salem U1 license renewal commitment #28. The inspectors also observed the containment liner condition after removal of the stainless steel insulating sheets which cover the liner during normal power operations. PSEG removed minor corrosion and repaired any damaged/missing coating before reinstalling the stainless steel insulating sheets.

The inspectors reviewed the certifications of the NDE technicians performing the examinations and verified that the inspections were performed in accordance with approved procedures and that the results were reviewed and evaluated by certified Level III NDE personnel.

Other Augmented Examinations: License Renewal One-Time Inspections The inspectors observed the phased array ultrasonic equipment calibration (PAUT)completed by PSEG staff and their contractor personnel on a sample of two small bore socket welds in the Unit 1 Safety Injection System. The inspectors also reviewed the PAUT reports of the examinations of the two socket welds.

These inspections were performed to partially meet license renewal commitment

1. 23, to develop a method to inspect small bore socket welds to detect intergranular stress corrosion cracking (IGSCC) and socket weld cracking due to thermal fatigue.

One socket weld sample (weld 1.5-SJ-1112-48) showed no indications. The second sample inspection on socket weld 1.5-SJ-1112-50R showed a process indication in the socket weld. Additional supplemental PAUT examinations on this indication and a dye penetrant surface examination showed that the indication was contained within the socket weld metal, and was not surface breaking. Neither of the sample socket welds showed indications of IGSCC or thermal fatigue cracking. However, a Performance Demonstration Initiative (PDI) check of this technique was not conducted on site during 1R23.

PSEG staff decided that expansion of the socket weld inspection scope was not required. PSEG intends to remove the indication in weld 1.5-SJ-1112-50R during the next refueling outage (1R24) in the spring of 2016, and conduct a destructive examination of the indication. PSEG prepared a technical justification for continued operation, with the indication present in the weld until 1R24 in 2016 in accordance with PSEG procedures. This justification demonstrated the ability of the safety injection piping to withstand operation for the next 18 months under the present vibration environment.

Review of Recordable Relevant Indications Accepted by Evaluation The inspectors reviewed a relevant condition reported by PSEG via Notification 20667167. During an ASME IWF inspection of the Steam Generator #11 supports, PSEG discovered some missing parts (plates and clips) from the support. An extent of condition inspection was conducted on the other three U1 SG supports and identified similar conditions. PSEG reviewed applicable plant drawings of the supports and determined that the missing parts were not required. This same evaluation had been completed during Unit 2 refueling outage 2R17; however plant drawings and inspection procedures for Unit 1 had not been changed. PSEG issued work orders and authorizations to remove the non-required parts and change plant drawings to reflect these changes.

During IWL inspection of the external concrete containment, PSEG identified recordable indications on the outside of the Unit 1 containment. These indications occurred where concrete cracked and spalled, exposing the top layer of rebar to the weather. This condition is documented in Notification 20666556. PSEG conducted an extent of condition examination in the same containment area in Unit 2 and identified two additional areas in Unit 2 with the same condition. This condition is documented in Notification 20667567. PSESG performed a technical evaluation of these conditions and provided a corrosion calculation for the exposed rebar showing that delay of repair of these areas until 1R24 would not result in significant rebar corrosion damage. PSEG plans on repairing these areas in 1R24 the spring of 2016.

Repair/Replacement Activities The inspectors reviewed Replacement Plan 60107871, which replaced Nuclear Class 1, Seismic Class 1 valves 1SJ202 & 1SJ203 per Work Order 60107871. The inspectors reviewed Weld History Records 76526, 76527, 76525, 76524, and 76487, which detailed the weld filler materials and in-process NDE required to certify the completed welds. Also, the inspectors reviewed the completed dye penetrant results for each weld. The inspectors verified that this replacement met the requirements of the ASME Code, Subsection XI.

The inspectors reviewed Replacement Plan 60094446, which replaced Nuclear Class 2, Seismic Class 1 valves 12GB19 & S1GBD-12GB19 per Work Order 60094446. The inspectors reviewed Weld History Records 76364, and 76365, the weld filler materials, in process welding parameters, and in-process NDE required to certify the completed welds. Also, the inspectors reviewed the completed dye penetrant results for each weld. The inspectors verified that this replacement met the requirements of the ASME Code.

02.02 PWR Vessel Upper Head (VUHP) Inspection Activities PSEG installed a new Reactor Vessel Head on the Salem U1 reactor vessel in the fall of 2005. The new reactor head contained nozzles and partial penetration welds made from PWSCC-resistant materials. The last visual inspection (VE) of the new Reactor Vessel Head was conducted during outage

1R22 in the spring of 2013. Per ASME Code Case N-729-1, Table 1, the next

VE is due during 1R24 scheduled for the spring of 2016. Also, the next required volumetric examination of the nozzles, per ASME Code Case N-729-1, is planned to be done during 1R24, during the Spring of 2016. The inspectors determined that PSEG staff calculated the effective degradation years (EDY)and remaining inspection years (RIY) per Code Case N-729-1, Section 2400 to determine the inspection frequency conformed to Table 1 of the Code Case.

This schedule meets the inspection requirements of ASME Code Case N-279-1 for the Unit 1 Reactor Vessel Head.

02.03 Boric Acid Corrosion Control (BACC) Inspection Activities:

The inspectors reviewed the boric acid corrosion control program and controlling procedures, and discussed the program with the boric acid program owner. The inspectors reviewed the results of the boric acid walkdown inspection completed after the shutdown of the plant. This inspection was performed by knowledge-able plant engineers, and was guided by approved procedures. The walkdown resulted in the generation of 40 Notifications which documented conditions requiring engineering disposition, the completion of boric acid evaluation to determine potential risk to target components, or more extensive repairs. The inspectors also reviewed a sample of boric acid evaluations resulting from inspection records of boric acid leaks found on safety significant piping and components inside the Salem Unit 1 containment and auxiliary building. These inspections were controlled by inspection procedures and guidance provided by the boric acid program manager during the initial containment entry during the outage 1R22. The inspectors also reviewed a sample of leaks observed and reported, the identification and documentation of non-conforming conditions identified in the corrective action program and reviewed a sample of boric acid evaluations completed by engineering to repair or monitor the reported conditions. The inspectors also verified that the observed conditions were entered into the PSEG corrective action program, and reviewed a sample of engineering staff evaluations of the conditions reported to verify that the corrective actions were consistent with the requirements of PSEG procedures and 10 CFR 50, Appendix B, Criterion XVI.

02.04 Steam Generator (SG) Tube Inspection Activities During 1R23 PSEG did not conduct primary or secondary SG inspections based upon the prior outage inspection results and subsequent Operational Assessment and Condition Monitoring evaluations, which demonstrated that the SGs could operate successfully until the spring of 2016.

The inspectors reviewed the Steam Generator Degradation & Operational Assessment Validation (Order 80112835) for Salem Unit 1 Refueling Outage 22 (1R22) & Cycles 22/23, dated September 2014. The inspectors verified that the past SG inspection data and conditions support operation through the next fuel cycle in accordance with the requirements of the EPRI SG Inspection Guidelines, Revision 7.

02.05 Identification and Resolution of Problems The inspectors reviewed a sample of Salem Unit 1 Notifications (condition reports), which identified NDE indications, deficiencies and other nonconforming conditions since the previous 1R22 outage and during the 1R23 outage. The inspectors verified that nonconforming conditions were properly identified, characterized, evaluated, corrective actions identified, actions completed, dispositioned, and appropriately entered into the PSEG CAP.

b. Findings

No findings were identified.

1R11 Licensed Operator Requalification Program

.1 Quarterly Review of Licensed Operator Requalification Testing and Training (71111.11Q

- 1 sample)

a. Inspection Scope

The inspectors observed licensed operator simulator training on December 2 which included a scenario covering the following major events: loose contamination on a source and an unisolable steam leak. 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

(71111.11Q - 1 sample)

a. Inspection Scope

The inspectors observed and reviewed the operators response during Unit 1 mid-loop operations on November 11, during the refueling outage. The inspectors observed infrequently performed test or evolution briefings, pre-shift briefings, and reactivity control briefings to verify that the briefings met HU-AA-1211, Pre-job Briefings.

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.

.3 Annual Review

a. Inspection Scope

On December 17, 2014, one NRC region-based inspector conducted an in-office review of results of licensee-administered written examination and annual operating tests for 2014, for Salem Unit 1 and 2 operators. The inspection assessed whether failure rates were consistent with the guidance of IMC 0609, Appendix I, and Operator Requalification Human Performance SDP. The review verified that the failure rate (individual or crew) did not exceed 20%.

8 out of 62 operators failed at least one section of the Annual Exam. The overall individual failure rate was 12.9%.

1 out of 6 crews failed the simulator test. The crew failure rate was 16.7%.

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 (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.

Unit 1, 13 kilovolt (kV) D-E breaker on October 16 Unit 1, SW foreign material challenges on November 6 Unit 1, primary system pressure relief valve lift test failures on November 12

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 during reduced inventory in modes 5 and 4 on November 9 Unit 2, AMSAC bypassed and unavailable on October 10

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, low temperature overpressure protection relief valve lifted on October 21 Unit 1, 12 SW piping structural integrity on November 1 Common, seismic instrumentation degradation on October 3 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.

A self-revealing, Green NCV of TS 6.8.1, Procedures and Programs, was identified when PSEG did not properly implement procedures associated with Safeguard Equipment Control (SEC) surveillance testing during solid RCS operations.

Consequently, this resulted in lifting a low temperature over-pressure protection valve during solid pressurizer operations.

Description.

On October 19, 2014, PSEG shut down Salem Unit 1 for its 23rd refueling outage. On October 20, low temperature over-pressure protection was established via the pressurizer power-operated relief valves (PORVs) and PSEG operators commenced filling the pressurizer in accordance with S1.OP-IO.ZZ-0006, Hot Standby to Cold Shutdown, Revision 36. Unit 1 achieved solid conditions at approximately 11:00 a.m.

At 4:30 p.m., a senior reactor operator (SRO) acting as a testing supervisor conducted a pre-job brief for two nuclear equipment operators (NEOs) on the restoration from procedure S1.OP-ST.SSP-0004, SEC Mode Ops Testing 1C Vital Bus, Revision 28, via its Attachment 3, Component Alignment and Restoration. At the same time, they also briefed on the component alignment for S1.OP-ST.SSP-0003, SEC Mode Ops Testing 1B Vital Bus, Revision 28, via its Attachment 2, Component Alignment and Restoration. The SRO did not inform the Control Room Supervisor (CRS) of pending actions by the NEOs and did not provide the NEOs with the prerequisite sections of the procedures. At 5:17 p.m., the NEOs closed the in-service 11 charging pumps discharge valve reducing charging flow to zero from a value of 124 gpm. A minute later, the reactor operator monitoring RCS parameters observed the loss of flow and corresponding drop in reactor pressure. He removed letdown flow and stabilized reactor pressure at 217. The 12 and 13 reactor coolant pump seal differential pressures lowered to approximately 157 psid. After control room staff determined the cause was closure of the 11 charging pump discharge valve, and following a brief discussion, the CRS directed the NEOs to slowly open the discharge valve as reactor operators attempted to restore letdown flow. Charging flow rapidly increased to greater than 200 gpm and a pressurizer PORV lifted for four cycles. At 5:22 p.m., charging and letdown flow were restored to pre-event values and reactor pressure was stabilized at 324 psig.

PSEG completed a technical evaluation (70170378) that determined that the peak RCS pressure reached was 365.1 psig as compared to the TS limiting value of 375 psig.

Other actions by PSEG included entering this in their CAP (20665897), completing a prompt investigation, delimiting four operators, resetting the Operations department clock, conducting department supervisory stand-downs on day and night shifts, and submitting Special Report 05000272/2014-07-00 to the NRC in accordance with TS 6.9.2.

The inspectors determined there were multiple examples of failure to follow station procedures. Specifically:

Surveillance procedure S1.OP-ST.SSP-0003 prerequisite step 2.9 states to ENSURE the following systems and equipment are in service: 2.9.4 IF charging and letdown is in service, ensure that 11 charging pump is NOT required to support plant operation. Contrary to this, charging and letdown were in service, the 11 charging pump was required since it was the only charging pump in service, and the NEOs did not ensure this step was met.

S1.OP-ST.SSP-0003 prerequisite step 1.2 requires a clearance applied to either the 11 charging pump breaker in the racked down position or its control power in the off position. This step was required to be implemented before locking closed the 11 charging pump discharge valve, 1CV48, in Attachment 2. Contrary to this, NEOs repositioned 1CV48 without verifying the prerequisite had been met.

S1.OP-ST.SSP-0003 prerequisite step 2.7 states to ENSURE NO maintenance or testing that could interfere with performance of this procedure is in progress on the following systems: Solid State Protection System (SSPS). S1.OP-ST.SSP-0004 is a test of the SSPS and restoration from this procedure was still in progress.

Additionally, the restoration and lineup of the individual tests were independent events in the PSEG work schedule whose durations did not overlap.

S1.OP-IO.ZZ-0006 step 5.1.50 requires that When the pressurizer is water solid (steam bubble collapsed), slowly adjust charging or letdown flowrate to stabilize RCP seal differential pressure 200 psid AND RCS pressure 340 psig. Contrary to this, operators did not appropriately control RCS pressure to meet these requirements.

OP-AA-101-111, Roles and Responsibilities of On-Shift Personnel, Revision 5, step 4.2.7 states that the CRS will authorize testing, surveillances, outages, and maintenance on all equipment and systems. Contrary to this, the testing supervisor authorized the surveillance vice the CRS.

On October 13, prior to the outage, PSEG had held a station stand-down to reinforce three focus areas that included procedure use and adherence. In response to this event, on October 21, PSEG held another stand-down regarding procedure use and adherence. While this event included aspects in many cross-cutting areas, the inspectors determined that procedure use and adherence was a common element to the examples listed above and is supported by PSEGs station-wide response following the event.

Analysis.

Non-compliance with TS 6.8.1 procedures was a performance deficiency.

This issue was determined to be more than minor because it was associated with the human performance attribute of the Barrier Integrity cornerstone, and adversely affected its objective to provide reasonable assurance that physical design barriers (RCS) protect the public from radionuclide releases caused by accidents or events. It was also similar to IMC 0612, Appendix E, example 4.b, in that not accomplishing activities in accordance with procedures is more than minor if it results in a trip or transient.

Specifically, not following procedures resulted in an RCS pressure transient that caused a protective relief valve to lift. The issue was evaluated using IMC 0609, Attachment 4, and determined to be associated with the Barrier Integrity cornerstone based on the PORV acting as an RCS boundary mitigator. Since the finding was associated with a shutdown event, IMC 0609, Appendix G, Attachment 1, Exhibit 4.A, was used to determine significance. Since the finding was not associated with a freeze seal, nozzle dam, criticality drain-down path, leakage path, or safety injection actuation, and did not involve or result in PORV unavailability or a setpoint issue, it screened to Green.

The finding had a cross-cutting aspect in the area of Human Performance, Procedure Adherence, in that individuals are expected to follow processes, procedures, and work instructions. Specifically, PSEG operators did not follow procedures nor review procedures before work to validate appropriateness and timing. (H.8)

Enforcement.

TS 6.8.1 states, in part, that written procedures shall be established, implemented, and maintained covering the activities referenced in the applicable procedures recommended in Appendix A of Regulatory Guide 1.33, Revision 2, February 1978. Regulatory Guide 1.33, Appendix A, section 2.j, covers Hot Standby to Cold Shutdown general operating procedures and section 3.a covers procedures for filling, draining, and changing RCS modes of operation. S1.OP-ST.SSP-0003 contained prerequisites to be met. S1.OP-IO.ZZ-0006, step 5.1.50 requires RCP seal pressure and RCS pressure to be maintained 200 psid and 340 psig respectively. Contrary to this, on October 20, 2014, PSEG did not properly implement these procedures.

Consequently, the low temperature overpressure setpoint was exceeded during a pressure transient. PSEG immediately stabilized reactor pressure. Because this finding was of very low safety significance, was not repetitive or willful, and was entered in PSEGs CAP (20665897), this violation is being treated as an NCV consistent with Section 2.3.2 of the NRCs Enforcement Policy. (05000272/2014-005-01, Procedural Non-Compliance Resulted in Low Temperature Overpressure Relief Lifting)

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, 1A 125 VDC battery replacement on October 24 Unit 1, control air header 1B containment building check valve, 12CA360, following seat and disc repairs on October 24 Unit 1, main feedwater stop check valve, 11BF22, following seat repairs on November 12 Unit 1, 11 auxiliary feedwater (AFW) inlet stop check, 11AF23, following corrective maintenance on November 12 Unit 1, boric acid recirculation control valve, 11CV160, following corrective maintenance on November 13 Unit 2, AFW pump turbine start/stop valve, 2MS132, following packing adjustment on October 2

b. Findings

No findings were identified.

1R20 Refueling and Other Outage Activities

a. Inspection Scope

The inspectors reviewed the stations work schedule and outage risk plan for the Unit 1 maintenance and refueling outage (1R23), which was conducted October 19 through November 23. The inspectors reviewed PSEGs development and implementation of outage plans and schedules to verify that risk, industry experience, previous site-specific problems, and defense-in-depth were considered. During the outage, the inspectors observed portions of the shutdown and cooldown processes 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 TSs when taking equipment out of service Implementation of clearance activities and confirmation that tags were properly hung and that equipment was appropriately configured to safely support the associated work or testing Installation and configuration of reactor coolant pressure, level, and temperature instruments to provide accurate indication and instrument error accounting Status and configuration of electrical systems and switchyard activities to ensure that TSs were met Monitoring of decay heat removal operations Impact of outage work on the ability of the operators to operate the spent fuel pool cooling system 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 TSs Refueling activities, including fuel handling and fuel receipt inspections Fatigue management 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 refueling outage activities

b. Findings

Introduction.

The inspectors identified a Green NCV of TS 6.8.1, Procedures and Programs, when PSEG operators did not implement the procedure steps to trip the main turbine, and manually initiate auxiliary feedwater (AFW), during a shutdown for a refueling outage. Consequently, operator response to degrading equipment conditions resulted in an unplanned manual reactor trip and coincident AFW actuation.

Description.

On October 19, 2014, inspectors observed the shutdown of Salem Unit 1 for its 23rd refueling outage. Operators were reducing load at a rate of approximately 20 percent per hour, in accordance with (IAW) S1.OP-IO.ZZ-0004, Power Operation (IOP-4). At 6:10 p.m., at approximately 83% thermal power, operators received a main power transformer (MPT) trouble alarm. Equipment operators responded, and reported that the low oil level alarm was locked in locally at the 1B MPT. PSEG had been monitoring an oil leak on the 1B MPT since October 2013, IAW an approved adverse condition monitoring plan (ACM). PSEG had been adding oil at a rate of approximately 175 gallons per week during the five weeks prior to the shutdown. With a low oil level alarm locked in on the 1B MPT, the ACM specified action to reduce power at 1 percent per minute to 40 percent power, trip the main turbine IAW S1.OP-AB.LOAD-0001, Rapid Load Reduction (AB-LOAD) and S1.OP-AB.TRB-0001, Turbine Trip Below P-9, and stabilize power at 10 to 15 percent rated thermal power.

Following receipt of the alarm, operators continued to reduce power at 20 percent per hour. At 8:27 p.m. and approximately 55 percent thermal power, operators exited IOP-4, entered AB-LOAD, Revision 14, and increased the power reduction to 1 percent per minute. At 8:44 p.m., the overhead alarm (OHA) re-flashed again. Equipment operators responded and reported that the 1B MPT gas detector gauge was in alarm. At 8:48 p.m. and approximately 23% thermal power, an OHA alarm came in for generator exciter voltage regulator trouble, and subsequently self-cleared. At 8:50 p.m., the control room supervisor conducted a crew brief that discussed the plan to manually trip the reactor based on the additional alarms associated with the 1B MPT. At 8:51 p.m. and approximately 19.5 percent thermal power, operators manually tripped the reactor. In reaction to the trip, the 12, 13 and 14 steam generator narrow range levels lowered to less than 14 percent, resulting in an engineered safety feature (ESF) AFW system actuation. AFW automatically responded as designed and restored steam generator water levels. PSEG subsequently reported the unplanned ESF actuation as an 8-hour event notification IAW 10 CFR 50.72(b)(3)(iv)(A).

Following the trip, the inspectors reviewed PSEGs completed procedures, the ACM, main control room narrative logs, inspector notes from the shutdown activities, and written operator statements. The inspectors identified multiple procedure non-compliances during the shutdown evolution and reactor trip, including:

Failure to implement a required contingency action of the ACM, IAW OP-AA-108-111, Adverse Contingency Monitoring and Contingency Planning, Revision 7, steps 3.2.4 and step 4.3.

Operators did not enter AB-LOAD, as directed by the ACM, until over two hours after receipt of the locked in low oil level alarm.

Operators did not trip the turbine at 40 percent power IAW the ACM. Instead, operators continued the load reduction to approximately 20 percent power, at 1 percent per minute.

Failure to trip the main turbine IAW AB-LOAD.

AB-LOAD continuous action summary (CAS) step 3.0 states that if at any time main turbine trip is required below P-9 (reactor trip setpoint above 49 percent power), and the steam dump system is available, then: place rods in manual, trip the main turbine, and go to S1.OP-AB.TRB-0001.

Failure to implement S1.OP-IO.ZZ-0005, Minimum Load to Hot Standby, Revision 21 (IOP-5).

Operators tripped the reactor without using steps or action specified by procedure.

S1.OP-AB.TRB-0001, Revision 13, step 3.24 stated, if turbine trip occurred at less than 20 percent reactor power, then initiate IOP-5. PSEG concluded, during operator performance reviews, that the actions in IOP-5 were referenced to trip the reactor, but the procedure was never formally entered and the actions were not completed IAW the requirements of a Level 1 procedure.

IOP-5, step 5.1.9.A stated, if a manual reactor trip is planned between 10 percent and 20 percent rated thermal power, then establish auxiliary feedwater flow to 11 -

14 steam generators IAW S1.OP-SO.AF-0001, Auxiliary Feedwater System Operation. Additionally, there is a note in step 5.1.9.A that states Establishing at least 10E4 lbm/hr flow to each steam generator prior to opening the reactor trip breakers significantly reduces the likelihood of an automatic start signal to the AFW pumps (ESF actuation).

The inspectors questioned PSEG regarding operators use of procedures during the event and provided the observed deficiencies. PSEG subsequently agreed with their observations and conclusions regarding procedure use and adherence deficiencies and captured them in the CAP under notification 20668967. PSEG immediate corrective actions included crew performance reviews during a post-trip review, coaching on operators performance, and operating crew table-top training prior to reactor start-up, which focused on the procedural transitions associated with several potential equipment failures and events.

Analysis.

The inspectors determined PSEGs failure to trip the main turbine and establish AFW flow on October 19, IAW abnormal and shutdown procedures, constituted a performance deficiency. The finding was more than minor because it was associated with the Human Performance attribute of the Initiating Event cornerstone, and adversely affected its objective to limit the likelihood of events that upset plant stability and challenge critical safety functions during shutdown as well as power operations.

Specifically, not following procedures in response to the 1B MPT challenges resulted in an unplanned manual reactor trip and coincident ESF AFW system actuation. IAW IMC 0609, Attachment 4, and Exhibit 1 of Appendix A, the inspectors determined that this finding was of very low safety significance, or Green, because the finding did not cause both a reactor trip and the loss of mitigation equipment relied upon to transition the plant from the onset of the trip to a stable shutdown condition.

The inspectors determined that this finding had a cross-cutting aspect in the area of Human Performance, Procedure Adherence, because PSEG operators did not follow procedures in response to degrading 1B MPT conditions during shutdown for a refueling outage on October 19. (H.8)

Enforcement.

TS 6.8.1, Procedures and Programs, states, in part, that written procedures shall be established, implemented and maintained covering the applicable procedures recommended in Appendix A of Regulatory Guide (RG) 1.33, Revision 2, February 1978. Contrary to TS 6.8.1, PSEG did not implement applicable RG 1.33 procedures, as evidenced by the following two examples:

RG 1.33, section 5, includes Procedures for Abnormal, Offnormal, or Alarm Conditions. PSEG Abnormal procedure S1.OP-AB.LOAD-0001, Rapid Load Reduction, continuous action step (CAS) 3.0, requires if at any time main turbine trip is required below P-9, and steam dump system is available, then place rods in manual, trip the main turbine, and go to S1.OP-AB.TRB-0001. Contrary to the above, during performance of S1.OP-AB.LOAD-0001 on October 19, PSEG operators did not implement CAS 3.0 when a main turbine trip was required below P-9 with the steam dump system available.

RG 1.33, section 2, General Plant Operating Procedures, subsection i, includes Plant Shutdown to Hot Standby. PSEG general operating procedure S1.OP-IO.ZZ-0005, Minimum Load to Hot Standby, step 5.1.9.A, requires, in part: Establish Auxiliary Feedwater flow to 11 - 14 Steam Generators IAW S1.OP-SO.AF-0001, Auxiliary Feedwater System Operation. Contrary to the above, during minimum load conditions on October 19, PSEG operators did not implement S1.OP-IO.ZZ-0005, and did not establish AFW flow to 11 - 14 Steam Generators.

Consequently, operator response to degrading 1B MPT conditions resulted in an unplanned manual reactor trip and coincident ESF AFW actuation. PSEG immediate corrective actions included crew performance reviews during a post-trip review and coaching on operators performance. Because this finding is of very low safety significance (Green) and was entered into PSEGs CAP (notification 20668967),this violation is being treated as an NCV consistent with Section 2.3.2 of the NRCs Enforcement Policy. (NCV 05000272/2014005-02, Failure to Implement Procedures during Shutdown Results in ESF Actuation)

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, containment pressure/vacuum relief isolation valves, 1VC5(6), (PCIV) on October 24 Unit 1, reactor coolant pump component cooling inlet isolation valves, 1CC118(119),

(PCIV) on October 30 Unit 2, core reactivity balance on October 14 Unit 2, charging pump full flow testing on November 11

b. Findings

No findings were identified.

1EP6 Drill Evaluation

.1 Emergency Preparedness Drill Observation

a. Inspection Scope

The inspectors evaluated the conduct of a routine PSEG emergency drill on December 11 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 and technical support center 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

2RS1 Radiological Hazard Assessment and Exposure Controls

a. Inspection Scope

This area was inspected during the period September 29 through October 2, 2014, and December 1-3, 2014. The inspectors reviewed PSEGs performance in assessing and controlling radiological hazards in the workplace. The inspectors used the requirements contained in 10 CFR Part 20, TSs, applicable Regulatory Guides, and PSEG procedures as criteria for determining compliance.

Inspection Planning

The inspectors reviewed 2013 and 2014 performance indicators for the occupational exposure cornerstone, radiation protection (RP) program audits, and reports of operational occurrences in occupational radiation safety since the last inspection.

Radiological Hazard Assessment The inspectors reviewed the following:

changes in radiological hazards for onsite workers or members of the public and potential impact of the changes; and, monitoring of loose surface contamination in areas of the plant Instructions to Workers The inspectors reviewed the following:

radiation work permits (RWP) and As Low As Reasonably Achievable (ALARA)plans; and, communications to workers of radiological hazards Contamination and Radioactive Material Control The inspectors reviewed the following:

locations where material was monitored and released from the radiological control area; performance of personnel surveying and releasing material for unrestricted use; and, radiation monitoring instrumentation used for equipment and personnel release for adequate sensitivity and for alarm response Radiological Hazards Control and Work Coverage The inspectors reviewed the following:

radiological controls, including: surveys, radiation protection job coverage, contamination controls, and use of electronic personal dosimeters (EPDs); and airborne radioactivity monitoring and controls Risk-Significant High Radiation Area (HRA) and Very High Radiation Area (VHRA)

Controls The inspectors discussed with RP supervisors and staff the controls and procedures for high-risk HRAs and VHRAs including reactor cavity work.

Problem Identification and Resolution The inspectors evaluated whether problems associated with radiation monitoring and exposure control were being identified at an appropriate threshold and were properly addressed for resolution in the PSEG CAP.

b. Findings

Introduction.

The inspectors identified a Green NCV in that PSEG did not implement TS 6.12.2 required locked HRA (LHRA) access controls for an area exhibiting accessible radiation dose rates in excess of 1 rem/hr at 30 cm from the radiation source.

Specifically, on October 28, 2014, NRC inspectors found the access door to the Unit 1 Containment elevation 78 ft Regenerative Heat Exchanger Room unlocked and unguarded, and personnel access was uncontrolled with the area exhibiting accessible radiation dose rates up to 1.4 rem/hr at 30 cm from the radiation source.

Description.

During tours of the Unit 1 Reactor Containment on October 28, 2014, at about 10:30 a.m., the inspectors identified that the door lock to the Unit 1 Containment Regenerative Heat Exchanger room, a LHRA, was broken and that PSEG had provided a separate lock and chain to prevent unauthorized access to the area. The area was required by TS 6.12.2 to be locked or guarded to prevent unauthorized access since radiation dose rates at 30 cm from the radiation source exceeded 1 rem/hr. The inspectors examined the chain and determined it to be unlocked and not secured to prevent unauthorized access to the area. The area had been entered at about 9:10 a.m. that day. The area was determined to exhibit accessible radiation dose rates of 1.4 rem/hr at 30 cm from the source, based on radiation survey 1207819. Further, no other access control methods (e.g., a door guard) were in place to provide access controls and prevent unauthorized access. The inspectors determined the door lock had been broken for an extended period of time (an estimated seven years) and that the chain and lock were being used in lieu of repairing the door lock. PSEG immediately locked access to this area and entered this issue into its CAP (Notification 20667323).

PSEG also conducted a Prompt Investigation as well as a Human Performance Evaluation.

Analysis.

PSEG did not establish and implement adequate locking or guarding of the Unit 1 Containment Regenerative Heat Exchanger Room, a LHRA, as required by TS 6.12.2. This is a performance deficiency (PD) that was within PSEGs ability to foresee and correct and should have been prevented. The PD was determined to be more than minor because, if left uncorrected, the PD had the potential to lead to a more significant safety concern if personnel made unauthorized access and were exposed to elevated radiation dose rates. Further, the PD was related to the programs and process attribute of the Occupational Radiation Safety cornerstone, and adversely affected the cornerstone objective to ensure adequate protection of workers from radiation exposure.

The finding was not subject to traditional enforcement because it was not willful, was not associated with a violation that impacted the regulatory process and did not contribute to actual safety consequences. The finding was assessed using IMC 0609, Appendix C, Occupational Radiation Safety Significance Determination Process, and was determined to be of very low safety significance (Green) because: it was not related to ALARA; did not result in an overexposure or a substantial potential for overexposure; and did not compromise PSEGs ability to assess dose.

This finding was associated with the Resolution aspect of the Problem Identification and Resolution cross-cutting area in that PSEG did not take effective corrective actions to address issues in a timely manner commensurate with their safety significance.

Specifically, PSEG did not repair a long-standing broken LHRA access door lock, resulting in extended use (multiple years) of an alternate chain and lock remedy that could not be readily verified in the locked condition and led to human error in not successfully locking the door from prior egress. [P.3]

Enforcement.

T.S. 6.12, High Radiation Areas, requires that each entryway to such areas shall be provided with a locked or continuously guarded door or gate that prevents unauthorized entry, and, in addition, doors and gates shall remain locked except during periods of personnel or equipment entry or exit. Contrary to this requirement, on October 28, 2014, PSEG did not provide a locked or continuously guarded door for the Unit 1 Containment Regenerative Heat Exchanger room, an area with dose rates greater than 1.0 rem/hour at 30 centimeters from the radiation source. Specifically, on that date, an NRC inspector identified the access door to the room to be unlocked and unguarded and dose rates within the room were determined to be up to 1.4 rem/hr at 30 centimeters from the radiation source. Upon identification of the issue, PSEG immediately locked the affected area and initiated additional radiation surveys and controls. PSEG also conducted a Prompt Investigation as well as a Human Performance Evaluation. The violation did not have any actual or any substantial potential for exceeding the occupational exposure limits since no unauthorized entries were identified and no abnormal personnel radiation doses were noted. Because this finding is of very low safety significance (Green) and was entered into PSEGs CAP (Notification 20667323),this violation is being treated as an NCV, consistent with Section 2.3.2 of the Enforcement Policy. (NCV 05000272/2014005-03; Failure to Implement TS Locked High Radiation Area Controls)

2RS2 Occupational ALARA Planning and Controls

a. Inspection Scope

During the period September 29 through October 2, 2014, the inspectors assessed performance with respect to maintaining occupational individual and collective radiation exposures as low as is reasonably achievable (ALARA). The inspectors used the requirements contained in 10 CFR 20, applicable Regulatory Guides, TSs, and PSEG procedures as criteria for determining compliance.

Inspection Planning

The inspectors reviewed the following:

collective dose history, current exposure trends, ongoing and planned work activities, and the plants three year rolling average collective exposure; compared the site-specific trends in collective exposures against the industry average values and those values from similar vintage reactors; and, changes in the radioactive source term, and site-specific procedures associated with maintaining occupational exposures ALARA.

Radiological Work Planning The inspectors reviewed the following:

work activities and ALARA work activity evaluations, exposure estimates, and exposure reduction requirements; use of dose reduction techniques and estimated dose goals; worker efficiency from use of respiratory protective devices, the use of remote technologies, and operating experience to reduce dose; and, integration of ALARA requirements into work procedure and RWP documents (e.g.,

reactor disassembly, transfer canal work, insulation work, reactor coolant pump seal/motor change out)results achieved (aggregate total dose) for various planned work as compared to initial planned dose estimates post-job radiological work activity reviews.

Verification of Dose Estimates and Exposure Tracking Systems The inspectors reviewed the following:

current annual collective dose estimate and applicable procedures to determine the methodology for estimating dose; measures to track, trend, and reduce occupational doses for ongoing work activities; and comparison of actual dose for various planned work as compared to initial dose estimates Source Term Reduction and Control The inspectors reviewed the following:

source term reduction, historical trends and current status of plant source term; PSEG contingency plans for changes in the source term as the result of changes in plant fuel performance or changes in plant primary chemistry; and, current 10 CFR 61 waste stream source term data Problem Identification and Resolution The inspectors evaluated whether problems associated with ALARA planning and controls were being identified at an appropriate threshold and were properly addressed for resolution in the PSEG corrective action program.

b. Findings

No findings were identified.

2RS3 In-Plant Airborne Radioactivity Control and Mitigation

a. Inspection Scope

During the period of September 29 through October 2, 2014, the inspectors reviewed controls for potential airborne radioactivity work and the use of respiratory protection devices. The inspectors used the requirements contained in 10 CFR Part 20, the guidance in applicable Regulatory Guides, TSs and PSEG procedures as criteria for determining compliance.

Inspection Planning

The inspectors reviewed performance indicators to identify any related to unintended dose resulting from intakes of radioactive material.

Problem Identification and Resolution The inspectors evaluated whether problems associated with in-plant airborne radioactivity controls were being identified at an appropriate threshold and were properly addressed for resolution in the PSEG corrective action program.

b. Findings

No findings were identified.

2RS4 Occupational Dose Assessment

a. Inspection Scope

During the period of September 29 through October 2, 2014, and December 1 - 3, 2014, the inspectors reviewed the monitoring, assessment, and reporting of occupational dose.

The inspectors used the requirements in 10 CFR 20, applicable Regulatory Guides, TSs, and procedures as criteria for determining compliance.

Inspection Planning

The inspectors reviewed: radiation protection program audits; post-outage reports; and corrective action program documents.

Routine Bioassay (In-Vivo)

The inspectors reviewed procedures to assess dose from internally deposited radionuclides and portal radiation monitors used as a passive internal dose monitoring system.

Internal Dose Assessment - Airborne Monitoring The inspectors reviewed internal dose assessment based on airborne monitoring and calculations of internal dose and associated documentation.

Problem Identification and Resolution The inspectors evaluated whether problems associated with occupational dose assessment were being identified at an appropriate threshold and were properly addressed for resolution in the PSEG CAP.

b. Findings

No findings were identified.

2RS5 Radiation Monitoring Instrumentation

a. Inspection Scope

During the period of September 29 - October 2, 2014, and December 1 - 3, 2014, the inspectors reviewed the accuracy and operability of radiation monitoring instruments that were used to protect occupational workers. The inspectors used the requirements in 10 CFR Part 20, applicable Regulatory Guides and industry standards, TSs, and PSEG station procedures as criteria for determining compliance.

Inspection Planning

The inspectors reviewed the following:

The updated FSAR to identify radiation instruments associated with monitoring area radiation, airborne radioactivity, materials/articles, and workers; records of in-service survey instrumentation including: air samplers, small article monitors (SAM), radiation monitoring instruments, personnel contamination monitors, portal monitors, and whole-body counters; and procedures for instrument source checks and calibrations Portal Monitors, Personnel Contamination Monitors, and SAMs The inspectors reviewed the various types of instruments in use and their alarm set-point values for the release of material from the site.

Portable Survey Instruments, Area Radiation Monitors (ARM),

Electronic Dosimetry, and Air Samplers/Constant Air Monitors (CAM)

The inspectors reviewed and discussed PSEG plans for placing in service new instrumentation.

Instrument Calibrator The inspectors reviewed the periodic certification of the calibration standards used for portable instrument calibrations and response checks to determine if instruments had been calibrated by a facility using National Institute of Science and Technology traceable sources and were appropriate for the expected source term.

Calibration and Check Sources The inspectors reviewed the plant waste stream characterization to assess whether calibration sources used were representative of the radiation encountered in the plant.

Problem Identification and Resolution The inspectors determined if problems associated with radiation monitoring instrumentation were being identified and placed in corrective action program for resolution.

b. Findings

No findings were identified.

2RS6 Radioactive Gaseous and Liquid Effluent Treatment

a. Inspection Scope

During the period of August 27- 28, September 15 - 30, 2014, the inspectors reviewed monitoring, evaluation, and control of gaseous radioactive effluents. The review was against criteria contained in 10 CFR Part 20, 10 CFR Part 50, applicable Regulatory Guides and industry standards, TSs, Offsite Dose Calculation Manual (ODCM), and PSEG station procedures for determining compliance.

Event Report and Effluent Report Reviews The inspectors reviewed 2012 and 2013 Annual Radiological Effluent Release Reports to determine if the reports: were submitted as required, provided any anomalous results, indicated unexpected trends or abnormal releases, or identified radioactive effluent monitor operability issues for further inspection; and, reviewed groundwater remediation reports.

b. Findings

No findings were identified.

2RS7 Radiological Environmental Monitoring Program (REMP)

a. Inspection Scope

During the period August 27 - 28; September 15 - 30, 2014, the inspectors reviewed he REMP in order to validate the effectiveness of the radioactive gaseous and liquid effluent release program. The inspectors used the requirements in 10 CFR Part 20; 40 CFR Part 190; 10 CFR 50 Appendix I; and the sites TSs, ODCM, and program procedures; as criteria for determining compliance.

Inspection Planning

The inspectors reviewed the following:

2012 and 2013 annual radiological environmental and effluent monitoring reports; results of PSEG assessments in this area since the last inspection; changes to the ODCM with respect to environmental monitoring, sampling locations, monitoring and measurement frequencies, Land Use Census, inter-laboratory comparison program, and analysis of data; the ODCM and associated environmental monitoring station maps; the Updated Final Safety Analysis Report (UFSAR);

Quality Assurance (QA) audit results; and 10 CFR Part 61 evaluations to identify predominant radionuclides likely to be released in effluents Onsite Inspection The inspectors reviewed the following:

observed sample collection, monitoring, and dose measurement stations (e.g., TLD, air monitoring, vegetation, milk);walked down PSEG sample gardens and placement; noted material condition of environmental monitoring equipment; verified calibration and maintenance records/data to confirm equipment operability; verified criteria for sampling alternate media upon loss of a required sampling station; verified environmental sampling of the effluent release pathways as specified in the ODCM; toured the meteorological tower and reviewed meteorological data readouts and potential foliage impact on tower instruments; verified that the meteorological instruments were operable, calibrated, and maintained; verified that missed and/or anomalous environmental samples were identified, resolved, and reported in the annual radioactive environmental monitoring report; reviewed and discussed the PSEG assessment of positive environmental samples; verified that for potential leaking structures, systems, or components (SSCs), PSEG had implemented a sampling and monitoring program sufficient to detect leakage; reviewed the Groundwater Protection Initiative Program Reports and Quarterly Groundwater Remedial Action Progress Reports; reviewed records for 10 CFR 50.75(g), leaks, spills, and remediation since the previous inspection; reviewed changes to the ODCM as the result of changes to the Land Use Census, long-term meteorological conditions, and modifications to the sampler stations; reviewed technical justifications for any changed sampling locations; reviewed detection sensitivities used for counting samples; and, reviewed vendor laboratory analysis results, results of the vendors quality control program, the inter-and intra-laboratory comparison program.

Identification and Resolution of Problems The inspectors determined if problems associated with the REMP were being identified and placed in the corrective action program for resolution.

b. Findings

No findings were identified.

4OA1 Performance Indicator Verification

.1 Mitigating Systems Performance Index (4 samples)

a. Inspection Scope

The inspectors reviewed PSEGs submittal of the Mitigating Systems Performance Index for the following systems for the period of October 1, 2013, through September 30, 2014.

Units 1 and 2, Emergency AC Power System (MS06)

Units 1 and 2, Cooling Water System (MS10)

To determine the accuracy of the performance indicator (PI) data reported during those periods, inspectors used definitions and guidance contained in Nuclear Energy Institute (NEI) Document 99-02, Regulatory Assessment PI Guideline. The inspectors reviewed PSEGs operator narrative logs, condition reports, mitigating systems performance index derivation reports, event reports, and NRC integrated inspection reports to validate the accuracy of the submittals.

b. Findings

No findings were identified.

.2 Occupational Exposure Control Effectiveness (1 sample)

a. Inspection Scope

During the week of December 1, 2014, the inspectors reviewed licensee submittals for the occupational radiological occurrences PI for the fourth quarter 2013 through the third quarter 2014. The inspectors used PI definitions and guidance contained in the Nuclear Energy Institute Document 99-02, Regulatory Assessment Performance Indicator Guideline, Revision 7, to determine the accuracy of the PI data reported during those periods. The inspectors reviewed electronic personal dosimetry accumulated dose alarms, dose reports, and dose assignments for any intakes that occurred during the time period reviewed to determine if there were potentially unrecognized PI occurrences.

The inspectors conducted walk-downs of various Locked High and Very High Radiation Area entrances to determine the adequacy of the controls in place for these areas.

b. Findings

No findings were identified.

.3 Radiological Effluent TS/ODCM Radiological Effluent Occurrences (1 sample)

a. Inspection Scope

During the week of December 1, 2014, the inspector reviewed licensee submittals for the radiological effluent TS/ODCM radiological effluent occurrences PI for the third quarter 2013 through the third quarter 2014. The inspectors used PI definitions and guidance contained in the Nuclear Energy Institute Document 99 02, Regulatory Assessment Performance Indicator Guideline, Revision 7, to determine if the PI data was reported properly during this period. The inspector reviewed the public dose assessments for the PI for public radiation safety to determine if related data was accurately calculated and reported.

The inspectors reviewed the PSEG issue report database to identify any potential occurrences such as unmonitored, uncontrolled, or improperly calculated effluent releases that may have impacted offsite dose. The inspectors reviewed gaseous and liquid effluent summary data and the results of associated offsite dose calculations to determine if indicator results were accurately reported.

b. Findings

No findings were identified.

4OA2 Problem Identification and Resolution

.1 Routine Review of Problem Identification and Resolution Activities

a. Inspection Scope

As required by Inspection Procedure 71152, Problem Identification and Resolution, the inspectors routinely reviewed issues during baseline inspection activities and plant status reviews to verify that PSEG entered issues into the CAP at an appropriate threshold, gave adequate attention to timely corrective actions, and identified and addressed adverse trends. In order to assist with the identification of repetitive equipment failures and specific human performance issues for follow-up, the inspectors performed a daily screening of items entered into the CAP and periodically attended condition report screening meetings.

b. Findings

No findings were identified.

.2 Annual Sample: Review of the Operator Workaround Program

a. Inspection Scope

The inspectors reviewed the cumulative effects of the existing OWAs, operator burdens, existing operator aids and disabled alarms, and open main control room (MCR)deficiencies to identify any effect on emergency operating procedure operator actions, and any impact on possible initiating events and mitigating systems. The inspectors evaluated whether station personnel had identified, assessed, and reviewed OWAs as specified in Salem procedure OP-AA-102-103, OWA Program.

The inspectors reviewed PSEGs process to identify, prioritize and resolve main control room distractions to minimize operator burdens as specified in Salem procedure OP-AA-102-103-1001, Operator Burdens Program. The inspectors reviewed the methods used to track these OWA and burdens. The inspectors also toured the control room and discussed the current operator workarounds with the operators to ensure the items were being addressed on a schedule consistent with their relative safety significance.

b. Findings and Observations

No findings were identified.

The inspectors determined that PSEG was identifying, assessing, and reviewing OWAs IAW procedure OP-AA-102-103. However, the inspectors identified some examples where the assessment and review of operator burdens and MCR distractions was not being performed IAW the Operator Burdens program procedure, as well as other general inconsistencies, including:

OP-AA-102-103-1001, step 5.4.1, requires a quarterly assessment of operator burdens to determine the Aggregate Impact using the list in Attachment 1.

Inspectors reviewed a sample of the quarterly Aggregate Impact assessments documented in WOs, and determined that Attachment 1 was not being used to perform the assessments. Specifically, the scope of quarterly assessments only included condition reports in the CAP, and did not include reviews of the other items listed in Attachment 1, such as temporary modifications, long-term work clearances, operability evaluations, operational technical decision making documents, and adverse condition monitoring plans.

OP-AA-102-103-1001, Attachment 1, requires an increase in the frequency of Aggregate Impact assessments when the list of items in Attachment 1 reaches a value that is 10 above the MCR distraction metric. The inspectors noted that the CAP code for MCR distractions is one of 32 potential CAP codes that fall under broader categories such as control room indicator, work around, or operator burden assessment. Additionally, the inspectors noted that there is no procedural guidance to compare the items listed in Attachment 1 with the list of MCR distractions. Consequently, there was no clear method to determine when the frequency of Aggregate Impact assessments was required to be increased.

The inspectors noted that there was no formal guidance describing how to screen notifications with the appropriate code to indicate OWA, burden, MCR distraction, etc. The inspectors noted that Operations had previously created, and subsequently closed, temporary standing orders 2012-0012 and 2013-0027 to establish guidance for screening notifications as OWAs or burdens. Despite the lack of current formal guidance, the inspectors determined that operators continued to use the coding process appropriately based on previously issued standing orders.

OP-AA-102-103-1001, Attachment 1, page 1, states that the operations training department will review the Aggregate Impact assessment reports to determine if additional training is required to address operator challenges. The inspectors noted that operations training department reviews were performed annually, which was inconsistent with the quarterly frequency of the Aggregate Impact assessments.

The quarterly OWA board meeting did not include a review of the quarterly Aggregate Impact assessment reports.

PSEG created a Hope Creek procedure for performing Operator Burden Assessments (OP-HC-102-103-1002), but did not create a similar procedure at Salem.

The inspectors noted that similar NRC-identified observations had been made in 2011 (IR 05000272;311/2011005), and 2013 (IR 05000272;311/2013004). PSEG captured the 2013 observations in the CAP as notifications 20624037 and 20626619. The inspectors reviewed the 2013 notifications, and noted that PSEG corrective actions were ongoing at the time of inspection.

PSEG captured the issues above in their CAP as notifications 20672486, 20672484, and 20672487. The inspectors concluded that any performance deficiencies identified above were not more than minor based on a review of IMC 0612. Specifically, the inspectors reviewed a sampling of issues and determined that they were properly screened into the OWA and burden programs. Additionally, the inspectors concluded that PSEG was properly identifying, prioritizing, and resolving OWAs.

.3 Annual Sample: Unit 2 Coolant Pump (RCP) Turning Vane Bolt (TVB) Failures

a. Inspection Scope

During the 2nd quarter of 2014, inspectors initiated an in-depth review of PSEGs evaluations, extent of condition (EOC) reviews, and corrective actions associated with degraded RCP TVBs. As documented in section 4OA2 of NRC inspection report 05000272;311/2014-003, since refueling outage 2R18 in 2011, a total of seventeen TVB heads had been discovered in the reactor coolant system. In June 2014, PSEG conducted a plant cooldown, defueled the reactor, and shipped all four RCPs offsite for inspection and repair at two vendor facilities. These inspections found TVB failures on all four RCPs. An unresolved item (URI)05000311/2014003-03 was identified because additional NRC review and evaluation was needed to determine if the issue was more than minor, whether the issue of concern constituted a violation, and the adequacy of PSEGs corrective actions. During this quarter, inspectors reviewed PSEGs completed evaluation, causal analysis, and corrective actions associated with the as-found condition and the impact on safety components and accident analysis. In addition, NRRs Reactor Systems Branch reviewed the Salem condition, including the applicability of the previous long history of bolt issues. Administratively, this annual sample is a continuation of the sample commenced in the 2nd quarter of 2014. URI 05000311/2014003-03 is closed.

b. Findings

Introduction.

The inspectors identified a Green non-cited violation of 10 CFR 50, Appendix B, Criterion XVI, Corrective Action, because PSEG staff did not promptly correct a condition adverse to quality related to failed Unit 2 reactor coolant pump (RCP)turning vane bolts (TVBs). Specifically, PSEG staffs use as is evaluation in 2012 was not technically adequate to support their conclusion that contact between the pump turning vane and rotating impeller was acceptable in the event all turning vane bolts failed. As a result, PSEG did not complete corrective actions to perform a pump specific technical analysis or to replace the bolts until this issue was identified in June 2014.

Description.

In 1990, the NRC issued Information Notice (IN) 90-68, Stress Corrosion Cracking of Reactor Coolant Pump Bolts, to make licensees aware that RCP turning vane had been installed with alloy A-286 TVBs that were susceptible to intergranular stress-corrosion cracking (IGSCC). In 1994, the pump vendor issued Technical Bulletin (TB) 94-06-RO, titled "Model 93A RCP Turning Vane Bolt IGSCC Issue," followed by IN 95-43, Failure of the Bolt-Locking Device on the RCP Turning Vane, to inform licensees of an event that included a loss of bolt-locking device integrity in the RCP turning vane and the discovery of a bolt and two lock devices on a reactor lower core plate.

Salem Unit 2 is a four-loop pressurized-water reactor plant with Model 93A RCPs. The RCP hydraulic section consists of a casing, impeller, a diffuser adapter, a thermal barrier, and a turning vane diffuser. The diffuser, which is located above the impeller, converts the velocity head generated by the impeller to a static head by reducing the fluid velocity in the expanding flow channels between the diffuser vanes. The flow is then directed to the outlet nozzle by the turning vanes. The turning vane diffuser (TV-D)is stationary and is attached to the thermal barrier flange by 20, 1-inch diameter bolts.

The TVBs are made from alloy A286, which is known to be susceptible to IGSCC. The bolts are designed to secure the turning vane diffuser to the thermal barrier flange and the bolt-locking device is to prevent bolt rotation and subsequent loss of bolt preload.

To ensure adequate core cooling after a loss of electrical power to the RCPs, each pump is designed with a flywheel that is attached to the top of the pump motor. If the reactor trips on a loss of flow, due to a loss of power to the reactor coolant pumps, the flywheels will extend the coast-down time to maintain adequate heat transfer capability and help establish natural circulation flow. Additionally, the plant is analyzed to accommodate one reactor coolant pump locked rotor condition.

In 2011, during the Unit 2 refueling outage (2R18), PSEG staff identified two RCP TVB heads, sheared from their bolt shank, in the reactor coolant system (RCS). PSEG documented this condition in their CAP as notification 20506297. In 2012, during the

2R19 refueling outage, PSEG staff observed additional RCP TVB heads in the RCS

and documented this condition in their CAP (20579944, 20580006 and 20581402).

PSEG staff communicated with the pump vendor and evaluated the condition in order 70144776. PSEGs evaluation stated that Dropping of the stationary hydraulic will have no direct impact on the seal assembly, as little or no contact between stationary and rotating parts should occur.

In 2014, during the 2R20 refueling outage, PSEG staff identified eight additional RCP TVB heads in the RCS and documented this issue in their CAP (20647745 and 20647674). The inspectors reviewed these CAP entries and referred them to a regional materials inspector for review. The inspectors reviewed PSEGs prior notifications and evaluations of the loose TVB heads that had also been identified during the previous two refueling outages. PSEGs evaluations concluded that the issue was not a safety concern based on pump flow seal temperatures, bearing temperatures, vibration parameters remaining normal and input from the pump vendor that indicated bolt failures should not significantly affect pump performance or result in a safety issue. The pump vendor recommended disassembling the RCPs to correct this bolting problem only if there were other issues that warranted disassembly.

The inspectors questioned the basis for acceptability of contact between pump stationary and rotating internal components. PSEG staff conducted additional reviews in coordination with the pump vendor and documented in operation technical decision making OTDM S-14-003, that in the event of a failure of the turning vane assembly, it was possible for machining to occur between the rotating and stationary parts. The inspectors questioned the technical basis for PSEGs conclusions as they related to the Salem Unit 2 locked rotor analysis, RCP pump coast down requirements, and the potential for debris in the RCS. In reviewing NRC questions and evaluating the bolting issue, PSEG staff determined the pumps should be disassembled and the bolts replaced. PSEG was not able to establish the number of RCPs affected. Additionally PSEG staff could not ensure that a turning vane drop would not cause debris that could be transported into the reactor core or affect pump performance.

PSEG delayed startup from the 2R20 refueling outage to perform RCP internal inspections to determine the extent of the issue and make necessary repairs and replacements. This necessitated a full core offload, disassembly of the four RCPs, and shipment of the RCPs to specialist vendors. All four Salem Unit 2 RCPs were disassembled for inspection. In three of the four RCPs, all TVBs (20 per RCP, 1-inch diameter) were broken and the TV-D had dropped. In two of the three RCPs with a dropped TV-D, there was visual evidence of rubbed metal and associated material loss on the contacting surfaces. There were no identifiable impacts on RCP operation or locked rotor events reported by PSEG. PSEG completed these corrective actions and returned Unit 2 to online power operations in July 2014.

The inspectors determined that because the potential existed to have multiple pumps with degraded coast down capabilities, the condition was not bounded by the UFSAR Chapter 15 accident analyses. In review of PSEG procedure LS-AA-120, Issue Identification and Screening Process, Revisions 9 through 12, the inspectors determined the procedure defines a condition adverse to quality (CAQ) as a failure, malfunction, deficiency, defective item, or non-conformance. The inspectors concluded PSEG staffs evaluations in 2012 under CAP notifications 20579944, 20580006 and 20581402, should have resulted in corrective actions to rule out this condition or provided for bolt replacement.

The inspectors noted the pump vendor subsequently identified this condition was a potential substantial safety hazard and reported the issue to the NRC in Event Report

1. 50279, dated July 14, 2014.

Analysis.

Failure to promptly correct a condition adverse to quality was a performance deficiency. The finding was evaluated in accordance with IMC 0612, Appendix B, and determined to be more than minor since it affected the equipment performance 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. Additionally, the issue was more than minor based on similarity to IMC 0612, Appendix E, example 3.a. Specifically, the dropped turning vanes adversely affected the operating RCP lineup, and the supporting documentation errors brought into question their effect on the RCP locked rotor accident analysis and resulted in additional field work. Given the discovery of bolts during multiple operating cycles, the finding was determined to pertain to at-power operations. Therefore, the finding was evaluated using IMC 0609, Attachment 4 and Appendix A, where it screened to Green since it was a qualification deficiency of a mitigating component, the RCP as related to its coast down capability that ultimately retained its functionality.

The finding was determined to have a cross-cutting aspect in the area of Problem Identification and Resolution, Evaluation, because PSEG, in addition to prior operating experience-related reports, had two opportunities in 2011 and 2012 when broken bolts were discovered, to thoroughly evaluate the technical basis for their conclusion that RCP turning vane dislodgement and contact with rotating pump components was acceptable.

When PSEG thoroughly considered the problem in 2014, they determined there was there was not adequate pump specific internal clearance information to support their prior technical conclusions that turning vane contact was acceptable. (P.2)

Enforcement.

10 CFR 50, Appendix B, Criterion XVI, states, in part, measures shall be established to assure that conditions adverse to quality, such as failures, malfunctions, deficiencies, deviations, defective material and equipment, and non-conformances are promptly identified and corrected. Contrary to this, from 2011 to 2014, PSEG did not promptly identify that a vendor evaluation was inadequate and thereby, did not initiate actions to correct the adverse condition of the RCP TVB heads failing due to IGSCC, enabling the turning vanes to drop on three of the four RCPs, with contact being made between turning vanes and impellers on two RCPs. PSEG replaced the TVBs on all four Unit 2 RCPs, entered this in their CAP (20660176, 20660177, 20660191, 20660175 and 20660173), and completed two root cause analyses. Because this finding was of very low safety significance (Green) and was entered into PSEGs CAP, this violation is being treated as an NCV consistent with Section 2.3.2 of the NRCs Enforcement Policy.

(NCV 05000311/2014-005-04, Failure to Promptly Correct Reactor Coolant Pump Turning Vane Bolt Failures)

.4 Annual Sample: Spent Fuel Pool and Ground Water Assessment

a. Inspection Scope

During the period December 15 - 17, 2014, the inspectors reviewed the status and on-going activities associated with identification, control, and resolution of spent fuel pool leakage at Salem Unit 1. The inspection included walk-downs and observations of the Unit 1 and Unit 2 spent fuel pools (SFPs), the SFP telltale drains and drain troughs, the seismic gap pump locations and the location of specific ground water sampling wells including the ground water sampling house.

The review was in accordance with guidance contained in IMC 71152, Section 03.06B, and included documentation of the identified groundwater contamination condition, the extent of condition, prioritization of identified issues, and identification of contributing causes and focus of corrective actions. The following matters were reviewed:

fuel pool leakage repair, minimization, and quantification status of structural issues/concerns since previous evaluation remediation efforts associated with legacy tritium ground water contamination the current groundwater tritium program investigation conceptual model of groundwater flow in deep and shallow aquifers including radionuclide characterization in the subsurface use of radioactive release permits for extracted groundwater contaminants public dose projections and reporting planned winter ground water pumping/ remediation efforts long term groundwater remediation plans extent of condition (e.g., Salem Unit 2)

b. Findings and Observations

No findings were identified.

The inspectors review determined that PSEG took various actions to evaluate and minimize seepage of Unit 1 SFP water to the Unit 1 Seismic Gap (a foam filled narrow space between the Unit 1 Spent Fuel Pool and the Auxiliary Building) which PSEG previously determined to be the source of tritium contamination of groundwater at Salem Unit 1. PSEG actions to minimize the seepage included routine monitoring and maintenance of the SFP tell-tale drain systems at both Salem 1 and Salem 2 to provide for proper collection of leakage, development of a seismic gap draining system to remove residual water from the seismic gap for proper disposal, and conduct of Unit 1 SFP liner leakage identification and repair efforts.

The Unit 1 SFP liner leakage identification efforts had identified some minor SFP liner leakage locations which were under evaluation at the time of the inspection. Such leakage is normally designed to be collected by the installed SFP liner leakage collection system (tell-tale drain system) and processed via the stations radioactive waste treatment system. Notwithstanding, some seepage continues to make its way to the seismic gap. To control, collect, and process this seepage to the seismic gap, PSEG has implemented enhanced collection of leakage into the seismic gap and has modified the seismic gap collection drain system to provide for active pumping of water within the seismic gap and processing by the installed radioactive waste processing system.

PSEG also initiated pumping of well AC (located in close proximity to the seismic gap)to collect water migrating from the seismic gap. These efforts have reduced migration of tritium to the ground water.

PSEG continues to utilize the installed ground water pumping system to clean-up residual legacy tritium in onsite ground water. These efforts have resulted in significant decreases in tritium contamination in the surface plume external to the Unit 1 coffer dam.

PSEG has conducted public dose projections associated with potential ground water migration to the river and determined there was no dose impact to the public.

The inspectors noted some red staining within the Unit 1 SFP tell-tale drain sump (Notification 20673589) and some areas of apparent water intrusion (Notification 20673588) in the Unit 1 Auxiliary Building in the course of their tours. They noted that PSEG was also evaluating the results of Vincentown ground water sampling results and is evaluating the need for further characterization of the width of the plume in this aquifer (Notification 20673469). PSEG placed these matters into its CAP for evaluation; as these issues were minor in significance, the inspector had no concern with the addressal of these issues in the future.

.5 Semi-Annual Trend Review

a. Inspection Scope

The inspectors performed a semi-annual review of site issues, as required by Inspection Procedure 71152, to identify trends that might indicate the existence of more significant safety issues. In this review, the inspectors included repetitive or closely-related issues that may have been documented by PSEG outside of the CAP, such as trend reports, performance indicators, major equipment problem lists, system health reports, maintenance rule assessments, and maintenance or corrective action program backlogs.

The inspectors also reviewed PSEGs CAP database for the first through fourth quarters of 2014 to assess notifications written in various subject areas (equipment problems, human performance issues, etc.), as well as individual issues identified during the NRCs daily condition report review (Section 4OA2.1). The inspectors reviewed PSEGs quarterly trend reports, 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.

Emerging Trend in Procedure Adherence (H.8). There were three NRC findings in the first three quarters of 2014 with this cross-cutting aspect. The inspectors reviewed the emerging cross-cutting theme, in accordance with 71152, to develop insights into PSEGs progress in addressing the theme. The following is a brief timeline of station events that the inspectors determined were relevant and/or related to the cross-cutting theme:

May 9, 2014 - NRC inspection report 05000272;311/2014-002 was issued with a Green NCV of 10 CFR 50.65(a)(1) for not establishing appropriate performance goals for a charging pump. The H.8 cross-cutting aspect was assigned since PSEG staff did not follow Maintenance Rule program guidance.

July 14, 2014 - Procedure LS-AA-1006, NRC Cross-Cutting Analysis and Trending, was voided, without a new, superseding procedure. An evaluation to update the procedure with the revised NRC safety culture language ultimately resulted in a decision to void the procedure.

August 4, 2014 - NRC inspection report 05000272;311/2014-003 was issued with a Green NCV of TS 6.8.1 for not maintaining a shutdown margin calculation procedure.

The H.8 cross-cutting aspect was assigned since PSEG staff did not follow a change management procedure during modification of another procedure.

October 9, 2014 - PSEG wrote a notification (20664836) that their performance indicator on cross-cutting aspects was in variance due to this emerging trend (three NRC findings with the same cross-cutting aspect). The notification was closed with a comment that the issue was to be addressed as part of a station-wide recovery action plan. This action plan, captured in 20664796 on October 10, 2014, included near-term recovery actions in advance of the Unit 1 refueling outage that included procedure use and adherence as part of a broader performance improvement initiative.

October 13, 2014 - PSEG issues a site-wide reinforcement communication on procedure use and adherence during the Unit 1 refueling outage.

October 19, 2014 - During a Unit 1 shutdown for a refueling outage and a reactor trip, inspectors identified multiple procedure non-compliances. An associated Green NCV with the H.8 cross-cutting aspect is documented in section 1R20 of this report.

October 20, 2014 - During solid RCS operations, multiple examples of failure to follow station procedures resulted in lifting of a low-temperature overpressure (LTOP) relief valve. An associated Green NCV with the H.8 cross-cutting aspect is documented in

1R15 of this report.

October 21, 2014 - PSEG issues a site-wide communication to conduct a stand-down on procedure use and adherence, citing a breakdown associated with the LTOP issue.

October 25, 2014 - Nuclear Oversight writes a trigger notification (20666615) identifying an adverse trend of inadequate procedure use and adherence fundamentals, based on an inadvertent lifting of a pressure relief, removal of an incorrect component, and instances of poor place-keeping.

October 28, 2014 - NRC inspection report 05000272;311/2014-405 was issued with a Green NCV related to material control and accounting. The H.8 cross-cutting aspect was assigned since PSEG staff did not follow procedures related to the activity.

December 31, 2014 - PSEG ended the inspection period in the process of developing their station-wide recovery plan that included actions focused on the procedure use and adherence theme.

Unplanned LCOs. PSEG maintains monthly performance indicators (PI) for unplanned shutdown LCOs on each unit. The 12 month rolling average trend for this indicator has risen on both units and is well above PSEGs established goal. In June 2014, PSEG described the unit trends as negative and adverse and entered this in their CAP (20652036). An inspector review of this CAP item revealed that it had a single action item to review negative trend, with a due date that had changed at least three times and a current due date of January 14, 2015. LS-AA-125-1005, Coding and Analysis Manual, Revision 7, step 4.3.8, says that adverse trends should be evaluated, e.g.

using a Work Group Evaluation, CCE, or ACE, to determine a cause. Step 3.2.5 says the department CAPCO is to develop an action plan when an adverse trend is identified. The unit PIs for unplanned LCOs credited the WO associated with this adverse trend as tracking results. No actions were identified by the inspectors during their review. LS-AA-125, Corrective Action Program, Revision 18, step 4.3, describes evaluations as typically approved within 30 days from order creation. The inspectors noted that this adverse trend had not yet been evaluated and exceeded procedure expectations. However, PSEG has established a system performance team for chillers, considered to be one of lead contributors to the unplanned LCOs. Since the absence of a trend evaluation was not directly attributed to any inoperability, the inspectors determined this was of minor significance.

Status Control Events. During 2014, there were a number of status control events.

Nuclear Oversight completed a focus area self-assessment (80111784) on configuration and status control in July 2014. PSEG concluded that current performance in this area was below expectations and that this performance was already known to station leadership given performance indicators that monitor this area. PSEG appropriately identified this adverse trend and entered it in their CAP (20661334) on September 5, 2014. However, the inspectors observed that while individual events were appropriately evaluated, as of the end of the quarter, there was no evaluation of the overall trend and there was one action item to revise the Operations PIIM due in December 2016. The status control events identified in this NOTF were:

Unit 2 SGFP trip test loading oil isolation valve on July 16 (20656775)

Unit 1 condensate return pump discharge control valve on August 9 (20658781)

Unit 2 SGFP reheat steam supply valve on August 15 (20659545)

Unit 1 to Unit 2 waste cross connect vent valve on August 30 (20660673)

Unit 2 holdup tank isolation and discharge header flush valves on August 28 (20660450)

The inspectors noted additional status control events during 2014:

Common #2 diesel fire pump day tank on March 6 (20643268)

Unit 2 incorrect SW pump breaker on March 10 (20642516)

Unit 2 radiological waste drain pump isolation valve on April 25 (20648538)

Unit 2 RCP seal water vent valves on May 4 (20649745)

Unit 2 containment fan cooling unit SW outlet valve on July 3 (20655397)

Unit 1 caustic tank level on October 10 (20664984)

Unit 2 SW traveling screen differential pressure instrument valve on October 12 (20664997)

Unit 1 charging pump discharge valve on October 20 (20665987)

Unit 2 reheat steam supply bypass on October 28 (20667109)

Unit 1 solid radiological waste test valve on October 19 (20665823)

Unit 1 hot leg test line stop valve on November 19 (20670441)

Unit 1 intermediate range nuclear instrument test switch on December 26 (20674109)

As of the end of December 2014, PSEG had coded 14 status control occurrences and 3 tagging control occurrences. Comparatively, in 2013, PSEG had coded 8 status control occurrences and 1 tagging control occurrence. The inspectors noted that five notifications in 2013 were marked for potential events, but remained unevaluated for status control. Overall, the inspectors determined that PSEGs identification of the adverse trend was appropriate, but that evaluation and implementation of corrective actions were untimely given the procedure expectations in LS-AA-125-1003 mentioned in the unplanned LCO discussion above. Green NCVs were associated with the diesel fire pump and charging pump discharge valve issues. Inspector evaluation of the remaining events determined they were of minor significance.

4OA3 Follow-Up of Events and Notices of Enforcement Discretion

.1 Plant Events

a. Inspection Scope

For the plant event 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 1, manual reactor trip during Unit 1 shutdown to refueling outage 1R23, on October Unit 2, TS 3.0.3 entry following failure of the 1B vital instrument bus and accident pressurization of the main control room on October 29

b. Findings

Introduction.

Inspectors identified a Severity Level IV NCV of 10 CFR 50.72(b)(2)(iv)(B)when PSEG failed to make the required event notification within four hours for a valid actuation of the reactor protection system (RPS) when the reactor was critical.

Description.

On October 19, 2014, inspectors observed PSEG shut down Salem Unit 1 for its 23rd refueling outage. The preplanned shutdown sequence called for operators to reduce power to 11 percent power, start and establish auxiliary feedwater (AFW) flow and manually trip the reactor. Specifically, the last step in S1.OP-IO.ZZ-0004, Power Operations, Revision 58, prior to transition to S1.OP-IO.ZZ-0005, Minimum Load to Hot Standby, Revision 21, requires power to be reduced less than 20 percent and stabilized. In addition to other procedural actions, S1.OP-IO.ZZ-0005 requires AFW to be started and to establish 10E4 lbm/hr flows to each of the steam generators prior to tripping the reactor.

During the reduction of main generator loading, operators received a main power transformer (MPT) trouble alarm. An equipment operator reported that the alarm was due to a low oil level on the 1B main power transformer. The transformer had a known oil leak and PSEG had been compensating for the loss by adding oil at a rate of approximately 175 gallons per week during the five weeks prior to the shutdown. The transformer was being monitored via an Adverse Condition Monitoring (ACM) plan and an Operating Technical Decision Making (OTDM) document. The ACM and OTDM provided operator guidance on how to maintain MPT oil levels within acceptable levels and when to remove the MPT from service if needed. Operators exited the S1.OP-IO.ZZ-0004 procedure to S1.OP-AB.LOAD-0001, Rapid Load Reduction, Revision 14, and changed the power reduction rate from 20 percent per hour to 1 percent per minute.

Subsequently, at approximately 27 percent power, equipment operators reported a gassing alarm associated with the same transformer. The ACM required that, given low oil level and gassing alarms, PSEG reduce power below 40 percent, trip the turbine in accordance with S1.OP-AB.LOAD-0001 and S1.OP-AB.TRB-0001, Turbine Trip Below P-9, Revision 13, and stabilize reactor power at 10 to 15 percent. Following removal of the main generator, PSEG would then follow the S1.OP-IO.ZZ-0005 procedure to complete the reactor shutdown. Instead, PSEG manually tripped the reactor before completing the rapid power reduction procedure, S1.OP-AB.LOAD-0001, and transitioned to procedure 1-EOP-TRIP, Reactor Trip or Safety Injection, Revision 27.

Because the AFW pumps had not been started and were not in service prior to the reactor trip, narrow range levels in three of the four steam generators reached 14 percent, resulting in a valid AFW actuation for low steam generator water level (an eight-hour 10 CFR 50.72(b)(3)(iv)(A) report made via EN 50550). AFW automatically initiated as designed and steam generator water levels were later restored to normal post trip values using 1-EOP-TRIP.

NUREG-1022, Event Report Guidelines 10 CFR 50.72 and 50.73, Revision 3, section 3.2.6, states that an event involving a critical scram is reportable under 10 CFR 50.72(b)(2)(iv) (a 4 hour4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> report) unless the actuation resulted from and was part of a preplanned sequence. Preplanned actuations are those that are expected to actually occur due to preplanned activities covered by procedures. Such actuations are those for which a procedural step or other appropriate documentation indicates that the specific actuation is actually expected to occur. However, if during the test or evolution, the system actuates in a way that is not part of the planned evolution, that actuation should be reported.

The inspectors determined that the manual reactor trip was not in accordance with PSEGs preplanned documented procedural sequence and, therefore, reportable under 10 CFR 50.72(b)(2)(iv)(B). The inspectors questioned PSEG the following day on why they had not reported the event as an RPS actuation. PSEG entered this in their CAP as notification 20668967, re-evaluated the sequence of events, and subsequently determined that the event was reportable under this criterion.

Analysis.

Failing to submit an event notification in accordance with 10 CFR 50.72 within the required time was a performance deficiency that was reasonably within PSEGs ability to foresee and correct, and should have been prevented. Since the failure to submit a required event report impacts the regulatory process, traditional enforcement applied and the violation was assessed using Section 2.2.4 of the NRCs Enforcement Policy. Using the example listed in Section 6.9.d.9, A licensee fails to make a report required by 10 CFR 50.72, the issue was determined to be a Severity Level IV violation.

The inspectors reviewed the condition for reactor oversight process significance and concluded there was no associated finding. Because this violation involves the traditional enforcement process and does not have an underlying technical violation that would be considered more-than-minor, a cross-cutting aspect is not assigned to this violation in accordance with IMC 0612.

Enforcement.

As stated in 10 CFR 50.72(b)(2)(iv)(B), "Four Hour Reports," any event or condition that results in actuation of the RPS when the reactor is critical, except when the actuation results from and is part of a preplanned sequence during reactor operation, requires the licensee to notify the NRC as soon as practical and in all cases within four-hours of the occurrence. Contrary to this requirement, on October 19, 2014, PSEG did not notify the NRC within four hours of the occurrence of a condition at Salem Unit 1 that resulted in actuation of the RPS when the reactor was critical and that was not part of a preplanned sequence. PSEG reported this RPS actuation in accordance with 10 CFR 50.72 by updating a previous report (EN 50550) on November 24, 2014. Because this SLIV violation was not repetitive or willful, and was entered into PSEGs CAP (20668967), the issue is being treated as a Severity Level IV NCV, consistent with Section 2.3.2 of the NRC Enforcement Policy. (NCV 05000272/2014005-05, Failure to Report a Manual Reactor Trip)

4OA5 Other Activities

.1 Temporary Instruction (TI) 2515/190 - Inspection of the Proposed Interim Actions

Associated with Near-Term Task Force Recommendation 2.1 Flooding Hazard Evaluations

a. Inspection Scope

Inspectors verified that PSEGs interim actions will perform their intended function for flooding mitigation.

The inspectors independently verified that the licensees proposed interim actions would perform their intended function for flooding mitigation.

Visual inspection of the flood protection feature was performed. External visual inspection was conducted for indications of degradation that would prevent its credited function from being performed.

Reasonable simulations of flood mitigation actions, to verify they could be execuded as specified, were reviewed.

Flood protection feature functionality was determined using either visual observation or by review of other documents.

The inspectors verified that issues identified were entered into the PSEG CAP.

b. Findings

No findings were identified.

4OA6 Meetings, including Exit

On January 20, the inspectors presented the inspection results to Mr. John Perry, Salem Site Vice President, and other members of the PSEG staff.

ATTACHMENT:

SUPPLEMENTARY INFORMATION

KEY POINTS OF CONTACT

Licensee Personnel

J. Perry, Site Vice President

L. Wagner, Plant Manager, Salem

C. Aung, Chemist

J. Baker, Fukushima Project Operations Specialist

W. Brammier, PSEG, IWL & Snubbers

J. Carney, Training Manager

K. Chambliss, Manager Regulatory Assurance

L. Clark, Instrument Supervisor

T. Cochaza, PSEG, Licensing Representative

B. Daly, Sustainability Manager

D. Denelsbeck, Radiation Protection Superintendent

R. DeNight Jr., Operations Director

T. Devik, Hope Creek Fukushima Design Manager

M. Eisemmann, Supervisor, Chemistry Group

P. Fabian, PSEG, Steam Generator Engineer

C. Geiger, Fukushima Project Engineering

E. Giles, ISI Program Manager

L. Kern, Assistant Engineering Director

K. King, Regulatory Assurance (Salem)

A. Kraus, Manager, Nuclear Environmental Affairs

D. LaFleur, PSEG, Licensing Representative

F. Leeser, Chemistry Manager (Hope Creek)

T. MacEwen, Hope Creek Regulatory Assurance

R. Montgomery, Buried Piping & FAC Program Manager

T. Morin, Regulatory Assurance (Hope Creek)

J. ORourke, PSEG Corporate License Renewal

J. Owad, PSEG Containment Engineer

J. Palombo, Maintenance Supervisor

C. Payne, System Engineer

W. Persinger, Areva NDE Level III

M. Pyle, Chemistry Manager

S. Raguseo, Salem Site Welding Engineer

G. Ruf, Fukushima Project Engineering Manager

E. Sarti, Boric Acid Corrosion Control Program Engineer

E. Schindelheim, Division Manager, Laboratory Testing

J. Scull, Electrical Maintenance Superintendent

J. Shelton, NOS Assessor

R. Shindel, Fukushima Project Training and Strategy

M. Simpson, Fukushima Project Operations Specialist

S. Simpson, Hope Creek Regulatory Assurance

J. Southens, Meteorological Computer Engineer

J. Stavely, Salem NOS Manager

J. Stead, Senior Plant Engineer

S. Swenson, Senior Manager Plant Engineering

S. Taylor, Radiation Protection Manager

G. Toft, Alara Engineer

J. Vidreiro, Senior Test Engineer

B. Wallace, Fukushima Project Operations Specialist

M. Wolk, Fukushima Project Operations Specialist

D. Yilgic, Lead Engineer

LIST OF ITEMS

OPENED, CLOSED AND DISCUSSED

Open/Closed

05000272/2014005-01 NCV Procedural Non-Compliance Resulted in Low Temperature Overpressure Relief Lifting (Section 1R15)

05000272/2014005-02 NCV Failure to Implement Procedures during Shutdown Results in ESF Actuation (Section 1R20)

05000272/2014005-03 NCV Failure to Implement TS Locked High Radiation Area Controls (Section 2RS1)

05000311/2014005-04 NCV Failure to Promptly Correct Reactor Coolant Pump Turning Vane Bolt Failures (Section 4OA2)

05000272/2014005-05 SLIV Failure to Report a Manual Reactor Trip (Section 4OA3)

Closed

05000311/2014003-03 URI Repetitive Failures of Reactor Coolant Pump Turning Vane Bolts (Section 4OA2)