IR 05000272/2014003

IR 05000272-14-003 and 05000311-14-003, April 1, 2014 Through June 30, 2014, Salem Nuclear Generating Station, Units 1 and 2, NRC Integrated

ML14212A656
Person / Time
Site:	Salem
Issue date:	08/04/2014
From:	Glenn Dentel Reactor Projects Branch 3
To:	Joyce T Public Service Enterprise Group
DENTEL, GT
References
IR-14-003
Download: ML14212A656 (60)

Text

UNITED STATES ugust 4, 2014

SUBJECT:

SALEM NUCLEAR GENERATING STATION, UNIT NOS. 1 AND 2 -

NRC INTEGRATED INSPECTION REPORT 05000272/2014003 AND 05000311/2014003

Dear Mr. Joyce:

On June 30, 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 July 17, 2014, with Mr. John Garecht, Salem Work Management Director, 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 three violations of NRC requirements, all of which were of very low safety significance (Green). However, because of the very low safety significance, and because they are entered into your corrective action program, the NRC is treating these findings as non-cited violations, consistent with Section 2.3.2.a of the NRC Enforcement Policy. If you contest the non-cited violations in this report, you should provide a response within 30 days of the date of this inspection report, with the basis for your denial, to the Nuclear Regulatory Commission, ATTN.: Document Control Desk, Washington, DC 20555-0001; with copies to the Regional Administrator, Region I; the Director, Office of Enforcement, United States Nuclear Regulatory Commission, Washington, DC 20555-0001; and the NRC Resident Inspector at Salem Nuclear Generating Station. In addition, if you disagree with the cross-cutting aspect assigned to any finding, or a finding not associated with a regulatory requirement in this report, you should provide a response within 30 days of the date of this inspection report, with the basis for your disagreement, to the Regional Administrator, Region I, and the NRC Resident Inspector at Salem Nuclear Generating Station. In accordance with Title 10 of the Code of Federal Regulations (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 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 05000272/2014003 and 05000311/2014003 w/Attachment: Supplementary Information

REGION I==

Docket Nos.: 50-272, 50-311 License Nos.: DPR-70, DPR-75 Report No.: 05000272/2014003 and 05000311/2014003 Licensee: PSEG Nuclear LLC (PSEG)

Facility: Salem Nuclear Generating Station, Units 1 and 2 Location: P.O. Box 236 Hancocks Bridge, NJ 08038 Dates: April 1, 2014 through June 30, 2014 Inspectors: P. Finney, Senior Resident Inspector A. Ziedonis, Resident Inspector J. Hawkins, Senior Resident Inspector, Hope Creek C. Cahill, Senior Reactor Analyst F. Arner, Senior Reactor Inspector J. Schoppy, Senior Reactor Inspector R. Barkley, Senior Project Engineer H. Gray, Senior Reactor Inspector R. Nimitz, Senior Health Physicist E. Andrews, Project Engineer Approved By: Glenn T. Dentel, Chief Reactor Projects Branch 3 Division of Reactor Projects Enclosure

SUMMARY

Inspection Report (IR) 05000272/2014003, 05000311/2014003; 04/01/2014 - 06/30/2014;

Salem Nuclear Generating Station Units 1 and 2; Operability Determinations and Functionality Assessments, Plant Modifications, and Event Response.

This report covered a three-month period of inspection by resident inspectors and announced inspections performed by regional inspectors. Inspectors identified three non-cited violations (NCV) 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, Components Within 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.

Cornerstone: Initiating Events

Green.

A self-revealing, Green NCV of TS 6.8.1, Procedures and Programs, as described in Regulatory Guide 1.33, Revision 2, February 1978, was identified when PSEG did not maintain procedure SC.RE-ST.ZZ-0002, Shutdown Margin Calculation, to cover certain mispositioned control rod events. Consequently, PSEG performed an unnecessary rapid boration, and a subsequent manual reactor trip, in response to a control rod drop event on January 31, 2014. PSEG entered this in their corrective action program (CAP),

implemented compensatory measures for calculating shutdown margin, performed an apparent cause evaluation, and initiated actions to correct the cause of the problem, extent of condition, and extent of cause.

The issue was more than minor because it was associated with the procedure quality attribute of the initiating events cornerstone, and adversely affected the cornerstone objective to limit the likelihood of events that upset plant stability and challenge critical safety functions during shutdown as well as power operations. Specifically, the finding resulted in an unnecessary rapid boration and a manual reactor trip. Using IMC 0609, Attachment 4,

Initial Characterization of Findings, and IMC 0609, Appendix A, The SDP for Findings At-Power, the inspectors determined that this finding was of very low safety significance (Green) because it did not cause 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 reactor engineering did not follow procedure HU-AA-1101,

Change Management, when performing a procedure change in response to TB 13-5.

Specifically, licensed operators perform and train on shutdown margin (SDM) calculations, but were not included in the SDM procedure change process as identified by PSEG in their ACE [H.8.] (Section 1R18)

Cornerstone: Barrier Integrity

Green.

A self-revealing, Green NCV of TS 6.8.1, Procedures and Programs, was identified when PSEG did not control reactor coolant system (RCS) pressure in accordance with a procedure. Consequently, on April 13, 2014, while shutdown for a refueling outage, this resulted in lifting a low temperature over-pressure protection valve during solid pressurizer operations. PSEG completed a prompt investigation and an apparent cause evaluation, entered this in the CAP, and submitted a Special Report to the NRC in accordance with TS 6.9.2.

This issue was more than minor because it was associated with the human performance attribute of the Barrier Integrity cornerstone and affected its objective to provide reasonable assurance that physical design barriers (i.e., the reactor coolant system) 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 the procedure resulted in a reactor coolant system 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, Challenge the Unknown, in that individuals should stop when faced with uncertain conditions. Specifically, a PSEG operator did not stop his activity after his first attempt to control pressure, communicate the unexpected RCS pressure response to supervision, nor resolve the issue prior to resuming activities. [H.11]

(Section 1R15)

Cornerstone: Occupational Radiation Safety

Green.

The inspectors identified a self-revealing NCV of very low safety significance associated with the failure to establish and implement adequate radiological controls for the transfer and control of radioactive material within the Unit 2 fuel transfer canal, and subsequent work performed on reactor vessel level instrumentation in the Unit 2 upper reactor cavity. Specifically, PSEG did not conduct necessary and reasonable surveys required by 10 CFR 20.1501 to detect radiation levels emanating from the fuel transfer canal on May 4, 2014. Further, on May 4, PSEG also did not provide sufficient high radiation area dose rate monitoring required by TS 6.12.1 to identify that workers were encountering increasing radiation dose rates. Finally, PSEG did not inform workers of the storage and transfer of radioactive material, required by 10 CFR 19.12(a), prior to performing work in the field on May 4. Upon identification of the radiation concern, PSEG implemented appropriate controls of the affected areas and initiated additional radiation surveys and controls for the sources of the radiation.

This issue was determined to be more than minor because, if left uncorrected, the performance deficiency (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 health and safety from exposure to radiation from radioactive material during routine reactor operation. The finding was assessed using IMC 0609, Appendix C, Occupational Radiation Safety SDP, dated August 19, 2008, 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 the licensee's ability to assess dose. This finding was associated with the Work Management aspect of the Human

Performance cross-cutting area. Specifically, PSEG did not implement adequate planning, control and execution of work activities associated with transfer of radioactive material to ensure the identification and management of risk commensurate to the work such that nuclear safety was an overriding priority. [H.5] (Section 4OA5)

REPORT DETAILS

Summary of Plant Status

Unit 1 began the inspection period at 100 percent power. On April 8, the unit was manually tripped due to lowering steam generator water level following the unplanned shutdown of one steam generator feedwater pump. Operators commenced a reactor startup on April 9, and the unit returned to 100 percent power on April 12. On April 13, the unit automatically tripped due to actuation of the main generator protection circuit as a result of a failed wiring termination on the C phase main generator current transformer. Operators commenced a reactor startup on April 17, and the unit was returned to 100 percent power on April 19. On May 7, the unit automatically tripped due to actuation of the main generator protection circuit as a result of a failed wiring termination on the A phase main generator current transformer. Operators commenced a reactor startup on May 10, and the unit was returned to 100 percent power on May 11. 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 April 12, the unit was shut down for refueling and maintenance outage number 20 (2R20). On May 12, 2R20 was extended by PSEG to perform repairs on the reactor coolant pump turning vane bolts. The unit remained shut down through the end of the inspection period.

REACTOR SAFETY

Cornerstones: Initiating Events, Mitigating Systems, and Barrier Integrity

1R01 Adverse Weather Protection

Summer Readiness of Offsite and Alternate Alternating Current (AC) Power Systems

a. Inspection Scope

On May 21, the inspectors performed a review of plant features and procedures for the operation and continued availability of the offsite and alternate AC power system to evaluate readiness of the systems prior to seasonal high grid loading. The inspectors reviewed PSEGs procedures affecting these areas and the communications protocols between the transmission system operator and PSEG. This review focused on changes to the established program and the material condition of the offsite and alternate AC power equipment. The inspectors assessed whether PSEG established and implemented appropriate procedures and protocols to monitor and maintain availability and reliability of both the offsite AC power system and the onsite alternate AC power system. The inspectors evaluated the material condition of the associated equipment by interviewing the responsible system manager, reviewing condition reports and open work orders, and walking down portions of the offsite and AC power systems, including the 500 kilovolt (KV) switchyard. Documents reviewed for each section of this inspection report are listed in the Attachment.

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, 12 auxiliary feedwater pump, following its return to service, on June 9 Unit 2, the service water (SW) system and electrical support systems during maintenance on the 21 SW nuclear header on April 17 Unit 2, spent fuel pool cooling during full core off load conditions on April 23 Unit 2, 21 residual heat removal during reduced inventory on May 1 The inspectors selected these systems based on their risk-significance relative to the Reactor Safety cornerstones at the time they were inspected. The inspectors reviewed applicable operating procedures, system diagrams, the Updated Final Safety Analysis Report (UFSAR), TSs, work orders, notifications, and the impact of ongoing work activities on redundant trains of equipment in order to identify conditions that could have impacted system performance of their intended safety functions. The inspectors also performed field walkdowns of accessible portions of the systems to verify system components and support equipment were aligned correctly and were operable. The inspectors examined the material condition of the components and observed operating parameters of equipment to verify that there were no deficiencies. The inspectors also reviewed whether PSEG staff had properly identified equipment issues and entered them into the CAP for resolution with the appropriate significance characterization.

b. Findings

No findings were identified.

.2 Full System Walkdown

a. Inspection Scope

On June 19, the inspectors performed a walkdown of accessible portions of the Unit 1 emergency diesel generator fuel oil 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 work orders to ensure PSEG appropriately evaluated and resolved any deficiencies.

b. Findings

No findings were identified.

1R05 Fire Protection

Resident Inspector Quarterly Walkdowns (71111.05Q - 5 samples)

a. Inspection Scope

The inspectors conducted tours of the areas listed below to assess the material condition and operational status of fire protection features. The inspectors verified that PSEG controlled combustible materials and ignition sources in accordance with administrative procedures. The inspectors verified that fire protection and suppression equipment was available for use as specified in the area pre-fire plan, and passive fire barriers were maintained in good material condition. The inspectors also verified that station personnel implemented compensatory measures for out of service, degraded or inoperable fire protection equipment, as applicable, in accordance with procedures and discussed with station personnel the repair plans for degraded equipment.

Unit 1, containment (elevation 78 and 100) on April 15 Unit 1, auxiliary feedwater pump area (elevation 84) on June 9 Unit 1, relay room (elevation 100) on June 23 Unit 2, spent fuel pool cooling and closed loop cooling water areas (elevation 84)on April 14 Unit 2, 21 residual heat removal pump room (elevation 45) on May 1

b. Findings

No findings were identified.

1R06 Flood Protection Measures

.1 Internal Flooding Review

a. Inspection Scope

The inspectors reviewed the UFSAR, the site flooding analysis, and plant procedures to assess susceptibilities involving internal flooding. The inspectors also reviewed the CAP to determine if PSEG identified and corrected flooding problems and whether operator actions for coping with flooding were adequate. The inspectors focused on the Unit 1 charging pump and spray additive tank areas to verify the adequacy of equipment seals located below the flood line, floor and water penetration seals, watertight door seals, common drain lines and sumps, sump pumps, level alarms, control circuits, and temporary or removable flood barriers. The inspectors also verified that PSEGs flooding mitigation plans and equipment for the Unit 1, charging pump and spray additive tank areas were consistent with the design requirements and the risk analysis assumptions.

b. Findings

No findings were identified.

.2 Annual Review of Cables Located in Underground Bunkers/Manholes

a. Inspection Scope

The inspectors conducted an inspection of underground bunkers/manholes subject to flooding that contain cables whose failure could affect risk-significant equipment. The inspectors performed walkdowns of risk-significant areas, including manholes H-4, H-7, E-5, and E-4, containing 13 kV power supply cables required by technical specifications, to verify physical conditions inside the manholes, that cables and/or splices appeared intact, and to observe the condition of cable support structures. The inspectors also ensured that drainage was provided and functioning properly in the applicable manholes, or that any degraded conditions were entered into the CAP as appropriate by PSEG.

For those cables found submerged in water, the inspectors verified that PSEG was implementing corrective actions in accordance with station procedures.

b. Findings

No findings were identified.

1R07 Heat Sink Performance

a. Inspection Scope

The inspectors reviewed the Unit 2, 21 Component Cooling HX, 2CCE5, on April 17, 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 April 16 - 29, 2014, the inspectors conducted an inspection and review of PSEGs implementation of inservice inspection (ISI) program activities for monitoring degradation of the reactor coolant system boundary, risk significant piping and components, steam generator tube integrity, and containment systems during the Salem Unit 2 refueling outage (RFO 2R20). The sample selection was based on the inspection procedure objectives and risk priority of those pressure retaining components in systems where degradation would result in a significant increase in risk. The inspectors observed in-process non-destructive examinations (NDE), reviewed documentation, and interviewed licensee personnel to verify that the NDE activities performed as part of the first period of the fourth interval, Salem Unit 2 ISI program, were conducted in accordance with the requirements of the American Society of Mechanical Engineers (ASME) Boiler and Pressure Vessel Code Section XI, 2004 Edition.

Nondestructive Examination and Welding Activities (IP Section 02.01)

The inspectors performed direct observations of NDE activities in process, and reviewed work instruction packages and records, both documentation and video of nondestructive examinations listed below:

Observation and review scope of ASME Code Required Examinations:

Observation of bare metal visual examination (VT) of the reactor vessel upper head and control rod drive mechanism (CRDM) nozzle penetrations.

Observation of the computer based volumetric ultrasonic testing (UT) of the reactor vessel upper head penetration nozzles in the vicinity of the CRDM to head welds, including a specific review of the past and present condition of CRDMs 2, 42, 49, and 57.

Observation of the visual examination process and record review of the primary containment liner examination report completed per the ASME Code Section XI, IWE. The areas covered during this inspection included those where insulation panels were temporarily removed to provide accessible portions of the containment liner for confirmation of the integrity of the containment pressure boundary.

Review of the work package instructions, procedure, and report PT-14-008 for liquid penetrant (PT) surface examinations of the #21 reactor coolant pump integral support lugs 1, 2 and 3 to confirm the inspection procedure and the examiner were qualified in accordance with the requirements of ASME Section XI.

Observation and record review of the work packages, drawings and procedure for the manual volumetric UT of the chemical and volume control tank 2-CVT-2, shell to lower head weld, weld C of VW2RH175, which is an elbow to pipe weld on 10-SJ-1221-20, and the pipe-to-elbow weld 6-PR-1205-6 above the pressurizer upper head per work order 50156367.

Remote observation of steam generator eddy current testing (ECT) data acquisition, review of the data acquisition, data evaluation, examination control practices and quality assurance aspects of the eddy current examination process. Review and preparation for steam generator tube plugging equipment and process.

The inspectors sampled qualification certificates of the NDE examiners performing the nondestructive testing. The inspectors verified that examinations were performed in accordance with ASME Section XI procedures, and the results were reviewed and evaluated by certified ASME Level III personnel.

Other Augmented or Industry Initiative Examinations The inspectors observed PSEG inspections in response to recommended actions in Westinghouse Nuclear Safety Advisory Letter NSAL-12-1, Steam Generator Channel Head Degradation, which discussed industry experience on cladding defects.

Specifically, the inspectors reviewed remote video coverage of the SG channel heads and divider plate-to-channel weld in SGs 21, 22, and 24, and verified no appearance of degradation.

The inspectors reviewed the Snubber Program Plan for Salem Unit 2, as submitted to NRC via LR-N13-0257, dated November 20, 2013, and observed an in-progress test of snubber 10-SJ-1211-19 per work order 50154848.

Review of previous indications There were no previously identified ASME Section XI NDE indications that required examination during this refueling outage.

Repair/Replacement Consisting of Welding Activities In the area of weld repairs, the inspectors reviewed the work package, weld planning and welding procedure for #23 steam generator blowdown line section replacement and reviewed the radiographs and radiography report dated April 22, 2014, on Weld ID S2-SGD-1014-A.

PWR Vessel Upper Head Penetration Inspection Activities (Section IP 02.02)

The inspectors verified that the reactor vessel upper head penetration J-groove weld examinations were performed in accordance with the requirements of 10 CFR 50.55a and ASME Code Case N-729-1, Alternative Examination Requirements for PWR Reactor Vessel Upper Heads, to ensure the structural integrity of the reactor vessel head pressure boundary. The inspection included a review of the computer based examination results of CRDMs 2, 42, 47 and 57. The inspectors also observed portions of the remote bare metal visual examination of the exterior surface of the reactor vessel upper head to verify that no boric acid leakage or wastage had been observed.

Boric Acid Corrosion Control (BACC) Inspection Activities (IP Section 02.03)

During the plant shutdown process the NRC resident inspectors observed the boric acid leakage identification process. The ISI inspectors reviewed the BACC program, which is performed in accordance with PSEG procedures, and discussed the program requirements with the boric acid program owner. The inspectors reviewed photographic inspection records of a sample of identified boric acid leakage locations and discussed the mitigation and evaluation plans. The inspectors reviewed a sample of condition reports for evaluation and disposition within the corrective action program. Samples selected were based on component function, significance of leakage, and location where direct leakage or impingement on adjacent locations could cause degradation of safety system function.

Steam Generator (SG) Tube Inspection Activities (IP Section 02.04)

The inspectors reviewed a sample of the SG eddy current tube examination results, which consisted of full length bobbin inspection of all active tubes in each of the four SGs, Rotating Probe examination of selected tubes including those with wear indications, Appui (tube supports of specific exterior bundle tubes) special interest locations, tube support (TSP) wear and anti-vibration bar (AVB) wear locations; and Array Probe examinations, including portions of periphery tubes 3 deep, 3 tubes in from the no-tube lane and tubes showing foreign objects. The inspectors compared the scope of the ECT activities with the potential degradation mechanisms documented in the Steam Generator Degradation Assessment Report.

The inspectors verified that the SG eddy current tube examinations were performed in accordance with Unit 2 Technical Specification, NEI 97-06, EPRI SG Examination Guidelines and the plant Steam Generator Program. The inspectors reviewed the SG tube eddy current test results to verify that no in-situ pressure testing was required, and no primary-to-secondary leakage had occurred over the operating cycle. The inspectors verified that the SG tube examination screening criteria was in accordance with the Electric Power Research Institute (EPRI) Steam Generator Guidelines, Revision 7, and flaw sizing was in accordance with the EPRI guidelines.

In addition, the inspectors reviewed foreign object search and retrieval results on the secondary side of the S/Gs and reviewed corrective actions to remove a short, wire-sized foreign object that was in contact with the tube outside surface.

Problem Identification & Resolution (PI&R) (IP Section 02.05)

The inspectors verified that ISI related problems and nonconforming conditions were properly identified, characterized and evaluated for disposition within the corrective action program.

During the visual observation of the steam generator 21 Cold Leg Bowl, PSEG identified two bolt heads as loose parts and documented this condition in Notification 20647694.

These were confirmed to be from bolts that attach the reactor coolant pump turning vane to the pump internals. The inspectors reviewed previous and current evaluations of the significance of the detached bolt heads.

b. Findings

No findings were identified. The PI&R aspects of the detached RCP bolt heads are discussed in Section 4OA2.

1R11 Licensed Operator Requalification Program

.1 Quarterly Review of Licensed Operator Requalification Testing and Training

a. Inspection Scope

The inspectors observed licensed operator simulator training on June 17, 2014, which included a seismic event coincident with a fuel failure, steam generator tube rupture, stuck open steam generator safety valve, and the failure of selected components to automatically start as required. 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 technical specification action statements entered by the shift technical advisor. Additionally, the inspectors assessed the ability of the crew and training staff to identify and document crew performance problems.

b. Findings

No findings were identified.

.2 Quarterly Review of Licensed Operator Performance in the Main Control Room

a. Inspection Scope

The inspectors observed and reviewed the Unit 2 RCS draindown to the reactor vessel flange on May 17, to support re-landing the reactor vessel head during refueling and maintenance outage 2R20. The inspectors observed infrequently performed test or evolution briefings, procedure use, crew communications, coordination of activities between work groups, and the oversight and direction provided by the control room supervisor to ensure it met OP-AA-101-111-1002, Operations Fundamentals, and S2.OP-SO.RC-0005, Draining the RCS to 101 Foot Elevation.

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 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 2, high head safety injection check valve, 23SJ17 on May 10 Unit 3, gas turbine engine on April 23

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, 11 steam generator feed pump control circuit ground fault and silent shutdown on April 9 Unit 1, 1C vital instrument bus failure on May 28 Unit 2, yellow shutdown risk during reduced RCS inventory on April 15 Unit 2, spent fuel pool cooling and time to boil during full core off-load on April 24 Unit 2, orange risk during mid-loop operations on May 3 Common, yellow risk during switchyard work, one offsite power source input on May 15

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 2, low temperature overpressure protection relief valve lift on April 13 Unit 2, leakage below fuel transfer canal in containment on April 23 Unit 2, source range monitors during core reload with the high flux at shutdown alarm in bypass on April 30 Unit 2, 21 residual heat removal water hammer on May 8 Unit 2, 25 service water degraded pipe stanchion weld on April 24 Unit 2, 21 reactor coolant pump heavy lift and rigging on May 25 Unit 2, spent fuel pool 60 days undispersed (non B.5.b configuration) on June 10 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 determination 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 control RCS pressure in accordance with a procedure. Consequently, on April 13, 2014, this resulted in lifting a low temperature over-pressure protection valve during solid pressurizer operations. PSEG completed a prompt investigation, an apparent cause evaluation, and submitted a Special Report to the NRC in accordance with TS 6.9.2.

Description.

On April 12, 2014, PSEG shutdown Salem Unit 2 for its 20th refueling outage. Mode 4 was reached at 11:16 p.m. and over-pressure protection was established at 11:59 p.m. via the pressurizer power-operated relief valves. Mode 5 was reached at 1:37 a.m. the next day. At 6:20 a.m., PSEG operators commenced filling the pressurizer solid in accordance with S2.OP-IO.ZZ-0006, Hot Standby to Cold Shutdown, Revision 44. At 7:20 a.m., the pressurizer was water-solid with its pressure at about 310 psig. When the reactor operator (RO) turned the backup and control heaters off, pressurizer pressure began to slowly rise. At 7:55 a.m., using the charging/letdown flow mismatch, the RO attempted to control pressure by inappropriately adjusting 2CV18, letdown pressure control valve, in the closed direction (vice open). Specifically, while cooling down the pressurizer to match RCS temperature and support chemical addition for a crud burst, adjustments in pressure are accomplished using a pressure control valve in the letdown line. This resulted in lowering letdown flow with a resulting rise in RCS pressure. When the RO did not obtain the expected response, he adjusted 2CV18 in the closed direction twice more. At this point, he notified the control room supervisor (CRS) of rising pressure, a response contrary to his expectations. Through discussion, the operators determined that letdown flow should be raised. At around the same time, at 7:57 a.m., 2PR1, a pressurizer power-operated relief valve (PORV) momentarily actuated. At its peak, the charging to letdown mismatch was approximately 83.5 gpm and pressurizer relief tank level rose 0.5 gallons. Operators established a letdown flow of 100 gpm until pressure was stabilized.

PSEG completed a technical evaluation (70165208) that determined that the peak RCS pressure reached was 363.01 psig as compared to the TS limiting value of 375 psig, and the minimum pressure observed during the transient was 258 psig. Ten minutes after the pressure transient, operators received an alarm for the 24 RCP standpipe based on elevated seal leakage of 0.6 gpm. Differential pressure for RCP seals reached a minimum of 230 psig. Seal leakage returned to normal following operation of the lift oil pump, a break-away torque check, and pump run. PSEG attributed the leakage to the pressure transient. Other actions by PSEG included: 1) removing the RO and CRS from duty for post-event assessment and remediation; 2) completing a prompt investigation, an apparent cause evaluation, a site-wide communication, an Operations department standdown, and an Operations crew clock reset; 3) entering this item in the CAP as 20646740; and, 4) submitting Special Report 05000311/2014-04-00 to the NRC in accordance with TS 6.9.2. S2.OP-IO.ZZ-0006, step 5.1.50 states, When the pressurizer is water solid (steam bubble collapsed), slowly adjust charging OR letdown flowrate to stabilize RCP seal differential pressure 200 psig AND RCS pressure 340 psig. Contrary to this, the operator did not appropriately control RCS pressure to meet these requirements.

Analysis.

Non-compliance with an operating procedure was a performance deficiency that was more than minor because it was associated with the human performance attribute of the Barrier Integrity cornerstone, and 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 the procedure 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, Challenge the Unknown, in that individuals should stop when faced with uncertain conditions.

Specifically, a PSEG operator did not stop his activity after his first attempt to control pressure, communicate the unexpected RCS pressure response to supervision, and resolve the issue prior to resuming activities. (H.11)

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, covers general plant operating procedures and section 3 covers procedures for operation of safety-related PWR systems to include procedures for operation of PWR systems such as filling, draining, and changing modes of operation. S2.OP-IO.ZZ-0006, step 5.1.50 states, When the pressurizer is water solid (steam bubble collapsed), slowly adjust charging OR letdown flowrate to stabilize RCP seal differential pressure 200 psig AND RCS pressure 340 psig. Contrary to this, the operator did not appropriately control RCS pressure to meet these requirements. Consequently, on April 12, the low temperature overpressure setpoint was exceeded during a pressure transient. PSEG operators took immediate action to restore RCS pressure within procedural requirements. Because this finding was of very low safety significance, was entered into PSEGs CAP (20646740),and was not repetitive or willful, this violation is being treated as an NCV consistent with Section 2.3.2 of the NRCs Enforcement Policy. (05000311/2014-003-01, Inadequate Solid Pressurizer Control Resulted in Low Temperature Overpressure Relief Lifting)

1R18 Plant Modifications

Permanent Modifications

a. Inspection Scope

The inspectors evaluated modifications to a Unit 2 turbine-driven auxiliary feedwater (TDAFW) high energy line break damper, a Unit 1 & 2 auxiliary building ventilation pressure transmitter replacement, and a reduction in the frequency of Safeguards Equipment Control (SEC) Sequencer surveillance (SR 4.3.2.1.1.6.6) common to both units. The inspectors verified that the design bases, licensing bases, and performance capability of the affected systems were not degraded by the modification. In addition, the inspectors reviewed modification documents associated with the design change.

The inspectors reviewed selected post-installation or removal test results as appropriate to evaluate whether the actual impact of the change or removal had been adequately demonstrated by the test.

Unit 1, main generator phase C current transformer modification on April 16 Unit 2, shutdown margin procedure change on May 28 Unit 2, reactor coolant pump turning vane bolt modification on June 26

b. Findings

Introduction.

The inspectors determined there was a self-revealing, Green NCV of TS 6.8.1, Procedures and Programs, as described in Regulatory Guide 1.33, Revision 2, February 1978, when PSEG did not maintain procedure SC.RE-ST.ZZ-0002, Shutdown Margin Calculation, Revision 22, to cover certain mispositioned control rod events. This resulted in an unnecessary rapid boration, and a subsequent manual reactor trip, in response to a control rod drop event.

Description.

On January 16, 2014, PSEG implemented a procedure change to SC.RE-ST.ZZ-0002, Shutdown Margin Calculation, in response to a Westinghouse Technical Bulletin (TB) 13-5. The purpose of TB 13-5 was to recommend that applicable PWR stations increase the minimum required shutdown margin (SDM) in the event of an untrippable, or stuck, rod control cluster assembly (RCCA). Specifically, for a stuck RCCA (i.e., control rod) event where the stuck control rod is in close proximity to the highest worth control rod, simply doubling the highest control rod worth (typically referred to as the N-2 approach) may not provide sufficient SDM. In response to TB-13-5, PSEG performed a technical evaluation and concluded that for an untrippable control rod event, increasing the required SDM by 2000 per cent mille (pcm), in addition to the single stuck rod worth, would be bounding for all cases.

On January 31, 2014, during the performance of a monthly rod control surveillance, a power cable to control rod drive mechanism (CRDM) 1D2 experienced a short to ground while inserting control bank D fifteen steps. The short to ground caused a movable gripper fuse to open, and control rod 1D2 dropped from 220 to 166 steps. Operations entered Technical Specification (TS) 3.1.3.1.c for an inoperable control rod, which requires a power reduction to 75 percent within one hour, and compliance with SDM TS 3.1.1.1 within one hour. Operations did not have any indication that control rod 1D2 was untrippable due to excessive friction or mechanical interference, and therefore did not enter TS 3.1.3.1.a. Operations contacted reactor engineering to support performance of the SDM calculation. Operations commenced a load reduction and a boration, per the dropped rod procedure, to reduce reactor power. After 19 minutes of boration, the axial flux distribution (AFD) went outside of the TS-required target band, requiring entry into TS 3.2.1.a.2 and reactor power to be reduced below 50 percent within one hour and 30 minutes. Operations commenced additional boration, per the dropped rod procedure.

After an additional 16 minutes, the SDM was determined to be below the TS 3.1.1.1 limit, which required action to borate at a rate of at least 33 gallons per minute (gpm) until the required shutdown margin was restored. Reactor engineering determined that RCS boron concentration was required to be greater than 468 parts per million (ppm).

Operations entered the procedure for commencing rapid boration. After 50 minutes of rapid boration, operations manually tripped the reactor, in accordance with procedure, due to RCS average temperature (Tavg) approaching the minimum temperature for criticality. All the RCCAs fully inserted, therefore verifying control rod 1D2 was, in fact, trippable. After verifying that the reactor was shut down, operations stopped the rapid boration, and determined that a total of 2858 gallons of borated water was added to the RCS.

PSEG entered the SDM issue into the CAP and performed an Apparent Cause Evaluation (ACE) (20639085) to determine the cause of the unsatisfactory SDM that resulted in rapid boration and the manual reactor trip. PSEG determined that the apparent cause was attributed to ineffective change management for the SDM calculation procedure revision. Specifically, licensed operators perform and train on SDM calculations, but were not included in the SDM calculation procedure change review. HU-AA-1101, Change Management, revision 6, steps 4.2.4 and 4.3.1, required defining who was affected by the change, as well as screening the risk and complexity based on department or function impact. PSEG also determined that the SDM calculation procedure did not distinguish between inoperable (TS 3.1.3.1.c) and untrippable (TS 3.1.3.1.a) control rods. While there is no specific requirement to distinguish between inoperable and untrippable control rods in the SDM calculation procedure, the 2000 pcm penalty was over 1000 pcm greater than the single most reactive stuck rod worth at Salem Unit 2. PSEG determined that the 2000 pcm penalty for an inoperable control rod guaranteed an unsatisfactory SDM calculation for any inoperable rod at 100 percent rated thermal power past the middle of core life. PSEG reviewed the previous two years of licensed operator simulator training scenario guides, and determined that dropped or misaligned rod events are not followed through to completion before the next event occurs. PSEG determined that the training focus was on implementing the rod recovery procedure, but the effect on SDM of an inoperable rod was not typically discussed.

The inspectors reviewed operator actions in response to the rod drop event and reactor trip event on January 31, 2014, as well as PSEGs ACE associated with the unsatisfactory SDM. The inspectors determined that operators followed procedures and took appropriate actions during the event. PSEGs ACE determined that several corrective actions were required, including: revising the SDM calculation procedure to differentiate between untrippable, misaligned and dropped rods; adding guidance to determine the power level at which SDM would be achieved in the event of an unsatisfactory SDM; creating a dynamic learning activity with simulated procedure changes for reactor engineers to identify appropriate interface reviews; presenting classroom training to licensed operators to reinforce lessons learned from this event; revising licensed operator simulator scenarios to include response to an untrippable rod at high power levels; and evaluating the extent of condition of reactor engineering-driven procedure changes over the past two years to ensure adequacy. The inspectors determined that PSEGs corrective actions, both planned and completed, were reasonable.

Analysis.

The inspectors determined PSEGs failure to maintain procedure SC.RE-ST.ZZ-0002 to cover certain mispositioned control rod events constituted a performance deficiency. The finding was more than minor because it was associated with the Procedure Quality attribute of the Initiating Events cornerstone, and adversely affected the cornerstone objective to limit the likelihood of events that upset plant stability and challenge critical safety functions during shutdown as well as power operations. Specifically, the finding resulted in an unnecessary rapid boration, and a subsequent manual reactor trip, in response to a control rod drop event. Using IMC 0609, Attachment 4, Initial Characterization of Findings, and IMC 0609, Appendix A, The SDP for Findings At-Power, the inspectors determined that this finding was of very low safety significance (Green) because it did not cause 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 reactor engineering did not follow procedure HU-AA-1101, Change Management, when performing a procedure change in response to TB 13-5. Specifically, licensed operators perform and train on SDM calculations, but were not included in the SDM procedure change process as identified by PSEG in their ACE. [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 1.33, Revision 2, February 1978. Regulatory Guide 1.33, Section 6, Procedures for Combating Emergencies and Other Significant Events, subpart (l), includes procedures for mispositioned control rod (and rod drops). PSEG procedure SC.RE-ST.ZZ-0002, Shutdown Margin Calculation, Revision 22, step 4.11, required a shutdown margin calculation following a rod drop event on January 31, 2014. Contrary to the above, SC.RE-ST.ZZ-0002 was not properly maintained to cover mispositioned control rod events during a procedure change that was implemented on January 16, 2014.

Consequently, PSEG performed unnecessary rapid boration, and a subsequent manual reactor trip, in response to a control rod drop event on January 31, 2014. PSEG entered the SDM issue in the CAP under notification 20639068, and implemented compensatory measures for calculating shutdown margin while pursuing a permanent procedure revision through the CAP. On May 30, PSEG revised the SDM calculation procedure, following the completion of an ACE, to distinguish the SDM calculation for inoperable versus untrippable control rod events. Because this finding is of very low safety significance (Green), was entered into PSEGs CAP, and was not repetitive or willful, this violation is being treated as an NCV consistent with Section 2.3.2 of the NRCs Enforcement Policy. (NCV 05000272,311/2014003-02, Failure to Maintain Shutdown Margin Calculation Procedure to Cover Certain Mispositioned Control Rod Events).

1R19 Post-Maintenance Testing

a. Inspection Scope

The inspectors reviewed the post-maintenance tests for the maintenance activities listed below to verify that procedures and test activities ensured system operability and functional capability. The inspectors reviewed the test procedure to verify that the procedure adequately tested the safety functions that may have been affected by the maintenance activity, that the acceptance criteria in the procedure was consistent with the information in the applicable licensing basis and/or design basis documents, and that the procedure had been properly reviewed and approved. The inspectors also witnessed the test or reviewed test data to verify that the test results adequately demonstrated restoration of the affected safety functions.

Unit 1, 11 steam generator feed pump uninterruptable power supply replacement on April 9 Unit 1, main generator phase C current transformer repairs on April 16 Unit 1, 12 chiller repairs on May 16 Unit 2, A emergency diesel generator after eighteen month PM on April 2 Unit 2, service water back-up to auxiliary feedwater spectacle flange installation on April 30

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 three forced outages on Unit 1, which were conducted during the dates listed below. 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 outages, the inspectors observed portions of Mode 3 operations in Hot Standby, the reactor startup, and the power ascension and monitored controls associated with the following outage activities:

Unit 1, loss of one feedwater pump and reactor trip on April 8 through April 11 Unit 1, turbine trip and subsequent reactor trip on April 13 through April 18 Unit 1, turbine trip and subsequent reactor trip on May 7 through May 11 The inspectors reviewed the stations work schedule and outage risk plan for the Unit 2 maintenance and refueling outage (2R20), which was commenced on April 12 and was ongoing through the end of the inspection period. 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 technical specifications 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 technical specifications 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 technical specifications 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

No findings were identified.

1R22 Surveillance Testing

a. Inspection Scope

The inspectors observed performance of surveillance tests and/or reviewed test data of selected risk-significant SSCs to assess whether test results satisfied TSs, the UFSAR, and PSEG procedure requirements. The inspectors verified that test acceptance criteria were clear, tests demonstrated operational readiness and were consistent with design documentation, test instrumentation had current calibrations and the range and accuracy for the application, tests were performed as written, and applicable test prerequisites were satisfied. Upon test completion, the inspectors considered whether the test results supported that equipment was capable of performing the required safety functions. The inspectors reviewed the following surveillance tests:

Unit 2, steam generator safety valve, 21MS15, surveillance (IST) on April 8 Unit 2, safeguards equipment control mode operations testing - 2C vital bus on April 13 Unit 2, 21 containment spray pump full flow test on April 17 Unit 2, RCP seal water header primary containment isolation valve (PCIV) leak rate testing on April 18 Unit 2, primary relief tank gas analyzer valve leak rate testing (PCIV) on April 19 Unit 2, A emergency diesel generator surveillance on April 22 Unit 2, charging header isolation valve leak rate testing (PCIV) on April 25 Common, control room envelope pressure test on April 1

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 March 4, 2014, to identify any weaknesses and deficiencies in the classification, notification, and protective action recommendation development activities. Although the drill was observed in the previous inspection quarter, the inspection continued into the second quarter pending ongoing inspection activity of PSEG drill critique items. 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 corrective action program.

b. Findings

No findings were identified.

2RS1 Radiological Hazard Assessment and Exposure Controls

a. Inspection Scope

During the period of April 28 - May 2, and on May 14 and 23, 2014, the inspector reviewed PSEGs performance in assessing and controlling radiological hazards in the workplace. The review was against criteria contained in 10 CFR Part 20, TSs, applicable Regulatory Guides, and PSEG procedures.

In addition, the inspector reviewed an event that occurred on May 4, 2014, during which workers in the Salem Unit 2 Reactor Cavity were exposed to elevated, unexpected radiation dose rates during draining of the Unit 2 Fuel Transfer Canal.

That event is discussed in Section 4OA5.

Inspection Planning

The inspector reviewed radiation protection (RP) Performance Indicators, program audits, and reports of operational occurrences in occupational radiation safety since the last inspection.

Radiological Hazard Assessment The inspector reviewed the following aspects and associated documentation:

changes in radiological hazards for onsite workers or members of the public and potential impact of the changes conducted walk-downs and independent radiation measurements during the Unit 2 outage and reviewed survey documentation risk-significant work activities (e.g., Unit 2 outage work activities including pulling of Unit 2 reactor coolant pump internals)radiological surveys for on-going and completed radiological risk significant work work in potential airborne radioactivity areas and evaluation of air samples including continuous air monitoring monitoring of loose surface contamination in areas of the plant Instruction to Workers The inspector reviewed the following aspects and associated documentation:

labeling of radioactive material containers radiation work permits (RWP) used to access high radiation areas (HRA)use of permissible dose under RWPs, including electronic personal dosimeter (EPD)alarm set-points occurrences of EPD alarms communications to workers of radiological hazards interviewed radiation workers High Radiation Area briefing of workers for radiological work tasks Contamination and Radioactive Material Control The inspector reviewed the following aspects and associated documentation:

observed locations where material was monitored and released from the radiological controlled area and inspected methods used for control, survey, and release observed the performance of personnel surveying and releasing material for unrestricted use radiation monitoring instrumentation used for equipment and personnel release for adequate sensitivity for release and for alarm response Radiological Hazards Control and Work Coverage The inspector reviewed the following aspects and associated documentation:

radiological conditions and performed independent radiation measurements during walk-downs of the facility radiological controls, including: surveys, radiation protection job coverage, contamination controls, and use of EPDs in high noise areas airborne radioactivity monitoring and controls posting and physical controls for HRAs and LHRAs Risk-Significant HRA and Very High Radiation Area (VHRA) Controls The inspector reviewed the following aspects and associated documentation:

discussed with the Radiation Protection Manager (RPM) the controls and procedures for high-risk HRAs and VHRAs on-going work in HRAs Radiation Worker Performance and RP Technician Proficiency The inspector reviewed radiological problem reports since the last inspection.

Problem Identification and Resolution The inspector 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 licensees corrective action program. The inspector assessed the appropriateness of the corrective actions for problems that involve radiation monitoring and exposure controls. The inspector assessed the process for applying operating experience to their plant.

b. Findings

No findings were identified.

2RS2 Occupational ALARA Planning and Controls

a. Inspection Scope

During the period of April 28 - May 2, and on May 14 and 23, 2014, the inspector assessed performance with respect to maintaining occupational individual and collective radiation exposures as low as is reasonably achievable (ALARA). The inspector used the criteria in 10 CFR 20, applicable Regulatory Guides, TSs, and PSEG procedures for determining compliance

Inspection Planning

The inspector reviewed the following aspects and associated documentation:

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 changes in the radioactive source term, and site-specific procedures associated with maintaining occupational exposures ALARA Radiological Work Planning The inspector reviewed the following ALARA aspects and associated documentation:

on-going work activities and ALARA work activity evaluations, exposure estimates, and exposure reduction requirements use of dose reduction techniques; and estimated dose goals use of respiratory protective devices integration of ALARA requirements, including changes and updates, into work procedure and RWP documents (e.g., Unit 2 reactor disassembly, transfer canal work, insulation work, reactor coolant pump seal/motor change out, and reactor coolant pump internals pulling)

Verification of Dose Estimates and Exposure Tracking Systems The inspector reviewed the following aspects and associated documentation:

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 source term reduction and control licensee contingency plans for expected changes in the source term as the result of changes in plant fuel performance issues or changes in plant primary chemistry current 10 CFR 61 waste stream source term data Problem Identification and Resolution The inspector evaluated whether problems associated with ALARA planning and controls are being identified by the licensee at an appropriate threshold and were properly addressed for resolution in the licensees corrective action program. The inspector assessed the process for applying operating experience to their plant.

b. Findings

No findings were identified.

2RS3 In-Plant Airborne Radioactivity Control and Mitigation

a. Inspection Scope

During the period of April 28 - May 2, and on May 14 and 23, 2014, the inspectors reviewed controls for potential airborne radioactivity work and the use of respiratory protection devices. The inspectors used the criteria in 10 CFR Part 20, the guidance in applicable Regulatory Guides, TSs and PSEG procedures for determining compliance.

Inspection Planning

The inspectors reviewed the following aspects and associated documentation:

procedures for maintenance, inspection, use, and storage of non-emergency respiratory protection equipment performance indicators to identify any related to unintended dose resulting from intakes of radioactive material Engineering Controls The inspectors reviewed the use of permanent and temporary ventilation to minimize airborne radioactivity.

Use of Respiratory Protection Devices The inspectors reviewed the use of non-emergency respiratory protection devices, including ALARA dose reviews, use of certified equipment, and qualification of users.

Problem Identification and Resolution The inspectors evaluated whether problems associated with the control and mitigation of in-plant airborne radioactivity were being identified by PSEG at an appropriate threshold and were properly addressed for resolution in the licensee CAP.

b. Findings

No findings were identified.

2RS4 Occupational Dose Assessment

a. Inspection Scope

During the period of April 28 - May 2, and on May 14 and 23, 2014, the inspector reviewed the monitoring, assessment, and reporting of occupational dose. The inspector used the criteria in 10 CFR 20, applicable Regulatory Guides, TSs, and procedures for determining compliance.

Inspection Planning

The inspector reviewed radiation protection program audits, dosimeter occurrence reports, use of National Voluntary Laboratory Accreditation Program (NVLAP) certified dosimetry devices, and corrective action program documents.

Internal Dosimetry, Dose Assessment, Airborne Monitoring The inspector reviewed: procedures to assess dose from internally deposited radionuclides, including the release of contaminated individuals; portal radiation monitors used as a passive monitoring system; the program for dose assessment based on airborne monitoring and calculations of internal dose and associated documentation; and available whole body counts for cause.

Problem Identification and Resolution The inspector assessed whether problems associated with occupational dose assessment are being identified by PSEG at an appropriate threshold and were properly addressed for resolution in the licensee corrective action program.

b. Findings

No findings were identified.

2RS5 Radiation Monitoring Instrumentation

a. Inspection Scope

During the period of April 28 - May 2, and on May 4 and 23, 2014, the inspector reviewed the accuracy and operability of radiation monitoring instruments that were used to protect occupational workers. The review was against criteria contained in 10 CFR Part 20, applicable Regulatory Guides and industry standards, TSs, and PSEG station procedures for determining compliance.

Inspection Planning

The inspector reviewed the following aspects and associated documentation:

Updated FSAR to identify radiation instruments associated with monitoring area radiation, airborne radioactivity, process streams, effluents, materials/articles, workers, and post-accident monitoring 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 procedures that govern instrument source checks and calibrations Walkdowns and Observations The inspector reviewed portable survey instruments in use and assessed calibration and source check stickers for currency, as well as, instrument material condition and operability; and compared monitor response (via local readout) with actual area radiological conditions and independent radiation measurements.

Calibration and Check Sources The inspector reviewed the licensees source term or waste stream characterization per 10 CFR Part 61, Licensing Requirements for Land Disposal of Radioactive Waste, to assess whether calibration sources used were representative of the types and energies of radiation encountered in the plant.

Problem Identification and Resolution The inspector evaluated whether problems associated with radiation monitoring instrumentation were being identified by the licensee at an appropriate threshold and were properly addressed for resolution in the licensee corrective action program.

b. Findings

No findings were identified.

2RS6 Radioactive Gaseous and Liquid Effluent Treatment

a. Inspection Scope

During the period of April 28 - May 2, and on May 14, 2014, the inspector reviewed ground water contamination monitoring. The review was against criteria contained in 10 CFR Part 20, 10 CFR Part 50, 40 CFR 190, applicable Regulatory Guides and industry standards, TSs/Offsite Dose Calculation Manual (ODCM), and PSEG station procedures for determining compliance.

Procedures, Special Reports, and Other Documents The inspector reviewed available Licensee Event Reports, event reports and/or special reports related to the effluent program issued since the previous inspection.

Walkdowns and Observations The inspector reviewed the status and efficacy of ground water remediation efforts associated with Salem Unit 1.

Groundwater Protection Initiative (GPI) Implementation The inspector reviewed monitoring results of the voluntary Nuclear Energy Institute GPI and assessed whether PSEG has identified and addressed deficiencies through its corrective action program.

Problem Identification and Resolution The inspector assessed whether problems associated with the effluent monitoring and control program are being identified by the licensee at an appropriate threshold and are properly addressed for resolution in the licensee corrective action program. In addition, the inspector evaluated the appropriateness of the corrective actions for a selected sample of problems documented.

b. Findings

No findings were identified.

4OA1 Performance Indicator Verification

Complications (6 samples)

a. Inspection Scope

The inspectors reviewed PSEGs submittals for the following Initiating Events Cornerstone performance indicators for the period of July 1, 2013, through March 31, 2014.

Units 1 and 2 Unplanned Scrams per 7000 Critical Hours, IE01 Units 1 and 2 Unplanned Power Changes per 7000 Critical Hours, IE03 Units 1 and 2 Unplanned Scrams with Complications, IE04 To determine the accuracy of the performance indicator data reported during those periods, inspectors used definitions and guidance contained in Nuclear Energy Institute (NEI) Document 99-02, Regulatory Assessment Performance Indicator Guideline, Revision 7. The inspectors reviewed PSEGs operator narrative logs, maintenance planning schedules, condition reports, event reports, and NRC integrated inspection reports to validate the accuracy of the submittals.

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 IP 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 Semi-Annual Trend Review

a. Inspection Scope

The inspectors performed a semi-annual review of site issues, as required by Inspection Procedure 71152, Problem Identification and Resolution, to identify trends that might indicate the existence of more significant safety issues. In this review, the inspectors included repetitive or closely-related issues that may have been documented by PSEG outside of the corrective action program, 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 corrective action program database for the first and second quarters of 2014 to assess notifications written in various subject areas (equipment problems, human performance issues, etc.), as well as individual issues identified during the NRCs daily condition report review (Section 4OA2.1). The inspectors reviewed PSEGs quarterly trend reports for the first through second quarters of 2014, conducted under LS-AA-125, to verify that PSEG personnel were appropriately evaluating and trending adverse conditions in accordance with applicable procedures.

b. Findings and Observations

No findings were identified.

The inspectors determined that any performance deficiencies associated with the four trends discussed below were captured in previous findings (as noted below), or were of minor significance in accordance with IMC 0612, Appendix B.

Maintenance Rule The inspectors identified multiple issues associated with PSEGs implementation of the Maintenance Rule program. The examples highlighted two areas of the program scope:

identification and evaluation of functional failures, and subsequent monitoring of (a)(1)systems to provide reasonable assurance of performing their specified functions.

Specific examples include:

In January 2014, the inspectors challenged PSEGs determination of no functional failure for the Unit 2 main generator bus duct cooling fan belt failure in November 2013, which resulted in an unplanned downpower to 55 percent power. PSEG reclassified this issue as a functional failure and entered this in their CAP.

(20638061)

PSEG completed a WGE in January 2014, in response to the inspectors challenging PSEGs determination that there were no functional failures associated with reactor trip breaker test issues, as well as a challenge to the reactor trip breaker (a)(2) performance criteria. This issue was documented in URI

===05000272/2013005-02. PSEG took actions to reevaluate the equipment issues and adjust the performance criteria. (20634111)

The inspectors identified that PSEG had not established appropriate (a)(1)performance goals for the Unit 1 #13 charging pump, as documented in NCV 05000272/2014002-005. (20636958)

The inspectors identified that despite Salem Unit 3, a gas turbine generator, being monitored under (a)(1), it did not have a reliability goal, which is contrary to a station procedure. Despite this, the system had not exceeded reasonable reliability goals.

PSEG entered this in their CAP and created a reliability goal. (20656508)

Risk Assessment The inspectors noted multiple issues, both NRC and PSEG-identified, associated with risk screening of work activities. Specific examples include:

The inspectors identified an inadequate risk assessment during a period of adverse grid conditions on January 6, 2014, as documented in NCV 05000272;311/2014002-02. (20635632)

The inspectors identified an inadequate risk assessment prior to 4 kV vital bus undervoltage surveillance testing on February 13, 2014, as documented in NCV 05000311/2014002-03. (20640080)

In April 2014, during 2R20, PSEG Nuclear Oversight identified 2,668 Unit 2 outage risk activities (out of approximately 20,000 scheduled) that were not screened for risk in accordance with a procedure. PSEG initiated notification 20646970, completed the appropriate risk screenings, and performed a work group evaluation (WGE) to analyze the issue and take corrective actions as appropriate.

Additionally, in February 2014, the same department had identified another 25 activities without an appropriate risk screening completed.

Equipment Reliability PSEG developed a 2014 station focus area and Performance Improvement Action Plan to address their concerns with equipment reliability. PSEG initiated a 2014 Performance Improvement Action Plan in the area of Equipment Reliability. The plan includes an action to conduct a common cause evaluation (70159882) presently due to be completed in August 2014. The inspectors noted the following recent challenges related to equipment reliability:

January 31, 2014 - Unit 2 manual reactor trip following rod control cable failure, partial control rod drop, subsequent emergency boration and lowering of reactor coolant system average temperature Tavg. (EQACE 70153348)

February 13, 2014 - Unit 2 Notice of Enforcement Discretion request following removal of the 24 station power transformer from service due to elevated gassing levels. (EQACE 70163632)

In February 2014, PSEG identified a high number of preventive maintenance deferrals that did not receive the appropriate level of review per procedure.

(20641638)

April 8, 2014 - Unit 1 manual reactor trip on low steam generator level following the loss of one feedpump due to a turbine speed control circuit failure. (Root Cause Evaluation [RCE] 70165169)

April 13 and May 7, 2014 - Two Unit 1 automatic trips following main generator current transformer field wiring connection failures. (RCE 70165317)

May 12, 2014 - Salem extended the refueling and maintenance outage 2R20 to perform repairs on the turning vane bolts of its four reactor coolant pumps, after a total of 17 bolt heads had been discovered in the RCS over the past three refueling outages. (RCE 70167382)

In June 2014, Salem identified a negative trend on their performance metric associated with unplanned LCO entries per station TSs. (20652036)

Radiation Monitors PSEG identified an adverse trend of radiation monitor equipment failures, as evident by a common cause evaluation on radiation monitor failures (70162556). The inspectors noted, however, that PSEG had previous opportunities to identify this trend.

Inspectors raised concerns regarding Salem radiation monitor performance late in the 3rd quarter of 2013. At the time, inspectors requested any CAP items that identified the radiation monitors as a potential adverse trend. While PSEG did not have examples, a monitoring plan was provided. The inspectors continued to observe equipment challenges in this area throughout the 4th quarter of 2013 and 1st quarter of 2014. On January 9, 2014, PSEG entered notification 20635706 in the CAP to initiate a common cause evaluation (CCE) on radiation monitor failures. The CCE was completed February 28, 2014, with multiple corrective actions due to be completed later this year.

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

a. Inspection Scope

The inspectors performed an in-depth review of PSEGs evaluations, extent of condition (EOC) reviews and corrective actions associated with issues related to degraded RCP turning vane bolts (TVB). These TVBs are susceptible to intergranular stress corrosion cracking (IGSCC), resulting in separation of the bolt head from the shank. This issue was captured in PSEG Notification 20647694.

The inspectors assessed PSEGs problem identification threshold, EOC reviews, compensatory actions, and the prioritization and timeliness of PSEGs corrective actions to determine whether PSEG was appropriately identifying, characterizing, and correcting problems associated with this issue, and whether the planned and completed corrective actions were appropriate. The inspectors compared the actions taken to the require-ments of PSEGs CAP and 10 CFR 50, Appendix B. In addition, the inspectors interviewed engineering and operations personnel to assess the effectiveness of the implemented corrective actions.

b. Finding

Introduction.

The inspectors identified an Unresolved Item (URI) concerning the repetitive failures of RCP TVBs.

Description.

The inspectors performed an in-depth review of PSEGs evaluation and corrective actions associated with continued failures of RCP TVBs. The RCPs at Salem Unit 2 are model 93A supplied by Westinghouse. The turning vane is attached to the thermal barrier, internal to the pump, by twenty 1.0 inch diameter bolts fabricated from alloy A286. This material is susceptible to IGSCC as identified by Westinghouse in technical bulletin NSD-TB-94-06-R0, issued on August 11, 1994. Since refueling outage

2R18 in 2011, a total of seventeen TVB heads have been discovered in the reactor

coolant system. The issue was originally evaluated during refueling outage 2R18, when two separated bolt heads were identified in April 2011, under order number 70123042 and determined not to have an adverse effect on RCP operations. During refueling outage 2R19, five additional loose TVB heads were found in the reactor coolant system.

The licensee again communicated with Westinghouse and evaluated the condition as documented in order 70144776. The 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. Additionally, during refueling outage 2R20, more loose turning bolt heads were discovered as documented in notification 20647694.

The NRC inspector reviewed this notification and previous evaluations and questioned the basis for acceptability of contact between stationary and rotating components.

The licensee conducted additional reviews in coordination with Westinghouse and documented in OTDM S-14-003, that in the event of a failure of the turning vane assembly, it was possible for machining between the rotating and stationary parts to occur. Based on this information, the licensee 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) was identified because additional NRC review and evaluation is needed to determine if the issue is more than minor and whether the issue of concern constitutes a violation. The inspectors will review PSEGs evaluation and causal analysis of the as-found condition and the impact on safety components and accident analysis upon its completion. (URI 05000311/2014003-03, Repetitive Failures of Reactor Coolant Pump Turning Vane Bolts)

.4 Annual Sample: Cable Vault Flooding

a. Inspection Scope

The inspectors performed an in-depth review of PSEG's evaluations and corrective actions associated with submerged 4kV and 13kV medium voltage cables in manholes/vaults. The inspection scope was focused on Technical Specification-required off-site power supply cables to vital 4kV buses, which are also monitored under the scope of the maintenance rule. The inspectors reviewed multiple notifications, tan-delta testing results, licensee renewal commitments, engineering evaluations, and the electrical manhole/vault water removal plan for the 4kV and 13kV manholes/vaults.

The inspectors assessed PSEGs problem identification threshold, problem analysis, extent of condition reviews, compensatory actions, and the prioritization and timeliness of PSEG's corrective actions to determine whether PSEG was appropriately identifying, characterizing, and correcting problems associated with this issue and whether the planned or completed corrective actions were appropriate. The inspectors compared the actions taken to the requirements of PSEG's corrective action program and 10 CFR 50, Appendix B, Criterion XVI, Corrective Action.

b. Findings and Observations

No findings were identified.

The inspectors identified a minor performance deficiency because PSEG did not initiate corrective actions to ensure electrical manholes/vaults are kept clear of water that could submerge cables, in accordance with section 5.6.1 of ER-AA-3003, Cable Condition Monitoring and Aging Management Program. Specifically, the previous 3 preventative maintenances (PMs) activities on the 4kV and 13kV cable manholes discovered that the cables continue to become submerged in water. Additionally, historical as-found PM results indicated repetitive submerged cable conditions. The inspectors noted that PSEG wrote notification 20641554 in February 2014, to capture an NRC-identified issue where as-found manhole conditions with submerged 4kV and 13kV cables were not consistently being documented in notifications as required under work order instructions.

The inspectors noted that during this inspection sample, PSEG took appropriate actions to identify cables submerged in water, pumped out the manholes of excess water, and wrote a notification for the as-found condition of each manhole. The inspectors also noted that PSEG engineering was performing trending of the as-found cable manhole/vault conditions (e.g. submerged, dry, etc.).

On June 4, 2014, the inspectors observed PSEG performance of 13kV manhole PMs in the switchyard. Of the eight 13kV manholes in the switchyard, the inspectors observed the cables in all the manholes were submerged in water; PSEG subsequently pumped out the water from these manholes. PSEG wrote notifications, in accordance with work order instructions, to document the as-found condition of the submerged cables. The inspectors reviewed each notification, and noted that PSEG Operations screened the submerged cables as operable.

In August 2010, PSEG issued ER-AA-3003, Cable Condition Monitoring and Aging Management Program. This was a result of a self-assessment and review of INPO EPG-16, Electric Cable Reliability, in which PSEG determined that a medium and low voltage power cable monitoring program was required. ER-AA-3003 requires action to be taken for cables subject to adverse conditions. Step 5.6.1.1 requires, in part, performance of periodic inspections of ducts, manholes and vaults to ensure cables are kept clear of water that could submerge cables. Additionally, step 5.6.1.2 requires that cables subjected to long-term wetting should be assessed for material condition. PSEG accessed the condition of the submerged cables by performing tan-delta testing and performing quarterly and monthly inspections on the 4kV and 13kV manholes/vaults.

Also, as part of License Renewal commitments, PSEG has approved a long term asset management (LTAM) action S-12-0118 to install drains and/or sump pumps and level indication for all cable manholes/vaults prior to the period of extended operation for both units. The inspectors noted that PSEG wrote notification 20653921, in June 2014, to capture an NRC-identified issue where corrective actions were not being taken to address submerged cables in accordance with ER-AA-3003, step 5.6.1.1. As a result of notification 20653921, PSEG created long-term corrective action (LTCA) order 70167049, activity 70, to track LTAM S-12-0118 in the CAP.

The inspectors determined there was a performance deficiency because PSEG did not take action in accordance with ER-AA-3003, step 5.6.1.1, to ensure that cables were being kept clear of water that could cause submergence. The inspectors determined this performance deficiency was of minor safety significance, in accordance with IMC 0612, Appendix B, because it did not impact any cornerstone objective. Specifically, PSEG was performing tan-delta testing to assess the condition of the cables, in accordance with ER-AA-3003, step 5.6.1.2. Additionally, the inspectors noted that testing results to date have been satisfactory. The inspectors also noted that PSEG was appropriately following their PM process of inspecting and pumping out manholes, and also noted that no safety-related cables were found submerged since PSEG implemented the manhole PM inspections. Therefore, the inspectors concluded the PSEG technical assessment of this issue was appropriate and the actions taken or planned were commensurate with the safety significance.

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

.1 Plant Events

a. Inspection Scope

For the plant events listed below, the inspectors reviewed and/or observed plant parameters, reviewed personnel performance, and evaluated performance of mitigating systems. The inspectors communicated the plant events to appropriate regional personnel, and compared the event details with criteria contained in IMC 0309, Reactive Inspection Decision Basis for Reactors, for consideration of potential reactive inspection activities. As applicable, the inspectors verified that PSEG made appropriate emergency classification assessments and properly reported the event in accordance with 10 CFR 50.72. The inspectors reviewed PSEGs follow-up actions related to the events to assure that PSEG implemented appropriate corrective actions commensurate with their safety significance.

Unit 1, manual reactor trip due to lowering steam generator water level following the loss of one feedwater pump on April 8, 2014 Unit 1, automatic reactor trip, due to a turbine trip attributed to a failed connection in the C phase of the main generator protection logic on April 13, 2014 Unit 1, automatically tripped due to a failed connection in the A phase of the main generator protection logic, on May 7, 2014

b. Findings

No findings were identified.

.2 (Closed) Licensee Event Report (LER) 05000311/2014-001-00: High Energy Line Break

Door Blocked Open During Maintenance Activity

a. Inspection Scope

On October 3, 2013, PSEG maintenance workers were working on a HELB damper in the Unit 2, 23 Turbine Driven Auxiliary Feedwater (TDAFW) pump enclosure, when the inspectors observed that the enclosure HELB barrier door was opened for an extended period of time with a dedicated door attendant as a compensatory measure to support AFW system operability. Additionally, the inspectors determined that welding cables had been run through the door to support planned maintenance activities. The inspectors questioned this practice and requested that Salem provide the basis for this compensatory measure. PSEG reviews could not provide sufficient bases to indicate that a designated door attendant would be a sufficient compensatory measure to ensure operability of the adjacent motor driven auxiliary feedwater (MDAFW) pumps while the TDAFW pump enclosure door was open with high pressure steam supplied to the piping inside the enclosure.

On January 7, 2014, PSEG determined that the control of the HELB door to the 23 TDAFW pump enclosure did not ensure the operability of the MDAFW pumps. Once this determination had been made, an 8-hour event report was required pursuant to 10 CFR 50. 72(b)(3)(ii)(B) as "the nuclear power plant being in an unanalyzed condition that significantly degrades plant safety." PSEG submitted this LER within 60 days of the January 7 determination, in accordance with 10 CFR 50.73.

b. Findings

No findings were identified.

The enforcement aspects of this LER are discussed in NCV 2013005-03. The inspectors did not identify any new issues during the review of the LER. This LER is closed.

.3 Reactor Coolant Pump Bolt Head Recovery Event Follow-up

a. Inspection Scope

On May 4, 2014, PSEG was in the process of draining the Unit 2 spent fuel transfer canal located within the Unit 2 Containment. At the same time, two workers entered the upper elevation of the Unit 2 reactor cavity about 3:15 am to conduct work. The workers remained in the area for a short period of time and subsequently exited the radiological controlled area. When they signed off their RWP, the workers received indications that they had received elevated radiation dose rate alarms. Subsequent PSEG reviews indicated the workers had worked in elevated radiation dose rates in the Unit 2 reactor cavity caused by loss of water shielding over radioactive components located in the nearby Unit 2 spent fuel transfer canal.

The inspector reviewed the following aspects:

reportability radiation doses received by the workers potential radiation dose to the workers conformance with applicable radiation protection program procedures adequacy and effectiveness of applied radiological controls corrective actions The review was against criteria contained in 10 CFR Part 20, applicable Regulatory Guides and industry standards, TSs, and PSEG station procedures for determining compliance.

b. Findings and Observations

Introduction:

The inspectors identified a self-revealing NCV of very low safety significance associated with the failure to establish and implement adequate radiological controls for the transfer and control of radioactive material within the Unit 2 fuel transfer canal, and subsequent work performed on reactor vessel level instrumentation in the Unit 2 upper reactor cavity. Specifically, PSEG did not conduct necessary and reasonable surveys required by 10 CFR 20.1501 to detect radiation levels emanating from the fuel transfer canal on May 4, 2014. Further, on May 4, PSEG also did not provide sufficient high radiation area dose rate monitoring required by TS 6.12.1 to identify that workers were encountering increasing radiation dose rates. Finally, PSEG did not inform workers of the storage and transfer of radioactive material, required by 10 CFR 19.12(a), prior to performing work in the field on May 4.

Description:

On April 26, 2014, PSEG identified six reactor coolant pump turning vane bolts inside the Unit 2 reactor vessel on the lower core plate during an internal reactor vessel inspection. Those bolts were recovered and transferred under water to the lower Unit 2 reactor cavity (94 foot elevation) and stored within a bucket. On April 27, 2014, the bolts were supposed to be transferred to a debris canister for subsequent transfer to the Unit 2 spent fuel pool. Unknown to PSEG, five of the bolts were not transferred due to error or spillage of the bolts to the floor of the Unit 2 fuel transfer canal (90 foot elevation). The bolts were radioactive with elevated contact radiation dose rates (estimated at 11,000 R/hr on a bolt). On May 3, 2014, PSEG commenced drain down of the reactor cavity in preparation for decontamination of the lower cavity as well as installation of the Unit 2 fuel transfer tube blank flange unaware that the bolts remained.

On May 4, 2014, PSEG was draining down the Unit 2 fuel transfer canal, located in the Unit 2 reactor cavity, in preparation for blank flange installation. PSEG had established TS 6.12, HRA Controls, (including posting the upper cavity as a HRA), for personnel entry to the Unit 2 upper reactor cavity (104 foot elevation) and had allowed two workers to enter the upper reactor cavity to conduct work on reactor vessel level instrumentation.

The lower Unit 2 reactor cavity, as well as the Unit 2 fuel transfer canal area were posted and controlled as TS 6.12 Locked High Radiation Areas (LHRA). The workers were provided access control briefings and electronic personnel dosimeters (EPDs) to alarm at an accumulated radiation dose of 50 millirem or a radiation dose rate of 200 mR/hr.

Unknown to the workers, PSEG continued to drain water from the nearby Unit 2 fuel transfer canal causing the radioactive material (reactor coolant pump turning vane bolts and a known in-core detector fragment) to lose shielding as the water was drained (approximately 4 - 6 inches of water remaining as estimated). The draining of the water resulted in elevated radiation dose rates in the upper cavity work areas including areas traversed by the workers as they entered and exited the reactor cavity as well as areas on the 130 foot elevation of the Unit 2 containment.

Due to the arrangement of portable reactor cavity radiation monitors, and the de-mobilization of equipment as the outage was ending, no portable or installed radiation monitors detected the increase in ambient radiation dose rates. PSEG had de-mobilized the real-time radiation monitors normally positioned on the manipulator bridge resulting in the inability to promptly detect increasing radiation levels to accessible areas of the manipulator bridge and the associated necessity to post and control the High Radiation Area caused by the increased radiation levels (estimated measured radiation dose rates approximately 300 - 400 mR/hr). Further, despite the on-going draining of the fuel transfer canal, the recent cutting of in-core detectors, as well as the transfer of radioactive materials to the fuel transfer canal, there was no active, adequate radiation protection job coverage of the work at that time to promptly detect potential radiation dose rate increases as the water was drained from over the radioactive materials. In addition, although the workers had been issued alarming dosimeters, the alarms on the dosimeters were not heard (audible) due, in part, to the use of air powered face shields by the workers. The EPD of one worker did alarm for short periods but did not lock in an alarm. The EPD of the second worker did go into alarm condition for about 1 minute but that worker did not hear the EPD alarm. PSEG subsequently determined both EPDs were working properly.

Unaware of the alarms, the workers left the area and exited the radiological controlled area. Radiation protection personnel on the Unit 2 refueling floor were unaware of the condition. Upon logging out of the radiological controlled area outside containment, the workers became aware that they had received elevated radiation dose rate alarms. The identification of the alarms caused subsequent notification of radiation protection personnel. One workers dosimeter indicated a dose rate of 579 mR/hr had been entered while the second workers EPD indicated a radiation dose rate of 377 mR/hr had been entered (both readings with EPD bias correction applied). The workers had been briefed to expect radiation dose rates less than about 30 mR/hr in the work areas. The workers were restricted from further RCA access pending evaluations of the cause of the alarms and potential dose.

RP personnel, unaware of the EPD alarm, conducted a general area survey of the refueling floor after the workers exited but no elevated radiation dose rates were identified. This survey did not include the area around the reactor cavity or the manipulator crane despite on-going cavity draining. Shortly thereafter, in response to the dose rate alarms, a more detailed survey of the refueling floor and reactor cavity area resulted in the identification of the elevated radiation dose rates. PSEG restricted access to the areas and also re-posted the access (stairwell) to the upper reactor cavity as a LHRA. PSEG also posted and controlled areas within the personnel barriers (hand rails) around the reactor cavity and manipulator crane on the refueling floor as a HRA.

PSEG determined that sometime between the initial pre-job surveys and about 4:00 am that morning (May 4, 2014) when discovered, the manipulator crane area on the refuel floor elevation had become a HRA. PSEG also reviewed reportability and did not identify a need to provide a formal report to the NRC as regards to this matter.

Subsequent PSEG radiation surveys detected the presence of radioactive debris (reactor coolant pump turning vane bolts and the known in-core instrument fragment) in the refueling transfer canal which caused the elevated radiation levels. PSEG believed the material produced a collimated radiation field due to the walls of the fuel transfer canal acting to partially shield the spread of the radiation.

The elevated radiation dose rates did not exist for a significant time period in that pre-work surveys (conducted 10:30 p.m. May 3, 2014) did not indicate significant dose rates.

PSEG conducted far-field gamma spectroscopy analysis of the irradiated hardware and also calculated bounding radiation dose rates the workers may have been exposed to had all the water been drained out of the transfer canal. PSEG determined estimated radioactive (curie) content for the materials for these analyses. PSEG determined the workers did not sustain significant radiation exposure and were not likely to have experienced substantial exposure due to available radiation source strength, distance from source and access controls in place. PSEG determined no additional individuals entered the area in that RP technicians maintained positive control of the upper reactor cavity entrance from the refueling floor. No personnel gained unauthorized access to the reactor cavity or the manipulator bridge. In addition PSEG also reviewed possible drain paths from the transfer canal and potential radiation dose rates in the event debris entered these paths. PSEG did not identify significant exposure potential.

PSEG determined the origin of the bolts was loss of control of them during attempted loading and transfer of them into a bucket for transfer to the Unit 2 spent fuel pool for storage on April 27, 2014. The bolts had originally been transferred to the fuel transfer canal for movement to the Unit 2 spent fuel pool. The work plan and procedures for the transfer did not provide adequate guidance in regards to verifying successful transfer of the materials. The ALARA Plan (#2014-29) specified, in additional guidance, to ensure communication and knowledge of exact placement/location of debris. Further, radiation surveys, conducted following the transfer, were inadequate and did not identify the radioactive material. Upon identification of this radiation concern, PSEG implemented appropriate controls of the affected areas and initiated additional radiation surveys and controls for the sources of the radiation.

Analysis:

PSEG did not establish and implement adequate radiological controls for the transfer and control of radioactive material within the Unit 2 fuel transfer canal and subsequent work performed on reactor vessel level instrumentation in the Unit 2 upper reactor cavity on May 4, 2014, to provide for the prompt identification and occupational exposure control of elevated radiation dose rates caused by radiation emanating from the radioactive material. 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 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 health and safety from exposure to radiation from radioactive material during routine reactor operation. PSEG did not implement adequate radiological controls to ensure prompt identification and control of elevated radiation dose rates to workers. The finding was assessed using IMC 0609, Appendix C, 2 Enclosure Occupational Radiation Safety SDP, dated August 19, 2008, 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 the licensee's ability to assess dose.

This finding was associated with the Work Management aspect of the Human Performance cross-cutting area. Specifically, PSEG did not implement adequate planning, control and execution of work activities associated with transfer of radioactive material to ensure the identification and management of worker radiological risk commensurate to the work such that nuclear safety was an overriding priority. [H.5]

Enforcement:

PSEG did not establish and implement adequate radiological controls for the transfer and control of radioactive material within the Unit 2 fuel transfer canal and subsequent work performed on reactor vessel level instrumentation in the Unit 2 upper reactor cavity on May 4, 2014, to provide for the prompt identification and occupational exposure control of elevated radiation dose rates caused by radiation emanating from the radioactive material. Specifically, the following violations of NRC requirements were identified to be associated with this green finding:

1. 10 CFR 20.1501 requires, in part, that licensees make surveys that may be

necessary to comply with the regulations in Part 20 and are reasonable under the circumstances to evaluate the magnitude and extent of radiation levels and the potential radiological hazards. Pursuant to 10 CFR 20.1003, survey means an evaluation of the radiological conditions and potential hazards incident to the production, use, transfer, release, disposal or presence of radioactive material or other sources of radiation.

Contrary to the above, on May 4, 2014, PSEG did not conduct necessary and reasonable surveys to detect the presence of elevated radiation dose rates emanating from radioactive material (irradiated reactor coolant turning vane bolts) as workers entered and worked in the Unit 2 upper reactor cavity. As a result, the workers were unknowingly exposed to elevated radiation dose rates.

2. TS 6.12.1 requires, in part, that for High Radiation Areas with dose rates not

exceeding 1.0 rem/hour at 30 centimeters from the radiation source or from any surface penetrated by the radiation, each individual or group entering such an area shall possess, among other options, a radiation monitoring device that continuously displays radiation dose rates in the area; or a radiation monitoring device that continuously integrates the radiation dose rates in the area and alarms when the device's dose alarm set point is reached, with an appropriate alarm set point.

Contrary to the above, on May 4, 2014, workers unknowingly entering a High Radiation Area in the Unit 2 reactor cavity did not possess a radiation monitoring device that continuously displayed radiation dose rates in the area and did not possess alarming self-reading dosimeters capable of being heard under working conditions therein. Further, no other active radiation monitoring of the workers ambient radiation conditions, in their work area was conducted. Consequently, PSEG did not provide sufficient radiation dose rate monitoring and High Radiation Area access controls to identify that workers entering the Unit 2 upper reactor cavity, were encountering increasing radiation dose rates that could have impacted personnel exposure.

3. 10 CFR 19.12(a) requires, in part, that all individuals who in the course of

employment are likely to receive in a year an occupational dose in excess of 100 mrem shall be kept informed of the storage, transfer, or use of radiation and/or radioactive material.

Contrary to the above, on May 4, 2014, individuals who in the course of employment were likely to receive in a year an occupational dose in excess of 100 mrem were not kept informed of the storage, transfer, or use of radiation and/or radioactive material.

Specifically, workers in the Unit 2 upper reactor cavity experienced dose rate alarms on their personal dosimeters that were caused by the lowering of water over irradiated bolts that were located in the Unit 2 transfer canal. Because the workers could not hear the alarms, and because their work area and pathway dose rates were not adequately monitored, the workers were not informed of the storage of this material and the impact on their personal exposure as a result of the lowering of water levels. Further, the workers were not informed that the Unit 2 fuel transfer cavity was being drained prior to their entry into the upper cavity.

Upon identification of the radiation concern PSEG implemented appropriate controls of the affected areas and initiated additional radiation surveys and controls for the sources of the radiation. The violation did not have any actual or any substantial potential for exceeding the occupational exposure limits since the workers promptly exited the area and no significant radiation exposure was sustained by the workers. This violation is being treated as an NCV, consistent with Section 2.3.2 of the Enforcement Policy. The violation was entered into the licensees CAP (Notification 20582871, 20649575, 20649581). (NCV 05000311/2014003-0X; Failure to establish and implement adequate radiological controls)

4OA5 Other Activities

.1 Ground Water Monitoring Program

a. Inspection Scope

During the period of April 28 - May 2, and on May 14 and 23, 2014, the inspectors reviewed the current results of PSEGs ground water monitoring program. This included PSEGs on-going evaluations associated with the identification of tritium contamination in a new well (AA-V) placed in the Vincentown formation. This matter had been previously discussed in IR 05000272,311/2013004 (ML13323A526).

The inspectors reviewed: on-going evaluations; ground water flow measurements; supplemental public dose projections; remediation efforts and minimization of existing contamination; possible sources of contamination; and groundwater characterization.

The inspectors reviewed PSEG sample results relative to the PSEG Ground Water Monitoring Program and NEI-07-07, Industry Ground Water Protection Initiative. The inspectors also reviewed PSEG sampling results for Salem Unit 1 and Unit 2 seismic gap drains.

b. Findings and Observations

No findings were identified.

At the time of inspection, PSEG was continuing to evaluate the possible causes and sources of tritium within well AA-V. PSEG was evaluating the need for additional wells to support characterization of subsurface contamination and was also evaluating possible enhancements to existing remediation processes as well as contamination control and minimization.

PSEG installed the new well to provide additional data for evaluation to supplement the currently existing four wells within that formation. PSEG conducted additional dose projections and concluded that the onsite tritium ground water contamination did not result in any impact on public doses. The inspectors will continue to follow resolution of the cause of the tritium in well AA-V, and PSEGs review of concentrations of radioactivity in seismic gap drains including causes and actions.

=

a. Inspection Scope

The licensees buried piping and underground piping and tanks program was inspected in accordance with paragraph 03.02.a of the Temporary Instruction (TI), and it was confirmed that activities which correspond to completion dates specified in the program which have passed since the Phase 1 inspection was conducted, have been completed.

Additionally, the licensees buried piping and underground piping and tanks program was inspected in accordance with paragraph 03.02.b of the TI, and responses to specific questions found in http://www.nrc.gov/reactors/operating/ops-experience/buried-pipe-ti-phase-2-insp-req-2011-11-16.pdf were submitted to the NRC headquarters staff.

b. Findings

No findings were identified.

4OA6 Meetings, Including Exit

On July 17, the inspectors presented the inspection results to Mr. John Garecht, Salem Work Management Director, and other members of the PSEG staff. The inspectors verified that no proprietary information was retained by the inspectors or documented in this report.

ATTACHMENT:

SUPPLEMENTARY INFORMATION

KEY POINTS OF CONTACT

Licensee Personnel

J. Perry, Site Vice President

L. Wagner, Plant Manager, Salem

M. Bacca, Dosimetry Supervisor

C. Banner, Emergency Preparedness Station Manager

D. Best, Nuclear Specialist, Engineering

T. Cachaza, Regulatory Assurance

K. Chambliss, Regulatory Assurance Manager

L. Clark, Instrument Supervisor

A. Crampton, Senior Reactor Operator

C. Dahms, Regulatory Assurance

B. Daly, Nuclear Environmental Affairs, Sustainability Manager

M. Davis, Reactor Operator

R. DeNight Jr., Operations Director

J. Garecht, Manager, Work Management Director, Acting Plant Manager

F. Grenier, Chemistry/RP Instructor

A. Johns, Radiation Protection Supervisor

L. Kern, Assistant Engineering Director

K. King, Regulatory Assurance

A. Kraus, Manager, Nuclear Environmental Affairs

D. LaFleur, Regulatory Assurance

T. Mulholland, Senior Reactor Operator

J. Palombo, Maintenance Supervisor

M. Pyle, Chemistry Manager

J. Stead, Senior Plant Engineer

S. Swenson, Senior Manager Plant Engineering

S. Taylor, Radiation Protection Manager

S. Thomassen, Emergency Preparedness Manager - Salem

Others

J. Vouglitois, Nuclear Engineer NJ Department of Environmental Protection

Bureau of Nuclear Engineering

LIST OF ITEMS OPENED, CLOSED, DISCUSSED, AND UPDATED

Opened/Closed

05000311/2014003-01 NCV Inadequate Solid Pressurizer Control Resulted in Low Temperature Overpressure Relief Lifting (Section 1R15)

05000311/2014003-02 NCV Failure to Maintain Shutdown Margin Calculation Procedure to Cover Certain Mispositioned Control Rod Events (Section 1R18)

05000311/2014003-04 NCV Failure to Establish and Implement Adequate Radiation Protection Procedures (Section 4OA3)

Opened

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

Closed

05000311/2014001-00 LER High Energy Line Break Door Blocked Open During Maintenance Activity (Section 4OA3)