IR 05000255/2015004

NRC Integrated Inspection Report 05000255/2015004

ML16047A125
Person / Time
Site:	Palisades
Issue date:	02/12/2016
From:	Jandovitz J, Christine Lipa Division of Nuclear Materials Safety III, Division Reactor Projects III
To:	Vitale A Entergy Nuclear Operations
References
IR 2015004
Download: ML16047A125 (97)

Text

UNITED STATES ary 12, 2016

SUBJECT:

PALISADES NUCLEAR PLANT - NRC INTEGRATED INSPECTION REPORT 05000255/2015004

Dear Mr. Vitale:

On December 31, 2015, the U.S. Nuclear Regulatory Commission (NRC) completed an inspection at your Palisades Nuclear Plant. The enclosed report documents the results of this inspection, which were discussed on January 12, 2016, with yourself, and other members of your staff.

Based on the results of this inspection, the NRC has identified four issues that were evaluated under the risk significance determination process as having a very-low safety significance (Green). The NRC has also determined that violations are associated with these issues. These violations are being treated as Non-Cited Violations (NCVs), consistent with Section 2.3.2 of the Enforcement Policy. These NCVs are described in the subject inspection report. Additionally, a licensee-identified violation is listed in Section 4OA7 of this report.

If you contest the subject or severity of these NCVs, you should provide a response within 30 days of the date of this inspection report, with the basis for your denial, to the U.S. Nuclear Regulatory Commission, ATTN: Document Control Desk, Washington, DC 20555-0001, with copies to the Regional Administrator, Region III; the Director, Office of Enforcement, U.S. Nuclear Regulatory Commission, Washington, DC 20555-0001; and the NRC Resident Inspector at Palisades Nuclear Plant. In addition, if you disagree with the cross-cutting aspect assigned to any finding 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 III, and the NRC Resident Inspector at Palisades Nuclear Plant. In accordance with Title 10 of the Code of Federal Regulations (10 CFR) 2.390, Public Inspections, Exemptions, Requests for Withholding, of the NRC's "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 (PARS)

component of the NRC's Agencywide Documents Access and Management System (ADAMS).

ADAMS is accessible from the NRC Web site at http://www.nrc.gov/reading-rm/adams.html (the Public Electronic Reading Room).

Sincerely,

/RA/

John Jandovitz, Acting Chief Branch 3 Division of Reactor Projects

/RA/

Christine A. Lipa Deputy Division Director, Division of Nuclear Materials Safety Docket No. 50-255 License No. DPR-20

Enclosure:

IR 05000255/2015004

REGION III==

Docket No: 50-255 License No: DPR-20 Report No: 05000255/2015004 Licensee: Entergy Nuclear Operations, Inc.

Facility: Palisades Nuclear Plant Location: Covert, MI Dates: October 1 through December 31, 2015 Inspectors: A. Nguyen, Senior Resident Inspector J. Boettcher, Resident Inspector A. Armstrong, Reactor Operations Engineer J. Cassidy, Senior Health Physicist J. Corujo-Sandin, Engineering Inspector, Mechanical M. Domke, Observer G. Hansen, Senior Emergency Preparedness Inspector M. Holmberg, Reactor Inspector C. Hunt, Reactor Engineer M. Keefe-Forsythe, Human Factors Specialist J. Lennartz, Project Engineer V. Myers, Senior Health Physicist G. ODwyer, Reactor Engineer L. Rodriguez, Engineering Inspector, Mechanical J. Rutkowski, Project Engineer T. Taylor, D.C. Cook Resident Inspector Approved by: J. Jandovitz, Acting Chief Branch 3 Division of Reactor Projects Christine A. Lipa Deputy Division Director, Division of Nuclear Materials Safety Enclosure

SUMMARY

Inspection Report (IR) 05000255/2015004, October 1, 2015 - December 31, 2015;

Palisades Nuclear Plant; Inservice Inspection Activities; Component Design Bases Inspection.

This report covers a 3-month period of inspection by resident inspectors and announced baseline inspections by regional inspectors. Two Green findings and two Severity Level IV traditional enforcement violations were identified by the inspectors. The findings were considered non-cited violations (NCVs) of U.S. Nuclear Regulatory Commission (NRC)regulations. The significance of inspection 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 April 29, 2015. Cross-cutting aspects are determined using IMC 0310, Aspects Within the Cross-Cutting Areas, dated December 4, 2014. All violations of NRC requirements are dispositioned in accordance with the NRCs Enforcement Policy, dated February 4, 2015. The NRC's program for overseeing the safe operation of commercial nuclear power reactors is described in NUREG-1649, Reactor Oversight Process, Revision 5, dated February 2014.

Cornerstone: Mitigating Systems

Green.

The inspectors identified a finding of very-low safety significance (Green),

and an associated NCV of Title 10, Code of Federal Regulations (CFR), Part 50,

Appendix B, Criterion IX, Control of Special Processes, for the licensees failure to perform a dye penetrant (PT) examination of the Safety Injection System (SIS) pipe lug welds in accordance with the American Society of Mechanical Engineers (ASME)

Code Section XI requirements. The licensee entered this issue into the Corrective Action Program (CAP) as CR-PLP-2015-04191, repeated the PT examination of the affected SIS lug welds to meet the full extent of coverage required by the ASME Code, repeated examinations of other welds conducted by the PT examiner during the outage, and removed the PT examiner from further weld examination activities.

This performance deficiency was determined to be more than minor because, if left uncorrected, the failure to perform a PT examination in accordance with the ASME Code requirements could result in acceptance and return to service of a component with an undetected crack that would increase the possibility of pipe leakage or failure.

In addition, the failure to perform a PT examination in accordance with the ASME Code adversely affected the Mitigating System Cornerstone attribute of Equipment Performance, because it could result in failure to detect cracks in pipe welds, which would reduce the availability and reliability of the SIS mitigating system. The inspectors evaluated the finding in accordance with IMC 0609, Appendix A, The SDP for Findings At-Power, Exhibit 2, Mitigating Systems Screening Questions, and answered yes to screening question number 1. Although this finding adversely affected the design or qualification of the SIS pipe lugs, the finding screened as very-low safety significance (Green), because it did not result in the loss of operability or functionality of the affected SIS pipe segment. This finding had a cross-cutting aspect in the Field Presence component of the Human Performance cross-cutting area. Specifically, licensee leaders were not observed in the work areas of the plant to coach and reinforce standards or expectations for the licensees vendor staff to ensure deviation from standards and expectations were promptly corrected [H.2]. (Section 1R08.1)

Green.

The inspectors identified a finding of very-low safety significance, and an associated NCV of 10 CFR, Part 50, Appendix B, Criterion II, Quality Assurance Program, for the licensees failure to identify all component cooling water (CCW)structures, systems, and components (SSC), which were required to be covered by the Quality Assurance Program (i.e., be safety-related). As a result, the licensee incorrectly credited nonsafety-related CCW components to remain functional during and following a design basis event (DBE). The licensee entered this finding into their CAP and, after performing operability determinations, concluded the system would still be capable of performing its function.

The performance deficiency was determined to be more than minor because it was associated with the Mitigating Systems cornerstone attribute of equipment performance, and adversely affected the cornerstone objective of ensuring the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. The finding screened as having very-low safety significance (Green)because, although it was a deficiency affecting the design or qualification of a mitigating SSC, the SSC maintained its operability. The inspectors did not identify a cross-cutting aspect associated with this finding because it was determined not to be representative of current performance. (Section 1R21.b.(1))

• SL IV. The inspectors identified a Severity Level (SL) IV, NCV of 10 CFR, Part 50,

Section 59, Changes, Tests, and Experiments, for the licensees failure to maintain records of written safety evaluations, which provide the bases for concluding the nonsafety-related portions of the CCW system inside containment could be credited to perform their function during and following a DBE, and that the change would not result in an unreviewed safety question. The licensee entered this issue into their CAP and, after performing operability determinations, concluded the system would still be capable of performing its function.

The violation was determined to be more than minor because the inspectors could not reasonably determine that the changes would not have ultimately required NRC prior approval. The violation was categorized as a SL IV in accordance with Section 6.1.d.2 of the NRC Enforcement Policy because the resulting changes were evaluated by the SDP as having very-low safety significance (i.e., green finding). The resulting changes, the violations underlying technical concerns, impacted the Mitigating Systems cornerstone, and were evaluated separately as the Green finding with the associated 10 CFR, Part 50, Appendix B, Criterion II, NCV discussed above. The inspectors did not identify a cross-cutting aspect because cross-cutting aspects are not assigned to traditional enforcement violations. (Section 1R21.b.(2))

• SL IV. The inspectors identified a SL IV, NCV of 10 CFR, Part 50.59, Changes, Tests, and Experiments, and an associated finding of very-low safety significance (Green) for the licensees failure to maintain a record of the declassification of the Chemical Volume and Control System (CVCS) from safety-related to nonsafety-related, which includes a written evaluation that provides the bases for the determination that the change did not require a license amendment. The licensee entered this issue into their CAP, and after a review of the system, determined there was reasonable assurance that it could perform its function.

The inspectors determined the underlying technical concern was a performance deficiency associated with the Mitigating Systems cornerstone that was more than minor because, if left uncorrected, would become a more significant safety concern. The underlying technical concern screened as a finding with very-low safety significance (Green) because, although it affected the design or qualification of the CVCS, it did not result in the loss of functionality of the CVCS. The violation was determined to be more than minor because the inspectors could not reasonably determine that the changes would not have ultimately required NRC prior approval. The violation was categorized as a SL IV in accordance with Section 6.1.d.2 of the NRC Enforcement Policy because the changes were evaluated by the SDP, described above, as having very-low safety significance (i.e., Green finding). The inspectors did not identify a cross-cutting aspect associated with the finding because the finding was not representative of current performance. (Section 1R21.b.(3))

• Violations of very-low safety or security significance or Severity Level IV that were identified by the licensee have been reviewed by the NRC. Corrective actions taken or planned by the licensee have been entered into the licensees CAP. These violations and CAP tracking numbers are listed in Section 4OA7 of this report.

REPORT DETAILS

Summary of Plant Status

The plant began the assessment period shut down for a planned refueling outage (RFO)

1R24 . On October 18, 2015, the reactor was taken critical and the plant was synchronized

to the grid on October 19, 2015. The reactor achieved full power on October 22, 2015, and remained at or near full power for the remainder of the inspection period.

REACTOR SAFETY

Cornerstones: Initiating Events, Mitigating Systems, and Barrier Integrity

1R01 Adverse Weather Protection

.1 Readiness for Impending Adverse Weather Condition - High Wind Conditions

a. Inspection Scope

On November 12 and 13, 2015, thunderstorms with potential high winds were forecast in the vicinity of the facility. The inspectors reviewed the licensees overall preparations/protection for the expected weather conditions. On November 11 and 12, 2015, the inspectors walked down the Emergency Diesel Generators (DGs), Service Water System (SWS), and Auxiliary Feedwater (AFW)

System, in addition to the licensees emergency alternating current (AC) power systems, because their safety-related functions could be affected or required as a result of high winds or tornado-generated missiles or the loss of offsite power. The inspectors evaluated the licensee staffs preparations against the sites procedures and determined that the staffs actions were adequate. During the inspection, the inspectors focused on plant-specific design features and the licensees procedures used to respond to specified adverse weather conditions. The inspectors also toured the plant grounds to look for any loose debris that could become missiles during a tornado. The inspectors evaluated operator staffing and accessibility of controls and indications for those systems required to control the plant. Additionally, the inspectors reviewed the Updated Final Safety Analysis Report (UFSAR) and performance requirements for systems selected for inspection, and verified that operator actions were appropriate as specified by plant specific procedures. The inspectors also reviewed a sample of Corrective Action Program (CAP) items to verify that the licensee identified adverse weather issues at an appropriate threshold and dispositioned them through the CAP in accordance with station corrective action procedures. Documents reviewed are listed in the Attachment to this report.

This inspection constituted one readiness for impending adverse weather condition sample as defined in Inspection Procedure (IP) 71111.01-05.

b. Findings

No findings were identified.

1R04 Equipment Alignment

a. Inspection Scope

The inspectors performed partial system walkdowns of the following risk-significant systems:

• Spent Fuel Pool (SFP) Cooling and Ventilation;

• Boric Acid addition pathway; and

• Electrical Power system alignment during 1R24.

The inspectors selected these systems based on their risk significance relative to the Reactor Safety Cornerstones at the time they were inspected. The inspectors attempted to identify any discrepancies that could impact the function of the system and, therefore, potentially increase risk. The inspectors reviewed applicable operating procedures, system diagrams, UFSAR, Technical Specification (TS) requirements, outstanding work orders (WOs), condition reports, and the impact of ongoing work activities on redundant trains of equipment in order to identify conditions that could have rendered the systems incapable of performing their intended functions. The inspectors also walked down 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 obvious deficiencies. The inspectors also verified that the licensee had properly identified and resolved equipment alignment problems that could cause initiating events or impact the capability of mitigating systems or barriers and entered them into the CAP with the appropriate significance characterization. Documents reviewed are listed in the to this report.

These activities constituted three partial system walkdown samples as defined in IP 71111.04-05.

b. Findings

No findings were identified.

1R05 Fire Protection

a. Inspection Scope

The inspectors conducted fire protection walkdowns which were focused on availability, accessibility, and the condition of firefighting equipment in the following risk-significant plant areas:

• Fire Area 24: AFW pumps room;

• Fire Area 13G: SFP heat exchanger room;

• Fire Area 17: Refueling and SFP area;

• Fire Area 13B: Charging pump rooms; and

• Fire risk-significant areas for the higher risk plant operating state #2 during 1R24.

The inspectors reviewed areas to assess if the licensee had implemented a Fire Protection Program that adequately controlled combustibles and ignition sources within the plant, effectively maintained fire detection and suppression capability, maintained passive fire protection features in good material condition, and implemented adequate compensatory measures for out-of-service, degraded or inoperable fire protection equipment, systems, or features in accordance with the licensees fire plan. The inspectors selected fire areas based on their overall contribution to internal fire risk as documented in the plants Individual Plant Examination of External Events with later additional insights, their potential to impact equipment which could initiate or mitigate a plant transient, or their impact on the plants ability to respond to a security event.

Using the documents listed in the Attachment to this report, the inspectors verified that fire hoses and extinguishers were in their designated locations and available for immediate use; that fire detectors and sprinklers were unobstructed; that transient material loading was within the analyzed limits; and fire doors, dampers, and penetration seals appeared to be in satisfactory condition. The inspectors also verified that minor issues identified during the inspection were entered into the licensees CAP.

Documents reviewed are listed in the Attachment to this report.

These activities constituted five quarterly fire protection inspection samples as defined in IP 71111.05-05.

b. Findings

No findings were identified.

1R07 Annual Heat Sink Performance

.1 Heat Sink Performance

a. Inspection Scope

The inspectors reviewed the licensees testing of VHX-1, #1 Containment Air Cooler, to verify that potential deficiencies did not mask the licensees ability to detect degraded performance, to identify any common cause issues that had the potential to increase risk, and to ensure that the licensee was adequately addressing problems that could result in initiating events that would cause an increase in risk. The inspectors reviewed the licensees observations as compared against acceptance criteria, the correlation of scheduled testing and the frequency of testing, and the impact of instrument inaccuracies on test results. The inspectors also verified that test acceptance criteria considered differences between test conditions, design conditions, and testing conditions. Documents reviewed for this inspection are listed in the to this document.

This annual heat sink performance inspection constituted one sample as defined in IP 71111.07-05.

b. Findings

No findings were identified.

.2 Triennial Review of Heat Sink Performance

a. Inspection Scope

The inspectors reviewed operability determinations, completed surveillances, vendor manual information, associated calculations, performance test results, and cooler inspection results associated with the 1-2 DG lube oil cooler (E-31B). This cooler was chosen based on its risk significance in the licensees probabilistic safety analysis, its important safety-related mitigating system support function, its operating history, and its relatively low margin.

The licensee did not do thermal performance testing for E-31B. However, the inspectors verified that inspection, maintenance, and monitoring of biotic fouling and macrofouling programs were adequate to ensure proper heat transfer. This was accomplished by verifying:

(1) the methods used were consistent with accepted industry practices, or an equivalent;

(2) the cleanings were consistent with the selected methodology;

(3) the inspection acceptance criteria were consistent with procedure requirements; and

(4) results of inspections were adequate.

For E-31B, the inspectors reviewed the methods and results of heat exchanger performance inspections. The inspectors verified the methods used to inspect and clean the heat exchanger were consistent with as-found conditions identified, expected degradation trends, and industry standards and contained established acceptance criteria. The as-found results were recorded, evaluated, and appropriately dispositioned such that the as-left condition was acceptable.

In addition, the inspectors verified the condition and operations of E-31B were consistent with design assumptions in heat transfer calculations and as described in the UFSAR.

This included verification that the number of plugged tubes was within pre-established limits based on capacity and heat transfer assumptions. The inspectors verified the licensee evaluated the potential for water hammer and established adequate controls and operational limits to prevent heat exchanger degradation due to excessive flow-induced vibration during operation. In addition, Eddy Current test reports and visual inspection records were reviewed to determine the structural integrity of the heat exchanger.

The inspectors also reviewed the licensees operation of the SWS and Ultimate Heat Sink. This included a review of the licensees procedures for a loss of service water and verification that instrumentation, which is relied upon for decision-making, was available and functional. In addition, the inspectors verified that macrofouling was adequately monitored, trended, and controlled by the licensee to prevent clogging. The inspectors verified that the licensees biocide treatments for biotic control were adequately conducted and the results were monitored, trended, and evaluated. The inspectors also reviewed strong pump-weak pump interaction and design changes to the SWS and Ultimate Heat Sink.

The inspectors performed a system walkdown of the SWS intake structure to verify the licensees assessment on structural integrity and component functionality. This included verification that the licensee ensured proper functioning of traveling screens and strainers and structural integrity of component mounts. In addition, the inspectors verified that the Service Water pump bay silt accumulation was monitored, trended, and maintained at an acceptable level by the licensee, and that water level instruments were functional and routinely monitored. The inspectors also verified the licensees ability to ensure functionality of the bay and instruments during adverse weather conditions and that the licensee had adequate protection against silt introduction during periods of low-flow or low water level.

Finally, the inspectors reviewed condition reports related to heat exchangers/coolers and heat sink performance issues to verify that the licensee had an appropriate threshold for identifying issues and to evaluate the effectiveness of corrective actions.

The documents that were reviewed are included in the Attachment to this report.

These inspection activities constituted two triennial heat sink inspection samples as defined in IP 71111.07-05.

b. Findings

No findings were identified.

1R08 Inservice Inspection Activities

From September 21, 2015, through October 7, 2015, the inspectors conducted a review of the implementation of the licensees Inservice Inspection (ISI) Program for monitoring degradation of the reactor coolant system, steam generator (SG) tubes, emergency feedwater systems, risk-significant piping and components and containment systems.

The inspections described in Sections 1R08.1, 1R08.2, R08.3, IR08.4, and 1R08.5 below constituted one ISI sample as defined in IP 71111.08.

.1 Piping Systems Inservice Inspection

a. Inspection Scope

The inspectors either observed or reviewed data acquired for the following non-destructive examinations (NDEs) mandated by Title 10, Code of Federal Regulations (CFR), Part 50.55a, Codes and Standards, to evaluate compliance with the applicable American Society of Mechanical Engineers (ASME) Code requirements, and if any indications and defects were detected, to determine whether these were dispositioned in accordance with the ASME Code or an U.S. Nuclear Regulatory Commission (NRC)-approved alternative requirement.

• Automated Phased Array Ultrasonic (UT) examination of Primary Coolant System (PCS) Hot Leg Drain Nozzle Weld (PCS-42-RCL-1H-3/2);

• Automated Phased Array UT examination of PCS Cold Leg Drain Nozzle Weld (PCS-30-RCL-2A-5/2);

• Automated Phased Array UT examination of PCS Cold Leg Charging Nozzle Weld (PCS-30-RCL-1A-11/2);

• Automated Phased Array UT examination of Shutdown Cooling Hot Leg B Nozzle to Pipe Weld (PCS-12-SDC-2H1-2);

• Dye Penetrant (PT) examination of Safety Injection System (SIS) Pipe Lug Welds (ESS-12-SIS-1A1-3PL1-4); and

• Magnetic Particle examination of A SG, E-50A, Support Skirt Weld (1-110-251).

For the surface and volumetric NDE performed since the previous RFO, the licensee had not identified any relevant indications. Therefore, no NRC review was completed for this inspection procedure attribute.

The inspectors reviewed the following pressure boundary welds completed for risk-significant systems since the beginning of the last RFO to determine if the licensee applied the pre-service NDEs and acceptance criteria required by the Construction Code and ASME Code,Section XI. Additionally, the inspectors reviewed the welding procedure specification and supporting weld procedure qualification records to determine whether the weld procedures were qualified in accordance with the requirements of Construction Code and the ASME Code Section IX.

• Weld repair/replacement of Class 1 Pressurizer Spray connection elbow (Welds PCS-3-PSS-2A1-1X1 and 3X1)

b. Findings

(1) Inadequate Dye Penetrant Examination of Pipe Lug Welds

Introduction:

The inspectors identified a finding of very-low safety significance (Green), and an associated Non-Cited Violation (NCV) of 10 CFR Part 50, Appendix B, Criterion IX, Control of Special Processes, for the licensees failure to perform a PT Examination of SIS pipe lug welds in accordance with the ASME Code Section XI requirements.

Description:

During observation of a PT examination of the SIS pipe lug welds, the inspectors identified that the extent of the licensees examination coverage was less than that required by the ASME Code. The inspectors were concerned that absent NRC intervention, the weld examinations, as performed, would be inadequate to detect service-induced cracks.

The inspectors observed the licensees vendor examiner during PT examination of SIS pipe lug welds ESS-12-SIS-1A1-3PL-1, 2, 3 and 4 in accordance with site procedure CEP-NDE-0641, Liquid Penetrant Examination for ASME Section XI.

Procedure CEP-NDE-0641 was identified as Informational Use, and, as such, was not required to be present at the examination location. Additionally, this procedure referenced, but did not include, the ASME Code Section XI figure numbers which defined the extent of examination coverage for these welds. The licensees examiner elected to bring a copy of the procedure to the weld location, but not a copy of the ASME Code figure that defined the extent of the examination. Following application of the penetrant material on the pipe lug welds, the inspectors identified areas of base metal adjacent to these lug welds without penetrant material coverage. After prompting by the NRC, the licensees examiner added penetrant material to obtain coverage for 0.25 inches of adjacent base material. Similarly, after application of developer, the inspectors noted areas which did not receive developer coverage in the examination area. The licensees examiner corrected this error by application of developer to obtain coverage that included 0.25 inches of the adjacent base material. Following application of the developer, the inspectors identified penetrant material bleeding out from creviced locations near the ends of the lug welds caused by the weld configuration/geometry.

The inspectors were concerned that these bleed out locations could have masked/

obscured crack indications and result in a PT examination with less than the full extent of required coverage. The licensees examiner initially reported that these areas did represent limitations, but this was an expected outcome for these welds. The inspectors concern for masked areas prompted the licensees examiner to obtain measuring equipment and record the extent of the examination area limited by the excessive bleed out near the end of these lug welds. Following completion of the PT examination for these lug welds, the inspectors identified that the extent of examination coverage, as completed, included only 0.25 inches of base material adjacent to the welded lugs, as mentioned above, which was not sufficient to meet the ASME Code Section XI.

Specifically, for these lug welds, the extent of examination as defined by the ASME Code Section XI, Figure IWC-2500-5, included 0.5 inches of the base metal adjacent to each side of the weld.

The licensee entered this issue into the CAP as CR-PLP-2015-04191, repeated the PT examination of the affected SIS lug welds to meet the full extent of coverage required by the ASME Code, repeated examinations of other welds conducted by the PT examiner during the outage, and removed the examiner of these pipe lug welds from further weld examinations. Because the NRC identified this issue and the licensee corrected this issue before the SIS lug welds were returned to service, the operability of the SIS was not affected.

Analysis:

The inspectors determined that the licensee's failure to perform a PT examination of the SIS lug welds in accordance with the ASME Code Section XI requirements was contrary to 10 CFR Part 50, Appendix B, Criterion IX, Control of Special Processes, and was a performance deficiency. The inspectors determined that the performance deficiency was more than minor in accordance with Inspection Manual Chapter (IMC) 0612, Appendix B, Issue Screening, dated September 7, 2012.

Specifically, if left uncorrected, the failure to perform a PT examination in accordance with the ASME Code requirements could result in acceptance and return to service of a component with an undetected crack that would increase the possibility of pipe leakage or failure. In addition, the failure to perform a PT examination in accordance with the ASME Code adversely affected the Mitigating System cornerstone attribute of Equipment Performance because it could result in failure to detect cracks in pipe welds, which would reduce the availability and reliability of the SIS mitigating system.

The inspectors evaluated the finding in accordance with IMC 0609, Significance Determination Process (SDP), Attachment 0609.04, Phase 1 - Initial Screening and Characterization of Findings, and Exhibit 2, Mitigating Systems Screening Questions of IMC 0609, Appendix A, The Significance Determination Process for Findings At-Power, dated July 1, 2012. The inspectors answered yes to screening question number 1 of exhibit 2. Although this finding adversely affected the design or qualification of the SIS pipe lugs, the finding screened as very-low safety significance (Green),because it did not result in the loss of operability or functionality of the affected SIS pipe segment.

This finding had a cross-cutting aspect in the Field Presence component of the Human Performance cross-cutting area. Specifically, licensee leaders were not observed in the work areas of the plant to coach and reinforce standards or expectations for the licensees vendor staff to ensure deviation from standards and expectations were promptly corrected. [H.2]

Enforcement:

Title 10 CFR, Part 50, Appendix B, Criterion IX, Control of Special Processes, requires that measures shall be established to assure that special processes, including welding, heat treating, and non-destructive testing, are controlled and accomplished by qualified personnel using qualified procedures in accordance with applicable codes, standards, specifications, criteria, and other special requirements.

The ASME Code Section XI, Article IWC-2500, Examination and Pressure Test Requirements, states components shall be examined and pressure tested as specified in Table IWC-2500-1. Table IWC-2500-1, Examination Categories, Category C-C, Welded Attachments for Vessels, Piping, Pumps, and Valves, Item C3.20, Welded s - Piping, requires a 100 percent surface examination of each welded attachment in accordance with Figure IWC-2500-5. Figure IWC-2500-5 depicts the attachment weld and 0.5 inches of base metal adjacent to each side of the weld.

Contrary to the above, on September 23, 2015, during PT examination of pipe lug welded attachments classified as Item C3.20 (welded pipe lugs ESS-12-SIS-1A1-3PL-1, 2, 3 and 4), the licensee completed examination of approximately 0.25 inches of the base metal adjacent to the attachment welds. Once identified, the licensee repeated the PT examination to include the full extent of the required area; 0.5 inches of base metal.

Because this violation was of very-low safety significance, and was entered into the licensees CAP as CR-PLP-2015-04191, this violation is being treated as an NCV, consistent with Section 2.3.2 of the NRC Enforcement Policy.

(NCV 05000255/2015004-01; Inadequate Dye Penetrant Examination of Pipe Lug Welds).

.2 Reactor Pressure Vessel Upper Head Penetration Inspection Activities

a. Inspection Scope

A bare metal visual (BMV) examination and a non-visual examination were required this outage pursuant to 10 CFR 50.55a(g)(6)(ii)(D).

The inspectors reviewed the records of the BMV examination of the reactor vessel head at each of the penetration nozzles to determine whether the activities were conducted in accordance with the requirements of ASME Code Case (CC) N-729-1 and 10 CFR 50.55a(g)(6)(ii)(D). Specifically, to determine:

• if the required visual examination scope/coverage was achieved and limitations (if applicable were recorded), in accordance with the licensee procedures;

• if the licensee criteria for visual examination quality and instructions for resolving interference and masking issues were adequate; and

• for indications of potential through-wall leakage, that the licensee entered the condition into the corrective action system and implemented appropriate corrective actions.

The inspectors observed a number of non-visual examinations conducted on the reactor vessel head penetrations to determine whether the activities were conducted in accordance with the requirements of ASME CC N-729-1 and 10 CFR 50.55a(g)(6)(ii)(D).

Specifically, to determine:

• if the required examination scope (volumetric and surface coverage) was achieved and limitations (if applicable were recorded), in accordance with the licensee procedures;

• if the UT examination equipment and procedures used were demonstrated by blind demonstration testing;

• for indications or defects identified, that the licensee documented the conditions in examination reports and/or entered this condition into the corrective action system and implemented appropriate corrective actions; and

• for indications accepted for continued service, that the licensee evaluation and acceptance criteria were in accordance with the ASME Section XI Code, 10 CFR 50.55a(g)(6)(ii)(D) or an NRC-approved alternative.

The licensee did not perform any welded repairs to vessel head penetrations since the beginning of the preceding outage. Therefore, no NRC review was completed for this inspection procedure attribute.

b. Findings

No findings were identified.

.3 Boric Acid Corrosion Control

a. Inspection Scope

The inspectors performed a walk down of the PCS and related lines in the containment during the licensees boric acid walk down to verify whether the licensees boric acid corrosion control visual examinations emphasized locations where boric acid leaks can cause degradation of safety significant components.

The inspectors reviewed the following licensee evaluations of PCS components with boric acid deposits to determine if degraded components were documented in the CAP.

The inspectors also evaluated corrective actions for any degraded PCS components to determine if they met the ASME Section XI Code.

• 14-PAL-0032; P-50B, Primary Coolant Pump (PCP) seal leak;

• 14-PAL-0187; CV-1057, Pressurizer Spray Valve packing leak; and

• 14-PAL-0099; MV-PC600, B SG Hot Leg sample line isolation valve, downstream cap leak.

The inspectors reviewed the following corrective actions related to evidence of boric acid leakage to determine if the corrective actions completed were consistent with the requirements of the ASME Code Section XI and 10 CFR Part 50, Appendix B, Criterion XVI.

• CR-PLP-2014-0343; Boric Acid on P-50A, A PCP; and

• CR-PLP-2014-02127; Boric Acid on MV-PC1038A, Pressurizer pressure transmitter/level transmitter root valve, fitting.

b. Findings

No findings were identified.

.4 Steam Generator Tube Inspection Activities

a. Inspection Scope

The NRC inspectors observed acquisition and analysis of Eddy Current testing (ET)data, interviewed ET data analysts, and reviewed documentation related to the SG ISI Program to determine if:

• in-situ SG tube pressure testing screening criteria used were consistent with those identified in the Electric Power Research Institute (EPRI) TR-1025132, SG In-Situ Pressure Test Guidelines, and that these criteria were properly applied to screen degraded SG tubes for in-situ pressure testing;

• the numbers and sizes of SG tube flaws/degradation identified was bounded by the licensees previous outage operational assessment predictions;

• the SG tube ET examination scope and expansion criteria were sufficient to meet the TSs, and the EPRI 1003138, Pressurized Water Reactor Steam Generator Examination Guidelines, Revision 6;

• the SG tube ET examination scope included potential areas of tube degradation identified in prior outage SG tube inspections and/or as identified in NRC generic industry operating experience applicable to these SG tubes;

• the licensee identified new tube degradation mechanisms and implemented adequate extent of condition inspection scope and repairs for the new tube degradation mechanism;

• the licensee implemented repair methods which were consistent with the repair processes allowed in the plant TS requirements and to determine if qualified depth sizing methods were applied to degraded tubes accepted for continued service;

• the licensee implemented an inappropriate plug on detection tube repair threshold (e.g., no attempt at sizing of flaws to confirm tube integrity);

• the licensee primary-to-secondary leakage (e.g., SG tube leakage) was below 3 gallons per day or the detection threshold during the previous operating cycle;

• the ET probes and equipment configurations used to acquire data from the SG tubes were qualified to detect the known/expected types of SG tube degradation in accordance with Appendix H, Performance Demonstration for ET Examination, of EPRI 1013706, Pressurized Water Reactor Steam Generator Examination Guidelines, Revision 7; and

• the licensee performed secondary side SG inspections for location and removal of foreign materials.

The licensee did not perform in-situ pressure testing of SG tubes. Therefore, no NRC review was completed for this inspection attribute.

b. Findings

No findings were identified.

.5 Identification and Resolution of Problems

a. Inspection Scope

The inspectors performed a review of ISI-related problems entered into the licensees CAP and conducted interviews with licensee staff to determine whether:

• the licensee had established an appropriate threshold for identifying ISI-related problems;

• the licensee had performed a root cause (if applicable) and taken appropriate corrective actions; and

• the licensee had evaluated operating experience and industry generic issues related to ISI and pressure boundary integrity.

The inspectors performed these reviews to evaluate compliance with 10 CFR Part 50, Appendix B, Criterion XVI, Corrective Action, requirements. The corrective action documents reviewed by the inspectors are listed in the Attachment to this report.

b. Findings

No findings were identified.

1R11 Licensed Operator Requalification Program

.1 Resident Inspector Quarterly Review of Licensed Operator Requalification

a. Inspection Scope

On December 1, 2015, the inspectors observed a crew of licensed operators in the plants simulator during licensed operator requalification training. The inspectors verified that operator performance was adequate, evaluators were identifying and documenting crew performance problems, and that training was being conducted in accordance with licensee procedures. The inspectors evaluated the following areas:

• licensed operator performance;

• crews clarity and formality of communications;

• ability to take timely actions in the conservative direction;

• prioritization, interpretation, and verification of annunciator alarms;

• correct use and implementation of abnormal and emergency procedures;

• control board manipulations;

• oversight and direction from supervisors; and

• ability to identify and implement appropriate TS actions and Emergency Plan actions and notifications.

The crews performance in these areas was compared to pre-established operator action expectations and successful critical task completion requirements. Documents reviewed are listed in the Attachment to this report.

This inspection constituted one quarterly Licensed Operator Requalification Program simulator sample as defined in IP 71111.11-05.

b. Findings

No findings were identified.

.2 a

Resident Inspector Quarterly Observation During Periods of Heightened Activity or Risk (71111.11Q)

a. Inspection Scope

On October 7, 2015, the inspectors observed the control room operating crew conduct a drain of the PCS to reduced inventory to facilitate work during RFO 24. This was an activity that required heightened awareness and precise plant control and was an increased risk period (Yellow) for plant operations. The inspectors evaluated the following areas:

• licensed operator performance;

• the crews clarity and formality of communications;

• ability to take timely actions in the conservative direction;

• prioritization, interpretation, and verification of annunciator alarms;

• correct use and implementation of procedures;

• control board manipulations; and

• oversight and direction from supervisors.

Performance in these areas was compared to pre-established operator action expectations, procedural compliance, and task completion requirements.

Documents reviewed are listed in the Attachment to this report.

This inspection constituted one quarterly licensed operator heightened activity/risk sample as defined in IP 71111.11-05.

b. Findings

No findings were identified.

.2 b

Resident Inspector Quarterly Observation During Periods of Heightened Activity or Risk (71111.11Q)

a. Inspection Scope

On October 18, 2015, the inspectors observed a reactor startup and approach to criticality following RFO 24. This was an activity that required heightened awareness, precise plant control, and was related to increased risk. The inspectors evaluated the following areas:

• licensed operator performance;

• the crews clarity and formality of communications;

• ability to take timely actions in the conservative direction;

• prioritization, interpretation, and verification of annunciator alarms;

• correct use and implementation of procedures;

• control board manipulations; and

• oversight and direction from supervisors.

Performance in these areas was compared to pre-established operator action expectations, procedural compliance, and task completion requirements.

Documents reviewed are listed in the Attachment to this report.

This inspection constituted one quarterly licensed operator heightened activity/risk sample as defined in IP 71111.11-05.

a. Findings

No findings were identified.

.2 c

Resident Inspector Quarterly Observation During Periods of Heightened Activity or Risk (71111.11Q)

a. Inspection Scope

October 16, 2015, the inspectors observed the control room operating crew respond to a voltage transient which caused a loss of incoming 4160V power from the switchyard to the plant. This was an activity that required heightened awareness and was related to increased risk. The inspectors evaluated the following areas:

• licensed operator performance;

• the crews clarity and formality of communications;

• ability to take timely actions in the conservative direction;

• prioritization, interpretation, and verification of annunciator alarms;

• correct use and implementation of procedures;

• control board manipulations;

• oversight and direction from supervisors; and

• the ability to identify and implement appropriate TS actions and Emergency Plan actions and notifications.

Performance in these areas was compared to pre-established operator action expectations, procedural compliance, and task completion requirements.

Documents reviewed are listed in the Attachment to this report.

This inspection constituted one quarterly licensed operator heightened activity/risk sample as defined in IP 71111.11-05.

b. Findings

No findings were identified.

1R12 Maintenance Effectiveness

a. Inspection Scope

The inspectors evaluated degraded performance issues involving the following risk-significant systems:

• Digital Electro-hydraulic (DEH) system The inspectors reviewed events such as where ineffective equipment maintenance had resulted in valid or invalid automatic actuations of engineered safeguards systems and independently verified the licensee's actions to address system performance or condition problems in terms of the following:

• implementing appropriate work practices;

• identifying and addressing common cause failures;

• scoping of systems in accordance with 10 CFR 50.65(b) of the maintenance rule;

• characterizing system reliability issues for performance;

• charging unavailability for performance;

• trending key parameters for condition monitoring;

• ensuring 10 CFR 50.65(a)(1) or (a)(2) classification or re-classification; and

• verifying appropriate performance criteria for structures, systems, and components (SSCs)/functions classified as (a)(2), or appropriate and adequate goals and corrective actions for systems classified as (a)(1).

The inspectors assessed performance issues with respect to the reliability, availability, and condition monitoring of the system. In addition, the inspectors verified maintenance effectiveness issues were entered into the CAP with the appropriate significance characterization. Documents reviewed are listed in the Attachment to this report.

This inspection constituted one quarterly maintenance effectiveness samples as defined in IP 71111.12-05.

b. Findings

No findings were identified.

1R13 Maintenance Risk Assessments and Emergent Work Control

a. Inspection Scope

The inspectors reviewed the licensee's evaluation and management of plant risk for the maintenance and emergent work activities affecting risk-significant and safety-related equipment listed below to verify that the appropriate risk assessments were performed prior to removing equipment for work:

• High-risk period while the PCS was in reduced inventory during 1R24;

• High-risk activity associated with the High-Pressure Turbine rotor lift;

• Emergent work to identify and troubleshoot intermittent grounds on 2400V Buses 1C, 1D, and 1E; and

• Emergent work for temporary modification and repair of P/S-0550, Master Power Supply.

These activities were selected based on their potential risk significance relative to the Reactor Safety Cornerstones. As applicable for each activity, the inspectors verified that risk assessments were performed as required by 10 CFR 50.65(a)(4), and were accurate and complete. When emergent work was performed, the inspectors verified that the plant risk was promptly reassessed and managed. The inspectors reviewed the scope of maintenance work, discussed the results of the assessment with the licensee's probabilistic risk analyst or shift technical advisor, and verified plant conditions were consistent with the risk assessment. The inspectors also reviewed TS requirements and walked down portions of redundant safety systems, when applicable, to verify risk analysis assumptions were valid and applicable requirements were met. Documents reviewed during this inspection are listed in the Attachment to this report.

These maintenance risk assessments and emergent work control activities constituted four samples as defined in IP 71111.13-05.

b. Findings

No findings were identified.

1R15 Operability Determinations and Functional Assessments

a. Inspection Scope

The inspectors reviewed the following issues:

• Leakage from the FLEX connection cap for the Low-Pressure Safety Injection system;

• Inability to perform the in-service valve stroke test for the Shutdown Cooling valves;

• Water and corrosion found in the Containment building floor liner leak-chase channels;

• SWS leak on Fire Protection piping in containment;

• SWS flow balancing test did not meet acceptance criteria; and

• Operability/design control of the CCW and CVCS.

The inspectors selected these potential operability issues based on the risk significance of the associated components and systems. The inspectors evaluated the technical adequacy of the evaluations to ensure that 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 TS and UFSAR to the licensees 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. The inspectors determined, where appropriate, compliance with bounding limitations associated with the evaluations. Additionally, the inspectors reviewed a sampling of corrective action documents to verify that the licensee was identifying and correcting any deficiencies associated with operability evaluations. Documents reviewed are listed in the to this report.

This operability inspection constituted six samples as defined in IP 71111.15-05.

b. Findings

No findings were identified.

1R18 Plant Modifications

a. Inspection Scope

The inspectors reviewed the following modification(s):

• Engineering Change 60676, Swap Qualified Incore Cables Locations with Non-Qualified Cables to Ensure 4 Qualified Circuits per Reactor Quadrant

[Temporary Modification]; and

• Engineering Change 55367, Replace 1C and 1D 500MCM Feeder Cables from Startup Transformer 1-2 with 1000MCM Feeder Cables [Permanent Modification].

The inspectors reviewed the configuration changes and associated 10 CFR 50.59 safety evaluation screening against the design basis, the UFSAR, and the TS, as applicable, to verify that the modification did not affect the operability or availability of the affected system(s). The inspectors, as applicable, observed ongoing and completed work activities to ensure that the modifications were installed as directed and consistent with the design control documents; the modifications operated as expected; post-modification testing adequately demonstrated continued system operability, availability, and reliability; and that operation of the modifications did not impact the operability of any interfacing systems. As applicable, the inspectors verified that relevant procedure, design, and licensing documents were properly updated. Lastly, the inspectors discussed the plant modification with operations, engineering, and training personnel to ensure that the individuals were aware of how the operation with the plant modification in place could impact overall plant performance. Documents reviewed are listed in the Attachment to this report.

This inspection constituted one temporary modification sample and one permanent plant modification sample as defined in IP 71111.18-05.

b. Findings

No findings were identified.

1R19 Post-Maintenance Testing

a. Inspection Scope

The inspectors reviewed the following post-maintenance activities to verify that procedures and test activities were adequate to ensure system operability and functional capability:

• Completed WO package and operation post-RFO of C PCP seal following replacement;

• Control Rod drop time testing;

• Valve stroke time testing and position verification of CV-3057, Safety Injection and Refueling Water storage tank outlet isolation valve following repairs;

• Completed WO package and satisfactory system operation of Backup Nitrogen station #5 following replacement of relief valve, RV-2279;

• Surveillance testing following 1-2 DG maintenance window;

• Completed WO package and satisfactory system operation of P-55C,

'C' Charging pump, following discharge manifold flush outlet valves replacement;

• Surveillance testing following P-54A, A Containment Spray pump, maintenance window; and

• Valve stroke time testing and position verification of VOP-3007, High-Pressure Safety Injection to Reactor Coolant Loop 1A Train 1, following a condition check.

These activities were selected based upon the structure, system, or component's ability to impact risk. The inspectors evaluated these activities for the following (as applicable):

the effect of testing on the plant had been adequately addressed, testing was adequate for the maintenance performed; acceptance criteria were clear and demonstrated operational readiness; test instrumentation was appropriate; tests were performed as written in accordance with properly reviewed and approved procedures; equipment was returned to its operational status following testing (temporary modifications or jumpers required for test performance were properly removed after test completion); and test documentation was properly evaluated. The inspectors evaluated the activities against TSs, the UFSAR, 10 CFR Part 50 requirements, licensee procedures, and various NRC generic communications to ensure that the test results adequately ensured that the equipment met the licensing basis and design requirements. In addition, the inspectors reviewed corrective action documents associated with post-maintenance tests to determine whether the licensee was identifying problems and entering them in the CAP and that the problems were being corrected commensurate with their importance to safety. Documents reviewed are listed in the Attachment to this report.

This inspection constituted eight post-maintenance testing samples as defined in IP 71111.19-05.

b. Findings

No findings were identified.

1R20 Outage Activities

a. Inspection Scope

The inspectors evaluated outage activities for RFO 1R24 that began on September 16, 2015, and continued into the fourth quarter assessment period.

The inspectors reviewed the Outage Risk Assessment (ORAT) and contingency plans for 1R24, prior to the shutdown, to confirm that the licensee had appropriately considered risk, industry operating experience, and previous site-specific problems in developing and implementing a plan that assured maintenance of defense-in-depth.

During 1R24, the inspectors observed portions of the startup process and monitored licensee controls over the RFO activities listed below:

• Licensee configuration management, including maintenance of defense-in-depth commensurate with the ORAT for key safety functions and compliance with the applicable TSs when taking equipment out of service;

• Implementation of clearance activities and confirmation that tags were properly hung and equipment appropriately configured to safely support the work or testing;

• Installation and configuration of primary coolant pressure, level, and temperature instruments to provide accurate indication, accounting for instrument error;

• Controls over the status and configuration of electrical systems to ensure that TS and ORAT requirements were met, and controls over switchyard activities;

• Monitoring of decay heat removal processes, systems, and components;

• Controls to ensure that RFO work was not impacting the ability of the operators to operate the SFP cooling system;

• Reactor water inventory controls including flow paths, configurations, and alternative means for inventory addition, and controls to prevent inventory loss;

• Controls over activities that could affect reactivity;

• Maintenance of secondary containment as required by TSs;

• Licensee fatigue management, as required by 10 CFR 26, Subpart I,

• Refueling activities, including fuel handling and sipping to detect fuel assembly leakage;

• Startup and ascension to full power operation, tracking of startup prerequisites, walkdown of primary containment to verify that debris had not been left which could block emergency core cooling system suction strainers, and reactor physics testing; and

• Licensee identification and resolution of problems related to RFO activities.

Documents reviewed are listed in the Attachment to this report.

This inspection constituted one RFO sample as defined in IP 71111.20-05.

b. Findings

No findings were identified.

1R21 Component Design Bases Inspection

a. Inspection Scope

In 2014, the NRC completed a Component Design Basis Inspection (CDBI) at the Palisades Nuclear Plant, documented in Inspection Report 05000255/2014008. In that inspection, the inspectors opened two separate unresolved items (URIs) related to the CCW system. The URIs are the following:

• URI 05000255/2014008-11, Classification of CCW Piping and Components Inside the Reactor Containment Building; and

• URI 05000255/2014008-12, CCW System Licensing Bases.

The first URI, URI 05000255/2014008-11, is related to the ISI classification of CCW piping and components inside the reactor containment building. The inspectors performed intermittent in office inspection activities from November 2014 until October 2015. The inspection activities consisted of reviews of licensee documents, NRC requirements, NRC Safety Evaluation Reports (SERs), NRC guidance documents, and also included discussions with licensee personnel.

The Findings section below documents the conclusions reached as part of the inspectors review. With that information, URI 05000255/2014008-11, Classification of CCW Piping and Components inside the Reactor Containment Building, is considered closed.

The second URI, URI 05000255/2014008-12, is related to the licensing bases for the CCW system at the Palisades Nuclear Plant, and what failures the licensee is required to postulate and evaluate for the system. Although this URI is closely related to URI 05000255/2014008-11, the item is sufficiently different to warrant further inspection activities to resolve it. Therefore, URI 05000255/2014008-12, remains open.

b. Findings

(1) Failure to Identify Components Required to be Covered by the Quality Assurance Program

Introduction.

The inspectors identified a finding of very-low safety significance (Green),and an associated NCV of 10 CFR, Part 50, Appendix B, Criterion II, Quality Assurance Program, for the licensees failure to identify all CCW structures, systems, and components (SSC), which were required to be covered by the Quality Assurance Program (i.e., be safety-related).

Description.

The CCW system is discussed in Section 9.3 of the Palisades FSAR.

The CCW system contains both safety-related and nonsafety-related portions. The portions of the system inside containment are nonsafety-related and are not seismically qualified. The portions of CCW inside containment were originally designed to isolate from the rest of CCW. The original FSAR, Section 9.3.1, [Component Cooling System]

Design Bases stated:

The parts of the system located inside containment are isolated in the event of a

[design basis accident] DBA. The remainder of the system, including pumps and heat exchangers, is located outside containment. The portion of the system located outside containment is designed to Seismic Class 1 requirements and protected from tornadoes.

The CCW system is a closed cycle system, which provides cooling water to various SSCs. Even though there are redundant pumps and heat exchangers, the system's piping is not redundant and a single pipe break or failure of the pressure boundary could result in the complete loss of CCW. One of the CCW systems safety functions is to transfer heat from the reactor and containment (post-design bases event (DBE)) to the ultimate heat sink (CCW is an intermediate system). Another safety function for the CCW system is to provide cooling to the engineered safeguards (ESF) pumps. The ESF pumps include the containment spray pumps, high-pressure safety injection pumps, and the low-pressure safety injection pumps. The CCW system also provides cooling water to the nonsafety-related charging pumps.

In addition to the system functions described above, some CCW components serve as containment isolation valves (CIVs). The original licensing bases for Palisades established the following safety-related valves as CIVs:

(1) air operated valve (AOV)

CV-0910 and check valve CK-CC910 on the CCW supply line to containment; and

(2) AOVs CV-0911 and CV-0940 on the CCW return line from containment. Originally, the CCW portion inside containment would automatically isolate from the rest of the system during a DBE following a safety injection system (SIS) actuation. As a result, the nonsafety-related portion of CCW inside containment would isolate from the rest of the system, during a DBE, when an SIS actuation signal was present. This isolation scheme was changed in 1984 and again in 1987. The changes were documented under facility change documents FC-452-2 and FC-657, respectively. The current isolation scheme isolates the nonsafety-related CCW inside containment when a containment high pressure (CHP) signal is present, instead of an SIS signal.

In 1989 - 1990, the licensee identified single failures which could render the plant incapable of isolating the NSR portion of CCW inside containment from the safety-related portion outside of containment. As a result, the entire CCW system could be lost due to a failure of the nonsafety-related portions of CCW inside containment.

The licensee was particularly concerned that a high-energy line break (HELB) inside containment could impact and breach the nonsafety-related CCW piping, resulting in the loss of CCW inventory and the loss of the entire system. This vulnerability was originally documented in Licensee Event Report (LER)89-006, Component Cooling Water Availability Following a HELB.

The LER addresses the licensees concern that a single active failure of CV-0910 to close, concurrent with the failure of nonsafety-related CCW inside containment, could lead to a complete loss of the CCW system due to a loss of inventory. It should be noted that the containment integrity function would not be lost because a redundant CIV upstream of CV-0910, a check valve, could still isolate containment. In order to correct the vulnerability the licensee completed Deviation Reports D-PAL-89-061, Post-Accident Operation of CCW System, and D-PAL-89-120, Loss of Instrument Air -

CCW System. The licensee attempted to address the vulnerabilities by demonstrating that the nonsafety-related CCW piping inside containment would not fail. They identified three potential failure mechanisms for the CCW piping inside containment:

(1) missiles;

(2) HELBs; and

(3) earthquakes.

To address the missile failure mechanism, the licensee reviewed the Systematic Evaluation Program (SEP) Topic VI-4, Internally Generated Missiles, which documented the NRCs evaluation of the entire CCW system (including the portion inside containment), and found it to be adequately protected against missiles. Therefore, the licensee determined that the CCW system inside containment was not vulnerable to missiles.

To address the HELB failure mechanism, the licensee prepared engineering analysis, EA-GWO 7793-01, CCW Piping inside Containment, in 1990. The evaluation concluded that nonsafety-related portions of CCW piping inside containment were not susceptible to failure due to a HELB.

To address the seismic failure mechanism, the licensee reviewed the CCW system design. The licensee found that the CCW system piping inside containment was not seismically qualified, and therefore was susceptible to failure during an earthquake.

However, since neither a Loss of Coolant Accident nor a steam line/feed line break are required to be postulated during a seismic event (because of the seismic qualifications of those systems) the licensee concluded that the plant could be brought to a safe shutdown condition without relying on the CCW system. Using the information from SEP Topic IX-3, Station Service and Cooling Water Systems, the licensee determined:

(1) reactor heat removal could be accomplished using the auxiliary feedwater system, and steam generators; and

(2) primary system makeup and boration could be provided by intermittently operating the constant speed charging pumps without CCW cooling flow until CCW repairs could be made. It is important to note, that at the time of this evaluation (1989-1990), the charging pumps were categorized as safety-related.

Based on the above, the licensee decided to credit the nonsafety-related CCW system inside containment to remain intact during a HELB (not vulnerable to HELB damage),and documented this new licensing basis in their FSAR. This change was processed on August 21, 1990, as FSAR change request 5-39-R11-391. In effect, the licensee added a safety function to the CCW piping inside containment by now relying on it to shut down the reactor and maintain it in a safe shutdown condition during and following a DBE, which causes a HELB inside containment, given the single active failure of CIV CV-0910. This change was made incorrectly because the licensee failed to either reclassify the CCW piping inside containment as safety-related when it was credited to perform a safety function, or obtain prior NRC approval to credit the nonsafety-related piping to perform a safety function.

In 1999, the licensee made changes to containment penetrations MZ-14 (CCW supply)and MZ-15 (CCW return). The changes were made using the conclusion that CCW piping inside containment was not considered susceptible to failure (as discussed above). These penetrations are part of the containment isolation system, which is discussed in Section 6.7 of the FSAR. Originally, each containment penetration credited two in-series CIVs and the CCW system piping inside containment was not credited.

The containment penetrations were then changed to credit one CIV per penetration (check valve CK-CC910 and AOV CV-0911), and the CCW system piping inside containment because it was no longer believed to be susceptible to failure. In effect, the licensee added an additional safety function to the CCW piping inside containment by now relying on it to form a part of the containment boundary. This change was evaluated under 50.59 Unreviewed Safety Question Evaluation SDR-99-0884. The change was made incorrectly because the licensee failed to either reclassify the CCW piping inside containment as safety-related when it was credited it to perform an additional safety function, or obtain prior NRC approval to credit the nonsafety-related piping to perform a safety function. It is important to note that:

(1) the instrument air supplied to the CIV AOV CV-0911 is nonsafety-related;

(2) CV-0911 is a fail open valve;

(3) CV-0911 has an air accumulator rated for four hours; but it is also nonsafety-related;

(4) the CCW piping inside containment credited to form a part of the containment barrier is not seismically qualified; and

(5) once the containment penetration changes were made the local leak rate testing requirement of the remaining credited CCW CIVs was removed.

Title 10 CFR 50.2, in part, defines safety-related SSCs as those SSCs that are relied upon to remain functional during and following design basis events to assure:

(1) the integrity of the reactor coolant pressure boundary;

(2) the capability to shut down the reactor and maintain it in a safe shutdown condition; or

(3) the capability to prevent or mitigate the consequences of accidents, which could result in potential offsite exposures comparable to the applicable guideline exposures set forth in 10 CFR 100.11. This definition of safety-related is also included in the licensees FSAR under Section 5.2.2.8.1. In addition, 10 CFR Part 50, Appendix B, Criterion II, Quality Assurance Program, requires in part, that licensees identify the SSCs to be covered by the Quality Assurance Program (i.e., safety-related components).

Based on the above, the inspectors determined the licensee has incorrectly made changes to the plant to credit nonsafety-related SSCs with a safety-related function without reclassifying them as safety-related. The nonsafety-related SSCs and their safety-related functions are the following:

• Given a postulated single active failure of CIV CV-0910, the nonsafety-related CCW piping inside containment is credited with a safety-related function to maintain its pressure boundary (remain intact) following a DBE (excluding a seismic event). This function is required in order for the CCW system to perform its safety-related reactor and containment heat removal functions needed to:

(1) shut down the reactor and maintain it in a safe shutdown condition; and

(2) prevent or mitigate the consequences of accidents.

• The nonsafety-related CCW piping inside containment is credited to maintain its pressure boundary (remain intact) following a DBE to provide a safety-related containment integrity barrier (the first of two barriers for containment penetrations MZ-14 and MZ-15) to prevent or mitigate the consequences of accidents which could result in potential offsite exposures.

Analysis.

The inspectors determined the licensee failed to identify all CCW SSCs, which were required to be covered by the Quality Assurance Program, i.e., be safety-related SSCs in accordance with 10 CFR Part 50, Appendix B, Criterion II, Quality Assurance Program. As a result, the licensee incorrectly credited nonsafety-related CCW components to remain functional during and following a DBE. This was a performance deficiency. The performance deficiency was determined to be more than minor because it was associated with the Mitigating Systems cornerstone attribute of equipment performance and affected the cornerstone objective of ensuring the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. Specifically, since nonsafety-related components are not maintained to the same design, fabrication, construction, and testing quality standards as safety-related SSCs, these nonsafety-related components could not be relied upon to perform their functions during a DBE.

The inspectors determined the finding could be evaluated using the SDP in accordance with IMC 0609, SDP, Attachment 0609.04, Initial Characterization of Findings.

Specifically, the inspectors used IMC 0609, Appendix A, SDP for Findings At-Power, Exhibit 2, Mitigating Systems Screening Questions, issued June 19, 2012, and answered yes to Question A.1. The finding screened as having very low safety significance (Green) because, although it was a deficiency affecting the design or qualification of a mitigating SSC, the SSC maintained its operability. Specifically the licensee evaluated the CCW systems operability as part of corrective actions CR-PLP-2015-01872, and CR-PLP-2015-05468, and concluded the system would still be capable of performing its function.

The inspectors did not identify a cross-cutting aspect associated with this finding.

Based on the dates (1989 and 1999) when the modifications were implemented, the inspectors determined the finding was not representative of current performance.

Enforcement.

Title 10 CFR, Part 50, Appendix B, Criterion II, Quality Assurance Program, requires, in part, that the licensee shall identify the SSCs to be covered by the Quality Assurance Program.

Title 10 CFR, Part 50, Appendix B, Introduction, states, in part, that nuclear power plants and fuel reprocessing plants include SSCs that prevent or mitigate the consequences of postulated accidents that could cause undue risk to the health and safety of the public. This appendix establishes quality assurance requirements for the design, manufacture, construction, and operation of those SSCs. The pertinent requirements of this appendix apply to all activities affecting the safety-related functions of those SSCs, these activities include designing, purchasing, fabricating, handling, shipping, storing, cleaning, erecting, installing, inspecting, testing, operating, maintaining, repairing, refueling, and modifying. As used in this appendix, quality assurance comprises all those planned and systematic actions necessary to provide adequate confidence that a structure, system, or component will perform satisfactorily in service. Quality assurance includes quality control, which comprises those quality assurance actions related to the physical characteristics of a material, structure, component, or system which provide a means to control the quality of the material, structure, component, or system to predetermined requirements.

Title 10 CFR Part 50.2, Definitions, states, in part, that safety-related SSCs means those SSCs that are relied upon to remain functional during and following DBEs to assure:

(1) the integrity of the reactor coolant pressure boundary;

(2) the capability to shut down the reactor and maintain it in a safe shutdown condition; or

(3) the capability to prevent or mitigate the consequences of accidents which could result in potential offsite exposures comparable to the applicable guideline exposures set forth in

§ 50.34(a)(1) or § 100.11 of this chapter, as applicable.

Contrary to the above, since August 21, 1990, the licensee failed to identify all the CCW SSCs which were required to be covered by the Quality Assurance Program. Quality assurance requirements apply to all activities affecting the safety-related functions of SSCs and comprise all those planned and systematic actions necessary to provide adequate confidence that a SSC will perform satisfactorily in service.

Specifically, the portions of CCW inside containment meet the 10 CFR 50.2 definition of Safety-Related SSCs, and are required to be covered by the Quality Assurance Program because they are credited to remain functional during and following design basis events to ensure:

(1) the capability to shut down the reactor and maintain it in a safe shutdown condition; and

(2) the capability to prevent or mitigate the consequences of accidents which could result in potential offsite exposures comparable to the applicable guidelines. In particular, the nonsafety-related portions of CCW inside containment:

(1) are part of the pressure boundary which ensure CCW inventory is maintained so the safety-related portions of CCW can perform their function; and

(2) form part of the containment isolation system as one of the two containment barriers, which ensure containment can perform its safety-related function.

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 as CR-PLP-2015-01872 and CR-PLP-2015-05468. As part of their immediate corrective actions, the licensee performed operability determinations which concluded the system would still be capable of performing its function. (NCV 05000255/2015004-02; Failure to Identify Components Required to be Covered by the Quality Assurance Program)

(2) Failure to Provide Bases to Determine Changes Did Not Involve Unreviewed Safety Questions

Introduction.

The inspectors identified a Severity Level (SL) IV, NCV of 10 CFR 50.59, Changes, Tests, and Experiments, for the licensees failure to maintain records of written safety evaluations which provide the bases for concluding the nonsafety-related portions of the CCW system inside containment could be credited to perform their function during and following a DBE, and that the change would not result in an unreviewed safety question.1

Description.

The CCW system is discussed in Section 9.3 of the Palisades FSAR.

The CCW system contains both safety-related and nonsafety-related portions. The portions of the system inside containment are classified as nonsafety-related, and are not seismically qualified. The portions of CCW inside containment were originally designed to automatically isolate from the rest of CCW. The original FSAR, Section 9.3.1, [Component Cooling System] Design Bases stated:

The parts of the system located inside containment are isolated in the event of a DBA. The remainder of the system, including pumps and heat exchangers, is located outside containment. The portion of the system located outside containment is designed to Seismic Class 1 requirements and protected from tornadoes.

The CCW system is a closed cycle system which provides cooling water to various SSCs. Although CCW has redundant pumps and heat exchangers, the system's piping is not redundant and a single pipe break or failure of the pressure boundary could result in the complete loss of CCW. Safety functions for the CCW system include:

(1) transferring heat from the reactor and containment to the ultimate heat sink (serving as an intermediate loop);

(2) providing cooling to the ESF pumps; and

(3) serving as part of the containment isolation scheme.

The original licensing bases established a number of CCW SR valves as CIVs. For the supply line to containment the valves are: AOV CV-0910 and check valve CK-CC910.

For the return line the valves are: AOVs CV-0911 and CV-0940. These CIVs would automatically close following a SIS actuation. As a result, the nonsafety-related portions of CCW inside containment would automatically isolate from the rest of the system, during a DBE, when an SIS actuation signal was present. This isolation scheme was changed in 1984, and again in 1987. The changes were documented under facility change documents FC-452-2 and FC-657, respectively. The current isolation scheme no longer isolates the nonsafety-related CCW inside containment on a SIS, but instead isolates it on a CHP signal.

In 1989-1990, the licensee identified single failures which could render the plant incapable of isolating the nonsafety-related portions of CCW inside containment from the safety-related portions outside of containment. As a result, the entire CCW system could be lost if any of the nonsafety-related portions of CCW inside containment failed.

This vulnerability was originally documented in LER 89-006, CCW Availability Following a HELB. To resolve the concern, the licensee performed a series of evaluations and 1 It is important to note that until 1999 the 10 CFR Part 50 Section 59 rule was different than the current version. As a result; the inspectors evaluated the licensees activities against the version in effect at the time the changes in question were performed.

concluded the nonsafety-related portions of CCW inside containment were not vulnerable to failure (except following a seismic event). As a result, the licensee decided to credit the nonsafety-related portions of CCW inside containment as not being vulnerable to failure during a DBE (except during a seismic event). This was a new licensing bases for Palisades, and an FSAR update was processed under FSAR Change No. 5-39-RII-391 on August 21, 1990. The current version of FSAR Section 9.3 (Revision 29) discusses the HELB concern regarding CCW inside containment in Section 9.3.2.3.

In July 27, 1990, the FSAR change was evaluated for 50.59 implications under Unreviewed Safety Question Evaluation 90-1063. The evaluation concluded no NRC-approval was required prior to implementing the change. The evaluation, however, failed to recognize the change could increase the probability of malfunction of equipment important to safety. Specifically, the licensee answered No to Question 3 of Evaluation 90-1063,Section I, which asked, Will the probability of malfunctions of equipment important to safety be increased? The inspectors determined that, as a result of the change, in order for the safety-related portions of CCW to perform their design bases function, the pressure boundary of the nonsafety-related/non-seismic CCW portions inside containment (i.e., piping, relief valve, heat exchangers, etc.)

must remain intact during and following a DBE. In other words, the change made the probability of malfunction of the safety-related portions of CCW dependent on the proper functioning of the nonsafety-related portions of CCW inside containment. The nonsafety-related portions are not maintained, evaluated or tested to the same quality assurance standards as the safety-related portions. The inspectors concluded the licensee failed to provide the bases for determining the change would not result in an unreviewed safety question as defined in 10 CFR 50.59(a)(2). The 50.59 rule required licensees to submit a license amendment request for changes deemed to be unreviewed safety questions.

In addition to the changes discussed above, in 1999, the licensee re-classified the containment penetrations associated with CCW. The penetrations were MZ-14 and MZ-15, CCW supply and return from containment, respectively. These penetrations are part of the containment isolation system, which is discussed in Section 6.7 of the FSAR. The new containment isolation scheme relies on the nonsafety-related pressure boundary of CCW inside containment, and one CIV per penetration (CK-CC910 and AOV CV-0911). In July 22, 1999, this change was evaluated under 10 CFR 50.59, Unreviewed Safety Question Evaluation SDR-99-0884. The evaluation also concluded no NRC-approval was required prior to implementing the change.

However, similar to the discussion above, the licensee failed to recognize the increased probability of malfunction of the safety-related containment isolation system in Section I.3 of the evaluation. Specifically, the change made the containment isolation design bases safety function dependent on the nonsafety-related/non-seismic CCW SSCs' pressure boundary inside containment, thereby requiring these nonsafety-related components to remain functional during and following a DBE. Each penetration went from having two safety-related components as the containment isolation barrier to one safety-related component and one nonsafety-related barrier. As described previously, nonsafety-related components are not maintained, evaluated or tested to the same quality assurance standards as the safety-related portions. These quality standards ensure safety-related SSCs can be relied upon to perform their function during and following a DBE. The inspectors concluded the licensee failed to provide the bases for determining the change would not result in an unreviewed safety question as defined in 10 CFR 50.59(a)(2). The 50.59 rule required licensees to submit a license amendment request for changes deemed to be unreviewed safety questions.

The inspectors concluded the changes made in 1990 and 1999, violated the requirements of 10 CFR 50.59. The underlying technical concern associated with this violation resulted in a Green finding and an additional NCV of 10 CFR Part 50, Appendix B, Criterion II, Quality Assurance Program. The finding was documented in this report under 05000255/2015004-02, Failure to Identify Components Required to be Covered by the Quality Assurance Program. The licensee documented the inspectors concerns in the CAP as CR-PLP-2015-01872 and CR-PLP-2015-05468.

Analysis.

The inspectors determined the licensee failed to maintain records of written safety evaluations which provided the bases for the conclusion that nonsafety-related portions of CCW could be credited to perform their function during and following a DBE, and that this change would not result in an unreviewed safety question. This was contrary to 10 CFR 50.59(b)(1), and was a violation of regulatory requirements.

Specifically, the licensee did not provide the bases to explain why crediting the nonsafety-related portions of CCW inside containment to perform their function would not result in an increase in the probability of malfunction of the safety-related CCW or safety-related containment isolation systems. A bases is essential for crediting the nonsafety-related SSCs because they are not maintained to the same design, fabrication, construction, and testing quality standards as safety-related SSCs.

The violation of 10 CFR 50.59 was determined to be more than minor because the inspectors could not reasonably determine that the changes would not have ultimately required NRC prior approval. Violations of 10 CFR 50.59 are dispositioned using the traditional enforcement process instead of the SDP because they are considered to be violations that potentially impede or impact the regulatory process. This violation is associated with a finding that has been evaluated by the SDP and communicated with an SDP color reflective of the safety impact of the deficient licensee performance.

The SDP, however, does not specifically consider the regulatory process impact. Thus, although related to a common regulatory concern, it is necessary to address the violation and finding using different processes to correctly reflect both the regulatory importance of the violation and the safety significance of the associated finding.

In this case, the inspectors determined the underlying technical concern resulted in a Green finding. The details of the finding and its significance determination were documented in this report as05000255/2015004-02, Failure to Identify Components Required to be Covered by the Quality Assurance Program.

In accordance with Section 6.1.d.2 of the NRC Enforcement Policy, this violation was categorized as a SL IV because the resulting changes were evaluated by the SDP as having very low safety significance (i.e., Green finding).

Cross-cutting aspects are not assigned to traditional enforcement violations.

Enforcement.

The version of the 10 CFR 50.59 rule, in effect, in 1990 and 1999, was different than the current version. At the time, 10 CFR 50.59(b)(1) required, in part, that the licensee shall maintain records of tests and experiments carried out pursuant to paragraph

(a) of the section. These records must include a written safety evaluation which provides the bases for the determination that the change, test, or experiment does not involve an unreviewed safety question. In addition, 10 CFR 50.59(c)(2) stated, in part, that a licensee desiring to make a change in the facility or the procedures described in the safety analysis report or to conduct tests or experiments not described in the safety analysis report, which involve an unreviewed safety question or a change in technical specifications, shall submit an application for amendment of his license pursuant to 10 CFR 50.90. In accordance with 10 CFR 50.59(a)(2), a change was deemed to involve an unreviewed safety question if the probability of occurrence or the consequences of an accident or malfunction of equipment important to safety previously evaluated in the safety analysis report may be increased.

Contrary to the above, on July 27, 1990, and July 22, 1999, the licensee failed to maintain records of written safety evaluations which provided the basis for determining the changes did not involve an unreviewed safety question, as defined in 10 CFR 50.59(a)(2), and would not require a license amendment pursuant to 10 CFR 50.90. Specifically:

• Palisades' Unreviewed Safety Question Evaluation 90-1063,Section I.3, failed to provide the basis for determining there was no increased probability of malfunction of the safety-related portions of CCW, which are equipment important to safety. Particularly, the change made the ability of the safety-related portions of CCW to perform their function dependent on the ability of the nonsafety-related portions of CCW inside containment to maintain their pressure boundary; and

• Palisades' Unreviewed Safety Question Evaluation 99-0884,Section I.3, failed to provide the basis for determining there was no increased probability of malfunction of the safety-related containment isolation system, which is equipment important to safety. Particularly, the change made the ability of the safety-related containment isolation system to perform its function dependent on the ability of nonsafety-related portions of CCW inside containment to maintain their pressure boundary.

The nonsafety-related CCW components inside containment are not maintained to the same design, fabrication, construction, and testing quality standards as safety-related components. Quality assurance standards ensure safety-related SSCs can be relied upon to perform their function during and following a DBE. In accordance with Section 6.1.d.2 of the NRC Enforcement Policy, this violation of 10 CFR 50.59 is classified as a SL IV Violation. The Enforcement Policy classifies violations of 10 CFR 50.59 as SL IV if the resulting conditions are evaluated by the SDP as having a very low safety significance (i.e., Green).

This violation is being treated as an NCV, consistent with Section 2.3.2 of the Enforcement Policy because it was a SL IV violation and was entered into the licensees CAP as CR-PLP-2015-01872 and CR-PLP-2015-05468. As part of their immediate corrective actions, the licensee performed operability determinations which concluded the system would still be capable of performing its function.

(NCV 05000255/2015004-03; Failure to Provide Bases to Determine Changes Did Not Involve Unreviewed Safety Questions)

(3) Failure to Perform a Required 50.59 Evaluation for Declassification of the Chemical and Volume Control System

Introduction.

The inspectors identified a SL IV, NCV of 10 CFR 50.59, Changes, Tests, and Experiments, and an associated finding of very-low safety significance (Green) for the licensees failure to maintain a record of a change in the facility which includes a written evaluation that provides the bases for the determination that the change did not require a license amendment. Specifically, the licensee failed to maintain a record of the declassification of the Chemical and Volume Control System (CVCS) from safety-related to nonsafety-related, which includes a written evaluation that provides the bases for the determination that the change did not require a license amendment pursuant to paragraph (c)(2)(ii) of 10 CFR 50.59, because it did not result in more than a minimal increase in the likelihood of occurrence of a malfunction of the system as previously evaluated in Sections 5.1, 5.2, and 1.8.5 of the FSAR.

Description.

FSAR Section 5.1 discusses Palisades compliance with the NRC General Design Criteria (GDC) that were in place at the time the plant was licensed. FSAR Section 5.1.2.2, Criterion 2 - Design Bases for Protection Against Natural Phenomena, describes Palisades compliance with GDC 2. It states that, this criterion has been met by designing, fabricating and erecting those SSCs important to safety to withstand the effects of extraordinary natural phenomena. A seismic event is one of the natural phenomena events discussed in GDC 2, which the licensee is required cope with. At Palisades, the CVCS is one of the systems credited to achieve and maintain a safe shutdown condition following a seismic event, and hence it is required to meet GDC 2 for Palisades.

Originally, the CVCS was considered a Consumers Design Class 1 system.

As discussed in FSAR Section 5.2.1.2, Original Palisades Design Review, Consumers Design Class is a combination of Safety Class and Seismic Class. In FSAR Section 5.2.2.1, Design - Class 1, describes Consumers Design Class 1 by stating that, Class 1 systems and components were designed for functional dependability following an earthquake by using the load combinations in Section 5.10.1.

Class 1 systems and components are always Seismic Category I equivalents in current design practice, however, they may be equivalent to ASME Boiler and Pressure Vessel (B&PV) Class 1, 2 or 3. Class 1 systems could also be Safety Class 1, 2 or 3 per American National Standards Institute (ANSI) N18.2-1973. Table 5.2-3 identifies systems' classification and industrial design codes utilized. Therefore, the seismic classification of the CVCS was originally considered equivalent to Seismic Category I.

In December of 1980, the NRC initiated Unresolved Safety Issue (USI) A-46, Seismic Qualification of Equipment in Operating Nuclear Plants, because equipment in nuclear plants for which construction permit applications had been docketed before about 1972 had not been reviewed according to the then-current (1980-1981), licensing criteria for seismic qualification of equipment. Therefore, the seismic adequacy of the equipment in these older plants and the equipments ability to survive and function in the event of a safe shutdown earthquake (SSE) was in question. Palisades was one of the plants for which the concern existed.

On May 19, 1995, Palisades submitted a report, Report of Seismic Qualification Utility Group (SQUG) Assessment at Palisades Nuclear Plant for the Resolution of USI A-46, to resolve NRC USI A-46 for the seismic qualification of equipment at the plant. The report used the SQUG Generic Implementation Procedure (GIP), endorsed by NRC Generic Letter 87-02, Supplement 1, to identify the preferred paths to be used in accomplishing safe shutdown functions following a SSE. Once the preferred paths were identified, specific equipment in the safe shutdown paths was evaluated using the SQUG GIP. The CVCS, also known as the charging system, was credited as part of the preferred paths and the seismic qualification of CVCS equipment was verified in the process. Subsequently, the NRC issued a SER on September 25, 1998, documenting the staffs conclusions on their review of the Palisades SQUG Report and closure of the NRC USI A-46 review for Palisades.

The information on resolution of USI A-46 for Palisades was approved for incorporation into the FSAR in September of 2003, and is discussed in Section 1.8.5 of the FSAR.

That section of the FSAR describes the credit taken by the licensee, since at least 1995, for the CVCS as one of the systems used to attain the safe shutdown condition following a seismic event. Specifically, it describes the design function of the charging system (CVCS) to provide a flow path to, ensure the maintenance of inventory and boron concentration in the primary coolant system while the plant is shutdown following a seismic event. This CVCS design function is further described in the Palisades SQUG Report, which was approved by the NRC SER, and is a part of the current licensing basis for Palisades. The SQUG Report describes the CVCS as part of the safe shutdown paths to accomplish the reactor reactivity control and reactor inventory control safe shutdown functions following a SSE. Therefore, the CVCS, including the charging pumps, has a design function to mitigate the consequences of a seismic event.

Since at least 1995, when the CVCS was credited to mitigate the consequences of a seismic event for resolution of USI A-46, it has been required to meet GDC 2 for Palisades. At that time, the system was classified as a Consumers Design Class 1 system and was considered equivalent to a Seismic Category I system. In addition, the seismic qualification of equipment which formed part of the system had also been verified through the SQUG methodology. The system was also considered safety-related and subject to the QA requirements of 10 CFR 50, Appendix B.

Therefore, at that time, the CVCS met the requirements of GDC 2 for Palisades by having the qualifications described above.

In 2003, the licensee decided to declassify most portions of the CVCS, including the charging pumps, from a safety-related classification to a nonsafety-related classification.

This was done, in part, to resolve an operable but degraded condition of some of the piping in the system. In September 22, 2003, the licensee completed a 10 CFR 50.59 screening, SDR-03-1073, CVCS Declassification, and concluded that the change did not involve adverse effects and therefore, did not require a 10 CFR 50.59 evaluation.

The licensee then proceeded with the change and declassified most portions of the system. The declassification removed all 10 CFR Part 50, Appendix B, QA requirements and ASME Code requirements for most portions of the system. It also removed the seismic qualification requirements for most portions of the system, including the charging pumps. Therefore, the CVCS qualification requirements for meeting GDC 2, as described above, were either entirely removed or significantly reduced.

Through a review of the 10 CFR 50.59 screening, the inspectors noted that the CVCS function for mitigating the consequences of a seismic event was not identified as a design function affected by the change. Therefore, the licensee did not review all CVCS design functions when determining the change did not involve adverse effects.

Per Section 4.2.1 of Nuclear Energy Institute (NEI) 96-07, Revision 1, Guidelines for 10 CFR 50.59 Implementation, endorsed by NRC Regulatory Guide 1.187, Guidance for Implementation of 10 CFR 50.59, Changes, Tests, and Experiments, a change that decreases the reliability of a function whose failure could initiate an accident would be considered to adversely affect a design function and would screen in and require a 10 CFR 50.59 evaluation. It also states that, changes that would relax the manner in which Code requirements are met for certain SSCs should be screened for adverse effects on design function.

Since the declassification of most portions of the CVCS was a change that, among other things, removed QA and Code requirements, the change was a relaxation of Code requirements that could be reasonably viewed as an adverse change that could decrease the reliability of the system. In addition, since the seismic qualification requirements for the system were also removed, the change could be reasonably viewed as an adverse change because the system was no longer required to be qualified for the external event (seismic event) it is credited for to get the plant to a safe shutdown condition. Had the licensee identified the design function of the CVCS to mitigate the consequences of a seismic event, they would have had to evaluate whether the changes made to the system adversely affected the design function. As described above, the inspectors determined the changes made to the system could be reasonably viewed as adverse changes, and therefore the licensee was required to perform a 10 CFR 50.59 evaluation. It is worth noting that although the plant has other means of getting the plant to a safe shutdown condition following a SSE, the equipment in those paths was not seismically verified as part of the resolution for USI A-46, and cannot be credited following a SSE.

The inspectors reviewed the requirement in 10 CFR 50.59(c)(2)(ii) for determining whether a change results in more than a minimal increase in the likelihood of occurrence of a malfunction of a SSC important to safety previously evaluated in the FSAR (as updated). The inspectors also reviewed the guidance in NEI 96-07 for making that determination. Section 4.3.2 of NEI 96-07 states that, departures from the design, fabrication, construction, testing and performance standards as outlined in the GDC (Appendix A to Part 50) are not compatible with a no more than minimal increase standard. Since the declassification of the system resulted in a departure from the licensees original compliance with GDC 2, the change could be reasonably viewed as resulting in a more than a minimal increase in the likelihood of occurrence of a malfunction of the important to safety CVCS.

In addition, Section 4.3.2 of NEI 96-07 states that, changes in design requirements for earthquakes, tornadoes, and other natural phenomena should be treated as potentially affecting the likelihood of malfunction. Since the licensee changed the design requirements of the CVCS for a seismic event, the change could again be reasonably viewed as a change resulting in a more than a minimal increase in the likelihood of the systems malfunction.

Based on the information described above, the inspectors determined that the licensee failed to provide a written evaluation which provided the bases for the determination that the change, reclassification of the CVCS, did not require a license amendment pursuant to 10 CFR 50.59(c)(2). The inspectors could not reasonably determine that the change made would not have ultimately required NRC prior approval, because it could be reasonably viewed as a change which caused a more than a minimal increase in the likelihood of occurrence of a malfunction of the CVCS.

The licensee captured the inspectors concern in the CAP as condition report CR-PLP-2015-01873. The licensees immediate corrective actions included a review of the system and determination that there was reasonable assurance that it could perform its function because its configuration had not been altered to remove features which would allow its operation following a seismic event.

Analysis.

Violations of 10 CFR 50.59 can be dispositioned using both the traditional enforcement process and the SDP because in addition to being violations that potentially impede or impact the NRCs ability to perform its regulatory oversight function, they may be associated with underlying technical issues that have potential safety significance.

First, the underlying technical issue is evaluated to determine whether its a finding, and if so, an SDP color reflective of its safety significance is determined. Then, because the SDP does not specifically consider the regulatory process impact, the findings safety significance is used to assign a traditional enforcement SL using Section 6.1, Reactor Operations, of the NRC Enforcement Policy. Thus, although related to a common regulatory concern, it is necessary to address the traditional enforcement violation and finding using different processes to correctly reflect both the regulatory importance of the violation and the safety significance of the associated finding.

To evaluate the issue of concern using the SDP process, the inspectors first determined that the change to the CVCS safety classification was contrary to 10 CFR 50.59(d)(1)and was a performance deficiency. Specifically, the licensee failed to provide the bases for the determination that the declassification of the CVCS, the change in its seismic design requirements, and the removal of quality standards for design, fabrication, and testing of the system did not result in more than a minimal increase in the likelihood of occurrence of a malfunction of the system and did not require a license amendment.

The inspectors determined that the performance deficiency was more than minor because, if left uncorrected, it would become a more significant safety concern.

Specifically, the failure to maintain seismic qualification requirements and other quality requirements which control the design, fabrication, and testing quality standards for the CVCS could result in changes being implemented which affect the ability of the charging system to successfully respond to and mitigate the effects of a seismic event. The inspectors concluded this finding was associated with the Mitigating Systems cornerstone.

The inspectors also determined that the issue of concern described above was a traditional enforcement violation because it was a violation of 10 CFR 50.59 and was considered to potentially impede or impact the NRCs ability to perform its regulatory oversight function. The traditional enforcement violation was determined to be more than minor because the inspectors could not reasonably determine that the change made, reclassification of the CVCS, would not have ultimately required NRC prior approval.

The inspectors determined the finding described above could be evaluated using the SDP in accordance with IMC 0609, SDP, issue date April 29, 2015, 0609.04, Initial Characterization of Findings, issue date June 19, 2012.

Because the finding impacted the Mitigating Systems cornerstone, the inspectors screened the finding through IMC 0609 Appendix A, The SDP for Findings At-Power, issue date June 19, 2012, using Exhibit 2, Mitigating Systems Screening Questions, and answered yes to Question A.1. The finding screened as having very low safety significance (Green) because although it affected the design or qualification of the CVCS, it did not result in the loss of functionality of the CVCS. Specifically, the licensee determined that although the CVCS components were declassified, no physical changes or modifications had been implemented, which affected the SSCs ability to perform its mitigating function following a seismic event.

In accordance with Section 6.1.d.2, Reactor Operations, of the NRC Enforcement Policy this violation is categorized as SL IV because the resulting changes were evaluated by the SDP as having very low safety significance (i.e., green finding).

The inspectors did not identify a cross-cutting aspect associated with the finding because the finding was not representative of current performance. Specifically, the declassification of the CVCS was completed in 2003.

Enforcement.

Title 10 CFR Part 50.59, Changes, Tests, and Experiments, Section (d)(1) requires the licensee to maintain records of changes in the facility, of changes in procedures, and of tests and experiments made pursuant 10 CFR 50.59(c).

These records must include a written evaluation which provides the bases for the determination that the change, test, or experiment does not require a license amendment pursuant to paragraph (c)(2) of the section.

Title 10 CFR Part 50.59 (c)(2)(ii) states, in part, that a licensee shall obtain a license amendment pursuant to 10 CFR 50.90 prior to implementing a proposed change, test, or experiment if the change, test, or experiment would result in more than a minimal increase in the likelihood of occurrence of a malfunction of a SSC important to safety previously evaluated in the FSAR (as updated).

FSAR Section 5.1.2.2, Criterion 2 - Design Bases for Protection Against Natural Phenomena, describes Palisades compliance with draft GDC 2. It states that, this criterion has been met by designing, fabricating and erecting those SSCs important to safety to withstand the effects of extraordinary natural phenomena.

FSAR Section 5.2.2.1, Design - Class 1 states that, Class 1 systems and components were designed for functional dependability following an earthquake by using the load combinations in Section 5.10.1. Class 1 systems and components are always Seismic Category I equivalents in current design practice, however, they may be equivalent to ASME B&PV Class 1, 2 or 3. Class 1 systems could also be Safety Class 1, 2 or 3 per ANSI N18.2-1973. Table 5.2-3 identifies systems' classification and industrial design codes utilized. FSAR Section 1.8.5, USI (NUREG-0410), describes a design function of the charging system [CVCS] to provide a flow path, to ensure the maintenance of inventory and boron concentration in the primary coolant system while the plant is shutdown following a seismic event.

Contrary to the above, since September 22, 2003, the licensee failed to maintain a record of a change in the facility which includes a written evaluation that provides the bases for the determination that the change did not require a license amendment pursuant to paragraph (c)(2) of 10 CFR 50.59. Specifically, the licensee failed to maintain a record of the declassification of the CVCS from safety-related to nonsafety-related, which included a written evaluation that provided the bases for the determination that the change did not require a license amendment pursuant to paragraph (c)(2)(ii) of 10 CFR 50.59 because it did not result in more than a minimal increase in the likelihood of occurrence of a malfunction of the system as previously evaluated in Sections 5.1, 5.2 and 1.8.5 of the FSAR. In particular, by declassifying the CVCS and removing seismic qualification and quality requirements, the system was no longer subject to the original and more stringent requirements that ensured any maintenance and/or changes were performed in a quality manner so as to maintain the CVCS design function for mitigating a seismic event.

This violation is being treated as an NCV, consistent with Section 2.3.2 of the Enforcement Policy because it was a SL IV violation and was entered into the licensees CAP as CR-PLP-2015-01873. As part of the immediate corrective actions, the licensee performed a review of the system, and determined there was reasonable assurance the CVCS could perform its function because its configuration had not been altered to remove features which would allow its operation following a seismic event.

(NCV 05000255/2015004-04; Failure to Perform a Required 50.59 Evaluation for Declassification of the CVCS).

1R22 Surveillance Testing

a. Inspection Scope

The inspectors reviewed the test results for the following activities to determine whether risk-significant systems and equipment were capable of performing their intended safety function and to verify testing was conducted in accordance with applicable procedural and TS requirements:

• RT-8C, left train Engineered Safeguards system integrated testing (routine);

• RT-36, Containment leak test (routine);

• RO-12, Containment High Pressure and Spray test (routine);

• RT-191, Low Power Physics testing (routine);

• QO-21A, A Auxiliary Feedwater pump in-service testing (IST); and

• RO-19, Control Rod Drive position verification test (routine).

The inspectors observed in-plant activities and reviewed procedures and associated records to determine the following:

• did preconditioning occur;

• were the effects of the testing adequately addressed by control room personnel or engineers prior to the commencement of the testing;

• were acceptance criteria clearly stated, sufficient to demonstrate operational readiness, and consistent with the system design basis;

• was plant equipment calibration correct, accurate, and properly documented;

• were as-left setpoints within required ranges, and was the calibration frequency in accordance with TSs, the UFSAR, plant procedures, and applicable commitments;

• was measuring and test equipment calibration current;

• was the test equipment used within the required range and accuracy and were applicable prerequisites described in the test procedures satisfied;

• did test frequencies meet TS requirements to demonstrate operability and reliability;

• were tests performed in accordance with the test procedures and other applicable procedures;

• were jumpers and lifted leads controlled and restored where used;

• were test data and results accurate, complete, within limits, and valid;

• was test equipment removed following testing;

• where applicable for inservice testing activities, was testing performed in accordance with the applicable version of Section XI of the ASME Code, and were reference values consistent with the system design basis;

• was the unavailability of the tested equipment appropriately considered in the performance indicator (PI) data;

• where applicable, were test results not meeting acceptance criteria addressed with an adequate operability evaluation, or was the system or component declared inoperable;

• where applicable for safety-related instrument control surveillance tests, was the reference setting data accurately incorporated into the test procedure;

• was equipment returned to a position or status required to support the performance of its safety function following testing;

• were all problems identified during the testing appropriately documented and dispositioned in the licensees CAP;

• where applicable, were annunciators and other alarms demonstrated to be functional and were annunciator and alarm setpoints consistent with design documents; and

• where applicable, were alarm response procedure entry points and actions consistent with the plant design and licensing documents.

Documents reviewed are listed in the Attachment to this report.

This inspection constituted five routine surveillance testing samples and one in-service test sample as defined in IP 71111.22, Sections-02 and-05.

b. Findings

No findings were identified.

1EP4 Emergency Action Level and Emergency Plan Changes (IP 71114.04)

a. Inspection Scope

The regional inspectors performed an in-office review of the latest revisions to the Emergency Plan, Emergency Action Levels (EALs).

The licensee transmitted the Emergency Plan and EAL revisions to the NRC pursuant to the requirements of 10 CFR, Part 50, Appendix E,Section V, Implementing Procedures." The NRC review was not documented in a safety evaluation report and did not constitute approval of licensee-generated changes, therefore, this revision is subject to future inspection.

This EAL and Emergency Plan Changes inspection constituted one sample as defined in Inspection Procedure 71114.04.

b. Findings

No findings were identified.

2RS1 Radiological Hazard Assessment and Exposure Controls

This inspection constituted one complete sample as defined in IP 71124.01-05.

.1 Inspection Planning (02.01)

a. Inspection Scope

The inspectors reviewed all licensee performance indicators for the Occupational Exposure Cornerstone for follow-up. The inspectors reviewed the results of radiation protection program audits (e.g., licensees quality assurance audits or other independent audits). The inspectors reviewed any reports of operational occurrences related to occupational radiation safety since the last inspection. The inspectors reviewed the results of the audit and operational report reviews to gain insights into overall licensee performance.

b. Findings

No findings were identified.

.2 Radiological Hazard Assessment (02.02)

a. Inspection Scope

The inspectors determined if there have been changes to plant operations since the last inspection that may result in a significant new radiological hazard for onsite workers or members of the public. The inspectors evaluated whether the licensee assessed the potential impact of these changes and has implemented periodic monitoring, as appropriate, to detect and quantify the radiological hazard.

The inspectors reviewed the last two radiological surveys from selected plant areas and evaluated whether the thoroughness and frequency of the surveys were appropriate for the given radiological hazard.

The inspectors conducted walkdowns of the facility, including radioactive waste processing, storage, and handling areas to evaluate material conditions and performed independent radiation measurements to verify conditions.

The inspectors selected the following radiologically risk-significant work activities that involved exposure to radiation:

• 1R24 Radiography activities;

• Refuel Project: Incore Instrumentation (ICI) installation/removal;

• Pressurizer Spray Control Valves, CV-1057 & CV-1059;

• Refuel Project: Replace proximity switches on Reactor side Tilt Machine and remove debris for Reactor Tilt Pit; and

• Steam Generator inspections and repairs (Primary side).

For these work activities, the inspectors assessed whether the pre-work surveys performed were appropriate to identify and quantify the radiological hazard and to establish adequate protective measures. The inspectors evaluated the radiological survey program to determine if hazards were properly identified, including the following:

• identification of hot particles;

• the presence of alpha emitters;

• the potential for airborne radioactive materials, including the potential presence of transuranics and/or other hard-to-detect radioactive materials (This evaluation may include licensee planned entry into non-routinely entered areas subject to previous contamination from failed fuel.);

• the hazards associated with work activities that could suddenly and severely increase radiological conditions and that the licensee has established a means to inform workers of changes that could significantly impact their occupational dose; and

• severe radiation field dose gradients that can result in non-uniform exposures of the body.

The inspectors observed work in potential airborne areas and evaluated whether the air samples were representative of the breathing air zone. The inspectors evaluated whether continuous air monitors were located in areas with low background to minimize false alarms and were representative of actual work areas. The inspectors evaluated the licensees program for monitoring levels of loose surface contamination in areas of the plant with the potential for the contamination to become airborne.

b. Findings

No findings were identified.

.3 Instructions to Workers (02.03)

a. Inspection Scope

The inspectors selected various containers holding non-exempt licensed radioactive materials that may cause unplanned or inadvertent exposure of workers, and assessed whether the containers were labeled and controlled in accordance with 10 CFR, Part 20.1904, Labeling Containers, or met the requirements of 10 CFR 20.1905(g),

Exemptions To Labeling Requirements.

The inspectors reviewed the following radiation work permits (RWPs) used to access high radiation areas and evaluated the specified work control instructions or control barriers:

• RWP 20150487: 1R24 Radiography Activities;

• RWP 20150429: Refuel Project: ICI Installation/Removal;

• RWP 20150468: Pressurizer Spray Control Valves CV-1057 & CV-1059;

• RWP 20150431: Refuel Project: Replace Proximity Switches on Reactor Side Tilt Machine and Remove Debris for Reactor Tilt Pit; and

• RWP 20150454: Steam Generator Inspections and Repairs (Primary Side).

For these RWPs, the inspectors assessed whether allowable stay times or permissible dose (including from the intake of radioactive material) for radiologically significant work under each RWP were clearly identified. The inspectors evaluated whether electronic personal dosimeter alarm set-points were in conformance with survey indications and plant policy.

The inspectors reviewed selected occurrences where a workers electronic personal dosimeter noticeably malfunctioned or alarmed. The inspectors evaluated whether workers responded appropriately to the off-normal condition. The inspectors assessed whether the issue was included in the CAP, and dose evaluations were conducted as appropriate.

For work activities that could suddenly and severely increase radiological conditions, the inspectors assessed the licensees means to inform workers of changes that could significantly impact their occupational dose.

b. Findings

No findings were identified.

.4 Contamination and Radioactive Material Control (02.04)

a. Inspection Scope

The inspectors observed locations where the licensee monitors potentially contaminated material leaving the radiological control area and inspected the methods used for control, survey, and release from these areas. The inspectors observed the performance of personnel surveying and releasing material for unrestricted use and evaluated whether the work was performed in accordance with plant procedures and whether the procedures were sufficient to control the spread of contamination and prevent unintended release of radioactive materials from the site. The inspectors assessed whether the radiation monitoring instrumentation had appropriate sensitivity for the type(s) of radiation present.

The inspectors reviewed the licensees criteria for the survey and release of potentially contaminated material. The inspectors evaluated whether there was guidance on how to respond to an alarm that indicates the presence of licensed radioactive material.

The inspectors reviewed the licensees procedures and records to verify that the radiation detection instrumentation was used at its typical sensitivity level based on appropriate counting parameters. The inspectors assessed whether or not the licensee has established a de facto release limit by altering the instruments typical sensitivity through such methods as raising the energy discriminator level or locating the instrument in a high-radiation background area.

The inspectors selected several sealed sources from the licensees inventory records and assessed whether the sources were accounted for and verified to be intact.

The inspectors evaluated whether any transactions, since the last inspection, involving nationally tracked sources were reported in accordance with 10 CFR 20.2207.

b. Findings

No findings were identified.

.5 Radiological Hazards Control and Work Coverage (02.05)

a. Inspection Scope

The inspectors evaluated ambient radiological conditions (e.g., radiation levels or potential radiation levels) during tours of the facility. The inspectors assessed whether the conditions were consistent with applicable posted surveys, RWPs, and worker briefings.

The inspectors evaluated the adequacy of radiological controls, such as required surveys, radiation protection job coverage (including audio and visual surveillance for remote job coverage), and contamination controls. The inspectors evaluated the licensees use of electronic personal dosimeters in high-noise areas as high-radiation area monitoring devices.

The inspectors assessed whether radiation monitoring devices were placed on the individuals body consistent with licensee procedures. The inspectors assessed whether the dosimeter was placed in the location of highest expected dose or that the licensee properly employed an NRC-approved method of determining effective dose equivalent.

The inspectors reviewed the application of dosimetry to effectively monitor exposure to personnel in high-radiation work areas with significant dose rate gradients.

The inspectors reviewed the following RWPs for work within airborne radioactivity areas with the potential for individual worker internal exposures:

• RWP 20150429; Refuel Project: ICI Installation/ Removal;

• RWP 20150468; Pressurizer Spray Control Valves CV-1057 & CV-1059;

• RWP 20150431; Refuel Project: Replace Proximity Switches on Reactor Side Tilt Machine and Remove Debris for Reactor Tilt Pit; and

• RWP 20150454; Steam Generator Inspections and Repairs (Primary Side).

For these RWPs, the inspectors evaluated airborne radioactive controls and monitoring, including potential for significant airborne levels (e.g., grinding, grit blasting, system breaches, entry into tanks, cubicles, and reactor cavities). The inspectors assessed barrier (e.g., tent or glove box) integrity and temporary high-efficiency particulate air ventilation system operation.

The inspectors examined the licensees physical and programmatic controls for highly activated or contaminated materials (i.e., nonfuel) stored within spent fuel and other storage pools. The inspectors assessed whether appropriate controls (i.e.,

administrative and physical controls) were in place to preclude inadvertent removal of these materials from the pool.

The inspectors examined the posting and physical controls for selected high-radiation areas and very-high radiation areas to verify conformance with the occupational performance indicator.

b. Findings

No findings were identified.

.6 Risk-Significant High-Radiation Area and Very-High Radiation Area Controls (02.06)

a. Inspection Scope

The inspectors discussed with the radiation protection manager the controls and procedures for high-risk, high-radiation areas and very-high radiation areas. The inspectors discussed methods employed by the licensee to provide stricter control of very-high radiation area access as specified in 10 CFR 20.1602, Control of Access to Very-High Radiation Areas, and Regulatory Guide 8.38, Control of Access to High and Very-High Radiation Areas of Nuclear Plants. The inspectors assessed whether any changes to licensee procedures substantially reduce the effectiveness and level of worker protection.

The inspectors discussed the controls in place for special areas that have the potential to become very-high radiation areas during certain plant operations with first-line health physics supervisors (or equivalent positions having backshift health physics oversight authority). The inspectors assessed whether these plant operations require communication beforehand with the health physics group, so as to allow corresponding timely actions to properly post, control, and monitor the radiation hazards including re-access authorization.

The inspectors evaluated licensee controls for very-high radiation areas and areas with the potential to become a very-high radiation areas to ensure that an individual was not able to gain unauthorized access to the very high radiation areas.

b. Findings

No findings were identified.

.7 Radiation Worker Performance (02.07)

a. Inspection Scope

The inspectors observed radiation worker performance with respect to stated radiation protection work requirements. The inspectors assessed whether workers were aware of the radiological conditions in their workplace and the RWP controls/limits in place, and whether their performance reflected the level of radiological hazards present.

The inspectors reviewed radiological problem reports since the last inspection that found the cause of the event to be human performance errors. The inspectors evaluated whether there was an observable pattern traceable to a similar cause. The inspectors assessed whether this perspective matched the corrective action approach taken by the licensee to resolve the reported problems. The inspectors discussed with the radiation protection manager any problems with the corrective actions planned or taken.

b. Findings

No findings were identified.

.8 Radiation Protection Technician Proficiency (02.08)

a. Inspection Scope

The inspectors observed the performance of the radiation protection technicians with respect to all RWP requirements. The inspectors evaluated whether technicians were aware of the radiological conditions in their workplace and the RWP controls/limits, and whether their performance was consistent with their training and qualifications with respect to the radiological hazards and work activities.

The inspectors reviewed radiological problem reports since the last inspection that found the cause of the event to be radiation protection technician error. The inspectors evaluated whether there was an observable pattern traceable to a similar cause. The inspectors assessed whether this perspective matched the corrective action approach taken by the licensee to resolve the reported problems.

b. Findings

No findings were identified.

.9 Problem Identification and Resolution (02.09)

a. Inspection Scope

The inspectors evaluated whether problems associated with radiation monitoring and exposure control were being identified by the licensee at an appropriate threshold and were properly addressed for resolution in the licensees CAP. The inspectors assessed the appropriateness of the corrective actions for a selected sample of problems documented by the licensee that involve radiation monitoring and exposure controls.

The inspectors assessed the licensees process for applying operating experience to their plant.

b. Findings

No findings were identified.

2RS2 Occupational As-Low-As-Reasonably-Achievable Planning and Controls

The inspection activities supplement those documented in IR 05000255/2014002, and constitute one complete sample as defined in IP 71124.02-05.

.1 Inspection Planning (02.01)

a. Inspection Scope

The inspectors reviewed pertinent information regarding plant collective exposure history, current exposure trends, and ongoing or planned activities in order to assess current performance and exposure challenges. The inspectors reviewed the plants 3-year rolling average collective exposure.

The inspectors reviewed the site-specific trends in collective exposures and source term measurements.

The inspectors reviewed site-specific procedures associated with maintaining occupational exposures as-low-as-reasonably-achievable, which included a review of processes used to estimate and track exposures from specific work activities.

b. Findings

No findings were identified.

.2 Source Term Reduction and Control (02.04)

a. Inspection Scope

The inspectors used licensee records to determine the historical trends and current status of significant tracked plant source terms known to contribute to elevated facility aggregate exposure. The inspectors assessed whether the licensee had made allowances or developed 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.

b. Findings

No findings were identified.

2RS4 Occupational Dose Assessment

The inspection activities supplement those documented in IRs 05000255/2014004; 05000255/2015011; and constitute one complete sample as defined in IP 71124.04-05.

.1 Special Dosimetric Situations (02.04)

Assigning Dose of Record

a. Inspection Scope

For the special dosimetric situations reviewed in this section, the inspectors assessed how the licensee assigns dose of record for total effective dose equivalent, shallow dose equivalent, and lens dose equivalent. This included an assessment of external and internal monitoring results, supplementary information on Individual exposures (e.g.,

radiation incident investigation reports and skin contamination reports), and radiation surveys and/or air monitoring results when dosimetry was based on these techniques.

b. Findings

No findings were identified.

OTHER ACTIVITIES

Cornerstones: Initiating Events, Mitigating Systems, Barrier Integrity, Emergency Preparedness, Public Radiation Safety, Occupational Radiation Safety, and Security

4OA1 Performance Indicator Verification

.1 Mitigating Systems Performance IndexEmergency AC Power System

a. Inspection Scope

The inspectors sampled licensee submittals for the Mitigating Systems Performance Index (MSPI) - Emergency AC Power System (MS06) performance indicator (PI) for the period from the fourth quarter 2014 through the third quarter 2015. To determine the accuracy of the PI data reported during those periods, PI definitions and guidance contained in the NEI Document 99-02, Regulatory Assessment Performance Indicator Guideline, Revision 7, dated August 31, 2013, were used. The inspectors reviewed the licensees operator narrative logs, MSPI derivation reports, issue reports, event reports and NRC Integrated Inspection Reports for the period of October 1, 2014, through September 30, 2015, to validate the accuracy of the submittals. The inspectors reviewed the MSPI component risk coefficient to determine if it had changed by more than 25 percent in value since the previous inspection, and if so, that the change was in accordance with applicable NEI guidance. The inspectors also reviewed the licensees issue report database to determine if any problems had been identified with the PI data collected or transmitted for this indicator. Documents reviewed are listed in the to this report.

This inspection constituted one MSPI emergency AC power system sample as defined in IP 71151-05.

b. Findings

No findings were identified.

.2 Mitigating Systems Performance IndexCooling Water Systems

a. Inspection Scope

The inspectors sampled licensee submittals for the MSPI - Cooling Water Systems (MS10) PI for the period from the fourth quarter 2014 through the third quarter 2015.

To determine the accuracy of the PI data reported during those periods, PI definitions and guidance contained in NEI 99-02, Regulatory Assessment Performance Indicator Guideline, Revision 7, dated August 31, 2013, were used. The inspectors reviewed the licensees operator narrative logs, issue reports, MSPI derivation reports, event reports and NRC Integrated Inspection Reports for the period of October 1, 2014, through September 30, 2015, to validate the accuracy of the submittals. The inspectors reviewed the MSPI component risk coefficient to determine if it had changed by more than 25 percent in value since the previous inspection, and if so, that the change was in accordance with applicable NEI guidance. The inspectors also reviewed the licensees issue report database to determine if any problems had been identified with the PI data collected or transmitted for this indicator. Documents reviewed are listed in the to this report.

This inspection constituted one MSPI cooling water systems sample as defined in IP 71151-05.

b. Findings

No findings were identified.

4OA2 Identification and Resolution of Problems

.1 Routine Review of Items Entered into the Corrective Action Program

a. Inspection Scope

As part of the various baseline inspection procedures discussed in previous sections of this report, the inspectors routinely reviewed issues during baseline inspection activities and plant status reviews to verify they were being entered into the licensees CAP at an appropriate threshold, that adequate attention was being given to timely corrective actions, and that adverse trends were identified and addressed. Attributes reviewed included: identification of the problem was complete and accurate, timeliness was commensurate with the safety significance, evaluation and disposition of performance issues, generic implications, common causes, contributing factors, root causes, extent-of-condition reviews, and previous occurrences reviews were proper and adequate, and that the classification, prioritization, focus, and timeliness of corrective actions were commensurate with safety and sufficient to prevent recurrence of the issue.

Minor issues entered into the licensees CAP as a result of the inspectors observations are included in the Attachment to this report.

These routine reviews for the identification and resolution of problems did not constitute any additional inspection samples. Instead, by procedure they were considered an integral part of the inspections performed during the quarter and documented in Section 1 of this report.

b. Findings

No findings were identified.

.2 Daily Corrective Action Program Reviews

a. Inspection Scope

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 licensees CAP. This review was accomplished through inspection of the stations daily condition report packages.

These daily reviews were performed by procedure as part of the inspectors daily plant status monitoring activities and, as such, did not constitute any separate inspection samples.

b. Findings

No findings were identified.

.3 Semi-Annual Trend Review

a. Inspection Scope

The inspectors performed a review of the licensees CAP and associated documents to identify trends that could indicate the existence of a more significant safety issue. The inspectors review was focused on repetitive equipment issues, but also considered the results of daily inspector CAP item screening discussed in Section 4OA2.2 above, licensee trending efforts, and licensee human performance results. The inspectors review nominally considered the 6-month period of July 2015 through December 2015, although some examples expanded beyond those dates where the scope of the trend warranted.

The review also included issues documented outside the normal CAP in major equipment problem lists, repetitive and/or rework maintenance lists, departmental problem/challenges lists, system health reports, quality assurance audit/surveillance reports, self-assessment reports, and Maintenance Rule assessments. The inspectors compared and contrasted their results with the results contained in the licensees CAP trending reports. Corrective actions associated with a sample of the issues identified in the licensees trending reports were reviewed for adequacy.

This review constituted one semi-annual trend inspection sample as defined in IP 71152-05.

b. Findings and Observations

The inspectors performed a review of conditions identified in the CAP as potential rework issues to determine if there existed a more significant safety issue. Through the inspectors review of condition reports written for equipment deficiencies found during the RFO; it was identified that a number of items were categorized as requiring rework evaluations. The inspectors assessed the licensees identification and screening of equipment issues that could potentially be rework; the evaluation of the cause of rework; the corrective actions taken to prevent the cause of the rework issue from occurring again; and reviewed trend data from the rework evaluations to determine potential common themes. The inspectors also attended the licensees Station Rework Review Board (SRRB) meeting and reviewed past meeting minutes.

The purpose of evaluating issues for rework is to improve overall plant safety, equipment reliability, and reduce cost/resource use associated with re-performing maintenance on important plant equipment. This is done through evaluation of the issues to identify programmatic or human performance deficiencies that can be corrected to prevent trends and/or significant plant events from occurring. There were 57 condition reports written related to equipment deficiencies identified during or after the RFO that were evaluated for being rework. Of those, 33 were determined to be classified as rework and those evaluations were approved by the SRRB. Most were classified as low level events, having no adverse consequences on plant operation, which is typical from reviewing the other quarterly trend information. About one-third of the rework issues were skill-based (human performance) errors, with the rest being distributed across other areas such as design deficiencies, procedure/instruction adequacy, and vendor deficiencies, to name a few. Also, about one-third of the issues were coded to vendor/supplemental employee work activities. There historically have been trends for outage-related rework issues pertaining to the use of vendors, vendor errors, or supplemental workers. The licensee has written corrective actions to enhance their vendor/supplemental worker oversight and review program. Actions have also been written to enhance and correct the areas in which the rework was grouped, such as revising procedures were errors were identified and correcting parts records or purchase orders when the wrong part was attained. No significant adverse trends were identified and actions/enhancements to address commonalities have been entered into the CAP.

The SRRB will roll-up all rework data from calendar year 2015 to potentially identify trends and compare that data to previous years.

.4 Annual Follow-up of Selected Issues: 1-2 Diesel Generator Failure to Start

a. Inspection Scope

During a review of items entered in the licensees CAP, the inspectors reviewed a corrective action item documenting the failure of 1-2 DG to start during performance of post-maintenance testing on March 18, 2015. The licensee identified that the 1-2 DG did not start due to a failure of the air start motor, ASM-2A. The licensee replaced ASM-2A on March 19, 2015, and post-maintenance testing was completed satisfactorily.

Additionally, the licensee performed an equipment apparent cause evaluation (EACE)and sent the failed air start motor to a vendor for failure analysis. The failure analysis identified that the direct cause of the failure of ASM-2A was a sheared stop nut pin in the starter drive assembly. Destructive analysis was performed on the motor and it was determined that the apparent cause of the failure of the stop nut pin was due to inadequate material used in manufacturing the pin. Specifically, the stop nut pin was found to be made of unhardened steel. The characteristics consistent with this material do not have a high enough shear strength for the rated output torque of the air start motor. Testing of a stop nut pin from a similar air start motor identified that the pin had characteristics associated with hardened steel, which is suitable for the air start motors rated output torque.

The inspectors reviewed the EACE and failure analysis report for identification of the apparent cause. Additionally, the inspectors assessed the consideration of the extent of condition and the evaluation of potential common cause operability issues due to this failure mode. The licensee performed an extent of condition review and operability evaluations on the 1-1 DG ASMs and ASM-2B on the 1-2 DG to determine if this same issue existed on the other currently installed motors. The inspectors also reviewed the licensees evaluation of operating experience for applicability to this issue. The licensee did not identify any similar operating experience and determined that no similar failures in the industry had occurred. The ASMs installed on the 1-1 DG and ASM-2B were determined to be operable. The licensee also has a corrective action planned to evaluate this issue for applicability to 10 CFR 21, Reporting of Defects and Noncompliance. Documents reviewed are listed in the Attachment to this report.

This review constituted one in-depth problem identification and resolution sample as defined in IP 71152-05.

b. Findings

No findings were identified.

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

.1 (Closed) Licensee Event Report 255/2015-001-00: Automatic Reactor Trip Results from

a Turbine Trip Initiated from the Digital Electro-Hydraulic Control System

a. Inspection Scope

On September 16, 2015, at approximately 0117, an anomaly within the DEH control system initiated a turbine trip which actuated the reactor protection system to automatically trip the reactor. The direct cause was an actuation of the DEH controller loss of power turbine trip logic. Troubleshooting determined the cause of this actuation to be from a combination of a failed power supply module on a circuit board within the DEH overspeed protection control (OPC) unit and either a loss of power from the OPC distributed processing units (DPUs) to the main system data highway or a loss of communication between the primary and backup OPC DPUs. This combination of issues signaled no overspeed protection for the turbine and actuated the trip logic. Prior to restarting the reactor following 1R24, the licensee replaced the failed circuit board and implemented a modification to remove the OPC loss of power and loss of communications turbine trip logics based on operating experience from other plants that use the same model DEH control system. Future corrective actions will include replacing circuit boards on other susceptible parts of this system in the next two RFOs.

These actions are reasonable to prevent recurrence combined with the elimination of the trip logic from the modification that was implemented. The timeframe is acceptable based on the DEH system being single-failure proof and site operating experience of the circuit boards. Documents reviewed are listed in the Attachment to this report. This LER is closed.

This event follow-up review constituted one sample as defined in IP 71153-05.

b. Findings

No findings were identified.

4OA5 Other Activities

.1 (Closed) Unresolved Item 05000255/2015001-03, Turbine-Driven Auxiliary Feedwater

Pump Trip During Surveillance Testing

a. Inspection Scope

The inspectors completed a review of URI 05000255/2015001-03, Turbine-Driven AFW Pump Trip During Surveillance Testing. On November 14, 2014, during performance of the Auxiliary Feedwater (AFW) system 18 month surveillance test procedure, the turbine-driven Auxiliary Feedwater pump (P-8B) tripped on overspeed approximately three minutes after the pump was started. The licensee conducted an equipment apparent cause evaluation (EACE) that identified possible causes and additional testing and data collection occurred in March 2015 to confirm or refute those potential causes.

The inspectors reviewed the data and conclusions from the March testing, other subsequent pump testing and system monitoring activities, and corrective actions from the EACE to evaluate the potential causes.

The direct cause of the turbine-driven AFW (TDAFW) pump trip was that the trip valve shut due to actuation of the overspeed trip device. The apparent cause, as stated in the EACE, concluded that no single probable cause in and of itself caused the tripseveral system and program anomalies could not be ruled out and as a result it is concluded that the apparent cause is a combination of multiple probable causes seen. The EACE was revised to indicate five possible causes:

(1) Condensate present in the steam supply can slow down or speed up the turbine while in operation. Through inspections of the steam traps and review of the system during the cause evaluation, it was determined that the moisture removal system was not fully effective and the preventive maintenance program for the safety-related steam traps was not effectively or consistently implemented. The inconsistent equipment classifications and ineffective preventive maintenance strategy for safety-related steam traps is considered a performance deficiency and is documented as a licensee-identified violation in section 4OA7.

(2) Margin between the as-found operating speed and the overspeed setpoint was less than expected. Real-time monitoring of turbine speed, steam supply pressure, and governor valve operation was conducted multiple times during subsequent pump test runs since the event. Any anomalies were documented in the test procedure and dispositioned through the corrective action program. The overspeed trip setpoint was revised based on the vendors recommendation for the operating conditions of this particular pump.

(3) Inherent design conditions of the steam supply and control systems could lead to condensate buildup which could change the turbine speed or cause pressure oscillations at the steam supply inlet. As mentioned in number 2 above, real-time monitoring of the system has been implemented during test runs and any issues are documented in the corrective action program. The steam supply piping from the A steam generator was mapped and determined to have a section of negative slope which had the potential for condensate buildup in the piping upstream of the turbine steam supply valve. The licensee is currently evaluating options for enhancing the draining capability of this line. However, these actions are considered enhancements to the system and are not likely causes of the trip.

(4) Testing the operation of the turbine trip valve while conducting pre-test checks provides an increased frequency for error in properly resetting the trip mechanism. The auxiliary feedwater pumps test procedures were reviewed to identify instances where the overspeed trip valve was tested prior to running the pump. The quarterly technical specification surveillance was revised to remove this testing and the overspeed trip valve will only be tested on a refueling cycle frequency going forward.

(5) Other owners of Elliott turbines have raked knife edges and reset the lever/latch plate assembly differently. The licensee has completed an engineering change to install a raked latch plate and knife edge on the overspeed trip assembly. This will be completed in February 2016 during the next pump maintenance window.

Based on the inspectors review of the licensees operational data collection and evaluation, and subsequent successful testing of the pump, this unresolved item is being closed. Documents reviewed are listed in the attachment.

b. Findings

There was one licensee-identified violation related to this URI that is documented in section 4OA7. This URI is closed.

.2 (Closed) NRC Temporary Instruction 2515/190, Inspection of the Licensees Proposed

Interim Actions As A Result of the Near-Term Task Force Recommendation 2.1 Flooding Reevaluation

a. Inspection Scope

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

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

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

• Reasonable simulation, if applicable to the site.

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

The inspectors verified that issues identified were entered into the licensee's CAP.

These activities constituted the completion of Temporary Instruction (TI) 2515/190, Inspection of the Proposed Interim Actions Associated with Near-Term Task Force Recommendation 2.1 Flooding Hazard Evaluations.

b. Findings and Observations

The licensee identified that potential interim actions required for a Beyond Design Basis Local Intense Precipitation event were not identified in PNP 2015-018, Required Response 2 for Near-Term Task Force Recommendation 2.1: Flooding - Hazard Re-Evaluation Report. The report discussed a water ingress path to the North Penetration Room (Door #106) that eventually leads, through an elevated pipeway, into the safety related 1D Switchgear Room. The licensees report stated that flooding during rainfall had never been recorded in the area and the entire room would have to flood before reaching the pipeway. On November 19, 2015, the licensee identified an additional pipeway inside the North Penetration Room and that the pipeway from the electrical penetration room to the 1D switchgear room was not elevated. The licensee entered this issue into their CAP, evaluated the potential water ingress path, and determined that additional interim actions were needed. The licensee identified an additional interim action to place sandbags across the doorway to the North Penetration Room in the event that heavy rain is predicted. In addition to this interim action, the inspectors reviewed other interim actions and procedures to implement these actions.

Materials for performing these activities were onsite and licensee staff was familiar with their use.

No findings were identified. This TI is closed.

.3 Safety-Conscious Work Environment Issue of Concern Follow-up (IP 93100)

a. Inspection Scope

The inspectors reviewed licensee actions to assess if they addressed previously identified work environmental conditions that potentially impacted licensee employees willingness and ability to raise issues impacting nuclear safety. Specifically the inspectors reviewed documents and conducted focus group and individual interviews to determine if:

• indications of a chilled work environment existed;

• employees were reluctant to raise safety or regulatory issues; and

• employees were being discouraged from raising safety or regulatory issues.

The inspectors also reviewed the results of a safety culture assessment conducted for the licensee by an independent contractor. Documents reviewed are listed in the to this report.

b. Findings

No findings were identified. The inspectors interviews and focus groups and a recent licensee-initiated safety culture survey indicated that most individuals felt free to raise safety or regulatory issues without fear of retaliation. The inspectors did not identify indications of a chilled work environment at the plant. Additionally, the safety culture assessment survey indicated that the culture of the station had improved since the previous assessment conducted approximately 3 years ago.

c. Observations The inspectors conducted four focus groups with Security Officers and one group with Mechanical Maintenance personnel for a total of 40 individuals. The inspectors also conducted nine one-on-one interviews with Security Officers in the field. In addition, the inspectors interviewed some of the station management team, including the Employee Concerns Program (ECP) manager, and conducted a review of the ECP files from 2015.

Overall, the responses from the interviews were that personnel were encouraged and willing to raise nuclear safety concerns and did not feel that they would suffer retaliation for raising issues. Some of the individuals expressed a reluctance to write condition reports because they did not receive feedback on the issues and therefore did not feel like their concerns were effectively resolved. However, these individuals stated that they would raise issues to their first line supervisors and resolve them through that avenue.

Through the interviews and focus groups, it was highlighted to the inspectors that there continues to be issues with trust of the ECP program. Plant personnel knew who the ECP manager was and where the ECP office was located, but they did not feel that the ECP was always confidential.

The Security organization indicated that they were fully staffed and that overtime was at an all-time low. This was an improvement over previous responses obtained in focus groups and interviews, where concerns were expressed on the shortage of staff and resources and the increased use of overtime to ensure full crew compliments. The interviews continued to reveal challenges with regard to communication, particularly from the senior management team down to the line organization. This has been a continuing area for improvement within the security department and the entire Palisades organization. For example, there have been numerous opportunities for job placement outside of the Security Organization, including some opportunities for additional training within the department. However, when asked if the officers were aware of these openings, they indicated that applying for those positions was not of benefit because they did not believe they would be hired or given the chance to try something different.

So, while these opportunities may have been available to the staff, the conditions for pursuing them were not clearly communicated in a manner that encouraged individuals to try them.

The inspectors also reviewed actions in the Confirmatory Order action list that were implemented by the security department. While the majority of items from the action list were being effectively implemented, including improvement in the safety culture, some items in the action list were not being effectively utilized. Specifically, the Questions and Concerns notebook, in which officers are able to write down questions or concerns they may have and acts as a log for keeping answers to those questions, was not being effectively utilized. When asked about the notebook, the officers indicated that it was available for a couple of weeks and then disappeared. The inspectors located and reviewed the notebook and noted that the last entry was from May 2015. Additionally, the Security Ombudsman program is not apparent to the officers within the department, which was another tool that was intended to be utilized to improve communications. The inspectors communicated the observations of the implementation of the items in the action list to the licensee management team.

There have been a series of safety culture surveys conducted in 2015, however, at the time of the inspection, none of the results had been communicated to the line organization. Station personnel had received information regarding the response rates for the surveys for each organization, but the actual survey data and results had not been communicated. This could lead to the potential for the workforce to become apathetic about participating in the surveys at all. In addition, some members of the licensees staff said they felt that many of the questions, as worded in the surveys, did not pertain specifically to their jobs or roles within the organization.

The licensee commissioned an independent third-party safety culture assessment survey which was conducted in 2015. That assessment had an overall participation response rate of 76 percent and compared results with a previous equivalent assessment survey in 2012. The specific primary areas/dimensions measured were Nuclear Safety Culture, General Cultural and Work Environment, and Leadership, Management, and Supervisory Behaviors and Practices. Three sub- dimensions measured were Employee Concerns Program, Nuclear Safety Values, Behaviors, Practices, and Safety Conscious Work Environment. The 2015 assessment survey found a notable improvement of +6.4 % in cultural scores since the 2012 assessment.

Five of six areas/dimensions measured were identified as an Area of Strength, the sixth area (Employee Concerns Program) was considered an Area of Competency.

Inspectors did not identify any items from the interviews that were at significant variance with the assessment survey results.

4OA6 Management Meetings

.1 Exit Meeting Summary

On January 12, 2016, the inspectors presented the inspection results to Mr. A. Vitale, Site Vice President, and other members of the licensee staff. The licensee acknowledged the issues presented. The inspectors confirmed that none of the potential report input discussed was considered proprietary.

.2 Interim Exit Meetings

Interim exits were conducted for:

• The results of the Radiological Hazard Assessment and Exposure Controls inspection during 1R24 were presented to Mr. A. Vitale, Site Vice President, and other members of the licensee staff on October 2, 2015;

• The inspection results of the biennial In-Service Inspection during 1R24 were presented to Mr. A. Vitale, Site Vice President, and other members of the licensee staff on October 7, 2015;

• The results of the inspectors review of URI 05000255/2014008-11, Classification of CCW Piping and Components Inside the Reactor Containment Building, was presented to Mr. A. Vitale; Site Vice President and other members of the licensee staff on October 29, 2015;

• On November 4, 2015, the inspectors debriefed the preliminary results of the Safety Conscious Work Environment follow-up inspection to the Site Vice President, Mr. A. Vitale, and other members of the licensee staff.

On January 7, 2016, the inspectors presented inspection results to the Site Vice President, Mr. A. Vitale, and other members of the licensee staff.

The licensee acknowledged the issues presented;

• The annual review of Emergency Action Level and Emergency Plan changes was presented to Mr. D. Malone, Emergency Preparedness Manager, and other members of licensee staff via telephone on November 24, 2015;

• The inspection results of the Triennial Review of Heat Sink Performance were presented to Mr. A. Williams, General Manager, for Plant Operations, and other members of the licensee staff on November 20, 2015, and

• The inspection results of the CDBI activities related to the closure of URI 05000255/2014008-11 were presented to Mr. Vitale, and other members of the licensees staff on October 29, 2015.

The inspectors confirmed that none of the potential report input discussed was considered proprietary. Proprietary material received during the inspection was returned to the licensee.

4OA7 Licensee-Identified Violations

The following violation of very low significance (Green) was identified by the licensee and is a violation of NRC requirements which meets the criteria of the NRC Enforcement Policy for being dispositioned as an NCV.

• Title 10 CFR 50.65(a)(1), requires, in part, that the holders of an operating license shall monitor the performance or condition of structures, systems, and components (SSCs), against licensee-established goals, in a manner sufficient to provide reasonable assurance that these SSCs, as defined in 10 CFR 50.65(b),are capable of fulfilling their intended functions. Title10 CFR 50.65(a)(2) states that monitoring as specified in 50.65(a)(1) is not required, where it has been demonstrated that the performance or condition of a SSC is being effectively controlled through the performance of appropriate preventive maintenance, such that the SSC remains capable of performing its intended function. Contrary to the above, as identified after the November 14, 2014, TDAFW pump trip, the licensee failed to demonstrate the performance or condition of the safety-related auxiliary feedwater system steam traps had been effectively controlled through the performance of appropriate preventive maintenance. Specifically, some of the safety-related steam traps, one relief valve, and one check valve associated with the steam supply piping of the turbine-driven AFW system were inappropriately classified in the maintenance rule program, resulting in inadequate and/or untimely maintenance being performed on these components, which probably contributed to the overspeed trip event. The licensee found 3 steam traps and one relief valve classified as non-critical components that were reclassified as high critical components and one steam trap and one check valve classified as run-to-failure components that were reclassified as high critical components.

Some of these components also had no preventive maintenance (PM) strategies or ones that were not the correct frequency based on the component classification. The licensee identified this issue while conducting the equipment apparent cause evaluation for the overspeed trip event and documented actions to correct the issue in CR-PLP-2014-5477. The licensee performed inspections of all the steam traps required for the TDAFW pump operation and identified some issues with steam cutting, foreign material exclusion in the traps, and incomplete seat contact. These issues were corrected and PM changes have been made for all the system components mentioned above.

The inspectors determined that the inconsistent equipment classifications and ineffective preventive maintenance strategy for the safety-related steam traps in the turbine-driven auxiliary feedwater system is considered a performance deficiency. The performance deficiency was more than minor because it was associated with the Equipment Performance attribute of the Mitigating Systems cornerstone and adversely impacted the cornerstone objective of ensuring the availability, reliability, and capability of systems that respond to initiating events.

Specifically, the licensee identified that the degraded condition of the moisture removal system could have led to excess condensate being present in the steam supply line which had the potential to adversely affect the operation of the turbine for the TDAFW pump, contributing to the overspeed trip event. The inspectors screened the issue using IMC 0609, Appendix A, The SDP for Findings at Power, Exhibit 2, Mitigating Systems Screening Questions, and answered Yes to the question of does this finding represent a loss of system and/or function? This trip of the TDAFW pump on overspeed was evaluated as a failure that impacted the ability of the AFW system to provide the specific function, which could only be accomplished by this train, of decay heat removal via steaming of the A Steam Generator. The turbine-driven AFW pump was also determined to not be in a condition to meet performance requirements defined by the probabilistic risk assessment success criteria, which for AFW is a 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> mission time. Therefore, the issue was screened further in a detailed risk evaluation.

A Region III Senior Reactor Analyst performed a detailed risk evaluation using the NRCs Standardized Plant Analysis Risk Model for Palisades, Revision 8.20.

The SRA assumed the turbine driven AFW pump was unavailable to perform its function for a period of 3 days because the pump was successfully tested and returned to service on November 16, 2014. Given the short exposure period, the calculated delta core delta frequency was less than 1.0E-7/yr. As a result of the low calculated delta core delta frequency, no additional analysis of external event risk contribution or large early release risk contribution was necessary. The dominant core damage sequence was a station blackout followed by the failure of the turbine driven AFW pump and the failure to recover onsite or offsite power.

Therefore, the finding screened as very low safety significance (Green).

ATTACHMENT:

SUPPLEMENTAL INFORMATION

KEY POINTS OF CONTACT

Licensee

A. Vitale, Site Vice President

B. Baker, Operations Manager - Shift

J. Borah, Engineering Manager, Systems and Components

E. Chatfield, Employee Concerns Coordinator

R. Craven, Production Manager

T. Davis, Licensing Specialist

B. Dotson, Licensing Specialist

J. Erickson, Regulatory Assurance

T. Mulford, Operations Manager

D. Nestle, Radiation Protection Manager

T. Fouty, Engineering Supervisor

O. Gustafson, Director of Regulatory and Performance Improvement

J. Hardy, Regulatory Assurance Manager

J. Haumersen, Site Projects and Maintenance Services Manager

G. Heisterman, Maintenance Manager

M. Lee, Operations Manager - Support

M. Liska, System Engineer

D. Lucy, Outage Manager

D. Malone, Emergency Planning Manager

D. MacMaster, Engineering Supervisor

W. Nelson, Training Manager

D. Nestle, Radiation Protection Manager

K. OConnor, Engineering Manager, Design and Programs

C. Plachta, Nuclear Independent Oversight Manager

P. Russell, Site Engineering Director

M. Schultheis, Performance Improvement Manager

M. Soja, Chemistry Manager

K. Strickland, Environmental Specialist

J. Tharp, Security Manager

A. Williams, General Manager Plant Operations

U.S. Nuclear Regulatory Commission

E. Duncan, Chief, Branch 3

LIST OF ITEMS OPENED, CLOSED, AND DISCUSSED

Opened

05000255/2015004-01 NCV Inadequate Dye Penetrant Examination of Pipe Lug Welds (Section 1R08.1)

05000255/2015004-02 NCV Failure to Identify Components Required to be Covered by the Quality Assurance Program (Section 1R21.b.(1))

05000255/2015004-03 SL IV Failure to Provide Bases to Determine Changes Did Not Involve Unreviewed Safety Questions (Section 1R21.b.(2))

05000255/2015004-04 SL IV Failure to Perform a Required 50.59 Evaluation for Declassification of the CVCS (Section 1R21.b.(3))

Closed

05000255/2015004-01 NCV Inadequate Dye Penetrant Examination of Pipe Lug Welds (Section 1R08.1)

05000255/2014008-11 URI Classification of CCW Piping and Components Inside the Reactor Containment Building (Section 1R21.a)

05000255/2015004-02 NCV Failure to Identify Components Required to be Covered by the Quality Assurance Program (Section 1R21.b.(1))

05000255/2015004-03 SL IV Failure to Provide Bases to Determine Changes Did Not Involve Unreviewed Safety Questions (Section 1R21.b.(2))

05000255/2015004-04 SL IV Failure to Perform a Required 50.59 Evaluation for Declassification of the CVCS (Section 1R21.b.(3))

2515/190 TI Inspection of the Licensees Proposed Interim Actions As A Result of the Near-Term Task Force Recommendation 2.1 Flooding Reevaluation (4OA5.2)

05000255/2015001-03 URI Turbine-Driven Auxiliary Feedwater Pump Trip During Surveillance Testing (4OA5.1)

Discussed

05000255/2014008-11 URI Classification of CCW Piping and Components Inside the Reactor Containment Building (Section 1R21.a)