IR 05000237/2017004

NRC Integrated Inspection Report 05000237/2017004; 05000249/2017004; and Emergency Preparedness Annual Inspection Report 05000237/2017501; 05000249/2017501

ML18022A431
Person / Time
Site:	Dresden
Issue date:	01/22/2018
From:	Jamnes Cameron Reactor Projects Region 3 Branch 4
To:	Bryan Hanson Exelon Generation Co, Exelon Nuclear
References
IR 2017004, IR 2017501
Download: ML18022A431 (64)

Text

UNITED STATES January 22, 2018

SUBJECT:

DRESDEN NUCLEAR POWER STATION, UNITS 2 AND 3NRC INTEGRATED INSPECTION REPORT 05000237/2017004; 05000249/2017004; AND EMERGENCY PREPAREDNESS ANNUAL INSPECTION REPORT 05000237/2017501; 05000249/2017501

Dear Mr. Hanson:

On December 31, 2017, the U.S. Nuclear Regulatory Commission (NRC) completed an integrated inspection at your Dresden Nuclear Power Station, Units 2 and 3. On January 8, 2018, the NRC inspectors discussed the results of this inspection with Mr. P. Karaba and other members of your staff. The results of this inspection are documented in the enclosed report. The NRC also completed its annual inspection of the Emergency Preparedness Program. This inspection began on January 1, 2017, and the issuance of this letter closes Inspection Report 05000237/2017501; 05000249/2017501.

Based on the results of this inspection, the NRC has identified one issue that was evaluated under the risk significance determination process as having very low safety significance (Green). The NRC has also determined that one violation is associated with this issue. Because the licensee initiated condition reports to address this issue, this violation is being treated as a Non-Cited Violation (NCV), consistent with Section 2.3.2 of the Enforcement Policy. The NCV is described in the subject inspection report.

If you contest the violation or significance of the NCV, you should provide a response within 30 days of the date of this inspection report, with the basis for your denial, to the 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; and the NRC Resident Inspector at the Dresden Nuclear Power Station.

If you disagree with the cross-cutting aspect assignment or any finding not associated with a regulatory requirement in this report, you should provide a response within 30 days of the date of this inspection report, with the basis for your disagreement, to the U.S. Nuclear Regulatory Commission, ATTN: Document Control Desk, Washington DC 20555-0001; with copies to the Regional Administrator, Region III; and the NRC Resident Inspector at the Dresden Nuclear Power Station. This letter, its enclosure, and your response (if any) will be made available for public inspection and copying at http://www.nrc.gov/reading-rm/adams.html and at the NRC Public Document Room in accordance with 10 CFR 2.390, Public Inspections, Exemptions, Request for Withholding.

Sincerely,

/RA/

Jamnes Cameron, Chief Branch 4 Division of Reactor Projects Docket Nos. 50-237; 50-249 License Nos. DPR-19; DPR-25 Enclosure:

IR 05000237/2017004; 05000249/2017004; 05000237/2017501; 05000249/2017501 cc: Distribution via LISTSERV

SUMMARY

Inspection Report 05000237/2017004, 05000249/2017004; 10/01/2017 - 12/31/2017; 05000237/2017501, 05000249/2017501; 01/01/2017 - 12/31/2017; Dresden Nuclear Power Station, Units 2 & 3; Fire Protection.

This report covers a 3-month period of inspection by resident inspectors and announced baseline inspections by regional inspectors. One Green finding was identified by the inspectors.

The finding involved a Non-Cited Violation (NCV) of the U.S. Nuclear Regulatory Commission (NRC) requirements. 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, 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 November 1, 2016. The NRC's program for overseeing the safe operation of commercial nuclear power reactors is described in NUREG-1649, Reactor Oversight Process, Revision 6.

Cornerstone: Mitigating Systems

Green.

The inspectors identified a finding of very-low safety significance and associated NCV of Technical Specification 5.4.1.c for the licensees failure to implement the established Fire Protection Program procedures which ensure Fire Barrier Integrity.

Specifically, the licensee ran an electrical cable through the doorway of an automatically closing fire door. This was contrary to Procedure DFPP 4175-01, which requires in part that fire doors must not be blocked open by props or any other material in its closing path. The licensee took immediate actions to restore the fire door, by removing the obstruction and entered the issue into their Corrective Action Program (CAP).

The inspectors determined that the performance deficiency was more-than-minor because it affected the Mitigating Systems cornerstone objective since the electrical cable could have prevented the fire door from performing its function. The finding was of very-low safety significance per Task 1.4.3-A of IMC 0609, Appendix F. Specifically, the total combustible loading on both sides of the affected fire door was representative of a fire duration less than 1.5 hours5.787037e-5 days <br />0.00139 hours <br />8.267196e-6 weeks <br />1.9025e-6 months <br />. The inspectors determined the finding had a cross-cutting aspect in the area of Human Performance, associated with the Training component, because the licensee failed to provide training and ensure knowledge transfer to maintain a knowledgeable, technically competent workforce and instill nuclear safety values. Specifically, the licensee believed the performance deficiency was caused by the one of the new temporary contractors brought onto the site to work in support of the D2R25 refueling outage. [H.9] (Section 1R05)

REPORT DETAILS

Summary of Plant Status

Unit 2 Unit 2 began the inspection period in coastdown for refueling outage D2R25. On October 30, 2017, operators shut down the unit to commence the refueling outage. At the completion of D2R25, operators synchronized the unit onto the grid on November 18, 2017 and achieved full power on November 19, 2017. On December 13, 2017, operators reduced power to 32 percent and the licensee made a containment entry to repair an oil leak on the 2A reactor recirculation pump lower bearing. The operators returned the unit to full power on December 14, 2017, where it remained for the rest of the inspection period.

Unit 3 Unit 3 operated at or near full power for the duration of the inspection period.

REACTOR SAFETY

Cornerstones: Initiating Events, Mitigating Systems, Barrier Integrity, and Emergency Preparedness

1R01 Adverse Weather Protection

.1 Winter Seasonal Readiness Preparations

a. Inspection Scope

The inspectors conducted a review of the licensees preparations for winter conditions to verify that the plants design features and implementation of procedures were sufficient to protect mitigating systems from the effects of adverse weather. Documentation for selected risk-significant systems was reviewed to ensure that these systems would remain functional when challenged by inclement weather. During the inspection, the inspectors focused on plant specific design features and the licensees procedures used to mitigate or respond to adverse weather conditions. 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. Cold weather protection, such as heat tracing and area heaters, was verified to be in operation where applicable. The inspectors also reviewed CAP items to verify that the licensee was identifying adverse weather issues at an appropriate threshold and entering them into their CAP in accordance with station corrective action procedures. Documents reviewed are listed in the Attachment to this report. The inspectors reviews focused specifically on the following plant systems due to their risk significance or susceptibility to cold weather issues:

• Unit 1 and 2/3 cribhouses at the diesel generator cooling water pumps and the diesel fire pumps;

• 2/3A and B isolation condenser (IC) make-up pump house;

• radwaste tank area;

• Unit 2 and Unit 3 125 VDC and 250 VDC battery rooms; and

• station blackout diesel building.

This activity constituted one winter seasonal readiness preparations sample as defined in Inspection Procedure (IP) 71111.01-05.

b. Findings

No findings were identified.

1R04 Equipment Alignment

.1 Quarterly Partial System Walkdowns

a. Inspection Scope

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

• Unit 2 IC following return to service after maintenance;

• shutdown cooling while in alternate decay heat removal mode;

• Unit 2, Division I engineered safety buses 23, 23-1, and 28 during Division II outage; and

• Unit 2 containment cooling service water return to service following piping replacements.

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 four partial system walkdown samples as defined in IP 71111.04-05.

b. Findings

No findings were identified.

1R05 Fire Protection

.1 Routine Resident Inspector Tours

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 Zone 1.2.2, Unit 2 Primary Containment - Drywell all elevations;

• Fire Zone 8.2.5B, Unit 2 Low Pressure Heater Bays, Elevation 517;

• Fire Zone 8.2.5A, Unit 2 High Pressure Heaters/Steam Lines, Elevation 517;

• Fire Zone 8.2.6B, Unit 2 Low Pressure Heater Bays, Elevation 538; and

• compensatory measures with Unit 1 diesel fire pump and CO2 suppression system out-of-service (OOS).

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 and conditions 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

Failure to Follow Procedure, Results in Non-Functional Fire Door

Introduction:

The inspectors identified a finding of very low safety significance (Green)and associated NCV of Technical Specifications 5.4.1.c, Procedures, for the licensees failure to implement the established Fire Protection Program procedures which ensure fire barrier Integrity. Specifically, the licensee ran an electrical cable through the doorway of an automatically closing fire door. This was contrary to procedure DFPP 4175-01, which requires that fire doors must not be blocked open by props or any other material in its closing path.

Description:

On October 18, 2017, during a plant walkdown the inspectors identified an electrical cable (extension cord) passing through a doorway protected by rolling fire door 2/3-4100-57. The cable passed through the top south corner of the doorway.

Rolling fire door 2/3-4100-57 is normally opened and actuated via a fusible link. When closed it separates Fire Zone (FZ) 1.1.2.2, Unit 2 Reactor Ground Floor Elevation 517 from FZ 1.1.1.2, Unit 3 Reactor Ground Floor Elevation 517.

In response to the inspectors observation, the licensee removed the electrical cable and restored the fire barriers functionality. When informed of the obstruction, the licensee entered the required actions for TRM 3.7.n, Fire Rated Assemblies, Condition A, One or more fire rated assemblies or sealing devices inoperable.

The inspectors reviewed a number of the licensees fire protection implementation procedures including DFPS 4175-01, Fire Barrier Integrity and Maintenance, Revision 23. This procedure outlines the policies regarding the proper maintenance of each type of fire barrier. Adherence to this procedure ensures that fire barriers are kept in proper condition at all times. Section G.4.a. of DFPS 4175-01 states:

Fire doors must not be blocked open by props or any other material in its closing path. Hoses, ropes, cabling, etc. running through a fire door opening could prevent the door from closing as describe during a fire From conversations with the licensee and review of the fire protection reports, the inspectors noted that in case of a fire on FZ 1.1.2.2 (Unit 2) some of the equipment used to achieve safe shutdown was located on FZ 1.1.1.2 (Unit 3). The reverse is also true.

If a fire occurs on FZ 1.1.1.2 (Unit 3) some of the equipment used to achieve safe shutdown was located on FZ 1.1.2.2 (Unit 2). The licensee stated that in a case like this, the site has additional procedures to control the needed equipment from alternate locations.

The inspectors reviewed the sites fire loading calculation, DRE97-0105, Revision 9 to determine the baseline combustible loading expected for each affected fire zone. The inspectors also obtained the totals for additional combustible loading due to transient combustibles in these zones, at the time the deficiency was identified.

For FZ 1.1.2.2 (Unit 2) the total loading was 25,350 BTU/ft2 and for FZ 1.1.1.2 (Unit 3)the total loading was 27,853 BTU/ft2. For a total loading across both zones of 53,203 BTU/ft2.

The licensee entered this issue into their CAP as Issue Report (IR) 04064252, Fire Door 2/3-4100-57 INOP.

Analysis:

The inspectors determined that the licensees failure to follow fire protection program implementing procedures regarding fire doors was contrary to Technical Specification 5.4.1.c, which requires that written procedures covering Fire Protection Program implementation, be established, implemented, and maintained. As a result, this is considered a performance deficiency. Specifically, licensee procedure DFPP 4175-01, Fire Barrier Integrity and Maintenance, Revision 23, Section G.4.a requires that fire doors must not be blocked open by props or any other material in its closing path.

Using IMC 0612 Appendix B, Issue Screening (issued date 09/07/12) the performance deficiency was determined to be more-than-minor because it was associated with the Mitigating Systems cornerstone attribute of Protection Against External Events (Fire) and affected the cornerstone objective of ensuring the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences (i.e., core damage). Specifically, the electrical cable running through the fire door path could have affected the capability of the fire barrier by preventing the fire door from closing if required during a fire.

In accordance with IMC 0609, Significance Determination Process, (issued date 04/29/15) Attachment 0609.04, Phase I - Initial Characterization of Findings, (issued date 10/07/16) Table 3, Section F.2.a the inspectors determined the finding involved the ability to confine a fire. Therefore, screening under IMC 0609, Appendix F, Fire Protection Significance Determination Process, (issued date 09/20/13) was required.

Using IMC 0609, Appendix F the inspectors determined that the finding affected the fire finding category of Fire Containment. The inspectors were able to answer yes to Question Task 1.4.3-A. The finding involved a fire door for which the combustible loading on both sides of the wall was representative of a fire duration less than 1.5 hours5.787037e-5 days <br />0.00139 hours <br />8.267196e-6 weeks <br />1.9025e-6 months <br /> (i.e., less than 120,000 BTU/ft2. Specifically, total combustible loading at the time the issue occurred was 53,203 BTU/ft2. Therefore, the inspectors determined that the finding screened as having very-low safety significance (Green).

The inspectors determined the finding had a cross-cutting aspect in the area of Human Performance, associated with the Training component, because the licensee failed to provide training and ensure knowledge transfer to maintain a knowledgeable, technically competent workforce and instill nuclear safety values. Specifically, the licensee believed the performance deficiency was caused by the one of the new temporary contractors brought onto the site to work during the refueling outage. [H.9]

Enforcement:

Technical Specification 5.4.1.c, Procedures, requires, in part, that written procedures covering Fire Protection Program implementation, be established, implemented, and maintained. Procedure DFPP 4175-01, Fire Barrier Integrity and Maintenance, Revision 23, was the established procedure that outlines the policies regarding proper maintenance of fire barriers and ensures those fire barriers are kept in proper condition at all times. Specifically, Procedure DFPP 4175-01, Section G.4.a.

requires, in part, that fire doors must not be blocked open by props or any other material in their closing path.

Contrary to the above, on October 18, 2017, the licensee blocked open fire door 2/3-4100-57 by running an electrical cable through the doorway. Since the electrical cable was tied in place on both sides of the fire door, if a fire had occurred the door would not have been able to fully close when required.

This violation is being treated as an NCV, consistent with Section 2.3.2.a of the Enforcement Policy because it was of very-low safety significance, and was entered into the licensees CAP as IR 04064252. As immediate actions, the licensee removed the electrical cable and posted a sign instructing workers not to obstruct the doorway.

(NCV 05000237/2017004-01; 05000249/2017004-01, Failure to Follow Procedure, Results in Non-Functional Fire Door)

1R06 Flooding

.1 Internal Flooding

a. Inspection Scope

The inspectors reviewed selected risk important plant design features and licensee procedures intended to protect the plant and its safety-related equipment from internal flooding events. Specifically, the inspectors performed a walkdown of failed flood barrier FL-12-6 to assess the adequacy of repairs made to this flood barrier in the Unit 2 condensate pit area. The inspectors reviewed flood analyses and design documents, including the UFSAR, engineering calculations, and abnormal operating procedures to identify licensee commitments. The specific documents reviewed are listed in the Attachment to this report. In addition, the inspectors reviewed licensee drawings to identify areas and equipment that may be affected by internal flooding caused by the failure or misalignment of nearby sources of water, such as the fire suppression or the circulating water systems. The inspectors reviewed the licensees corrective action documents with respect to past flood-related items identified in the corrective action program to verify the adequacy of the corrective actions. The inspectors also visually inspected watertight doors and verified drains and sumps were clear of debris and were operable, and that the licensee complied with its commitments.

Documents reviewed during this inspection are listed in the Attachment to this report.

This inspection constituted one internal flooding sample as defined in IP 71111.06-05.

b. Findings

No findings were identified.

1R07 Heat Sink Performance

.1 Triennial Review of Heat Sink Performance

a. Inspection Scope

The inspectors reviewed completed surveillances, associated calculations, performance test results, and inspection results associated with the 3B low pressure coolant inspection (LPCI)/containment cooling service water heat exchanger. The heat exchanger was chosen based on its risk-significance in the licensees probabilistic safety analysis, its important safety-related mitigating system support functions, its operating history, and its relatively low margin.

For the 3B LPCI heat exchanger, the inspectors reviewed the testing, inspection, maintenance, and monitoring of biotic fouling and macrofouling programs to assess the heat transfer capability of the heat exchanger. This was accomplished by reviewing whether:

(1) the test method used was consistent with accepted industry practices;

(2) the test conditions were consistent with the selected methodology;

(3) the test acceptance criteria were consistent with the design basis values; and

(4) the results of the heat exchanger performance test met established acceptance criteria. The inspectors also reviewed whether:

(1) the test results considered differences between testing conditions and design conditions;

(2) the frequency for testing considered previous test result trends; and

(3) test results considered test instrument inaccuracies and differences.

For the 3B LPCI heat exchanger, the inspectors reviewed the testing, inspection, maintenance, and monitoring of biotic fouling and macrofouling programs to assess the heat transfer capability of the heat exchanger. The inspectors reviewed whether:

(1) the methods used to inspect and clean the heat exchanger were consistent with as-found conditions identified, expected degradation trends, and industry standards;

(2) the licensees inspection and cleaning activities had established acceptance criteria consistent with industry standards; and

(3) the as-found results were recorded, evaluated, and dispositioned such that the as-left condition was consistent with the established criteria.

In addition, the inspectors reviewed the condition and operation of the 3B LPCI heat exchanger to determine consistency with design assumptions in heat transfer calculations and as described in the Final Safety Analysis Report. The inspectors reviewed the periodic flow testing at or near maximum design flow for redundant and infrequently used heat exchangers. In addition, eddy current test reports and visual inspection records were reviewed to determine the structural integrity of the heat exchanger.

The inspectors reviewed the performance of ultimate heat sink (UHS) and safety-related containment cooling service water system and subcomponents such as piping, intake screens, pumps, valves, etc. by tests or other equivalent methods to ensure availability and accessibility to the inplant cooling water systems. Specifically, the inspectors reviewed the UHS in accordance with NRC Inspection Procedure 71111.07, Heat Sink Performance, Section 02.02, Sub-Sections d.4 and d.7.

The inspectors reviewed the results of the licensees inspection of the UHS intake and discharge canals. The inspectors also reviewed whether identified settlement or movement indicating loss of structural integrity and/or capacity was appropriately evaluated and dispositioned by the licensee. In addition, the inspectors assessed the licensees trending and removing of debris or sediment buildup in the UHS to ensure sufficient reservoir capacity.

The inspectors reviewed the licensees operation of the containment cooling service water systems and UHS. This included a review of procedures for a loss of the containment cooling service water system or UHS, and a review of the availability and functionality of instrumentation which is relied upon for decision making. In addition, the inspectors assessed whether macrofouling was adequately monitored, trended, and controlled by the licensee to prevent clogging. The inspectors reviewed whether the licensees biocide treatments for biotic control were adequately conducted and the results monitored, trended, and evaluated. The inspectors also reviewed whether the licensee maintained adequate pH, calcium hardness, etc. of the UHS. The inspectors reviewed the containment cooling service water systems susceptibility to strong pump weak pump interaction, and the licensees controls in place for susceptible systems. In addition, the inspectors reviewed design changes to the containment cooling service water systems and the UHS to verify they were not adversely impacted by the changes.

The inspectors performed a system walkdown of the service water intake structure to assess its structural integrity and component functionality. This included observations of the structural integrity of component mounts and an assessment of the functionality of the traveling screens and strainers. The inspectors reviewed licensee activities which monitor, trend, and maintain containment cooling service water and pump bay silt accumulation at acceptable levels, and those which monitor and ensure proper function of pump bay water level instruments. The inspectors also reviewed the licensees ability to ensure functionality of the intake structure during adverse weather conditions. The inspectors also evaluated the licensees strategy for protecting against silt intrusion during periods of low flow or low level.

In addition, the inspectors reviewed corrective action documents related to the heat exchanger and heat sink performance issues to verify that the licensee had an appropriate threshold for identifying issues and to evaluate the effectiveness of their corrective actions. The documents that were reviewed are included in the Attachment to this report.

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

b. Findings

No findings were identified.

1R08 Inservice Inspection Activities

From October 30, 2017, through November 3, 2017, the inspectors conducted a review of the implementation of the licensees Inservice Inspection (ISI) Program for monitoring degradation of the Unit 2 reactor coolant system (RCS), emergency feedwater systems, risk-significant piping and components and containment systems.

The inspections described in Sections 1R08.1 and 1R08.5 below constituted one ISI sample as defined in IP 71111.08-05.

.1 Piping Systems Inservice Inspection

a. Inspection Scope

The inspectors observed and/or reviewed records of the following Non-Destructive Examinations mandated by the American Society of Mechanical Engineers (ASME)

Section XI Code to evaluate compliance with the ASME Code Section XI and Section V requirements and if any indications and defects were detected, to determine if these were dispositioned in accordance with the ASME Code or an NRC approved alternative requirement:

• magnetic particle examination of integral attachment welds for pipe support M-1151D-132; high-pressure coolant injection system;

• liquid penetrant examination of integral attachment welds for pipe support M-1164D-296; LPCI system;

• ultrasonic (UT) examination of pipe elbow to elbow weld, 2/2/2302-16/16-9 in the high-pressure coolant injection system;

• UT examination of pipe weld, 2/1/1404-10/W-112B in the core spray system;

• UT examination of heat exchanger weld 2-1503B-1 in the LPCI system; and

• magnetic particle examination of heat exchanger nozzle welds 2-1503B-N3-1A and 1B in the LPCI system; The licensee had not identified any recordable indications during surface and volumetric examinations performed since the beginning of the previous refueling outage.

Therefore, no NRC review was completed for this inspection procedure attribute.

The inspectors reviewed the following pressure boundary weld completed for risk-significant systems during the last Unit 2 refueling outage to determine if the licensee applied the pre-service non-destructive examination and acceptance criteria required by the construction Code, or the ASME Code Section XI. Additionally, the inspectors reviewed the welding procedure specification and supporting weld procedure qualification records to determine if the weld procedure was qualified in accordance with the requirements of the Construction Code and the ASME Code Section IX:

• field welds no. 1 on thermos-well connection, in standby liquid control system (Work Order 01502648-01).

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 Corrective Action Program and conducted interviews with licensee staff to determine if:

• 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 Title 10 of the Code of Federal Regulations (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 Observation During Periods of Heightened Activity or Risk

(71111.11Q)

a. Inspection Scope

On December 13, 2017, the inspectors observed main control room operators during an emergent down power of Unit 2 to 32 percent rated thermal power and the deinerting of the primary containment in order to support repairs of an oil leak on the 2A reactor recirculation pump lower bearing oil reservoir system. This was an activity that required heightened awareness and was related to increased risk. 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 procedures;

• control board manipulations;

• oversight and direction from supervisors; and

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

The 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 activity 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

.1 Routine Quarterly Evaluations

a. Inspection Scope

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

• quality control audit of maintenance affecting the main steam system; and

• emergency direct current (DC) lighting.

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 performed a quality review for main steam, as discussed in IP 71111.12, Section 02.02.

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 activity constituted one quarterly maintenance effectiveness sample and one quality control sample as defined in IP 71111.12-05.

b. Findings

No findings were identified.

1R13 Maintenance Risk Assessments and Emergent Work Control

.1 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:

• Unit 3 online risk Yellow due to Unit 2 outage activities;

• Unit 2 shutdown risk Yellow with bus 24-1 OOS & 2B reactor building closed cooling water OOS; and

• U2 shutdown risk Yellow during 2B service water pump OOS (bus 24 outage).

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

b. Findings

No findings were identified.

1R15 Operability Determinations and Functional Assessments

.1 Operability Evaluations

a. Inspection Scope

The inspectors reviewed the following issues:

• standby gas treatment single failure concern during a hypothetical loss of offsite/loss of coolant accident with failure of DC Bus 2B-1;

• Engine Systems, Inc. - 10 CFR 21 - speed switch issue results in emergency diesel generator failure to start in the industry;

• Unit 2 emergency diesel generator (EDG) output breaker did not close with bus 24-1 de-energized;

• Unit 3 LPCI heat exchanger relief valve flange potential non-conforming condition;

• Unit 2 IC 3-1301-3 stroke length too short, historic operability assessment; and

• 2/3 EDG foreign material found in the air start regulator valve.

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

.1 Plant Modifications

a. Inspection Scope

The inspectors reviewed the following modification(s):

• main steam Target Rock relief valve bellows drain modification (engineering change (EC) 404631); and

• main steam isolation valve (MSIV) bypass switch addition to the containment Group I isolation logic circuitry (EC 397320).

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. 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 activity constituted two permanent plant modification samples as defined in IP 71111.18-05.

b. Findings

No findings were identified.

1R19 Post-Maintenance Testing

.1 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:

• 1A, 2C, 2D MSIV local leak rate testing (LLRT) following valve internals repairs;

• 2-1601-33F torus to drywell vacuum breaker testing following repairs;

• anticipated transient without scram (ATWS) recirculation pump trip (RPT) on high reactor pressure test following set point change (EC 395141);

• 2A reactor recirculation pump seal hydrostatic pressure testing following seal package replacement;

• Unit 2 essential service system uninterruptible power supply testing following replacement (EC 406339);

• Unit 2 drywell spray containment isolation valve 2-1501-28A testing following repairs; and

• Unit 2 A feedwater check valves 2-0220-58A and 2-0220-62A LLRT following repairs.

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 activity constituted seven post-maintenance testing samples as defined in IP 71111.19-05.

b. Findings

No findings were identified.

1R20 Outage Activities

.1 Refueling Outage Activities

a. Inspection Scope

The inspectors reviewed the Outage Safety Plan (OSP) and contingency plans for the Unit 2 refueling outage (RFO) D2R25, conducted October 30, 2017 through November 18, 2017, to confirm that the licensee had appropriately considered risk, industry experience, and previous site-specific problems in developing and implementing a plan that assured maintenance of defense-in-depth. During the RFO, the inspectors observed portions of the shutdown and cooldown processes and monitored licensee controls over the outage activities listed below:

• licensee configuration management, including maintenance of defense-in-depth commensurate with the OSP for key safety functions and compliance with the applicable TS 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 reactor 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 OSP requirements were met, and controls over switchyard activities;

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

• controls to ensure that outage work was not impacting the ability of the operators to operate the spent fuel pool 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 TS;

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

• refueling activities, including fuel handling;

• startup and ascension to full power operation, tracking of startup prerequisites, walkdown of the drywell (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 activity constituted one RFO sample as defined in IP 71111.20-05.

b. Findings

No findings were identified.

1R22 Surveillance Testing

.1 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:

• Unit 2 MSIV LLRT (isolation valve);

• Unit 2 high pressure coolant injection, reactor water clean-up, B feedwater containment check valve leak tightness testing (isolation valve);

• emergency core cooling system (ECCS) integrated functional test (routine); and

• ATWS-RPT and ECCS Level functional test (routine).

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

• did preconditioning occur;

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

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

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

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

• measuring and test equipment calibration was current;

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

• test frequencies met TS requirements to demonstrate operability and reliability; tests were performed in accordance with the test procedures and other applicable procedures; jumpers and lifted leads were controlled and restored where used;

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

• test equipment was removed after testing;

• where applicable for inservice testing activities, testing was performed in accordance with the applicable version of Section XI, American Society of Mechanical Engineers code, and reference values were consistent with the system design basis;

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

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

• where applicable, actual conditions encountering high resistance electrical contacts were such that the intended safety function could still be accomplished;

• prior procedure changes had not provided an opportunity to identify problems encountered during the performance of the surveillance or calibration test;

• equipment was returned to a position or status required to support the performance of its safety functions; and

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

Documents reviewed are listed in the Attachment to this report.

These inspections constituted two routine surveillance testing samples, and two containment isolation valve samples as defined in IP 71111.22, Sections-02 and-05. In addition, the inspectors did not identify any performance degradation in the RCS leakage for the entire cycle. The reactor coolant system leak detection inspection sample was not performed as defined in IP 71111.22, Section-02.

b. Findings

No findings were identified.

1EP4 Emergency Action Level and Emergency Plan Changes

a. Inspection Scope

The regional inspectors performed an in-office review of the latest revisions to the Emergency Plan, Emergency Action Levels (EALs), and EAL Bases document to determine whether these changes decreased the effectiveness of the Emergency Plan.

The inspectors also performed a review of the licensees 10 CFR 50.54(q) change process, and Emergency Plan change documentation to ensure proper implementation for maintaining Emergency Plan integrity.

The inspectors review was not documented in a safety evaluation report, and did not constitute NRC approval of licensee-generated changes; therefore, this revision is subject to future inspection. The specific documents reviewed during this inspection are listed in the Attachment to this report.

This EAL and Emergency Plan change inspection constituted one sample as defined in Inspection Procedure 71114.04-06.

b. Findings

No findings were identified.

1EP6 Drill Evaluation

.1 Emergency Preparedness Drill Observation

a. Inspection Scope

The inspectors evaluated the conduct of a routine licensee emergency drill on October 10, 2017, to identify any weaknesses and deficiencies in classification, notification, and protective action recommendation development activities. The inspectors observed emergency response operations in the Technical Support Center and Operational Support Center to determine whether the event classification, notifications, and protective action recommendations were performed in accordance with procedures. The inspectors also attended the licensee drill critique to compare any inspector-observed weakness with those identified by the licensee staff to evaluate the critique and to verify whether the licensee staff was properly identifying weaknesses and entering them into the corrective action program. As part of the inspection, the inspectors reviewed the drill package and other documents listed in the Attachment to this report.

This emergency preparedness drill inspection constituted one sample as defined in IP 71114.06-05.

b. Findings

No findings were identified.

RADIATION SAFETY

Cornerstones: Occupational and Public Radiation Safety

2RS1 Radiological Hazard Assessment and Exposure Controls

.1 Radiological Hazard Assessment (02.02)

a. Inspection Scope

The inspectors assessed the licensees current and historic isotopic mix, including alpha emitters and other hard-to-detect radionuclides. The inspectors evaluated whether survey protocols were reasonable to identify the magnitude and extent of the radiological hazards.

The inspectors determined whether there have been changes to plant operations since the last inspection that may have resulted in a significant new radiological hazard for onsite individuals. The inspectors evaluated whether the licensee assessed the potential impact of these changes and 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 materiel conditions and performed independent radiation measurements, as needed, to verify conditions were consistent with documented radiation surveys.

The inspectors assessed the adequacy of pre-work surveys for select radiologically risk-significant work activities.

The inspectors evaluated the radiological survey program to determine whether hazards were properly identified. The inspectors discussed procedures, equipment, and performance of surveys with radiation protection staff and assessed whether technicians were knowledgeable about when and how to survey areas for various types of radiological hazards.

The inspectors observed work in potential airborne areas to assess whether air samples were being taken appropriately for their intended purpose and reviewed various survey records to assess whether the samples were collected and analyzed appropriately. The inspectors also reviewed the licensees program for monitoring contamination which has the potential to become airborne.

These inspection activities constituted one complete sample as defined in Inspection Procedure (IP) 71124.01-05.

b. Findings

No findings were identified.

.2 Instructions to Workers (02.03)

a. Inspection Scope

The inspectors reviewed select radiation work permits used to access high radiation areas and evaluated the specified work control instructions or control barriers. The inspectors also assessed whether workers where made aware of the work instructions and area dose rates.

The inspectors reviewed electronic alarming dosimeter dose and dose rate alarm set point methodology. For selected electronic alarming dosimeter occurrences, the inspectors assessed the workers response to the alarm, the licensees evaluation of the alarm, and any follow-up investigations.

The inspectors reviewed the licensees methods for informing workers of changes in plant operations or radiological conditions that could significantly impact their occupational dose.

The inspectors reviewed the labeling of select containers of licensed radioactive material that could cause unplanned or inadvertent exposure to workers.

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

b. Findings

No findings were identified.

.3 Contamination and Radioactive Material Control (02.04)

a. Inspection Scope

The inspectors observed locations where the licensee monitors material leaving the radiologically controlled area and assessed the methods used for control, survey, and release of material from these areas. As available, the inspectors observed health physics personnel surveying and releasing material for unrestricted use.

The inspectors observed workers leaving the radiologically controlled area and assessed their use of tool and personal contamination monitors and reviewed the licensees criteria for use of the monitors.

The inspectors assessed whether instrumentation was used at its typical sensitivity levels based on appropriate counting parameters or whether the licensee had established a de facto release limit.

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

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

b. Findings

No findings were identified.

.4 Radiological Hazards Control and Work Coverage (02.05)

a. Inspection Scope

The inspectors evaluated ambient radiological conditions during tours of the facility. The inspectors assessed whether the conditions were consistent with applicable posted surveys, radiation work permits, and worker briefings.

The inspectors evaluated the adequacy of radiological controls, such as required surveys, radiation protection job coverage, and contamination controls. The inspectors evaluated the licensees use of electronic alarming 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 a NRC-approved method of determining effective dose equivalent.

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

For select airborne area radiation work permits, the inspectors reviewed airborne radioactivity controls and monitoring, the potential for significant airborne levels, containment barrier integrity, and temporary filtered ventilation system operation.

The inspectors examined the licensees physical and programmatic controls for highly activated or contaminated materials stored within pools and assessed whether appropriate controls were in place to preclude inadvertent removal of these materials from the pool.

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

b. Findings

No findings were identified.

.5 High Radiation Area and Very High Radiation Area Controls (02.06)

a. Inspection Scope

The inspectors observed posting and physical controls for high radiation areas and very high radiation areas to assess adequacy.

The inspectors conducted a selective inspection of posting and physical controls for high radiation areas and very high radiation areas to assess conformance with performance indicators.

The inspectors reviewed procedural changes to assess the adequacy of access controls for high and very-high radiation areas to determine whether procedural changes substantially reduced the effectiveness and level of worker protection.

The inspectors assessed the licensees controls for high radiation areas greater than 1 rem/hour that included areas with the potential to become high radiation areas for compliance with Technical Specifications and procedures.

The inspectors assessed the controls for very-high radiation areas and areas with the potential to become very-high radiation areas. The inspectors also assessed whether individuals were unable to gain unauthorized access to these areas.

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

b. Findings

No findings were identified.

.6 Radiation Worker Performance and Radiation Protection Technician Proficiency (02.07)

a. Inspection Scope

The inspectors observed radiation worker performance and assessed their performance with respect to radiation protection work requirements, the level of radiological hazards present, and radiation work permit controls.

The inspectors assessed worker awareness of electronic alarming dosimeter set points, stay times, or permissible dose for radiologically significant work as well as expected response to alarms.

The inspectors observed radiation protection technician performance and assessed whether the technicians were aware of the radiological conditions and radiation work permit controls and whether their performance was consistent with training and qualifications for the given radiological hazards.

The inspectors observed radiation protection technician performance of radiation surveys and assessed the appropriateness of the instruments being used, including calibration and source checks.

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

b. Findings

No findings were identified.

.7 Problem Identification and Resolution (02.08)

a. Inspection Scope

The inspectors assessed whether problems associated with radiological hazard assessment and exposure controls were being identified at an appropriate threshold and were properly addressed for resolution. For select problems, the inspectors assessed the appropriateness of the corrective actions. The inspectors also assessed the licensees program for reviewing and incorporating operating experience.

The inspectors reviewed select problems related to human performance errors and assessed whether there was a similar cause and whether corrective actions taken resolved the problems.

The inspectors reviewed select problems related to radiation protection technician error and assessed whether there was a similar cause and whether corrective actions taken resolved the problems.

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

b. Findings

No findings were identified.

2RS2 Occupational As Low As Reasonably Achievable Planning and Controls

.1 Problem Identification and Resolution (02.06)

a. Inspection Scope

The inspectors reviewed self-assessments and/or audits performed of the as low as reasonably achievable program and determined whether these reviews identified problems or areas for improvement.

The inspectors assessed whether problems associated with as low as reasonably achievable planning and controls were being identified by the licensee at an appropriate threshold and properly addressed for resolution.

These inspection activities constituted one complete sample as defined in IP 71124.02-05.

b. Findings

No findings were identified.

2RS8 Radioactive Solid Waste Processing and Radioactive Material Handling, Storage, and

Transportation (71124.08)

.1 Radioactive Material Storage (02.02)

a. Inspection Scope

The inspectors selected areas where containers of radioactive waste are stored, and evaluated whether the containers were labeled in accordance with 10 CFR 20.1904, or controlled in accordance with 10 CFR 20.1905.

The inspectors assessed whether the radioactive material storage areas were controlled and posted in accordance with the requirements of 10 CFR Part 20. For materials stored or used in the controlled or unrestricted areas, the inspectors evaluated whether they were secured against unauthorized removal and controlled in accordance with 10 CFR 20.1801 and 10 CFR 20.1802.

The inspectors evaluated whether the licensee established a process for monitoring the impact of low-level radioactive waste storage that was sufficient to identify potential unmonitored, unplanned releases or nonconformance with waste disposal requirements.

The inspectors evaluated the licensees program for container inventories and inspections. The inspectors selected containers of stored radioactive material, and assessed for signs of swelling, leakage, and deformation.

These inspection activities constituted one complete sample as defined in IP 71124.08-05.

b. Findings

No findings were identified.

.2 Radioactive Waste System Walk-Down (02.03)

a. Inspection Scope

The inspectors walked down accessible portions of select radioactive waste processing systems to assess whether the current system configuration and operation agreed with the descriptions in plant and/or vendor manuals.

The inspectors reviewed administrative and/or physical controls to assess whether equipment that is not in service or abandoned in place would not contribute to an unmonitored release path and/or affect operating systems or be a source of unnecessary personnel exposure. The inspectors assessed whether the licensee reviewed the safety significance of systems and equipment abandoned in place in accordance with 10 CFR 50.59.

The inspectors reviewed the adequacy of changes made to the radioactive waste processing systems since the last inspection. The inspectors evaluated whether changes from what is described in the Final Safety Analysis Report were reviewed and documented in accordance with 10 CFR 50.59 or that changes to vendor equipment were made in accordance with vendor manuals. The inspectors also assessed the impact of these changes on radiation doses to occupational workers and members of the public.

The inspectors selected processes for transferring radioactive waste resin and/or sludge discharges into shipping/disposal containers and assessed whether the waste stream mixing, sampling, and waste concentration averaging were consistent with the process control program, and provided representative samples of the waste product for the purposes of waste classification.

The inspectors evaluated whether tank recirculation procedures provided sufficient mixing.

The inspectors assessed whether the licensees process control program correctly described the current methods and procedures for dewatering and waste stabilization.

These inspection activities constituted one complete sample as defined in IP 71124.08-05.

b. Findings

No findings were identified.

.3 Waste Characterization and Classification (02.04)

a. Inspection Scope

For select waste streams, the inspectors assessed whether the licensees radiochemical sample analysis results were sufficient to support radioactive waste characterization as required by 10 CFR Part 61. The inspectors evaluated whether the licensees use of scaling factors and calculations to account for difficult-to-measure radionuclides was technically sound and based on current 10 CFR Part 61 analysis.

The inspectors evaluated whether changes to plant operational parameters were taken into account to:

(1) maintain the validity of the waste stream composition data between the sample analysis update; and

(2) assure that waste shipments continued to meet the requirements of 10 CFR Part 61.

The inspectors evaluated whether the licensee had established and maintained an adequate quality assurance program to ensure compliance with the waste classification and characterization requirements of 10 CFR 61.55 and 10 CFR 61.56.

These inspection activities constituted one complete sample as defined in IP 71124.08-05.

b. Findings

No findings were identified.

.4 Shipment Preparation (02.05)

a. Inspection Scope

The inspectors did not observe radioactive waste processing; however inspectors discussed the process of radioactive processing with radiation workers. Inspectors also observed radioactive material shipment preparation and receipt activities.

The inspectors observed shipment packaging, surveying, labeling, marking, placarding, vehicle checks, emergency instructions, disposal manifest, shipping papers provided to the driver, and licensee verification of shipment readiness. Also, the inspectors reviewed the technical instructions presented to workers and assessed whether the licensees training program provided training to personnel responsible for the conduct of radioactive waste processing and radioactive material shipment preparation activities.

The inspectors assessed whether shippers were knowledgeable of the shipping regulations and demonstrated adequate skills to accomplish package preparation requirements. The inspectors evaluated whether the licensee was maintaining shipping procedures in accordance with current regulations. The inspectors assessed whether the licensee was meeting the expectations in NRC Bulletin 79-19, Packaging of Low-Level Radioactive Waste for Transport and Burial, and 49 CFR Part 172, Subpart H, Training.

The inspectors evaluated whether the requirements for Type B shipment Certificates of Compliance had been met. The inspectors determined whether the user was a registered package user and had an NRC-approved quality assurance program.

The inspectors assessed whether procedures for cask loading and closure were consistent with vendor procedures.

The inspectors assessed whether non-Type B shipments were made in accordance with the package quality documents.

The inspectors assessed whether the receiving licensee was authorized to receive the shipment packages.

These inspection activities constituted one complete sample as defined in IP 71124.08-05.

b. Findings

No findings were identified.

.5 Shipping Records (02.06)

a. Inspection Scope

The inspectors reviewed select shipments to evaluate whether the shipping documents indicated the proper shipper name; emergency response information and a 24-hour contact telephone number; accurate curie content and volume of material; and appropriate waste classification, transport index, and UN number. The inspectors assessed whether the shipment marking, labeling, and placarding was consistent with the information in the shipping documentation.

These inspection activities constituted one complete sample as defined in IP 71124.08-05.

b. Findings

No findings were identified.

.6 Identification and Resolution of Problems (02.07)

a. Inspection Scope

The inspectors assessed whether problems associated with radioactive waste processing, handling, storage, and transportation, were being identified by the licensee at an appropriate threshold, were properly characterized, and were properly addressed for resolution. Additionally, the inspectors evaluated whether the corrective actions were appropriate for a selected sample of problems documented by the licensee that involve radioactive waste processing, handling, storage, and transportation.

These inspection activities constituted one complete sample as defined in IP 71124.08-05.

b. Findings

No findings were identified.

Cornerstone: Security

3S08 Fitness-For-Duty Program (71130.08)

a. Inspection Scope

The inspectors evaluated this area by: reviewing program procedures, implementing procedures, and records; conducting interviews with responsible personnel and plant employees; and performing walkdowns.

The inspectors completed 32 (5 Tier I, 21 Tier II, and 6 Tier III) inspection requirements as described in IP 71130.08, dated September 30, 2016. Along with the inspection requirements documented in inspection report DRESDEN NUCLEAR POWER STATION, UNITS 2 AND 3 - NRC SECURITY BASELINE INSPECTION REPORT 05000237/2017403; 05000249/2017403 (ML17080A147), these activities constitute completion of one required sample. The following sample requirements were completed:

Tier I: 02.01a; 02.02a; 02.04a-c Tier II: 02.05a-h; 20.06a-d; 02.07a-g; 02.08a-e; 02.09a, b Tier III: 02.12a; 02.13a; 02.14a-c, e

b. Findings

No findings were identified.

OTHER ACTIVITIES

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

4OA1 Performance Indicator Verification

.1 Safety System Functional Failures

a. Inspection Scope

The inspectors sampled licensee submittals for the Safety System Functional Failures (MS05) performance indicator (PI) Units 2 and 3, for the period from the fourth quarter 2016 through the third quarter 2017. To determine the accuracy of the PI data reported during those periods, the inspectors used PI definitions and guidance contained in the Nuclear Energy Institute (NEI) Document 99-02, Regulatory Assessment Performance Indicator Guideline, Revision 7, dated August 31, 2013, and NUREG-1022, Event Reporting Guidelines 10 CFR 50.72 and 50.73 definitions and guidance. The inspectors reviewed the licensees operator narrative logs, operability assessments, maintenance rule records, maintenance work orders, issue reports, event reports and NRC Integrated Inspection Reports for the period of October 1, 2016 through September 30, 2017 to validate the accuracy of the submittals. 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 and none were identified. Documents reviewed are listed in the Attachment to this report.

This activity constituted two safety system functional failures samples as defined in IP 71151-05.

b. Findings

No findings were identified.

.2 Reactor Coolant System Leakage

a. Inspection Scope

The inspectors sampled licensee submittals for the RCS Leakage (BI02) performance indicator (PI) Units 2 and 3, for the period from the fourth quarter 2016 through third quarter 2017. To determine the accuracy of the PI data reported during those periods, the inspectors used PI definitions and guidance contained in NEI 99-02, Regulatory Assessment Performance Indicator Guideline, Revision 7, dated August 31, 2013. The inspectors reviewed the licensees operator logs, RCS leakage tracking data, issue reports, event reports and NRC Integrated Inspection Reports for the period of October 1, 2016 through September 30, 2017 to validate the accuracy of the submittals.

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 and none were identified. Documents reviewed are listed in the Attachment to this report.

This activity constituted two reactor coolant system leakage samples as defined in IP 71151-05.

b. Findings

No findings were identified.

.3 Occupational Exposure Control Effectiveness

a. Inspection Scope

The inspectors sampled licensee submittals for the Occupational Exposure Control Effectiveness Performance Indicator for the period from the first quarter 2016 through the third quarter 2017. The inspectors used PI definitions and guidance contained in NEI 99-02, Regulatory Assessment Performance Indicator Guideline, Revision 7, dated August 2013, to determine the accuracy of the Performance Indicator data reported during those periods. The inspectors reviewed the licensees assessment of the Performance Indicator for occupational radiation safety to determine if indicator related data was adequately assessed and reported. To assess the adequacy of the licensees Performance Indicator data collection and analyses, the inspectors discussed with radiation protection staff, the scope and breadth of its data review and the results of those reviews. The inspectors independently reviewed electronic personal dosimetry dose rate, accumulated dose alarms, dose reports, and the dose assignments for any intakes that occurred during the time period reviewed to determine if there were potentially unrecognized occurrences. The inspectors also conducted walkdowns of numerous locked high and very-high radiation area entrances to determine the adequacy of the controls in place for these areas. Documents reviewed are listed in the to this report.

This inspection constituted one occupational exposure control effectiveness sample as defined in IP 71151-05.

b. Findings

No findings were identified.

.4 Radiological Effluent Technical Specification/Offsite Dose Calculation Manual

Radiological Effluent Occurrences

a. Inspection Scope

The inspectors sampled licensee submittals for the radiological effluent Technical Specification/Offsite Dose Calculation Manual radiological effluent occurrences performance indicator for the period from the first quarter of 2016 through the second quarter of 2017. The inspectors used PI definitions and guidance contained in NEI 99-02, Regulatory Assessment Performance Indicator Guideline, Revision 7, dated August 2013, to determine the accuracy of the Performance Indicator data reported during those periods. The inspectors reviewed the licensees issue report database and selected individual reports generated since this indicator was last reviewed to identify any potential occurrences such as unmonitored, uncontrolled, or improperly calculated effluent releases that may have impacted offsite dose. The inspectors reviewed gaseous effluent summary data and the results of associated offsite dose calculations for selected dates to determine if indicator results were accurately reported. The inspectors also reviewed the licensees methods for quantifying gaseous and liquid effluents and determining effluent dose. Documents reviewed are listed in the to this report.

This inspection constituted one Radiological Effluent Technical Specification/Offsite Dose Calculation Manual radiological effluent occurrences 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 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 corrective action program at an appropriate threshold, adequate attention was being given to timely corrective actions, and adverse trends were identified and addressed. Some minor issues were entered into the licensees corrective action program as a result of the inspectors observations; however, they are not discussed in 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.

b. Findings

No findings were identified.

.2 Semi-Annual Trend Review

a. Inspection Scope

The inspectors performed a review of the licensees corrective action program 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 corrective action program item screening discussed in Section 4OA2.1 above, licensee trending efforts, and licensee human performance results. The inspectors review nominally considered the 6-month period of July 2017 through December 2017, although some examples expanded beyond those dates where the scope of the trend warranted.

The review also included issues documented outside the CAP in major equipment problem lists, repetitive and/or rework maintenance 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 activity constituted one semi-annual trend review inspection sample as defined in IP 71152.

b. Observations and Assessments During the period covered in this inspection sample, the inspectors and the licensee noted similar trends in equipment and program performance. Although these errors did not always result in any immediate adverse consequences, a potential trend in these areas is apparent and suggests that additional licensee attention to affect corrective actions may be appropriate. The licensee entered the following potential adverse trends into their CAP during this time period: intermediate range monitor performance (IR 4082783); digital electro-hydraulic control equipment issues (IR 4071797); source range monitor performance (IR 4082782); instrument air performance issues (IR 4061492); maintenance and technical training quality (IR 4041350); reactor recirculation adjustable speed drive system performance (IR 4061712); ventilation systems performance (IR 4035745); and 4kV breaker issues (IR 4021996). The inspectors also identified potential adverse trends in area radiation monitor performance; control rod drive/rod position indication system performance; and direct current (DC)system performance (grounds). Specific examples associated with these trends included, but were not limited to:

• abnormal operating procedures entries for rod position indication failure (IRs 4060528, 4060526, and 4040337);

• numerous Unit 2, 125 VDC system grounds (IRs 4083357, 4071210, 4065977, 4034419, 4031202, 4000497, and 3965179); and

• numerous false spurious high radiation and downscale failures of area radiation monitors (IRs 4066595, 4064804, 4054695, 4046011, 4018908, and 4009373).

c. Findings

No findings were identified.

.3 Annual Follow-up of Selected Issues: Review of the Licensees Corrective Actions

Associated with Non-Cited Violation 05000237/2017001-01; 05000249/2017001-01, Failure to Correct a Condition Adverse to Quality Associated with Emergency Diesel Generator Single Largest Load Rejection Surveillance Testing

a. Inspection Scope

The inspectors performed a review of the licensees CAP and associated documents, specifically Corrective Action Program Evaluation Report 3964435, DOS 6600-12 Procedure Revision Inadequate. The inspectors interviewed personnel, reviewed engineering analysis documents associated with the single largest load operated on an EDG during accident conditions, reviewed historical surveillance testing and performance records for the Unit 2, Unit 3, and 2/3 EDGs, reviewed procedure changes for performing a single largest load rejection surveillance while parallel with the grid and while separated from the grid, and observed successful surveillance testing of the Unit 2 and 2/3 EDGs.

The inspectors review and evaluation was focused on the causal determination for this safety related surveillance test which ensures the EDG does not trip on overspeed during accident conditions following a trip of a core spray pump, which has been analyzed as the largest load on an EDG post-accident at 720 kilowatts (KW). In addition, the licensees corrective actions were reviewed to ensure they: were complete, accurate, and timely; considered extent of condition; provided appropriate classification and prioritization; provided identification of apparent and contributing causes; were appropriately focused; included action taken which resulted in the correction of the identified problem; ensured operating experience was adequately evaluated for applicability; and communicated applicable lessons learned to appropriate organizations.

This review constituted a single follow-up inspection sample for in-depth review as defined in IP 71152-05.

b. Background During a January 2017 review of licensee CAP documents associated with historic issues identified in the area of surveillance testing, the inspectors noted IR 2501498, TSSR [Technical Specification Surveillance Requirement] 3.8.1.10: EDG Largest Load Reject, dated May 15, 2015. The IR described a condition identified by operations personnel which stated that when TSSR 3.8.1.10 was performed a service water pump, which had been identified in the Technical Specification Bases document and engineering documents as the single largest load, was to reject 686 KW under accident conditions. A review of actual load rejection during the most recent performances of this surveillance for all three EDGs indicated an actual load rejection of between 525-575 KW. The lower KW rejected were due to a lower heat load on the service water system in the colder month of November when the tests are performed during the Dresden Unit 2 or 3 refueling outages.

TSSR 3.8.1.10 specifically requires that each EDG reject a load greater than or equal to its associated single largest post-accident load, and:

a) following load rejection, frequency 66.73 hertz (Hz);b) within 3 seconds following load rejection, voltage is 3952 V and 4368 V; and c) within 4 seconds following load rejection, the frequency is 58.8 Hz and 61.2 Hz.

The licensee performed the rejection of a service water pump with its respective EDG solely powering their associated safety related buses as a part of operations surveillance procedures DOS 6600-03, Bus Undervoltage and ECCS Integrated Functional Test for Unit 2/3 Diesel Generator to Unit 3; DOS 6600-04, Bus Undervoltage and ECCS Integrated Functional Test for Unit 3 Diesel Generator; DOS 6600-05, Bus Undervoltage and ECCS Integrated Functional Test for Unit 2 Diesel Generator; and DOS 6600-06, Bus Undervoltage and ECCS Integrated Functional Test for Unit 2/3 Diesel Generator to Unit 2. These procedures performed the single largest load rejections utilizing the acceptance criteria called out by TSSR 3.8.1.10, but did not have operators verify that at least 686 KW was rejected, therefore ensuring that the EDG would be able to meet acceptance criteria under design post-accident conditions. Actual load rejected was between 525 and 575 KW due to lower loading on the service water system during the month of November when the tests were performed.

In addition to performing a single largest load reject surveillance, the licensee also performs a full load reject in accordance with TSSR 3.8.1.11 in which the EDG must reject 2340 KW and 2600 KW while not experiencing an over speed trip or exceeding a generator output 5000 V. The licensee accomplishes this surveillance requirement with the EDG fully loaded and in parallel with the electrical grid. Operations surveillance procedure DOS 6600-12, Diesel Generator Tests Endurance and Margin/Full Load Rejection/ECCS/ Hot Restart is used to accomplish this surveillance requirement. The inspectors determined that a performance deficiency and violation of NRC requirements existed for the licensees failure to take corrective actions for a condition adverse to quality, specifically the failure to adequately test the EDGs with respect to TSSR 3.8.1.10. This issue was originally documented as NCV 05000237/2017001-01; 05000249/2017001-01, Failure to Correct a Condition Adverse to Quality Associated with EDG Single Largest Load Rejection Surveillance Testing in NRC Integrated Inspection Report 05000237/2017001 and 05000249/2017001 (ML17110A423).

c. Observations The inspectors validated that the licensee incorporated adequate procedure changes for performing a single largest load rejection in accordance with Technical Specification Surveillance Requirement (TSSR) 3.8.1.10 into procedures DOS 6600-01, Diesel Generator Surveillance Tests; DOS 6600-03, Bus Undervoltage and ECCS Integrated Functional Test for Unit 2/3 Diesel Generator to Unit 3; DOS 6600-04, Bus Undervoltage and ECCS Integrated Functional Test for Unit 3 Diesel Generator; DOS 6600-05, Bus Undervoltage and ECCS Integrated Functional Test for Unit 2 Diesel Generator; and DOS 6600-06, Bus Undervoltage and ECCS Integrated Functional Test for Unit 2/3 Diesel Generator to Unit 2. In addition, the inspectors reviewed engineering analysis documents created by the licensee which established the single largest load on a post-accident EDG as a core spray pump at 720KW. Lastly, the inspectors observed successful completion of TSSR 3.8.1.10 for the Unit 2 and 2/3 EDGs and noted that the licensee is scheduled to perform TSSR 3.8.1.10 for the Unit 3 EDG during the 2018 Unit 3 refueling outage D3R25.

d. Findings

No findings were identified.

.4 Annual Follow-Up of Selected Issues: Corrective Action Program Evaluation

Report 04014904, U.S. Nuclear Regulatory Commission Questions Environmental Qualification for Emergency Diesel Generator Auto Start Relay

a. Inspection Scope

The inspectors performed a review of the licensees CAP and associated documents, specifically Corrective Action Program Evaluation Report 04014904, NRC Questions EQ [Environmental Qualification] for EDG Auto Start Relay.

The licensees corrective actions were reviewed to ensure they: were complete, accurate, and timely; considered extent of condition; provided appropriate classification and prioritization; provided identification of apparent and contributing causes; were appropriately focused; included action taken which resulted in the correction of the identified problem; ensured operating experience was adequately evaluated for applicability; and communicated applicable lessons learned to appropriate organizations.

In addition, the inspectors reviewed the licensees extent of condition. The inspectors review and evaluation was focused on the licensees justification that the identified non-EQ qualified interposing relays did not need to be qualified.

This review constituted a single follow-up inspection sample for in-depth review as defined in IP 71152-05.

b. Background During a baseline post maintenance testing inspection of the Unit 3 EDG performed by the Dresden resident inspectors in May 2017, the inspectors noted that the licensee had previously replaced the auto start relay (ASR) with a non-EQ part in 2006 and was only now replacing the part as EQ. The inspectors asked the licensee questions about the operability assessment of the ASR when it was a non-EQ part and the timing of the replacement. The licensee entered this issue into the corrective action program as IR 04014904, NRC Questions EQ for EDG Auto Start Relay on May 24, 2017.

The licensee preformed an extent of condition and reviewed 32 components in the EDG and found that all of the components were EQ and seismically qualified with the exception of the interposing relays. The licensees justification for why the interposing relays did not need to be EQ qualified was that the relays perform their safety-related function of closing the output breaker on the EDG in 13 seconds which is before the harsh environment would reach the component. In the loss of coolant accident scenario the licensee has evaluated that it takes approximately 60 minutes for the area where the interposing relays are located to reach a harsh environment. In a high energy line break scenario the licensee evaluated that at the 13 second mark the interposing relays would, through thermal lag effect, not experience the harsh environment. In addition, the licensee noted that the interposing relays, model number GE relay model 12HGA11J52, are the same model as the ASR relays which are currently EQ qualified. The inspectors reviewed the licensees EQ Screening Considerations and Checklist for the interposing relays, the design specifications for the ASR and interposing relays, and the EQ and Seismic Qualification for the EDG ASR.

c. Findings

No findings were identified.

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

.1 (Closed) Licensee Event Report 05000249/2017-001-00: Unit 3 Standby Liquid Control

System Inoperable Due to a Manufacturing Defect Causing a Piping Leak

a. Inspection Scope

The inspectors reviewed the licensees response to and assessment of a through-wall leak which developed on the Unit 3 standby liquid control (SBLC) system common discharge piping. Specifically, on September 10, 2017, during equipment operator (EO)rounds, the EO found crystalized boron on Unit 3 SBLC discharge piping. There was no visible active leak and the source of the boron crystals was unknown, therefore the licensee staffed the outage control center to investigate the source of the boron crystals.

On September 12, 2017, the Division 1 SBLC pump was started to pressurize the system to the normal in-service testing pressure. A leak of approximately one drop per minute was identified on the common discharge line of the SBLC pumps which is ASME Code Class 2 piping. Due to the piping being ASME Code Class 2, the licensee was required to isolate it in accordance with Technical Requirements Manual 3.4.a, Structural Integrity. Isolating this piping resulted in both divisions of SBLC being declared inoperable, thus entering TS Limiting Condition for Operations (LCO) 3.1.7 with an action to restore one SBLC subsystem to operable status within eight hours. The licensee requested a Notice of Enforcement Discretion (NOED) to exceed the TS eight hours completion time to complete the pipe repair. The NRC granted a verbal NOED on September 12, 2017, followed by a letter on September 18, 2017 (ML17261B237). The licensee completed the repair and restored the SBLC system to operable status within the Technical Specification (TS) eight hour completion time. Follow-up investigation and testing of the failed piping indicated a manufacturing defect which evolved into a through-wall leak. The piping that failed had been in service since Dresden Unit 3 started operating in 1971.

The licensee reported this event in accordance with 10 CFR 50.73(a)(2)(v)(A)and 10 CFR 50.73(a)(2)(v)(D), any event or condition that could have prevented the fulfillment of the safety function of structures or systems that are needed to shut down the reactor and maintain it in a safe shutdown condition and mitigate the consequences of an accident. Documents reviewed are listed in the Attachment to this report. This Licensee Event Report (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 05000249/2017003-01,Granted Notice of Enforcement

Discretion 17-3-001: Limiting Condition for Operations 3.1.7 Required Action B.1 per Technical Specification 3.1.7, Standby Liquid Control System The inspectors reviewed the licensees response to and assessment of a through-wall leak which developed on the Unit 3 SBLC A pump discharge piping. Specifically, on September 12, 2017, during a system operational pressure test, a through-wall leak was observed coming from the forged body of a 1.5 stainless steel pipe tee in the Unit 3 SBLC system. The affected component is a part of the ASME Code Class 2 boundary.

Due to the piping being ASME Code Class 2, it was required to be immediately isolated in accordance with Technical Requirements Manual 3.4.a, Structural Integrity. Isolating this piping resulted in both trains of the Unit 3 SBLC system becoming inoperable as the leak was unisolable from both pumps. With both trains inoperable, the licensee entered LCO 3.1.7, Required Action B.1 which requires the restoration of at least one train of SBLC within 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br />.

The inspectors examined the sites actions to uncover the issue with the Unit 3 SBLC system, their actions to address the issue once it was identified, and their compensatory actions associated with the receipt of the NOED. The inspectors also reviewed licensee documents to verify that information contained in the NOED request was accurate.

Inspection activities included gathering additional information on the licensees bases for needing the NOED; examining the sites decision-making process for the issue; reviewing the licensees condition evaluation; observing the licensees compensatory actions; and evaluating the licensees operability determination. To correct this issue and exit the NOED, the licensee completed replacement of the affected Unit 3 piping and connections, satisfactorily tested the replaced components, and declared the Unit 3 SBLC system operable. The failed tee is part of original pipe installation in 1971. The licensee determined the cause was a manufacturing defect which evolved into a through-wall leak when the closely spaced inclusions from the manufacturing process opened up and linked due to service induced stresses to form a leak path. Structural Integrity Associates performed an historic operability evaluation of the flawed tee and determined the resulting leak would not have prevented the SBLC system form performing its intended function.

The inspectors determined that there was no violation of regulatory requirements. This item is closed.

4OA6 Management Meetings

.1 Exit Meeting Summary

On January 8, 2018, the inspectors presented the inspection results to Mr. P. Karaba 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 inspection results for the Triennial Review of Heat Sink Performance were discussed with Mr. J. Washko, Plant Manager; and other plant staff on October 20, 2017.

• The results of the ISI with the Site Vice President Mr. P. Karaba and other members of the licensee staff on November 3, 2017.

• The inspection results for the Radiation Safety Program review with Mr. P. Karaba, Site Vice President, on November 3, 2017 and again on December 1, 2017.

• The results of the Emergency Preparedness Program inspection with Mr. B. Franzen, Regulatory Assurance Manager, conducted over the phone on December 14, 2017.

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.

ATTACHMENT:

SUPPLEMENTAL INFORMATION

KEY POINTS OF CONTACT

Licensee

P. Karaba, Site Vice President

J. Washko, Station Plant Manager

Q. Alsup, Chemistry Specialist

D. Anthony, NDE Services Manager

L. Antos, Manager Site Security

J. Banks, Security Programs Lead

R. Bauman, Shift Operations Superintendent

M. Budelier, Senior Engineering Manager

H. Bush, Radiation Protection Manager

P. DiSalvo, Engineer

D. Doggett, Emergency Preparedness Manager

B. Franzen, Regulatory Assurance Manager

F. Gogliotti, Director, Site Engineering

P. Hansett, Operations Director

J. Jones, Rad Waste Coordinator

J. Kish, Engineer

K. Kretsinger, Manager Site Security Operations

A. Martin, Chemistry Manager

S. Matzke, Corrective Action Program Coordinator

A. McMartin, Manager Site Chemistry, Environment & Radwaste

J. Miller, NDE Services

M. Pansera, Engineer

M. Pavey, Health Physicist

S. Peacock, Security Scheduling and Oversight Lead

T. Pile, Manager Security Training

F. Polak, Senior Engineer

J. Quinn, Director, Site Maintenance

W. Remiasz, Work Control Director

F. Sadnick, Security Operations Supervisor

B. Sampson, Organizational Effectiveness Manager

D. Siuda, Licensed Operator Requal Author and Instructor

D. Thomas, Director, Site Training

D. Walker, Regulatory Assurance - Senior NRC Coordinator

D. Wolverton, Manager, Design Engineering Mechanical

IEMA

M. Porfirio, Resident Inspector, Illinois Emergency Management Agency

L. Torres, ASME Inspector, IEMA

U.S. Nuclear Regulatory Commission

J. Cameron, Chief, Reactor Projects Branch 4

LIST OF ITEMS OPENED, CLOSED, AND DISCUSSED

Opened

05000237/2017004-01 NCV Failure to Follow Procedure, Results in Non-Functional

05000249/2017004-01 Fire Door (1R05)

Closed

05000237/2017004-01 NCV Failure to Follow Procedure, Results in Non-Functional

05000249/2017004-01 Fire Door (1R05)

05000249/2017-001-00 LER Standby Liquid Control System Inoperable Due to a Manufacturing Defect Causing a Piping Leak

05000249/2017003-01 URI Granted Notice of Enforcement Discretion 17-3-001:

LCO 3.1.7 Required Action B.1 per TS 3.1.7, Standby Liquid Control System