IR 05000454/2014002

IR 05000454-14-002, 05000455-14-002 and 07200068-14-001; 01/01/2014 - 03/31/2014; Byron Station, Units 1 & 2; Fire Protection

ML14127A317
Person / Time
Site:	Byron
Issue date:	05/07/2014
From:	Eric Duncan Region 3 Branch 3
To:	Pacilio M Exelon Generation Co
References
IR-14-002
Download: ML14127A317 (55)

Text

UNITED STATES NUCLEAR REGULATORY COMMISSION May 7, 2014

SUBJECT:

BYRON STATION, UNITS 1 AND 2, NRC INTEGRATED INSPECTION REPORT 05000454/2014002; 05000455/2014002; AND 07200068/2014001

Dear Mr. Pacilio:

On March 31, 2014, the U.S. Nuclear Regulatory Commission (NRC) completed an integrated inspection at your Byron Station, Units 1 and 2. The enclosed report documents the results of this inspection, which were discussed on April 3, 2014, with Mr. B. Youman, and other members of your staff.

Based on the results of this inspection, one self-revealed finding of very low safety significance was identified. The finding involved a violation of NRC requirements. However, because the finding was of very low safety significance, and because the issue was entered into your corrective action program, the NRC is treating the violation as a non-cited violation (NCV) in accordance with Section 2.3.2 of the NRC Enforcement Policy. Additionally, two licensee-identified violations are listed in Section 4OA7 of this report.

If you contest the subject or severity of any 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 a copy to the Regional Administrator, U.S. Nuclear Regulatory Commission - Region III, 2443 Warrenville Road, Suite 210, Lisle, IL 60532-4352; the Director, Office of Enforcement, U.S.

Nuclear Regulatory Commission, Washington, DC 20555-0001; and the Resident Inspector Office at the Byron Station.

If you disagree with the cross-cutting aspect assigned to any finding in this report, you should provide a response within 30 days of the date of this inspection report, with the basis for your disagreement, to the Regional Administrator, Region III, and the NRC Resident Inspector at the Byron Station.

Additionally, as we informed you in the most recent NRC integrated inspection report, cross-cutting aspects identified in the last 6 months of 2013 using the previous terminology were being converted in accordance with the cross-reference in Inspection Manual Chapter (IMC) 0310. Section 4OA5 of the enclosed report documents the conversion of these cross-cutting aspects which will be evaluated for cross-cutting themes and potential substantive cross-cutting issues in accordance with IMC 0305 starting with the 2014 mid-cycle assessment review. If you disagree with the cross-cutting aspect assigned, you should provide a response within 30 days of the date of this inspection report, with the basis for your disagreement, to the Regional Administrator, Region III, and the NRC Resident Inspector at the Byron Station.

In accordance with Title 10 of the Code of Federal Regulations 2.390, Public Inspections, Exemptions, Requests for Withholding, of the NRC's "Rules of Practice," a copy of this letter and its enclosure, and your response (if any) will be available electronically for public inspection in the NRC Public Document Room or from the Publicly Available Records System (PARS)

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

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

Sincerely,

/RA/

Eric R. Duncan, Chief Branch 3 Division of Reactor Projects Docket Nos. 50-454; 50-455;72-068 License Nos. NPF-37; NPF-66

Enclosure:

IR 05000454/2014002; 05000455/2014002; and 07200068/2014001 w/Attachment: Supplemental Information

REGION III==

Docket Nos: 50-454; 50-455;72-068 License Nos: NPF-37; NPF-66 Report No: 05000454/2014002; 05000455/2014002; and 07200068/2014001 Licensee: Exelon Generation Company, LLC Facility: Byron Station, Units 1 and 2 Location: Byron, IL Dates: January 1 through March 31, 2014 Inspectors: J. McGhee, Senior Resident Inspector J. Robbins, Resident Inspector J. Cassidy, Senior Health Physicist M. Holmberg, Reactor Inspector M. Learn, Reactor Engineer C. Thompson, Resident Inspector, Illinois Emergency Management Agency B. Metrow, Inspector, Illinois Emergency Management Approved by: E. Duncan, Chief Branch 3 Division of Reactor Projects Enclosure

SUMMARY OF FINDINGS

Inspection Report 05000454/2014002, 05000455/2014002 and 07200068/2014001; 01/01/2014 - 03/31/2014; Byron Station, Units 1 & 2; Fire Protection.

This report covers a 3-month period of inspection by resident inspectors and announced baseline inspections by regional inspectors. Additionally, a review of unresolved items associated with the Independent Spent Fuel Storage Installation (ISFSI) was conducted by regional inspectors. One Green finding was identified by the inspectors. The finding was considered a non-cited violation (NCV) of 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 June 2, 2011. Cross-cutting aspects are determined using IMC 0310, Components Within the Cross-Cutting Areas, dated January 1, 2014. All violations of NRC requirements are dispositioned in accordance with the NRCs Enforcement Policy dated July 9, 2013. The NRC's program for overseeing the safe operation of commercial nuclear power reactors is described in NUREG-1649, Reactor Oversight Process, Revision 4.

NRC-Identified

and Self-Revealed Findings

Cornerstone: Initiating Events

Green.

A finding with two examples of very low safety significance and an associated non-cited violation of Technical Specification 5.4.1.c was self-revealed when required compensatory fire watches were discovered to have been terminated while the fire systems were still impaired. Specifically, the licensee failed to maintain compensatory fire watches for Fire Zone 3.1-1, Unit 1 Electrical Cable Tunnel, and for Fire Zones 10.1-2, 2B Diesel Fuel Oil Storage Room, and 10.2-2, 2A Diesel Fuel Oil Storage Room, required by procedure OP-MW-201-007, Fire Protection System Impairment Control, and as described in the Technical Requirements Manual (TRM) limiting condition for operations. The licensee entered this issue into their Corrective Action Program (CAP) as Issue Report (IR) 1596029, Fire Watches Missed Due To 1DSH120 Installation, and IR 1603889, Fire Watch Suspended Prematurely in Diesel Oil Storage Tank Room.

The inspectors determined that this finding was more than minor in accordance with IMC 0612, Appendix B, Issue Screening, because the finding was associated with the Initiating Events cornerstone attribute of Protection Against External Factors (Fire) and adversely affected the cornerstone objective of limiting the likelihood of those events that upset plant stability and challenge critical safety functions during plant operations.

Specifically, required fire watches established as compensatory measures should have been maintained for the duration of the work activity so that the sites ability to promptly detect and suppress a fire would be maintained. The inspectors evaluated this issue in accordance with IMC 0609, Significance Determination Process, Attachment 0609.04,

Initial Characterization of Findings. In Table 3 of Attachment 4, SDP [Significance Determination Process] Appendix Router, the inspectors answered Yes to Question E.2, Does the finding involve:(2) Fixed fire protection systems.? Therefore, the inspectors continued the risk evaluation using IMC 0609, Appendix F, Fire Protection Significance Determination Process. Due to the equipment located in each of the affected fire zones, the two examples were evaluated independently. The first example screened as Green using the questions under Task 1.4.2 for fixed fire protection systems. For the second example, a Senior Reactor Analyst (SRA) performed a quantitative Phase 2 evaluation and determined the issue to be

Green.

The inspectors determined that a principle contributor to the finding was that the organization did not implement a process for planning, implementing, and executing concurrent work activities that ensured the required compensatory actions were maintained such that nuclear safety was the overriding priority (WP.1). As a result, the inspectors assigned a cross-cutting aspect of Work Management (H.5) to the finding. (Section 1R05.1.b (1))

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

REPORT DETAILS

Summary of Plant Status

Unit 1 The unit began the period at full licensed thermal power and operated at or near full power until February 12, 2014, when an NRC-approved Measurement Uncertainty Recapture Power Uprate was implemented per Engineering Change (EC) 378382 that raised licensed thermal power by approximately 1.6 percent. The unit operated at or near the new full power limit until March 10, 2014, when the unit was shut down for a scheduled refueling outage. The unit was restarted on March 27, 2014, reaching full power on March 30, 2014. The unit operated at or near the new full power for the remainder of the inspection period.

Unit 2 The unit began the period at full licensed thermal power and operated at or near full power until January 14, 2014, when two control rods became misaligned during surveillance testing. One rod dropped to the full in position and a second rod dropped to an intermediate position.

Reactor power was reduced to approximately 40 percent while repairs were completed and the rods were tested and realigned. The unit returned to full licensed thermal power on January 17, 2014, and operated at or near full power until February 10, 2014, when an NRC-approved Measurement Uncertainty Recapture Power Uprate was implemented per EC 378383 that raised licensed thermal power by approximately 1.6 percent. The unit operated at or near the new full power for the remainder of the inspection period.

REACTOR SAFETY

Cornerstones: Initiating Events, Mitigating Systems, and Barrier Integrity

1R04 Equipment Alignment

.1 Quarterly Partial System Walkdowns

a. Inspection Scope

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

• 1B emergency diesel generator air and fuel oil systems with the 1A emergency diesel generator out of service for maintenance and switchyard work activities in progress;

• Unit 2 main generator stator cooling system;

• 1B essential service water pump and associated piping; and

• 1B residual heat removal system during refueling outage when protected for shutdown cooling.

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, the Updated Final Safety Analysis Report (UFSAR), Technical Specification (TS) requirements, outstanding work orders (WOs), issue reports (IRs),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

.

These activities constituted four partial system walkdown samples as defined in Inspection Procedure (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 the availability, accessibility, and condition of firefighting equipment in the following risk-significant plant areas:

• Fire Zone 11.3-0, Auxiliary Building, Elevation 364', General Area;

• Fire Zone 5.2-1, Auxiliary Building, Elevation 426', Unit 1 Division 11 Engineered Safety Feature (ESF) Switchgear Room;

• Fire Zone 3.3A-2, Auxiliary Building, Elevation 463', Unit 2 Upper Cable Spreading Room;

• Fire Zone 11.1A-0, Auxiliary Building, Elevation 330, Unit 1 Essential Service Water Pump Room;

• Fire Zone 11.1B-0, Auxiliary Building, Elevation 330, Unit 2 Essential Service Water Pump Room; and

• Fire Zone 5.4-1, Auxiliary Building, Elevation 451', Unit 1 Division 12, Miscellaneous Electrical Equipment and Battery Room.

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

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

b. Findings

(1) Failure to Properly Implement a Compensatory Fire Watch as Required by the Fire Protection Program

Introduction:

A self-revealed finding with two examples of very low safety significance (Green) and an associated NCV of TS 5.4.1.c was identified for the failure to maintain compensatory fire watches for Fire Zone 3.1-1, Unit 1 Electrical Cable Tunnel, and for Fire Zones 10.1-2, 2B Diesel Fuel Oil Storage Room, and 10.2-2, 2A Diesel Fuel Oil Storage Room, in accordance with fire protection program (FPP) requirements.

Specifically, the licensee failed to implement the compensatory fire watches required by procedure OP-MW-201-007, Fire Protection System Impairment Control, and as described in TRM limiting condition for operations (LCOs) for the affected fire zones.

Description:

On December 11, 2013, during planned activities, the CO2 (carbon dioxide)suppression system was isolated from Fire Zone 3.1-1, Unit 1 Electrical Cable Tunnel.

Access to the tunnel was achieved via a hatch that must be unbolted and removed. The cable tunnel is a confined space and the suppression system was isolated to ensure personnel safety. The required compensatory measures identified in the TRM for mitigating this case were: 1) ensuring automatic fire detection instrumentation was operable, 2) ensuring that fire wrap in the fire zone was operable, and 3) establishing an hourly fire watch. The appropriate actions were initially put in place. After work in the tunnel had been completed, the hatch was reinstalled. The fire watch was secured when the hatch was reinstalled, but the fire suppression system was not restored to an operable condition. The inappropriate suspension of the fire watch was revealed during restoration activities associated with the suppression system approximately 15 hours1.736111e-4 days <br />0.00417 hours <br />2.480159e-5 weeks <br />5.7075e-6 months <br /> later.

On January 3, 2014, during planned activities associated with the fire suppression system in the diesel oil storage tank rooms, water was isolated from the suppression system for Fire Zones 10.1-2 and 10.2-2, 2B and 2A Diesel Fuel Oil Storage Rooms.

Valve repairs were planned that required the water to be isolated to facilitate maintenance. Additionally, a second maintenance group was correcting an issue associated with the automatic fire detection equipment. TRM LCOs 3.10.a and 3.10.c required compensatory measures for mitigating this condition. TRM LCO 3.10.a required an hourly fire watch and TRM LCO 3.10.c required either an hourly fire watch or automatic fire detection instrumentation to be verified operable. When the second work group completed restoration of the detection equipment, the fire watch was secured.

While this was permitted under TRM LCO 3.10.c, it did not address the limitations under 3.10.a. The inappropriate suspension of the fire watch was revealed during restoration activities associated with suppression system testing approximately 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> later.

Analysis:

The inspectors determined that the failure to maintain compensatory fire watches as required by the FPP for two different fire zones during separate events was a performance deficiency warranting further review.

The inspectors determined that this finding was more than minor in accordance with IMC 0612, Appendix B, Issue Screening, dated September 7, 2012, because the finding was associated with the Initiating Events cornerstone attribute of Protection Against External Factors (Fire) and adversely affected the cornerstone objective of limiting the likelihood of those events that upset plant stability and challenge critical safety functions during plant operations. Specifically, required fire watches established as compensatory measures should have been maintained for the duration of the work activity so that the sites ability to promptly detect and suppress a fire would be maintained.

The inspectors evaluated this issue in accordance with IMC 0609, Significance Determination Process, Attachment 0609.04, Initial Characterization of Findings. In Table 3 of Attachment 4, SDP Appendix Router, the inspectors answered Yes to Question E.2, Does the finding involve:(2) Fixed fire protection systems.?

Therefore, the inspectors continued the risk evaluation using IMC 0609, Appendix F, Fire Protection Significance Determination Process. Due to the equipment located in each of the affected fire zones, the two examples were evaluated independently.

The January event was evaluated in accordance with Appendix F as an impact to a zone served by a fixed fire protection system. Using Figure F.1, Phase 1 Flow Chart, the inspectors evaluated the issue using the questions in Task 1.4.2, Fixed Fire Protection Systems, and answered each of the screening questions No until question 1.4.2.E, Does the finding only affect a manually actuated suppression system for an area that is accessible by the fire brigade? The inspectors answered this question Yes and determined the finding as it related to this event to be of very low safety significance (Green) with no further analysis required.

The fire zone impacted by the December event contained both Division 1 and Division 2 electrical cables and required a more detailed evaluation. The inspectors used IMC 0609, Appendix F, Attachment 2, Degradation Rating Guidance Specific to Various Fire Protection Program Elements, dated February 28, 2005, and assigned the first example a high degradation because the inspectors determined that the suppression systems would not function while in a maintenance configuration. The inspectors assigned a duration factor of 0.01 for the time period the fire watches were not implemented. Using Attachment 1, Fire Protection Significance Determination Process Worksheet, the inspectors performed the screening check determining a change in core damage frequency of 4E-5. This change in core damage frequency was above the value identified in Appendix F, Table 1.5.4, for no additional analysis required, and therefore a Phase 2 analysis was needed.

Using Figure F.1, Phase 1 Flow Chart, the inspectors evaluated the issue using the questions in Task 1.4.2, Fixed Fire Protection Systems, and answered No to all the questions. Pertinent to the No answer of Question E was that the fire brigade would be delayed entering the Unit 1 cable tunnel due to the need to remove a floor access plate.

In Task 1.4.6, Manual Fire Fighting, the inspectors answered Yes to Question C: Is the fire finding associated with an observed fire drill deficiency or equipment deficiency which could have delayed suppression of a fire by more than 5 minutes? Therefore, the risk evaluation continued with a quantitative evaluation and was performed by the Region III senior reactor analyst (SRA).

The SRA estimated the frequency of fire in the Unit 1 cable tunnel as 1.4E-03/year using Table A1.3 of IMC 0609, Attachment 1, Fire Frequency Evaluation Worksheet. This value reflected the assumption that the cable tunnel contained nonqualified cables with high loading. This value was adjusted to the exposure time of 15 hours1.736111e-4 days <br />0.00417 hours <br />2.480159e-5 weeks <br />5.7075e-6 months <br />, such that the effective fire frequency used in this risk evaluation was 2.40E-06/year.

Control, instrumentation, and power cables associated with ESF Divisions 11 and 12 are located in the Unit 1 cable tunnel according to a December 2010 License Amendment for Byron (Amendment 24). The SRA contacted the licensee PRA staff and obtained a specific list of components that are assumed failed as a result of a fire in the cable tunnel. Using the Byron Standardized Plant Analysis Risk model, Version 8.25, and Systems Analysis Programs for Hands-on Integrated Reliability Evaluations, (SAPHIRE) Version 8.0.9.0, the SRA performed an initiating event assessment assuming a transient initiating event with failure of the equipment from the licensees list.

The result was a Conditional Core Damage Probability (CCDP) of 1.47E-02.

Using the above information, the delta core damage frequency (CDF) for this finding was estimated to be 3.53E-08/year. The dominant core damage sequence involved a transient initiating event, failure of auxiliary and main feedwater, failure to recover feedwater, and failure of high pressure recirculation. Based on the Detailed Risk Evaluation, the SRAs determined that the finding was of very low safety significance (Green).

The inspectors determined that a principle contributor to the finding was that the organization did not implement a process for planning, implementing, and executing concurrent work activities that ensured the required compensatory actions were maintained such that nuclear safety was the overriding priority (WP.1). As a result, the inspectors assigned a cross-cutting aspect of Work Management (H.5) to the finding.

Enforcement:

Technical Specification 5.4.1.c, Fire Protection Program Implementation, for Units 1 and 2 required that written procedures be established, implemented, and maintained, covering activities related to FPP implementation. As part of its FPP implementation, the licensee had established procedures which provided guidelines for control of fire protection and safe shutdown equipment. Procedure OP-MW201-007, Fire Protection System Impairment Control, established the requirements for compensatory measures and performance of fire watches. Specifically, Step 4.2.9 required compensatory measures for inoperable fire protection systems, structures, and components (SSCs) to be established in accordance with the TRM.

• TRM Table 3.10.d-1 required Fire Zone 3.1-1, Unit 1 Cable Tunnel, to be maintained in accordance with Condition B of 3.10.d. Technical Requirements Manual 3.10.d Condition B required, in part, that hourly fire watches be established.

• TRM Table 3.10.a required Fire Zones 10.1-2, 2B Diesel Fuel Oil Storage Room, and 10.2-2, 2A Diesel Fuel Oil Storage Room, be maintained in accordance with Condition B of 3.10.a. Technical Requirements Manual 3.10.a Condition B required, in part, that hourly fire watches be established.

Contrary to the above, on December 11 and 12, 2013, and again on January 3, 2014, the licensee failed to implement the FPP requirements for compensatory fire watches as required by OP-MW201-007 for the affected fire zones. Specifically, the licensee failed to maintain the required hourly fire watch for the duration of the work activities.

Because this violation was of very low safety significance (Green) and was entered into the licensees CAP as IR 1596029, Fire Watches Missed Due To 1DSH120 Installation, and IR 1603889, Fire Watch Suspended Prematurely in Diesel Oil Storage Tank Room, this violation is being treated as an NCV consistent with Section 2.3.2 of the Enforcement Policy (NCV 05000454/2014002-01; 05000455/2014002-01, Failure to Properly Implement a Compensatory Fire Watch As Required by the Fire Protection Program).

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. The inspectors reviewed flood analyses and design documents, including the UFSAR, engineering calculations, and abnormal operating procedures to identify licensee commitments. 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 also reviewed the licensees corrective action documents with respect to past flood-related items identified in the CAP to verify the adequacy of the corrective actions. The inspectors performed a walkdown of the following plant areas to assess the adequacy of watertight doors and verify drains and sumps were clear of debris and were operable, and that the licensee complied with its commitments:

• Units 1 and 2 Essential Service Water Pump Rooms; and

• Upper Cable Spreading Room.

Documents reviewed are listed in the Attachment.

This inspection constituted two internal flooding samples as defined in IP 71111.06-05.

b. Findings

No findings were identified.

1R08 Inservice Inspection Activities

From March 10, 2014 through March 20, 2014, the inspectors conducted a review of the implementation of the licensees Inservice Inspection (ISI) Program for monitoring degradation of the Unit 1 reactor coolant system, steam generator (SG) tubes, emergency feedwater systems, risk-significant piping and components, and containment systems.

The reviews described in Sections 1R08.1, 1R08.2, 1R08.3, 1R08.4, and 1R08.5 below constitute one inspection sample as described by IP 71111.08.

.1 Piping Systems Inservice Inspection

a. Inspection Scope

The inspectors observed and reviewed records of the following non-destructive examinations required by the American Society of Mechanical Engineers (ASME)

Section XI Code, and/or 10 CFR 50.55a to evaluate compliance with the ASME Code,Section XI, and Section V requirements, and if any indications and defects were detected, to determine whether these were dispositioned in accordance with the ASME Code or an NRC-approved alternative requirement:

• Ultrasonic (UT) examination of four safety injection line pipe welds (1SI08FA-3/J29, J30, J31 and J32);

• Magnetic Particle (MT) and UT examination of feedwater shell-to-nozzle weld (1RC-01-BB/N-3);

• Liquid Penetrant (PT) examination of safety injection line closure plate support-to-pipe weld (1SI08JA-1.5/W-15a); and

• Liquid penetrant of reactor vessel head penetration No. 31 and No. 43 repair welds.

The inspectors reviewed the following examination records with relevant/recordable conditions/indications identified by the licensee to determine whether acceptance of these indications for continued service was in accordance with the ASME Code Section XI or an NRC-approved alternative.

• MT examination of 2B Steam Generator (SG) nozzle-to-shell weld 2RC-01-BB/SGN-03 (Reports Nos. B2R17-MT-001 and B2R17-MT-003).

The inspectors reviewed records of the following risk-significant pressure boundary ASME Code Section XI Class 1 welds fabricated since the beginning of the last refueling outage to determine if the licensee followed the welding procedure, applied appropriate weld filler material, and implemented the applicable Section XI or Construction Code non-destructive examinations and acceptance criteria. 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 ASME Code Section IX.

• Class 1 - Replace Valve 1RC8042C - Isolation Valve in Cold Leg Bypass Line - Weld Nos. 1, 2, and 3 (WO 1549925); and

• Class 2 - Repair Weld-to-Valve Body 1SD054E - 1B SG Blowdown Valve - Weld No. 2 (WO 01386972-01).

b. Findings

No findings were identified.

.2 Reactor Pressure Vessel Upper Head Penetration Inspection Activities

a. Inspection Scope

For the Unit 1 vessel head, a bare metal visual examination as well as non-visual examinations were required this outage pursuant to 10 CFR 50.55a(g)(6)(ii)(D).

The inspectors observed portions of the visual examination conducted on the Unit 1 reactor vessel head to determine if the activities were conducted in accordance with the requirements of ASME Code Case N-729-1 and 10 CFR 50.55a(g)(6)(ii)(D). In particular, the inspectors confirmed for a sample of penetration locations that:

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

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

• if indications of potential through-wall leakage were identified, the licensee entered the condition into the CAP and implemented appropriate corrective actions.

The inspectors also observed the UT and PT examinations conducted on the Unit 1 reactor vessel head penetrations, to determine whether the activities were conducted in accordance with the requirements of ASME Code Case N-729-1 and 10 CFR 50.55a(g)(6)(ii)(D). In particular, the inspectors confirmed for a sample of the head penetration locations that:

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

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

• if indications or defects were identified, the licensee documented the conditions in examination reports and/or entered this condition into the CAP and implemented appropriate corrective actions; and

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

Based upon the licensees examination, no new relevant indications were accepted for continued service and no new welded repairs were required for the Unit 1 vessel head penetrations. Therefore, no NRC review was completed for these inspection procedure attributes.

b. Findings

No findings were identified.

.3 Boric Acid Corrosion Control

a. Inspection Scope

The inspectors independently walked down the Unit 1 reactor coolant system loop piping, including the reactor coolant pumps, pressurizer, and emergency core cooling systems within containment to identify boric acid leakage. The inspectors then reviewed the walkdown performed by the licensee to ensure that components with boric acid deposits were identified and entered into the CAP. The inspectors observed these examinations to determine whether the licensee focused on locations where boric acid leaks could cause degradation of safety significant components.

The inspectors reviewed the following licensee evaluations of components with boric acid deposits to determine if the affected components were documented and properly evaluated in the CAP. Specifically, the inspectors evaluated the licensees corrective actions to determine if degraded components met the component Construction Code and/or the ASME Section XI Code:

• Leak Record - Pressurizer Valve 1PS9354B Inactive Packing and Body to Bonnet Leak; and

• Leak Record - Reactor Coolant System Loop 1B Differential Pressure Cell Transmitter Leak at Process Inlets to Flow Transmitter 1FT-0424.

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

• IR 01520547, Large Boric Acid Buildup on 1CV220, and

• IR 01418262, Pipe Cap Near 1SI8833A Leaking 12 DPM (Drops Per Minute).

b. Findings

No findings were identified.

.4 Steam Generator Tube Inspection Activities

a. Inspection Scope

For the Unit 1 SGs, no examination was required pursuant to the TSs during the current refueling outage. Therefore, no NRC review was completed for this inspection procedure attribute.

b. Findings

No findings were identified.

.5 Identification and Resolution of Problems

a. Inspection Scope

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

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

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

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

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

b. Findings

No findings were identified.

1R11 Licensed Operator Requalification Program

.1 Resident Inspector Quarterly Review of Licensed Operator Requalification

a. Inspection Scope

On January 31, 2014, the inspectors observed a crew of licensed operators in the plants simulator during licensed operator requalification training to verify that operator performance was adequate, evaluators were identifying and documenting crew performance problems, and training was being conducted in accordance with licensee procedures. The inspectors evaluated the following areas:

• licensed operator performance;

• crews clarity and formality of communications;

• the ability to take timely actions in the conservative direction;

• prioritization, interpretation, and verification of annunciator alarms;

• correct use and implementation of abnormal and emergency procedures;

• control board manipulations;

• oversight and direction from supervisors; and

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

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

This inspection constituted one quarterly licensed operator requalification training sample as defined in IP 71111.11.

b. Findings

No findings were identified.

.2 Resident Inspector Quarterly Observation of Heightened Activity or Risk

a. Inspection Scope

On January 15, 2014, the inspectors observed operators in the Unit 2 control room recover two misaligned control rods and raise reactor power from 50 percent to 100 percent. This was an activity that required heightened awareness or was related to increased risk. The inspectors evaluated the following areas:

• licensed operator performance;

• crews clarity and formality of communications;

• the ability to take timely actions in the conservative direction;

• prioritization, interpretation, and verification of annunciator alarms;

• correct use and implementation of procedures;

• control board (or equipment) manipulations;

• oversight and direction from supervisors; and

• the ability to identify and implement appropriate TS actions.

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

Documents reviewed are listed in the Attachment.

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

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:

• Unit 1 Bus 111 Inverter Failure;

• Units 1 and 2 Generator Stator Cooling Systems; and

• Units 1 and 2 Essential Service Water Systems.

The inspectors reviewed events including those in which 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 SSCs/functions classified as (a)(2),or appropriate and adequate goals and corrective actions for systems classified as (a)(1).

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

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

b. Findings

No findings were identified.

1R13 Maintenance Risk Assessments and Emergent Work Control

.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 2 On-Line Risk (OLR) changes from Yellow to Orange due to grid conditions on January 12 and 13, 2014;

• Schedule changes due to implementation of the Measurement Uncertainty Recapture license amendment during Work Week February 10, 2014;

• Unit 2 OLR impact due to 0D auxiliary building supply fan work on February 14, 2014;

• Schedule changes due to snow/weather and revisions to the risk profile due to using a dedicated operator to maintain auxiliary feedwater (AF) availability;

• Risk assessment to both units for SX146 work impacting U0 component cooling heat exchangers during Work Week February 24, 2014; and

• Unit 1 outage schedule and shutdown risk profile including contingency plans, and Unit 1 electrical equipment outage impact on Unit 2 OLR.

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 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 are listed in the Attachment.

These maintenance risk assessments and emergent work control activities constituted six 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:

• Operating Evaluation 14-001, Unit 1 Train A Residual Heat Removal Pump Operability With Degraded Cubical Cooler;

• IR 1624246, MSIV [Main Steam Isolation Valve] Bypass Actuation Does Not Comply with IEEE STD 279-1971;

• EC 396998, 30 Day 10 CFR 50.46 Report for B&B Unit 1 ASTRUM LBLOCA

[Large Break Loss of Coolant Accident] Model Concerning Methodology Changes and Errors;

• Component Cooling System Makeup Requirements; and

• EC 393745, Revision 003; Operability Evaluation 13-004 - NSR

[Nonsafety-Related] Gaskets in AOVs [Air-Operated Valves].

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

.

This operability inspection constituted five 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 modifications:

• EC 386524, Design Change to Auxiliary Feedwater (AF) Suction Pressure Logic for Unit 1, and

• EC 383886, Modify Void and Vent Piping Upstream of 1A AF Pump, SX Suction Side.

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 systems. The inspectors, as applicable, observed ongoing and completed work activities to ensure that the modifications were installed as directed and were 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.

This inspection 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 testing activities to verify that procedures and test activities were adequate to ensure system operability and functional capability:

• WO 1317228: Unit 2 Train A Diesel Generator Relay Replacement;

• WO 1681636: Unit 2 Movable Control Assemblies Surveillance;

• WO 1678931: Unit Common Train A Fire Pump; and

• WO 1240444: Instrument Maintenance (IM) Contingency Unit 1 Rod Drive Troubleshooting.

These activities were selected based upon the SSCs 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 into the CAP at the appropriate threshold, and correcting the problems commensurate with their importance to safety. Documents reviewed are listed in the Attachment.

This inspection constituted four 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 1 refueling outage (RFO), conducted March 10-28, 2014, 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 TSs;

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

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

• startup and ascension to full power operation, tracking of startup prerequisites, walkdown of the 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.

This inspection 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 1 1MS013B IST TREVI Test (IST);

• Surveillance of the Upper Cable Spreading Room Halon Fire Protection System (Routine);

• Unit 1 Train A Diesel Generator Operability Surveillance (IST);

• Unit 2 Train A Containment Spray Additive Flow Rate Verification (Routine);

• Unit 2 Reactor Coolant Water Inventory Balance Surveillance (Leak Detection);and

• Unit 1 Primary Containment Type C Local Leakage Rate Tests and IST Tests of Service Air System (Isolation Valve).

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

• did preconditioning occur;

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

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

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

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

• was measuring and test equipment calibration current;

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

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

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

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

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

• was test equipment removed following testing;

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

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

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

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

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

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

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

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

Documents reviewed are listed in the Attachment.

This inspection constituted two routine surveillance testing samples, two inservice testing samples, one reactor coolant system leak detection inspection sample, and one containment isolation valve sample as defined in IP 71111.22, Sections -02 and -05.

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 February 27, 2014, 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 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 in order to evaluate the critique and to verify whether the licensee staff was properly identifying weaknesses and entering them into the CAP. As part of the inspection, the inspectors reviewed the drill package and other documents listed in the Attachment.

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

b. Findings

No findings were identified.

RADIATION SAFETY

Cornerstones: Public Radiation Safety and Occupational Radiation Safety

2RS1 Radiological Hazard Assessment and Exposure Controls

This inspection constituted a partial sample as defined in IP 71124.01-05.

.1 Radiological Hazard Assessment (02.02)

a. Inspection Scope

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

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

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

• B1R19 Reactor Head: Disassemble/Reassemble - All Activities;

• B1R19 Reactor Nozzle Covers: All Activities; and

• B1R19 Reactor Head and Upper Internals Move and Reactor Flange Inspection.

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

• identification of hot particles;

• the presence of alpha emitters;

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

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

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

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

b. Findings

No findings were identified.

.2 Instructions to Workers (02.03)

a. Inspection Scope

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

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

• Radiation Work Permit 10015280, (B1R19) Reactor Head:

Disassemble/Reassemble - All Activities;

• Radiation Work Permit 10015281, (B1R19) Reactor Nozzle Covers: All Activities; and

• Radiation Work Permit 10015284, (B1R19) Reactor Head and Upper Internals Move and Reactor Flange Inspection.

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

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

b. Findings

No findings were identified.

.3 Contamination and Radioactive Material Control (02.04)

a. Inspection Scope

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

b. Findings

No findings were identified.

.4 Radiological Hazards Control and Work Coverage (02.05)

a. Inspection Scope

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

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

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

• Radiation Work Permit 10015280, (B1R19) Reactor Head:

Disassemble/Reassemble - All Activities;

• Radiation Work Permit 10015281, (B1R19) Reactor Nozzle Covers: All Activities; and

• Radiation Work Permit 10015284, (B1R19) Reactor Head and Upper Internals Move and Reactor Flange Inspection.

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

b. Findings

No findings were identified.

.5 Radiation Worker Performance (02.07)

a. Inspection Scope

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

b. Findings

No findings were identified.

.6 Radiation Protection Technician Proficiency (02.08)

a. Inspection Scope

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

b. Findings

No findings were identified.

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

This inspection constituted a partial sample as defined in IP 71124.02-05.

.1 Inspection Planning (02.01)

a. Inspection Scope

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

b. Findings

No findings were identified.

.2 Radiation Worker Performance (02.05)

a. Inspection Scope

The inspectors observed radiation worker and radiation protection technician performance during work activities being performed in radiation areas, airborne radioactivity areas, or high radiation areas. The inspectors evaluated whether workers demonstrated the as-low-as-reasonably-achievable (ALARA) philosophy in practice (e.g., workers were familiar with the work activity scope and tools to be used, workers used ALARA low-dose waiting areas) and whether there were any procedure compliance issues (e.g., workers were not complying with work activity controls). The inspectors observed radiation worker performance to assess whether the training and skill level was sufficient with respect to the radiological hazards and the work involved.

b. Findings

No findings were identified.

OTHER ACTIVITIES

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

4OA1 Performance Indicator Verification

.1 Unplanned Scrams Per 7000 Critical Hours

a. Inspection Scope

The inspectors sampled licensee submittals for the Unplanned Scrams Per 7000 Critical Hours performance indicator (PI) for Unit 1 and Unit 2 for the period from the first quarter of 2013 through the fourth quarter of 2013. To determine the accuracy of the PI data reported during those periods, PI guidance contained in Nuclear Energy Institute (NEI)99-02, Regulatory Assessment Performance Indicator Guideline, Revision 6, dated October 2009, was used. The inspectors reviewed the licensees operator narrative logs, IRs, event reports, and NRC integrated inspection reports for the period of January 2013 through December 2013 to validate the accuracy of the submittals. The inspectors also reviewed the licensees IR database to determine if any problems had been identified with the PI data collected or transmitted for this indicator. Documents reviewed are listed in the Attachment.

This inspection constituted two unplanned scrams per 7000 critical hours samples as defined in IP 71151-05.

b. Findings

No findings were identified.

.2 Unplanned Scrams with Complications

a. Inspection Scope

The inspectors sampled licensee submittals for the Unplanned Scrams with Complications PI for Unit 1 and Unit 2 for the period from the first quarter of 2013 through the fourth quarter of 2013. To determine the accuracy of the PI data reported during those periods, PI guidance contained in NEI 99-02, Regulatory Assessment Performance Indicator Guideline, Revision 6, dated October 2009, was used. The inspectors reviewed the licensees operator narrative logs, IRs, event reports, and NRC integrated inspection reports for the period of January 2013 through December 2013 to validate the accuracy of the submittals. The inspectors also reviewed the licensees IR database to determine if any problems had been identified with the PI data collected or transmitted for this indicator. Documents reviewed are listed in the Attachment.

This inspection constituted two unplanned scrams with complications samples as defined in IP 71151-05.

b. Findings

No findings were identified.

.3 Unplanned Transients Per 7000 Critical Hours

a. Inspection Scope

The inspectors sampled licensee submittals for the Unplanned Transients Per 7000 Critical Hours PI for Unit 1 and Unit 2 for the period from the first quarter of 2013 through the fourth quarter of 2013. To determine the accuracy of the PI data reported during those periods, PI guidance contained in NEI 99-02, Regulatory Assessment Performance Indicator Guideline, Revision 6, dated October 2009, was used. The inspectors reviewed the licensees operator narrative logs, IRs, maintenance rule records, event reports and NRC integrated inspection reports for the period of January 2013 through December 2013 to validate the accuracy of the submittals. The inspectors also reviewed the licensees IR database to determine if any problems had been identified with the PI data collected or transmitted for this indicator. Documents reviewed are listed in the Attachment.

This inspection constituted two unplanned transients per 7000 critical hours samples as defined in IP 71151-05.

b. Findings

No findings were identified.

4OA2 Identification and Resolution of Problems

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

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

a. Inspection Scope

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

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

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

b. Findings

No findings were identified.

.2 Daily Corrective Action Program Reviews

a. Inspection Scope

In order to assist with the identification of repetitive equipment failures and specific human performance issues for follow-up, the inspectors performed a daily screening of items entered into the licensees CAP. This review was accomplished through inspection of the stations daily IR packages.

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

b. Findings

No findings were identified.

.3 Selected Issue Follow-Up Inspection: Diesel Generator Fuel Pump Replacement

a. Inspection Scope

During a review of items entered in the licensees CAP, the inspectors recognized a corrective action item documenting that a new fuel oil pump being installed on the 2B diesel generator as part of a preventative maintenance activity was not similar to the fuel oil pump being removed. This discrepancy was identified by maintenance staff during a procedurally required assessment of the new fuel oil pump. The licensee entered the issue into the CAP as IR 1604977, 2A Diesel Generator Engine Driven Fuel Oil Pump Not Like-For-Like, reinstalled the original fuel oil pump, and performed an evaluation for the remaining diesel generators. The extent of condition review identified that the fuel oil pumps currently installed on the remaining diesels (Unit 1 Trains A and B; Unit 2 Train B) were like the new fuel oil pump. These pumps had been replaced previously as part of routine preventative maintenance activities. Post-identification reviews determined that the new fuel oil pumps with the alternate configuration would perform similarly to the original pumps and therefore would not adversely impact diesel generator operability. See additional information regarding this issue in Section 4OA7.

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

b. Findings

No findings were identified.

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

.1 Unit 2 Control Rods Dropped During Surveillance

a. Inspection Scope

On January 14, 2014, two control rods became misaligned during surveillance testing.

One rod dropped to the full in position and a second rod dropped to an intermediate position. No blown fuses or other Urgent Failure indications were apparent. Technical Specification 3.1.4, Rod Group Alignment Limits, was entered leaving the unit in a 72 hour8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> LCO after shutdown margin was verified to be within the limits of the core operating limits report. Operators implemented abnormal operating procedure 2BOA ROD-3, Dropped or Misaligned Rod, and reduced power to approximately 40 percent of rated power. The licensee entered the issue into their CAP as IR 1607715 and engaged Westinghouse in the troubleshooting activities. While troubleshooting and subsequent testing of the circuit card did not pinpoint a specific cause, cards within the circuit were replaced and electrical connectivity was verified through post-maintenance testing activities. The rods were tested and subsequently realigned. The unit returned to full licensed thermal power on January 17, 2014. In addition to card replacements and connectivity verifications performed, the licensee replaced several cards of similar age during the refueling outage in March.

Documents reviewed are listed in the Attachment.

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

b. Findings

No findings were identified.

.2 Unit 1 Loss of Offsite Power During Refueling Outage

a. Inspection Scope

The inspectors reviewed the plants response to a loss of offsite power to Unit 1 (i.e. Lockout of System Auxiliary Transformers (SATs) 142-1 and 142-2) while in Mode 6. The event was reported as Event Notification (EN) 499919. At 11:02 a.m. on Saturday, March 15, 2014, the lockout signal opened switchyard oil circuit breaker (OCB) 5-6 and OCB 6-7, de-energizing the SATs. Both emergency diesel generators (EDGs) started in the emergency mode and closed onto their respective ESF buses. All safe shutdown loads started as expected when signaled by the EDG sequencers. The only anomaly identified in the plant response was the failure of the 0A control room ventilation chiller to start when required by the EDG sequencer. No fuel movements were in progress at the time and no loads were suspended at the time of the power loss.

In addition, the containment radiation monitor generated a containment isolation signal on loss of power and ventilation/purge components isolated as expected. Operators entered abnormal operating procedures for loss of offsite power and loss of shutdown cooling. The 1A residual heat removal pump was restarted within 3 minutes of the loss of power to restore shutdown cooling with no change in reactor coolant system (RCS)temperature.

Organization, Analysis, and Design (OAD) technicians were replacing relays on nonsafety-related 6.9 Kilovolt (kV) Bus 158 when the trip occurred. Appropriate troubleshooting was conducted to ensure no actual fault condition existed before operators reenergized the SATs, transferred busses back to the normal power alignment, and shut down the EDGs. The licensee entered the issue into the CAP as IR1633834 and the cause evaluation was still in progress at the end of the inspection period.

Documents reviewed are listed in the Attachment.

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

b. Findings

No findings were identified.

.3 (Closed) Licensee Event Report (LER) 05000455/2013-002-00: Unqualified Valve

Diaphragm Installed in 2RE9160A in B2R16 On September 18, 2013, the licensee identified that the wrong part number was identified in the instructions included in WO 01324133-01, Rebuild Actuator, Regulators/Replace Elastomers, and in September of 2011 an unqualified valve diaphragm had been installed in the actuator for AOV 2RE9160A, Reactor Coolant Drain Tank to Waste Gas Compressor Inside Containment Isolation Valve. When the issue was identified, the licensee immediately declared the valve inoperable and took the action required by TS 3.6.3, Primary Containment Isolation Valves, Condition A to isolate the penetration by closing 2RE9160B, Reactor Coolant Drain Tank to Waste Gas Compressor Outside Containment Isolation Valve. The licensee entered the issue into the CAP as IR 1560606, Unqualified Valve Diaphragm Installed in 2RE9160A in B2R16, and replaced the diaphragm with a qualified part. The valve was tested and declared operable on October 11, 2013. Additionally, the model WO was corrected and work planners were tested to ensure the appropriate parts verifications could be performed.

Documents reviewed are listed in the Attachment. Section 4OA7 contains additional information on the resolution of this issue. This LER is closed.

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

.4 (Closed) LER 05000455/2012-001-00: Manual Reactor Trip During Power Ascension

Due to Steam Generator Level Approaching Turbine Trip Setpoint Caused by an Overly Complex Startup Procedure Byron Unit 2 was in the process of starting up on February 6, 2012, in accordance with 2BGP 100-3, Power Ascension, and the Unit was at 25 percent power when the operators attempted to perform the procedure steps to switch feedwater flow from the upper nozzles of the SGs to the lower nozzles through the 2FW009 valves. To support opening a 2FW009 valve, the common practice at Byron was to place the feedwater regulating valve (FRV) in manual controlled by a dedicated operator (SG operator). The 2FW009C valve was selected to be the first valve opened since it had a history of being thermally bound and hard to open. A heating blanket had been installed on the valve in accordance with past practices to improve the likelihood that the valve would open.

When 2FW009C was opened by the reactor operator, water level in 2C SG began to rise as expected. Due to concerns that the valve may not operate as expected, both the unit supervisor and the unit operator were focused on watching the valve stroke. The SG operator manipulating the feedwater controls further opened the FRV in an attempt to control upper nozzle subcooling and ensure water hammer interlocks were satisfied, and neglected the impact of the increased feedwater flow on steam generator level. When a third operator recognized the rapidly rising steam generator level and notified the crew, the SG operator throttled back on the FRV in an attempt to lower feedwater flow and control steam generator level. When SG levels continued to rise, the unit supervisor directed a manual reactor trip which was executed by the operators. The 2C SG level reached the High-High level setpoint (P-14), resulting in a feedwater isolation, main turbine trip, and main feedwater pump trip. The licensee entered the event into their CAP as IR 1323547, B2F27 U-2 Manual Rx [Reactor] Trip and Manual AF [Auxiliary Feedwater] Actuation, and added additional corrective actions in IR 1437830, Additional Actions for RCR [Root Cause Report] 1323547.

The licensee determined that the root cause of the event was that the complex procedural evolution of opening the FRV was minimized in the instructional steps and exacerbated by requiring the control to be in manual. Less than adequate crew and individual operator performance, a distraction created by the degraded 2FW009C valve, and the lack of simulator modeling for the Unit 2 FRV control logic contributed to the event. Immediate corrective actions involved revising 2BGP 100-3, reviewing other procedures for similar vulnerabilities, providing operator training, and reinforcing performance expectations for all operators. The subsequent unit startup was performed using the revised procedure. Training tools were implemented to ensure operators maintained the required operating skills for Unit 2 feedwater manipulation. The 2FW009C valve was repaired in the spring of 2013 during the following Unit 2 refueling outage.

An organizational root cause was also identified in that the operators risk perception of the feedwater manipulation was not commensurate with the complexity of the task at hand. As a result, the crew did not apply the appropriate rigor required to support the operational risk evolution. OP-AA-102-103-1001, Operator Burden and Plant Significant Decisions Impact Assessment Program, was revised to prevent minimized risk perception leading to erosion over time of overall sensitivity of equipment related issues which may be challenging operators. The inspectors reviewed the current operator burden aggregate impact assessment and determined that the new procedure was being implemented as designed.

Documents reviewed are listed in the Attachment. This LER is closed.

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

.5 (Closed) LER 05000454/2012-004-00: Reactor Pressure Vessel Head Control Rod

Drive Mechanism (CRDM) Penetration Nozzle Weld Repair On September 14, 2012, the licensee identified multiple rounded indications on weld overlay repairs to vessel head penetration nozzles 31 and 43. One of those indications on each nozzle did not meet the acceptance criteria to remain in service without repair and was reported in EN 48311 as a condition that resulted in a principal safety barrier being seriously degraded. The licensee entered the issue into the CAP as IR 1413371, PT Indication in CRDM PEN [Penetration] 31 and 43. The licensee was performing volumetric and surface inspections as a follow-up to a code repair performed in the spring of 2011 on these and other nozzles. Region III inspectors reviewed the records for that repair in 2011 and observed the post-repair volumetric and surface inspections.

Those inspection samples were documented in Section 1R08 of Byron Station, Units 1 and 2, NRC Inspection Report 05000454/2011003; 05000455/2011003.

The licensee determined that the indications found in 2012 were weld overlay mechanical discontinuities that opened up due to thermal and pressure stresses during the operating cycle. The indications were reduced to acceptable size by mechanical means using WO 1478855, Perform U-1 Head Repair As Required - B1R18, and no additional welding was performed. Region III inspectors reviewed the records for the repair and observed the post-repair volumetric and surface inspections. Those inspections were documented in Section 1R08 of Byron Station, Units 1 and 2, NRC Inspection Report 05000454/2012004; 05000455/2012004.

Follow-up inspections were performed by the NRC during the 2014 Unit 1 refueling outage with no change in the indication and no unacceptable indications identified.

Documents reviewed are listed in the Attachment. This LER is closed.

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

.6 (Closed) LER 05000454/2013-001-00: Unit 1 Failed Surveillance Test of A Train

Control Room Emergency Filtration System On September 17, 2013, with Byron Station Unit 1 in Mode 1 at 100 percent power, a charcoal sample was drawn from the A Train of the control room emergency filtration system and sent offsite for analysis. On September 26, 2013, the station was notified that the sample results did not meet the surveillance test acceptance criteria, and the station determined that the A Train had been inoperable since 11:40 a.m. on September 17, 2013, when the surveillance began. Technical Specification 3.7.10, Control Room Ventilation (VC) Filtration System, was declared not met at 6:45 a.m. on September 26, 2013, and actions to replace the charcoal were initiated. The degraded charcoal was replaced and tested satisfactorily on September 27, 2013. The station determined that the event was reportable since the filtration train had been inoperable for longer than the 7 days allowed by the TS.

The cause of the event was that applicable charcoal banks had reached the end of life.

Unexpected delays in the processing of the sample allowed the expired charcoal to exceed the TS allowed out-of-service time frame. The licensee replaced the charcoal and revised sample processing to keep the organization cognizant of the sample status using operations department tracking tools. In addition, the site implemented an expedited sampling process to provide time to react to a failed sample within the TS allowed out-of-service time.

Documents reviewed are listed in the Attachment. This LER is closed.

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

.7 (Opened/Closed) LER 05000454/2014-001-00: 0A Essential Service Water (SX)

Makeup Pump Unexpected Auto-Start During 0B SX Pump Monthly Surveillance On January 23, 2014, Byron Units 1 and 2 were operating at full power when the Operations department started 0BOSR 7.9.6-2, Essential Service Water Makeup Pump 0B Monthly Operability Surveillance. One option for the surveillance had the operators manually lower basin level until the pump automatically started. In preparation for the automatic start of the 0B Makeup Pump, operators lowered both the 0B and 0A SX tower basin levels, as they are cross-tied. Basin level was being lowered in the automatic mode by reducing the signal on the Manual/Auto station which prevented the automatic makeup valve from opening during the surveillance. The demand signal was set to 71 percent which should have been above the automatic start setpoint (i.e. 62 percent) for the pumps. As the controller was responding to the signal, the valve overshoot allowed level to reach 68 percent indicated. High winds and wave action in the tower basin, combined with the lowered level, started the 0A SX Makeup pump.

Because the start was not part of the pre-planned sequence and the essential service water system was included in the systems listed under 10 CFR 50.73(a)(2)(iv)(B), the event was reportable.

The cause of the pump start was that the operating procedure directed the controller to be set at a level that left little margin to the SX makeup pump automatic start level switch setpoint when adverse environmental conditions such as high winds and wave action existed. Because the indicated level and the automatic start level switches were different instruments, the station verified through alternate testing that the level switch setpoints were correct, the level indication was correctly calibrated, and that the start signal was valid. Additional corrective actions included revising the operating procedures for SX basin level changes to include a more conservative target setpoint and clarify the procedure with additional notes and cautions regarding potential pump starts.

Documents reviewed are listed in the Attachment. This LER is closed.

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

4OA5 Other Activities

.1 Conversion of 2013 Cross-Cutting Aspects

The table below provides a cross-reference from the third and fourth quarter 2013 findings and associated cross-cutting aspects to the new cross-cutting aspects resulting from the common language initiative. These aspects and any others identified since January 2014 will be evaluated for cross-cutting themes and potential substantive cross-cutting issues in accordance with IMC 0305 starting with the 2014 mid-cycle assessment review.

Finding Old Cross-Cutting Aspect New Cross-Cutting Aspect 05000454/2013007-01; P.1(a) P.1 05000455/2013007-01 05000454/2013007-02; H.4(a) H.11 05000455/2013007-02 05000455/2013005-04 H.1(b) H.14 05000455/2013005-06 P.1(d) P.3 05000455/2013005-07 H.2(c) H.7

.2 Operation of an Independent Spent Fuel Storage Installation (ISFSI) at Operating Plants

(60855.1)

a. Inspection Scope

On August 28-29, 2010, a Holtec HI-STORM 100 spent fuel storage system multipurpose canister (MPC) containing fuel assemblies and located within a transfer cask was left unattended at Byron Station for the evening following vacuum drying activities. A cooling system, which circulated water in the annulus between the canister and transfer cask to keep cladding temperatures below allowable limits, was found to be inoperable the next morning.

On September 17, 2010, the NRC completed a reactive inspection at the Byron Station, and issued NRC Inspection Reports 05000454/2010007, 05000455/2010007, and 07200068/2010002 (Agencywide Documents Access and Management System (ADAMS) Accession No. ML103140226). The inspectors identified three unresolved items (URIs) during the inspection.

On October 18, 2010, NRC Region III transmitted a Technical Assistance Request (TAR)to the Division of Spent Fuel Storage and Transportation (SFST) of the Office of Nuclear Material Safety and Safeguards (NMSS), concerning the three URIs and several potential generic issues that were identified during the Byron Station reactive inspection which was completed on September 17, 2010.

SFST has completed its review of the three unresolved items. The NRC issued Information Notice (IN) 2011-10 (ADAMS Accession No. ML111090200) to inform all stakeholders of the Byron issues. The IN stated the NRC expected that recipients would review the information for applicability to their facilities and take actions, as appropriate, to avoid similar problems. The NRC may issue further communications as necessary associated with the use of the vacuum drying system.

Since the initial loading campaign at the Byron Station, the licensee has transitioned from utilizing a vacuum drying system and annulus cooling system to utilizing a forced helium dehydration system and supplemental cooling system.

(1) (Closed) URI 05000454/2010007-03; 05000455/2010007-03: Licensee ISFSI Annulus Cooling System Important to Safety Classification Previously, the inspectors identified an URI associated with the licensees classification of ISFSI components and systems as either important to safety (ITS) or not important to safety (NITS). Specifically, the inspectors questioned whether the licensees annulus cooling water system was ITS.

The system used by the licensee for HI-TRAC annulus cooling consisted of a heat exchanger, submersible pump, temperature monitoring device, and chiller. The system was not classified as either ITS or NITS in the Holtec HI-STORM 100 Final Safety Analysis Report (FSAR), Revision 5. The licensee purchased the chiller as commercial grade equipment and since the system was not identified within the Holtec FSAR, characterized the system as NITS.

The licensee initiated IR 1116408, NRC Potential URIs from ISFSI Reactive Inspection, to determine whether the system needed to be re-designated as ITS. Subsequent to the completion of the inspection, the licensee utilized input from Holtec to make the ITS or NITS classification. Holtec Standard Procedure 345 was used to implement a graded classification approach, consistent with NUREG/CR-6407. Using the evaluation matrix in Holtec Standard Procedure 345 the licensee classified the cooling system as NITS.

In Holtecs response to the licensee regarding its recommendation to classify the annulus cooling system as NITS, Holtec recommended the following:

To preclude the possibility of peak cladding temperature exceeding 1058°F, administrative measures should be taken by the licensee to monitor the operation of the system and mitigate the likelihood of the annulus water temperature rising above 125°F by taking additional actions such as:

(a) regular monitoring of the device operability;

(b) regular monitoring of the annulus bulk water temperature; and (c)procedurally establishing compensatory measures in order to mitigate the possibility of an adverse temperature condition.

The inspectors coordinated with SFST through a Technical Assistance Request. The staff determined that it may be adequate to classify the annulus cooling system as NITS when it is used as part of the vacuum drying system for the purpose of maintaining sufficient cooling of fuel, and if there is appropriate operator attendance to address potential system failures.

The staff determined that with properly trained operators in attendance, an annulus cooling system failure could be addressed by operator actions, such as returning the assemblies to the spent fuel pool or backfilling the canister with helium.

The inspectors determined that although the licensee appropriately classified the system as NITS, they failed to have adequate procedures to ensure appropriate actions during cooling system failures. The inspectors previously identified a Severity Level IV NCV of 10 CFR 72.150, "Instructions, Procedures, and Drawings," associated with inadequate procedures in NRC Inspection Reports 05000454/2010007, 05000454/2010007, and 07200068/2010002. Specifically, the licensee failed to have procedures in place to ensure that the design basis peak fuel cladding temperature limit would not be exceeded during vacuum drying operations. The licensee entered this issue into their CAP and revised the procedure to provide monitoring criteria. Since enforcement action has already been taken on this issue and the licensee implemented appropriate corrective actions in response to that violation, no further enforcement action is warranted. This review closes the unresolved item. (URI 05000454/2010007-03; 05000455/2010007-03; 07200068/2010002-03, Licensee ISFI Annulus System Important to Safety Classification).

(2) (Closed) URI 05000454/2010007-02; 05000455/2010007-02: Non-Inert Atmosphere May Challenge Fuel Integrity Previously, inspectors identified a URI associated with the licensees adherence to Holtec Certificate of Compliance (CoC) 1014, Amendment 3, Appendix B, Section 3.4.10, during vacuum drying operations. Specifically, Appendix B Section 3.4.10 states that users shall establish procedural and/or mechanical barriers to ensure that during loading operations and unloading operations, either the fuel cladding is covered by water, or the MPC is filled with an inert gas.

The inspectors observed that while under vacuum, a potential hose rupture would allow air to flow back into the MPC. The vacuum drying system is categorized as NITS in the HI-STORM 100 FSAR Revision 5, and the licensee used commercial grade equipment hosing and valves, to complete the vacuum drying process. The licensee had no compensatory measures in place to promptly isolate and/or backfill the canister. The licensee documented this issue into their CAP as IR1116408, NRC Potential URIs from ISFSI Reactive Inspection. The inspectors determined that a hose failure is neither a design basis accident, nor an abnormal event.

SFST ISG-22 discusses that cladding and fuel damage may occur if:

(a) the fuel has pinhole leaks or hairline cracks; and

(b) air is introduced into a dry fuel canister while fuel is at an elevated temperature. The Holtec FSAR indicates that during vacuum drying operations, fuel cladding temperatures are designed to be less than 1058oF, but could be as high as 1040oF. This temperature is outside the range considered in NUREG-1536, Standard Review Plan for Spent Fuel Dry Storage Systems at a General License Facility, indicating fuel oxidation and the potential for cladding failure in a short period of time if fuel assemblies were exposed to an unlimited supply of air, as would be the case in the event of an unattended hose breach.

The licensee determined that the fuel selected for the initial loading campaign was intact fuel with no pinhole leaks or hairline cracks. This determination was made from a review of fuel sipping and chemistry records. Since no fuel failures including pinhole leaks and hairline cracks existed, fuel oxidation as described in ISG-22 should not occur even if oxygen was present within the canister. To ensure defense-in-depth, the licensee added additional contingency procedures to appropriately recognize a hose failure and backfill the canister with an inert gas if a hose failure occurred.

Since at the time of fuel loading a vacuum hose break was not a design basis event, and the licensee only loaded intact fuel without pinhole leaks or hairline cracks, the inspectors determined that no violation was warranted. This review closes the unresolved item. (URI 05000454/2010007-02; 05000455/2010007-02; 07200068/2010002-02, Non-Inert Atmosphere May Challenge Fuel Integrity.)

(3) (Closed) URI 05000454/2010007-04; 05000455/2010007-04: Thermal Models in FSAR Design Basis Analysis May Not be Conservative Previously, the inspectors identified an URI associated with design basis peak cladding temperature thermal analyses as described in the Holtec HI-STORM 100 FSAR Revision 5 and the corresponding use of the Holtec CoC 1014, Amendment 3 at Byron Station.

During the reactive inspection, an NRC technical reviewer assessed the CoC 1014, Amendment 3 design basis calculation for adequacy. When comparing the results of the reviewers model utilized in later amendments to the results of the design basis calculation, a discrepancy was noted. The design basis calculation stated that during steady state vacuum drying of an MPC-32 canister with a heat load of 28.74 kilowatts and a shell temperature postulated at 125oF, fuel cladding temperatures would not exceed 1040oF. The NRC reviewers model calculated fuel cladding temperatures in excess of 1058oF. NRC SFST Interim Staff Guidance document 11 discussed that cladding temperature limits should not exceed 1058oF during short term operations.

As documented in the Safety Evaluation Report for CoC 1014, Amendment 5, the design basis fuel cladding temperatures for CoC 1014, Amendment 3 were not supported by NRCs current thermal models for any of the MPCs. Amendment 5 thermal evaluation of vacuum drying was based on 3-D thermal models, while CoC 1014 Amendments 1-4 were based on 2-D axisymmetric models which, based on the staffs review, include non-conservative assumptions. Based on confirmatory analyses, the staff found that the two approaches (2-D vs. 3-D) compared well at low decay heat loads, but deviated at design basis heat loads.

The NRC conducted an inspection at the Holtec International offices in October 2010, and subsequently issued an Inspection Report and NOV on February 24, 2011 (ADAMS Accession No. ML110450157). The NOV required Holtec to provide a response to address these issues. Holtec provided its response to the NOV on March 24, 2011 (ADAMS Accession No. ML110870968). The response identified the root cause, corrective actions, and actions to prevent recurrence. On March 21, 2011, Holtec issued Holtec Information Bulletin HIB-48 to the Holtec Users Group (HUG) to advise them of modified heat load and time limits during vacuum drying. The staff is evaluating options for enhancing currently approved amendments either through corrections to the CoC and/or voluntary enhancements by Holtec to applicable FSAR revisions, through the 72.48 change process.

The licensee implemented corrective actions as necessary as the CoC holder implemented additional guidance. The inspectors determined that no additional enforcement action is warranted for the licensee. This review closes the unresolved item. (URI 05000454/2010007-04; 05000455/2010007-04; 07200068/2010002-04, Thermal Models in FSAR Design Basis Analysis May Not Be Conservative.)

b. Findings

No findings were identified.

4OA6 Management Meetings

.1 Exit Meeting Summary

On April 3, 2014, the inspectors presented the inspection results to Mr. B. Youman, and other members of the licensee staff. The licensee acknowledged the issues presented.

The inspectors confirmed that none of the potential report input discussed was considered proprietary.

.2 Interim Exit Meetings

Interim exits were conducted for:

• The results of the inservice inspection were presented to Mr. F. Kearney, Site Vice President, and other members of his staff on March 20, 2014.

• The results of the ISFSI inspection were presented to Mr. F. Kearney, Site Vice President, and other members of his staff on March 14, 2014.

• The inspection results for radiological hazard assessment and exposure controls and occupational as-low-as-reasonably-achievable planning and controls were presented to Mr. B. Barton, Radiation Protection Manager, and other members of the licensee staff on March 14, 2014.

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

4OA7 Licensee-Identified Violations

The following violations of very low safety significance (Green) or Severity Level IV were identified by the licensee and are violations of NRC requirements which meet the criteria of the NRC Enforcement Policy for being dispositioned as Non-Cited Violations.

• Title 10 CFR 50, Appendix B, Criterion V, Instruction, Procedure, and Drawings, requires, in part, that activities affecting quality shall be prescribed by documented instructions appropriate to the circumstances. Contrary to that requirement, the work instructions were not appropriate for the circumstances for a WO executed during the September 2011 refueling outage for a containment isolation valve in that the parts list identified the wrong part number for an actuator diaphragm. On September 18, 2013, the licensee identified that the wrong part number was identified in the instructions included in WO 01324133-01, Rebuild Actuator, Regulators/Replace Elastomers, and an unqualified valve diaphragm was installed in the actuator for AOV 2RE9160A, Reactor Coolant Drain Tank to Waste Gas Compressor Inside Containment Isolation Valve. The licensee entered the issue into their CAP as IR 1560606, Unqualified Valve Diaphragm Installed in 2RE9160A in B2R16, and replaced the diaphragm with a qualified part. The valve was tested and declared operable on October 11, 2013.

The work planner selected the wrong diaphragm from the model WO while preparing the work instructions for WO 01324133 and failed to ensure the part selected was qualified for the containment environment. The inspectors determined that the performance deficiency was more than minor because it was associated with the Containment Isolation attribute of the Barrier Integrity cornerstone and adversely impacted the cornerstone objective of providing reasonable assurance that the design barrier of the containment be maintained to protect the public from radionuclide releases caused by accidents or events.

The inspectors screened the issue using IMC 0609, Appendix A, The Significance Determination Process for Findings at Power, Exhibit 3, Barrier Integrity Screening Questions, and determined that both questions for the Reactor Containment were answered No and therefore the issue screened as Green.

• Title 10 CFR Part 50, Appendix B, Criterion VIII, Identification and Control of Materials, Parts, and Components, requires, in part, that measures shall be established for the identification and control of materials, parts, and components, including partially fabricated assemblies. These identification and control measures shall be designed to prevent the use of incorrect or defective material, parts, and components. Contrary to that requirement, on January 7, 2014, following planned work on the Unit 2, Train A Emergency Diesel Generator, the licensee identified that an incorrect component, a fuel oil pump with an alternate design, had been installed on multiple emergency diesel generators. The licensee entered the issue into the CAP as IR 1604977, 2A Diesel Generator Engine Driven Fuel Oil Pump Not Like For Like, reinstalled the original fuel oil pump, and performed an evaluation for the remaining diesel generators.

The licensee identified that a new fuel oil pump being installed on the diesel generator was not similar to the fuel oil pump being removed. This discrepancy was identified by maintenance staff during a procedurally required assessment of the new fuel oil pump. An extent of condition review identified that the fuel oil pumps currently installed on the remaining diesels (Unit 1 Trains A and B; Unit 2 Train B) were like the new fuel oil pump. These pumps had been replaced previously as part of routine preventative maintenance activities.

Post-identification reviews determined that the new fuel oil pumps with the alternate configuration would perform similarly to the original pumps and therefore would not adversely impact diesel generator operability. The inspectors determined that the failure to identify that the fuel oil pumps installed on Unit 1 Trains A and B; and Unit 2 Train B were not like for like was a performance deficiency. The inspectors determined that the performance deficiency was more than minor because it was similar to an example in IMC 0612, Appendix E, Examples of Minor Issues. Specifically, Work in Progress Findings, Example C, identified that an issue is not minor if an incorrect component is installed and the system is returned to service. Also, the inspectors screened the issue using IMC 0609, Appendix A, The Significance Determination Process for Findings at Power, Exhibit 2, Mitigating System Screening Questions and answered Yes to Question 1: If the finding is a deficiency affecting the design or qualification of a mitigating SSC, does the SSC maintain its operability or functionality? Therefore, the issue screened as Green.

ATTACHMENT:

SUPPLEMENTAL INFORMATION

KEY POINTS OF CONTACT

Licensee

F. Kearney, Site Vice President

B. Youman, Plant Manager

T. Chalmers, Operations Director

E. Hernandez, Engineering Director

J. Fiesel, Maintenance Director

S. Gackstetter, Regulatory Assurance Manager

D. Spitzer, Regulatory Assurance

G. Armstrong, Security Manager

S. Kerr, Training Manager

J. Reed, Health Physicist

D. Anthony, Corporate NDE Manager

R. McBride, ISI Program Engineer

J. Miller, Senior Corporate NDE Specialist

M. Swartz, Senior NDE Specialist

D. Sible, Engineering Programs Manager (Acting)

L. Zurawski, NRC Coordinator

L. Wehner, Nuclear Oversight Manager

Nuclear Regulatory Commission

E. Duncan, Chief, Reactor Projects Branch 3

Illinois Emergency Management Agency (IEMA)

R. Zuffa, IEMA

LIST OF ITEMS

Opened

05000454/2014002-01; NCV Failure to Properly Implement a Compensatory Fire Watch

05000455/2014002-01 As Required by the Fire Protection Program (Section 1R05.1.b (1))

05000454/2014-001-00 LER 0A Essential Service Water (SX) Makeup Pump Unexpected Auto-Start During 0B SX Pump Monthly Surveillance (Section 4OA3.7)

Closed

05000454/2014002-01; NCV Failure to Properly Implement a Compensatory Fire Watch

05000455/2014002-01 As Required by the Fire Protection Program (Section 1R05.1.b (1))

05000454/2014-001-00 LER 0A Essential Service Water (SX) Makeup Pump Unexpected Auto-Start During 0B SX Pump Monthly Surveillance (Section 4OA3.7)

05000455/2013 002 00 LER Unqualified Valve Diaphragm Installed in 2RE9160A in B2R16 (Section 4OA3.3)

05000455/2012-001-00 LER Manual Reactor Trip During Power Ascension Due to Steam Generator Level Approaching Turbine Trip Setpoint Caused by an Overly Complex Startup Procedure (Section 4OA3.4)

05000454/2012-004-00 LER Reactor Pressure Vessel Head Control Rod Drive Mechanism Penetration Nozzle Weld Repair (Section 4OA3.5)

05000454/2013 001-00 LER Unit 1 Failed Surveillance Test of A Train Control Room Emergency Filtration System (Section 4OA3.6)

05000454/2010007-02; URI Non-Inert Atmosphere May Challenge Fuel Integrity 50000455/2010007-02; (Section 4OA5.3)

200068/2010002-02

05000454/2010007-03; URI Licensee ISFSI Annulus Cooling System Important to 50000455/2010007-03; Safety Classification (Section 4OA5.3)

200068/2010002-03

05000454/2010007-04; URI Thermal Models in FSAR Design Basis Analysis May Not 50000455/2010007-04; be Conservative (Section 4OA5.3)

200068/2010002-04