IR 05000261/2012002

IR 05000261-12-002, Carolina Power and Light Company, on 01/01/2012-03/31/2012, H.B. Robinson Steam Electric Plant, Unit 2, Operability Evaluations, Refueling and Outage Activities

ML12121A659
Person / Time
Site:	Robinson
Issue date:	04/30/2012
From:	Randy Musser NRC/RGN-II/DRP/RPB4
To:	Gideon R Carolina Power & Light Co
Catherine Morrison
References
IR-12-002
Download: ML12121A659 (54)

Text

UNITED STATES ril 30, 2012

SUBJECT:

H.B. ROBINSON STEAM ELECTRIC PLANT - NRC INTEGRATED INSPECTION REPORT 05000261/2012002

Dear Mr. Gideon,

On March 31, 2012, the U.S. Nuclear Regulatory Commission (NRC) completed an inspection at your H. B. Robinson Steam Electric Plant, Unit 2. The enclosed inspection report documents the inspection results which were discussed on April 12, 2012, with Tom Cosgrove and other members of your staff.

The inspection examined activities conducted under your license as they relate to safety and compliance with the Commissions rules and regulations and with the conditions of your license.

The inspectors reviewed selected procedures and records, observed activities, and interviewed personnel.

Three NRC identified findings of very low safety significance (Green) were identified during this inspection. Two of these findings were determined to involve violations of NRC requirements.

The NRC is treating these violations as non-cited violations (NCVs) consistent with Section 2.3.2 of the Enforcement Policy.

If you contest these findings, you should provide a response within 30 days of the date of this inspection report, with the basis for your denial, to the Nuclear Regulatory Commission, ATTN:

Document Control Desk, Washington DC 20555-0001; with copies to the Regional Administrator, Region II, the Director, Office of Enforcement, United States Nuclear Regulatory Commission, Washington, DC 20555-0001; and the NRC Resident Inspector at H. B. Robinson Steam Electric Plant, Unit 2.

If you disagree with the cross-cutting aspect assignment in this report, you should provide a response within 30 days of the date of this report, with the basis for your disagreement, to the Regional Administrator, Region II, and the Senior Resident Inspector at H.B. Robinson.

CP&L 2 In accordance with 10 CFR 2.390 of the NRC's "Rules of Practice," a copy of this letter, its enclosure, and your response (if any) will be available electronically for public inspection in the NRC Public Document Room or from the Publicly Available Records (PARS) component of NRC's Agency wide Document 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/

Randall A. Musser, Chief Reactor Projects Branch 4 Division of Reactor Projects Docket No.: 50-261 License No.: DPR-23

Enclosure:

Inspection Report 05000261/2012002 w/Attachment: Supplemental Information

REGION II==

Docket No. 50-261 License No. DPR-23 Report No. 005000261/2012002 Facility: H. B. Robinson Steam Electric Plant, Unit 2 Location: 3581 West Entrance Road Hartsville, SC 29550 Dates: January 1, 2012 through March 31, 2012 Inspectors: J. Hickey, Senior Resident Inspector P. Lessard, Acting Senior Resident Inspector C. Scott, Resident Inspector A. Nielsen, Senior Health Physicist (Section 2RS1, 2RS3, 2RS5)

R. Hamilton, Senior Health Physicist (Section 2RS2, 2RS4, 4OA1)

W. Pursley, Health Physicist (Section 2RS5)

J. Rivera, Health Physicist (Section 2RS4, 4OA1)

L. Lake, Senior Reactor Inspector (Section 1R08)

A. Sengupta, Reactor Inspector (Section 1R08)

Approved by: R. Musser, Chief Reactor Projects Branch 4 Division of Reactor Projects Enclosure

SUMMARY OF FINDINGS

IR 05000261/2012002, Carolina Power and Light Company; on 01/01/2012-03/31/2012; H.B.

Robinson Steam Electric Plant, Unit 2; Operability Evaluations, Refueling and Outage Activities The report covered a three month period of inspection by resident inspectors, and announced inspections by health physics inspectors and reactor inspectors. One green finding and two green NCVs were identified. The significance of most findings is indicated by their color (Green, White, Yellow, Red) using Inspection Manual Chapter (IMC) 0609, Significance Determination Process (SDP). Findings for which the SDP does not apply may be Green or be assigned a severity level after NRC management review.

Cornerstone: Mitigating Systems

Green.

The inspectors identified a Green NCV of Technical Specification (TS) 3.8.4, DC Electrical Sources, when the licensee failed to comply with the action time following discovery of reasonable information to determine that Surveillance Requirement (SR)3.8.4.6 had not been performed within its frequency plus 25 percent grace period for the B safety related battery. The B battery was inoperable due to the SR not being performed. The issue was documented in the corrective action program as Nuclear Condition Report (NCR) 511315. As corrective actions, the licensee shut down the plant and successfully performed the SR.

The failure to declare in a timely manner that the TS surveillance requirement for the B safety related battery was not met, was a performance deficiency. This performance deficiency is more than minor because it is associated with the equipment performance attribute and adversely affected the Mitigating Systems Cornerstone objective to ensure the availability and reliability of systems that respond to initiating events to prevent undesirable consequences. Specifically, the licensee mistakenly extended the amount of time that they operated in Mode 1 with an inoperable safety related system. The significance of this finding was assessed in accordance with Inspection Manual Chapter 0609, Attachment 4. Using the Mitigating Systems Cornerstone column of Table 4a of Attachment 4, it was determined that the finding was of very low significance (Green)because the finding did not represent a loss of safety function and did not screen as potentially risk significant due to a seismic, flooding or severe weather initiating event.

The inspectors determined this performance deficiency has a cross-cutting aspect in the Decision Making component of the Human Performance Area, because the licensee did not use conservative assumptions to determine operability of the B safety related battery. (H.1 (b)) (Section 1R15)

Green.

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

Design Control, for the licensees installation of a plant modification that adversely affected the operability of nearby safety related equipment. Specifically, the licensees installation of radiation barriers in containment impeded the travel path for equipment associated with containment water level transmitter, LT-802E, and resulted in the B train of containment sump water level instrumentation being inoperable for a period of time greater than allowed in Technical Specification 3.3.3. The licensee took immediate actions to remove the interference with the level instrumentation. This issue was entered into the licensees corrective action program as NCR 510240.

The licensees installation of a plant modification that adversely affects the operability of nearby safety related equipment was a performance deficiency and resulted in containment water level transmitter, LT-802E, being inoperable for greater than the allowed outage time specified in Technical Specification 3.3.3. The performance deficiency was considered more than minor because it affected the Mitigating Systems Cornerstone objective of ensuring the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences (i.e. core damage). Specifically, reactor operators would have unreliable indication of containment water level during a postulated Loss of Coolant Accident (LOCA).

Using Manual Chapter 0609.04, Phase 1 Initial Screening and Characterization of Findings, the issue was evaluated to be a degradation of the Mitigation Systems cornerstone because it affects long term core decay heat removal in the event of a LOCA. Table 4a of the Phase 1 worksheet requires a Phase 2 significance determination evaluation, because the finding represents an actual loss of safety function of a single train, for greater than its Technical Specifications Allowed Outage Time. A further characterization of the safety significance could not be performed in Phase 2 because the function (i.e., containment water level indication) was not modeled and necessitated that a Phase 3 SDP be done.

The SRA performed a bounding event assessment. The dominant accident sequence was where a LOCA occurs and, as a result of the depressurization, a Steam Generator Tube Rupture happens. This leads to the water from the steam generator adding to the internal flooding event. Subsequently operators fail to isolate the ruptured steam generator thus continuing to feed the break. The increase in core damage probability (CDF) for this event was determined to be < 1E-6 therefore, this condition should be treated as very low safety significance (Green). The inspectors did not identify a cross-cutting aspect associated with this finding because the performance deficiency occurred in 2005 and does not represent current licensee performance. (Section 1R15)

Cornerstone: Barrier Integrity

Green.

The inspectors identified a Green finding for failure to follow the TS bases associated with Improved Technical Specification (ITS) 3.0.2 Limiting Condition for Operability (LCO) Applicability. Specifically, the licensee rendered the Low Temperature Overpressure Protection System (LTOP) inoperable and entered ITS 3.4.12 Condition G for operational convenience. On March 11, 2012, for approximately 90 minutes, while transitioning the Low Temperature Overpressure System from ITS LCO 3.4.12 b. to ITS LCO 3.4.12 a., the LTOP system was rendered inoperable. This issue has been entered in the corrective action program as NCR 523648. Corrective actions are being evaluated.

Rendering the LTOP system inoperable for operational convenience was a performance deficiency. The finding was more than minor because it impacted the Equipment Performance attribute of the Barrier Integrity Cornerstone, and adversely affected the cornerstone objective to provide reasonable assurance that the physical design barriers of the reactor coolant system protect the public from radionuclide releases caused by accidents or events. Specifically, with an inoperable LTOP system the RCS protection from an overpressure event is reduced. The significance of this finding was assessed using Inspection Manual Chapter 0609 Shutdown Significance Determination Process Appendix G. The inspectors determined that the finding was of very low safety significance (Green) and it did not adversely impact the five guidelines contained in Checklist 4 of core heat removal, inventory control, power availability, containment closure, or reactivity.

No cross-cutting aspect is associated with this finding as the performance deficiency does not reflect current licensee performance in that licensee has utilized this process for years. (Section 1R20.3)

Licensee-Identified Violations

None.

REPORT DETAILS

Summary of Plant Status

The unit began the inspection period at or near full rated thermal power. The unit was shutdown on January 18 to begin refueling outage RO27 on January 20, 2012. The unit was returned to service on March 23, 2012. A reactor trip occurred on March 28, 2012, due to a feedwater regulating valve problem and was returned to service on March 31, 2012. The unit operated at or near full power for the remainder of the inspection period.

REACTOR SAFETY

Cornerstones: Initiating Events, Mitigating Systems, Barrier Integrity

1R04 Equipment Alignment

a. Inspection Scope

Partial System Walkdowns:

The inspectors performed the following five partial system walkdowns, while the indicated structures, systems, and/or components (SSCs) were out-of-service for maintenance and testing:

• The B Service Water system while the A Service Water Booster Pump was out-of-service for planned maintenance on January 12, 2012;

• The B Emergency Diesel Generator while the A Emergency Diesel Generator was out-of-service for planned maintenance on January 9, 2012;

• The B Residual Heat Removal (RHR) system while the A RHR system was out-of-service for planned maintenance on January 20, 2012;

• The B Emergency AC Electrical System while the A Emergency AC Electrical System was unavailable due to testing on January 23, 2012; and

• A DC Electrical System while the "B" Station Battery was out of service for planned maintenance on January 23, 2012 To evaluate the operability of the selected trains or systems under these conditions, the inspectors compared observed positions of valves, switches, and electrical power breakers to the procedures and drawings listed in the Attachment.

The inspectors reviewed the documents listed in the Attachment to this report, to verify that the ability of the system to perform its functions could not be affected by outstanding design issues, temporary modifications, operator workarounds, adverse conditions, and other system-related issues tracked by the engineering department.

The inspectors reviewed the following ARs associated with this area to verify that the licensee identified and implemented appropriate corrective actions:

• 518276, Operating procedure and drawings do not agree for service water valves 228 and 227

• 515778, Breaker 52/MCC-5(2M) Containment Vessel Recirculation Cooler, HVH-4, Found with Dual Position Indication

b. Findings

No findings were identified.

1R05 Fire Protection

a. Inspection Scope

For the five areas identified below, the inspectors reviewed the control of transient combustible material and ignition sources, fire detection and suppression capabilities, fire barriers, and any related compensatory measures to verify that those items were consistent with Updated Final Safety Analysis Report (UFSAR) Section 9.5.1, Fire Protection System, and UFSAR Appendix 9.5.A, Fire Hazards

Analysis.

The inspectors walked down accessible portions of each area and reviewed results from related surveillance tests to verify that conditions in these areas were consistent with descriptions of the areas in the UFSAR. Documents reviewed are listed in the

.

The following areas were inspected:

• RHR Pump Room (fire zone 27)

• Component Cooling Water (CCW) Pump Room (fire zone 5)

• Containment Vessel (CV) (fire zone 24)

• Pipe Alley (Penetration Area) (fire zone 11)

• North Cable Vault (fire zone 10)

The inspectors reviewed the following ARs associated with this area to verify that the licensee identified and implemented appropriate corrective actions:

• 518299, Fire Watch Patrolling the Wrong Portion of Aux Building Hallway

• 509113, Fire Drill 12-1Q-06A/U Critical Objective Unsatisfactory

b. Findings

No findings were identified.

1R06 Underground Cable Inspection

a. Inspection Scope

The inspectors walked down two underground cable manholes/bunkers to verify the following:

• The cable was not submerged in water;

• The condition of any cable splices;

• The condition of any cable support structures; and

• The condition of any dewatering devices, if applicable.

The following cable/locations were inspected:

• A and B Service Water Pump location M-50A

• C and D Service Water Pump location M-50B Documents reviewed are listed in the Attachment.

b. Findings

No findings were identified.

1R07 Heat Sink Performance

a. Inspection Scope

The inspectors observed the inspection of the B Component Cooling Water heat exchanger to verify that inspection results were appropriately categorized against the pre-established acceptance criteria described in procedure CM-201, Safety Related and Non-Safety Related Heat Exchanger Maintenance, Rev. 51. The inspectors also verified that the frequency of inspection was sufficient to detect degradation prior to loss of heat removal capability below design basis values.

b. Findings

No findings were identified.

1R08 Inservice Inspection Activities

a. Inspection Scope

Non-Destructive Examination Activities and Welding Activities: From February 6 - 10, 2012, the inspectors conducted an on-site review of the implementation of the licensees Inservice Inspection (ISI) Program for monitoring degradation of the reactor coolant system, emergency feed water systems, risk-significant piping and components, and containment systems in Unit 2. The inspectors activities included a review of non-destructive examinations (NDEs) to evaluate compliance with the applicable edition of the American Society of Mechanical Engineers (ASME) Boiler and Pressure Vessel Code (BPVC),Section XI (Code of record: 1995 Edition with 1996 Addenda), and to verify that indications and defects were appropriately evaluated and dispositioned in accordance with the requirements of the ASME Code,Section XI, acceptance standards or NRC approved alternative requirement.

The inspectors directly observed or reviewed records of the following NDE mandated by the ASME Code to evaluate compliance with the ASME Code Section XI and Section V requirements, and if any indications and defects were detected. Inspectors also reviewed evaluations of results that were dispositioned in accordance with the ASME Code or an NRC-approved alternative requirement.

(1) Directly observed:

• Visual examinations of the reactor pressure vessel internals required by table IWB 2500 of Section XI; and

• Augmented Visual examinations of the reactor pressure vessel internals required by Material Research Project Guideline MRP 227.

(2) Reviewed records:

• Ultrasonic (UT) examination of welds 220A/62 and 220A/69 associated with Valve CVC-277A; and

• Liquid Penetrant examination of welds 220A/62 and 220A/69 associated with Valve CVC-277A.

The inspectors reviewed the records of the following volumetric examinations performed during the previous refuelling outage where indications where found unacceptable and required additional analytical evaluation to determine acceptability for continued service.

Inspectors also reviewed the plans and procedures for the required follow-up ultrasonic to be performed later during this outage. These plans were reviewed for incorporation of new requirements in 10CFR50.55a that adopted ASME Code Case N 770.

• Phased Array UT examination of the following safe-end dissimilar metal welds in the Reactor Coolant system;

(1) 107/01 DM-Outlet A at 130 degrees

(2) 107/14 DM Inlet A at 80 degrees

(3) 107A/01 DM Outlet B at 10 degrees

(4) 107A/14 DM Inlet B at 320 degrees

(5) 107B/01 DM Outlet C at 320 degrees

(6) 107B/14 DM Inlet C at 200 degrees The inspectors reviewed documentation for the repair/replacement of the following pressure boundary welds. The inspectors evaluated if the licensee applied the pre-service non-destructive examinations and acceptance criteria required by the construction Code. In addition, the inspectors reviewed the welding procedure specifications, welder qualifications, welding material certifications, and supporting weld procedure qualification records to evaluate if the weld procedures were qualified in accordance with the requirements of Construction Code and the ASME Code Section IX.

• Work Order 01958279 Replacement of valve CVC 277A in the Chemical and Volume Control System.

PWR Vessel Upper Head Penetration (VUHP) Inspection Activities: For the Unit 2 vessel head, a bare metal visual examination was not required this outage pursuant to 10 CFR 50.55a. The licensee did not perform any inspections or repairs on the RPVUHP this outage. Therefore, no NRC review was completed for this inspection procedure attribute.

Boric Acid Corrosion Control (BACC) Inspection Activities: The inspectors reviewed the licensees BACC program activities to ensure implementation with commitments made in response to NRC Generic Letter 88-05, Boric Acid Corrosion of Carbon Steel Reactor Pressure Boundary, and applicable industry guidance documents. Specifically, the inspectors performed an on-site record review of procedures and the results of the licensees containment walkdown inspections performed during the current winter refueling outage. The inspectors also interviewed the BACC program owner, conducted an independent walkdown of containment to evaluate compliance with licensees BACC program requirements, and verified that degraded or non-conforming conditions, such as boric acid leaks, were properly identified and corrected in accordance with the licensees BACC and corrective action programs.

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

• 255325-18, Evaluation of small amount of boric acid accumulation at the base at one of the casing bolts of SI-PMP-A;

• 467704-15, Evaluation of small amount of boric acid accumulation at the base at one of the casing bolts of SI-PMP-B; and

• Technical Report dated February 3, 2012, Robinson Nuclear Plant Material Characterization of Deposits Removed from Control Rod Drive Mechanism Penetrations on the Reactor Head.

Steam Generator Inspection Activities: The inspectors reviewed the Steam Generator Condition Monitoring Assessment of Spring 2010 Inspection Results and Operating Assessment for Operating Cycles 27 and 28 H.B. Robinson Unit 2. No Steam Generator Tube Inspection Activities occurred during this outage.

Identification and Resolution of Problems: The inspectors performed a review a sample of ISI-related problems that were identified by the licensee and entered into the corrective action program as condition reports (CRs). The inspectors reviewed the CRs to confirm the licensee had appropriately described the scope of the problem and had initiated corrective actions. The review also included the licensees consideration and assessment of operating experience events applicable to the plant. The inspectors performed this review to ensure compliance with 10CFR Part 50, Appendix B, Criterion XVI, Corrective Action, requirements. The corrective action documents reviewed by the inspectors are listed in the report attachment.

b. Findings

No findings were identified.

1R11 Licensed Operator Requalification

a. Inspection Scope

Licensed Operator Requalification Activities in Simulator The inspectors observed licensed-operator performance during requalification simulator training to verify that operator performance was consistent with expected operator performance, as described in Exercise Guide License Operator Continuing Training, RO-27 Startup JITT. This training tested the operators ability to operate components from the control room, direct auxiliary operator actions, and determine the appropriate emergency action level classifications while responding to a control rod withdrawal malfunction during rod withdrawal for criticality. The inspectors focused on clarity and formality of communication, the use of procedures, alarm response, control board manipulations, group dynamics, and supervisory oversight.

The inspectors observed the simulator exercise freeze critiques to verify that the licensee identified deficiencies and discrepancies that occurred during the simulator training.

Licensed Operator Performance in the Actual Plant/Main Control Room The resident inspectors were in the control room to observe and assess licensee operator performance during heat up and start up activities following the reactor trip on March 28, 2012. During this period of heightened risk the inspectors verified that the licensed operators actions and communication were in accordance with OMM-001, Conduct of Operations, Rev. 38.

The inspectors reviewed the following ARs associated with this area to verify that the licensee identified and implemented appropriate corrective actions:

• 519398, Information on qualification experience form entered incorrectly

• 507238, Preliminary Results of Initial License Training NRC Exam Did Not Meet Goals

b. Findings

No findings were identified.

1R12 Maintenance Effectiveness

a. Inspection Scope

The inspectors reviewed the two degraded SSC/function performance problems or conditions listed below to verify the appropriate handling of these performance problems or conditions in accordance with 10 CFR 50, Appendix B, Criterion XVI, Corrective Action, and 10 CFR 50.65, Maintenance Rule. Documents reviewed are listed in the

.

• Containment liner condition monitoring and maintenance

• Boric acid heat trace system condition monitoring and maintenance During the reviews, the inspectors focused on the following:

• Appropriate work practices;

• Identifying and addressing common cause failures;

• Scoping in accordance with 10 CFR 50.65(b);

• Characterizing reliability issues (performance);

• Charging unavailability (performance);

• Trending key parameters (condition monitoring);

• 10 CFR 50.65(a)(1) or (a)(2) classification and reclassification; and

• Appropriateness of performance criteria for SSCs/functions classified (a)(2) and/or appropriateness and adequacy of goals and corrective actions for SSCs/functions classified (a)(1).

The inspectors reviewed the following ARs associated with this area to verify that the licensee identified and implemented appropriate corrective actions:

• 520785, Inadequate Maintenance Rule Performance Criteria; and

• 517949, Wide Range Steam Generator (SG) Level Indication Not in Scope of Maintenance Rule.

b. Findings

No findings were identified.

1R13 Maintenance Risk Assessments and Emergent Work Evaluation

a. Inspection Scope

For the six samples listed below, the inspectors reviewed risk assessments and related activities to verify that the licensee performed adequate risk assessments and implemented appropriate risk-management actions when required by 10 CFR 50.65(a)(4). For emergent work, the inspectors also verified that any increase in risk was promptly assessed, and that appropriate risk-management actions were promptly implemented. Documents reviewed are listed in the Attachment. Those periods included the following:

• Qualitative Yellow Risk Condition due to Crane Operations in the Vicinity of the Refueling Water Storage Tank (RWST) and the A Safety Injection Pump out-of-service for maintenance, on January 13, 2012;

• Yellow Risk Condition during Cool-down with 'B' Station Battery train inoperable and Pressurizer Level Transmitter, LT-4, out-of-service, on January 19, 2012;

• Yellow Risk Condition due to A AC Electrical train out-of-service and Containment Penetrations being open during outage activities on January 22, 2012;

• Yellow Risk Condition during Lower Inventory Conditions with B Emergency Diesel Generator out-of-service for maintenance; on January 31, 2012 - February 2, 2012;

• Yellow Risk Condition while performing fuel moves, with the C Service Water Pump out-of-service for maintenance, on February 7, 2012; and

• Yellow Risk Condition while the "B" Electrical Power train was out of service for planned maintenance and the B Charging Pump out-of-service for maintenance on February 14, 2012.

The inspectors reviewed the following ARs associated with this area to verify that the licensee identified and implemented appropriate corrective actions:

• 507406, Work Activity Stopped Due to Not Being in Risk Profile

• 513466, Protected Equipment Walk down Deviations

b. Findings

No findings were identified.

1R15 Operability Evaluations

a. Inspection Scope

The inspectors reviewed the eight operability determinations associated with the ARs listed below. The inspectors assessed the accuracy of the evaluations, the use and control of any necessary compensatory measures, and compliance with the TS. The inspectors verified that the operability determinations were made as specified by Procedure OPS-NGGC-1305, Operability Determinations. The inspectors compared the justifications provided in the determinations to the requirements from the TS, the UFSAR, associated design-basis documents, to verify that operability was properly justified and the subject components or systems remained available, such that no unrecognized increase in risk occurred:

• 511315, Excessive Time Required to Determine if MST-920 Was Missed

• 510086, Operability Evaluation of 'A' Station Battery Capacity

• 513437, EDG 'A'/'B' Undervoltage Relay May not be Seismically Qualified

• 500790, Damaged Support on Steam Driven Auxiliary Feedwater Exhaust Piping

• 501537, Potential Seismic Interaction with B EDG Exhaust

• 510240, Chain Located Around Float for CV Water Level

• 524419, Boric Acid Buildup on ECCS Strainers in the area behind the C RCP

• 510195, Evaluation of Required Battery Recharge Requirements Following a Discharge Documents reviewed are listed in the Attachment.

The inspectors reviewed the following ARs associated with this area to verify that the licensee identified and implemented appropriate corrective actions:

• 524619, Unplanned LCO 3.5.4 Entry Due to RWST on Purification

• 524895, Steam Dumps Came open Unexpectedly

1. Failure to Implement TS Requirements Regarding B Battery Inoperability

Introduction:

The inspectors identified a Green NCV of TS 3.8.4, DC Electrical Sources, when the licensee failed to comply with the action times following discovery of reasonable information to determine that SR 3.8.4.6 had not been performed within its frequency plus 25 percent grace period for the B safety related battery. TS 3.8.4 requires restoration of the affected battery within 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br />, or be in mode 3 within 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br />.

Description:

At 0921 on January 17, 2012, the shift manager (SM) was informed by Engineering that SR 3.8.4.6 (capacity test) for the B battery had not been performed within its frequency plus 25 percent grace period. This report was based upon a review of the licensees surveillance tracker and quality assurance (QA) records. The frequency for this SR is 60 months. The plant was in Mode 1 and the SM immediately recognized that the plant would have to be shut down to Mode 5 if this SR was to be performed.

The licensees SR 3.0.3 states that if it is discovered that an SR was not performed within its specified frequency, then compliance with the requirement to declare the Limiting Condition for Operation (LCO) not met may be delayed, from the time of discovery, up to 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> or up to the limit of the specified frequency, whichever is less.

This delay period is permitted to allow performance of the SR. However, the delay period is not applicable to this situation because the licensee was not going to be able to perform the SR in Mode 1. Additionally, the licensees SR 3.0.3 does not grant the ability to assess and manage the risk associated with a missed SR in lieu of performance of the SR.

However, instead of declaring the B battery inoperable, the licensee decided to enter their operability determination process. This decision was based upon the previously discussed incorrect interpretation of the delay period in SR 3.0.3 and guidance in licensee procedure OPS-NGGC-1305, Rev. 4, Operability Determinations. This procedure states that once a degraded or nonconforming condition is identified, in most cases it is expected the operability determination can be made almost immediately and in other cases the decision can be made within approximately 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> of discovery even though complete information may not be available. The licensees operability determination considered three paths:

1) Search for another test that was performed that could be credited for the SR. This search produced no completed test that could be substituted.

2) Determine how many days are in a month (i.e. if a month contains 31 days instead of 30, the licensee would have been within the frequency plus 25 percent grace period).

The licensee determined this path would not be successful.

3) Pursue Enforcement Discretion from the NRC to enable them to not perform the SR prior to the scheduled shutdown planned for January 21, 2012. At approximately 1730 on January 17, 2012, during a teleconference with the NRC, the licensee was informed that they did not qualify for Enforcement Discretion because they had already exceeded the SR frequency plus 25 percent grace period.

The inspectors determined that the Operability Determination process was not appropriate because sufficient information was available to allow the SM to reasonably conclude that the B battery was inoperable. This information was provided when Engineering presented evidence of a potential missed SR to the SM at 0921, and was based upon a review of the licensees surveillance tracker and QA records. With that information, the SM should have declared the B battery inoperable and immediately entered the action statements of TS 3.8.4. If this had been done properly, the licensee would have entered Mode 3 by 1721 on January 17, 2012. However, the licensee did not enter Mode 3 until 0040 on January 18, 2012.

Analysis:

The failure to declare in a timely manner that the TS surveillance requirement for the B safety related battery was not met, was a performance deficiency. This performance deficiency was more than minor because it is associated with the equipment performance attribute and adversely affected the Mitigating Systems Cornerstone objective to ensure the availability and reliability of systems that respond to initiating events to prevent undesirable consequences. Specifically, the licensee extended the amount of time that they operated in Mode 1 with an inoperable safety related system. The significance of this finding was assessed in accordance with Inspection Manual Chapter 0609, Attachment 4. Using the Mitigating Systems Cornerstone column of Table 4a of Attachment 4, it was determined that the finding was of very low significance (Green) because the finding did not represent a loss of safety function and did not screen as potentially risk significant due to a seismic, flooding or severe weather initiating event. The inspectors determined this performance deficiency had a cross-cutting aspect in the Decision Making component of the Human Performance Area, because the licensee did not use conservative assumptions to determine operability of the B safety related battery. (H.1(b))

Enforcement:

TS 3.8.4 requires restoration of an inoperable battery within 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> or be in Mode 3 within the following 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br />. Contrary to this requirement, on January 17, 2012, the licensee was not able to restore the B battery to operable and did not enter Mode 3 until approximately 15 hours1.736111e-4 days <br />0.00417 hours <br />2.480159e-5 weeks <br />5.7075e-6 months <br /> after reasonable information was available to determine that the B battery was inoperable. As corrective actions, the licensee shut down the plant and successfully performed the SR. Because this finding is of very low safety significance and has been entered into the licensees corrective action program as NCR 511315, it is being treated as an NCV, consistent with Section 2.3.2 of the NRC Enforcement Policy: NCV 05000261/2012002-01, Failure to Implement Technical Specification Action Requirements Regarding B Battery Inoperability.

2. Inadequate Design Change resulted in Interference and Inoperability of Containment

Water Level Indication

Introduction:

The inspectors identified a Green NCV of 10 CFR Part 50, Appendix B, Criterion III, Design Control, for the licensees installation of a plant modification that adversely affected the operability of nearby safety related equipment. Specifically, the licensees installation of radiation barriers in containment impeded the travel path for equipment associated with containment water level transmitter, LT-802E, and resulted in the B train of containment water level instrumentation being inoperable for a period of time greater than allowed in Technical Specification 3.3.3. The licensee documented the issue in NCR 510240 and made a field change to remove the interaction with the level instrumentation.

Description:

On January 19, 2012, the resident inspectors performed a walk down of containment. During the walk down inspectors noted that an anchor bolt and chain, used to restrain a radiation barrier near the reactor pit shield area, was installed in very close proximity to one of two containment sump level floats. The inspectors questioned whether the anchor bolt and chain could impact the float during operation. The inspectors were concerned that the anchor bolt and chain could impede the movement of the float and potentially affect the instruments ability to measure containment water level. The licensee documented the inspectors concerns in NCR 510240.

The licensee performed an evaluation to determine if the potential obstruction identified by the inspectors affected the operation of the containment sump water sump level instrument. Site engineering confirmed that the anchor bolt and chain, installed near the instrument, interfered with the path of the travel for containment level instrument, LT-802E. The plant has two redundant trains of containment sump water level instrumentation. The affected instrument was associated with the B train. The containment sump water level (wide range) instruments are a part of the Post Accident Monitoring Instrumentation (PAM). The primary purpose of the PAM instrumentation is to provide information to operators during accident situations. This information provides the necessary support for the operators to take manual actions for which no automatic control is provided and that are required for safety systems to accomplish their safety functions for design bases accidents. PAM instrumentation is required to be operable in Modes 1, 2, and 3. The plant was in Mode 5 when the interference was discovered and the licensee determined that the instrumentation was degraded. The licensee initiated actions to relocate the chain to remove the interaction with the level instrumentation.

The licensee also performed an evaluation to determine the past operability of the B train containment sump water level indication.

In Engineering Change (EC) 84575, engineering determined that the float associated with LT-802E would be stopped by the anchor bolt at a containment water level of 370 inches. The top range of the instrument is 423.5 inches above the reactor vessel floor.

Emergency Operating Procedure FR-J.2, Response to Containment Flooding, provide actions for the operators to respond when the containment level is greater that the design flood level of 375 inches. Due to LT-802E, not being able to provide an indicated containment water level of 375 inches as required by the Critical Safety Function Status Tree, LT-802E was determined to have been inoperable since 2005. The licensees evaluation of AR 510240 noted that the chain and anchor bolt were installed in 2005 as part of an EC 58222 to install very high radiation area (VHRA) and locked high radiation area (LHRA) barriers in containment. Additionally, engineering confirmed that the float would have been able to provide the necessary indication, of 354 inches, for operators to place the reactor coolant system (RCS) and RHR system in recirculation.

The inspectors reviewed EC 58222 and noted that the installation package did not mention the containment sump water level instrumentation as being a potential interface.

The interface requirements for the EC stated LHRA and VRHA barriers shall not adversely impact any safety related SSC. Furthermore, licensee procedure ERG-NGGC-0005, Engineering Change, states in part that design inputs shall be specified to the level of detail necessary to permit the activity to be carried out in a correct manner and to provide a consistent basis for making design decisions The inspectors concluded that the design sketches and installation package did not take into account the location of the containment sump water level instrumentation and lacked the necessary detail to install the radiation barriers in a manner that would not adversely affect nearby safety related equipment. The installation of the anchor bolt and chain in close proximity to the containment sump level instrumentation adversely affected a safety related SSC and rendered the B train containment water level indication inoperable.

Analysis.

The licensees installation of a plant modification that adversely affects the operability of nearby safety related equipment was a performance deficiency and resulted in containment water level transmitter, LT-802E, being inoperable for greater than the allowed outage time specified in Technical Specification 3.3.3. The performance deficiency was considered more than minor because it affected the Mitigating Systems Cornerstone objective of ensuring the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences (i.e. core damage). Specifically, reactor operators would have unreliable indication of containment water level during a postulated Loss of Coolant Accident (LOCA).

Using Manual Chapter 0609.04, Phase 1 Initial Screening and Characterization of Findings, the issue was evaluated to be a degradation of the Mitigation Systems cornerstone because it affects long term core decay heat removal in the event of a LOCA. Table 4a of the Phase 1 worksheet requires a Phase 2 significance determination evaluation, because the finding represents an actual loss of safety function of a single train, for greater than its Technical Specifications Allowed Outage Time. A further characterization of the safety significance could not be performed in Phase 2 because the function (i.e., containment water level indication) was not modeled and necessitated that a Phase 3 SDP be done.

The SRA performed a bounding event assessment. The dominant accident sequence was where a LOCA occurs and, as a result of the depressurization, a Steam Generator Tube Rupture happens. This leads to the water from the steam generator adding to the internal flooding event. Subsequently operators fail to isolate the ruptured steam generator thus continuing to feed the break. The increase in core damage probability (CDF) for this event was determined to be < 1E-6 therefore, this condition should be treated as very low safety significance (Green).

The inspectors did not identify a cross-cutting aspect associated with this finding because the performance deficiency occurred in 2005 and does not represent current licensee performance.

Enforcement:

10 CFR Part 50, Appendix B, Criterion III, Design Control, requires, in part, that design control measures shall provide for verifying or checking the adequacy of design, such as by the performance of design reviews, by the use of alternate or simplified calculation methods, or by the performance of a suitable testing program.

Contrary to the above, in 2005, during the installation of Engineering Change 58222, the licensees design control measures failed to verify the adequacy of the design and ensure that the radiation barriers did not adversely impact safety related equipment. As corrective actions, the licensee removed the interference with the containment sump water level instrumentation. Because this violation was of very low safety significance and it was entered into the licensees corrective action program (AR 510240), this violation is being treated as a non-cited violation (NCV), consistent with consistent with Section 2.3.2 of the NRC Enforcement Policy. This violation is therefore designated as NCV 05000261/2012002-02, Inadequate Design Change resulted in Interference and Inoperability of Containment Water Level Indication.

1R18 Plant Modifications

.1 Permanent Modifications

a. Inspection Scope

The inspectors reviewed the two permanent modifications listed below, to verify that the modification design, implementation, and testing did not degrade the design basis, and performance capabilities of risk significant equipment and did not place the plant in an unsafe or unanalyzed condition. The inspectors verified that the modification satisfied the requirements of Procedure EGR-NGGC-005, Engineering Change, and 10 CFR 50, Appendix B, Criterion III, Design Control. Documents reviewed are listed in the

.

• Engineering Change 75047 EDG B Voltage Regulator Replacement

• Engineering Change 77389, Replace Existing B-1 Battery Charger

b. Findings

No findings were identified.

1R19 Post Maintenance Testing

a. Inspection Scope

For the seven post-maintenance tests (PMT) listed below, the inspectors witnessed the test and/or reviewed the test data to verify that test results adequately demonstrated restoration of the affected safety functions described in the UFSAR and TS. Documents reviewed are listed in the Attachment.

The following tests were witnessed/reviewed:

• WO 2035189, Replace Blown Fuse on Transformer ; PMT in accordance with OP-602, Dedicated Shutdown Diesel Generator, Rev.63

• WO 2053272, Replace Sequencer Relay S-2; PMT in accordance with OST-163, Safety Injection Test and Emergency Diesel Generator Auto Start on Loss of Power and Safety Injection (Refueling), Rev.62

• WO 2032527, Replace D Service Water Pump; PMT in accordance with OST-302-2 Service Water Pumps C and D Inservice Test, Rev. 53

• WO 2038902, Replace EDG A Jacket Water Heater; PMT in accordance with OST-604, Emergency Diesel Generator Operation, Rev.87

• WO 1810311, Cleaning and inspection of the B Component Cooling Water Heat Exchanger; PMT in accordance with CM-201, Safety Related and Non-Safety Related Heat Exchanger Maintenance, Rev. 49, Rev. 50 and Rev. 51

• WO 1700177, Replace Stationary Contacts on B Safety Injection Pump Breaker; PMT in accordance with MST 025, Emergency E-2 Undevoltage and Load Shed Test (Refueling Shutdown), Rev.17 and Rev. 18

• WO 1655939, Replace Emergency Diesel Generator B Voltage Regulator; PMT in accordance with SPP-051, Diesel Generator B Operation and Automatic Voltage Regulator Set-Up and Testing Procedure, Rev. 2, 3, 4, and 5 The inspectors reviewed the following ARs associated with this area to verify that the licensee identified and implemented appropriate corrective actions:

• 519164, SI-864A, Refueling Water Storage Tank Discharge, Leaks Approx 1.4 GPH

• 526176, Return To Service /Monitoring Plans Failed to Identify Error in Feedwater Pump Bearing Reassembly

b. Findings

No findings were identified.

1R20 Refueling and Outage Activities

For the outage that began on January 18 and ended on March 23 the inspectors evaluated licensee outage activities as described below to verify that the licensee considered risk in developing outage schedules, adhered to administrative risk reduction methodologies they developed to control plant configuration, and adhered to operating license and technical specification requirements that maintained defense-in-depth. The inspectors also verified that the licensee developed mitigation strategies for losses of the following key safety functions:

• decay heat removal

• inventory control

• power availability

• reactivity control

• containment Documents reviewed are listed in the Attachment.

.1 Review of Outage Plan

a. Inspection Scope

Prior to the outage, the inspectors reviewed the outage risk control plan to verify that the licensee had performed adequate risk assessments, and had implemented appropriate risk-management strategies when required by 10 CFR 50.65(a)(4).

b. Findings

No findings were identified.

.2 Monitoring of Shutdown Activities

a. Inspection Scope

The inspectors observed portions of the cooldown process to verify that technical specification cooldown restrictions were followed.

b. Findings

No findings were identified.

.3 Licensee Control of Outage Activities

a. Inspection Scope

During the outage, the inspectors observed the items or activities described below to verify that the licensee maintained defense-in-depth commensurate with the outage risk-control plan for key safety functions and applicable technical specifications when taking equipment out of service.

• Clearance Activities

• Reactor Coolant System Instrumentation

• Electrical Power

• Decay Heat Removal (DHR)

• Spent Fuel Pool Cooling

• Inventory Control

• Reactivity Control

• Containment Closure The inspectors also reviewed responses to emergent work and unexpected conditions to verify that resulting configuration changes were controlled in accordance with the outage risk control plan, and to verify that control-room operators were kept cognizant of the plant configuration.

b. Findings

Introduction:

The inspectors identified a Green finding (FIN) for failure to follow the TS bases associated with Improved Technical Specification (ITS) 3.0.2 Limiting Condition for Operability (LCO) Applicability. Specifically, the licensee rendered the Low Temperature Overpressure Protection System (LTOP) inoperable and entered ITS 3.4.12 Condition G for operational convenience.

Description:

During a review of operational logs, the inspectors identified that on March 11, 2012, at 12:04 am the licensee entered ITS 3.4.12 Condition G as a result of removing both pressurizer power operated relief valves (PORV) from service. The pressurizer PORVs were removed from service to support removing the blocking devices which were installed to ensure the pressurizer PORVs remained open to provide an adequate reactor coolant system (RCS) vent path. The pressurizer PORV blocking devices were removed and the LTOP system declared operable at 01:30 am.

ITS LCO 3.0.2 bases states, in part The reasons for intentionally relying on the ACTIONS include, but are not limited to, performance of Surveillances, preventive maintenance, corrective maintenance, or the investigation of operational problems.

Entering ACTIONS for these reasons must be done in a manner that does not compromise safety. Intentional entry into ACTIONS should not be made for operational convenience. Alternatives that would not result in redundant equipment being inoperable should be used instead.

The licensee has followed this sequence for many years in transitioning from the blocked opened pressurizer PORVs to comply with ITS LCO 3.4.12 b. which requires the RCS to be depressurized via an RCS vent of greater than or equal to 4.4 square inches to ITS LCO 3.4.12 a. which utilizes the automatic LTOP system to lift the pressurizer PORV at 400 psig. During the removal of the pressurizer PORV blocking device the pressurizer PORV is maintained open. Subsequently and in accordance with procedures, the licensee verified the pressurizer PORVs stroke times were within acceptable limits and the control switches were placed in the positions to support LTOP operability. Because of this sequence, the LTOP system remained available throughout the time the LTOP system was inoperable. This issue has been entered in the corrective action program as CR 523648. Corrective actions are being evaluated.

Analysis:

The inspectors determined that the licensees entry in ITS LCO 3.4.12 G. was for operational convenience and constituted a performance deficiency. Specifically, the licensee rendered the LTOP system inoperable while transitioning from using the blocked open pressurizer PORVs as a greater than or equal to 4.4 square inch vent path for the RCS to using the pressurizer PORVs in an automatic opening system with a setpoint of 400 psig. The inspectors evaluated the performance deficiency in accordance with IMC 0612 Appendix B, Issue Screening. This performance deficiency was not similar to any of the examples in IMC 0612 Appendix E, Examples of Minor Issues, but was characterized as more than minor because it impacted the Equipment Performance attribute of the Barrier Integrity Cornerstone, and adversely affected the cornerstone objective to provide reasonable assurance that the physical design barrier of the reactor coolant system protect the public from radionuclide releases caused by accidents or events. Specifically, with an inoperable LTOP system the RCS protection from an overpressure event is reduced.

The inspectors determined the finding could be evaluated using the SDP in accordance with IMC 0609, Significance Determination Process, Attachment 0609.04, Phase 1 -

Initial Screening and Characterization of Findings, Table 3b for the Mitigating Systems Cornerstone. This directed the inspectors to IMC 0609, Appendix G Shutdown Operations Significance Determination Process Phase 1 Operational Checklists for Both PWRs and BWRs. The inspectors used Checklist 4 and determined the finding was of very low safety significance (Green) because it did not adversely impact the five guidelines contained in the checklist of core heat removal, inventory control, power availability, containment closure, or reactivity.

No cross-cutting aspect is associated with this finding as the performance deficiency does not reflect current licensee performance as the licensee has utilized this process for years.

Enforcement:

Enforcement action does not apply because the performance deficiency did not involve a violation of regulatory requirements. Because this finding does not involve a violation and has very low safety significance, it is identified as FIN 05000261/2012002-03, Low Temperature Overpressure System Rendered Inoperable For Operational Convenience.

.4 Refueling Activities

a. Inspection Scope

The inspectors observed fuel handling operations (removal, inspection, and insertion)and other ongoing activities to verify that those operations and activities were being performed in accordance with technical specifications and approved procedures. Also, the inspectors observed refueling activities to verify that the location of the fuel assemblies, including new fuel, was tracked from core offload through core reload.

b. Findings

No findings were identified.

.5 Monitoring of Heatup and Startup Activities

a. Inspection Scope

Prior to mode changes and on a sampling basis, the inspectors reviewed system lineups and/or control board indications to verify that TSs, license conditions, and other requirements, commitments, and administrative procedure prerequisites for mode changes were met prior to changing modes or plant configurations. Also, the inspectors periodically reviewed RCS boundary leakage data, and observed the setting of containment integrity to verify that the RCS and containment boundaries were in place and had integrity when necessary. Prior to reactor startup, the inspectors walked down containment to verify that debris had not been left which could affect performance of the containment sumps. The inspectors reviewed reactor physics testing results to verify that core operating limit parameters were consistent with the design.

b. Findings

No findings were identified.

.6 Identification and Resolution of Problems

a. Inspection Scope

Periodically, the inspectors reviewed the items that had been entered into the CAP to verify that the licensee had identified problems related to outage activities at an appropriate threshold and had entered them into the corrective action program. For the significant problems documented in the corrective action program and listed below, the inspectors reviewed the results of the investigations to verify that the licensee had determined the root cause and implemented appropriate corrective actions, as required by 10 CFR 50, Appendix B, Criterion XVI, Corrective Action.

• 510233, White Boric Acid Found on PS-955L Isolation System Vent Valve

• 510236, Boric Acid Found in C Reactor Coolant Pump (RCP) Bay

• 510237, Boric Acid on Wall in B RCP Bay

• 518264 Boric acid on Top of C Hot Leg Piping Insulation

• 510652, Oil Spilled on Reactor Vessel Head Spare O-Rings

• 511781, Protected Pathway not Bolded on Key Safety Function Status Sheet

.7 March 28, 2012, Reactor Trip as a Result of the B Feed Regulating Valve Failing Open

a. Inspection Scope

For the unscheduled outage that began on March 28 and ended on March 31 the inspectors evaluated licensee outage activities to verify that the licensee considered risk in developing outage schedules, adhered to administrative risk reduction methodologies they developed to control plant configuration, and adhered to operating license and technical specification requirements that maintained defense-in-depth. The inspectors also verified that the licensee developed mitigation strategies for losses of the following key safety functions:

• decay heat removal

• inventory control

• power availability

• reactivity control

• containment The inspectors observed the reactor startup and power ascension activities.

b. Findings

No findings were identified.

1R22 Surveillance Testing

a. Inspection Scope

For the eight surveillance tests listed below, the inspectors witnessed testing and/or reviewed the test data to verify that the systems, structures, and components involved in these tests satisfied the requirements described in the TS, the UFSAR, and applicable licensee procedures, and that the tests demonstrated that the SSCs were capable of performing their intended safety functions. Documents reviewed are listed in the

.

• MST-801, Dedicated Shutdown Diesel Generator (DSDG) and Uninterruptable Power Supply (UPS) and AMSAC UPS Batteries (Weekly), Rev. 22

• OST-410, Emergency Diesel Generator A ( Twenty-Four Hour Load Test), Rev.45

• OST-910, DSDG Monthly Run, Rev.51

• MST-921, Station Battery Service Test, Rev. 28

• EST-030, Operational Test for Manipulator Crane and Refueling Interlocks (Refueling Interval), Rev. 48 Inservice Testing Surveillance

• OST-251-2, RHR Pump B and Components Test, Rev. 28 Containment Isolation Valve Surveillance

• EST-135-2, Local Leak Rate Test of Vacuum Relief Valves, Rev. 1 Reactor Coolant System Leakage Surveillance

• OST-051, Reactor Coolant Leakage Evaluation (Every 72 Hours During Steady State Operation and Within 12 Hours of Reaching Steady State Operation) Rev. 45 The inspectors reviewed the following ARs associated with this area to verify that the licensee identified and implemented appropriate corrective actions:

• 522529, Recalibrate Generator Volt Meter on EDG A Generator Panel

• 522860, High Leakage During EST-135, Local Leak Rate Test- Containment Vessel Supply Valves

b. Findings

No findings were identified.

2RS1 Radiological Hazard Assessment and Exposure Controls

a. Inspection Scope

Hazard Assessment and Instructions to Workers: During facility tours, the inspectors directly observed labeling of radioactive material and postings for radiation areas, high radiation areas (HRAs), and airborne radioactivity areas established within the radiologically controlled area (RCA) of the auxiliary building, reactor containment building, and radioactive waste (radwaste) processing and storage locations. The inspectors independently measured radiation dose rates or directly observed conduct of licensee radiation surveys for selected RCA areas. The inspectors reviewed survey records for several plant areas including surveys for alpha emitters, discrete radioactive particles, airborne radioactivity, gamma surveys with a range of dose rate gradients, and pre-job surveys for upcoming tasks. The inspectors also discussed changes to plant operations that could contribute to changing radiological conditions since the last inspection. For selected outage jobs, the inspectors attended pre-job briefings and reviewed radiation work permit (RWP) details to assess communication of radiological control requirements and current radiological conditions to workers.

Hazard Control and Work Practices: The inspectors evaluated access barrier effectiveness for selected Locked High Radiation Area (LHRA) locations. Changes to procedural guidance for LHRA and Very High Radiation Area (VHRA) controls were discussed with health physics (HP) supervisors. Controls and their implementation for storage of irradiated material within the spent fuel pool (SFP) were reviewed and discussed in detail. Established radiological controls (including airborne controls) were evaluated for selected Refueling Outage 27 (RO-27) tasks including maintenance activities in the lower cavity and reactor head work. In addition, licensee controls for areas where dose rates could change significantly as a result of plant shutdown and refueling operations were reviewed and discussed.

Occupational workers adherence to selected RWPs and HP technician (HPT)proficiency in providing job coverage were evaluated through direct observations and interviews with licensee staff. Electronic dosimeter (ED) alarm set points and worker stay times were evaluated against area radiation survey results for filter replacement, containment sump entry, and lower cavity maintenance work. The use of personnel dosimetry (ED alarms, extremity dosimetry, multibadging in high dose rate gradients, etc.) was reviewed as part of Inspection Procedure (IP) 71124.04. Worker response to dose and dose rate alarms during selected work activities was also evaluated.

Control of Radioactive Material: The inspectors observed surveys of material and personnel being released from the RCA using small article monitor, personnel contamination monitor, and portal monitor instruments. The inspectors reviewed the last two calibration records for selected release point survey instruments and discussed equipment sensitivity, alarm setpoints, and release program guidance with licensee staff.

The inspectors compared recent 10 Code of Federal Regulations (CFR) Part 61 results for the Dry Active Waste radioactive waste stream with radionuclides used in calibration sources to evaluate the appropriateness and accuracy of release survey instrumentation. The inspectors also reviewed records of leak tests on selected sealed sources and discussed nationally tracked source transactions with licensee staff.

Problem Identification and Resolution: Nuclear Condition Reports (NCR)s associated with radiological hazard assessment and control were reviewed and assessed. The inspectors evaluated the licensees ability to identify and resolve the issues in accordance with procedure CAP-NGGC-0200, Condition Identification and Screening Process, Rev. 34. The inspectors also evaluated the scope of the licensees internal audit program and reviewed recent assessment results.

Radiation protection activities were evaluated against the requirements of Updated Final Safety Analysis Report (UFSAR) Section 12; Technical Specifications (TS) Sections 5.4 and 5.7; 10 CFR Parts 19 and 20; and approved licensee procedures. Licensee programs for monitoring materials and personnel released from the RCA were evaluated against 10 CFR Part 20 and IE Circular 81-07, Control of Radioactively Contaminated Material. Documents reviewed are listed in Sections 2RS1, 2RS2, 2RS3, and 2RS5 of the report Attachment.

b. Findings

No findings were identified.

2RS2 Occupational As Low As Reasonably Achievable (ALARA) Planning and Controls

a. Inspection Scope

Radiological Work Planning: The inspectors reviewed a number of ALARA Work Plans (AWPs) associated with the current RO-27 refueling outage. The AWPs were reviewed with respect to activity evaluation, exposure estimates, exposure mitigation requirements, incorporation of lessons learned, and reasonableness of dose goals. For work activities associated with RO-27, the inspectors reviewed tracked dose-to-date on select jobs, comparing estimates with actual dose received, and observed development of selected in-progress reviews. AWPs assessed included work on air operated valves, scaffolding, shielding, decontamination, reactor disassembly to include removal of the core barrel, and check valve inspections to include radiography.

Verification of Dose Estimates and Exposure Tracking Systems: For the ALARA work plans reviewed, the inspectors evaluated the assumptions and basis for the dose rate and man-hour estimates. The inspectors discussed with ALARA staff the means by which wrench-hours were derived from the work order hours provided by craft supervision to ALARA staff. The inspectors reviewed licensee methodology for tracking and trending doses for ongoing work activities. The inspectors observed discussions between ALARA staff and job owners related to in-progress reviews and re-planning work when dose/hour budgets were exceeded or when emergent work and/or changes in scope were encountered. The inspectors attended an ALARA committee meeting in which additional dose was requested for scaffold work due to increased scope.

Source Term Reduction and Control: The inspectors evaluated the historical trends and current status of the plant source term through review of records. Through interviews and document review, the inspectors assessed the licensees current activities and future plans related to source term reduction, including shutdown chemistry and response to problems with fuel in previous cycles.

Radiation Worker Performance: The inspectors observed radiation worker performance through direct observation, via remote camera monitoring, and via telemetry. Jobs observed associated with the RO-27 refueling outage included refueling cavity leak detection work, scaffolding and shielding work, measurements on upper internals lift rig, and fuel movement. Radiation worker performance was also evaluated under IP 71124.01.

Problem Identification & Resolution: Licensee Corrective Action Program (CAP)documents associated with ALARA planning and controls were reviewed and assessed.

This included review of selected NCRs, self-assessments, and audits. The inspectors evaluated the licensees ability to identify, characterize, prioritize, and resolve the identified issues in accordance with procedure CAP-NGGC-0200, Condition Identification and Screening Process, Rev. 34.

Radiation protection activities were evaluated against the requirements of UFSAR Section 12; 10 CFR Parts 19 and 20; and approved licensee procedures. Records reviewed are listed in Sections 2RS1 and 2RS2 of the report Attachment.

b. Findings

No findings were identified.

2RS3 In-Plant Airborne Radioactivity Control and Mitigation

a. Inspection Scope

Engineering Controls: The inspectors reviewed the use of temporary and permanent engineering controls to mitigate airborne radioactivity during the RO-27 refueling outage.

The inspectors observed the use of portable air filtration units for work in contaminated areas of the containment building and reviewed filtration unit testing certificates. The inspectors evaluated the effectiveness of continuous air monitors and air samplers placed in work area breathing zones to provide indication of increasing airborne levels.

Respiratory Protection Equipment: The inspectors reviewed the use of respiratory protection devices to limit the intake of radioactive material. This included review of devices used for routine tasks and devices stored for use in emergency situations. The inspectors reviewed ALARA evaluations for the use of respiratory protection devices during work in the lower cavity near the transfer canal. Selected Self-Contained Breathing Apparatus (SCBA) units and negative pressure respirators (NPRs) staged for routine and emergency use in the Main Control Room and other locations were inspected for material condition, SCBA bottle air pressure, number of units, and number of spare masks and air bottles available. The inspectors reviewed maintenance records for selected SCBA units for the past two years and evaluated SCBA and NPR compliance with National Institute for Occupational Safety and Health certification requirements. The inspectors also reviewed records of air quality testing for supplied-air devices and SCBA bottles.

The inspectors observed the use of powered air-purifying respirators during maintenance work in the lower cavity. The inspectors discussed training for various types of respiratory protection devices with HP staff and interviewed radworkers and control room operators on use of the devices including SCBA bottle change-out and use of corrective lens inserts.

Respirator qualification records (including medical qualifications) were reviewed for several Main Control Room operators and emergency responder personnel in the Maintenance and HP departments. In addition, qualifications for individuals responsible for testing and repairing SCBA vital components were evaluated through review of training records.

Problem Identification and Resolution: NCRs associated with airborne radioactivity mitigation and respiratory protection were reviewed and assessed. The inspectors evaluated the licensees ability to identify and resolve the issues in accordance with procedure CAP-NGGC-0200, Condition Identification and Screening Process, Rev. 34.

The inspectors also reviewed recent self-assessment results.

Licensee activities associated with the use of engineering controls and respiratory protection equipment were reviewed against TS Section 5.4; 10 CFR Part 20; Regulatory Guide (RG) 8.15, Acceptable Programs for Respiratory Protection; and applicable licensee procedures. Documents reviewed during the inspection are listed in Sections 2RS1 and 2RS3 of the report Attachment.

b. Findings

No findings were identified.

2RS4 Occupational Dose Assessment

a. Inspection Scope

External Dosimetry: The inspectors reviewed National Voluntary Laboratory Accreditation Program (NVLAP) certification data (including thermoluminescent dosimeter (TLD) testing for neutron, gamma, and beta exposures) and discussed program guidance for storage, processing, and evaluation of results for active and passive personnel dosimeters currently in use. The use of EDs to assign dose in the event of abnormal or unattainable TLD results was discussed. In addition, the inspectors reviewed 4 Personnel Exposure Investigation (PEI) reports related to an ED alarm and abnormal TLD readings and evaluated licensee assessment actions.

Internal Dosimetry: The inspectors reviewed program guidance, instrument detection capabilities, and assessment results for internally deposited radionuclides. The inspectors reviewed an in vivo Whole Body Count (WBC) analysis performed in April 2010 and reviewed procedural guidance for WBCs. Capabilities for collection and analysis of special bioassay samples were evaluated and discussed with licensee staff.

Special Dosimetric Situations: The inspectors evaluated the licensees use of multi-badging, extremity dosimetry, and dosimeter relocation within non-uniform dose rate fields and discussed worker monitoring in neutron areas with licensee staff. The inspectors evaluated the use of TLDs at the Restricted Area fence surrounding the Independent Spent Fuel Storage Installation (ISFSI). The inspectors also reviewed records of monitoring for declared pregnant workers from May 2011 to January 2012 and discussed monitoring guidance with dosimetry staff. In addition, three Personnel Contamination Events (PCEs) occurring between May 2011 and January 2012 were reviewed and discussed, and the adequacy of a shallow dose assessment performed in February 2012 was evaluated.

Problem Identification and Resolution: The inspectors reviewed and discussed selected CAP documents associated with occupational dose assessment. The inspectors evaluated the licensees ability to identify and resolve the issues in accordance with procedure CAP-NGGC-0200, Condition Identification and Screening Process, Rev. 34.

The inspectors also evaluated the scope of the licensees internal audit program and reviewed recent assessment results.

Occupational dose assessment activities were evaluated against the requirements of UFSAR Section 12; TS Section 5.4; 10 CFR Parts 19 and 20; and approved licensee procedures. Records reviewed are listed in Section 2RS4 of the report Attachment.

b. Findings

No findings were identified.

2RS5 Radiation Monitoring Instrumentation

a. Inspection Scope

Radiation Monitoring Instrumentation: During tours of the reactor auxiliary building, spent fuel pool areas, and RCA exit point, the inspectors observed installed radiation detection equipment including the following instrument types: area radiation monitors (ARM), continuous air monitors, personnel contamination monitors (PCM), small article monitors (SAM), portal monitors (PM), and liquid and gaseous effluent monitors.

Setpoint methodologies for R-18, R-19, and R-37 were evaluated for correct alarm setpoint determination based on Offsite Dose Calculation Manual (ODCM) requirements.

The inspectors observed the physical location of the components, noted the material condition, and compared sensitivity ranges with UFSAR details.

In addition to equipment walk-downs, the inspectors observed functional checks and alarm set-point testing of various fixed and portable detection instruments, including SAMs, teletectors, PCMs, and PMs. Source certificates were reviewed to evaluate consistency between radionuclides used for instrument testing and actual plant source term. Inspectors also reviewed and witnessed daily performance tests of laboratory instrumentation such as gas proportional counters, high purity germanium (HPGe)detectors, scintillation counters and gross alpha and beta counters. The inspectors reviewed calibration records for selected PCMs, PMs, and SAMs located at the RCA exit. The inspectors also reviewed calibration records for instruments used to quantify effluent sample activity including HPGe detectors and liquid scintillation counters.

Calibration source documentation was reviewed for the ARM high-range calibrator and the Cs-137 source used for portable instrument checks. Calibration records were also reviewed for ARM channels R-32A and R-32B (Containment High-Range monitors), and R-14 (Plant Vent Radiation Monitor). Calibration stickers on portable survey instruments were noted during inspection of storage areas for ready-to-use equipment.

Problem Identification and Resolution: Selected licensee NCR documents associated with instrumentation were reviewed and assessed. The inspectors evaluated the licensees ability to identify, characterize, prioritize, and resolve the identified issues in accordance with procedure CAP-NGGC-0200, Condition Identification and Screening Process, Rev. 34. The inspectors also evaluated the scope of the licensees internal audit program and reviewed recent assessment results.

Operability and reliability of selected radiation detection instruments were reviewed against details documented in the following: 10 CFR Part 20; NUREG-0737, Clarification of Three Mile Island Action Plan Requirements; TS Sections 3 and 5; UFSAR Chapters 11 and 12; and applicable licensee procedures. Documents reviewed during the inspection are listed in Section 2RS5 of the report Attachment.

b. Findings

No findings were identified.

4OA1 Performance Indicator (PI) Verification

a. Inspection Scope

The inspectors verified the six PIs identified below. For each PI, the inspectors verified the accuracy of the PI data that had been previously reported to the NRC by comparing those data to the actual data, as described below. The inspectors also compared the licensees basis in reporting each data element to the PI definitions and guidance contained in NEI 99-02, Regulatory Assessment Performance Indicator Guideline. In addition, the inspectors interviewed licensee personnel associated with collecting, evaluating, and distributing these data.

Mitigating Systems Cornerstone

• Mitigating Systems Performance Index, Residual Heat Removal System

• Mitigating Systems Performance Index, Cooling Water Systems For the period from the 1st quarter of 2011 through the 4th quarter of 2011 the inspectors reviewed Licensee Event Reports (LERs), records of inoperable equipment, and Maintenance Rule records to verify that the licensee had accurately accounted for unavailability hours that the subject systems had experienced during the subject period.

The inspectors also reviewed the number of hours those systems were required to be available and the licensees basis for identifying unavailability hours.

Barrier Integrity Cornerstone

• For the Reactor Coolant System Specific Activity PI, the inspectors observed sampling and analysis of reactor coolant system samples, and compared the reported performance indicator data with records developed by the licensee while analyzing previous samples, for the period from the 1st quarter of 2011 through the 4th quarter of 2011.

• For the Reactor Coolant System Leakage PI, the inspectors reviewed records of daily measures of RCS identified leakage, for the period from the 1st quarter of 2011 through the 4th quarter of 2011.

Occupational Radiation Safety Cornerstone

• The inspectors reviewed the Occupational Exposure Control Effectiveness PI results for the Occupational Radiation Safety Cornerstone from May, 2011 through January, 2012. For the assessment period, the inspectors reviewed ED alarm logs and selected NCRs related to controls for exposure significant areas. Documents reviewed are listed in section 4OA1 of the report Attachment.

Public Radiation Safety Cornerstone

• The inspectors reviewed the Radiological Control Effluent Release Occurrences PI results for the Public Radiation Safety Cornerstone from May, 2011 through January, 2012. For the assessment period, the inspectors reviewed cumulative and projected doses to the public contained in liquid and gaseous release permits and NCRs related to Radiological Effluent Technical Specifications/ODCM issues. Documents reviewed are listed in section 4OA1 of the report Attachment.

b. Findings

No findings were identified.

4OA2 Identification and Resolution of Problems

.1 Routine Review of ARs

To aid in the identification of repetitive equipment failures or specific human performance issues for followup, the inspectors performed frequent screenings of items entered into the CAP. The review was accomplished by reviewing daily AR reports.

.2 Annual Sample Review

a. Inspection Scope

The inspectors selected several ARs associated, with the 2011 NRC 95002 Supplemental Inspection, for detailed review. This detailed review represents a single sample of IP 71152. The ARs reviewed are listed in the Attachment. The inspectors reviewed the associated condition reports to verify:

• complete and accurate identification of the problem in a timely manner;

• evaluation and disposition of performance issues;

• evaluation and disposition of operability and reportability issues;

• consideration of extent of condition, generic implications, common cause, and previous occurrences;

• appropriate classification and prioritization of the problem;

• identification of root and contributing causes of the problem;

• identification of corrective actions which were appropriately focused to correct the problem; and

• completion of corrective actions in a timely manner.

The inspectors also reviewed these ARs to verify compliance with the requirements of the CAP as delineated in Procedure CAP-NGGC-0200, Corrective Action Program, and 10 CFR 50, Appendix B. Documents reviewed are listed in the Attachment.

• 519774, Non-Conformance Inappropriately Closed Due to Manipulated Route List

• 524688, Activity Closed in Progress Reporter That was Not Performed

b. Observations and Findings

No findings were identified.

4OA3 Event Follow-up

.1 Failure of the B Steam Generator Feed Regulating Valve resulted in a Reactor Trip

a. Inspection Scope

Following the reactor trip that occurred on March 28, 2012, the inspectors responded to the control room and evaluated the status of mitigating systems and fission product barriers, equipment and personnel performance, and related plant management decisions to assist NRC management in making an informed evaluation of plant conditions. The inspectors also reviewed post-trip activities to verify that the licensee identified and resolved event-related issues prior to restarting the plant. Documents reviewed are listed in the Attachment.

b. Findings

No findings were identified.

.2 Alert Declared for Inadvertent Release of Halon in the Emergency Bus Room E1/E2

a. Inspection Scope

Following the Alert declaration on December 23, 2011, for the release of a toxic gas in a vital area, the inspectors responded to the control room and evaluated the status of mitigating systems and fission product barriers, equipment and personnel performance, and related plant management decisions to assist NRC management in making an informed evaluation of plant conditions. The inspectors reviewed the licensees compensatory measures for the loss of fire suppression in the E1/E2 Emergency Bus Room and verified that the licensee terminated the event in accordance with the site emergency preparedness procedure. The inspectors completed the event review in the first quarter of 2012. Documents reviewed are listed in the Attachment.

b. Findings

No findings were identified.

.3 Unusual Event Declared for a Fire in the Containment Polar Crane

a. Inspection Scope

On January 23, 2011, the inspectors responded to the control room, following a Notice of Unusual Event declaration, for a fire in an electrical cabinet in the containment polar crane that could not be confirmed to be extinguished within 15 minutes. The inspectors evaluated the status of mitigating systems and fission product barriers, equipment and personnel performance, and related plant management decisions to assist NRC management in making an informed evaluation of plant conditions. The inspectors verified that the licensee terminated the event in accordance with the site emergency preparedness procedure. Documents reviewed are listed in the Attachment.

b. Findings

No findings were identified.

4OA5 Other Activities

.1 Quarterly Resident Inspector Observations of Security Personnel and Activities

a. Inspection Scope

During the inspection period, the inspectors observed Security force personnel and activities to ensure that the activities were consistent with licensee security procedures and regulatory requirements relating to nuclear plant security. These observations took place during both normal and off-normal plant working hours.

These quarterly resident inspector observations of security force personnel and activities did not constitute any additional inspection samples. Rather, they were considered an integral part of the inspectors normal plant status review and inspection activities.

b. Findings

No findings were indentified.

4OA6 Meetings, Including Exit

On April 12, 2012, the resident inspectors presented the inspection results to Mr. Tom Cosgrove and other members of his staff. The inspectors confirmed that proprietary information was not provided or examined during the inspection.

ATTACHMENT:

SUPPLEMENTAL INFORMATION

KEY POINTS OF CONTACT

Licensee personnel

D. Barker, Nuclear Oversight Manager

T. Cosgrove, Plant General Manager

H. Curry, Training Manager

R. Gideon, Vice President

R. Hightower, Licensing Supervisor

K. Holbrook, Operations Manager

B. Houston, Radiation Protection Superintendent

B. Matherne, Outage & Scheduling Manager

L. Martin, Engineering Manager

C. Morris, Maintenance Manager

J. Rotchford, Environmental & Chemistry Superintendent

S. Wheeler, Manager, Support Services - Nuclear

NRC personnel

R. Musser, Chief, Reactor Projects Branch 4

LIST OF ITEMS OPENED, CLOSED, AND DISCUSSED

Opened &

Closed

05000261/2012002-01 NCV Failure to Implement Technical Specification Action Requirements Regarding B Battery Inoperability (Section 1R15)

05000261/2012002-02 NCV Inadequate Design Change resulted in Interference and Inoperability of Containment Water Level Indication (Section 1R15)

05000261/2012002-03 FIN Low Temperature Overpressure System Rendered Inoperable For Operational Convenience (Section 1R20.3)