IR 05000321/2011003

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IR 05000321-11-003 & 05000366-11-003, on 04/01/2011 - 06 /30/2011, Edwin I. Hatch Nuclear Plant, Units 1 and 2, Problem Identification and Resolution, Other Activities
ML112150522
Person / Time
Site: Hatch  Southern Nuclear icon.png
Issue date: 08/03/2011
From: Scott Shaeffer
NRC/RGN-II/DRP/RPB2
To: Madison D
Southern Nuclear Operating Co
References
IR-11-003
Download: ML112150522 (48)
v • d • e


Text

UNITED STATES ust 3, 2011

SUBJECT:

EDWIN I. HATCH NUCLEAR PLANT - NRC INTEGRATED INSPECTION REPORT 05000321/2011003 AND 05000366/2011003

Dear Mr. Madison:

On June 30, 2011, U. S. Nuclear Regulatory Commission (NRC) completed an inspection at your Edwin I. Hatch Nuclear Plant, Units 1 and 2. The enclosed integrated inspection report documents the inspection results, which were discussed on July 25, 2011, with you and other members of your staff.

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

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

This report documents two NRC identified and one self-revealing finding of very low safety significance (Green). Each of these findings were determined to involve violations of NRC requirements. However, because of the very low safety significance and because they are entered into your corrective action program (CAP), the NRC is treating these findings as non-cited violations (NCV) consistent with the NRCs Enforcement Policy. If you contest 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 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 the Hatch facility.

SNC 2 In accordance with 10 CFR 2.390 of the NRCs Rules of Practice, a copy of this letter, its enclosures, 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 the NRCs document 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/

Scott M. Shaeffer, Chief Reactor Projects Branch 2 Division of Reactor Projects Docket Nos.: 50-321, 50-366 License Nos.: DPR-57 and NPF-5

Enclosures:

Inspection Report 05000321/2011003, 05000366/2011003 w/Attachment: Supplemental Information

REGION II==

Docket Nos.: 50-321, 50-366 License Nos.: DPR-57 and NPF-5 Report Nos.: 05000321/2011003 and 05000366/2011003 Licensee: Southern Nuclear Operating Company, Inc.

Facility: Edwin I. Hatch Nuclear Plant Location: Baxley, Georgia 31513 Dates: April 1 - June 30, 2011 Inspectors: E. Morris, Senior Resident Inspector D. Hardage, Resident Inspector T. Chandler, Resident Inspector (Vogtle)

B. Collins, Reactor Inspector (1R08)

A. Nielsen, Senior Health Physicist (2RS2, 4OA1)

C. Dykes, Health Physicist (2RS4)

R. Kellner, Health Physicist (2RS1, 2RS3, 4OA1, 4OA5)

J. Rivera, Health Physicist (2RS8)

R. Bernhard, Senior Reactor Analyst Approved by: Scott M. Shaeffer, Chief Reactor Projects Branch 2 Division of Reactor Projects Enclosure

SUMMARY OF FINDINGS

IR 05000321/2011003, 05000366/2011003; 04/01/2011-06 /30/2011; Edwin I. Hatch Nuclear

Plant, Units 1 and 2, Problem Identification and Resolution, Other Activities.

The report covered a three-month period of inspection by one senior resident inspector, two resident inspectors, one reactor inspector, one senior health physicist, one senior reactor analyst, and three health physicists. Two NRC identified and one self-revealing NCV were identified and documented in this report. The significance of most findings is indicated by their color (greater than Green, or Green, White, Yellow, Red); the significance was determined using Inspection Manual Chapter (IMC) 0609, Significance Determination Process (SDP); the cross-cutting aspect was determined using IMC 0310, Components Within The Cross-Cutting Areas; and that 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.

A self-revealing NCV of 10 CFR 50, Appendix B, Criterion XVI, Corrective Actions, was identified for failure to promptly identify and take corrective actions to ensure Bussmann fuses identified by the Part 21 notification 2005-37, were removed from use in safety related applications. Corrective actions taken include replacing the KTN-R 10 amp fuses on the 1B emergency diesel generator with fuses manufactured after 1991, placing a hold on all KWN-R and KTN-R fuses size 30 amps below manufactured between 1987 and 1991, and replacement of these fuses with new KWN-R and KTN-R fuses with a date code 2009 or newer. This violation has been entered into the licensees corrective action program as condition report (CR) 2010116039.

Failure to promptly identify and take corrective actions to ensure Bussmann fuses identified by the Part 21 notification 2005-37 were removed from use in safety related applications is 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, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. Specifically, on December 23, 2010, the Hatch 1B emergency diesel generator #3 stop circuitry operability light was discovered not illuminated on panel 1R43-P003B. Without power to this circuitry the 1B emergency diesel generator is inoperable and unavailable to provide its required safety function.

The significance of this finding was screened using IMC 0609 Attachment 4, table 4a. The risk significance screening required a Phase 3 analysis, because the finding screened as potentially risk significant due to a seismic initiating event. The regional senior reactor analyst (SRA) performed a Phase 3 analysis for the finding. The analysis included two parts, the first covering the time period of total inoperability of the fuse; and the second covering the exposure time from when the non qualified fuses were installed until they were replaced, when they were subject to potential seismic failure. Calculations were performed using the NRCs plant specific risk models. The short exposure time for the first analysis, and the low likelihood of a seismic event at the plant for the second analysis, caused the combined result to be a very low risk condition. The finding was determined to be Green in the SDP.

Because the performance deficiency occurred in 2006 and is outside the past three years, no cross-cutting aspect is assigned. (Section 4OA2.2)

Green.

An NRC-identified NCV of 10 CFR 50 Appendix B, Criterion V, Instructions,

Procedures, and Drawings, was identified for failure to establish adequate procedures that address potential adverse system interactions when opening safety relief valves (SRV) without power. Immediate corrective actions taken by the licensee include changing procedure 31EO-TSG-001-0, Attachment 6, SRV Actuation Without Power to Allow Injection with Portable Pump, to ensure the SRV control circuits are isolated electrically from the direct current (DC) busses prior to installing the portable DC power supply. This violation has been entered into the licensees corrective action program as CR 2011106008.

Failure to address potential adverse system interactions when developing procedures affecting quality is a performance deficiency. This performance deficiency is more than minor because it is associated with the Procedural Quality attribute of the Mitigating Systems Cornerstone and adversely affects the cornerstone objective to ensure the availability, reliability, and capability of the safety relief valves to reduce reactor pressure in response to a loss of alternating current (AC) and DC power event. Because this finding is associated with B.5.b mitigation strategies, the finding was assessed using MC 0609 Appendix L, B.5.b Significance Determination Process, Table 2. The inspectors performed an initial screening and determined the finding did not meet the criteria listed within Table 2 for greater than Green significance therefore this finding was screened as

Green.

Because the mitigating strategy was developed and implemented in site procedures in 2007, the performance deficiency occurred outside the past three years and no cross-cutting aspect is assigned. (Section 4OA5.3)

Green.

An NRC-identified NCV of 10 CFR 50, Appendix B, Criterion V. Instructions,

Procedures, and Drawings, was identified for failure to establish adequate procedures that address the anticipated environmental conditions when operating containment vents without power. Immediate corrective actions taken by the licensee include changing procedure 34AB-R22-003-1/2, Station Blackout, to perform preliminary actions in the torus area before high containment pressure and temperature conditions require venting. This change is intended to allow required torus area entries to be performed prior to reaching high temperature conditions in the area. This violation has been entered into the licensees corrective action program as CR 2011105966 and CR 2011106007.

Failure to address the anticipated environmental conditions when developing procedures affecting quality is a performance deficiency. This performance deficiency is more than minor because it is associated with the Procedural Quality attribute of the Mitigating Systems Cornerstone and adversely affects the cornerstone objective to ensure the availability, reliability, and capability of the containment vent valves to allow reliable pressure control of primary containment in response to a loss of AC and DC power event. This finding was assessed using MC 0609 Appendix L, B.5.b Significance Determination Process, Table 2. The inspectors performed an initial screening and determined the finding did not meet the criteria listed within Table 2 for greater than Green significance therefore this finding was screened as

Green.

Because the procedure was developed and implemented in 2005, the performance deficiency occurred outside the past three years and no cross-cutting aspect is assigned. (Section 4OA5.3)

REPORT DETAILS

Summary of Plant Status

Unit 1 began the inspection period at or near 100% Rated Thermal Power (RTP). The unit operated at or near 100% RTP during this inspection period.

Unit 2 began the inspection period shutdown for a scheduled refueling outage. On May 1, the unit was restarted. On May 5, the unit was shutdown to make repairs to the 2B reactor feed pump. On May 6, the unit was restarted and reached 97% RTP on May 16.

On May 17, unit power was reduced to 87% due to 2A safety relief valve pilot valve leakage. On May 27, the unit was shutdown to Mode 4 Cold Shutdown to replace the 2A safety relief valve pilot. On May 31, the unit was restarted and achieved 100% RTP on June 5. The unit operated the remainder of the inspection period at or near 100%

RTP.

REACTOR SAFETY

Cornerstones: Initiating Events, Mitigating Systems, and Barrier Integrity

1R01 Adverse Weather

.1 Readiness of Offsite and Alternate AC Power Systems

a. Inspection Scope

The inspectors verified that plant features and procedures for operation and continued availability of offsite and alternate AC power systems during adverse weather were appropriate. The inspectors reviewed the licensees procedures affecting these areas and the communications protocols between the transmission system operator (TSO) and the plant to verify that the appropriate information was being exchanged when issues arose that could impact the offsite power system. Aspects considered in the inspectors review included:

  • The coordination between the TSO and the plant during off-normal or emergency events;
  • The explanations for the events;
  • The estimates of when the offsite power system would be returned to a normal state; and
  • The notifications from the TSO to the plant when the offsite power system was returned to normal.

The inspectors also verified that plant procedures addressed measures to monitor and maintain availability and reliability of both the offsite AC power system and the onsite alternate AC power system prior to or during adverse weather conditions. Specifically, the inspectors verified that the procedures addressed the following:

  • The actions to be taken when notified by the TSO that the post-trip voltage of the offsite power system at the plant would not be acceptable to assure the continued operation of the safety-related loads without transferring to the onsite power supply;
  • The compensatory actions identified to be performed if it would not be possible to predict the post-trip voltage at the plant for the current grid conditions;
  • A re-assessment of plant risk based on maintenance activities which could affect grid reliability, or the ability of the transmission system to provide offsite power; and
  • The communications between the plant and the TSO when changes at the plant could impact the transmission system, or when the capability of the transmission system to provide adequate offsite power was challenged.

Documents reviewed are listed in the Attachment. The inspectors also reviewed corrective action program items to verify that the licensee was identifying adverse weather issues at an appropriate threshold and entering them into their corrective action program in accordance with station corrective action procedures.

b. Findings

No findings were identified.

.2 Readiness to Cope With External Flooding

a. Inspection Scope

External Flooding. The inspectors performed a review of licensee readiness to cope with external flooding. The inspectors performed walkdowns of the systems listed below to verify that equipment was in place to mitigate the potential impacts from external flooding. The inspectors reviewed licensee procedure 34AB-Y22-002-0, Naturally Occurring Phenomena, to verify guidance existed to cope with an external flood.

Additionally, the inspectors reviewed licensee documentation that shows design flood levels for area containing safety-related equipment. Documents reviewed are listed in the Attachment.

  • Unit 1 & 2 Intake Area
  • Independent Spent Fuel Storage Area

b. Findings

No findings were identified.

1R04 Equipment Alignment

a. Inspection Scope

Partial Walkdowns. The inspectors performed partial walkdowns of the following three systems when the opposite train was removed from service, a remaining operable system/train with high risk significance for the plant configuration exists, or a system/train that was recently realigned following an extended system outage or a risk significant single train system exists. The inspectors checked system valve positions, electrical breaker positions, and operating switch positions to evaluate the operability of the opposite trains or components by comparing the position listed in the system operating procedure to the actual position. Documents reviewed are listed in the

.

  • Unit 2 B train of core spray during mode 5 operations with all low pressure core injection and A core spray out of service for maintenance, April 5
  • Unit 1 startup transformer 1D while the startup transformer 1C was out of service for maintenance, April 13

b. Findings

No findings were identified.

1R05 Fire Protection

a. Inspection Scope

Fire Area Tours. The inspectors toured the following five risk significant plant areas to assess the material condition of the fire protection and detection equipment, verify fire protection equipment was not obstructed and that transient combustibles were properly controlled. The inspectors reviewed the Fire Hazards Analysis drawings to verify that the necessary fire fighting equipment, such as fire extinguishers, hose stations, ladders, and communications equipment, was in place. Documents reviewed are listed in the

.

  • Unit 1, Torus Area, fire area 1203A & 1205A
  • Unit 2, Torus Area, fire area 2203A & 2205A
  • Unit 1 & 2, Control Room, fire area 0024C, D
  • Unit 1, Reactor Building 158 Working Floor South, fire area 1203K

b. Findings

No findings were identified.

1R08 Inservice Inspection Activities

Main article: IP 71111.08P

From April 4, 2011, through April 8, 2011, the inspectors conducted a review of the implementation of the licensees Inservice Inspection (ISI) Program for monitoring degradation of the reactor coolant system, emergency feedwater systems, risk-significant piping and components and containment systems.

The inspections described in Sections 1R08.1 and 1R08.2 below constituted one inservice inspection sample as defined in Inspection Procedure 71111.08-05.

.1 Piping Systems ISI

a. Inspection Scope

The inspectors evaluated the following non-destructive examinations mandated by the ASME Code Section XI, to verify compliance with the ASME Code Section XI, and Section V requirements, and if any indications and defects were detected, to evaluate if they were dispositioned in accordance with the ASME Code or an NRC-approved alternative requirement.

Direct Observation

  • Magnetic Particle (MT) examination of weld 2B11/2C-6, ASME Class 1, Category B-K, Reactor Coolant System, Reactor Vessel-to-Skirt weld - Direct Observation During non-destructive surface and volumetric examinations performed since the previous refueling outage, the licensee did not identify any recordable indications that were accepted for continued service. Therefore, no NRC review was completed for this inspection procedure attribute.

The inspectors reviewed documentation for the following pressure boundary welds completed for risk-significant systems during the outage to evaluate if the licensee applied the preservice non-destructive examinations and acceptance criteria required by ASME Code Section XI. In addition, the inspectors reviewed the welding procedure specification, welder qualifications, welding material certification 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.

b. Findings

No findings were identified.

.2 Identification and Resolution of Problems

a. Inspection Scope

The inspectors performed a review of ISI-related problems entered into the licensees corrective action program and conducted interviews with licensee staff to determine if;

  • The licensee had established an appropriate threshold for identifying ISI-related problems;
  • The licensee had performed a root cause (if applicable) and taken appropriate corrective actions; and
  • The licensee had evaluated operating experience and industry generic issues related to ISI and pressure boundary integrity.

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

b. Findings

No findings were identified.

1R11 Licensed Operator Requalification

a. Inspection Scope

Resident Quarterly Observation On May 16 the inspectors observed the performance of a licensee simulator scenario, which included loss of 600 volt 2D, plant service water strainer clog, loss of area ventilation, and loss of coolant accident. The inspectors reviewed the proper classification in accordance with the Emergency Plan and licensee procedures 10-AC-MGR-019-0, Procedure Use and Adherence, and DI-OPS-59-0896, Operations Management Expectations, to verify formality of communication, procedure usage, alarm response, control board manipulations, group dynamics, and supervisory oversight. The inspectors attended the post-exercise critique of operator performance to assess if the licensee identified performance issues were comparable to those identified by the inspectors. In addition, the inspectors reviewed the critique results from previous training sessions to assess performance improvement.

b. Findings

No findings were identified.

1R12 Maintenance Effectiveness

a. Inspection Scope

The inspectors reviewed the following two samples associated with structures, systems, and components to assess the licensees implementation of the Maintenance Rule (10 CFR 50.65) with respect to the characterization of failures and the appropriateness of the associated (a)

(1) or (a)
(2) classification. The inspectors reviewed operator logs, associated CRs, Maintenance Work Orders (WO), and the licensees procedures for implementing the Maintenance Rule to determine if equipment failures were being identified, properly assessed, and corrective actions established to return the equipment to a satisfactory condition. Documents reviewed are listed in the Attachment.
  • Unit 1 and 2 service, instrument air system, P51, P52

b. Findings

No findings were identified.

1R13 Maintenance Risk Assessments and Emergent Work Evaluation

a. Inspection Scope

The inspectors reviewed the following work activities listed below to verify that risk assessments were performed prior to components being removed from service. The inspectors reviewed the risk assessment and risk management controls implemented for these activities to verify they were completed in accordance with licensee procedure 90AC-OAM-002-0, Scheduling Maintenance, and 10 CFR 50.65 (a)(4). For emergent work, the inspectors assessed whether any increase in risk was promptly assessed and that appropriate risk management actions were implemented.

  • April 5 and 6 - Unit 2 outage safety assessments during Mode 5 operations.
  • April 19 - April 22 including the following activities on Unit 1 emergency diesel generator testing, station service battery testing, undervoltage relay testing on the 1E, 1F, 1G safety buses, reactor protection system testing; and outage activities on Unit 2.
  • May 2 - May 6 including Unit 2 startup from refueling outage and switchyard activities by Georgia Power Company.
  • May 21 - May 27 including unit 1 reactor high water level functional test and calibration, 2C emergency diesel generator loss of coolant accident timer test, 1B turbine building chiller repairs, 1E11-F217B repairs, 1F battery charger maintenance, hot line tag on the Vidalia line, and pilot valve leakage on 2A SRV.
  • June 4 - June 10, including 1A standby liquid control pump outage, 1F emergency bus undervoltage relay functional test and calibration, switchyard hot line tag, 2A battery charger maintenance, and 2B reactor building component cooling water heat exchanger cleaning.

b. Findings

No findings were identified.

1R15 Operability Evaluations

a. Inspection Scope

The inspectors reviewed the following six operability evaluations and compared the evaluations to the system requirements identified in the Technical Specifications (TS)and the Final Safety Analysis Report (FSAR) to ensure operability was adequately assessed and the system or component remained available to perform its intended function. Also, the inspectors assessed the adequacy of compensatory measures implemented as a result of the condition. Documents reviewed are listed in the

.

  • Unit 2 core spray jockey pump discovered with no visible oil level, CR 2011106192
  • Standby plant service water discharge pressure at zero pressure, CR 2011105437
  • High drywell pressure signal bypass logic relay exceeded its maximum time, CR 2011105586
  • C main control room air conditioner tripped on high compressor discharge pressure, CR 2011106885

b. Findings

No findings were identified.

1R18 Plant Modifications

a. Inspection Scope

The inspectors reviewed the following plant permanent and temporary modifications to ensure that safety functions of important safety systems have not been affected. Also, the inspectors verified that the design bases, licensing bases and performance capability of risk significant structures, systems and components have not been degraded through modifications. The inspectors verified that any modifications performed during increased risk-significant configurations did not place the plant in an unsafe condition. Documents reviewed are listed in the Attachment.

.1 Permanent Modification:

b. Findings

No findings were identified.

1R19 Post Maintenance Testing

a. Inspection Scope

For the following six post maintenance tests, the inspectors reviewed the test scope to verify the test demonstrated the work performed was completed correctly and the affected equipment was functional and operable in accordance with TS requirements.

The inspectors also reviewed equipment status and alignment to verify the system or component was available to perform the required safety function. Documents reviewed are listed in the Attachment.

  • WO 1110709002, C main control room air conditioner tripped on high compressor discharge pressure, May 19, 2011

b. Findings

No findings were identified.

1R20 Refueling and Other Outage Activities

a. Inspection Scope

The inspectors performed the inspection activities described below for the Unit 2 refueling outage that began on March 29 through May 2 and for a Unit 2 maintenance outage May 27 through May 31. The inspectors confirmed that, when the licensee removed equipment from service, the licensee maintained defense-in-depth commensurate with the outage risk control plan for key safety functions and applicable TS and that configuration changes due to emergent work and unexpected conditions were controlled in accordance with the outage risk control plan. Documents reviewed are listed in the Attachment. Inspection activities included:

  • Reviewed reactor coolant system pressure, level and temperature instruments to verify that the instruments provided accurate indication and that allowances were made for instrumentation errors.
  • Verified that outage work did not impact the operation of the spent fuel cooling system.
  • Reviewed the status and configuration of electrical systems to verify that those systems met technical specification requirements and the licensees outage risk control plan.
  • Observed decay heat removal parameters to verify that the system was properly functioning and providing cooling to the core.
  • Reviewed system alignments to verify that the flow paths, configurations and alternative means for inventory addition were consistent with the outage risk plan.
  • Reviewed selected control room operations to verify that the licensee was controlling reactivity in accordance with the technical specifications.
  • Observed the licensees control of containment penetrations to verify that the requirements of the technical specifications were met.
  • Reviewed the licensees plans for changing plant configuration to verify that technical specifications, license conditions and other requirements, commitments and administrative procedure prerequisites were met prior to changing plant configuration.
  • Inspection of drywell and torus containment for degraded conditions prior to reactor startup.
  • Observed portions of reactor startup and plant heatup

b. Findings

No findings were identified.

1R22 Surveillance Testing

a. Inspection Scope

The inspectors reviewed six licensee surveillance test procedures and either witnessed the test or reviewed test records to determine if the scope of the test adequately demonstrated the affected equipment was operable. The inspectors reviewed these activities to assess for preconditioning of equipment, procedure adherence, and equipment alignment following completion of the surveillance. The inspectors reviewed licensee procedure NMP-GM-005-GL03, Human Performance Tools, and attended selected briefings to determine if procedure requirements were met. Documents reviewed are listed in the Attachment.

Surveillance Tests

  • 34SV-E51-002-1, [Reactor Core Isolation Cooling] Pump Operability In-Service Test
  • 34SV-R43-010-0, Diesel Generator Fuel Oil Transfer Pump Surveillance Test

b. Findings

No findings were identified.

Cornerstone: Emergency Preparedness

1EP6 Drill Evaluation

a. Inspection Scope

The inspectors observed the following emergency plan evolution. The inspectors observed licensee activities in the simulator and Technical Support Center to verify implementation of licensee procedure 10AC-MGR-006-0, Hatch Emergency Plan. The inspectors reviewed the classification of the simulated events and the development of protective action recommendations to verify these activities were conducted in accordance with licensee procedure NMP-EP-110, Emergency Classification Determination and Initial Actions, and NMP-EP-112, Protective Action Recommendations. The inspectors also reviewed licensee procedure NMP-EP-111, Emergency Notifications, to verify the proper offsite notifications were made. The inspectors attended the post-exercise critique to assess the licensees effectiveness in identifying areas of improvement. Documents reviewed are listed in the Attachment.

b. Findings

No findings were identified.

RADIATION SAFETY

(RS)

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 Unit 2 (U2) drywell and reactor building, Unit 1 (U1) and U2 control and turbine buildings, 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, hot 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. The inspectors also walked down the Independent Spent Fuel Storage Installation (ISFSI)and independently measured radiation dose rates or directly observed conduct of licensee radiation and contamination surveys.

Hazard Control and Work Practices The inspectors evaluated access barrier effectiveness for selected U1 and U2 Locked High Radiation Area (LHRA) and Very High Radiation Area (VHRA) locations. Changes to procedural guidance for LHRA and 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 U2 Refueling Outage 21 (2R21) tasks including safety relief valve, N2G weld overlay activities, reactor vessel disassembly/assembly, work in reactor building HRAs, and radwaste processing and storage. 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 safety relief valve work, N2G weld overlay activities, and condenser hotwell activities. ED alarm logs were reviewed and worker response to dose and dose rate alarms during selected work activities was evaluated. For HRA tasks involving significant dose rate gradients, e.g.

safety relief valve and condenser hotwell activities, the inspectors evaluated the use and placement of whole body and extremity dosimetry to monitor worker exposure.

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 CFR Part 61 results for the Dry Active Waste (DAW)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 CRs 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 NMP-GM-002, Corrective Action Program, Ver. 11 and NMP-GM-002-001, Corrective Action Program Instructions, Ver. 21. 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 FSAR Section 12; 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 Section 2RS1 of the Attachment.

b. Findings

No findings were identified.

2RS2 As Low As Reasonably Achievable (ALARA)

a. Inspection Scope

Work Planning and Exposure Tracking The inspectors reviewed planned work activities and their collective exposure estimates for the current 2R21 outage. ALARA planning packages were reviewed for the following high collective exposure tasks: N2G nozzle weld overlay and inspection; reactor head disassembly and re-assembly; shielding installation and removal; safety relief valve maintenance; and insulation removal. For the selected tasks, the inspectors reviewed established dose goals and discussed assumptions regarding the bases for the current estimates with responsible ALARA planners. The inspectors evaluated the incorporation of exposure reduction initiatives and operating experience, including historical post-job reviews, into RWP requirements.

Day-to-day collective dose data for the selected tasks were compared with established dose estimates and evaluated against procedural criteria (trigger points) for additional ALARA review. Where applicable, changes to established estimates were discussed with ALARA planners and evaluated against work scope changes or unanticipated elevated dose rates.

Source Term Reduction and Control The inspectors reviewed the collective exposure three-year rolling average (TYRA) from 2007 - 2009 and reviewed historical collective exposure trends from 1976 - 2009. The inspectors reviewed historical dose rate trends for recirculation piping (BRAC points) and compared them to current 2R21 data. Source term reduction initiatives were reviewed and discussed with Chemistry and HP staff.

Radiation Worker Performance Radiation worker performance was observed and evaluated as part of IP 71124.01 and is documented in section 2RS1. While observing job tasks, the inspectors evaluated the use of remote technologies to reduce dose including teledosimetry and remote visual monitoring.

Problem Identification and Resolution The inspectors reviewed and discussed selected CAP documents associated with ALARA program implementation. The inspectors evaluated the licensees ability to identify and correct the issues in accordance with licensee procedure NMP-GM-002. The inspectors also evaluated the scope and frequency of the licensees self-assessment program and reviewed recent assessment results.

ALARA program activities were evaluated against the requirements of FSAR Section 12, TS Section 5.4, 10 CFR Part 20, and approved licensee procedures. Records reviewed are listed in Sections 2RS1 and 2RS2 of the 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 inside the U2 drywell, reactor building and turbine building during the 2R21 refueling outage. The inspectors observed the use of negative pressure units (NPUs) and vacuums to control contamination during safety relief valve work and reactor vessel disassembly and inspection activities and reviewed NPU testing records. The inspectors also reviewed ventilation flow, charcoal, and High Efficiency Particulate Air (HEPA) filter test records for the Main Control Room Environmental Control System. 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. In addition, plant guidance and its implementation for the monitoring of potential airborne beta-gamma and alpha-emitting radionuclides were reviewed and discussed with licensee representatives.

Respiratory Protection Equipment The inspectors reviewed the use of respiratory protection devices to limit the intake of radioactive material. This included review of program guidance for issuance and use of respiratory protection devices, discussion with responsible licensee representatives, and review of devices used for routine tasks and devices stored for use in emergency situations. The inspectors reviewed Total Effective Dose Equivalent (TEDE)-ALARA evaluations conducted for selected 2R21 outage tasks.

Selected whole-body count (WBC) routine and investigative analysis results for occupational workers were reviewed and discussed. Use of powered air purifying respirator equipment (PAPRs) was evaluated for the workers involved in Subpile [under vessel] room work and those involved in reactor head disassembly/removal activities. The inspectors toured selected onsite compressors available for supplying breathing air for

2R21 outage activities and reviewed recent air quality sampling results. Training, fit testing,

and medical qualifications for selected HP, maintenance, and support staff using respiratory protection for 2R21activities were reviewed. 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.

SCBA for Emergency Use: The inspectors reviewed the current status, operability and availability of selected SCBA equipment maintained within the technical support center, U1 and U2 control rooms, and fire brigade staging facilities. Maintenance activities for selected respiratory protective equipment, e.g., compressed gas cylinders, regulators, valves, and hose couplings, by certified vendor technicians was evaluated for selected SCBA units. Training, fit testing, and medical qualifications for selected HP, maintenance, and operations staff assigned Emergency Response Organization duties were reviewed.

For selected U1 and U2 control room operators, the inspectors discussed annual hands-on SCBA training activities including donning, doffing and functionally checking SCBA equipment and availability of corrective lens, as applicable, for on-shift personnel.

Problem Identification and Resolution: CRs associated with airborne radioactivity mitigation and respiratory protection were reviewed and assessed. The inspectors evaluated the licensees ability to identify and correct the issues in accordance with procedure NMP-GM-002 and NMP-GM-002-001. Documents reviewed are listed in section 2RS3 of the Attachment.

Licensee activities associated with the use of engineering controls and respiratory protection equipment and airborne radioactivity monitoring and controls were evaluated against details and requirements documented in FSAR Sections 11 and 12; TS Section 5.4, Procedures; 10 CFR Part 20; RG 8.15, Acceptable Programs for Respiratory Protection; and approved licensee procedures. Documents reviewed are listed in Sections 2RS1, 2RS2, and 2RS3 of the Attachment.

b. Findings

No findings were identified.

2RS4 Occupational Dose Assessment

a. Inspection Scope

External Dosimetry Inspectors reviewed and discussed the licensees National Voluntary Accreditation Program (NVLAP) certification data for accreditation years 2010-2011 and 2011-2012 for Ionizing Radiation Dosimetry. Program procedures were reviewed for processing active personnel dosimeters and onsite storage of dosimeters were discussed. Comparisons between ED and personnel dosimeter results were discussed in detail.

Internal Dosimetry Inspectors reviewed and discussed the in vivo bioassay program with the licensee. Inspectors reviewed procedures that addressed methods for determining internal or external contamination, releasing contaminated individuals, the assignment of dose and the frequency of measurements depending on the nuclides.

Inspectors reviewed and evaluated WBC records selected from February 2009 to March 2011. The licensees program for in vitro monitoring was reviewed and discussed in detail.

Special Dosimetric Situations Inspectors reviewed records for declared pregnant workers (DPWs) since January 2009 and discussed guidance for monitoring and instructing DPWs. Inspectors reviewed the licensees practices for monitoring external dose in areas of expected dose rate gradients, including the use of multi-badging and extremity dosimetry. The inspectors evaluated the licensees neutron dosimetry program and reviewed neutron surveys related with ISFSI loading and monitoring.

Problem Identification and Resolution Inspectors reviewed and discussed licensee CAP documents associated with occupational dose assessment. The inspectors evaluated the licensees ability to identify and correct the identified issues in accordance with procedure NPM-GM-002. The inspectors also discussed the scope of the licensees internal audit program and reviewed recent assessment results HP program occupational dose assessment activities were evaluated against the requirements of FSAR Section 12; TS Section 5.4; 10 CFR Parts 19 and 20; and approved licensee procedures. Records reviewed are listed in Section 2RS01, 2RS02, and 2RS04 of the Attachment.

b. Findings

No findings were identified.

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

Transportation

a. Inspection Scope

Radioactive Material Storage The inspectors walked down indoor and outdoor areas of the Waste Separation and Temporary Storage Facility building. During the walk-down, the inspectors observed the physical condition and labeling of several storage containers, and the posting of Radioactive Material Areas. The inspectors also reviewed licensees radwaste procedures for routine surveys and waste storage, in order to evaluate the impact of long-term storage.

Radioactive Waste System Walkdown, Characterization and Classification The inspectors walked down accessible sections of the liquid and solid radwaste systems, to assess material condition and conformance of equipment with system design diagrams.

This included the indoor portion of the Radwaste Building containing storage tanks, the unused equipment area, the Radwaste Control Room, and the outdoor Resin Processing Pad Areas for Units 1 and 2. The inspectors discussed the function of radwaste components with the radwaste operator. The inspectors discussed possible changes to the radwaste processing systems with radwaste staff. The processes for the dewatering of resins, spent resin tank recirculation, resin sampling, and transfer of resins from the Processing Pads to the shipping casks and temporary storage casks were discussed with the resin processing contractor.

The inspectors reviewed the 2009 Radioactive Effluent Release Report and the 2009-2010 radionuclide characterization and classification for the DAW and dewatered resin waste streams. The inspectors evaluated analyses for hard-to-detect nuclides, reviewed the use of scaling factors, and examined quality assurance comparison results between licensee waste stream characterizations and outside laboratory data. The inspectors also evaluated how changes to plant operational parameters were taken into account in waste characterization.

Shipment Preparation and Records The inspectors directly observed preparation of an intermodal shipment containing DAW in the form of scrap metal. The inspectors noted package markings and placarding, and interviewed the shipping technician regarding Department of Transportation (DOT) regulations. In addition, training records for selected individuals currently qualified to ship radioactive material were reviewed for compliance with 49 CFR Part 172 Subpart H. Six shipping records were reviewed for consistency with licensee procedures and compliance with NRC and DOT regulations.

This included review of emergency response information, waste classification, radiation survey results, information on the waste manifest, and the authorization of the receiving licensee to receive shipments.

Identification and Resolution of Problems The inspectors reviewed selected CRs in the area of radwaste/shipping, as well as the results of a self-assessment. The inspectors evaluated the licensees ability to identify and correct the issues in accordance with procedure NMP-GM-002-001.

Radioactive material and waste storage activities were reviewed against the requirements of 10 CFR Part 20. Radwaste processing activities and equipment configuration were reviewed for compliance with the licensees Process Control Program and FSAR Chapter 11. Waste stream characterization analyses were reviewed against regulations detailed in 10 CFR Part 20, 10 CFR Part 61, and guidance provided in the Branch Technical Position on Waste Classification (1983). Transportation program implementation was reviewed against regulations detailed in 10 CFR Part 20, 10 CFR Part 71 (which requires licensees to comply with DOT regulations in 49 CFR Parts 107, 171-180, and 390-397), as well as the guidance provided in NUREG-1608. Training activities were assessed against 49 CFR Part 172 Subpart H. Documents reviewed are listed in section 2RS8 of the Attachment.

b. Findings

No findings were identified.

OTHER ACTIVITIES

4OA1 Performance Indicator (PI) Verification

a. Inspection Scope

The inspectors reviewed a sample of the licensee submittals for the PIs listed below to verify the accuracy of the data reported. The PI definitions and the guidance contained in NEI 99-02, Regulatory Assessment Indicator Guideline, Rev. 6 and licensee procedure 00AC-REG-005-0, Preparation and Reporting of NRC PI Data, were used to verify procedure and reporting requirements were met.

Cornerstone: Barrier Integrity

  • Reactor Coolant System Activity The inspectors reviewed raw PI data collected April 2010 through March 2011for the Barrier Integrity indicators identified. The inspectors compared graphical representations from the most recent PI report to the raw data to verify the data was included in the report. The inspectors also examined a sampling of operations logs and procedures to verify the PI data was appropriately captured for inclusion into the PI report, and the individual PIs were calculated correctly. The inspectors observed a chemistry technician perform a sample of the reactor coolant system and a portion of the analysis in accordance with licensee procedure 64CH-SAM-025-0, Reactor Coolant Sampling and
Analysis.

Applicable licensee event reports (LERs) issued during the referenced time frame were also reviewed. Documents reviewed are listed in the

.

Occupational Radiation Safety Cornerstone The inspectors reviewed the Occupational Exposure Control Effectiveness PI results for the Occupational Radiation Safety Cornerstone from January through December 2010. For the assessment period, the inspectors reviewed ED alarm logs and selected CRs related to controls for exposure significant areas. The inspectors also reviewed licensee procedural guidance for collecting and documenting PI data. Documents reviewed are listed in sections 2RS1 and 4OA1 of the Attachment.

Public Radiation Safety Cornerstone The inspectors reviewed the Radiological Effluent Technical Specification/Offsite Dose Calculation Manual Radiological Effluent Occurrences PI results from January through December 2010. The inspectors reviewed CAP documents, effluent dose data, and licensee procedural guidance for classifying and reporting PI events. Reviewed documents are listed in Section 4OA1 of the

.

b. Findings

No findings were identified.

4OA2 Identification and Resolution of Problems

.1 Daily Screening of Corrective Action Items

As required by Inspection Procedure 71152, Identification and Resolution of Problems, and in order to help identify repetitive equipment failures or specific human performance issues for follow-up, the inspectors performed a daily screening of items entered into the licensees corrective action program. This review was accomplished by either attending daily screening meetings that briefly discussed major CRs, or accessing the licensees computerized corrective action database and reviewing each CR that was initiated.

.2 Annual Samples:

a. Inspection Scope

The inspectors performed a detailed review of the following two CRs to verify the full extent of the issues were identified, an appropriate evaluation was performed, and appropriate corrective actions were specified and prioritized. The inspectors evaluated the CR against the licensees corrective action program as delineated in licensee procedure NMP-GM-002, and 10 CFR 50, Appendix B. Documents reviewed are listed in the Attachment.

  • CR 2010113110, Delays in work activities performed during rod sequence exchanges have resulted in challenges in core management

b. Findings and Observations

Introduction:

A Green self-revealing NCV of 10 CFR 50, Appendix B, Criterion XVI, Corrective Actions, was identified for failure to promptly identify and take corrective actions to ensure Bussmann fuses identified by the Part 21 notification 2005-37, were removed from use in safety related applications.

Description:

On March 3, 2006, NRC Information Notice 2006-05, Possible Defect in Bussmannn KWN-R and KTN-R Fuses, was issued to inform licensees of a possible defect in Bussmann KWN-R and KTN-R reported to the NRC as Part 21 2005-37. The information notice states that KTN-R fuses with ratings less than or equal to 30 amps manufactured between 1987 and 1991 were potentially defective. In response to Information Notice 2006-005, the licensee initiated action item 2006202114 to procure new KTN-R fuses and replace existing KTN-R fuses currently within warehouse inventory. Actions taken under action item 2006202114 were completed in August 2006, but failed to identify all existing Part 21 KTN-R fuses within the warehouse inventory.

Specifically, KTN-R 10 amp fuses purchased in 1990 and listed at the site under stock number 67142 were not removed from warehouse stock and not replaced as directed under action item 2006202114. 10 CFR 50, Appendix B, Criterion XVI, Corrective Actions, requires in part that measures shall be established to assure that conditions adverse to quality such as defective material and equipment are promptly identified and corrected.

Subsequently, on May 18, 2010, under work order 1100323603 the licensee replaced ten KTN-R 10 amp fuses for the 1B emergency diesel generator control and indication circuitry with fuses purchased in 1990 and within the scope of the Bussmann Fuse Part 21. Approximately seven months later on December 23, 2010, the Hatch 1B emergency diesel generator #3 stop circuitry operability light was discovered not illuminated on panel 1R43-P003B due to the failure of a Bussmann KTN-R 10 amp fuse. Without power to this circuitry the 1B emergency diesel generator is inoperable and unavailable.

Specifically, because of the loss of power, the permissive in the #3 circuitry does not change state to de-energize the 1B emergency diesel generator shutdown relay; therefore, seven seconds after an initial start the diesel would trip because of its shutdown relay remaining energized. Additionally, this failure would also prevent the DC system from energizing the generator excitation control circuitry which would prevent the diesel from providing power to the emergency bus. Hatch CR 2010116039 was initiated to document and investigate this failure. The failed fuse was sent to Wyle labs for dissection and it was confirmed by Wyle labs in failure analysis report 58240R11 that the fuse failure was caused by the manufacturing soldering issues identified in the Bussmann Fuse Part 21. Corrective actions taken under CR 2010116039 included replacing the KTN-R 10 amp fuses on the 1B emergency diesel generator with fuses manufactured after 1991, placing a hold on all KWN-R and KTN-R fuses size 30 amps below manufactured between 1987 and 1991 and replacement of these fuses with new KWN-R and KTN-R fuses with a date code 2009 or newer.

Analysis:

Failure to promptly identify and take corrective actions to ensure Bussmann fuses identified by the Part 21 notification 2005-37, were removed from use in safety related applications is 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, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. Specifically, on December 23, 2010, the Hatch 1B emergency diesel generator #3 stop circuitry operability light was discovered not illuminated on panel 1R43-P003B. Without power to this circuitry the 1B emergency diesel generator is inoperable and unavailable to provide its required safety function.

The significance of this finding was screened using IMC 0609 Attachment 4, table 4a.

The risk significance screening required a Phase 3 analysis, because the finding screened as potentially risk significant due to a seismic initiating event. The regional SRA performed a Phase 3 analysis for the finding. The analysis included two parts, the first covering the time period of total inoperability of the fuse; and the second covering the exposure time from when the non qualified fuses were installed until they were replaced, when they were subject to potential seismic failure. Calculations were performed using the NRCs plant specific risk models. The short exposure time for the first analysis, and the low likelihood of a seismic event at the plant for the second analysis, caused the combined result to be a very low risk condition. The finding was determined to be Green in the SDP. Because the performance deficiency occurred in 2006 and is outside the past three years, no cross-cutting aspect is assigned.

Enforcement:

10 CFR 50, Appendix B, Criterion XVI, Corrective Actions, requires in part that measures shall be established to assure that conditions adverse to quality such as defective material and equipment are promptly identified and corrected. Contrary to the above from August 2006 to December 2010 the licensee failed to promptly identify and take corrective actions to ensure defective material identified by the Bussmann Fuse Part 21 notification 2005-37, was removed from use in safety related applications.

Specifically, KTN-R 10 amp fuses purchased in 1990 and listed at the site under stock number 67142 were not removed from warehouse stock and not replaced as directed under action item 2006202114. Immediate corrective actions taken by the licensee include replacing the KTN-R 10 amp fuses on the 1B emergency diesel generator with fuses manufactured after 1991, placing a hold on all KWN-R and KTN-R fuses size 30 amps below manufactured between 1987 and 1991, and replacement of these fuses with new KWN-R and KTN-R fuses with a date code 2009 or newer. Because this violation was of very low safety significance and it was entered into the licensees corrective actions program as CR 2010116039, this violation is being treated as an NCV, consistent with the Enforcement Policy. NCV 05000321,366/2011003-01, Failure to promptly identify and take corrective actions to ensure Bussmann fuses identified by the Part 21 notification 2005-37, were removed from use in safety related applications.

.3 Semi-Annual Trend Review

a. Inspection Scope

The inspectors performed a review of the licensees corrective action program and associated documents to identify trends which could indicate the existence of a more significant safety issue. The review was focused on repetitive equipment issues, but also considered the results of inspector daily CR screening, licensee trending efforts, and licensee human performance results. The review nominally considered the six month period of January 2011 through June 2011 although some examples extended beyond those dates when the scope of the trend warranted. The inspectors compared and contrasted their results with the results contained in the licensees quarterly trend reports. Corrective actions associated with a sample of the issues identified in the licensees trend reports were reviewed for adequacy. The inspectors also evaluated the trend reports against the requirements of the licensees corrective action program as specified in licensee procedure NMP-GM-002, and 10 CFR 50, Appendix B.

Documents reviewed are listed in the Attachment.

b. Findings and Observations

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 conducted observations of 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 identified.

.2 (Closed) Temporary Instruction (TI) 2515/179 Verification of Licensee Responses to

NRC Requirement for Inventories of Materials Tracked in the National Source Tracking System (NSTS) Pursuant to Title 10, Code of Federal Regulations, Part 20.2207 (10 CFR 20.2207)

a. Inspection Scope

The inspectors performed this TI concurrent with IP 71124.01, Radiation Hazard

Analysis.

The inspectors reviewed the licensees source inventory records and identified the sources that met the criteria for reporting to the National Source Tracking System (NSTS). The inspectors visually identified the sources contained in various calibration systems and observed the presence of the source by direct radiation measurement using a calibrated portable radiation detection survey instrument. The inspectors reviewed the physical condition of the irradiation device. The inspectors reviewed the licensees procedures for source receipt, maintenance, transfer, reporting and disposal.

The inspectors reviewed documentation that was used to report the sources to the NSTS. Documents reviewed are listed in sections 2RS1 of the Attachment.

b. Findings

No findings were identified. This completes the Region II inspection requirements.

.3 (Closed) NRC Temporary Instruction 2515/183, Follow-up to the Fukushima Daiichi

Nuclear Station Fuel Damage Event

a. Inspection Scope

The inspectors assessed the activities and actions taken by the licensee to assess its readiness to respond to an event similar to the Fukushima Daiichi nuclear plant fuel damage event. This included

(1) an assessment of the licensees capability to mitigate conditions that may result from beyond design basis events, with a particular emphasis on strategies related to the spent fuel pool, as required by NRC Security Order Section B.5.b, issued February 25, 2002, as committed to in severe accident management guidelines, and as required by 10 CFR 50.54(hh);
(2) an assessment of the licensees capability to mitigate station blackout (SBO) conditions, as required by 10 CFR 50.63, and station design bases;
(3) an assessment of the licensees capability to mitigate internal and external flooding events, as required by station design bases; and
(4) an assessment of the thoroughness of the walkdowns and inspections of important equipment needed to mitigate fire and flood events, which were performed by the licensee to identify any potential loss of function of this equipment during seismic events possible for the site.

b. Findings

Inspection Report 05000321,366/2011010 (ML111330108) documented detailed results of this inspection activity. Following issuance of the report, the inspectors conducted detailed follow-up on selected issues. The following findings were identified during this follow-up inspection:

Introduction:

A Green NRC-identified NCV of 10 CFR 50 Appendix B, Criterion V.

Instructions, Procedures, and Drawings, was identified for failure to establish adequate procedures that address potential adverse system interactions when opening safety relief valves without power.

Description:

During performance of TI-183, the inspectors questioned the ability of the licensee to perform procedure 31EO-TSG-001-0, Technical Support Guidelines, 6, SRV Actuation Without Power to Allow Injection with Portable Pump, as written. This procedure was implemented by the licensee in July 2007 and installs a portable DC power supply to locally energize and operate the safety relief valves when on site electrical power is unavailable. The procedure for operating SRVs without power is written such that the safety relief valves control circuits are not verified to be electrically isolated from the stations DC distribution system prior to installing a portable DC power supply. The portable DC power supply does not have the electrical capacity to supply power to the SRVs and to back feed the stations DC busses. Therefore if the SRVs remained electrically connected to the stations DC busses the portable DC power supply would not produce sufficient voltage to energize the SRV solenoids resulting in the SRVs failing to open. In this case the SRVs would periodically lift at their mechanical relief setpoint of 1150 +/- 34.5 psig. With the reactor pressure vessel (RPV)at this high pressure and no high pressure injection cooling available, reactor coolant inventory lost could not be made up by the low pressure portable pump. This would ultimately result in the core becoming uncovered and subsequent fuel damage. This issue was entered into the licensees corrective actions program as CR 2011106008.

The licensee was able to demonstrate to the inspectors that, although the possibility exists for the portable DC power supply to fail to open SRVs due to the backfeed condition, due to self protecting features the DC power supply would not be damaged and there is a high likelihood the licensee would be able to identify and correct the backfeed circuit prior to the core becoming uncovered.

Analysis:

Failure to consider potential adverse system interactions when developing procedures affecting quality is a performance deficiency. This performance deficiency is more than minor because it is associated with the Procedural Quality attribute of the Mitigating Systems Cornerstone and adversely affects the cornerstone objective to ensure the availability, reliability, and capability of the safety relief valves to reduce reactor pressure in response to a loss of AC and DC power event. Because this finding is associated with B.5.b mitigation strategies, the finding was assessed using MC 0609 Appendix L, B.5.b Significance Determination Process, Table 2. The inspectors performed an initial screening and determined the finding did not meet the criteria listed within Table 2 for greater than Green significance, therefore this finding was screened as Green. Because the mitigating strategy was developed and implemented in site procedures in 2007 the performance deficiency occurred outside the past three years and no cross-cutting aspect is assigned.

Enforcement:

10 CFR 50, Appendix B, Criterion V. Instructions, Procedures, and Drawings, requires in part that activities affecting quality shall be prescribed by procedures appropriate to the circumstances. Contrary to the above from July 2007 to June 2011 the licensee failed to prescribe within procedure 31EO-TSG-001-0, Technical Support Guidelines, Attachment 6, SRV Actuation Without Power to Allow Injection with Portable Pump, the potential adverse system interactions when operating SRVs with a portable DC power supply, which is an activity affecting quality. Immediate corrective actions taken by the licensee include changing 31EO-TSG-001-0, Attachment 6, SRV Actuation Without Power to Allow Injection with Portable Pump, to ensure the SRV control circuits are isolated electrically from the DC busses prior to installing the portable DC power supply. Because this violation was of very low safety significance and it was entered into the licensees corrective actions program as CR 2011106008, this violation is being treated as an NCV, consistent with the Enforcement Policy. NCV 05000321,366/2011003-02, Failure to consider potential adverse system interactions when developing procedure to open SRVs without power.

Introduction:

A Green NRC-identified NCV of 10 CFR 50, Appendix B, Criterion V.

Instructions, Procedures, and Drawings, was identified for failure to establish adequate procedures that address the anticipated environmental conditions when operating containment vents without power.

Description:

During performance of TI-183, the inspectors questioned whether the manual operation of the containment vent procedure, 31EO-TSG-001-0, Attachment 10, Manually Open Containment Vent Lines, could be performed as written. This procedure was implemented by the licensee in September 2005 and has operators manually operate vent valves to relieve pressure inside primary containment during a loss of AC and DC power event. The inspectors determined this procedure did not take into account anticipated environmental conditions within the areas operators would enter during performance of portions of this procedure. Under some scenarios this procedure may not be able to be performed due to the high ambient temperature conditions expected to be present within the area operators would be required to enter to install rigs and operate dampers. During a loss of AC and DC power condition, reactor decay heat would be transferred from the reactor to the torus suppression pool through the safety relief valves. The suppression pool will heat up, reach saturation conditions, and cause pressure within the primary containment to increase. The licensees emergency operating procedures and severe accident guidelines direct the venting of the torus before the primary containment pressure limit is exceeded. The primary containment pressure limit maximum acceptable torus pressure would require torus venting prior to exceeding 60 psig. Utilizing ASME Steam Tables, for a 60 psig pressure (74.7 psia) the saturation temperature is ~307 degrees F. Should the licensee vent containment at a torus pressure as low as 40 psig (54.7 psia) the saturation temperature is still ~285 degrees F. Attachment 10 directs operators to perform numerous strenuous and complicated tasks within the torus area. Among the actions operators would perform include 1) transferring several air bottles down vertical ladders to the torus area, 2)disconnecting fittings and connecting temporary air lines to three dampers while standing directly on top of the un-lagged metal shell of the saturated torus, and 3)periodically operating the three dampers using air cylinders while maintaining radio contact to control primary containment pressure. This evolution would be performed in very low light conditions using portable battery operated lighting (flashlights) due to the loss of power to installed area lighting. These conditions would hinder performance and require increased time within the high temperature environment to complete the 10 procedure. The inability to vent primary containment during a loss of AC and DC power utilizing the containment vent valves could result in the over pressurization and subsequent failure of primary containment. To address this issue the licensee initiated CRs 2011105966 and 2011106007. The licensee has changed procedure 34AB-R22-003-1/2, Station Blackout, to perform preliminary actions in the torus area before the high containment pressure conditions require venting. This change is intended to allow required torus area entries to be performed prior to the time when high temperature saturation conditions are reached inside the torus.

Analysis:

Failure to address the anticipated environmental conditions when developing procedures affecting quality is a performance deficiency. This performance deficiency is more than minor because it is associated with the Procedural Quality attribute of the Mitigating Systems Cornerstone and adversely affects the cornerstone objective to ensure the availability, reliability, and capability of the containment vent valves to allow reliable primary containment pressure control in response to a loss of AC and DC power event. This finding was assessed using MC 0609 Appendix L, B.5.b Significance Determination Process, Table 2. The inspectors performed an initial screening and determined the finding did not meet the criteria listed within Table 2 for greater than Green significance therefore this finding was screened as Green. Because the procedure was developed and implemented in 2005, the performance deficiency occurred outside the past three years and no cross-cutting aspect is assigned.

Enforcement:

10 CFR 50, Appendix B, Criterion V. Instructions, Procedures, and Drawings, requires in part that activities affecting quality shall be prescribed by procedures appropriate to the circumstances. Contrary to the above from September 2005 through June 2011 the licensee failed to prescribe within procedures the appropriate circumstances of considering the environmental conditions within the torus area for manually operating containment vent valves, which is an activity affecting quality. Specifically, procedures did not address operation of the vent valves in an anticipated high temperature condition. Immediate corrective actions taken by the licensee include changing procedure 34AB-R22-003-1/2, Station Blackout, to perform preliminary actions in the torus area before high torus temperature conditions are reached. Because this violation was of very low safety significance and it was entered into the licensees corrective actions program as CR 2011105966 and CR 2011106007, this violation is being treated as an NCV, consistent with the Enforcement Policy. NCV 05000321,366/2011003-03, Failure to address the anticipated environmental conditions when developing procedures to manually operate containment vent valves.

.4 (Closed) NRC Temporary Instruction 2515/184, Availability and Readiness Inspection of

Severe Accident Management Guidelines (SAMGs)

On May 27, 2011, the inspectors completed a review of the licensees severe accident management guidelines (SAMGs), implemented as a voluntary industry initiative in the 1990s, to determine

(1) whether the SAMGs were available and updated,
(2) whether the licensee had procedures and processes in place to control and update its SAMGs,
(3) the nature and extent of the licensees training of personnel on the use of SAMGs, and
(4) licensee personnels familiarity with SAMG implementation.

The results of this review were provided to the NRC task force chartered by the Executive Director for Operations to conduct a near-term evaluation of the need for agency actions following the Fukushima Daiichi fuel damage event in Japan. Plant-specific results for E.I. Hatch Station were provided as an Enclosure to a memorandum to the Chief, Reactor Inspection Branch, Division of Inspection and Regional Support, dated June 02, 2011 (ML111530328).

4OA6 Meetings, Including Exit

On June 25, 2011, the resident inspectors presented the inspection results to you and other members of your staff. The inspectors confirmed that proprietary information was not provided or examined during the inspection.

ATTACHMENT:

SUPPLEMENTAL INFORMATION

KEY POINTS OF CONTACT

Licensee personnel

S. Bargeron, Plant Manager
G. Brinson, Maintenance Manager
B. Duval, Site Support Manager
G. Johnson, Engineering Director
C. Lane, Engineering Systems Manager
D. Madison, Hatch Vice President
K. Underwood, Performance Improvement Supervisor
R. Varnadore, Operations Manager

LIST OF ITEMS

OPENED AND CLOSED

Closed

2515/179 TI Verification of Licensee Responses to NRC Requirement for Inventories of Materials Tracked in the National Source Tracking System (NSTS) Pursuant to Title 10, Code of Federal Regulations, Part 20.2207 (10 CFR 20.2207). (Section 4OA5.2)

2515/183 TI Follow-up to the Fukushima Daiichi Nuclear Station Fuel Damage Event. (Section 4OA5.3)

2515/184 TI Availability and Readiness Inspection of Severe Accident Management Guidelines (SAMGs). (Section 4OA5.4)

Opened &

Closed

05000321,366/2011003-01 NCV Failure to promptly identify and take corrective actions to ensure Bussmann fuses identified by the Part 21 notification 2005-37 were removed from use in safety related applications. (Section 4OA2.2)
05000321,366/2011003-02 NCV Failure to consider potential adverse system interactions when developing procedure to open SRVs without power. (Section 4OA5.3)
05000321,366/2011003-03 NCV Failure to address the anticipated environmental conditions when developing procedures to manually operate containment vent valves. (Section 4OA5.3)

LIST OF DOCUMENTS REVIEWED

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