IR 05000280/2006005

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IR 05000280-06-05, IR 05000281-06-05, IR 05000280-06-501, IR 05000281-06-501, IR 07200002-06-003; on 10/01-12/31, 2006; Surry Power Station Units 1 & 2 and Independent Spent Fuel Storage Installation; Event Followup, Routine Integrated Repo
ML070310592
Person / Time
Site: Surry, 07200002  Dominion icon.png
Issue date: 01/31/2007
From: Eugene Guthrie
NRC/RGN-II/DRP/RPB5
To: Christian D
Virginia Electric & Power Co (VEPCO)
References
IR-06-003, IR-06-005, IR-06-501
Download: ML070310592 (45)
v • d • e


Text

ary 31, 2007

SUBJECT:

SURRY POWER STATION - NRC INTEGRATED INSPECTION REPORT NOS.

05000280/2006005, 05000281/2006005, 05000280/2006501, 05000281/2006501 AND 07200002/2006003

Dear Mr. Christian:

On December 31, 2006, the United States Nuclear Regulatory Commission (NRC) completed an inspection at your Surry Power Station, Units 1 and 2, and the Surry Independent Spent Fuel Storage Installation. The enclosed report documents the inspection findings which were discussed on January 10, 2007, with Mr. Jernigan 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.

Based on the results of this inspection, the inspectors identified two Severity Level IV violations of NRC regulations. In addition, two licensee-identified violations which were determined to be of very low safety significance are listed in this report. However, because of their very low safety significance and because they are entered into your corrective action program, the NRC is treating these findings as Non-cited violations in accordance with Section VI.A.1 of the NRCs Enforcement Policy. If you deny these non-cited violation you should provide a response within 30 days of the date of this inspection report, with the basis for your denial, to the United States 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 Surry Power Station.

In accordance with 10 CFR 2.390 of the NRCs 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

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/

Eugene F. Guthrie, Chief Reactor Projects Branch 5 Division of Reactor Projects Docket Nos.: 50-280, 50-281,72-002 License Nos.: DPR-32, DPR-37, SNM-2501

Enclosure:

NRC Inspection Reports 05000280, 05000281/2006005, 05000280, 05000281/2006501 and 07200002/2006003 w/Attachment: Supplemental Information

REGION II==

Docket Nos.: 50-280, 50-281,72-002 License Nos.: DPR-32, DPR-37, SNM-2501 Report Nos.: 05000280/2006005, 05000281/2006005, 05000280/2006501, 05000281/2006005, 07200002/2006003 Licensee: Virginia Electric and Power Company (VEPCO)

Facilities: Surry Power Station, Units 1 & 2 Surry Independent Spent Fuel Storage Installation Location: 5850 Hog Island Road Surry, VA 23883 Dates: October 1 - December 31, 2006 Inspectors: N. Garrett, Senior Resident Inspector D. Arnett, Resident Inspector R. Chou, Senior Reactor Inspector (Section 1R08)

L. Garner, Senior Project Engineer (Parts of Sections 1R11.2, 1R17, 1R22, 1R23 and Sections 4AO2.4 and 4OA2.5)

E. Lea, Senior Operations Engineer (Section 1R11.1)

B. Miller, Reactor Inspector (Section 1R08)

L. Miller, Senior Emergency Preparedness Inspector (Sections 1EP2, 1EP3, 1EP4, 1EP5, 4OA1)

R. Moore, Senior Reactor Inspector (Section 4OA5)

M. Scott, Senior Reactor Inspector (Section 1R07)

Approved by: E. Guthrie, Chief, Reactor Projects Branch 5 Division of Reactor Projects Enclosure

SUMMARY OF FINDINGS

IR 05000280/2006-05, IR 05000281/2006-05, IR 05000280/2006-501, IR 05000281/2006-501, IR 07200002/2006-003; on 10/01-12/31, 2006; Surry Power Station Units 1 & 2 and Independent Spent Fuel Storage Installation; Event followup,

Routine Integrated Report.

The report covered a three month period of inspection by resident inspectors, a senior project engineer, a senior emergency preparedness inspector, three senior reactor inspectors and a reactor inspector. Two Severity Level IV violations were identified.

The significance of most findings is indicated by their color (Green, White, Yellow, Red)using 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. The NRCs program for overseeing the safe operation of commercial nuclear power reactors is described in NUREG-1649, Reactor Oversight Process, Revision 3, dated July 2000.

NRC Identified and Self-Revealing Findings

Cornerstone: Mitigating Systems

No Color: The inspectors identified a Severity Level IV non-cited violation of 10 CFR 50.59, Changes, Tests, and Experiments. Specifically, the licensee implemented proceduralized departures from the approved station technical specifications (TS)without the required NRC approval in procedures AP-13.0, Turbine Building Flooding, revision 13, and FCA 6.01, Uncontrollable Turbine Building Flooding, revision 2.

This finding was evaluated using traditional enforcement since it impacted or impeded the regulatory process in that the licensee improperly used the 10 CFR 50.59,

Changes, Tests, and Experiments, process to incorporate operator actions inconsistent with the TS. This finding was of more than minor safety significance because the procedure changes improperly bypassed the required NRC review and approval prior to implementation. The unapproved procedural actions would only be involved at the end of a very rare accident sequence. Given the time during the accident sequence in which these actions were to be accomplished, the actions were not a determent to core damage. Therefore, the violation was of very low safety significance. The finding is identified as Severity Level IV because the noncompliance is not considered to be of more than very low significance based on risk. (Section 4OA5)

Cornerstone: Emergency Preparedness

No Color: The inspectors identified a Severity Level IV non-cited violation (NCV) of 10 CFR 50.54(q) for implementing a change which decreased the effectiveness of the emergency plan without prior NRC approval. The licensee implemented an Emergency Plan change that modified the default Protective Action Recommendation (PAR) for the General Emergency classification to evacuate to 5 miles in all directions.

The finding was evaluated using the NRCs Enforcement Policy because licensee reductions in the effectiveness of its emergency plan impacted the regulatory process, in that, NRC approval was not requested prior to licensee implementation of the change.

This finding is of more than minor concern because the change made may be overly conservative in such a way as to place members of the public at unnecessary risk during evacuation of an area unaffected by a radiological release which would be more appropriately recommended for sheltering. The finding was determined to be a non-cited Severity Level IV violation in accordance with Supplement VIII of the Enforcement Policy because it involved licensee failure to meet an emergency planning requirement not directly related to assessment and notification. (Section 1EP4)

Licensee-Identified Violations

Violations of very low safety significance, which were identified by the licensee, have been reviewed by the inspectors. Corrective actions taken or planned by the licensee have been entered into the licensees corrective action program. These violations and corrective action tracking numbers are listed in Section 4OA7 of this report.

REPORT DETAILS

Summary of Plant Status

Unit 1 operated at or near full rated thermal power (RTP) until power was reduced to 72 percent on December 18 due to a dropped control rod. On December 22, power was increased to 80 percent RTP where the unit was operated until the end of the report period.

Unit 2 operated at or near full RTP until the reactor was manually tripped on October 7.

The unit remained shutdown for a refueling outage which began on October 12. The unit was placed on-line November 20, and reached 100 percent RTP on November 24.

The unit was operated at or near full RTP for the remainder of the report period.

REACTOR SAFETY

Cornerstones: Initiating Events, Mitigating Systems, Barrier Integrity

1R01 Adverse Weather Protection

.1 Severe Weather Preparations

a. Inspection Scope

On October 6, 2006, the licensee made preparations for an expected severe rainstorm.

The inspectors reviewed OC-21, Severe Weather Checklist and performed a walkdown of the turbine building, auxiliary building, safeguard buildings, and portions of the plant grounds to verify preparations for severe weather.

b. Findings

No findings of significance were identified.

.2 Cold Weather Preparations

a. Inspection Scope

The inspectors performed a seasonal review of the licensee cold weather preparations.

The inspectors reviewed licensee procedures 0-OSP-ZZ-001, Cold Weather Preparations and OC-21, Severe Weather Checklist. The inspectors walked down portions of the emergency diesel generators (EDGs), high level intake structure, low level intake structure, refueling water storage tanks (RWSTs), and condensate storage tanks (CSTs) to assess condition of heat tracing, heaters, and insulation. The inspectors observed equipment condition and documented system deficiencies to determine system readiness for cold weather. The inspectors reviewed the Updated Final Safety Analysis Report (UFSAR) and Technical Specifications (TS) requirements to verify that these systems would remain operable during cold weather conditions.

b. Findings

No findings of significance were identified.

1R04 Equipment Alignment

.1 Partial System Walkdowns

a. Inspection Scope

The inspectors performed two partial walkdowns of the following systems to verify correct system alignment. The inspectors checked for correct valve and electrical power alignments by comparing positions of valves, switches, and breakers to the procedures and drawings listed in the Attachment. Additionally, the inspectors reviewed the corrective action system to verify that equipment alignment problems were being identified and properly resolved.

  • 1'B Emergency Service Water (ESW) Pump, 1-SW-P-1B and 1'C ESW Pump, 1-SW-P-1C while 1'A ESW Pump, 1-SW-P-1A was out of service for pump replacement
  • 1'A Emergency Service Water (ESW) Pump, 1-SW-P-1A and 1'C ESW Pump, 1-SW-P-1C while 1'B ESW Pump, 1-SW-P-1B was out of service for cleaning and piping replacement

b. Findings

No findings of significance were identified.

.2 Complete System Walkdown

a. Inspection Scope

The inspectors performed a detailed walkdown on the accessible portions of the Unit 2 Residual Heat Removal System (RHR) to review the system alignment and condition.

The walkdown emphasized pump and piping overall condition, status of boric acid leaks and associated targets, plant issues associated with system deficiencies, valve and breaker position verifications, and component labeling. The documents reviewed by the inspectors are listed in the Attachment of this report.

b. Findings

No findings of significance were identified.

1R05 Fire Protection

Fire Area Walkdowns

a. Inspection Scope

The inspectors conducted tours of the following six areas to assess the adequacy of the fire protection program implementation. The inspectors checked for the control of transient combustibles and the condition of the fire detection and fire suppression systems (using SPS Appendix R Report,) in the following areas:

C Unit 1 Cable Spreading Room C Unit 2 Cable Spreading Room C Mechanical Equipment Room Number 4 C Fire Pump House C Mechanical Equipment Room Number 2 C Unit 2 Main Steam Valve House

b. Findings

No findings of significance were identified.

1R06 Flood Protection Measures

a. Inspection Scope

The inspectors reviewed an external water intrusion event which occurred the morning of October 7, 2006, during an extremely heavy rainfall. The inspectors walked down portions of the turbine building (TB) which were subject to flooding, portions of the emergency switchgear room (ESGR) subject to leakage from external sources, and the manways which channeled water into the TB and ESGR. The inspectors reviewed the Updated Final Safety Analysis Report, historical rainfall records maintained on-line by the National Oceanic & Atmospheric Administration (NOAA), and plant drawings for the electrical manways that connect the switchyard to the TB and ESGR. In addition, the inspectors observed maintenance activities to seal the cable ways inside the manways.

b. Findings

No findings of significance were identified.

1R07 Heat Sink Performance

Biennial Review

a. Inspection Scope

The inspectors reviewed inspection records, clean and inspect results, corrective action program documents, and other documentation to ensure that heat exchanger (HX)deficiencies that could mask or degrade performance were identified and corrected.

Procedures and records were also reviewed to verify that these were consistent with licensee commitments to Generic Letter (GL) 89-13, Service Water System Problems Affecting Safety-Related Equipment, and industry guidelines. Risk significant heat exchangers (HX) reviewed included the component cooling HXs, recirculation spray HX, and lube oil and seal coolers for the charging pumps.

The inspectors reviewed HX inspection and cleaning work instructions, work maintenance history, and completed inspection records for all the safety-related HXs selected. The documents were reviewed to verify that inspection methods were consistent with industry standards, to verify HX design margins were being maintained, and to verify performance of the HXs under the current maintenance frequency was adequate.

The inspectors also reviewed general health of the service water system via review of design basis documents, system health reports, inservice testing requirements, heat exchanger performance testing calculations, and discussions with the service water (SW) system engineer. These documents were reviewed to verify the design basis was being maintained and to verify adequate SW system performance under current preventive maintenance, inspections, and test frequencies. The inspectors physically walked down the service water/circulating water intake (ultimate heat sink) canal. The inspectors reviewed the intake or high canal repair documentation, canal inspection reports and spoke with chemistry personnel regarding the health of systems affected with respect to biotic fouling species.

The inspectors also verified SW system corrosion and degradation were being monitored and addressed via a review of corrosion control program procedures and, SW pipe replacement and material condition action plans. The inspectors reviewed samples of the licensees SW Project activities that are in progress for piping replacement over the next several years, or that have been accomplished since the previous inspection.

Corrective action program documents, and Corrective Reports (CR or PI) were reviewed for potential common cause problems and problems which could affect system performance to confirm that the licensee was entering problems into the corrective action program and initiating appropriate corrective actions.

b. Findings

No findings of significance were identified.

1R08 Inservice Inspection Activities

.1 Piping Systems and Containment Inservice Inspection (ISI)

a. Inspection Scope

From October 23-27, 2006, the inspectors observed and reviewed the licensees implementation of their ISI program for monitoring degradation of the reactor coolant system pressure boundary and risk significant piping system boundaries for Surry Unit

2. The inspectors observed and reviewed a sample of American Society of Mechanical

Engineers (ASME),Section XI, and Risk Informed ISI required examinations.

The inspectors conducted an on-site review of nondestructive examination (NDE)activities to evaluate compliance with Technical Specifications and the applicable editions of ASME,Section V and XI, to verify that indications and defects (if present)were appropriately evaluated and dispositioned in accordance with the requirements of ASME,Section XI acceptance standards.

Specifically, the inspectors observed the following examination:

Manual Ultrasonic Testing (UT):

  • VT-2: 2-NPT-CH-014, System Pressure Test for CVCS Piping Lines, 10/2006
  • VT-2: 2-OPT-BD-001, System Pressure Test for Blowdown System Components Inside Containment, 10/2006
  • VT-2: 2-OPT-RC-10.1, RCS Leakage Walkdown at Cold Shutdown, 10/2006
  • VT-2: 2-NPT-RC-003, Above-the-Insulation Vessel Head Exam for Boric Acid Leakage, 10/2006
  • VT-2: 0-NSP-RC-003, Vessel Bottom Mounted Instrumentation (BMI), 10/2006 Specifically, the inspectors reviewed the following examination records that contained recordable indications and verified that they were appropriately dispositioned in accordance with the ASME Code:
  • VT-3: Mark # 2-SI-H012 on 10"-SI-213-153, Vertical Support
  • VT-3: Mark # 2-CC-H001 on 6"-CC-177-151, Pipe Support
  • VT-3: Mark # 2-RC-H001 on 2"-RC-500-1502, Spring Support
  • VT-3: Mark # 2-SI-H003 on 10"-SI-363-153, Lateral Constraint
  • VT-3: Mark # 2-CH-H004A on 3"-CH-302-1503, Vertical Constraint
  • UT: Weld 1-16BC on 30"-SHP-122-601, Main Steam Line The inspectors reviewed a sample of welding activities performed since the beginning of the last Unit 2 refueling outage for ASME pressure boundary piping. The inspectors reviewed weld data sheets, welding procedures, and procedure qualification records for the following weld:
  • Mark # 02-CH-366-VALVE, 3/4" CVCS Valve and Piping, ASME Class 1 The inspectors performed a review of ISI related problems that included welding, boric acid corrosion control, and steam generator inservice examinations that were identified by the licensee and entered into their corrective action program. The inspectors reviewed a sample of these corrective action documents to confirm that the licensee had appropriately described the scope of the problem and had initiated appropriate corrective actions. The inspectors performed this review to ensure compliance with 10 CFR Part 50, Appendix B, Criterion XVI, Corrective Action, requirements. The corrective action documents reviewed by the inspectors are listed in the attachment to this report.

b. Findings

No findings of significance were identified.

.2 Boric Acid Corrosion Control Program

a. Inspection Scope

The inspectors reviewed the licensees Boric Acid Corrosion Control Program to ensure compliance with commitments made in response to NRC Generic Letter 88-05, Boric Acid Corrosion of Carbon Steel Reactor Pressure Boundary, and Bulletin 2002-01, Reactor Pressure Vessel Head Degradation and Reactor Coolant Pressure Boundary Integrity.

The inspectors conducted an on-site record review and an independent walk-down of the containment building, which is not normally accessible during at-power operations, to evaluate licensee compliance with their program procedures and applicable industry guidance. In particular, the inspectors verified that the licensees visual examinations focused on locations where boric acid leaks could cause degradation of safety significant components and that degraded or non-conforming conditions were properly identified in the licensees corrective action program. The inspectors reviewed documentation for the visual examination of reactor pressure vessel bottom mounted instrumentation, inspection of insulated bolted connections and principal leak locations, and reactor coolant system pressure tests.

The inspectors reviewed a sample of engineering evaluations completed for boric acid leaks on reactor coolant system piping and other ASME Code Class components to verify that the minimum design code required section thickness had been maintained for affected components. The inspectors also reviewed licensee corrective action documents initiated for evidence of boric acid leakage to confirm that they were consistent with requirements of Section XI of the ASME Code, 10 CFR 50 Appendix B Criterion XVI, and licensee BACCP procedures. Specifically, the inspectors reviewed boric acid engineering evaluations for the following components:

  • 2-CH-RV-2382B-VALVE, RCP Seal Return Line Relief Valve
  • 2-SI-MOV-2864A, Safety Injection Valve
  • 2-CH-MOV-2350, CVCS Valve in Auxiliary Building

b. Findings

No findings of significance were identified.

.3 Steam Generator (SG) Tube Inservice Inspection

a. Inspection Scope

From October 23-27, 2006 the inspectors reviewed the Unit 2 SG A tube examination activities conducted pursuant to Technical Specification (TS) and the ASME,Section XI requirements.

The inspectors reviewed activities, plans, condition and operational assessments, pre-outage degradation assessment, problem identification, and procedures for the inspection and evaluation of the steam generator Inconel Alloy 600TT tubing and related components to determine if the activities were being conducted in accordance with TS and applicable industry standards. Data gathering, analysis, and evaluation activities were reviewed, with special emphasis on evaluation of the eddy current data for the indication on the hot leg of tube R41C27, induced from the plug removed in 1991, and wear indications on four tubes produced by foreign objects in the secondary side.

These tubes included R34C27, R35C27, R40C29, and R41C29 on top of the tube sheet area. The inspectors also observed the licensees video visual examination on the secondary side for foreign objects. The inspectors reviewed the licensee engineering transmittal ET-MAT-06-0002, Rev. 0, Steam Generator Channel Head/ Tube Sheet Corrosion, Surry Power Station, and Memorandum: Steam Generator Condition Monitoring and Operational Assessment, Surry Unit 2 - Fall 2006, for the corrosion evaluation of the loss of the base metal on the channel head and tube sheet for tube R41C27 to ensure the defects did not violate code requirements. In addition, the inspectors reviewed the licensee corrective action reports to ensure the adequate evaluation and disposition of the problems. The inspectors also reviewed the data analyst certification and qualifications including the medical exams.

b. Findings

No findings of significance were identified.

1R11 Licensed Operator Requalification

.1 Annual Review of Licensee Requalification Examination Results

a. Inspection Scope

On February 24, 2006, the licensee completed the comprehensive requalification biennial written examinations and on March 24, 2006, the licensee completed annual operating tests, required to be given to all licensed operators by 10 CFR 55.59(a)(2).

The inspectors performed an in-office review of the overall pass/fail results of the written examinations, individual operating tests, and the crew simulator operating tests. These results were compared to the thresholds established in Manual Chapter 0609 Appendix I, Operator Requalification Human Performance Significance Determination Process.

b. Findings

No findings of significance were identified.

.2 Quarterly Licensed Operator Requalification Review

a. Inspection Scope

The inspectors observed licensed operator performance during simulator training session RQ-06.7-ST-3 to determine whether the operators:

  • were familiar with and could successfully implement the procedures associated with recognizing and recovering from loss of the iso-phase bus duct cooling, perform a rapid power reduction and recognize and recover from a station blackout
  • recognized the high-risk actions in those procedures
  • were familiar with related industry operating experiences The inspectors also observed a simulator session on December 14, 2006, involving a steam generator tube leak with loss of power to various electrical buses, to assess overall crew performance, crew communications, and effectiveness of the evaluators critique. The inspectors also verified that the scenario included risk significant operator actions and emergency plan implementation.

b. Findings

No findings of significance were identified.

1R12 Maintenance Effectiveness

a. Inspection Scope

For the two equipment issues described in the plant issues listed below, the inspectors evaluated the licensees effectiveness of the corresponding preventive and corrective maintenance. For each selected item below, the inspectors performed a detailed review of the problem history and surrounding circumstances, evaluated the extent of condition reviews as required, and reviewed the generic implications of the equipment and/or work practice problem. Inspectors performed walkdown of the accessible portions of the system, performed in-office reviews of procedures and evaluations, and held discussions with system engineers. Inspectors compared the licensees actions with the requirements of 10 CFR 50.65, the Maintenance Rule, licensee procedure VPAP 0815, Maintenance Rule Program, and the Surry Maintenance Rule Scoping and Performance Criteria Matrix. The documents reviewed are listed in the Attachment of this report.

  • Unit 1 and 2 Auxiliary Building Ventilation Fans, 1-VS-F-58A/B, and
  • Unit 1 and 2 Recirculation Spray System

b. Findings

No findings of significance were identified.

1R13 Maintenance Risk Assessments and Emergent Work Control

a. Inspection Scope

The inspectors evaluated the following five activities for adequacy, accuracy, and completeness of plant risk assessments performed prior to changes in plant configuration for maintenance activities or in response to emergent conditions. When applicable, inspectors assessed if the licensee entered the appropriate risk category in accordance with plant procedures. Specifically, the inspectors reviewed:

  • Plan of the day (POD) for Week of October 1 - 6. Includes extension of 1-VS-E-4D, 2-CC-E-1A, 2-C-E-1B, replacement of relay 1-RP-RLY-273XB, and adding safety significant surveillances.
  • POD for Week of October 8 - 13. Includes the early start of U2 Refueling Outage, Unit 2 K-14 stuck rod, ESGR penetration leaking and Unit 2 plant trip recovery.
  • POD for Week of November 27 - December 1. Includes entering OC-21 for expected high winds, shifting of PT 8.5 and other safety related surveillances
  • POD for Week of December 18 - 22. Includes the Unit 1 K-8 dropped rod, 1-CC-E-1A chlorides increase and extension of maintenance on 1-VS-E-4D.

b. Findings

No findings of significance were identified.

1R15 Operability Evaluations

a. Inspection Scope

The inspectors evaluated the technical adequacy of the three operability evaluations to ensure that operability was properly justified and the subject component or system remained available such that no unrecognized increase in risk occurred. The operability evaluations were described in the engineering transmittal (ET) and plant issues listed below:

  • Condition Report (CR) 2877, AAC Diesel Generator Breaker Lockout
  • CR 2199/2278, Water Intrusion in Emergency Switchgear Room and Turbine Building
  • CR 2066, TDAFW pump steam exhaust not properly protected from missile hazards

b. Findings

No findings of significance were identified.

1R17 Permanent Modification

a. Inspections Scope The inspectors reviewed design change package (DCP)06-031, 1-CH-MOV-1381 Defeat Torque Closure/Surry/Unit 1. Motor operated valve (MOV) 1-CH-MOV-1381, reactor coolant pump seal leakoff isolation valve, closes on a phase one containment isolation signal. DCP 06-031 was implemented to prevent the valve from hammering and not remaining in the full closed position as documented in Plant Issue S-2006-2158.

The inspectors also reviewed the associated 10 CFR 50.59 evaluation, the engineering transmittal which formed the technical basis for the modification, the test procedures used to return the valve back to service, and drawings and other engineering documents which were revised as results of the DCP. The licensees applicability determination of the root cause to other safety-related valves was evaluated.

b. Findings

No findings of significance were identified.

1R19 Post Maintenance Testing

a. Inspection Scope

The inspectors reviewed the following six post maintenance test procedures and activities associated with the repair or replacement of the following components to determine whether the procedures and test activities were adequate to verify operability and functional capability following maintenance of the following equipment:

  • Maintenance Work Order (WO) 726963-13, Replace 1-SW-P-1A with spare pump
  • WO 734076-01, Level switch replacement for U1 Turbine Building Sump Pumps, 1-PL-P-2A/B/C

b. Findings

No findings of significance were identified.

1R20 Refueling and Other Outage Activities (Unit 2)

a. Inspection Scope

The inspectors performed the inspection activities described below for the Unit 2 refueling outage that began on October 12, 2006, and ended November 20, 2006.

The inspectors reviewed the licensees outage risk control plan, Surry Unit 2 2006 RFO Shutdown Risk Review Initial Report and Refueling Outage Safety Assessment and subsequent revisions, to verify that the licensee had appropriately considered risk, industry experience and previous site specific problems, and to confirm that the licensee had mitigation/response strategies for losses of key safety functions.

During the cooldown which preceded the outage, the inspectors reviewed portions of the cooldown process to verify that technical specification cooldown restrictions were followed.

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 technical specifications, and that configuration changes due to emergent work and unexpected conditions were controlled in accordance with the outage risk control plan.

During the outage, the inspectors:

  • Reviewed reactor coolant system (RCS) pressure, level, and temperature instruments to verify that those instruments were installed and configured to provide accurate indication; and that instrumentation error was accounted for
  • 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 spent fuel pool operations to verify that outage work was not impacting the ability of the operations staff to operate the spent fuel pool cooling system during and after core offload
  • 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 licensee control of containment penetrations to verify that the licensee controlled those penetrations in accordance with the refueling operations technical specifications and could achieve containment closure for required conditions
  • The inspectors reviewed fuel handling operations to verify that those operations and related activities were being performed in accordance with technical specifications and approved procedures.

The inspectors reviewed the licensees plans for changing plant configurations to verify, on a sampling basis, that technical specifications, license conditions, and other requirements, commitments, and administrative procedure prerequisites were met prior to changing plant configurations. The inspectors reviewed RCS boundary leakage and the setting of containment integrity. The inspectors examined the spaces inside the containment building prior to reactor startup to verify that debris had not been left which could affect performance of the containment sumps.

The inspectors reviewed various problems that arose during the outage to verify that the licensee was identifying problems related to refueling outage activities at an appropriate threshold and entering them in the corrective action program.

b. Findings

No findings of significance were identified.

1R22 Surveillance Testing

a. Inspection Scope

For the seven surveillance tests listed below, the inspectors examined the test procedure and either witnessed the testing and/or reviewed test records to determine whether the scope of testing adequately demonstrated that the affected equipment was functional and operable:

Surveillance Tests

  • 2-OPT-ZZ-001, ESF Actuation with Undervoltage and Degraded Voltage
  • 0-OCM-0303-01, Fuse Inspection and Replacement Inservice Test
  • 1-OPT-CH-002, Charging Pump Operability and Performance Test for 1-CH-P-1B
  • 2-OPT-CT-201, Containment Isolation Valve Local Leak Rate Testing (Type C Containment Testing), Valves 2-SS-TV-203A and 2-SS-TV-203B
  • 1-PT-18.6D, Cold Shutdown Testing of 1-CH-MOV-1381

b. Findings

No findings of significance were identified.

1R23 Temporary Plant Modifications

a. Inspection Scope

The inspectors reviewed the following four Temporary Modifications to determine whether system operability/availability was affected, that configuration control was maintained, and that the associated safety evaluation(s) adequately justified implementation.

  • S1-06-090, 1-CH-MOV-1381 failed to remain in a full closed position
  • S1-06-094, Use of copper tubes in control room chiller, 1-VS-E-4D, condenser
  • S1-06-095, 1-VS-E-3A, Water chiller control cabinet 480V connection

b. Findings

No findings of significance were identified.

Cornerstone: Emergency Preparedness

1EP2 Alert and Notification System Testing

a. Inspection Scope

The inspector evaluated the adequacy of licensee methods for testing the alert and notification system in accordance with NRC Inspection Procedure 71114, Attachment 02, Alert and Notification System (ANS) Testing. The applicable planning standard 10 Code of Federal Regulation (CFR) Part 50.47(b)(5) and its related 10 CFR Part 50, Appendix E, Section IV.D requirements were used as reference criteria. The criteria contained in NUREG-0654, Criteria for Preparation and Evaluation of Radiological Emergency Response Plans and Preparedness in Support of Nuclear Power Plants, Revision 1, was also used as references. The inspector reviewed various documents which are listed in the Attachment to this report.

b. Findings

No findings of significance were identified.

1EP3 Emergency Response Organization (ERO) Augmentation

a. Inspection Scope

The inspector reviewed the ERO augmentation staffing requirements and the process for notifying the ERO to ensure the readiness of key staff for responding to an event and timely facility activation. The results of the April 12, 2006 unannounced off-hours augmentation drill were reviewed. The inspector conducted a review of the backup notification systems. The qualification records of key position ERO personnel were reviewed to ensure all ERO qualifications were current. A sample of problems identified from augmentation drills or system tests performed since the last inspection was reviewed to assess the effectiveness of corrective actions.

The inspection was conducted in accordance with NRC Inspection Procedure 71114, 03, Emergency Response Organization (ERO) Augmentation Testing.

The applicable planning standard, 10 CFR 50.47(b)(2) and its related 10 CFR 50, Appendix E requirements were used as reference criteria. The inspector reviewed various documents which are listed in the Attachment to this report.

b. Findings

No findings of significance were identified.

1EP4 Emergency Action Level (EAL) and Emergency Plan Changes

a. Inspection Scope

The inspectors review of revisions to the emergency plan, implementing procedures and EAL changes was performed to determine that changes had not decreased the effectiveness of the emergency plan. The inspector also evaluated the associated 10 CFR 50.54(q) reviews associated with non-administrative emergency plan, implementing procedures and EAL changes. The Surry Power Station Emergency Plan, Revision 50 was reviewed.

The inspection was conducted in accordance with NRC Inspection Procedure 71114, 04, Emergency Action Level and Emergency Plan Changes. The applicable planing standard, 10 CFR 50.47(b)(4) and its related 10 CFR 50, Appendix E requirements were used as reference criteria. The criteria contained in NUREG-0654, Criteria for Preparation and Evaluation of Radiological Emergency Response Plans and Preparedness in Support of Nuclear Power Plants, Revision 1, and Regulatory Guide 1.101, Emergency Response Planning and Preparedness for Nuclear Power Reactors were also used as references. This inspection activity represents one sample on an annual basis. The inspector reviewed various documents which are listed in the to this report.

b. Findings

Introduction.

The inspector identified that the licensees 10 CFR 50.54(q) evaluation for Revision 44 of the Surry Emergency Plan completed in October 2000 resulted in a potential decrease in effectiveness (DIE) of the emergency plan. The change appeared to be overly conservative in such a way as to place members of the public at unnecessary risk during evacuation of an area unaffected by a radiological release which would be more appropriately recommended for sheltering.

Description.

On October 31, 2000, the licensee implemented an Emergency Plan change that modified the minimum or default Protective Action Recommendation (PAR)upon declaration of a General Emergency to evacuate to 5 miles in all directions. The change replaced the licensees previous standard minimum PAR based on NRC and Federal Emergency Management Agency (FEMA) guidance, which used the keyhole approach (i.e., evacuate all sectors to 2 miles and downwind sectors 2-5 miles) with an evacuation to 5 miles in all directions.

The licensees 10 CFR 50.54(q) review stated that the revised PAR scheme continues to meet the standards of 10 CFR 50.47(b)(10) because it is based on a process endorsed by the Federal Emergency Management Agency and the Nuclear Regulatory Commission. This guidance is contained in Supplement 3 ... to NUREG-0654/FEMA-REP-1 ..., which was issued for interim use and comment on August 26, 1996.

Supplement 3 to NUREG-0654 does not contain explicit or implicit guidance that would support the licensees rationale for adopting the revised PAR methodology. The bases for the change were that

(1) expanding the keyhole concept to a 5-mile, 360° approach would avoid complications in situations where the wind direction straddles two sectors, and precludes the need for modification of the PAR in the event of shifts in wind direction; and
(2) that this was a process simplification desired by the State. The licensee further reasoned that this minimum PAR for a General Emergency (GE) would bound any associated radiological consequences in terms of an initial PAR. The subject change represents a potential DIE in that it may be overly conservative in such a way as to place members of the public at unnecessary risk during evacuation of an area unaffected by a radiological release which would be more appropriately recommended for sheltering.
Analysis.

This finding affects the emergency preparedness cornerstone attribute of procedure quality. This finding is of more than minor concern because the change made may be overly conservative in such a way as to place members of the public at unnecessary risk during evacuation of an area unaffected by a radiological release which would be more appropriately recommended for sheltering. Because this issue had the potential for impacting the NRCs ability to perform its regulatory function, traditional enforcement would be applied. NRC has determined that the changes to the default PARs implemented in the Surry emergency plan have the potential to unnecessarily increase the risk to the public, a non-conservative situation. Accordingly, the licensees emergency plan change decreased the effectiveness of the plan and, as such, the licensee should not have implemented the change pursuant to §50.54(q).

Enforcement.

10 CFR 50.54(q) states in part that the licensee may make changes to these plans without Commission approval only if the changes do not decrease the effectiveness of the plans. Proposed changes that decrease the effectiveness of the approved emergency plans may not be implemented without application to and approval by the Commission. Contrary to the above, on October 31, 2000, the licensee made changes to their Emergency Plan, which reduced the effectiveness of the emergency plans. These changes were not submitted to the NRC for approval prior to implementation. The finding was determined to be a non-cited Severity Level IV violation in accordance with Supplement VIII of the Enforcement Policy because it involved licensee failure to meet an emergency planning requirement not directly related to assessment and notification. Because the violation was entered into the licensees corrective action program as Condition Report (CR) CR003590, it is being treated as a non-cited Severity Level IV violation consistent with Section VI.A of the Enforcement Policy. NCV 05000280/2006501,05000281/2006501-01, Protective Actions for Severe Reactor Accidents.

1EP5 Correction of Emergency Preparedness (EP) Weaknesses and Deficiencies

a. Inspection Scope

The inspector reviewed the corrective actions identified through the EP program to determine the significance of the issues and to determine if repeat problems were occurring. The facilitys self-assessments and audits were reviewed to assess the licensees ability to be self-critical, thus avoiding complacency and degradation of their EP program. In addition, inspector review licensees self-assessments and audits to assess the completeness and effectiveness of all EP-related corrective actions.

The inspection was conducted in accordance with NRC Inspection Procedure 71114, 05, Correction of Emergency Preparedness Weaknesses and Deficiencies. The applicable planning standard, 10 CFR 50.47(b)(14) and its related 10 CFR 50, Appendix E requirements were used as reference criteria. The inspector reviewed various documents which are listed in the Attachment to this report.

b. Findings

No findings of significance were identified.

OTHER ACTIVITIES

4OA1 Performance Indicator Verification

.1 Mitigating Systems Cornerstone - Safety Systems Functional Failure Performance

Indicator

a. Inspection Scope

The inspectors performed a periodic review of the Safety Systems Functional Failure performance indicator for Units 1 and 2. Specifically, the inspectors reviewed this performance indicator from the third quarter of 2004 through the third quarter of 2006.

Inspectors evaluated whether the performance indicator was calculated in accordance with the guidance contained in NEI 99-02, Regulatory Assessment Performance Indicator Guideline. Documents reviewed included applicable monthly operating reports, licensee event reports, and operator logs.

b. Findings

No findings of significance were identified.

.2 Barrier Integrity Cornerstone - Reactor Coolant System Specific Activity Performance

Indicator

a. Inspection Scope

The inspectors performed a periodic review of the Reactor Coolant System Specific Activity performance indicator for Units 1 and 2. Specifically, the inspectors reviewed this performance indicator from the third quarter of 2004 through the third quarter of 2006. Inspectors evaluated whether the performance indicator was calculated in accordance with the guidance contained in NEI 99-02, Regulatory Assessment Performance Indicator Guideline. The inspectors compared the submitted data with that recorded in operator logs for the period and discussed this PI with the cognizant engineer and licensing staff and reviewed the system engineers data sheets.

b. Findings

No findings of significance were identified.

.3 Emergency Preparedness Cornerstone Performance Indicators

a. Inspection Scope

The inspector reviewed the licensees procedure for developing the data for the Emergency Preparedness PIs which are:

(1) DEP;
(2) ERO Drill Participation; and
(3) Alert and Notification System (ANS) Reliability. The inspector examined data reported to the NRC for the period January 1, 2006 to June 30, 2006. Procedural guidance for reporting PI information and records used by the licensee to identify potential PI occurrences were also reviewed. The inspector verified the accuracy of the PI for ERO drill and exercise performance through review of a sample of drill and event records.

The inspector reviewed selected training records to verify the accuracy of the PI for ERO drill participation for personnel assigned to key positions in the ERO. The inspector verified the accuracy of the PI for alert and notification system reliability through review of a sample of the licensees records of periodic system tests.

The inspection was conducted in accordance with NRC Inspection Procedure 71151, Performance Indicator Verification. The applicable planning standard, 10 CFR 50.9 and Nuclear Energy Institute (NEI) 99-02, Revisions 3 and 4, Regulatory Assessment Performance Indicator Guidelines, were used as reference criteria. This inspection activity represents three samples on an annual basis. The inspector reviewed various documents which are listed in the Attachment to this report.

b. Findings

No findings of significance were identified.

4OA2 Identification and Resolution of Problems

.1 Daily Review of Plant Issues

a. Inspection Scope

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 reviewing hard copies of condition reports, attending daily screening meetings, and accessing the licensees computerized database.

b. Findings

No findings of significance were identified.

.2 Semi-Annual Review of Plant Issues

a. Inspection Scope

As required by Inspection Procedure 71152, "Identification and Resolution of Problems,"

the inspectors performed a review of the licensees corrective action program (CAP) and associated documents to identify trends that could indicate the existence of a more significant safety issue. The inspectors review was focused on repetitive equipment issues, but also considered the results of daily inspector CAP item screening discussed in section 4OA2.1, above, licensee trending efforts, and licensee human performance results. The inspectors review nominally considered the six month period of July, 2006, through December, 2006, although some examples expanded beyond those dates when the scope of the trend warranted. The review included the following areas/documents:

  • 2006 second quarter trend report and graphs
  • NRC performance indicators
  • Station indicators
  • 2006 second and third quarter system heath reports
  • Station reliability issues list
  • Corrective action program status reports
  • Work management/normal process list

b. Findings

No findings of significance were identified. The inspectors evaluated the licensee trending methodology and observed that in general the licensee trending methodology has been effective in identifying and preventing problems from becoming more significant.

.3 Focused Review of Plant Issues

Component Cooling Heat Exchanger Fouling

a. Inspection Scope

The inspectors performed an in-depth review of the root cause evaluation and corrective actions for the repeated fouling of the Component Cooling (CC) Heat Exchangers. This issue was documented in the corrective action program as Plant Issue S-2006-1372.

The review was performed to ensure the full extent of the issue was identified, an appropriate evaluation was performed, and appropriate corrective actions were specified and prioritized. The inspectors evaluated the Plant Issue against the requirements of the licensees corrective action program as delineated in Station Administrative Procedure VPAP-1601, Corrective Action, and 10 CFR 50, Appendix B, Criterion XVI, Corrective Action.

b. Findings and Observations

The licensee performed a root cause analysis of the CC heat exchanger fouling after declaring the C CC heat exchanger inoperable following the performance of the monthly surveillance test in March, 2006. The RCE documented 29 plant issues written on heat exchanger fouling for the four CC heat exchangers. Eighteen of the PIs were written since January, 2005. The A HX was declared inoperable on March 29, 2006 and the C on March 8, and April 19, 2006. The heat exchanger test trend data indicated only one heat exchanger was inoperable at any time. Based on a review of the Final Safety Analysis Report and design basis calculations, there were no safety consequences resulting from one heat exchanger inoperable and various degrees of fouling on the remaining three heat exchangers.

The licensees root cause team determined the root cause to be system design. The CC heat exchangers were oversized for winter operations. The system is not designed to allow temperature control on either the service water (SW) or CC water side. When the SW injection temperature was very low during the winter months, the licensee throttled the SW flow to a very low flow rate. The low flow velocity allowed sediment and silt to be deposited inside the tubes which provided an active environment for biofouling in the tubes. If any biological growth was already present in the tubes the rate of sediment and silt buildup was increased. The root cause team determined the contributing causes were ineffective and/or inadequate chemistry control, a change in the timing of annual heat exchanger cleaning, and ineffective and/or inadequate cleaning of heat exchangers.

The root cause team also performed an extent of condition review on other heat exchangers. The team reviewing the condition of the recirculation spray heat exchangers, bearing cooling heat exchangers, and the main control room chillers. The team also addressed why previous corrective actions were inadequate and the organizational factors which contributed to these events. The licensee determined the following corrective actions to prevent recurrence; transfer ownership of the chemistry control program to Chemistry and allowed them to change chemicals that are required to prevent fouling, created a preventative maintenance task to clean the heat exchanger in the January-February time frame, and change the acceptance criteria and post cleaning inspections to insure tubing is completely free of debris. In addition, licensee management rejected a corrective action to modify the CC system by installing a bypass line to allow higher flow through the SW side.

.4 Focused Review of Plant Issues

CR002199 Water Intrusion The inspectors performed an in-depth review of the root cause evaluation and corrective actions associated with the October 7, 2006, water intrusion into the turbine building and emergency switchgear room. This event was entered into the licensees corrective action program as CR 002199. The review included evaluation of the licensees apparent cause report, review of applicable work orders, drawings and engineering documents, discussions with cognizant engineering personnel and a field walkdown of areas of the plant associated with event, as well as, others plants areas which might be susceptible to a similar event. The review focused on the extent of condition determination and the corrective actions taken to date. The inspectors assessed the licensee actions against the requirements of VPAP-1601 and 10 CFR 50, Appendix B, Criterion XVI.

Findings and Observations No findings of significance were identified. The licensees corrective action documents properly identified the cause and interim corrective actions implemented to preclude this same event from re-occurring until identified long term corrective actions could be implemented. The inspectors noted that both ends of some penetrations were sealed.

The work order, which sealed both sides, did not have documentation which justified this action. Licensee specification NUS 2030, Specification for Electrical Installation for Surry Units 1 and 2," specified that sealing should be done on the low side of the penetration. The inspectors observed that the apparent cause involved external flooding barriers into buildings but did not consider potential flooding barriers between the building. During the plant walkdown, the inspector, accompanied by the cognizant engineer, verified visually that installed flood protection barriers between buildings were acceptable. However, some of these barriers were not accessible. Of particular note was the penetrations between the EDG room and the emergency switchgear rooms. A corrective action document was generated to inspect these barriers. The inspectors also noted that external flooding has been the subject of several generic communications. These observations were discuss with plant management.

.5 Focused Review of Plant Issues

S-2006-2158 Valve 1-CH-MOV-1381 Hammering Plant Issue S-2006-2158 documents a malfunction of 1-CH-MOV-1381, Reactor Coolant Pump seal leakoff line isolation valve. When the valve closed, the torque would relax allowing the close torque switch to open which caused the valve to drive closed again, This process repeated (called hammering) until the valve motor tripped on the thermal overload. The inspectors reviewed the plant issue documentation including the cause evaluations, associated temporary and permanent modification documents, and safety evaluations. The inspectors assessed the licensee actions against the requirements of VPAP-1601 and 10 CFR 50, Appendix B, Criterion XVI.

Findings and Observations No findings of significance were identified. The licensee installed permanent modification DCP 06-031 to correct the condition. The inspectors noted that the DCP 06-031 justification for the acceptability of the modification was that it returned the valve control circuit to its original configuration. However, the justification did not address the reasons why the valve control circuit had been changed in previous years and if those reasons should be addressed. The licensee was planning another permanent modification to change the gear ratio which will eliminate the need for the DCP 06-031 modification. The inspectors also note that this issue had previously been the subject of a generic communications, NRC IE Notice 85-20, Motor-Operated Valve Failure Due to Hammering Effects. These observations were discussed with plant management.

.6 Focused Review of Operator Work-Arounds

The inspectors reviewed the licensee's list of identified operator work-arounds as of September 28, 2006, to assess the cumulative effects of operator work-arounds on the reliability, availability, and potential for mis-operation of a system to verify that there was no increase in overall plant risk. The assessment included increases of initiating event frequencies, effects on multiple mitigating systems, and the ability of operators to correctly respond to abnormal plant conditions.

Findings and Observations No findings of significance were identified. The inspectors verified that the licensee identified operator workaround problems at an appropriate threshold and entered them into the corrective action program, and has proposed or implemented appropriate corrective actions.

4OA3 Event Follow-up 71153

The inspectors responded to the site when Unit 2 was manually tripped and a partial loss of off-site power occurred on October 7. The plant was tripped following a main turbine electro-hydraulic control system transient and the lifting of the moisture separator crossunder relief valves. The inspectors responded to the event, assessed plant conditions following the trip, and manned the technical support center or remained on-site until off-site power was restored. The inspectors observed operator actions in the main control room and the technical support center during the plant recovery. The inspectors reviewed the licensees initial investigation reports and cause determinations.

An NRC special inspection was initiated on October 23. The NRC Special Inspection Report can be reviewed via Inspection Report 05000280/2006-011 and 05000281/2006-011.

4OA5 Other Activities

.1 (Closed) URI 05000280,281/2004006-002: Acceptability of Proceduralized Departures

from TS Requirements Without NRC Approval

Introduction:

A NCV of 10 CFR 50.59 was identified related to the licensees incorporation, without prior NRC review and approval, of preplanned and proceduralized operator actions which were inconsistent with the approved station TS.

Description:

During the safety system design and performance capability inspection conducted March 22, to April 8, 2004, it was identified that the licensee implemented changes to two operating procedures which added actions to address a potential uncontrollable turbine building flood event. Procedures AP-13.0, Turbine Building Flooding, revision 13, and FCA 6.01, Uncontrollable Turbine Building Flooding, revision 2, directed operators to perform the following actions which were inconsistent with station TS:

  • Drain the intake canal below TS limits
  • De-energize all safety related AC switchgear for both units, contrary to TS operability requirements.

The licensee performed Safety Evaluation 94-090, dated May 2, 1994, and concluded that NRC review and approval was not required prior to implementing the procedure changes incorporating the above operator actions. This item was unresolved pending further NRC review which was completed and documented in the Final Response to Task Interface Agreement 2004-04, Acceptability of Proceduralized Departures from TS Requirements at the Surry Power Station, dated September 12, 2006 ( ADAMS ML060590273).

Analysis:

The NRC determined that the licensees procedure changes, which added operator actions inconsistent with the TS, required prior NRC approval. This finding was addressed using traditional enforcement since it potentially impacted or impeded the regulatory process in that the licensee implemented proceduralized departures from the approved TS using the 10 CFR 50.59 process. However, 10 CFR 50.59 does not allow licensees to make changes to operating procedures that depart from the approved TS without prior NRC approval.

This finding is more than minor because the procedure changes improperly bypassed the required NRC review and approval prior to implementation. The unapproved procedural actions would only be involved at the end of a very rare accident sequence.

Given the time during the accident sequence in which these actions were to be accomplished, the actions were not a decrement to core damage. Therefore, the violation was of very low safety significance. The finding is identified as Severity Level IV because the noncompliance is not considered to be of more than very low significance based on risk.

The licensee entered this issue into their corrective action program (Plant Issue S-2004-1517) and has completed the corrective actions to delete the NRC unapproved operator actions from the applicable procedures. The inspector reviewed procedures 0-AP-13.01, Uncontrollable Turbine flooding, revision 3 (replaced previous 0-AP-13.0, revision 13) and emergency contingency action (ECA) 0.0, Loss of All AC, revision 23 (superceded previous FCA 6.01, revision 2) and verified that the NRC unapproved operator actions were deleted.

Enforcement:

10 CFR 50.59( c)(1) states, in part, that a licensee may make changes in the facility as described in the UFSAR or make changes in the procedures as described in the UFSAR without obtaining a license amendment pursuant to 10 CFR 50.90, Applications for Amendments of License or Construction Permits, in part only if a change to the TS incorporated by the license is not required. Contrary to the above, in 1994, the licensee implemented procedure changes without a license amendment to procedures AP-13.0, Turbine Building Flooding, revision 13, and FCA 6.01, Uncontrollable Turbine Building Flooding, revision 2, which required a change to the TS incorporated in the license. In accordance with Section VI.A of the NRC Enforcement Policy, this violation is classified as a Severity Level IV violation because the underlying technical issue is of very low safety significance. Because this non-willful violation is non-repetitive and was entered into the licensees corrective action program (Plant Issue S-2004-1517) it is considered a non-cited violation consistent with Section VI.A.1 of the NRC enforcement Policy. This finding is identified as NCV 05000280,281/2006005-01, Proceduralized Departures from TS Requirements Without NRC Approval.

.2 60855.1 Operation of an Independent Spent Fuel Storage Installation at Operating

Plants The inspectors requested a list of all 10 CFR 70.48 evaluations performed by the licensee during the years 2004 and 2005. The licensee did not perform any 10 CFR 70.48 evaluations during this time. This completes the required inspection activity.

.3 (Closed) NRC Temporary Instruction (TI) 2515/169, Mitigating Systems Performance

Index (MSPI) Verification

a. Inspection Scope

During this inspection period, the inspectors completed a review of the licensees implementation of the Mitigating Systems Performance Index (MSPI) guidance for reporting unavailability and unreliability of monitored safety systems in accordance with Temporary Instruction 2515/169.

The inspectors examined surveillances that the licensee determined would not render the train unavailable for greater than 15 minutes or during which the system could be promptly restored through operator action and therefore, are not included in unavailability calculations. As part of this review, the recovery actions were verified to be uncomplicated and contained in written procedures.

On a sample basis, the inspectors reviewed operating logs, work history information, maintenance rule information, corrective action program documents, and surveillance procedures to determine the actual time periods the MSPI systems were not available due to planned and unplanned activities. The results were then compared to the baseline planned unavailability and actual planned and unplanned unavailability determined by the licensee to ensure the datas accuracy and completeness. Likewise, these documents were reviewed to ensure MSPI component unreliability data determined by the licensee identified and properly characterized all failures of monitored components. The unavailability and unreliability data were then compared with performance indicator data submitted to the NRC to ensure it accurately reflected the performance history of these systems.

b. Findings and Observations

No findings of significance were identified.

With only minor exceptions, the licensee accurately documented the baseline planned unavailability hours, the actual unavailability hours and the actual unreliability information for the MSPI systems. No significant errors in the reported data were identified, which resulted in a change to the indicated index color. No significant discrepancies were identified in the MSPI basis document which resulted in:

(1) a change to the system boundary;
(2) an addition of a monitored component; or
(3) a change in the reported index color.

.4 Review of Surry Power Station Emergency Plan, Rev. 50 Minimum Staffing

Requirement (Note1)

At the request of Region IIs Division of Reactor Safety, the Division of Preparedness and Response (DPR) of the Office of Nuclear Security and Incident Response (NSIR)has reviewed the Surry Power Station emergency plan, revision 50, minimum staffing requirements (Table 5.1) against NUREG-0654, Table B-1 to determine whether Note

(1) can be cleared of the statement, Concurrence for change to position title and resource pool used to staff position provided by NRC via letter dated July 22, 1993 and whether Note
(2) can be cleared of the statement, This coverage previously required within approximately 30 minutes. Change approved per NRC Region II letter, Subject:

Surry and North Anna Proposed Emergency Plan Changes, May 18, 1990. The on-duty Shift Technical Advisor performs the responsibilities of this position prior to augmentation. Approval was based on factors outlined in the referenced letter remaining constant.

NRCs review found that the licensees emergency response plans have previously been found to adequately meet the standard required by 10 CFR 50.47(b)(2). The licensee may change the names of the position title along with the resource pool with the requirement that the candidates are qualified, as the licensee has acknowledged adhering to their emergency plan. Furthermore, with review of Table 5.1 regarding the subject note (1), the NRC concluded that the table continues to meet the criteria in Table B-1 of NUREG-0654, and therefore the Planning Standards of 10 CFR 50.47(b)and their requirements within Appendix E of 10 CFR Part 50. The determination has been made that the statement Concurrence for change to position title and resource pool used to staff position provided by NRC via letter dated July 22, 1993 can be cleared. However, any changes must continue to meet the Planning Standards outlined in 10 CFR 50.47(b) and the requirements within Appendix E of 10 CFR Part 50.

Upon review of the specific changes to the Surry Emergency Plan and the detailed functional analysis of the two response positions provided by the Virginia Electric and Power Company on January 17, 1990, it has been determined that the changes are consistent with the provisions of 10 CFR 50.47(b), Appendix E to 10 CFR Part 50, and Supplement 1 to NUREG-0737. As a result of the review it has been determined that the change in question did not decrease the effectiveness of the Emergency Plan. DPR will not alter the Regions previous conclusion that the licensees plans meet the standard required by 10 CFR 50.47(b)(2). For this reason, Note

(2) in Table 5.1 of the current revision of the Surry Emergency Plan can be cleared of the qualifying remarks Change approved per NRC Region II letter. However, the licensee should retain the portion of Note
(2) stating that The on-duty Shift Technical Advisor performs the responsibilities of this position prior to augmentation.

4OA6 Meetings, Including Exit

Exit Meeting Summary

.1 Reports 05000280/2006005, 05000281/2006005 and 07200002/2006003

On January 10, 2007, the resident inspectors presented the inspection results to Mr. D. Jernigan and other members of his staff who acknowledge the findings. The inspectors asked the licensee whether any of the material examined during the inspection should be considered as propriety. No proprietary information was identified.

.2 Reports 05000280/2006501 and 05000281/2006501

On October 27, 2006, the team lead for the Emergency Preparedness Inspection presented the inspection results to Mr. D. Jernigan, Surry Site Vice President, and other members of his staff who acknowledged the findings; but requested that they be able to provide additional information concerning proposed findings. The team lead stated that additional information would be accepted and reviewed.

The inspectors confirmed that proprietary information was not provided or taken during the inspection.

4OA7 Licensee Identified Violations

The following findings of very low significance were identified by the licensee and are violations of NRC requirements which meet the criteria of Section VI of the NRC Enforcement Policy, NUREG-1600, for being dispositioned as Non-Cited Violations (NCV).

  • 10 CFR Part 50.65(a)(4), requires, in part, that before performing maintenance activities, the licensee shall access and manage the increase in risk that may result from the proposed maintenance activity.

Contrary to the above, during the 2006 Unit 2 refueling outage, the licensee failed to perform a risk analysis on 2-SI-MOV-2890C, low head safety injection to cold leg isolation valve prior to performance of maintenance. When the licensee added the valve to the Safety Monitor program modeling the past plant configuration, plant risk changed from Green to Yellow for a period of twelve hours. Yellow plant risk occurs for an allowed configuration time (ACT) between 72 and 168 hours0.00194 days <br />0.0467 hours <br />2.777778e-4 weeks <br />6.3924e-5 months <br /> and Green risk is greater than 168 hours0.00194 days <br />0.0467 hours <br />2.777778e-4 weeks <br />6.3924e-5 months <br />. The modeled ACT was 154 hours0.00178 days <br />0.0428 hours <br />2.546296e-4 weeks <br />5.8597e-5 months <br />. In accordance with Inspection Manual Chapter (IMC) 0612 Appendix B, Issue Screening and Appendix E, Examples of Minor Issues, Section 7. Maintenance Rule Issues, Example e., the issue is more than minor.

This finding was identified in the licensees corrective action program as CR004133. This finding is of very low safety significance because the actual risk change occurred for a short period of time and the change in risk was not large.

Contrary to the above, during the 1991 Unit 2 refueling outage, the licensee failed to identify two conditions adverse to quality in the A Steam Generator (SG), in that degradations or corrosion on tube R41C27 and base metal on the interface of the tube sheet and the lower bowl area were not identified. The failure to identify the degradations or corrosion during the 1991 plug removal on the hot leg of the tube R41C27 resulted in degradation or corrosion on the base metal in both locations. These indications were identified through a video visual inspection and confirmed by a Rotating Probe Eddy Current inspection and sampling during this 2006 refueling outage. In 2002, the licensee failed to identify the degradations again in both locations during the video visual inspections inside lower bowl and bottom of the tube sheet area. The licensee traced back the problem to the 1991 refueling outage where the plug of tube R41C27 was removed, and an area of 1.75 inches X 0.9 inches on the bottom of the hot leg tube wall was removed by the machine. The machine also accidentally damaged the cladding of the interface of the tube sheet and the lower bowl area. Tube R41C27 had 100% through wall degradation due to the damage, and failed to meet inservice criteria of less than 40% through wall degradation. This tube was required to be plugged during this outage. This finding was identified in the licensees corrective action program as Condition Reports (CR) 003122, 003285, and 003591. The finding was determined to be Green using the SDP process in MC 0609 Appendix J, Table 1. The licensee plans to inspect both locations for the corrosion during each SG refueling outage to determine the corrosion progress.

ATTACHMENT:

SUPPLEMENTAL INFORMATION

KEY POINTS OF CONTACT

Licensee

M. Adams, Director, Nuclear Station Safety and Licensing
J. Costello, Supervisor Nuclear Emergency Preparedness
M. Crist, Manager, Operations
J. Eastwood, Steam Generator ISI
B. Garber, Supervisor, Licensing
J. Grau, Manager, Nuclear Oversight
E. Hendrixson, Director, Engineering
D. Jensen, ISI Manager
D. Jernigan, Site Vice President
L. Jones, Manager, Radiation Protection and Chemistry
C. Luffman, Manager, Protection Services
B. McBride, Manager Emergency Preparedness
W. Renz, Director Nuclear Protection Services & Emergency Preparedness
R. Simmons, Manager, Outage and Planning
K. Sloane, Director, Nuclear Station Operations and Maintenance
B. Stanley, Manager, Maintenance
C. Tudor, Engineering
M. Wilson, Manager, Training

NRC

E. Guthrie, Chief, Branch 5, Division of Reactor Projects, Region II

LIST OF ITEMS OPENED, CLOSED, AND DISCUSSED

Opened and Closed

05000280,281/2006005-01 NCV Proceduralized Departures from TS
05000280, 281/2006501-01 NCV Protective Actions for Severe Reactor Accidents.

Closed

05000280,281/2004006002 URI Acceptability of Proceduralized Departures from TS Requirements Without NRC Approval (4OA5.1)
05000280,281/2515/169 TI Mitigating Systems Performance Index Verification (Section 4OA5.1)
05000280, 281/2006008-02 URI Protective Actions for Severe Reactor Accidents (Section 1EP4)

LIST OF DOCUMENTS REVIEWED

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