IR 05000280/2008003

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IR 05000280-08-003 & 05000281-08-003 on 04/01/2008 - 06/30/08 for Surry Power, Units 1 & 2
ML082140022
Person / Time
Site: Surry, 07200055  Dominion icon.png
Issue date: 07/30/2008
From: Bates M
NRC/RGN-II/DRP/RPB5
To: Christian D
Virginia Electric & Power Co (VEPCO)
References
IR-08-003
Download: ML082140022 (44)
v • d • e


Text

July 30, 2008

SUBJECT:

SURRY POWER STATION - NRC INTEGRATED INSPECTION REPORT NOS.

05000280/2008003 AND 05000281/2008003.

Dear Mr. Christian:

On June 30, 2008, the United States Nuclear Regulatory Commission (NRC) completed an inspection at your Surry Power Station, Units 1 and 2. The enclosed integrated inspection report documents the inspection findings, which were discussed on July 24, 2008, with Mr. Sloane and other members of your staff.

The inspection examined activities conducted under your licenses as they relate to safety and compliance with the Commissions rules and regulations and with the conditions of your licenses. The inspectors reviewed selected procedures and records, observed activities, and interviewed personnel.

Based on the results of this inspection, no findings of significance were identified. However, a licensee-identified violation which was determined to be of very low safety significance is listed in this report. NRC is treating this violation as a non-cited violation (NCV)

consistent with Section VI.A.1 of the NRCs Enforcement Policy. If you contest any NCV in this report you should provide a response with the basis for your denial, within 30 days of the date of this inspection report, 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, U.S. Nuclear Regulatory Commission, Washington D.C. 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

VEPCO

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/

Mark Bates, Acting Chief Reactor Projects Branch 5 Division of Reactor Projects

Docket Nos.: 50-280, 50-281 (License Nos.:DPR-32, DPR-37)

Enclosure:

Integrated Inspection Report 05000280, and 281/2008003 w/Attachments: NRC Temporary Instruction (TI) 2515/172, Reactor Coolant System Dissimilar Metal Butt Welds (DMBWs), NRC Temporary Instruction (TI)

2515/166, Pressurized Water Reactor Containment Sump Blockage (NRC Generic Letter 2004-02) Unit 2, and Supplemental Information.

(

REGION II==

Docket Nos.: 50-280, 50-281,72-055 License Nos.: DPR-32, DPR-37

Report Nos.: 05000280/2008003, 05000281/2008003

Licensee:

Virginia Electric and Power Company (VEPCO)

Facilities:

Surry Power Station, Units 1 & 2

Location:

5850 Hog Island Road Surry, VA 23883

Dates:

April 1 through June 30, 2008

Inspectors:

C. Welch, Senior Resident Inspector K. Ellis, Acting Resident Inspector W. Loo, Acting Resident Inspector D. Mas-penaranda, Acting Resident Inspector A. Patel, Reactor Inspector C. Peabody. Reactor Inspector J. Rivera-Ortiz, Reactor Inspector A., Vargas, Reactor Inspector

Approved by: Mark Bates, Acting Chief Reactor Projects Branch 5 Division of Reactor Projects

SUMMARY OF FINDINGS

IR 05000280/2008-03, IR 05000281/2008-03; 04/01/2008 - 06/30/2008; Surry Power Station

Units 1 & 2, Routine Integrated Inspection Report.

The report covered a three month period of inspection by resident and region-based inspectors.

No findings of significance were identified by the NRC. The significance of most findings is indicated by their color (Green, White, Yellow, Red) using Inspection Manual Chapter (IMC)0609, Significance Determination Process, (SDP). Findings for which the SDP does not apply may be Green or be assigned a severity level after NRC management review. The NRCs program for overseeing the safe operation of commercial nuclear power reactors is described in NUREG-1649, Reactor Oversight Process, Revision 4, dated December 2006.

NRC-Identified and Self-Revealing Findings

None

B.

Licensee-Identified Violation

One violation of very low safety significance, which was identified by the licensee, has been reviewed by the inspectors. Corrective actions taken or planned by the licensee have been entered into the licensees corrective action program. The violation and corrective action tracking number is listed in Section 4OA7 of this report.

REPORT DETAILS

Summary of Plant Status:

Unit 1 began the inspection period operating at 100% rated thermal power (RTP). A planned forced outage was commenced on April 16 to repair feedwater heater 1-FW-6B.

The unit was taken off-line at 7:20 p.m. and reactor shutdown at 9:26 p.m. Following repairs, a startup was performed on April 20. Criticality was achieved at 10:51 a.m. and the unit connected to the electrical grid at 6:27 p.m. During the power ascension on April 20, a manual reactor trip and turbine trip were inserted at 10:14 p.m. due to high vibrations on the main turbine (EN44152). Following balancing of the main turbine a second startup was performed on April 21. Criticality was achieved at 4:56 p.m. and the unit connected to the grid at 11:48 p.m.. Full RTP was obtained on April 22, at 9:55 a.m..

On May 4, an unplanned power reduction to 67% was made due to a vacuum leak in the main condenser. Following repairs, full RTP was restored later that evening. The unit continued to operate at full RTP throughout the remainder of the inspection period.

Unit 2 began the inspection period operating at 100% RTP. On April 17, the unit began an end-of-cycle coast-down in power. Unit 2 was removed from the grid on April 27 at 12:24 a.m. and the reactor shutdown at 12:37 a.m. A 24 day refueling outage (RFO-22)followed. Criticality was achieved on May 20, at 12:05 p.m. and the unit connected to the electrical grid on May 21 at 2:28 a.m. Full RTP was obtained on May 22. The Unit continued to operate at full RTP for the remainder of the inspection period.

A partial loss of off-site power occurred on May 17, at 9:04 a.m. (EN44221.) One of the two primary sources of off-site power was lost when a protective relay located in the switchyard mechanically failed de-energizing Bus 5 and the A and B reserve station transformers (40A3.)

REACTOR SAFETY

Cornerstones: Initiating Events, Mitigating Systems, Barrier Integrity

==1R01 Adverse Weather Protection

a. Inspection Scope

==

The inspectors reviewed the licensees preparations for seasonal hot weather and the readiness of the off-site and alternate AC power systems for the high grid loading summer season. The inspection focused on verification of design features and implementation of licensee procedures for extreme hot weather conditions. The mitigating systems reviewed during this inspection include: auxiliary feedwater, emergency diesel generators, emergency switch gear rooms, the alternate AC diesel generator, and emergency battery rooms. The inspection consisted of discussions with select operations staff; review of applicable licensee documents, procedures, surveillance tests, and walkdowns of the selected mitigating systems and key structures (i.e. the turbine and auxiliary buildings, safeguards buildings, fire pump house, and the high and low level intake structures). Procedures associated with grid stability and communication and coordination with the grid operator were also reviewed. The procedures and associated actions for grid disturbances were discussed with operations personnel.

b. Findings

No findings of significance were identified.

==1R04 Equipment Alignment

==

.1 Partial System Walkdown

a. Inspection Scope

The inspectors walked down critical portions of the five risk-significant systems listed below to verify the systems were correctly aligned to perform their designated safety function. The walkdowns occurred following realignment after an extended system outage (RFO 22) prior to Unit 2 startup. The positions of critical valves, breakers, and control switches, required for system operability, were verified in the correct configuration by field observation and/or review of the main control board. To ascertain the required system configuration, the inspectors reviewed plant procedures, system drawings, the UFSAR, and the Technical Specifications. References used for this review are listed in the attachment to this report. The inspectors reviewed Dominions corrective action program to verify that equipment alignment problems were being identified and properly resolved.

  • Unit 2 inside recirculation spray system,
  • Unit 2 outside recirculation spray system, and
  • Unit 2 low head safety injection system.

b. Findings

No findings of significance were identified.

.2 Complete System Walkdown

a. Inspection Scope

The inspectors performed a detailed walkdown of the Unit 1 auxiliary feedwater (AFW)system and steam supply to the turbine drive auxiliary feedwater (TDAFW) pump. The purpose of this inspection was to verify the AFW system was properly aligned, capable of performing its safety function, and to assess the material condition of the system.

During the walkdown, the inspectors verified valve and breaker positions were in the proper alignment, component labeling was accurate, hangers and supports were functional, and valves were locked as required. The plant health report, plant issues documents, condition reports, the UFSAR, and Technical Specifications were reviewed.

Outstanding plant issues and system deficiencies were verified to be properly classified and not affect the capability of the system to perform its safety function. The documents reviewed are listed in the Attachment of this report.

b. Findings

No findings of significance were identified.

==1R05 Fire Protection

==

.1 Quarterly Fire Protection Tours

a. Inspection Scope

The inspectors performed a defense-in-depth review for the seven areas identified below by walkdowns and review of licensee documents to evaluate the fire protection program operational status and material condition and the adequacy of:

(1) control of transient combustibles and ignition sources;
(2) fire detection and suppression capability; (3)passive fire protection features;
(4) compensatory measures established for out-of-service, degraded or inoperable fire protection equipment, systems, or features; and (5)procedures, equipment, fire barriers, and systems so that the post-fire capability to safely shut down the plant is ensured. The inspectors reviewed the corrective action program to verify fire protection deficiencies were being identified and properly resolved. The references used for this review are listed in the attachment to this report.
  • Fire Zone 1, Unit 1 cable vault,
  • Fire Zone 2, Unit 2 cable vault,
  • Fire Zone 16, Unit 2 containment,
  • Fire Zone 31, Unit 2 turbine building,
  • Fire Zone 64, black battery building,
  • Fire Zone 69, alternate AC diesel generator building, and

b. Findings

No findings of significance were identified.

.2 Annual Fire Protection - Drill Observation

a. Inspection Scope

The inspectors observed the fire brigade respond to a reported fire on the first floor of the administration service building on May 14, 2008. The inspectors verified that the station fire alarm was sounded, that announcements were clear and properly identified the fires location; that the brigades response was timely, and that all required responders were present with the required turnout gear. Additional breathing air bottles were promptly brought to the scene. The inspector verified that the scene leader demonstrated command and control, was in possession of the firefighting strategy for the area, and communicated effectively with brigade members and the main control room. A thermal imaging device was available on scene and utilized to verify that a fire did not exist above the dropped ceiling. Visual inspections were also performed in areas with the strongest smoke odor. The inspector verified that the fire brigade identified the cause of the smoke and established a re-flash watch. The smoke was generated from insulation and oil that was exposed to hot work performed on the buildings roof and drawn into the buildings ventilation system.

The inspectors observed the fire brigade drill held on May 30, 2008, to evaluate the readiness of the licensees personnel to fight fires. Specific aspects evaluated were: the number of individuals assigned to the fire brigade; response timeliness; use of protective clothing and self contained breathing apparatus; control room response including, identification of the fires location; dispatch of the fire brigade; sounding of alarms; brigade team leaders command and control, use of pre-fire plan strategies, briefs, and delegation of assignments; fire hose deployment and reach; approach into the fire area; effectiveness of communications among the fire brigade members and the control room; sufficiency of fire fighting equipment brought to the fire scene; search for victims; effective smoke removal; and the drill objectives and acceptance criteria. The inspectors observed the post drill critique and verified noted deficiencies were captured.

b. Findings

No findings of significance were identified.

==1R07 Heat Sink Performance (Triennial Review)

a. Inspection Scope

==

From June 23 to June 27, 2008, the inspectors reviewed documentation and performed plant walkdowns for a sample of risk significant heat exchangers (HXs) to ensure that deficiencies that could mask or degrade performance were identified and corrected. The inspectors also verified that HX testing, monitoring, and maintenance activities were consistent with Generic Letter (GL) 89-13 licensee commitments, and industry guidelines. The inspectors selected the following HXs to review:

  • Unit 1 component cooling water HX 1D,
  • Unit 2 charging pump lubricating oil coolers 5A and 5B,
  • Unit 1 charging pump intermediate seal cooler 1B,
  • Unit 1 recirculation spray (RS) system HXs 1A, 1B, 1C, and 1D,
  • Unit 2 RS system HXs 1A, 1B, 1C, and 1D, and

For the HXs listed above, the inspectors reviewed, as applicable, the performance testing methodology and results, basis for acceptance criteria, frequency of performance monitoring, inspection/cleaning methods and results, HX cleaning and replacement schedules, susceptibility to water hammer, periodic flow testing for infrequently used HXs, tube plugging history, and eddy current/visual inspection records. In addition, the inspectors conducted a walkdown of the accessible HXs to assess general material condition and to identify any degraded conditions.

The inspectors also reviewed the general health of the ultimate heat sink (UHS) and its subcomponents via review of design basis documents, engineering evaluations, system health reports, intake screen inspection results, performance testing of safety related components, safety related buried piping inspections (crawl through inspections of RS and SW piping) and repairs, SW intake pipe diver inspections, intake canal inspection procedures, third party intake canal inspection results, through-wall piping leak history, intake canal instrumentation testing procedures, adverse weather procedures, and discussions with service water system engineers. These documents were reviewed to verify design basis were maintained and to verify adequate SW system performance under current preventive maintenance, inspections, and frequencies. The UHS subcomponents selected for performance testing review were:

  • charging pump service water pumps: 2-SW-P-10A, 2-SW-P-10B, 1-SW-P-10A, and 1-SW-P-1-B,

-100C, -106C, -100D, and -106D (Leak Testing),

  • Unit 1 SW system valves: 1-SW-MOV-101A, -101B, 1-SW-25, -27, -29, -31, -

33, -35, -37, and -39 (Leak Testing), and

  • Unit 1 SW system valves: 1-SW-MOV-102A and 1-SW-MOV-102B (Inservice Testing).

In addition, the inspectors performed a walkdown of the service water intake structure and service water system to assess general material condition and proper operation.

Finally, the inspectors reviewed Corrective Action Program documents to verify that industry operating experience, potential common cause problems, and problems which could affect system performance was entered into the corrective action program for evaluation and resolution.

b. Findings

No findings of significance were identified.

==1R08 Inservice Inspection (ISI) Activities (IP 71111.08P, Unit 2)

==

.1 Non-Destructive Examination (NDE) Activities and Welding Activities

a. Inspection Scope

From May 5 to May 16, the inspectors reviewed the implementation of the licensees In-service Inspection (ISI) program for monitoring degradation of the reactor coolant system (RCS) boundary and risk significant piping boundaries. The inspectors activities consisted of an on-site review of NDE and welding activities to evaluate compliance with the applicable edition of the American Society of Mechanical Engineers (ASME) Boiler and Pressure Vessel Code (BPVC),Section XI (Code of record: 1998 Edition with 2000 Addenda), and to verify that indications and defects (if present) were appropriately evaluated and dispositioned in accordance with the requirements of the ASME Code,Section XI acceptance standards.

The inspectors review of NDE activities specifically covered examination procedures, NDE reports, equipment and consumables certification records, personnel qualification records, and calibration reports (as applicable) for the following examinations:

  • Ultrasonic (UT) examination of weld 4-RC-314/1-06, Reactor Coolant System A-Loop, ASME Class 1, 4-inch diameter pipe-to-elbow (Risk Informed ISI). The inspectors directly observed this examination, including equipment calibration.
  • UT examination of weld 6-SI-249/2-14, Safety Injection System, ASME Class 2, 6-inch diameter pipe-to-elbow (Augmented ISI)
  • UT examination of weld 3-CH-371/0-09, Charging System, ASME Class 2, 3-inch diameter pipe-to-elbow (Section XI ISI)
  • Visual examination (VT-2) of Reactor Vessel Bottom Mounted Instrumentation nozzles, ASME Class 1 (Augmented ISI)

The inspectors also reviewed documentation for the following indications, which were accepted for continuous service:

  • Fracture mechanics analysis for an UT relevant indication in Weld 2-15, Reactor Vessel to C Inlet Nozzle, ASME Class 1, 10-Yr Reactor Vessel ISI, May 2005

The inspectors review of welding activities specifically covered the welding activity listed below in order to evaluate compliance with procedures and the ASME Code. The inspectors reviewed the work order, repair and replacement plan, weld data sheets, welding procedures, procedure qualification records, welder qualification records, and NDE reports.

  • Mark No. 02-RS-PP-10.00-RS-PIPE-109-153; Welds 1-07A, 1-08A, and 1-09A; Replacement of pipe section in Recirculation Spray System; ASME Class 2; 10-inch diameter pipe

b. Findings

No findings of significance were identified.

.2 PWR Vessel Upper Head Penetration (VUHP) Inspection Activities

a. Inspection Scope

The inspectors reviewed the licensees activities relative to the Bare Metal Visual examination of the reactor pressure vessel upper head (RPVUH) nozzles and the visual examination to identify potential boric acid leaks from pressure-retaining components above the RPVUH. These activities were reviewed to verify licensee compliance with the regulatory requirements of NRC Order EA-03-009 Modifying Licenses dated February 20, 2004. The inspectors specifically reviewed BMV examination procedures, final BMV examination report and disposition of indications, personnel training and qualification records, final image electronic report, a sample of examination videos, and reports for the visual inspection of pressure retaining components above the head performed every outage. In addition, the inspectors reviewed the licensees RPVUH Effective Degradation Years calculation to ensure it had been performed and updated in accordance with the NRC Order.

b. Findings

No findings of significance were identified.

.3 Boric Acid Corrosion Control (BACC) Inspection Activities

a. Inspection Scope

The inspectors reviewed the licensees BACC program activities to ensure implementation with commitments made in response to NRC Generic Letter 88-05, Boric Acid Corrosion of Carbon Steel Reactor Pressure Boundary, and applicable industry guidance documents. Specifically, the inspectors performed an on-site record review of procedures and the results of the licensees containment walk-down inspections performed during the Unit 2 Spring 2008 outage. The inspectors also interviewed the BACC program owner and conducted an independent walk-down of the reactor building to evaluate compliance with licensees BACC program requirements and verify that degraded or non-conforming conditions, such as boric acid leaks identified during the containment walk-down, were properly identified and corrected in accordance with the licensees BACC and Corrective Action Programs.

The inspectors reviewed a sample of engineering evaluations completed for evidence of boric acid found on systems containing borated water to verify that the minimum design code required section thickness had been maintained for the affected components. The inspectors selected the following evaluations for review:

b. Findings

No findings of significance were identified.

.4 Steam Generator (SG) Tube Inspection Activities

a. Inspection Scope

The inspectors reviewed the eddy current testing (ECT) activities of Unit 2 A, B, and C SGs tubes to ensure compliance with Technical Specifications (TS), applicable industry standards, SG Program Procedures, and ASME Code Section XI requirements.

The inspectors reviewed examination status reports and discussed them with the site lead Level III analyst to ensure that all tubes with relevant indications were appropriately screened for in-situ pressure testing. None of the SG tubes met the criteria for in-situ pressure testing. The inspectors also reviewed the last Condition Monitoring and Operational Assessment report in conjunction with the inspection status reports to assess the licensee prediction capability for maximum tube degradation. In addition, the inspectors reviewed the latest Degradation Assessment report to identify the scope of the inspection and verify it addressed potential degradation areas, plant specific degradation history, and applicable operating experience. The inspectors verified that appropriate inspection scope expansion criteria were applied based on inspection results of active and new degradation mechanisms.

Furthermore, the inspectors reviewed licensee procedures for tube repair by plugging to verify that repair methods were approved and in accordance with Quality Assurance requirements. In relation to the tube repair methods, the inspectors reviewed the licensees implementation of the tube repair criteria to ensure it was consistent with plant TS. The inspectors also reviewed licensee actions in response to primary to secondary leakage; however no primary to secondary leakage was identified during the previous operating cycle. Additionally, the inspectors reviewed documentation to ensure that data analysts, ECT probes, and equipment configurations were qualified to detect the expected types of SG tube degradation. The inspectors selected a sample of site-specific Examination Technique Specification Sheets (ETSS) to ensure that their qualification was consistent with industry standards. The inspectors also directly observed data acquisition for tubes R41C31, R42C30, R13C90, R13C91, R39C31, R40C30, R5C92, and R4C93 in SG A; and tube R40C69 in SG B. The inspectors reviewed ECT data with a qualified analyst for tubes R18C7, R6C29, and R2C48 in SG A; tubes R24C57, R22C64, and R24C67 in SG B; and tubes R40C33, R39C55, R3C35, and R1C38 in SG C. Finally, the inspectors discussed with plant personnel the status of foreign object search and recovery (FOSAR) in response to ECT indications of potential loose parts in the secondary side.

b. Findings

No findings of significance were identified.

.5 Identification and Resolution of Problems

a. Inspection Scope

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

b. Findings

No findings of significance were identified.

==1R11 Licensed Operator Requalification Program

==

.1 Resident Inspector Quarterly Review

a. Inspection Scope

The inspectors observed a licensed operator simulator exam given on June 3, 2008.

The exam was administered using scenario RQ-08.3-SP-1, Revision 0, and involved both operational transients and design basis events. The inspector verified that simulator conditions were consistent with the scenario and reflected the actual plant configuration (i.e., simulator fidelity). The inspector observed the crews performance to determine whether the crew met the scenario objectives; accomplished the critical tasks; demonstrated the ability to take timely action in a safe direction and to prioritize, interpret, and verify alarms; demonstrated proper use of alarm response, abnormal, and emergency operating procedures; demonstrated proper command and control; communicated effectively; and appropriately classified events per the emergency plan.

The inspector observed the evaluators post scenario critique and confirmed items for improvement were identified and discussed with the operators to further enhance performance.

b. Findings

No findings of significance were identified.

==1R12 Maintenance Effectiveness

a. Inspection Scope

==

For the three equipment issues described in the Condition Reports (CRs) 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 associated circumstances, evaluated the extent of condition reviews, as required, and reviewed the generic implications of the equipment and/or work practice problem. Inspectors performed walkdowns 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 the Maintenance Rule (10 CFR 50.65), VPAP 0815 Maintenance Rule Program, and the Surry Maintenance Rule Scoping and Performance Criteria Matrix.

  • CRs 097222, 097333; 1-S-F-58A tripped on low air flow,
  • CR 089923; #2 EDG engine stop time delay (ESTD) relay failure,
  • CRs 092592,093214, 093384, 093526, 091321, and 091454; component cooling water heat exchangers and charging pump lube oil cooler fouling due to service water silting and biofouling.

b. Findings

No findings of significance were identified.

==1R13 Maintenance Risk Assessments and Emergent Work Control

a. Inspection Scope

==

The inspectors evaluated the following attributes for the selected systems, structures, and components (SSCs) and activities listed below:

(1) the effectiveness of the risk assessments performed before maintenance activities were conducted;
(2) the management of the assessed risk;
(3) that upon identification of an unforeseen situation, necessary steps were taken to plan and control the resulting emergent work activities; and
(4) that maintenance risk assessments and emergent work problems were adequately identified and resolved.
  • April 17, 2008; Unit 1 shutdown risk and Unit 2 on-line risk conditions for emergent work to repair the Unit 2 6B feed water heater.
  • April 28, 2008; Unit 1 on-line and Unit 2 shutdown risk conditions (Green) for the issued tornado warning and watch.
  • April 29, 2008; Unit 2 elevated shutdown risk condition (Orange) for J bus testing.
  • April 30, 2008; Unit 2 elevated shutdown risk condition (Orange) for H bus testing.
  • May 9, 2008; Unit 1 on-line elevated risk condition (Orange) and Unit 2 elevated shutdown risk condition (Yellow) for the issued tornado warning and watch.
  • May 17, 2008; Unit 1 on-line elevated risk condition (Orange) and Unit 2 elevated shutdown risk condition (Yellow) for a loss of off-site power to the A and B reserve station transformers due to a protective relay failure.

b. Findings

No findings of significance were identified.

==1R15 Operability Evaluations

a. Inspection Scope

==

The inspectors reviewed the operability evaluations listed below affecting risk significant systems, to assess, as appropriate:

(1) the technical adequacy of the evaluations; (2)whether continued system operability was warranted;
(3) whether other existing degraded conditions were considered;
(4) if compensatory measures were involved, whether the compensatory measures were in place, would work as intended, and were appropriately controlled; and
(5) where continued operability was considered unjustified the impact on Technical Specification Limiting Condition for Operation. Documents reviewed are listed in the Attachment to this report.
  • CR 096956, 2-RS-P-2A differential pressure unsatisfactory during 2-OPT-RS-001.
  • CR 096994, during 2-OPT-RC-10.1, a bent bolt on a support for 2-RS-E-1A was identified.
  • CR 097689, low oil levels in 1-SW-P-1A engine and angle drive.
  • CR 097154, motor amps greater than 30% above nameplate on 2-SI-MOV-2864B during MOV testing.
  • CR 100175, 1-CS-P-1A bolting does not appear to have adequate thread engagement.
  • CR 098083, non safety related monitoring components were installed in the charging pump breaker cubicles and in the emergency switch gear bus metering circuits.

b. Findings

No findings of significance were identified.

==1R19 Post-Maintenance Testing

a. Inspection Scope

==

The inspectors reviewed the post-maintenance test (PMT) procedures and/or test activities, as appropriate, for selected risk significant systems to assess whether: (1)plant testing had been adequately addressed by control room and/or engineering personnel;

(2) testing was adequate for the maintenance performed;
(3) acceptance criteria were clear and adequately demonstrated operational readiness consistent with design and licensing basis documents;
(4) test instrumentation had current calibrations, range, and accuracy consistent with the application;
(5) tests were performed as written with applicable prerequisites satisfied;
(6) jumpers installed or leads lifted were properly controlled;
(7) test equipment was removed following testing; and
(8) equipment was returned to the status required to perform its safety function. The inspectors observed post maintenance testing and/or reviewed the results for the following work items:

38078388607, 38078388603, 0078388604, 0078388608, 38078388601, 38078388605, 0078388602;

  • Repair / replacement of safety injection check valves (02-SI-241-CKVALV, 02-SI-242-CKVALV, 02-SI-94-CKVALV, 02-SI-243-CKVALV, and 02-SI-130-CKVALV);

WOs 0076104101, 38102312162, 007610401, 38076818701, 0076149501;

  • TDAFW pump overhaul; WOs 38102343447, 38077293501, 38073520501;
  • Pressurizer power operated relief valve 02-RC-PCV-2455C refurbishment; WOs 38102283947, 38102257267, 38102181804, 38102336704;
  • Pressurizer power operated relief valve block valve 02-RC-PCV-2456 refurbishment; WOs 38076735301, 38077300001, 38076735302;
  • Unit 2 Containment equipment hatch.

b. Findings

No findings of significance were identified.

==1R20 Refueling and Other Outage Activities

==

.1 Unit 1 Forced Outage

a. Inspection Scope

A forced outage was conducted from April 16 - 21, 2008, to repair excessive tube leakage in the Unit 1 6th point feedwater heater (1-FW-6B.) The inspectors observed evolutions to shutdown the reactor and place the unit into an Intermediate Shutdown Mode, a hot condition (i.e. > 200°F). The inspectors verified Technical Specification (TS)cooldown limits were not exceeded, and on a sampling basis, verified plant risk assessments were accurate, and that TS requirements for Mode changes were met.

Licensee calculations for shutdown margin and the estimated position for criticality were reviewed and checked against independent calculations performed by the inspector.

Evolutions to startup and place the Unit on-line were observed by the inspectors and on a sampling basis Technical Specification (TS) requirements associated with the Mode changes were verified. TS plant heat-up limits were verified. No work was performed in containment during the forced outage.

b. Findings

No findings of significance were identified.

.2 Unit 2 Refueling Outage

a. Inspection Scope

The inspectors performed the activities described below for the Unit 2 Refueling Outage (RFO) that began on April 27 and ended May 22, 2008.

Review of Outage Plan:

Prior to the outage, the inspectors reviewed the Surry Unit 2 2008 RFO Shutdown Risk Review Report to verify the licensee had appropriately considered risk, industry operating experience, and previous site specific problems.

The inspector verified the outage impact on defense-in-depth for the five shutdown critical safety functions; electrical power availability, inventory control, decay heat removal, reactivity control, and containment; had been appropriately considered and that the Licensee had planned to provide adequate defense-in-depth for each safety function or had established contingencies to minimize the overall risk where redundancy was limited or not available.

On a routine basis, the inspectors reviewed the refueling outage work plan and daily shutdown risk assessments. Periodic updates to the Surry Unit 2 2008 RFO Shutdown Risk Review Report, accounting for schedule changes and unplanned activities, were also reviewed. Reviews focused on verifying that adequate defense-in-depth was provided for each safety function and/or the Licensee implemented planned contingencies to minimize the overall risk where redundancy was limited or not available.

Detailed risk reviews for specific high risk periods/activities are documented in section

==1R13 of this report.

Monitoring of Shutdown Activities:

==

The inspectors observed performance of portions of the reactor shutdown and plant cooldown to assess operator performance with respect to communications, command and control, procedure adherence, and compliance with Technical Specification cooldown limits. Upon shutdown, the inspectors conducted a thorough containment walkdown to identify structures, piping, and supports in containment with stains or deposited material that could indicate previously unidentified leakage from components containing reactor coolant and/or signs of physical damage.

Licensee control of Outage Activities:

Clearance Activities - The inspectors reviewed a sample of risk significant clearance activities and verified tags were properly hung and/or removed, equipment was appropriately configured per the clearance requirement, and that the clearance did not impact equipment credited to meet the shutdown critical safety functions.

Reactor Coolant System Instrumentation - The inspectors periodically observed and verified by diverse means that associated instruments were functioning properly for the reactor/refueling cavity and spent fuel pool (SFP) water level, the reactor coolant and spent fuel pool temperature, and the operating residual heat removal system

Electrical Power - The inspectors verified that the status of electrical systems met TS requirements and the licensees outage risk control plan. The inspectors verified that compensatory measures were implemented when electrical power supplies were impacted by outage work activities. The inspectors verified that credited backup power supplies were available.

Residual Heat Removal and SFP System Monitoring - The inspectors observed the SFP cooling and reactor RHR system status and operating parameters to verify that the cooling systems operated properly. Verification included periodic review of the SFP and reactor cavity level, temperature, and RHR system flow.

Inventory Control - The inspectors reviewed actions to establish, monitor, and maintain the proper water inventory in the reactor vessel/cavity and spent fuel pool. The inspectors reviewed the plant system flow paths and configurations established for reactor makeup and verified the configurations were consistent with the outage plan.

Reactivity Control - The inspectors reviewed the outage risk plan to verify that activities, systems, and/or components which could cause unexpected reactivity changes were identified and controlled accordingly.

Foreign Material Exclusion (FME) - The inspectors reviewed implementation of licensee procedures for FME control for the open reactor vessel, reactor cavity, and SFP.

Containment Closure - The inspectors reviewed activities during the outage to control containment penetrations and to maintain the capability to achieve containment closure in accordance with the refueling operations technical specifications. Periodic tours of containment were performed to review the control of work activities and containment conditions.

Problem Identification and Resolution - The inspectors verified the licensee was identifying outage related issues and had entered them into the corrective action program.

Control of Heavy Loads

In response to operational experience concerns regarding reactor vessel head lifts (NRC Operating Experience Smart Sample FY2007-03), the inspectors verified station procedures for heavy load lifts were consistent with guidance in the Nuclear Energy Institutes (NEI) formal initiative to ensure that heavy load lifts are conducted safely. The inspectors reviewed Dominions actions to manage the increased risk during these activities and observed the heavy load lifts for the Unit 2 reactor vessel head removal and reinstallation. The inspectors reviewed the procedures for the heavy load lifts involving the reactor coolant and residual heat removal pump motors.

Refueling Activities:

The inspectors, on a sampling basis, verified the requirements of TS 3.10, Refueling, were met, and that refueling activities were conducted in accordance with station procedures. Activities were monitored from the control room and refueling bridge at various times while fuel handling activities were in progress to observe the communications and coordination between personnel and to verify core reactivity was controlled and fuel movement was accomplished and tracked in accordance with the fuel movement schedule. The inspectors observed portions of the core mapping evolution and watched the video recording of the core verification to independently verify the as-loaded core configuration matched the designed core reload configuration for Unit 2 cycle 22.

Monitoring of Heat-up and Startup Activities:

Prior to startup, the inspectors examined the spaces inside the containment building to verify that debris had not been left which could affect performance of the containment sumps. On a sampling basis the inspectors verified that technical specification, license conditions, and other requirements, commitments, and administrative procedure prerequisites were met for changes in plant configurations/modes. To monitor restart activities, the inspectors performed control room observations, plant walkdowns, and reviewed main control board indicators, operator logs, plant computer information, and station procedures. Control room observations included the approach to criticality, critical operations, low power physics testing, and the synchronization of the main turbine generator to the electrical grid.

b. Findings

No findings of significance were identified.

==1R22 Surveillance Testing

a. Inspection Scope

==

The inspectors witnessed surveillance tests and/or reviewed test data for the risk-significant activities listed below to assess, as appropriate, whether the SSCs met TS, the UFSAR, and licensee procedural requirements. The inspectors also determined if the testing effectively demonstrated that the SSCs were ready and capable of performing their intended safety functions.

Surveillance Tests:

  • 1-OP-RX-004, Rev. 19; The Calculation of Estimated Critical Conditions
  • 2-NPT-RX-008, Rev. 19, Startup Physics Testing

In-service Tests:

  • 2-OPT-RS-001, Rev. 18; Containment Outside Recirculation Spray Pumps Flow and Leak Test
  • 2-OPT-RH-003, Rev. 11; RHR System Operability Test

Containment Penetration Type C Leak Test:

b. Findings

No findings of significance were identified.

Cornerstone: Emergency Preparedness

1EP6 Drill Evaluation

a. Inspection Scope

The inspector observed operator simulator training conducted on June 3, 2008, to assess the licensees performance in the risk significant performance standards of emergency classification, protective action recommendations, and off-site notification.

This drill evaluation is included in the Emergency Response Performance Indicator statistics.

b. Findings

No findings of significance were identified.

OTHER ACTIVITIES

4OA1 Performance Indicator Verification

a. Inspection Scope

The inspectors performed a periodic review of the following Unit 1 and 2 performance indicators (PI) to assess the accuracy and completeness of the submitted data and whether the performance indicators were calculated in accordance with the guidance contained in NEI 99-02, Regulatory Assessment Performance Indicator Guideline.

Specifically, the inspectors reviewed the PI indicator data for the third quarter 2007 through the first quarter 2008. Documents reviewed included applicable monthly operating reports, licensee even reports, operator and chemistry department logs, LERs, and NRC inspection reports. The inspectors observed licensee personnel draw and analyze a daily RCS sample for Units 1 and 2.

Mitigating Systems Cornerstone

  • Safety System Functional Failures (SSFF)

Barrier Integrity Cornerstone

b. Findings

No findings of significance were identified.

4OA2 Identification and Resolution of Problems

.1 Daily Reviews of Items Entered into the Corrective Action Program:

a. Inspection Scope

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

and in order to help identify repetitive, long-term, or latent equipment failures, or specific human performance issues for follow-up; the inspectors performed a daily screening of items entered into Dominions corrective action program. This review was accomplished by reviewing either hard copies of each condition report, attending daily screening meetings, and/or accessing and reviewing the licensees computerized database.

b. Findings

No findings of significance were identified.

.2 Semi-Annual Trend Review

a. Inspection Scope

A semi-annual review of plant issues was performed for the period January - June, 2008, to identify trends that might indicate the existence of a more significant safety issue.

Included within the scope of this review are repetitive or closely related issues which may have been captured outside the normal corrective action program, such as in trend reports, plant performance indicators, major equipment problem lists or equipment reliability program reports, repetitive rework maintenance lists, challenge lists, system health reports, workaround lists, maintenance rule assessments, and self assessments.

b.

Assessment and Observations

One finding of significance was identified regarding service water fouling and is discussed in the Focused PI&R Review documented in Section 4OA2 below. Other negative trends noted were in configuration control, administrative control of overtime, and radiation process monitor 2-RM-RI-259/260 issues.

.3 Focus PI&R Review:

Service Water System Fouling

a. Inspection Scope

The inspectors performed an in-depth PI&R review of the service water (SW) fouling issues that occurred from January to June, 2008. This inspection focused on the component cooling (CC) heat exchangers (HX) and charging pump lube oil coolers and associated temperature control valves (TCV). This issue was selected for review because of the potential common mode failure of the high head safety injection charging pumps, and its potential to adversely impact the two cooling mechanisms for the reactor coolant pump seals and the residual heat removal system.

The inspectors, on a sampling basis, reviewed pictures taken by engineering personnel of the degree of CCHX fouling; visually inspected the CCHXs and lube oil cooler 2-CH-E-5C, while open for cleaning; reviewed Root Cause Evaluations (RCE) 000223 and S-2006-1372; Apparent Cause Evaluations (ACE) 13823 and 13684; searched the condition reporting (CR) and plant issues (PI) systems from 1998-2008; and reviewed related CRs; and interviewed licensee personnel. The inspectors assessed licensee performance in addressing each of the following attributes:

  • complete and accurate identification of the problem in a timely manner,
  • evaluation and disposition of operability / reportability issues,
  • consideration of extent of condition, generic implications, common cause, and previous occurrences,
  • classification and prioritization of the resolution of the problem commensurate with its safety significance,
  • identification of root and contributing causes of the problem,
  • identification of corrective actions which are appropriately focused to correct the problem,
  • completion of corrective actions in a timely manner commensurate with the safety significance of the issue, and
  • implementation of interim corrective actions and /or compensatory measures to minimize the problem and/or mitigate its effects, until permanent action can be implemented.

b. Findings

No findings of significance were identified.

4OA3 Event Follow-up

.1 Unit 1 Manual Reactor Trip

a. Inspection Scope

The inspectors reviewed the plant response and operator performance for the Unit 1 manual reactor trip on April 20, 2008 at 10:16 pm. The Unit was tripped from 37% power due to high vibrations on the main turbine generator. Inspectors reviewed the licensees post trip report including operator logs and written statements, the alarm summary printout, plant computer data, and the associated completed procedures utilized during the event. The inspection objectives were to verify safety equipment responded properly, the plant responded as expected, and that the trip was not the result of or complicated by a human performance error.

b. Findings

No findings of significance were identified.

.2 Loss of Off-Site Power

a. Inspection Scope

The inspectors reviewed the plant response and operator performance for the partial loss of off-site power event that occurred on May 17, 2008, at 9:04 a.m. The inspectors responded to the control room and verified plant conditions were stable for both Units; walked down the switchyard and discussed the relay failure with transmission personnel; verified applicable reportability and event classification requirements; reviewed technical specifications, station logs, electrical drawings, and the 10CFR 50.72 notification; and interviewed operations personnel.

One of two primary sources of off-site power was lost when a protective relay located in the switchyard mechanically failed and tripped open circuit breaker L104 and de-energized Bus 5 and the A and B reserve station transformers (RSST). Unit 1s safety bus 1H and Unit 2s safety bus 2J de-energized momentarily until repowered by the emergency diesel generators (EDG) that auto started on the loss of off-site power. EDG

  1. 2 re-powered safety bus 2J and EDG #3 re-powered safety bus 1H. Safety buses 1J and 2H remained energized during the event via Bus 6 and the C RSST, which remained powered from the second source of primary off-site power. During the event, Unit 1 remained at 100% RTP and Unit 2 remained on shutdown cooling. Off-site power to Bus 5 and the A and B RSSTs was restored at approximately 11:30 a.m. The inspectors responded to the control room and verified plant conditions were stable for both Units.

The inspectors walked down the switchyard and discussed the relay failure with transmission personnel; verified applicable reportability and event classification requirements; reviewed technical specifications, station logs, electrical drawings, the 10CFR 50.72 notification, and interviewed operations personnel.

b. Findings

No findings of significance were identified.

4OA5 Other Activities

.1 NRC Temporary Instruction (TI) 2515/172, Reactor Coolant System Dissimilar Metal Butt

Welds (DMBWs).

a. Inspection Scope

From June 23 to June 27, 2008, the inspectors performed an in-office review of the licensees activities related to the inspection and mitigation of dissimilar metal butt welds in the Reactor Coolant System (RCS). The inspection included a review of design change packages, work orders, procedures, drawings and other documents to ensure that the licensee activities were consistent with the industry requirements established in the Materials and Reliability Program (MRP) document MRP-139, Primary System Piping Butt Weld Inspection and Evaluation Guidelines, July 2005. The response to specific TI questions is contained in Attachment 1 to this report.

b. Findings and Observations

No findings of significance were identified.

.2 NRC Temporary Instruction (TI) 2515/166, Pressurized Water Reactor Containment

Sump Blockage (NRC Generic Letter 2004-02) Unit 2.

a. Inspection Scope

The inspectors verified the implementation of the licensees commitments documented in their September 1, 2005, response (serial No.05-212) to Generic Letter 2004-02, Potential Impact of Debris Blockage on Emergency Recirculation During Design Basis Accidents at Pressurized Water Reactors. The commitments, referenced as corrective actions in the response, included plant modifications and procedure changes.

Modifications included In-core sump room drain modifications, changing recirculation spray pumps start initiation from a time delay function to a RWST level function, piping Insulation Modifications (installation of design basis accident (DBA) qualified jacketing on calcium-silicate insulation and repair of damaged insulation), and modified containment sump strainer installation. Corrective action commitments also included program controls to assure the assumptions regarding post loss of coolant accident (LOCA)debris generation and transport remain valid.

This inspection included review of the sump screen assembly installation procedure, 10 CFR 50.59 evaluations for GSI-191 related modifications, structural debris loading calculation, and validation testing of the modified sump screen design. The inspector also reviewed the foreign materials exclusion controls and the completed Quality Assurance / Quality Control records for the screen assembly installation. The inspector reviewed the resolution of problems identified in condition reports for the Unit 2 modifications. A walkdown was performed to verify the screen assembly configuration being installed was consistent with drawings and the tested configuration. The installation work documentation was reviewed to verify that quality control inspections were accomplished as required. The response to specific TI questions is contained in 2 to this report.

b. Findings and Observations

No findings of significance were identified.

.3 Quarterly Resident Inspector Observations of Security Personnel and Activities

a. Inspection Scope

During the inspection period, inspectors toured and observed security personnel conducting their assigned activities. These observations were performed to ensure that personnel were attentive, cognizant of their responsibilities, and to verify that the activities being performed were consistent with regulatory requirements and the licensees security procedures. Observations took place during both normal and off-normal work hours.

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

4OA6 Meetings, Including Exit

Exit Meeting Summary

On July 24, 2008, the inspection results were presented to Mr. Sloane, and other members of his staff who acknowledged the findings. The inspector asked the licensee whether any proprietary material examined during the inspection was not returned. No proprietary information was identified.

On July 31, 2008, the revised inspection results were presented to Mr. Barry Garber who acknowledged the results.

4OA7 Licensee Identified Findings

The following violation of very low significance (Green) was identified by the licensee and is a violation of NRC requirements which meet the criteria of Section VI of the NRC Enforcement Policy, NUREG-1600, for being dispositioned as an NCV.

  • TS 6.4.A requires, in part, that detailed written procedures with appropriate check-off lists and instructions be provided for normal startup, operation, and shutdown of a unit, and of all systems and components involving nuclear safety of the station. TS 6.4.D requires, in part, that all procedures specified in TS 6.4.A be followed. Contrary to the above, in the fall 2006 Refueling Outage containment close-out, the licensee had not identified the debris located in the Containment Air Recirculation Fan Duct Ring in the basement of Unit 2 Containment during the performance of procedure 2-GOP-1.7. This debris was discovered on an engineering walkdown performed on 5/9/2008 as an extent of condition for NCV 05000280/2008002-02, Failure to Follow Start-up Procedure which Resulted in Leaving Loose Fibrous Insulation in Containment. This violation was entered into the licensees corrective action program as CA024916, CR028438: SURR - Containment walkdown to verify the design input for GSI-191 project. The debris has been removed from containment. This finding is of very low safety significance because the amount of debris removed did not have the capability to overwhelm the partially installed replacement ECCS and CSS strainers.

NRC Temporary Instruction (TI) 2515/172, Reactor Coolant System Dissimilar Metal Butt Welds (DMBWs).

MRP-139 Baseline Inspections

1)

Have the baseline inspections been performed or are they scheduled to be performed in accordance with MRP-139 guidance? Were the baseline inspections of the pressurizer temperature DMBWs of the nine plants listed in TI 2515/172, 03.01.b completed during the spring 2008 outages?

The pressurizes in both units 1 & 2 do not contain any Alloy 600 material. All welds are stainless steel.

2)

Is the licensee planning to take any deviations from MRP-139 requirements?

No, the licensee has not submitted any requests for deviation from MRP-139 requirements.

Volumetric Examinations

1)

For each examination inspected, was the activity performed in accordance with the examination guidelines in MRP-139, Section 5.1, for unmitigated welds or mechanical stress improved welds and consistent with NRC staff relief request authorization for overlaid welds?

The licensee did not perform any weld overlays or mechanical stress improvement. The licensee has repaired/replaced the reactor vessel head in 2003, the reactor coolant system hot leg and cold leg RTD thermowells in 2007 for U1 and in 2008 for U2. The bottom mounted instrumentation nozzles are being inspected every refueling outage via bare metal visual and NDE every 10 years. The reactor vessel flange leakage monitor tube and the reactor vessel core guide lugs/welds are both being inspected per the ASME code. All inspections are ongoing pending industry (MRP) guidance.

2)

For each examination inspected, was the activity performed by qualified personnel?

Yes, each examination performed for the bottom mounted instrumentation nozzles, reactor vessel flange leakage monitor tube and the reactor vessel core guide lugs/welds are performed in accordance to the ASME code and with qualified personnel.

3)

For each examination inspected, was the activity performed such that deficiencies were identified, dispositioned, and resolved?

Yes, the inspectors reviewed examination reports and procedures associated with the inspections performed for the bottom mounted instrumentation nozzles, reactor vessel flange leakage monitor tube and the reactor vessel core guide lugs/welds. Based on the inspection activities, the inspectors determined that the examination was conducted in a manner such that deficiencies could be identified, dispositioned, and resolved.

Weld Overlays

The licensee has not implemented weld overlays as a mitigation method for DMBWs.

Mechanical Stress Improvement (Not Applicable)

The licensee has not implemented Mechanical Stress Improvement as a mitigation method for DMBWs.

In-service Inspection Program

1)

Has licensee prepared an MRP-139 in-service inspection program?

No, the licensee did not have a stand alone MRP-139 in-service inspection program document. The licensees MRP-139 inspection program consisted of the documents listed below, which were previously prepared documents, and the inclusion of MRP-139 requirements as augmented inspections in the ASME Section XI In-service Inspection Program (ISI Program). The inspectors reviewed the following documents and held discussions with licensee representatives.

  • ER-AA-MAT-11, Alloy 600 Management Program, Revision 2
  • Technical Report MT-0037, Identification and Evaluation of the RCS Alloy 600 Locations, June 5, 2007
  • Inservice Inspection Manual, Revision 3
  • Augmented Inservice Inspection Manual

2) Are welds appropriately categorized?

The inspectors reviewed all welds categorized at the time of the inspection for appropriate categorization in accordance with MRP-139, Section 6. Welds were appropriately categorized.

3)

Are inspection frequencies consistent with the requirements of MRP-139?

The licensee has replaced/repaired the Alloy 600 locations that would be governed by the requirements set forth in MRP-139 for both units. The remaining

locations which include the bottom mounted instrumentation nozzles, reactor vessel flange leakage monitor tube and the reactor vessel core guide lugs/welds are being inspected in accordance to the ASME code and are pending industry (MRP) guidance.

4)

What is the licensees basis for categorizing welds as H or I and plans for addressing potential PWSCC?

No welds were categorized as Categories H or I.

5)

What deviations has the licensee incorporated and what approval process was used?

No deviations to MRP-139 have been incorporated by the licensee.

Temporary Instruction (TI) 2515/166, Pressurized Water Reactor Containment Sump Blockage (NRC Generic Letter 2004-02) Unit 2

The inspectors determined the following answers to the Reporting Requirements detailed in TI 2515/166-05 issued May 16, 2007:

05.a Dominion implemented the plant modifications and procedure changes at Surry as committed to in their GL 2004-02 response for Unit 2. A list of commitments and the respective completion dates is provided below.

05.b Dominion updated Surry 2 licensing bases to reflect the corrective actions taken in response to GL 2004-02.

05.c An extension is pending for evaluation of the downstream and chemical effects analyses. These evaluations are scheduled for completion in September 2008.

The licensees actions as stated in their September 1, 2005 response to GL 2004-02 were complete at the end of the refueling outage. The following is a listing of the corrective action commitments listed in the licensees GL 2004-02 response and the current status:

1. Completion of activities described in the response related to modifications to the

containment sump. These modifications included the following:

In-core sump room drains modifications. [COMPLETE].

RWST level engineered safety feature actuation system (ESFAS) function to support GSI-191 sump modifications (recirculation spray (RS) pumps to start on RWST level instead of time delay) [COMPLETE].

Piping Insulation Modifications (installation of DBA qualified jacketing on calcium-silicate type insulation and repair of damaged insulation) [COMPLETE].

Containment sump strainer installation [COMPLETE].

2. Evaluate the adequacy of strainer design to include margin for head loss due to

chemical effects once the test results to quantify the chemical precipitant impact on head loss are known. [OPEN - extension request in progress; completion scheduled for Sep. 30, 2008].

3. Completion of any corrective actions that are shown to be necessary (for

components affected by downstream effects) as a result of these evaluations (long term wear). [OPEN - extension request in progress; scheduled to complete long term wear analysis and identify necessary corrective actions by Sep. 30, 2008].

4. Programmatic controls for containment debris sources will be put into existing

procedures as necessary to ensure the potential containment debris load is

adequately controlled to maintain the emergency core cooling system (ECCS)pump net positive suction head (NPSH) margin. [OPEN-extension request in progress; completion scheduled for Sep. 30, 2008].

5. The licensee will report the minimum NPSH margin in the SPS plant specific

license amendment request (LAR) described in item 2(e). Note that 2(e)discusses two LARs: one to change the method of starting RS pumps from timer relays to RWST level; and one to change the containment air partial pressure operation limits in TS Figure 3.9-1. [COMPLETE].

6. The licensee will submit the GOTHIC containment analysis methodology with

plant-specific analyses that support the proposed changes to TS Figure 3.8-1 and the RS pump start method via LAR. [COMPLETE].

7. The licensee will submit a revised alternate source term (AST) LOCA analysis for

Surry in December 2005 via LAR. [COMPLETE].

8. Evaluate the potential jet impingement and missile load on sump screens.

[COMPLETE].

9. Evaluate down stream flow paths to determine potential blockage due to debris

passing through strainer. [OPEN - extension request in progress; completion scheduled for Sep. 30, 2008].

TI 2515/166 is closed for Unit 2. The outstanding commitment items related to component long term wear (item 3 above), chemical effects (item 2 above), downstream effects (item 9 above), and containment debris sources were not scheduled to be completed until September 2008, via an NRC approved extension request.

This documentation of TI-2515/166 completion, as well as any results of sampling audits of licensee actions, will be reviewed by the NRC staff (Office of Nuclear Reactor Regulation - NRR) as input along with the Generic Letter (GL) 2004-02 Potential Impact of Debris Blockage on Emergency Recirculation During Design Basis Accidents at Pressurized-Water Reactors responses to support closure of GL 2004-02 and Generic Safety Issue (GSI)-191 Assessment of Debris Accumulation on Pressurized-Water Reactor (PWR) Sump Performance. The NRC will notify each licensee by letter of the results of the overall assessment as to whether GSI-191 and GL 2004-02 have been satisfactorily addressed at that licensees plant(s). Completion of TI-2515/166 does not necessarily indicate that a licensee has finished all testing and analyses needed to demonstrate the adequacy of their modifications and procedure changes. Licensees may also have obtained approval of plant specific extensions that allow for later implementation of plant modifications for which completion may subsequently be verified.

SUPPLEMENTAL INFORMATION

KEY POINTS OF CONTACT

Licensee

M. Adams, Director, Station Engineering
J. Ashley, Licensing
B. Garber, Supervisor, Licensing
K. Grover, Manager, Operations
D. Jernigan, Site Vice President
R. Johnson, Manager, Outage and Planning
L. Jones, Manager, Radiation Protection and Chemistry
T. Niemi, Licensing Engineer
C. Olson Supervisor, Station Engineering
M. Pittman, Supervisor, Engineering
R. Simmons, Manager, Maintenance
K. Sloane, Plant Manager, Nuclear
B. Stanley, Director, Station Safety and Licensing
M. Wilda, Supervisor, Station Engineering

LIST OF ITEMS OPENED, CLOSED, AND DISCUSSED

Opened

None

Opened and Closed

None

Closed

Temporary Instruction (TI) 2515/166,

Pressurized Water Reactor Containment Sump Blockage (NRC Generic Letter 2004-

2), Unit 2

Temporary Instruction (TI) 2515/172,

Reactor Coolant System Dissimilar Metal Butt Welds (DMBWs).

LIST OF DOCUMENTS REVIEWED

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