IR 05000498/2007005

IR 05000498-07-005, 05000499-07-005, on 10/06/07 - 12/31/07; South Texas Project Electric Generating Station, Units 1 and 2; Integrated Resident and Regional Report; Maintenance Effectiveness, and Identification and Resolution of Problems

ML080430717
Person / Time
Site:	South Texas
Issue date:	02/11/2008
From:	Clay Johnson NRC/RGN-IV/DRP/RPB-A
To:	Sheppard J South Texas
References
IR-07-005
Download: ML080430717 (47)

Text

ary 11, 2008

SUBJECT:

SOUTH TEXAS PROJECT ELECTRIC GENERATING STATION - NRC INTEGRATION INSPECTION REPORT 05000498/2007005 AND 05000499/2007005

Dear Mr. Sheppard:

On December 31, 2007, the U.S. Nuclear Regulatory Commission (NRC) completed an inspection at your South Texas Project Electric Generating Station, Units 1 and 2, facility. The enclosed integrated report documents the inspection findings, which were discussed on January 3, 2008, with you 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, one NRC-identified and two self-revealing findings of very low safety significance (Green) were identified, all three of which were determined to be violations. Additionally, two licensee-identified violations, which were determined to be of very low safety significance, are listed in Section 4OA7 of this report. If you contest these noncited violations, you should provide a response within 30 days of the date of this inspection report, with the basis for your denial, to the U.S. Nuclear Regulatory Commission, ATTN: Document Control Desk, Washington DC 20555-0001; with copies to the Regional Administrator, U.S.

Nuclear Regulatory Commission Region IV, 611 Ryan Plaza Drive, Suite 400, Arlington, Texas 76011-4005; the Director, Office of Enforcement, U.S. Nuclear Regulatory Commission, Washington DC 20555-0001; and the NRC Resident Inspector at South Texas Project Electric Generating Station, Units 1 and 2, facility.

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 made available electronically for public inspection

STP Nuclear Operating Company -2-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/

Claude E. Johnson, Chief Project Branch A Division of Reactor Projects Dockets: 50-498 50-499 Licenses: NPF-76 NPF-80

Enclosure:

NRC Inspection Report 05000498/2007005 and 05000499/2007005 w/Attachment: Supplemental Information

REGION IV==

Dockets: 05000498, 05000499 Licenses: NPF-76, NPF-80 Report: 05000498/2007005 and 05000499/2007005 Licensee: STP Nuclear Operating Company Facility: South Texas Project Electric Generating Station, Units 1 and 2 Location: FM 521 - 8 miles west of Wadsworth Wadsworth, Texas 77483 Dates: October 6, 2007, through December 31, 2007 Inspectors: D. Allen, Senior Resident Inspector, Comanche Peak G. Apger, Operations Engineer K. Clayton, Senior Operations Engineer R. Cohen, Resident Inspector, Columbia Generating Station J. Dixon, Senior Resident Inspector J. Drake, Senior Reactor Inspector S. Garchow, Operations Engineer S. Graves, Reactor Inspector G. Guerra, CHP, Health Physicist M. Haire, Senior Operations Engineer M. Hayes, Reactor Engineer (NSPDP)

B. Larson, Operations Engineer W. Sifre, Senior Reactor Inspector Approved By: Claude E. Johnson, Chief, Project Branch A Division of Reactor Projects Enclosure

SUMMARY OF FINDINGS

IR 05000498/2007005, 05000499/2007005; 10/06/07 - 12/31/07; South Texas Project Electric

Generating Station, Units 1 and 2; Integrated Resident and Regional Report; Maintenance Effectiveness, and Identification and Resolution of Problems.

This report covered a 3-month period of inspection by resident and regional inspectors. The inspection identified three Green findings. The significance of most findings is indicated by their color (Green, White, Yellow, or Red) using Inspection Manual Chapter 0609, Significance Determination Process. Findings for which the significance determination process does not apply may be Green or be assigned a severity level after NRC managements 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.

Cornerstone: Mitigating Systems

Green.

The inspectors reviewed a self-revealing noncited violation of 10 CFR Part 50, Appendix B, Criteria V, for the failure to follow Procedure STI 32174927, Conduct of Maintenance, Revision 5. On April 6, 2007, operations declared extended range nuclear instrument Channel NI46 inoperable due to erratic low range indications, as a result, the licensee replaced the log count rate circuit board in Slot A4 of the processor. On April 14, 2007, operations was taking shiftly logs and recognized that the startup rate channel check was approaching the limit of 0.5 decades per minute. The log count rate circuit board in Slot A4 was replaced again and it was determined that the wrong board had been installed. The licensees root cause determined that the wrong board was installed because maintenance personnel were not using appropriate reference material to ensure that the correct part was installed.

The inspectors determined that the finding was more than minor because it was associated with the Mitigating Systems cornerstone attribute of equipment and human performance, and it affected the cornerstone objective to ensure the availability of systems that respond to initiating events to prevent undesirable consequences. The inspectors evaluated the finding using Inspection Manual Chapter 0609, Appendix M, Significance Determination Process Using Qualitative Criteria, and determined that the finding screened as Green because: (1) the licensee had all power, intermediate, and source range nuclear instruments available; (2) the extended range nuclear instruments provide no protective functions other than alarms and indications; (3) the primary function is to provide indication to the operators to assess the sub-criticality critical safety function, and this was only impacted in the Yellow path; (4) the Updated Final Safety Analysis Report does not take credit for the extended range nuclear instruments except to provide the operators with a minimum of 15 minutes to respond to a dilution event pending a loss of shutdown margin; and (5) very low likelihood that shutdown margin would be challenged post trip. This finding also had human performance crosscutting aspects associated with work practices, in that, the licensee did not effectively communicate human error prevention techniques such as self and peer checking H.4(a), and maintenance personnel did not verify the replacement part using controlled documentation (Section 1R12).

Green.

The inspectors reviewed a self-revealing noncited violation of 10 CFR Part 50, Appendix B, Criteria V, for an inadequate procedure for testing safety-related solenoid valves that operate the steam dump valves. On December 18, 2006, during troubleshooting activities on Unit 1 to investigate the unexpected response of steam dump Valve N1MSPV7489, the licensee discovered that the safety-related solenoid valve instrument air line connections were crossed, such that the steam dump valve would not close. The licensee had incorrectly connected the instrument air lines in April 1999, and they also identified that they missed several opportunities to identify and correct this condition. The licensee determined that the maintenance procedure for the safety-related solenoid valves was inadequate because it only tested the function of the solenoid, electrical connection, and not the operation of the steam dump valve, instrument air line connection. As part of the corrective actions the licensee corrected the cross connection of the instrument air lines, walked down the other steam dump safety-related solenoid valves, and changed the maintenance procedure.

This finding is more than minor because it affected the Mitigating Systems cornerstone attribute of procedural quality and the objective of ensuring the availability and reliability of systems that respond to initiating events to prevent undesirable consequences. Using the Significance Determination Process Phase 1 worksheets, this finding was determined to have very low safety significance (Green) because it did not result in the actual loss of safety function of one or more non-Technical Specification trains of equipment for greater than 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> and it did not screen as risk significant due to seismic, flooding, or severe weather. This issue had no crosscutting aspects because the cross connection of the instrument air lines occurred in 1999 (Section 4OA2).

Cornerstone: Miscellaneous

Green.

The inspectors identified a noncited violation of 10 CFR Part 50,

Appendix B, Criteria V, for the failure to follow Procedure 0POP03-ZX-0002,

Condition Reporting Process, Revision 31. On April 14, 2007, operations recognized that the extended range nuclear instrument startup rate channel check was approaching the limit of 0.5 decades per minute. The log count rate circuit board was determined to be faulty and was replaced. Operations requested an operability/reportability review since the same circuit board had been previously replaced on April 7, 2007. The inspectors questioned the licensee on the review, because the review did not appear to be performed in the normal manner and did not answer questions related to the indications that were observed, namely the shutdown monitor alarm. The second more thorough review determined that the extended range nuclear instrument had been inoperable for longer than its technical specification allowed outage time and resulted in the requirement to submit a Licensee Event Report. The licensees root cause determined that the original reviewer did not adhere to the Condition Reporting Process procedure, in that, the reviewer did not review applicable design inputs, and since the reviewer did not have the technical expertise in this area, a technical review should have been requested.

The inspectors determined that the finding was more than minor because it resulted in the licensee not recognizing that an extended range nuclear instrument was inoperable for longer than its Technical Specification allowed outage time. The inspectors evaluated the finding using Inspection Manual Chapter 0609, Appendix M, Significance Determination Process Using Qualitative Criteria, and determined that the finding screened as Green because: (1) the licensee had all power, intermediate, and source range nuclear instruments available; (2) the extended range nuclear instruments provide no protective functions other than alarms and indications; (3) the primary function is to provide indication to the operators to assess the sub-criticality critical safety function, and this was only impacted in the Yellow path; (4) the Updated Final Safety Analysis Report does not take credit for the extended range nuclear instruments except to provide the operators with a minimum of 15 minutes to respond to a dilution event pending a loss of shutdown margin, and (5) very low likelihood that shutdown margin would be challenged post trip. This finding also had problem identification and resolution crosscutting aspects associated with the corrective action program in that the licensee did not thoroughly evaluate for operability and reportability conditions adverse to quality P.1(c), the reviewer did not consider all Technical Specifications and design requirements in his evaluation (Section 1R12).

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 their corrective actions are listed in Section 4OA7 of this report.

REPORT DETAILS

Summary of Plant Status

Unit 1 began the inspection period at 100 percent rated thermal power (RTP) and operated at or near full RTP for the remainder of the inspection period.

Unit 2 began the inspection period at 100 percent RTP and operated at or near full RTP for the remainder of the inspection period.

REACTOR SAFETY

Cornerstones: Initiating Events, Mitigating Systems, Barrier Integrity

1R04 Equipment Alignment

Partial Walkdown

a. Inspection Scope

The inspectors:

(1) walked down portions of the three below listed risk important systems and reviewed plant procedures and documents to verify that critical portions of the selected systems were correctly aligned, and

(2) compared deficiencies identified during the walk down to the licensees Updated Final Safety Analysis Report (UFSAR)and corrective action program (CAP) to ensure problems were being identified and corrected.

• October 25, 2007, Unit 2, Essential Cooling Water (ECW) Train B during overhaul of ECW Pump 2C

• November 1, 2007, Unit 2, Standby Diesel Generator (SDG) 22 in preparation for 5 year overhaul of SDG 23

• December 4, 2007, Unit 2, Essential Chilled Water Train A during Train B extended scope planned maintenance Documents reviewed by the inspectors are listed in the attachment.

The inspectors completed three samples.

b. Findings

No findings of significance were identified.

1R05 Fire Protection

Quarterly Inspection

a. Inspection Scope

The inspectors walked down the six below listed plant areas to assess the material condition of active and passive fire protection features and their operational lineup and readiness. The inspectors:

(1) verified that transient combustibles and hot work activities were controlled in accordance with plant procedures;

(2) observed the condition of fire detection devices to verify they remained functional;

(3) observed fire suppression systems to verify they remained functional and that access to manual actuators was unobstructed;

(4) verified that fire extinguishers and hose stations were provided at their designated locations and that they were in a satisfactory condition;

(5) verified that passive fire protection features (electrical raceway barriers, fire doors, fire dampers steel fire proofing, penetration seals, and oil collection systems) were in a satisfactory material condition;

(6) verified that adequate compensatory measures were established for degraded or inoperable fire protection features and that the compensatory measures were commensurate with the significance of the deficiency; and

(7) reviewed the UFSAR to determine if the licensee identified and corrected fire protection problems.

• October 25, 2007, Unit 1, component cooling water pump and essential chiller Train A (Fire Zone Z128)

• November 1, 2007, Unit 1, nonradioactive and radioactive piping and penetration areas (Fire Zones Z116, Z133, and Z135)

• November 15, 2007, Unit 2, nonradioactive and radioactive piping and penetration areas (Fire Zones Z116, Z133, and Z135)

• December 4, 2007, Unit 2, Essential Chilled Water Trains A, B, and C (Fire Zones Z128, Z139, and Z140)

• December 10, 2007, Unit 2, auxiliary shutdown area and Electrical Auxiliary Building 10' elevation corridor (Fire Zones Z016, and Z071)

• December 12, 2007, Unit 1 and Unit 2, fire pump house and SDGs 11, 12, 13, 21, 22, and 23 valve rooms (Fire Zones Z801, Z802, Z803, and Z804)

Documents reviewed by the inspectors included:

• Applicable fire preplans

• Condition Report (CR) 07-9154

• Fire Hazards Analysis Report, Revision 16

• Procedure 0PGP03-ZF-0018, Fire Protection System Operability Requirements, Revision 13

• Procedure 0PGP03-ZF-0019, Control of Transient Fire Loads and Use of Combustible and Flammable Liquids and Gases, Revision 5 The inspectors completed six samples.

b. Findings

No findings of significance were identified.

1R06 Flood Protection Measures

Semi-annual Internal Flooding

a. Inspection Scope

The inspectors:

(1) reviewed the UFSAR, the flooding analysis, and plant procedures to assess seasonal susceptibilities involving internal flooding;

(2) reviewed the UFSAR and CAP to determine if the licensee identified and corrected flooding problems;

(3) inspected underground bunkers/manholes to verify the adequacy of

(a) sump pumps,

(b) level alarm circuits,

(c) cable splices subject to submergence, and

(d) drainage for bunkers/manholes;

(4) verified that operator actions for coping with flooding can reasonably achieve the desired outcomes; and

(5) walked down the below listed area to verify the adequacy of:

(a) equipment seals located below the floodline;

(b) floor and wall penetration seals;

(c) watertight door seals;

(d) common drain lines and sumps;

(e) sump pumps, level alarms, and control circuits; and

(f) temporary or removable flood barriers.

• December 11, 2007, Unit 2, ECW intake structure Documents reviewed by the inspectors included:

• Drawing 9P200B0070, Essential Cooling Water Intake Structure Building Floor Plans & Details, Revision 8

• Drawing 5E020E02875, Essential Cooling Water Intake Structure Conduit Plan Unit 1, Revision 8

• Procedure 0POP09-AN-02M3, ECW INTK STRUC SUMP LVL HI-HI, Revision 19

• Calculation MC-5216, Flooding Calc. For the ECWIS, Revision 2

• Calculation NC-9711, Facility Response Analysis for ECWIS Flooding and Spray Effects, Revision 1 The inspectors completed one sample.

b. Findings

No findings of significance were identified.

1R07 Heat Sink Performance

a. Inspection Scope

The inspectors reviewed licensee programs, verified performance against industry standards, and reviewed critical operating parameters and maintenance records for the SDG 23 jacket water cooler and lube oil cooler heat exchangers as part of the 5 year overhaul during the week of November 12, 2007. The inspectors verified that:

(1) performance tests were satisfactorily conducted for heat exchangers/heat sinks and reviewed for problems or errors;

(2) the licensee utilized the periodic maintenance method outlined in Electric Power Research Institute NP-7552, Heat Exchanger Performance Monitoring Guidelines;

(3) the licensee properly utilized biofouling controls;

(4) the licensees heat exchanger inspections adequately assessed the state of cleanliness of their tubes; and

(5) the heat exchanger was correctly categorized under the Maintenance Rule.

Documents reviewed by the inspectors included:

• UFSAR

• Calculation MC-6476, Jacket Water and Lube Oil Cooler Performance, Revision 0

• CRs 07-16814, 07-16817, 07-16847, and 07-17017 The inspectors completed one sample.

b. Findings

No findings of significance were identified.

1R11 Licensed Operator Requalification Program

.1 Quarterly Inspection

a. Inspection Scope

On November 19, 2007, the inspectors observed testing and training of senior reactor operators and reactor operators to identify deficiencies and discrepancies in the training, to assess operator performance, and to assess the evaluators critique. The training scenario involved a sheared reactor coolant pump shaft that resulted in a reactor trip/turbine trip, followed by actuation of safety injection due to low reactor coolant system (RCS) pressure with a resultant steam generator tube leak which meets the criteria for declaring an Alert based on exceeding the capacity of a charging pump.

Finally, transitioning the plant through cooldown and depressurization to establish residual heat removal cooling.

The inspectors completed one sample.

b. Findings

No findings of significance were identified.

.2 Biennial Inspection

a. Inspection Scope

The inspectors were on site the week of September 10, 2007, the first week of six total weeks for operating test administration. The inspectors:

(1) evaluated examination security measures and procedures for compliance with 10 CFR 55.49;

(2) evaluated the licensees sample plan of the written examinations for compliance with 10 CFR 55.59 and NUREG-1021, Operator Licensing Examination Standards for Power Reactors, Revision 9, as referenced in the facility requalification program procedures;

(3) evaluated each licensed operators performance on the biennial written examination and the first and second annual operating tests against the Inspection Manual Chapter 0609, Appendix I, Operator Requalification Human Performance Significance Determination Process requirements; and

(4) reviewed the maintenance of license conditions for compliance with 10 CFR 55.53 by reviewing facility records (medical and administrative), procedures, and tracking systems for licensed operator training, qualification, and watchstanding. Concurrent with the examination results, the inspectors reviewed remedial training for examination failures for compliance with facility procedures and responsiveness to address failed areas.

Furthermore, the inspectors:

(1) interviewed seven personnel, including operators, instructors/evaluators, and training supervisors, regarding the policies and practices for administering requalification examinations;

(2) observed the administration of two dynamic simulator scenarios to two requalification crews; and

(3) observed three evaluators administer five job performance measures, including two in the control room simulator in a dynamic mode and three in the plant under simulated conditions.

Because the written examinations were not completed until December, the inspectors completed this portion of the review in the regional office the week of December 17, 2007, and compared the pass rates with the guidance of Inspection Manual Chapter 0609, Appendix I. Results are listed below.

Results:

• Crew failure rate on the dynamic simulator was less than 20 percent. The threshold for a Green finding is a failure rate between 20 and 33 percent (failure rate was 6.66 percent or 1 failure out of 15 tested).

• Individual failure rate on the dynamic simulator test was less than or equal to 20 percent (failure rate was 0 percent).

• Individual failure rate on the walkthrough test (job performance measures) was less than or equal to 20 percent (failure rate was 2.17 percent or 2 failures out of 92 tested).

• Individual failure rate on the comprehensive biennial written examination was less than or equal to 20 percent (failure rate was 4.59 percent or 4 failures out of 87 tested).

• More than 75 percent of the individuals passed all portions of the examination (93.5 percent of the individuals passed all portions of the examination).

All operators that failed any portion of the examination were remediated prior to returning to shift. The inspectors interviewed members of the training department and operating crews to assess the responsiveness of the licensed operator requalification program. The inspectors also observed the examination security maintenance for the operating tests given while the inspectors were on site September 10-14, 2007, which was the first week of administration of the annual operating tests.

Additionally, the inspectors assessed South Texas Project Electric Generating Stations plant-referenced simulator for compliance with 10 CFR 55.46 using Inspection Procedure 71111.11 (Section 03.11). This assessment included the adequacy of the licensees simulation facility for use in operator licensing examinations and for satisfying experience requirements as prescribed by 10 CFR 55.46. The inspectors reviewed a sample of simulator performance test records (transient tests, malfunction tests, core tests, and scenario-based tests), simulator discrepancy report records, and processes for ensuring simulator fidelity commensurate with 10 CFR 55.46. The inspectors reviewed the criteria in 10 CFR 55.46(c)(2) against the core performance test document samples and the Cycle 14 test data from the plant. The simulator was using the Cycle 14 core load for the current training cycle and no issues were found. The inspectors also interviewed members of the licensees simulator configuration control group as part of this review.

b. Findings

No findings of significance were identified. Additionally, the inspector confirmed that the licensees simulator was adequate for reactivity manipulation credits on the next initial licensing examination provided that they continue to maintain the simulator core model on the most recent core load as the plant for which licenses are being sought and the core testing program and results are maintained for the examiners to review on the respective examination validation week in accordance with NUREG-1021, Revision 9, Supplement 1, Operator Licensing Examination Standards for Power Reactors.

1R12 Maintenance Effectiveness

a. Inspection Scope

The inspectors reviewed the three below listed maintenance activities to:

(1) verify the appropriate handling of structure, system, and component (SSC) performance or condition problems;

(2) verify the appropriate handling of degraded SSC functional performance;

(3) evaluate the role of work practices and common cause problems; and

(4) evaluate the handling of SSC issues reviewed under the requirements of the Maintenance Rule, 10 CFR Part 50, Appendix B, and Technical Specifications (TSs).

• September 28, 2007, Units 1 and 2, source, intermediate, power, and extended range nuclear instrument recurring issues, including cable connections, noise interference, detector replacements, and power supply and inverter failures

• November 29, 2007, Units 1 and 2, ECW system health due to failure of bearing sleeve material and damage to spider and diffuser bearing

• December 20, 2007, Units 1 and 2, incore instrumentation due to multiple failures of core exit thermocouples on each unit Documents reviewed by the inspectors are listed in the attachment.

The inspectors completed three samples.

b. Findings

===.1

Introduction.

The inspectors reviewed a self-revealing Green noncited violation (NCV)===

of 10 CFR Part 50, Appendix B, Criteria V, for the failure to follow Procedure STI 32174927, Conduct of Maintenance, Revision 5.

Description.

On April 6, 2007, while Unit 1 was operating at 100 percent RTP, operations declared extended range nuclear instrument Channel NI46 inoperable due to erratic low range indications. On April 7, 2007, the licensee replaced the log count rate board in Slot A4 of the processor. The board was calibrated and post maintenance testing was completed satisfactorily and the channel was declared inoperable.

Approximately 9 hours1.041667e-4 days <br />0.0025 hours <br />1.488095e-5 weeks <br />3.4245e-6 months <br /> later, the control room received a shutdown monitor alarm and declared the shutdown monitor portion of extended range nuclear instrument Channel NI46 inoperable due to failing low. Operations was only tracking this item as a Mode 3, 4, and 5 issue, even though there are Mode 1 and 2 requirements. Subsequently, on April 14, 2007, operations was taking shiftly logs and recognized that the extended range nuclear instrument startup rate channel check between Channel NI45 and NI46 was approaching the TS limit of 0.5 decades per minute. The log count rate board in Slot A4 was replaced again and it was then determined that the wrong board had been installed. The correct board was installed, calibrated, and successfully passed a postmaintenance test on April 14, 2007. As a result of having installed the wrong board, the extended range nuclear instrument channel was inoperable for a period of time longer than allowed by TSs.

The licensees root cause determined that the wrong board was installed because maintenance personnel were not using appropriate reference material to ensure that the correct part was installed. Maintenance personnel did identify, using the master parts list, that the circuit boards for Slots A2 and A4 had different part numbers, but only one of the boards contained a stock code number. Maintenance personnel then consulted with their training material and determined that the boards were interchangeable. Per the Conduct of Maintenance procedure, maintenance personnel should have stopped and pursued further guidance before continuing based on the following excerpts. If at any time, a conflict arises, unexpected conditions develop. . . stop the job. . . the Craft are expected to ask questions of supervision when a replacement part is not identical.

Use only material that has been approved for your job. Unless properly authorized do not substitute material. Consequently, as a result of not following the procedure,

maintenance personnel convinced themselves that the boards were interchangeable and installed the wrong board.

Analysis.

The inspectors determined that the failure to follow the Conduct Maintenance procedure, which resulted in maintenance personnel installing an incorrect log count rate circuit board, was a performance deficiency. The inspectors determined that the finding was more than minor because it affected the Mitigating Systems cornerstone attribute of equipment and human performance, and the cornerstone objective to ensure the availability of systems that respond to initiating events to prevent undesirable consequences. The inspectors evaluated the finding using Inspection Manual Chapter 0609, Appendix M, Significance Determination Process Using Qualitative Criteria, and determined that the finding screened as Green because:

(1) the licensee had all power, intermediate, and source range nuclear instruments available;

(2) the extended range nuclear instruments provide no protective functions other than alarms and indications;

(3) the primary function is to provide indication to the operators to assess the sub-criticality critical safety function, and this was only impacted in the Yellow path;

(4) the UFSAR does not take credit for the extended range nuclear instruments except to provide the operators with a minimum of 15 minutes to respond to a dilution event pending a loss of shutdown margin; and

(5) very low likelihood that shutdown margin would be challenged post trip. This finding also had human performance crosscutting aspects associated with work practices in that the licensee did not effectively communicate human error prevention techniques such as self and peer checking H.4(a), and maintenance personnel did not verify the replacement part using controlled documentation.

Enforcement.

10 CFR Part 50, Appendix B, Criteria V, requires, in part, that activities affecting quality shall be prescribed by documented procedures and shall be accomplished in accordance with these procedures. The Conduct of Maintenance procedure states, in part. . . Use only material that has been approved for your job.

Unless properly authorized do not substitute material. Contrary to this, on April 7, 2007, the licensee replaced the circuit Board A4 with a circuit Board A2. Since this violation is of very low safety significance (Green) and it had been entered into the licensees CAP as CR 07-6164, this violation is being treated as a NCV consistent with Section VI.A of the Enforcement Policy: NCV 05000498/2007005-01, Incorrect Count Rate Board Installed in Extended Range Nuclear Instrument Channel.

===.2

Introduction.

The inspectors identified a Green NCV of 10 CFR Part 50, Appendix B,===

Criteria V, for the failure to follow Procedure 0POP03-ZX-0002, Condition Reporting Process, Revision 31.

Description.

On April 14, 2007, as part of taking shiftly logs, operations recognized that the extended range nuclear instrument startup rate channel check between Channels NI45 and NI46 was approaching the TS limit of 0.5 decades per minute. The licensee determined that the log rate circuit board in Slot A4 of the processor was faulty.

The log count rate circuit board was replaced and operations requested engineering to perform an operability/reportability review since the same circuit board had just been previously replaced on April 7, 2007. Maintenance engineering completed the review on April 16, 2007, which design engineering normally does, and concluded that the failure of the circuit board was from the time of discovery, April 14, 2007, and not the time from when the initial issue occurred, April 6, 2007. The inspectors questioned the licensee on

the operability/reportability review as the review did not appear to be performed in the normal manner and did not provide answers to questions related to the indications that were observed in the extended range nuclear instrument, namely the shutdown monitor alarm. Consequently, the licensee reopened the CR to reopen the operability/reportability review. During the followup review, it was determined that the original reviewer did not consider all the applicable TSs, and that the design documentation was not researched appropriately.

As a result, the original reviewer came to the wrong conclusion. The second more thorough review determined that the extended range nuclear instrument had been inoperable from the time it first started reading erratically on April 6, 2007, until the time the correct circuit board was installed, calibrated, and successfully passed a post maintenance test on April 14, 2007. Therefore, the extended range nuclear instrument was inoperable for longer than its TS allowed outage time and resulted in the requirement to submit a Licensee Event Report (LER). The licensees root cause determined that the original reviewer did not adhere to the Condition Reporting Process procedure, in that, they did not indicate the criteria they considered in making the review and they did not include a basis for the decision. As a result, the reviewer did not review applicable design inputs, and because the reviewer did not have the technical expertise in this area, a technical review should have been requested. As part of the corrective actions, the licensee is reviewing past operability/reportability reviews that were performed outside of the design engineering department for appropriate level of rigor.

Analysis.

The inspectors determined that the failure to follow the Condition Reporting Process procedure, indicating the criteria considered along with a brief basis for the decision resulted in a wrong conclusion in regards to the allowed outage time of the extended range nuclear instrument, was a performance deficiency. The inspectors determined that the finding was more than minor because it resulted in the licensee not recognizing that an extended range nuclear instrument was inoperable for longer than its TS allowed outage time, which required submitting an LER. The inspectors evaluated the finding using Inspection Manual Chapter 0609, Appendix M, Significance Determination Process Using Qualitative Criteria, and determined that the finding screened as Green because:

(1) the licensee had all power, intermediate, and source range nuclear instruments available;

(2) the extended range nuclear instruments provide no protective functions other than alarms and indications;

(3) the primary function is to provide indication to the operators to assess the sub-criticality critical safety function, and this was only impacted in the Yellow path;

(4) the UFSAR does not take credit for the extended range nuclear instruments except to provide the operators with a minimum of 15 minutes to respond to a dilution event pending a loss of shutdown margin; and

(5) very low likelihood that shutdown margin would be challenged post trip. This finding also had problem identification and resolution crosscutting aspects associated with the CAP, in that, the licensee did not thoroughly evaluate for operability and reportability conditions adverse to quality P.1(c), the operability/reportability reviewer did not consider all TSs and design requirements in his evaluation.

Enforcement.

10 CFR Part 50, Appendix B, Criteria V, requires, in part, that activities affecting quality shall be prescribed by documented procedures and shall be accomplished in accordance with these procedures. The Condition Reporting Process procedure states, in part, The review should indicate the criteria considered . . . include a brief basis for the decision. Contrary to this, on April 16, 2007, the licensee did not

include all the criteria necessary to perform a reportability review, specifically, all the applicable TSs and the design functions of the system were not addressed, which resulted in a wrong conclusion in regards to this allowed outage time of the extended range nuclear instrument. Since this violation is of very low safety significance (Green)and it had been entered into the licensees CAP as CRs 07-6164 and 07-15148, this violation is being treated as an NCV consistent with Section VI.A of the Enforcement Policy: NCV 05000498/2007005-02, Inadequate Reportability Review Results in Missed Reporting Requirement.

1R13 Maintenance Risk Assessments and Emergent Work Control

Risk Assessment and Management of Risk

a. Inspection Scope

Risk Assessment and Management of Risk The inspectors reviewed the four below listed assessment activities to verify:

(1) performance of risk assessments when required by 10 CFR 50.65 (a)(4) and licensee procedures prior to changes in plant configuration for maintenance activities and plant operations;

(2) the accuracy, adequacy, and completeness of the information considered in the risk assessment;

(3) that the licensee recognizes, and/or enters as applicable, the appropriate licensee-established risk category according to the risk assessment results and licensee procedures; and

(4) that the licensee identified and corrected problems related to maintenance risk assessments.

• Week of October 15, 2007, Units 1 and 2, planned maintenance activities on Unit 1 Train D, and Unit 2 Train C

• Week of October 22, 2007, Units 1 and 2, planned maintenance activities on Unit 1 Train A including corrective maintenance on essential Chiller 12A and emergent maintenance on a rod control power supply failure, and Unit 2 Train C including corrective maintenance to overhaul ECW Pump 2C and 10-year clean and inspect on the SDG 23 fuel oil storage tank

• Week of November 12, 2007, Unit 2, planned maintenance activities on Unit 2 Train C including 5 year overhaul of SDG 23

• Week of December 3, 2007, Units 1 and 2, planned maintenance activities on Unit 2 Train B, and emergent maintenance on Unit 1 steam generator main feedwater Pump 11 speed control feedback circuit The inspectors completed four samples.

b. Findings

No findings of significance were identified.

1R15 Operability Evaluations

a. Inspection Scope

The inspectors:

(1) reviewed plant status documents such as operator shift logs, emergent work documentation, deferred modifications, and standing orders to determine if an operability evaluation was warranted for degraded components;

(2) referred to the UFSAR and design basis documents to review the technical adequacy of licensee operability evaluations;

(3) evaluated compensatory measures associated with operability evaluations;

(4) determined degraded component impact on any TSs;

(5) used the significance determination process to evaluate the risk significance of degraded or inoperable equipment; and

(6) verified that the licensee has identified and implemented appropriate corrective actions associated with degraded components.

• October 25, 2007, Units 1 and 2, evaluation of change in essential chiller relief valve o-ring material from Buna-N or Viton to Neoprene, which is not considered compatible with the refrigerant type used for the chillers per CR 07-14474

• October 29, 2007, Units 1 and 2, evaluation of missing SDG generator outboard side inner shroud bolts on SDGs 11, 13, 21, 22, and 23 per CR 07-15292

• November 12, 2007, Units 1 and 2, evaluation of missed American Society of Mechanical Engineers (ASME) Code requirement to remove insulation to perform the inservice inspection on bolting on the residual heat removal (RHR)heat exchangers, the pressurizer manway, the steam generator primary side manways, and the reactor vessel head closure bolts

• November 29, 2007, Units 1 and 2, evaluation of compensatory measures established for declaring the fire detection panels inoperable due to multiple false alarms related to grounds, communication failures, and sensor failures Documents reviewed by the inspectors are listed in the attachment.

The inspectors completed four samples.

b. Findings

For a licensee-identified finding regarding the inservice inspection of the RHR heat exchangers, the pressurizer manway, the steam generator primary side manways, and the reactor vessel head closure bolts, see Section 4OA7.

1R19 Postmaintenance Testing

a. Inspection Scope

The inspectors selected the four below listed postmaintenance test activities of risk significant systems or components. For each item, the inspectors:

(1) reviewed the applicable licensing basis and/or design basis documents to determine the safety functions;

(2) evaluated the safety functions that may have been affected by the

maintenance activity; and

(3) reviewed the test procedure to ensure it adequately tested the safety function that may have been affected. The inspectors either witnessed or reviewed test data to verify that acceptance criteria were met, plant impacts were evaluated, test equipment was calibrated, procedures were followed, jumpers were properly controlled, the test data results were complete and accurate, the test equipment was removed, the system was properly realigned, and deficiencies during testing were documented. The inspectors also reviewed the UFSAR to determine if the licensee identified and corrected problems related to postmaintenance testing.

• October 25, 2007, Unit 1, oil leak repair on essential Chiller 12A

• November 2, 2007, Unit 2, ECW Pump 2C rebuild due to bearing sleeve failure and motor replacement

• November 18, 2007, Unit 2, SDG 23 following 5 year overhaul

• November 29, 2007, Unit 2, auxiliary feedwater Pump 21 anti-rotation pin replacement as part of corrective maintenance activities Documents reviewed by the inspectors are listed in the attachment.

The inspectors completed four samples.

b. Findings

No findings of significance were identified.

1R22 Surveillance Testing

a. Inspection Scope

The inspectors reviewed the UFSAR, procedure requirements, and TSs to ensure that the four below listed surveillance activities demonstrated that the SSCs tested were capable of performing their intended safety functions. The inspectors either witnessed or reviewed test data to verify that the following significant surveillance test attributes were adequate:

(1) preconditioning;

(2) evaluation of testing impact on the plant;

(3) acceptance criteria;

(4) test equipment;

(5) procedures;

(6) jumper/lifted lead controls;

(7) test data;

(8) testing frequency and method demonstrated TS operability;

(9) test equipment removal;

(10) restoration of plant systems;

(11) fulfillment of ASME Code requirements;

(12) updating of performance indicator (PI) data;

(13) engineering evaluations, root causes, and bases for returning tested SSCs not meeting the test acceptance criteria were correct;

(14) reference setting data; and

(15) annunciators and alarms setpoints. The inspectors also verified that the licensee identified and implemented any needed corrective actions associated with the surveillance testing.

• October 30, 2007, Unit 2, inservice testing of high head safety injection Loop 2A hot leg isolation Valve 2SI-MOV-0008A, per Procedure 0PSP03-SI-0020, Safety Injection System Miscellaneous and Train 1A(2A) Valve Operability Tests, Revision 15, and work order (WO) 459423

• November 15, 2007, Units 1 and 2, inservice inspection of RHR heat exchangers as a result of missed surveillance due to ASME code requirement to perform the inspection with insulation removed; the licensee removed the insulation and performed the inspection per Procedure 0PSP15-RH-0001, Residual Heat Removal System Inservice Pressure Test, Revision 12

• December 11, 2007, Unit 2, personnel airlock leakage rate test per Procedure 0PSP11-XC-0008, LLRT Penetration M-90 Personnel Airlock Door Seals, Revision 14

• December 13, 2007, Unit 2, Solid State Protection System master and slave relay quarterly test per Procedure 0PSP03-SP-0007C, SSPS Actuation Train C Master Relay Test, Revision 17 and 0PSP03-SP-0008C, SSPS Train C Quarterly Slave Relay Test, Revision 13 Documents reviewed by the inspectors are listed in the attachment.

The inspectors completed four samples.

b. Findings

For a licensee identified finding regarding the inservice inspection of the RHR heat exchangers, see Section 4OA7.

1R23 Temporary Plant Modifications

a. Inspection Scope

The inspectors reviewed the UFSAR, plant drawings, procedure requirements, and TSs to ensure that the one below listed temporary modification was properly implemented.

The inspectors:

(1) verified that the modification did not have an affect on system operability/availability,

(2) verified that the installation was consistent with the modification documents,

(3) ensured that the post installation test results were satisfactory and that the impact of the temporary modification on permanently installed SSCs were supported by the test,

(4) verified that the modifications were identified on control room drawings and that appropriate identification tags were placed on the affected drawings, and

(5) verified that appropriate safety evaluations were completed.

The inspectors verified that the licensee identified and implemented any needed corrective actions associated with temporary modifications.

• November 28, 2007, Units 1 and 2, rod control jumper installation which prevents automatic rod insertion if reactor power is higher than turbine power Documents reviewed by the inspectors included:

• CRs 06-16024 and 06-16878

• Procedure 0PMP08-RS-0660, RCS Rod Speed Control Calibration Loop (S-660), Revision 15

• Temporary modifications T1-06-16878-6 and T2-06-16024-16 The inspectors completed one sample.

b. Findings

No findings of significance were identified.

1EP2 Alert Notification System Testing

a. Inspection Scope

The inspector discussed with licensee staff the status of offsite siren and tone alert radio systems to determine the adequacy of licensee methods for testing the alert and notification system in accordance with 10 CFR Part 50, Appendix E. The licensees alert and notification system testing program was compared with criteria in NUREG-0654, Criteria for Preparation and Evaluation of Radiological Emergency Response Plans and Preparedness in Support of Nuclear Power Plants, Revision 1, Federal Emergency Management Agency Report REP-10, Guide for the Evaluation of Alert and Notification Systems for Nuclear Power Plants, and the licensees current federal emergency management agency-approved alert and notification system design report. The inspector also reviewed Procedure 0PGP05-ZV-0006, Emergency Notification and Response System, Revision 3, and Desktop Guide ZV-0013, Alert Radio Maintenance and Distribution, Revision 0.

The inspector completed one sample.

b. Findings

No findings of significance were identified.

1EP3 Emergency Response Organization Augmentation Testing

a. Inspection Scope

The inspector reviewed Procedure 0PGP05-ZV-0014, Emergency Response Activities, Revision 7, Form 19, ENRS Test (Autodialer Test), and the results of three call-in and drive-in drills to determine the licensees ability to staff emergency response facilities in accordance with the licensee emergency plan and the requirements of 10 CFR Part 50, Appendix E. The inspector also interviewed licensee staff responsible for maintaining the licensees Emergency Notification and Response System.

The inspector completed one sample during this inspection.

b. Findings

No findings of significance were identified.

1EP5 Correction of Emergency Preparedness Weaknesses and Deficiencies

a. Inspection Scope

The inspector reviewed the following documents related to the licensees corrective action program to determine the licensees ability to identify and correct problems in accordance with 10 CFR 50.47(b)(14) and 10 CFR Part 50, Appendix E.

• Procedure 0PGP03-ZX-0002, Condition Reporting Process, Revision 33

• Drill reports for 15 combined functional and stand-alone station emergency preparedness drills and exercises

• Fourteen Quality Assurance Audits and Monitoring Reports

• Summaries of all corrective actions assigned to the emergency preparedness department between January 2005 and November 2007

• Details of 16 selected CRs The inspector completed one sample during this inspection.

b. Findings

No findings of significance were identified.

1EP6 Drill Evaluation

a. Inspection Scope

For the one below listed drill and simulator-based training evolution contributing to drill/exercise performance, emergency response organization, and PIs, the inspectors:

(1) observed the training evolution to identify any weaknesses and deficiencies in classification, notification, and protective action requirements development activities;

(2) compared the identified weaknesses and deficiencies against licensee identified findings to determine whether the licensee is properly identifying failures; and

(3) determined whether licensee performance is in accordance with the guidance of the Nuclear Energy Institute (NEI) 99-02, Regulatory Assessment Performance Indicator Guideline, Revision 5, acceptance criteria.

• October 31, 2007, Unit 1, simulator, technical support center, and emergency operations facility; the training scenario started as a RCS flow transmitter failing, followed by a RCS leak, which results in a notice of unusual event; continuing on such that the charging system cannot maintain inventory, resulting in an alert; subsequently, a RCS pipe break results in radiation levels inside containment satisfying the site area emergency criteria; and finally, a failure of containment isolation valves resulting in a general emergency

Documents reviewed by the inspectors included:

• Combined Functional Drill Scenario Manual, October 31, 2007 The inspectors completed one sample.

b. Findings

No findings of significance were identified.

RADIATION SAFETY

Cornerstone: Occupational Radiation Safety

2OS1 Access Control to Radiologically Significant Areas (71121.01)

a. Inspection Scope

This area was inspected to assess the licensees performance in implementing physical and administrative controls for airborne radioactivity areas, radiation areas, high radiation areas, and worker adherence to these controls. The inspector used the requirements in 10 CFR Part 20, the TSs, and the licensees procedures required by TSs as criteria for determining compliance. During the inspection, the inspector interviewed the radiation protection manager, radiation protection supervisors, and radiation workers. The inspector performed independent radiation dose rate measurements and reviewed the following items:

• PI events and associated documentation packages reported by the licensee in the Occupational Radiation Safety cornerstone

• Radiation work permits, procedures, engineering controls, and air sampler locations

• Conformity of electronic personal dosimeter alarm set points with survey indications and plant policy

• Self-assessments, audits, LERs, and special reports related to the access control program since the last inspection

• Radiation work permit briefings and worker instructions

• Adequacy of radiological controls, such as required surveys, radiation protection job coverage, and contamination controls during job performance

• Posting and locking of entrances to accessible high dose rate - high radiation areas and very high radiation areas

• Radiation worker and radiation protection technician performance with respect to radiation protection work requirements

Either because the conditions did not exist or an event had not occurred, no opportunities were available to review the following items:

• Adequacy of the licensees internal dose assessment for any actual internal exposure greater than 50 millirem Committed Effective Dose Equivalent The inspector completed 11 of the required 21 samples.

b. Findings

No findings of significance were identified.

2OS2 As Low as is Reasonably Achievable (ALARA) Planning and Controls (71121.02)

a. Inspection Scope

The inspector assessed licensee performance with respect to maintaining individual and collective radiation exposures ALARA. The inspector used the requirements in 10 CFR Part 20 and the licensees procedures required by TSs as criteria for determining compliance. The inspector interviewed licensee personnel and reviewed:

• Current 3-year rolling average collective exposure

• Eleven work activities from previous work history data which resulted in the highest personnel collective exposures

• Site specific trends in collective exposures, plant historical data, and source-term measurements

• Site specific ALARA procedures

• ALARA work activity evaluations, exposure estimates, and exposure mitigation requirements

• Intended versus actual work activity doses and the reasons for any inconsistencies

• Post-job (work activity) reviews

• Method for adjusting exposure estimates, or re-planning work, when unexpected changes in scope or emergent work were encountered

• Records detailing the historical trends and current status of tracked plant source terms

• Radiation worker and radiation protection technician performance during work activities in radiation areas, airborne radioactivity areas, or high radiation areas

• Self-assessments, audits, and special reports related to the ALARA program since the last inspection

• Effectiveness of self-assessment activities with respect to identifying and addressing repetitive deficiencies or significant individual deficiencies The inspector completed 12 of the required 29 samples.

b. Findings

No findings of significance were identified.

4OA1 Performance Indicator Verification

Cornerstone: Mitigating Systems

The inspectors sampled licensee submittals for the one PI listed below for the period October 2006 through September 2007, for Units 1 and 2. The definitions and guidance of NEI 99-02, Regulatory Assessment Performance Indicator Guideline, Revision 5, were used to verify the licensees basis for reporting each data element in order to verify the accuracy of PI data reported during the assessment period. The inspectors reviewed LERs, out-of-service logs, operating logs, and the maintenance rule database as part of the assessment. Licensee PI data were also reviewed against the requirements of Procedure 0PGP05-ZN-0007, Preparation and Submittal of NRC Performance Indicators, Revision 4.

• Mitigating Systems Performance Index Documents reviewed by the inspectors included:

• CRs 06-17274, 07-3122, 07-9030, 07-9547, 07-12151, and 07-13577 The inspectors completed one sample for each unit.

Cornerstone: Emergency Preparedness

The inspector reviewed licensee submittals for the three PIs listed below for the period July 1, 2006, through September 30, 2007. The definitions and guidance of NEI 99-02, Regulatory Assessment Indicator Guideline, Revisions 2 and 3, were used to verify the licensees basis for reporting each data element in order to verify the accuracy of PI data reported during the assessment period. The licensees PI data were also reviewed against the requirements of Procedure 0PGP05-ZV-0013, Performance Indicator Tracking Guide, Revision 4.

The inspector reviewed a 100 percent sampling of drill and exercise scenarios, licensed operator simulator training sessions, notification forms, and attendance and critique records associated with training sessions, drills, and exercises conducted during the verification period. The inspector reviewed 30 selected emergency responder

qualification and training records, and a 100 percent sample of quarterly drill participation records. The inspector reviewed a 100 percent sample of siren test and maintenance records and procedures. The inspector also interviewed licensee personnel that were accountable for collecting and evaluating the PI data.

• Drill and Exercise Performance

• Emergency Response Organization Participation

• Alert and Notification System Reliability The inspector completed three samples during this inspection.

Cornerstone: Occupational Radiation Safety

The inspector reviewed licensee documents from March 1, 2007, through October 31, 2007. The review included corrective action documentation that identified occurrences in locked high radiation areas (as defined in the licensees TSs), very high radiation areas (as defined in 10 CFR 20.1003), and unplanned personnel exposures (as defined in NEI 99-02). Additional records reviewed included ALARA records and whole body counts of selected individual exposures. The inspector interviewed licensee personnel that were accountable for collecting and evaluating the PI data. In addition, the inspector toured plant areas to verify that high radiation, locked high radiation, and very high radiation areas were properly controlled. PI definitions and guidance contained in NEI 99-02, Regulatory Assessment Performance Indicator Guideline, Revision 5, were used to verify the basis in reporting for each data element.

• Occupational Exposure Control Effectiveness The inspector completed one sample.

Cornerstone: Public Radiation Safety

The inspector reviewed licensee documents from March 1, 2007, through October 31, 2007. Licensee records reviewed included corrective action documentation that identified occurrences for liquid or gaseous effluent releases that exceeded PI thresholds and those reported to the NRC. The inspector interviewed licensee personnel that were accountable for collecting and evaluating the PI data. PI definitions and guidance contained in NEI 99-02, Regulatory Assessment Performance Indicator Guideline, Revision 5, were used to verify the basis in reporting for each data element.

• Radiological Effluent Technical Specification/Offsite Dose Calculation Manual Radiological Effluent Occurrences The inspector completed one sample.

b. Findings

No findings of significance were identified.

4OA2 Identification and Resolution of Problems

.1 Routine Review of Identification and Resolution of Problems

The inspectors performed a daily screening of items entered into the licensees CAP.

This assessment was accomplished by reviewing WOs, CRs, etc. and attending corrective action review and work control meetings. The inspectors:

(1) verified that equipment, human performance, and program issues were being identified by the licensee at an appropriate threshold and that the issues were entered into the CAP;

(2) verified that corrective actions were commensurate with the significance of the issue; and

(3) identified conditions that might warrant additional followup through other baseline inspection procedures. The inspectors used the licensees Procedure 0PGP03-ZX-0002, Condition Reporting Process, Revision 33, for understanding the threshold level for generating a CR.

.2 Selected Issue Followup Inspection

a. Inspection Scope

In addition to the routine review, the inspectors selected the one below listed issue for a more in-depth review. The inspectors considered the following during the review of the licensees actions:

(1) complete and accurate identification of the problem in a timely manner;

(2) evaluation and disposition of operability/reportability issues;

(3) consideration of extent of condition, generic implications, common cause, and previous occurrences;

(4) classification and prioritization of the resolution of the problem;

(5) identification of root and contributing causes of the problem;

(6) identification of corrective actions; and

(7) completion of corrective actions in a timely manner.

• October 25, 2007, Unit 1, safety-related solenoid valves for steam dump Valve N1MSPV7489 incorrectly connected instrument air lines resulting in the steam dump valve not operating as expected when the solenoid was de-energized Documents reviewed by the inspectors are listed in the attachment.

b. Findings

Introduction.

The inspectors reviewed a Green self-revealing NCV of 10 CFR Part 50, Appendix B, Criteria V, for an inadequate procedure for testing safety-related solenoid valves that operate the steam dump valves.

Description.

On December 18, 2006, during troubleshooting activities on Unit 1 to investigate the unexpected response of steam dump Valve N1MSPV7489, the licensee discovered that the safety-related solenoid valve instrument air line connections were crossed, such that when the valve was de-energized the steam dump valve would not close. The licensee was investigating this event because of an unusual indication that was received while performing a turbine impulse chamber pressure transmitter calibration. During the calibration, the need to reduce power became evident and the operator adjusted the steam dump demand setpoint to close the steam dump valves.

During this adjustment, all the steam dump valves indicated closed except for Valve N1MSPV7489 which indicated open, and the corresponding demand signal remained at 5 percent. During the apparent cause investigation into the event, the licensee discovered that they had incorrectly connected the instrument air lines to the safety-related solenoid valve in April 1999, this was the last time that the valve was rebuilt. They also identified that they missed several opportunities to identify and correct this condition based on a CAP search. The search revealed that similar documented occurrences of unexpected response from N1MSPV7489 occurred in September 1999, October 2001, and April 2005, before the current event in November 2006. As part of the corrective actions, the licensee corrected the cross connection of the instrument air lines, walked down the other steam dump safety-related solenoid valves, and changed the maintenance procedure. The licensee determined that the maintenance procedure for the safety-related solenoid valves was inadequate because it only tested the function of the solenoid, electrical connection, and not the operation of the steam dump valve, instrument air line connection, however, the licensee determined that the lack of using a configuration change form resulted in the cross connection. The licensee has since changed the procedure to include testing the solenoid in a de-energized state to verify that the steam dump valves go closed. The licensee has also changed their criteria for work screening such that another similar event such as this would not be allowed to be performed using minor maintenance, and therefore a detailed work package would be required which would include a configuration change form.

Analysis.

The inspectors determined that having an inadequate procedure for testing the safety-related solenoids that operate the steam dump valves, that resulted in an unexpected response of steam dump Valve N1MSPV7489, to be a performance deficiency. This finding is greater than minor because it affected the Mitigating Systems cornerstone attribute of procedural quality and the objective of ensuring the availability and reliability of systems that respond to initiating events to prevent undesirable consequences. Using the Phase 1 worksheets in Inspection Manual Chapter 0609, Significance Determination Process, this finding was determined to have very low safety significance (Green) because it did not result in the actual loss of safety function of one or more non-TS trains of equipment for greater than 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> and it did not screen as risk significant due to seismic, flooding, or severe weather. This issue has no crosscutting aspects because the cross connection of the instrument air lines occurred in 1999 and the work control process has changed. However, a licensee-identified ineffective corrective action problem identification and resolution NCV is documented in Section 4OA7.

Enforcement.

10 CFR Part 50, Appendix B, Criteria V, requires, in part, that activities affecting quality shall be prescribed by procedures, and shall include appropriate acceptance criteria for determining that important activities have been satisfactorily accomplished. Contrary to this, as recently as December 18, 2006, Procedure 0PMP08-MS-7400, Main Steam Dump Pressure Control Calibration, did not include steps to test the safety-related solenoid valves in a de-energized state to ensure that the steam dump valves operated as expected. The licensee updated the procedure to include steps to test the safety-related solenoids in a de-energized state to ensure expected response of the steam dump valves. Since this violation is of very low safety significance (Green) and it has been entered into the licensees CAP as CRs 06-17055, 07-6005, and 07-15785, this violation is being treated as an NCV consistent with Section VI.A of the Enforcement Policy: NCV 05000498/2007005-03, Incorrectly

Installed Safety-Related Solenoid Valve Results in Unexpected Steam Dump Valve Operation.

.3 Semiannual Trend Review

a. Inspection Scope

The inspectors completed a semi-annual trend review of repetitive or closely related issues that were documented in trend reports, problem lists, PIs, health reports, quality assurance audits, corrective action documents, etc. to identify trends that might indicate the existence of more safety significant issues. The inspectors review consisted of the 6-month period of July through December 2007. When warranted, some of the samples expanded beyond those dates to fully assess the issue. The inspectors compared and contrasted their results with the results contained in the licensees quarterly trend reports. Corrective actions associated with a sample of their issues identified in the licensees trend report were reviewed for adequacy.

b. Findings

No findings of significance were identified. However, the inspectors did make the following observations which were shared with licensee management. The licensee has captured each of these events in their CAP under various CRs.

• A number of issues are still occurring with implementing the requirements of the Fire Protection Program. While the performance of fire watches is on a potential upward trend, there is a potential declining trend in the implementation of the requirements of the Fire Protection Program. These include items such as:

(1) implementation of compensatory measures,

(2) establishing the correct compensatory measures,

(3) timeliness of communications to allow establishment of compensatory measures,

(4) posting in the wrong location, and

(5) securing the compensatory measures too soon.

• There continues to be a potential declining trend in procedural compliance in the operations department. While the licensee does have a root cause CR to address the concern, there continues to be multiple examples of operations personnel not following the procedure at hand, for example, not adhering to the requirements for out of specifications logs and performing steps out of sequence when not specifically allowed.

.4 Annual Sample Review (Emergency Preparedness)

a. Inspection Scope

The inspectors reviewed a listing of action requests originated between November 2006, and November 2007, and reviewed licensee drill evaluation reports for 2006 through 2007. The reports were reviewed to ensure that the full extent of the issues were identified, an appropriate evaluation was performed, and appropriate corrective actions were specified and prioritized. This review was accomplished by reviewing hard copy or electronic summaries of selected CRs from the licensees computerized CAP database.

b. Findings

No findings of significance were identified.

.5 Sample Review (Radiation Safety)

a. Inspection Scope

The inspector evaluated the effectiveness of the licensees problem identification and resolution process with respect to the following inspection areas:

• Access Control to Radiologically Significant Areas (Section 2OS1)

• ALARA Planning and Controls (Section 2OS2)

b. Findings

No findings of significance were identified.

4OA3 Followup of Events and Notices of Enforcement Discretion

.1 (Closed) LER 05000498/2006-006-01, Inoperable Auxiliary Feedwater Flow

Instrumentation The inspectors reviewed LER 05000498/2006-006-01 to verify that the cause of the electrical transient to the qualified display processing system was identified and that the corrective actions were appropriate. This LER was updated to provide additional information regarding the failure mode, specifically, that testing of the surge suppressors found that they were undamaged. Consequently, the most probable cause of the damage is from a design incompatibility between the 120 volt system and the connected loads, as a result of having an ungrounded system. This allows for a high voltage bus to ground condition to be created under certain conditions, as was the case for this event.

The original LER 05000498/2006-006-00 was closed in NRC Inspection Report 05000498/2007002 and 05000499/2007002. The additional information provided in this revision does not change the original classification of the event. The licensee had previously submitted a TS change for this instrumentation to change the allowed outage time from 48 hours5.555556e-4 days <br />0.0133 hours <br />7.936508e-5 weeks <br />1.8264e-5 months <br /> to 30 days which was approved on June 13, 2007.

The licensee had documented this condition in CRs 06-16998 and 07-321. No findings of significance were identified. This LER is closed.

.2 (Closed) LER 05000498/2007-003-00, Incorrect Count Rate Board Installed in

Extended Range Nuclear Instrument Channel The inspectors reviewed LER 05000498/2007-003-00 to verify that the cause of the incorrect count rate board installed in the extended range nuclear instrument, and the less than adequate reportability review were identified and that the corrective actions were appropriate. The licensee documented these conditions in CRs 07-6164 and 07-15148. A description of the events associated with the findings and the enforcement aspects of this LER are documented in Section 1R12.1 and 1R12.2 of this inspection report. This LER is closed.

4OA6 Management Meetings, Including Exit

Exit Meeting Summary

On November 29, 2007, the inspector presented the emergency preparedness inspection results to Mr. C. Bowman and other members of licensee management.

Licensee management acknowledged the results. During the inspection, the inspector asked whether any materials examined should be considered proprietary. No proprietary information was identified.

On December 6, 2007, the inspector presented the occupational radiation safety inspection results to Mr. J. Sheppard, President and CEO, and other members of his staff who acknowledged the findings. The inspector confirmed that proprietary information was not provided or examined during the inspection.

On December 17, 2007, the inspector conducted a telephonic exit meeting to present the operations biennial requalification inspection results to Mr. J. Calvert, Operations Training Manager, who acknowledged the findings. The inspector confirmed that proprietary information was not provided or examined during the inspection.

On January 3, 2008, the inspectors presented the inspection results of the integrated inspection report to Mr. J. Sheppard, President and Chief Executive Officer, and other members of the licensees management staff. The licensee acknowledged the findings presented. The inspectors noted that while proprietary information was reviewed, none would be included in this report.

4OA7 Licensee-Identified Violations

The following violations of very low significance (Green) were identified by the licensee and are a violation of NRC requirements which meet the criteria of Section VI of the NRC Enforcement Policy for being dispositioned as NCVs.

• 10 CFR Part 50, Appendix B, Criteria XVI, requires, in part, that conditions adverse to quality, such as deficiencies and nonconformances are promptly identified and corrected. On November 30, 2006, during a surveillance test on the Unit 1 turbine impulse pressure, it was observed that Steam Dump PV7489 was not responding as expected. The apparent cause investigation, CR 06-17055, revealed that the safety-related solenoid valve that controls Steam Dump PV7489 was incorrectly installed in the plant. The instrument air lines were incorrectly installed, cross connected, when the valve was disassembled in April 1999. Additionally, the apparent cause revealed that the cross connected air lines should have been identified and corrected by three previous CRs before the November 30, 2006, event. Respectively, September 1999, October 2001, and April 2005, which were written for similar occurrences of unexpected response. Contrary to the requirements of 10 CFR Part 50, Appendix B, Criteria XVI, this deficiency and nonconformance was not promptly identified and corrected. The licensee has since corrected the cross connected air lines, inspected all other steam dump safety-related solenoids, and updated the maintenance procedure to include steps to test the steam dumps position for a de-energized safety solenoid. This finding is of very low safety significance

because it did not result in the actual loss of safety function of one or more non-TS trains of equipment for greater than 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> and it did not screen as risk significant due to seismic, flooding, or severe weather.

• TS 4.0.5, requires, in part, that inservice inspection of ASME Code Class 1, 2, and 3 components shall be performed in accordance with Section XI of the ASME Boiler and Pressure Vessel Code and applicable Addenda. The ASME Boiler and Pressure Vessel Code requires that, for bolted connections where the bolting content contains less than 10 percent chromium, the insulation be removed and a visual examination be performed while the system is at normal operating conditions. Contrary to this, on November 8, 2007, during an assessment of the boric acid corrosion control program, the licensee identified that they had not performed the inservice inspection for the bolted connections on the RHR heat exchangers, the pressurizer manway cover, the steam generator primary side manway covers, and the reactor vessel head closure bolts for Units 1 and 2 in accordance with the ASME Code. The licensee did not remove the insulation prior to performing the visual inspection. The licensee has since performed the inspection on the RHR heat exchangers and the pressurizer manway, and has performed a risk assessment to postpone the inspection on the steam generator primary side manways and reactor vessel head closure bolts for up to 1 year in accordance with TS 4.0.3. This finding is of very low safety significance because assuming worst case degradation, the finding would not result in exceeding the TS limit for identified RCS leakage or affected other mitigating systems.

ATTACHMENT:

SUPPLEMENTAL INFORMATION

KEY POINTS OF CONTACT

Licensee Personnel

L. Barton, Manager, Offsite Program

C. Bowman, General Manager Oversight

W. Bullard, Manager, Health Physics

K. Coates, Plant General Manager

R. Dunn Jr., Supervisor, Configuration Control and Analysis

R. Engen, Manager, Maintenance Engineering

J. Enoch, Offsite Coordinator, Emergency Response

T. Frawley, Manager, Plant Protection

R. Gangluff, Manager, Chemistry, Environmental and Health Physics

C. Grantom, Manager, PRA

E. Halpin, Site Vice President

W. Harrison, Senior Engineer, Licensing Staff Specialist

S. Head, Manager, Licensing

G. Hildebrant, Manager, Operations Unit 2

K. House, Manager, Design Engineering

D. Hubenak, Supervisor, ALARA

G. Janak, Manager, Operations, Unit 1

B. Jenewein, Manager, Testing, Programs Engineering

J. Johnson, Supervisor, Quality

A. McGalliard, Manager, Performance Improvement

R. Meier, Supervisor, Emergency Response

J. Mertink, Manager, Operations

J. Morris, Engineer, Licensing Staff Specialist

H. Murray, Manager, Maintenance

M. Murray, Manager, Systems Engineering

G. Powell, Manager, Site Engineering

M. Reddix, Manager, Security

D. Rencurrel, Vice President, Engineering

M. Ruvalcaba, Supervisor, Systems Engineering

R. Savage, Engineer, Licensing Staff Specialist

J. Sepulveda, Supervisor, Radiation Protection

J. Sheppard, President and CEO

D. Swett, Supervisor, Radiation Protection

K. Taplett, Senior Engineer, Licensing Staff Specialist

D. Towler, Manager, Quality

T. Walker, Manager, Quality

J. Wells, Manager, Work Control

J. Winters, Consulting Engineer, Systems

C. Younger, Test Engineering Supervisor

D. Zink, Supervisor, Plant Engineering

Attachment

LIST OF ITEMS OPENED, CLOSED, AND DISCUSSED

Opened

None

Opened and Closed

05000498/2007005-01 NCV Incorrect Count Rate Board Installed in Extended Range Nuclear Instrument Channel (Section 1R12)

05000498/2007005-02 NCV Inadequate Reportability Review Results in Missed Reporting Requirement (Section 1R12)

05000498/2007005-03 NCV Incorrectly Installed Safety-Related Solenoid Valve Results in Unexpected Steam Dump Valve Operation (Section 4OA2)

Closed

05000498/2006-006-01 LER Inoperable Auxiliary Feedwater Flow Instrumentation (Section 4OA3)

05000498/2007-003-00 LER Incorrect Count Rate Board Installed in Extended Range Nuclear Instrument Channel (Section 4OA3)

Discussed

None