IR 05000327/2003002
| ML030930200 | |
| Person / Time | |
|---|---|
| Site: | Sequoyah  |
| Issue date: | 04/02/2003 |
| From: | Ogle C NRC/RGN-II/DRS/EB |
| To: | Scalice J Tennessee Valley Authority |
| References | |
| IR-03-002 | |
| Download: ML030930200 (23) | |
Text
ril 2, 2003
SUBJECT:
SEQUOYAH NUCLEAR PLANT - NRC INSPECTION REPORT 50-327/03-02 AND 50-328/03-02
Dear Mr. Scalice:
On February 28, 2003, the Nuclear Regulatory Commission (NRC) completed a safety system design and performance capability inspection at your Sequoyah Nuclear Plant, Units 1 and 2.
The enclosed report documents the results of this inspection which were discussed on February 28, 2003, with Mr. D. Koehl and other members of your staff.
This inspection was an examination of activities conducted under your license as they relate to safety and compliance with the Commissions rules and regulations, and with the conditions of your operating license. Within these areas, the inspection involved selected examination of procedures and representative records, observations of activities, and interviews with personnel.
No findings of significance were identified during this inspection.
In accordance with 10 CFR 2.790 of the NRC's "Rules of Practice," a copy of this letter and its enclosure will be available electronically for public inspection in the NRC Public Document Room or from the Publicly Available Records (PARS) component of NRCs document system (ADAMS). ADAMS is accessible from the NRC web site at http://www.nrc.gov/reading-rm/adams.html (the Public Electronic Reading Room).
Sincerely,
/RA/
Charles R. Ogle, Chief Engineering Branch 1 Division of Reactor Safety Docket Nos.: 50-327, 50-328 License Nos.:DPR-77, DPR-79
Enclosure:
(See page 2)
TVA 2 Enclosure: NRC Inspection Report 50-327/03-02 50-328/03-02 w/Attachment
REGION II==
Docket Nos.: 50-327, 50-328 License Nos.: DPR-77, DPR-79 Report No.: 50-327/03-02, 50-328/03-02 Licensee: Tennessee Valley Authority (TVA)
Facility: Sequoyah Nuclear Plant, Units 1 & 2 Location: Sequoyah Access Road Soddy-Daisy, TN 37379 Dates: February 10-14 and February 24-28, 2003 Inspectors: J. Moorman, Lead Inspector C. Smith, Senior Reactor Inspector R. Moore, Reactor Inspector F. Jape, Senior Project Manager G. Skinner, Contractor Accompanied by: D. Mas-Penaranda, Intern Approved by: Charles R. Ogle, Chief Engineering Branch 1 Division of Reactor Safety Enclosure
SUMMARY OF FINDINGS
IR 05000327/2003-002, IR 05000328/2003-002; Tennesee Valley Authority; on 02/10-14/03 and 2/24-28/03; Sequoyah Nuclear Plant, Units 1 and 2; Safety System Design and Performance Capability Inspection.
This inspection was conducted by regional reactor inspectors and a contractor. No findings of significance were identified. The NRCs program for overseeing the safe operation of commercial nuclear power reactors is described in NUREG-1649, "Reactor Oversite Process,
Rev. 3, dated July 2000.
REPORT DETAILS
REACTOR SAFETY
Cornerstones: Initiating Events and Mitigating Systems
1R21 Safety System Design and Performance Capability
This team inspection reviewed selected components and operator actions that would be used to prevent or mitigate the consequences of a steam generator tube rupture (SGTR) event. Components in the main steam (MS), auxiliary feedwater (AFW), steam generator glowdown (SGBD), chemical and volume control (CVCS), reactor coolant (RCS), and radiation monitoring systems were included. This inspection also covered supporting equipment, equipment which provides power to these components, and the associated instrumentation and controls. The SGTR event is a risk-significant event as determined by the licensees probabilistic risk assessment.
.1 System Needs
.11 Controls
a. Inspection Scope
The team reviewed mechanical logic diagrams and electrical elementary diagrams of selected safety related components to verify that the components operation was consistent with the Updated Final Safety Analysis Report (UFSAR) description and the General Design Criteria (GDC) document for each process system. This review was conducted for the following equipment:
- PCV 1-5, steam generator 1 power operated relief valve
- FCV 147, steam generator 1 main steam isolation block valve
- FCV 1-181 and FCV 1-7, steam generator 1 blowdown isolation valves
- FCV 3-33, steam generator 1 feed water isolation valve
- FCV 3-35 and FCV 3-35A, steam generator 1 feed water flow control valves
- FCV 1-51, auxiliary feed water pump turbine trip and throttle valve
- motor driven auxiliary feed water pump 1A-A
- LCV 3-164, steam generator 1 level control valve from motor driven auxiliary feed water pump 1A-A
- LCV 3-164A, motor driven auxiliary feed water bypass level control valve for steam generator 1
- LCV 3-174, turbine driven auxiliary feed water steam generator 1 level control valve
- PCV 68-340A, pressurizer power operated relief valve
b. Findings
No findings of significance were identified.
.12 Energy Source
a. Inspection Scope
The team reviewed the electrical systems used for operation of critical equipment needed to mitigate a SGTR to verify the systems design, reliability, and availability were consistent with the design assumptions and licensing basis as described in the UFSAR.
Specific power availability for equipment reviewed included the charging pumps, motor driven AFW pumps, and AFW motor operated valves (MOVs). The team evaluated the 6900 volt
- (v) medium voltage system to assess vulnerabilities due to loss of the preferred offsite source and the standby onsite sources (diesel generators). In particular, the team evaluated adequacy of undervoltage protection and vulnerability to spurious separation from the offsite source. Documents reviewed included single line drawings, load flow calculations, protective device selection and coordination calculations, setpoint calculations, and design criteria documents.
The 125v vital direct current (DC) system, which is necessary to supply both motive and control power for SGTR mitigating systems, was evaluated by review of battery sizing calculations, voltage drop calculations, and protective device sizing and coordination studies. In addition, the team evaluated the 120v alternating current (AC) vital power system including inverter sizing, voltage drop, and transfer schemes for standby sources.
The team reviewed the availability, reliability and quality controls for the air system required for operation of air operated valves used to mitigate the SGTR event. Valve design drawings, vendor manuals, and periodic air quality test results were reviewed to verify that station air quality standards were consistent with vendor recommendations, regulatory guidance, and industry standards.
b. Findings
No findings of significance were identified.
.13 Process Medium
a. Inspection Scope
The team reviewed selected net positive suction head (NPSH) and tank volume calculations, design criteria information, drawings, and vendor manuals to verify that system design and UFSAR accident analysis assumptions were consistent with the actual capability of systems and equipment required to mitigate the SGTR event. This review included the refueling water storage tank (RWST) and its refill capability and the emergency raw cooling water (ERCW) supply as the assured source for the AFW system. The team also reviewed the volume control tank, condensate storage tank, and licensees actions to monitor and prevent degradation of the ERCW supply piping to the AFW pumps.
b. Findings
No findings of significance were identified.
.14 Operator Actions
a. Inspection Scope
The team reviewed selected portions of emergency operating procedures (EOPs),abnormal procedures (APs), annunciator response procedures (ARPs), and operating procedures (OPs) that operators would use to detect and mitigate a steam generator tube leak or tube rupture event. This review was conducted to verify that the procedures were consistent with guidance in the UFSAR and the EOP basis documents.
This review included a team observation of the operators use of the procedures during a simulator exercise of a SGTR event. The team also reviewed the EOP setpoints calculation to verify that the EOPs contained the correct setpoints.
b. Findings
No findings of significance were identified.
.15 Heat Removal
a. Inspection Scope
The team reviewed vendor manuals, design documentation, drawings, surveillance and test procedures, and equipment operating data to assess the reliability and availability of cooling for equipment and equipment spaces required to mitigate the SGTR event. This review was also conducted to verify that equipment operating conditions were consistent with design requirements and vendor recommendations. The equipment reviewed was cooling water to the AFW, safety injection (SI), and centrifugal charging pumps (CCPs).
b. Findings
No findings of significance were identified.
.2 System Condition and Capability
.21 Installed Configuration
a. Inspection Scope
The team performed field walk downs of accessible components in the AFW, CVCS, MS, and SGBD systems to assess general material condition, identify degraded conditions, and verify that the installed configuration was consistent with design drawings and design inputs to calculations. The team performed field walk downs of accessible electrical equipment to assess whether the installed configuration will support system functions under accident conditions. The components inspected included 6900v switchgear, 480v switchgear, AFW pump motors, AFW MOVs, the Unit 2 125v vital batteries, and their environs. Additionally, the team assessed potential flooding and missile impact on SGTR mitigation equipment. The team also inspected selected controls and indicators for appropriate human factors such as labeling, arrangement, and visibility.
b. Findings
No findings of significance were identified.
.22 Testing
a. Inspection Scope
The team reviewed surveillance testing and inspection documentation to verify design criteria were properly translated into acceptance criteria, were verified by test and maintenance activities, and that system and equipment function was maintained and performance degradation would be identified. This review included response time testing of valves, MOV torque and limit switch settings established in the MOV switch setting calculations, and selected controls and indicators in the control room that operators would use during a SGTR. This review also included selected surveillance procedures which are used for the calibration and functional test of post-accident monitoring (PAM) instruments The team reviewed data sheets for the last two functional tests and calibrations for the following indication equipment: radiation monitors, steam generator level, steam generator pressure, pressurizer level and RCS cold leg temperature. This review was conducted to determine if the functional test and calibrations were performed at intervals specified by the Technical Specifications (TS) and that any out-of-tolerance measurements or anomalies were addressed within the test procedure or following completion of the procedure.
b. Findings
No findings of significance were identified.
.23 Operation
a. Inspection Scope
During the in-plant procedures walk through and simulator exercise, the team assessed procedure adequacy, operator knowledge, and human factors design of the procedures and related equipment against Nuclear Regulatory Commission (NRC) requirements and guidelines for procedure quality. The team also observed simulator fidelity with the plant as needed to support effective operator training on EOPs. The team performed a walk through and verification of the procedure for refilling the RWST which could be used during a SGTR, to verify accessibility of equipment to be operated and the adequacy of guidance for this activity. Additionally, the team reviewed documented performances of this activity to verify that the licensee had demonstrated successful performance.
b. Findings
No findings of significance were identified.
.24 Design
a. Inspection Scope
The team reviewed load flow and voltage drop calculations to verify that supporting electrical systems would have sufficient capacity and capability to perform under the most limiting conditions required by the design and licensing bases. Calculations were reviewed to verify that they considered degradation of the offsite power source as well as limiting alignments of onsite electrical distribution equipment. The team reviewed operating procedures to verify that appropriate compensatory measures would be implemented when automatic voltage control equipment is out of service. The team reviewed calculation parameters subject to change, or subject to TS required surveillance, to verify that they were periodically verified and adjusted within required limits. Specifically, setpoints and intervals for under voltage relays, and on-load tap changer control calibrations were checked. In addition, the team reviewed outputs of electrical voltage drop calculations to verify that they were properly translated into MOV torque calculations.
The team reviewed design calculations, specifications, and UFSAR accident analysis to identify the design criteria which defined the required capacity and capability of SGTR mitigation equipment. Surveillance test procedures and equipment monitoring activities were reviewed to verify the design criteria was appropriately translated into acceptance criteria. The team reviewed NPSH calculations for the SI, AFW, and CCPs to verify that adequate NPSH was available from each of the applicable water sources. Design changes were reviewed to verify that system and equipment design functions were appropriately evaluated and maintained.
Instrument accuracy calculations prepared for process transmitters, 2-LT-3-43, 2-LT-68-320, 2-LT-3-42, and 2-PT-1-2A were reviewed by the team. This review was performed to verify that design input information required for determining the transmitters accident accuracy had correctly incorporated accident parameters for which the transmitters had been qualified. Component data sheets for the selected transmitters contained in the calculations were evaluated in order to verify that the design input information was consistent with values contained in the environmental qualification (EQ) binders.
Additionally, the team reviewed the accident accuracy calculation for the transmitters in order to verity that inaccuracies due to accident radiation exposure and temperature effect at accident conditions had been included in the analysis.
b. Findings
No findings of significance were identified.
.3 Selected Components
.31 Component Degradation
a. Inspection Scope
The team reviewed maintenance and testing documentation, performance trending, and equipment history as identified by in-service test program trending, work orders, system health reports, and PERs to assess the licensees actions to verify and maintain the safety function, reliability and availability of selected components. Also reviewed was the potential for common cause failure mechanisms due to flooding, maintenance, parts replacement and modifications. The selected components included: SG PORVs/secondary atmospheric reliefs (PCV-1-5,-12,-23,-30), PORV block valves (VLV-1-619,-620,-621,-622), SG safety valves (AFV-522 thru 526, et. al), SG blowdown isolation valves (FCV-1-181 thru 184), AFW SG inlet Iso valves (LCV-3-174, -64-,164A, et. al), TDAFW pump steam supply isolation valves (FCV-1-15,-16), AFW pumps, and charging pumps. Electrical equipment included switch yard and safety related portions of the electrical distribution system, including load tap changers, under voltage relays, vital batteries, and power circuit breakers.
b. Findings
No findings of significance were identified.
.32 Equipment/Environmental Qualification
a. Inspection Scope
The team reviewed load flow calculations, vendor correspondence, and qualification documentation to verify that the increased horsepower requirements for the charging pump motors, resulting from replacement of the pump impeller, did not shorten the qualified life of the motor, or increase motor running temperature beyond acceptable limits.
The team reviewed EQ binders SQNEQ-XMTR-001 and SQNEQ-1PT-002 in order to verify the accident parameters involving temperature, pressure, humidity, radiation and spray type for which selected instrument loops components were qualified. The scope of the review included the following field installed transmitters used during an SGTR event; 2-LT-3-43, 2-LT-68-320, 2-LT-3-42, and 2-PT-1-2A.
b. Findings
No findings of significance were identified.
.33 Operating Experience
a. Inspection Scope
The team reviewed the licensees applicability evaluations and corrective actions for selected industry experience issues related to turbine driven AFW pumps, MOVs, and service water system piping as related to SGTR mitigation equipment. Additionally, operating experience issues related to other SGTR equipment for the past two years were reviewed. The team reviewed the licensee response to Information Notice 95-05 regarding the effect of harmonic distortion on under voltage relays.
b. Findings
No findings of significance were identified.
.4 Identification and Resolution of Problems
a. Inspection Scope
The team reviewed selected SGTR mitigation equipment problems identified in the licensees corrective action program to assess the adequacy of the corrective actions to prevent recurrence and the scope of broadness reviews to other plant equipment. In addition, the team reviewed work orders on risk significant equipment to evaluate failure trends. The team also reviewed the licensees performance in the identification of procedural deficiencies.
b. Findings
No findings of significance were identified.
4. Other Activities
40A6 Meetings, Including Exit The lead inspector presented the inspection results to Mr. D. Koehl, and other members of the licensee staff, at an exit meeting on February 28, 2003. The licensee acknowledged the findings presented. Proprietary information is not included in this inspection report.
SUPPLEMENTAL INFORMATION
KEY POINTS OF CONTACT
Licensee
- J. Beasley, Site Quality Manager
- R. Gladley, Electrical Engineering Design Manager
- R. Goodman, Training Manager
- J. Hamilton, Site Support Manager
- D. Koehl, Plant Manager
- M. Lorek, Assistant Plant Manager
- D. Lundy, Engineering Manager
- R. Proffitt, Nuclear Engineer
- R. Rodgers, Engineering Design Manager
P. Salas. Licensing Manager
- J. Thomas, Mechanical Engineering Supervisor
- E. Truman, Operations Manager
- J. Wilkes, Maintenance Manager
NRC (attended exit meeting)
- C. Casto, RII, Division of Reactor Safety, Director
- S. Freeman, Senior Resident Inspector