IR 05000382/2006008
| ML061290021 | |
| Person / Time | |
|---|---|
| Site: | Waterford  |
| Issue date: | 05/08/2006 |
| From: | Laura Smith Division of Reactor Safety IV |
| To: | Venable J Entergy Operations |
| References | |
| IR-06-008 | |
| Download: ML061290021 (35) | |
Text
SUBJECT:
WATERFORD STEAM ELECTRIC STATION, UNIT 3 - NRC PROBLEM IDENTIFICATION AND RESOLUTION INSPECTION REPORT 05000382/2006008
Dear Mr. Venable:
On March 24, 2006, the U. S. Nuclear Regulatory Commission (NRC) completed a team inspection at your Waterford Steam Electric Station, Unit 3. The enclosed report documents the inspection findings, which were discussed with you and other members of your staff during an exit meeting on March 24, 2006.
This inspection was an examination of activities conducted under your license as they relate to the identification and resolution of problems, compliance with the Commissions rules and regulations and the conditions of your operating license. The team reviewed 237 condition reports, apparent cause and root cause analyses, as well as supporting documents. In addition, the team reviewed crosscutting aspects of NRC- and licensee-identified findings and interviewed personnel regarding the safety conscious work environment.
On the basis of the sample selected for review, there were no findings of significance identified during this inspection. The team concluded that, in general, problems were properly identified, evaluated, and corrected. The team concluded that a positive safety-conscious work environment existed at your Waterford Steam Electric Station, Unit 3. Several examples of minor problems were identified, including conditions adverse to quality that were not identified and entered into your corrective action program.
Entergy Operations, Inc. -2-In accordance with 10 CFR 2.390 of the NRC's "Rules of Practice," a copy of this letter and its enclosure, and your response (if any) will be available electronically for public inspection in the NRC Public Document Room or from the Publicly Available Records (PARS) component of NRCs document system (ADAMS). ADAMS is accessible from the NRC Web site at http://www.nrc.gov/reading-rm/adams.html (the Public Electronic Reading Room).
Sincerely,
/RA/
Linda Joy Smith, Chief Plant Engineering Branch Division of Reactor Safety Docket: 50-382 License: NPF-38
Enclosure:
NRC Inspection Report 05000382/2006008 ATTACHMENT A: Supplemental Information ATTACHMENT B: Waterford 3 Pressurizer Surge Line Temperature Change Rate ATTACHMENT C: White Paper on Effect of Diesel Sump Pump Inoperability on Ultimate Heat Sink Operability
REGION IV==
Docket: 50-382 License: NPF-38 Report: 05000382/2006008 Licensee: Entergy Operations, Inc.
Facility: Waterford Steam Electric Station, Unit 3 Location: Hwy. 18 Killona, Louisiana Dates: March 6-24, 2006 Inspectors: M. Brown, Project Engineer, Projects Branch A E. Crowe, Resident Inspector, Projects Branch E G. Larkin, Resident Inspector, Projects Branch E M. Murphy, Senior Operations Engineer, Operations Branch D. Overland, Project Engineer, Projects Branch B Approved by: L. J. Smith, Chief Engineering Branch 2 Division of Reactor Safety-1- Enclosure
SUMMARY OF FINDINGS
IR 05000382/2006008; Entergy Operations, Inc., 03/06-24/2006; Waterford Steam Electric
Station, Unit 3; biennial baseline inspection of the identification and resolution of problems.
The inspection was conducted by two resident inspectors, one senior operations engineer, and two project engineers. 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.
Identification and Resolution of Problems
- The team reviewed 237 corrective action program documents, apparent and root cause analyses, as well as supporting documents to assess problem identification and resolution activities. Based on this review, the team found the licensees process to identify, prioritize, evaluate, and correct problems was generally effective; thresholds for identifying issues remained appropriately low and, in most cases, corrective actions were adequate to address conditions adverse to quality. However, a number of issues were identified associated with the proper identification of degraded conditions in the plant. The team reviewed corrective actions associated with these degraded conditions and design issues at Waterford Steam Electric Station, Unit 3, which had crosscutting aspects in the area of problem identification and resolution.
The team concluded that a positive safety-conscious work environment exists at Waterford Steam Electric Station, Unit 3, based upon interviews conducted with plant personnel. The team determined that employees and contractors feel free to raise safety concerns to their supervision or bring concerns to the employee concerns program.
Inspector-Identified and Self-Revealing Findings None
REPORT DETAILS
OTHER ACTIVITIES (OA)
4OA2 Identification and Resolution of Problems
a. Effectiveness of Problem Identification
- (1) Inspection Scope The inspectors reviewed items selected across four of the seven cornerstones to determine if problems were being properly identified, characterized, and entered into the corrective action program for evaluation and resolution. Specifically, the teams review included a selection of 237 condition reports, equipment walkdowns, review of operator logs, maintenance records, and station quarterly trend reports. The majority of the condition reports were opened and closed since the last NRC problem identification and resolution inspection completed on May 21, 2004. The team also performed a historical review of condition reports written over the last 5 years for the high pressure safety injection system, main feedwater isolation valves, main steam isolation valves, essential chillers, and the emergency diesel generators. The team reviewed a sample of licensee audits and self assessments, trending reports, system health reports, and various other reports and documents related to the problem identification and resolution program.
The audit and self-assessment results were compared with the self-revealing and NRC-identified issues to determine the effectiveness of the audits and self assessments.
The team interviewed station personnel and evaluated corrective action documentation to determine the licensees threshold for identifying problems and entering them into the corrective action program. In addition, in order to assess the licensees handling of operator experience, the team reviewed the licensees evaluation of selected industry operating experience reports, including licensee event reports, NRC generic letters, NRC bulletins, and NRC information notices, and generic vendor notifications to assess if issues applicable to Waterford Steam Electric Station, Unit 3, were appropriately addressed.
A listing of specific documents reviewed during the inspection is included in the attachment to this report.
- (2) Assessment The team determined that, in general, problems were adequately identified and entered into the corrective action program, as evidenced by the relatively few findings identified during the assessment period. The licensees threshold for entering issues into the corrective action program was appropriately low. However, the team found two examples of ineffective problem identification during this inspection. The licensee also failed in some instances to identify or document deficiencies, which resulted in NRC noncited violations.
Current Issues Example 1: The licensee failed to identify multiple temperature changes of the pressurizer surge line, which exceeded the heatup and cooldown rate described in Section 5.4.3.1 of the stations Final Safety Analysis Report. Specifically, the inspection team discovered during a plant shutdown in August 2005 that the pressurizer surge line had experienced 19 changes in temperature, which exceeded this limit. This example is further described in Section 4OA2.e of this report.
Example 2: The team found the licensee's identification of adverse trends to be weak.
The inspection team reviewed 17 conditions reports, in which the licensee documented inadequacies in the procurement of replacement parts for the station. The licensee had identified a trend of improper parts passing through the receipt inspection, but failed to identify adverse trends related to lack of engineering involvement, as required by the procurement process; failure to perform professional engineering evaluations for parts transferred into the system; and receipt inspection documents missing required attributes. These procurement process weaknesses resulted in a nonseismically qualified synchronization switch being installed in an otherwise operable emergency diesel generator and a nonconforming fuel oil nipple passing receipt inspection.
Example 3: The NRC identified that the licensee missed several opportunities to identify the containment fan cooler condensate flow switches that did not meet the design requirements for detecting a one gallon per minute reactor coolant system leak (NRC Inspection Report 05000382/2005005-01).
Example 4: Control room operators missed several opportunities over a 32.5 hour5.787037e-5 days <br />0.00139 hours <br />8.267196e-6 weeks <br />1.9025e-6 months <br /> period to identify that a vacuum had been drawn on the reactor coolant system during refueling outage draindown conditions (self-revealing, NRC Inspection Report 05000382/2005010-03).
Historical Issue Example: The NRC identified the licensee failed to identify an inappropriate value of the unfiltered in-leakage parameter used to calculate the control room operator dose for design basis accident conditions involving radiological releases (NRC Inspection Report 05000382/2004006-01).
b. Prioritization and Evaluation of Issues
- (1) Inspection Scope The team reviewed condition reports, engineering operability evaluations, and operations operability determinations to assess the licensees ability to evaluate the importance of the conditions adverse to quality. The team reviewed a sample of condition reports, failure mode analyses, apparent cause and root cause analyses, to ascertain whether the licensee identified and considered the full extent of conditions,
generic implications, common causes, and previous occurrences. The team also observed management oversight of the significant conditions adverse to quality, including one Corrective Action Review Board meeting.
In addition, the inspectors reviewed licensee evaluations of selected industry operating experience reports, including licensee event reports, NRC generic letters, NRC bulletins, NRC information notices, and generic vendor notices to assess whether issues applicable to Waterford Steam Electric Station, Unit 3, were appropriately addressed.
The team performed a historical review of condition reports covering the last 5 years regarding the high pressure safety injection system, the emergency diesel generators, main feedwater isolation valves, essential chillers, and the dry cooling tower to determine if the licensee had appropriately addressed long-standing issues and those that might be age dependent.
A listing of specific documents reviewed during the inspection is included in the attachment to this report.
- (2) Assessment The team concluded that problems were generally prioritized and evaluated in accordance with the licensees corrective action program guidance and NRC requirements. The team found that for the sample of root cause analyses reviewed, that the licensee was generally self critical and exhaustive in its research into the history of significant conditions adverse to quality. However, the team found one example of ineffective problem evaluation during this inspection.
Current Issues Example 1: The inspectors discovered the licensee had categorized the failure of a fuel oil pipe nipple in the Emergency Diesel Generator B in 2002, as a condition adverse to quality. The licensee followed Procedure EN-LI-102, Corrective Action Process, Revision 4, in making the determination of significance. The inspectors followed the steps of Procedure EN-LI-102 and arrived at the same level of significance, however, the procedure provides a provision for the Condition Review Group to change the level of significance, as warranted by the conditions. The inspectors determined that this was a significant condition adverse to quality because the failure rendered one emergency diesel inoperable. The Emergency Diesel Generator A experienced a failure of its corresponding fuel oil nipple in 2005. The licensee determined this failure was a significant condition adverse to quality solely because of the repetitive nature of the failure.
c. Effectiveness of Corrective Actions
- (1) Inspection Scope The team reviewed 237 condition reports to verify that corrective actions related to the issues were identified and implemented in a timely manner commensurate with safety, including corrective actions to address common cause or generic concerns. The team
reviewed corrective actions planned and implemented by the licensee and sampled specific technical issues to determine whether adequate decisions related to structure, system, and component operability were made.
In addition, the team reviewed a sample of those condition reports written to address NRC inspection findings to ensure that the corrective actions adequately addressed the issues as described in the inspection report writeups. The team also reviewed a sample of corrective actions closed to other condition reports and programs, such as work and engineering work requests to ensure that the condition described was adequately addressed and corrected.
A listing of specific documents reviewed during the inspection is included in the attachment to this report.
- (2) Assessment The effectiveness of identified corrective actions to address adverse conditions was generally adequate. The team evaluated several occurrences where the licensee did not effectively address conditions adverse to quality and corrective actions taken were untimely and inappropriate. These included five examples, one identified by the team and four by other NRC inspections, where the licensee failed to take prompt corrective actions to resolve long-standing issues. The team also evaluated nine other findings identified by the NRC baseline inspection program and other NRC inspections at Waterford Steam Electric Station, Unit 3, since the last problem identification and resolution inspection that had crosscutting aspects related to prompt and effective corrective actions to resolve conditions adverse to quality.
Current Issues Example 1: The reactor coolant draindown procedure failed to identify that temporary vent rigs, required by procedure to properly establish vent paths, included in-line ball valves in series with the vent path and also failed to direct those ball valves be opened to establish the vent path. The licensee was aware of and did not fix the procedure to address the ball valves in 2002 (NRC Inspection Report 05000382/2005010-02).
Example 2: The NRC identified the licensee failed to correct the condition which resulted in multiple cycle timer failures in the essential chiller (NRC Inspection Report 05000382/2005002-01).
Example 3: The NRC identified the licensee failed to prevent recurrence of through wall pipe leakage on the main steam line Pipe 2MS2-123. This deficiency resulted in an unisolable steam leak requiring NRC approval to deviate from the American Society of Mechanical Engineers Boiler and Pressure Code Case N523-2 to perform temporary repairs preventing a plant shutdown (NRC Inspection Report 05000382/2005004-03).
Historical Issues Example 1: The NRC identified the licensee failed to correct a known deficient condition involving the failure to account for instrument uncertainty to satisfy Technical Specification Surveillance Requirement 4.7.6.5.a. This failure potentially affects the ability of the control room envelope to perform its design function with respect to protecting operators from postulated design basis accidents resulting in radiological releases (NRC Inspection Report 05000382/2004006-03).
Example 2: The NRC identified the licensee failed to correct a known deficient condition involving multiple occasions of accumulator overpressure conditions resulting from degraded hydraulic fluid adversely affecting the main feedwater isolation valve hydraulic actuator pressure relief system. These over pressure conditions potentially result in valve closure stroke times outside design basis values (NRC Inspection Report 05000382/2004005-03).
Example 3: The NRC identified the licensee failed to promptly correct instances where the main feedwater isolation valve actuator thermal relief valves failed to properly function. In one case, the licensee failed to properly address system operability and, for a 2-week period, actual valve operability was unknown (NRC Inspection Report 05000382/2004006-02).
Example 4: The NRC identified the licensee failed to correct deficiencies in the emergency diesel generator loading and fuel oil consumption analysis. The licensee inappropriately closed a corrective action requiring the revisions, which subsequently resulted in the failure to maintain design control of the emergency diesel generator fuel oil storage inventory requirements to ensure a 7-day postaccident fuel oil inventory (NRC Inspection Report 05000382/2004002-05).
Example 5: The NRC identified the licensee failed to determine the cause and precluded recurrence of main steam isolation solenoid-operated dump valve failures.
The inspectors noted that the licensees apparent cause did not provide an extent of condition analysis for the solenoid-operated valve failure (NRC Inspection Report 05000382/2004004-03).
Example 6: The NRC identified the licensee failed to take adequate corrective action to ensure the torque applied to the flow control valve for Accumulator B of main feedwater isolation Valve 1 was sufficient to prevent an o-ring from extruding, resulting in a loss-of-system hydraulic fluid and rendering the valve inoperable (NRC Inspection Report 05000382/2004008-02).
Example 7: The NRC identified the licensee failed on multiple occasions to correct a known deficient condition involving the failure to account for instrument uncertainty to satisfy Technical Specification Surveillance Requirement 4.7.6.5.a. This failure potentially affects the ability of the control room envelope to perform its design function with respect to protecting operators from postulated design basis accidents resulting in radiological releases (NRC Inspection Report 05000382/2004006-03).
Example 8: The licensee failed to replace known age-degraded o-rings affecting the main feedwater isolation valves in the Year 2000 resulting in o-ring failure and inoperability of the Train A feedwater isolation valve on December 27, 2003 (NRC Inspection Report 05000382/2004002-01).
Example 9: The NRC identified the licensee failed to establish appropriate torque specification to ensure adequate o-ring compression that ultimately led to an o-ring failure and the inoperability of the Train A main feedwater isolation valve. The licensee had previously identified concerns related to inadequate work instructions for performing maintenance activities on the main feedwater isolation valves (NRC Inspection Report 05000382/2004002-02).
d.
Assessment of Safety-Conscious Work Environment
- (1) Inspection Scope The team interviewed 24 individuals from the licensees staff, representing a cross section of functional organizations and supervisory and nonsupervisory personnel.
These interviews assessed whether conditions existed that would challenge the establishment of a safety-conscious work environment. The team interviewed the site employee concerns program coordinator.
- (2) Assessment The team concluded that a positive safety-conscious work environment exists at Waterford Steam Electric Station, Unit 3. Based on interviews, station personnel felt free to enter issues into the corrective action program, raise safety concerns with their supervision, to the employee concerns program, and to the NRC. The team determined that the majority of safety concerns were addressed through the sites normal chain of command by the relatively few safety concerns entered into the employee concerns program and the small number of allegations made to the NRC.
e.
Specific Issues Identified During this Inspection
- (1) Inspection Scope During this assessment, the team performed the inspections scoped in Sections 4OA2 a.(1), 4OA2 b.(1), 4OA2 c.(1), and 4OA2 d.(1) above.
- (2) Finding Details
- (i) Unresolved Item: 05000382/2006008-01, Failure to Maintain Design Control of the Pressurizer Surge Line
Introduction.
The team identified an unresolved item related to compliance with 10 CFR Part 50, Appendix B, Criterion III, Design Control, for the failure to translate design-basis heatup and cooldown rates for the pressurizer surge line into appropriate specifications, procedures, and instructions. As a result, Entergy Operations, Inc., failed
to effectively control and evaluate pressurizer surge line temperature changes on numerous occasions.
Description.
Final Safety Analysis Report (FSAR) Section 5.4.3.1, Reactor Coolant Piping Design Basis, and Section 5.4.10.1, Pressurizer Design Basis, states, in part, that during heatup and cooldown of the plant, the allowable rate of temperature change for the surge line is limited to 200°F/hr. Technical Requirements Manual (TRM),
Section 3.4.8.2, Pressurizer Heatup/Cooldown, specifies the limiting condition for operation, in part, as a maximum heatup rate of 200°F per hour and a maximum cooldown rate of 135°F per hour.
On April 18, 2005, Entergy Condition Report CR-WF3-2005-1392 stated that a pressurizer surge line temperature transient occurred with the surge line temperature dropping from 425°F to 140°F, a change of approximately 285°F with approximately 200°F occurring within 8 minutes. Technical Requirements Manual, Section 3.4.8.2 Action specifies, "With any of the pressurizer limits in excess of the above, the operators must restore the affected parameter to within the limits within 30 minutes; perform an engineering evaluation to determine the effects of the out-of-limit condition on the structural integrity of the pressurizer; and enter TRM LCO 3.0.3."
The team noted that Entergy Operations, Inc., failed to restore pressurizer/surge line limits within 30 minutes and perform an engineering evaluation to determine the effects of the out-of-limit condition on the structural integrity of the pressurizer/surge line. The team reviewed Entergy Operations, Inc.s operating procedures for plant heatup and cooldown activities, OP-010-005, Plant Shutdown, and OP-010-003, Plant Startup, and did not find procedure steps to limit surge line temperature changes to less than 200°F/hr, nor were there any procedure steps to assess whether surge line stress or fatigue limits had been exceeded. This appeared to be a violation of 10 CFR Part 50, Appendix B, Criterion III, Design Control, for the failure to translate design-basis heatup and cooldown rates for the pressurizer surge line into appropriate specifications, procedures, and instructions.
The design limit in Report CEN-387-P was based, in part, by temperature gradients greater than 200°F occurring less than 3.6 occurrences per heatup/cooldown cycle for 500 heatup/cooldown cycles over the 40-year life of the plant. Calculation CN-OA-04-53 documented 19 instances where pressurizer insurges, in excess of the volume of the surge line, occurred with a temperature gradient greater than 200°F. These pressurizer insurges occurred during five refueling outage heatup/cooldown cycles (Refueling Outages 8-12)for an average of 3.8 temperature gradients greater than 200°F per heatup/cooldown cycle.
Entergy Operations, Inc. disagreed and provided a paper (Attachment B), which documented their position. While they acknowledged that the FSAR was not up to date, they stated that the pressurizer surge line temperature transient on April 18, 2005, was bounded by Combustion Engineering Owners Group Report CEN-387-P, Pressurizer Surge Line Flow Stratification Evaluation, submitted to the NRC in response to NRC Bulletin 88-11, Pressurizer Surge Line Thermal Stratification. Report CEN-387-P concluded that the pressurizer surge line met all applicable design codes, FSAR, and
other regulatory commitments for the licensed life of the plant considering the phenomenon of thermal stratification in fatigue and stress evaluations. The team noted that this conclusion was based on operating the plant consistent with the assumptions in the evaluation (Report CEN-387-P). Additional inspection is required to complete the review of Entergy Operations, Inc.'s, position and determine whether the licensee was operating their facility within the assumptions of the analysis.
Analysis.
The significance of this issue depends on whether or not the analysis bounds past plant operation.
Enforcement.
The potential failure to translate the design basis into appropriate specifications, procedures, and instructions to effectively control and evaluate surge line temperature changes, during plant heatup and cooldown, that exceeded those limits described in the FSAR and the TRM is unresolved: (URI 05000382/2006008-01);
"Failure to Maintain Design Control of the Pressurizer Surge Line."
- (ii) Unresolved Item 05000382/2006008-02, Failure to Ensure that Written Procedures Adequately Incorporate Regulatory Requirements and Design Basis
Introduction.
The team identified an unresolved item related to compliance with Technical Specification, Section 6.8.1, for the failure to ensure that written procedures adequately incorporate regulatory requirements and the design basis for the dry cooling tower diesel-driven sump pumps.
Description.
Waterford Safety Evaluation Report, Supplement 4, Section 2.4.2.3, discusses the design basis rainfall event and combination of events. This supplement commits the licensee to the probable maximum precipitation event. Because of the fact that the motor-driven sumps are not seismically qualified, the NRC requested the licensee analyze the effects of a standard project storm, which consists of 50 percent of the probable maximum precipation event concurrent with an operating basis earthquake. The results of the licensees analysis showed the licensee was susceptible to ponding in the dry cooling tower sumps, assuming the loss of all motor-driven pumps, which would endanger the safety-related transformers and motor control centers located in the cooling tower areas.
The licensee submitted Amendment 34, dated January 1984, subsequent to Safety Evaluation Report, Supplement 4. Section 2.4.2.3.4 of this amendment submittal contains an analysis showing the probability of standard project storm and operating basis earthquake is 3.6E-08, which is considered negligible. However, the licensee proposed to provide a 100 gpm portable pump that would be sufficient to pump down the dry cooling tower sumps in the event of the standard project storm. The NRC determined that the portable pump was sufficient (as evidenced in Safety Evaluation Report, Supplement 4) provided the pump was placed in operation within 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br />. In 2000, after determining that more sump pumping capacity was needed, the licensee installed a diesel-driven sump pump, with 300 gpm capacity, in each dry cooling tower sump. The Design Basis Calculation EC-M99-010 analyzed for a probable maximum precipation event, concurrent with a loss-of-offsite power, and determined that a higher capacity portable pump was needed. The calculation also analyzed for a rainfall equivalent to 60 percent of the probable maximum precipation event, concurrent with a loss of all motor-driven sump pumps, and determined that a 300 gpm portable pump
would be sufficient. The licensees Procedure OP-100-014, Technical Specifications and Requirements Compliance, Revision 14, states that two motor-driven sump pumps or one motor-driven pump and one diesel-driven pump are required for ultimate heat sink operability. This procedure implies that the diesel driven sump pump can be out of service indefinitely without affecting operability of the ultimate heat sink. The NRC staff believes this procedure does not adequately address the requirement of the portable sump pump in the design basis of the ultimate heat sink, nor does the procedure require any compensatory actions be taken in the event the diesel-driven sump pump becomes inoperable. Also, the staff believes the controls and location of the diesel-driven sump pump are not adequately addressed by the licensee.
Analysis.
The significance of this issue has not been determined.
Enforcement.
The licensee has provided a position paper (Attachment C) related to the design basis requirements for the dry cooling tower diesel-driven sump pumps, which has not been fully reviewed by the NRC. The potential failure to ensure regulatory requirements for these pumps is unresolved: (URI 05000382/2006008-02) "Failure to Translate Design Control into Station Documents Regarding Diesel-driven Dry Cooling Tower Sump Pumps"
4OA6 Exit Meeting
The team discussed the findings of the Problem Identification and Resolution inspection with Mr. J. Venable, Vice President Operations, and other members of the licensees staff on March 24, 2006. Licensee management did not identify any materials examined during the inspection as proprietary.
The licensee acknowledged the findings presented. The inspectors noted that while proprietary information was reviewed, none would be included in this report.
ATTACHMENT A: Supplemental Information ATTACHMENT B: Waterford 3 Pressurizer Surge Line Temperature Change Rate ATTACHMENT C: White Paper on Effect of Diesel Sump Pump Inoperability on Ultimate Heat Sink Operability
KEY POINTS OF CONTACT Licensee Personnel B. Baxter, Control Room Supervisor C. DeDeaux Sr., Senior Project Manager, Licensing R. Dodds, Manager, Operations R. Fletcher, Training Manager C. Fugate, Assistant Operations Manager J. Hall, Operations Training Supervisor - Operator Requalification J. Holman, Manager, Nuclear Engineering J. Laque, Manager, Maintenance R. Murillo, Senior Staff Engineer R. Osborne, Manager, Engineering Programs and Components A. Pilutti, Manager, Radiation Protection O. Pipkins, Senior Licensing Engineer R. Porter, Superintendent, Mechanical Maintenance B. Proctor, Systems Engineering Manager J. Rachal, Design Engineering Supervisor J. Ridgel, Manager, Corrective Action Program T. Tankersley, Acting Director, Nuclear Safety Assurance K. Walsh, General Manager, Plant Operations B. Williams, Engineering Director J. Venable, Site Vice President, Waterford 3 NRC M. Hay, Senior Resident Inspector Waterford 3 LIST OF ITEMS OPENED, CLOSED, AND DISCUSSED Opened 05000382/2006008-01 URI Failure to Maintain Design Control of the Pressurizer Surge Line (Section 4OA2 e.)05000382/2006008-02 URI Failure to Translate Design Control into Station Documents Regarding Diesel-driven Dry Cooling Tower Sump Pumps (Section 4OA2 e.)
A
LIST OF
DOCUMENTS REVIEWED
Plant Procedures
NAME TITLE REVISION
CEP-IST-1 IST Bases Document 3
EN-OP-115 Conduct of Operations 0
LI-102 Corrective Action Process 4
LI-19645 Quality Related Administrative Procedure 2
MM-006-119 Yard Oil Separator to CW Temporary Pumping System 0
OI-042-000 Watch Station Procedures 1
OP-001-003 Reactor Coolant System Draindown 23
OP-005-004 Main Steam 12
OP-009-008 Safety Injection System 18
OP-100-001 Operations Standards and Management Expectations 22
OP-100-009 Control of Valves and Breakers 17
OP-100-0014 Technical Specification and Technical Requirements 13
Compliance
UNT-005-004 Temporary Alteration Control 16
Engineering Reports
ER-W3-2002-0055 ER-W3-2004-0537 ER-W3-2005-0426 ER-W3-00-0337
ER-W3-2003-0010 ER-W3-2005-0305 ER-W3-2002-0278
Calculations
CN-OA-04-53 EC-M99-010 MN(Q)-6-27
Root Cause Analysis Reports for CR-WF3-
2001-0317 2002-0339 2003-0062 2003-3891 2004-759 2004-1011
Attachment A
Condition Reports, CR-WF3-
1997-1227 2004-0759 2004-2404 2005-0109 2005-1626 2005-3831
2000-0441 2004-0821 2004-2487 2005-0132 2005-1646 2005-3840
2000-1347 2004-0835 2004-2496 2005-0134 2005-1694 2005-3872
2000-1455 2004-0865 2004-2517 2005-0197 2005-1821 2005-3872
2001-0596 2004-0903 2004-2520 2005-0217 2005-1836 2005-3902
2001-0673 2004-1011 2004-2522 2005-0346 2005-2070 2005-3914
2001-0782 2004-1047 2004-2545 2005-0413 2005-2139 2005-3924
2001-1284 2004-1190 2004-2547 2005-0415 2005-2267 2005-3928
2001-1367 2004-1208 2004-2549 2005-0471 2005-2272 2005-3960
2002-0468 2004-1312 2004-2638 2005-0489 2005-2350 2005-3961
2002-0470 2004-1340 2004-2690 2005-0530 2005-2402 2005-3985
2002-0588 2004-1446 2004-2722 2005-0587 2005-2469 2005-4038
2002-0678 2004-1480 2004-2734 2005-0590 2005-2489 2005-4065
2002-1410 2004-1518 2004-2766 2005-0591 2005-2536 2005-4066
2002-1842 2004-1553 2004-2884 2005-0592 2005-2546 2005-4067
2002-2799 2004-1572 2004-2890 2005-0608 2005-2548 2005-4147
2003-0147 2004-1593 2004-2928 2005-0717 2005-2600 2005-4149
2003-0577 2004-1621 2004-2973 2005-0763 2005-2679 2005-4151
2003-1192 2004-1645 2004-2995 2005-0804 2005-2685 2005-4173
2003-1202 2004-1646 2004-3066 2005-0805 2005-2695 2005-4251
2003-2758 2004-1668 2004-3130 2005-0806 2005-2780 2005-4444
2003-2759 2004-1679 2004-3200 2005-0839 2005-2799 2005-4480
2003-2991 2004-1684 2004-3219 2005-0852 2005-2819 2005-4597
2003-3088 2004-1716 2004-3244 2005-0921 2005-2837 2005-4647
2003-3649 2004-1751 2004-3413 2005-0966 2005-2844 2005-4694
2003-3891 2004-1753 2004-3460 2005-0967 2005-2869 2005-4915
2004-0251 2004-1763 2004-3464 2005-1132 2005-2874 2005-4917
2004-0304 2004-1810 2004-3695 2005-1143 2005-2990 2005-4929
2004-0309 2004-1850 2004-3720 2005-1173 2005-3006 2005-5024
2004-0326 2004-1854 2004-3725 2005-1247 2005-3091 2006-0006
2004-0420 2004-1855 2004-3753 2005-1260 2005-3293 2006-0058
2004-0464 2004-1863 2004-3853 2005-1279 2005-3308 2006-0164
2004-0483 2004-1880 2004-3881 2005-1315 2005-3455 2006-0200
2004-0494 2004-1942 2004-3924 2005-1332 2005-3474 2006-0380
2004-0508 2004-2002 2004-3944 2005-1346 2005-3659 2006-0492
2004-0634 2004-2228 2004-3949 2005-1362 2005-3698 2006-0759
2004-0651 2004-2290 2004-4000 2005-1363 2005-3812 2006-0767
2004-0701 2004-2320 2005-0033 2005-1392 2005-3822 2006-0839
2004-0703 2004-2326 2005-0081 2005-1463 2005-3830 2006-0895
2004-0721 2004-2382 2005-0098
Attachment A
Learning Organization Conditions Reports
LO-OPX-2004-0247 LO-OPX-2005-0100 LO-OPX-2005-0217 LO-OPX-2006-0011
LO-OPX-2005-0036 LO-OPX-2005-0103 LO-OPX-2005-0243 LO-OPX-2006-0034
LO-OPX-2005-0085 LO-OPX-2005-0132 LO-OPX-2005-0252
Work Orders
51697 52825 72604 412565 4599901
51699 57759 72606 4281801 5100331101
2824 62641
Maintenance Action Items
20105 438981
Miscellaneous Documents
Commercial Grade Evaluation 01214
C-PAC-002
L-23993
MMR Project 53465
PO WPY20583
2004 Second Quarter Waterford Quarterly Trend Report
2004 Third Quarter Waterford Quarterly Trend Report
2004 Fourth Quarter Waterford Quarterly Trend Report
Quality Assurance Audit Report QA-12-20050-WF3-1
Quality Assurance Audit Report QA-12-20050-WF3-009
Quality Assurance Audit Report QA-12-20050-WF3-1
PO 10083675
INITIAL MATERIAL REQUEST
INITIAL INFORMATION REQUEST FROM WATERFORD 3
FOR PI&R INSPECTION (Report Number 05000382/2004006)
The inspection will cover the period of October 2002 to March 2004. The information may be
provided in either electronic or paper media or a combination thereof. Information provided in
electronic media may be in the form of CDs, or 3-1/2 inch floppy disks. The agencys text editing
software is Corel WordPerfect 8, Presentations, and Quattro Pro; however, we have document
viewing capability for MS Word, Excel, Power Point, and Adobe Acrobat (.pdf) text files.
Please provide the following information to Peter Alter by March 29, 2004 at the Resident
Inspector Office at Waterford-3
Attachment A
All procedures governing or applying to the corrective action program, including the
processing of information regarding generic communications and industry operating
experiences
Procedures and descriptions of any informal systems, used by engineering, operations,
maintenance, security, training, and emergency planning for issues below the threshold
of the formal corrective action program
A searchable table of all corrective action documents (condition reports) that were
initiated or closed during the period, include condition report number, description of
issue and significance classification
Either annotate on the above list or a separate list of all condition reports associated
with:
(1) Human performance issues
(2) Emergency preparedness issues
(3) Response to 10 CFR Part 21 reports
A separate list of all condition reports closed to other programs, such as maintenance
action items/work orders, engineering requests, etc.
A copy of each significant event review team report and root cause analysis report for
the period (not necessarily the whole condition report)
Copies of condition reports (for the period) associated with nonescalated (no response
required) or noncited violations for the period
Copies of condition reports for the period associated with repetitive problems or issues
Copies of condition reports for the period associated with ineffective or untimely
corrective actions
List of all self assessments or quality assurance assessments/audits for the period
All corrective action program reports or metrics used for tracking effectiveness of the
corrective action program for the period
All quality assurance audits and surveillances, and functional self assessments of
corrective action activities completed for the period
Control room logs for the Year 2003
Security event logs for the year 2003
Radiation protection event logs for the year 2003
List of risk significant systems from W3 PRA/PSA, based on risk achievement worth
(RAW) and "0% availability CDF"
Attachment A
Searchable list of all maintenance action items/work orders for the period
List of all SSCs placed in or removed from the maintenance rule a(1) category for the
period
All corrective action documents related to the following industry operating experience
generic communications:
NRC Bulletins
NRC Bulletin 2002-001, Reactor Pressure Vessel Head Degradation and Reactor
Coolant Pressure Boundary Integrity
NRC Information Notices
NRC Information Notice 2004-001, Auxiliary Feedwater Pump Recirculation Line Orifice
Fouling - Potential Common Cause Failure
NRC Information Notice 2003-019, Unanalyzed Condition of Reactor Coolant Pump
Seal Leakoff Line During Postulated Fire Scenarios or Station Blackout
NRC Information Notice 2003-013, Steam Generator Tube Degradation at Diablo
Canyon
NRC Information Notice 2003-011, Leakage Found on Bottom-Mounted
Instrumentation Nozzles
NRC Information Notice 2003-008, Potential Flooding Through Unsealed Concrete
Floor Cracks
NRC Information Notice 2003-005, Failure to Detect Freespan Cracks in PWR Steam
Generator Tubes
NRC Information Notice 2003-002, Recent Experience With Reactor Coolant System
Leakage And Boric Acid Corrosion
NRC Information Notice 2002-034, Failure of Safety-Related Circuit Breaker External
Auxiliary Switches at Columbia Generating Station
Attachment A
Information Request 1 - January 2006
Waterford PIR Inspection (IP 71152; Inspection Report 50-382/06-08)
The inspection will cover the period of March 1, 2004 to March 1, 2006. All requested
information should be limited to this period unless otherwise specified. The information may be
provided in either electronic or paper media of a combination of this media. Information
provided in electronic media may be in the form of e-mail attachment(s), CDs, or 3 1/2 inch
floppy disks. The agencys text editing software is Corel WordPerfect 10, Presentations, and
Quattro Pro; however, we have document viewing capability for MS Word, Excel, PowerPoint,
and Adobe Acrobat (pdf.) text files.
Please provide the following by February 8, 2006, to:
U.S. Nuclear Regulatory Commission
Resident Inspectors Office - Attn. Grant Larkin
Waterford Steam Electric Station Unit 3
Entergy Operations, Inc.
265 River Road
Killona, Louisiana 70066
Note: On summary lists please include a description of problem, status, initiating date, and
owner organization
1. Summary list of all condition reports opened during the period
2. Summary list of all open condition reports with significance of B or greater which were
generated during the period
3. Summary list of all condition reports with significance of B or greater closed during the
specified period
4. Summary list of all condition reports which were down-graded or up-graded in
significance during the period
5. A list of all corrective action documents that subsume or "roll-up" one or more smaller
issues for the period
6. List of all root cause analyses completed during the period
7. List of all apparent cause analyses completed during the period
8. List of root cause analyses planned, but not complete at end of the period
9. List of plant safety issues raised or addressed by the employee concerns program
during the period
10. List of action items generated or addressed by the plant safety review committees
during the period
Attachment A
11. Summary list of operator work-arounds, engineering review requests and/or operability
evaluations, temporary modifications, safety system deficiencies, and control room
deficiencies
2. All quality assurance audits and surveillances of corrective action activities completed
during the period
13. A list of all quality assurance audits and surveillances scheduled for completion during
the period, but which were not completed
14. All corrective action activity reports, functional area self-assessments, and non-NRC
third party assessments completed during the period
15. Corrective action performance trending/tracking information generated during the period
and broken down by functional organization
16. Current procedures/policies/guidelines for:
1. Condition Reporting
2. Corrective Action Program
3. Root Cause Evaluation/Determination
4. Deficiency Reporting and Resolution
17. A listing of all external events evaluated for applicability at Waterford during the period
18. Condition Reports or other actions generated for each of the items below [ADAMS
accession numbers or other cross reference listed for some]:
1. Part 21 Reports (2005-41-00; 2005-38-00 [ml053180299]; 2005-37-00;
2005-33-01 [ml052860229]; 2005-30-01 [ml052640220]; 2005-26-01
[ml052910389]; 2005-22-00; 2005-20-00; 2005-17-00 [ml051110087];
2005-16-00 [ml051100285]; 2005-13-00 [ml050950428]; 2005-12-01
[ml052080368]; 2005-12-00 [ml050630275]; 2005-10-00 [ml050560142];
2005-07-00; 2005-05-01 [ml051100355]; 2005-01-00 [ml043520077];
2004-27-01 [ml043280541]; 2004-24-00 [ml042470299]; 2004-22-00
[ml042660175]; 2004-21-00 [ml042520048]; 2004-17-00 [ml041900058];
2004-15-00; 2004-14-00; 2004-10-00 [ml041140335]; 2004-08-00
[ml041110893]; 2004-02-01 [ml040420567]
2. NRC Information Notices 05-32; 05-31; 05-30; 05-29; 05-26; 05-25; 05-24; 05-
23; 05-21; 05-19; 05-16; 05-11; 05-09; 05-08; 05-06; 05-02;04-021; 04-019; 04-
016;04-012; 04-011;04-010; 04-009;04-008; 04-007;04-001
3. All LERs issued by Waterford during the period
4. NCVs and Violations issued to Waterford during the period
19. Safeguards event logs for the period
20. Radiation protection event logs
Attachment A
21. Current system health reports or similar information
2. Current predictive performance summary reports or similar information
23. Corrective action effectiveness review reports generated during the period
Attachment A
ATTACHMENT B
Waterford 3 Pressurizer Surge Line Temperature Change Rate
Waterford 3 Pressurizer Surge Line Temperature Change Rate
Purpose
This Paper is to document the Entergy position on the potential NCV of 10CFR50
Appendix B, Criterion III, Design Control for not translating design basis criteria
into plant operating procedures. The design basis criteria in question is a
statement in the FSAR (Section 5.4.3.1) which states:
During heatup and cooldown of the plant, the allowable rate of
temperature change for the surge line is increased to 200°F/hr as a design
requirement specified in Subsection 3.9.1.1.
Background
The following is a time line of the Entergy response to NRC Bulletin No. 88-11.
This concludes that the fatigue life of the Waterford 3 surge line is 40 years which
the NRC concurred with.
- The NRC issued NRC Bulletin No. 88-11, Pressurizer Surge Line Thermal
Stratification, on December 20, 1988. The purpose of the Bulletin was to
request that addressees establish and implement a program to confirm
pressurizer surge line integrity in view of the occurrence of thermal
stratification and to inform the staff of the actions taken to resolve this
issue.
- CEN-387-P was transmitted to the NRC on July 27, 1989. This
documented that the Waterford 3 surge line fatigue life is longer than 40
years.
- On August 28, 1989, Entergy sent a letter to the NRC stating that Bulletin 88-11 item 1b, 1c and 1d were addressed in CEN-387-P and that item 1a
(visual inspection of the pressurizer surge line) would be addressed during
the next refueling outage.
- On March 7, 1990, Entergy sent a letter to the NRC which addressed the
results of the visual inspections of the pressurizer surge line. The letter
concluded that the Waterford 3 surge line was structurally sound.
- On August 15, 1990, the NRC issued a letter stating there was not enough
information in the CEN document to conclude that the pressurizer surge
line meets all appropriate Code limits for a 40 year plant life.
- On December 20, 1991, CEN-387-P, Revision 1-P was sent to the NRC to
address the concerns of the August 15, 1990 NRC evaluation of the CEN
document.
- On May 5, 1992, Entergy sent a letter to the NRC documenting the
submittal of the revised CEN document and stated the only remaining
action to complete the response to the Bulletin is for the Waterford 3 to
update the pressurizer surge line design documentation. This was
committed to be completed within 180 days of issuance of a favorable
SER by the NRC.
Page 1 of 4
Waterford 3 Pressurizer Surge Line Temperature Change Rate
- On June 22, 1993, the NRC issued an SER for CEN-387-P, Revision 1. It
was concluded that the analysis in the CEN adequately demonstrates that
the bounding surge line and nozzles meet ASME Code stress and fatigue
requirements for the 40 year design life of the facility considering the
phenomenon of thermal stratification and thermal stripping. The staff
requested Entergy to provide a final status of the Waterford 3 activities
required by NRC Bulletin 88-11.
- On December 23, 1993, Entergy sent a letter to the NRC stating that all
design documents had been updated and that all actions required by NRC
Bulletin 88-11 had been completed.
CEN-387-P, Revision 1, is the Combustion Engineering response to NRC
Bulletin 88-11. This document addresses pressurizer surge line flow
stratification. The document provides a detailed fatigue analysis of stress due to
stratified temperature profiles of the fluid in the pressurizer surge line. Note that
this document indicates that thermal stratification is assumed for all surge flow as
the velocities will always be low. This document also specifically indicates that
the stratified temperature analysis envelopes high velocity flow and thermal
shock.
The following paragraphs are excerpted from the Thermal Striping Analysis for
the pressurizer surge line in CEN-387-P, Revision 1. The conclusion is the
effect of thermal striping is negligible and will not affect the fatigue life of the
pressurizer surge line.
The term striping refers to the thermal oscillations that occur at the hot-
cold interface.
The period of oscillations was chosen to be 1 second and 4 seconds for
the surge line analysis. Test data was measured or was empirically
determined to be in the range of 1 second to 10 seconds. For the large
temperature differences and high heat transfer coefficient used in this
analysis, the period is closer to 1 second than 4 seconds. A longer period
would yield a lower heat transfer coefficient, and therefore smaller
changes in metal temperatures. However, to be conservative, the same
heat transfer coefficient was used for all cases.
The stresses due to each gradient as a function of time were calculated
using formulas in ASME Code Section III, NB-3653.2. Table 3.5.3-2 lists
the alternating stress calculated for each of the four transients used for
evaluating fatigue. As can be seen from this table only one of the four
transients contributes anything to fatigue. That transient is number four
(4) with an alternating stress of 15,780 psi and a number of allowable
cycles of 1.42E7.
Page 2 of 4
Waterford 3 Pressurizer Surge Line Temperature Change Rate
Waterford 3 Design Specification 9270-PE-140 is the project specification for
reactor coolant pipe and fittings. This document provides a summary of the
design analysis for surge line temperature transients. It includes text sections
and 2 tables as they apply to the surge line and surge line nozzle. The tables
address temperature differences anticipated as a result of thermal stratification.
Table 4.5.15.3.1 lists expected occurrences of temperature differences between
the pressurizer and the RCS hot leg and provides the number of expected
occurrences. Table 4.5.15.3.2 lists expected occurrences of temperature
differences between the top and bottom of the surge line piping. These
temperatures differences are for the pressurizer surge line piping and not the
fluid temperature in the piping. The number of occurrences is the expected
number for the life of the plant.
Entergy Position
The Entergy position is that pressurizer surge line temperature is not required to
be specifically monitored per procedure to ensure the design limits are
maintained, and that FSAR Section 5.4.3.1 should have been revised in 1993
when the Waterford 3 stress and fatigue analyses and design specifications were
revised per NRC Bulletin 88-11 to reflect the results of CEN-387-P, Revision 1.
This section of the FSAR has not been revised since the initial FSAR. CR-WF3-
2006-0839 was initiated to revise the FSAR. The reasoning for Entergys
position is documented in the paragraphs below.
The pressurizer surge line temperatures during heatup and cooldown are
maintained by ensuring the heatup and cooldown limits in the RCS and
pressurizer are maintained. The RCS limits are located in the TS and the
pressurizer limits are located in the TRM. Temperature changes in the surge line
can be greater than 200°F due to thermal stratification and thermal stripping.
CEN-387-P, Revision 1 documented that the pressurizer surge line meets Code
stress and fatigue requirements for the 40 year design life of the facility
considering the phenomenon of thermal stratification and thermal stripping.
Analysis in the CEN has indicated that temperature differences of up to 340°F
have been evaluated for.
The data recorded by the temperature element in the surge line has shown
periods of temperature changes greater than 200°F/hr. Thermal stratification is
applicable to all of these recorded temperature changes. These temperature
changes do not necessarily reflect the average temperature change of the surge
line but reflects a change in local fluid temperature at the temperature element.
This recorded temperature changes over time are not the same delta
temperatures listed in the tables in 9270-PE-140.
Therefore, the temperature difference in the pressurizer surge line is bounded by
the analysis performed in CEN-387-P, Revision 1 and monitoring pressurizer
Page 3 of 4
Waterford 3 Pressurizer Surge Line Temperature Change Rate
surge line temperature per procedure during heatup and cooldown is not
necessary.
Additional Information
The additional information specifically addresses the difference between the
surge line temperature increase seen during Refuel 13 and during the shutdown
for Hurricane Katrina, and the delta temperature values in 9720-PE-140. It also
addresses the reason Waterford 3 does not currently monitor surge line
temperature during heatups and cooldowns.
There following information is clarification regarding cycles listed in Design
Specification 9270-PE-140 and the temperatures recorded in PI with the
temperature element located in the surge line. The graphical data recording the
single surge line temperature element over time for our Refuel 13 outage and the
Hurricane Katrina outage indicates periods of temperature changes greater than
200 degrees within one hour. Thermal stratification is applicable to all of these
recorded temperature changes. Thermal stratification temperature changes were
addressed by CEN-327-P (NRC accepted response to NRC Bulletin 88-11). This
single temperature element does not necessarily reflect the average temperature
change of the surge line but reflects a change in local fluid temperature at the
temperature element. The recorded temperature changes of a single point over
time is not the same delta temperatures listed in the tables of the W3 Design
specification of RCS Piping and Fitting document (document #9270-PE-140).
The table 4.5.15.3.1 lists expected occurrences of temperature differences
between two different locations; the pressurizer and the RCS hot leg and
provides the number of expected occurrences. Table 4.5.15.3.2 lists expected
occurrences of temperature differences between the top and bottom of the surge
line piping. These tables clearly state this information at the end of their
respective sections. Thus comparing a graph of temperature changes with
respect to time to these tables is not appropriate.
The effects on the Pressurizer Surge Line due to thermal stratification and
thermal stripping were evaluated in CEN-327-P, Revision 1. This was reviewed
by the NRC and in the SER the Staff concluded that the surge line meets ASME
Code stress and fatigue requirements for the 40-year design life. Waterford 3
currently monitors heatups and cooldowns of the RCS and Pressurizer. The
effects of these heatups and cooldowns on the pressurizer surge line have been
evaluated in CEN-327-P.
Page 4 of 4
ATTACHMENT C
White Paper on Effect of Diesel Sump Pump
Inoperability on Ultimate Heat Sink Operability
1.0 Purpose
This paper provides an answer to the question, what is the original licensing
basis for flood protection of essential equipment in the Dry Cooling Tower Areas?
The paper also provides the chronology of regulatory requirements and licensing
bases that support the conclusion.
2.0 Conclusion Regarding Licensing Basis
The original licensing basis for essential equipment in the Dry Cooling Tower
areas is that essential equipment be protected from Standard Project Storm
(SPS).
The elements of the licensing basis are the following:
§ The SPS, with all installed sump pumps inoperative, was analyzed as an
event less severe than the probable maximum precipitation.
§ Provisions are required to be in place for emplacing the portable sump pump
within 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> of an SPS event to ensure that the ponding level from SPS
does not adversely affect essential equipment if installed pumps are
inoperative.
§ The electric pumps are seismically designed but not seismically qualified;
therefore they were assumed not to be available following an OBE.
§ The probability of the occurrence of an SPS and OBE is 3.6E-8 and
negligible.
In essence, the original licensing basis required that the portable sump pump be
emplaced and started within 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> of the start of an SPS (sump high level
alarm) to ensure that essential equipment in the DCT areas is not flooded.
On July 26, 1999, Condition Report CR-WF3-1999-0789 was initiated to identify
that the Dry Cooling Tower sump pump capacities were not sufficient to meet the
original licensing basis.
A new discharge path for the DCT sump pumps was installed via DCP-3251.
The DCP also replaced the 1 portable sump pump that had a capacity of 100
gpm with 2 portable sump pumps having a capacity of 300 gpm each. The
installed sump pumps capacities were reduced from 325 gpm to 270 gpm due to
the new piping configuration. The revised time frame for starting the portable
sump pump to ensure essential equipment is not flooded was re-established as 3
hours from the start of an SPS (sump high level alarm). Procedure OP-901-521
instructs Operations to operate the DCT Portable Sump Pumps in accordance
with OP-003-024, Sump Pump Operation within 3 hours3.472222e-5 days <br />8.333333e-4 hours <br />4.960317e-6 weeks <br />1.1415e-6 months <br /> of the sump level alarm.
3.0 Chronology
Regulatory Guide 1.70, Revision 2, September 1975
Waterford 3 is committed to Regulatory Guide 1.70, Revision 2, as noted in
section 1.8 of FSA
- R. Neither Regulatory Guide Section 2.4.2.3, Effects of Local
Intense Precipitation, or Section 2.4.3.1, Probable Maximum Precipitation
(PMP), have any requirement to consider OBE or SPS concurrently.
Regulatory Guide Section 2.4.2.3 states:
Describe the effects of local probable maximum precipitation (see Section
2.4.3.1) on adjacent drainage areas and site drainage systems, including
drainage from the roofs of structures. Summarize the design criteria for site
drainage facilities and provide analyses that demonstrate the capability of site
drainage facilities to prevent flooding of safety related facilities resulting from
local probable maximum precipitation.
The fundamental requirement in the Regulatory Guide is that the applicant
ensures that safety related equipment is not adversely impacted from maximum
precipitation.
Regulatory Guide 1.59, Revision 2, August 1977
Waterford 3 is committed to Regulatory Guide 1.59, Revision 2, as noted in
section 1.8 of FSA
- R. Regulatory Guide 1.59, Revision 2, does not have a
specific requirement to consider OBE and SPS concurrently.
Two important requirements are discussed in the Regulatory Guide.
First, seismically induced floods are associated with land features specific to
each site such as streams, estuaries, dam failures, and landslides. This
requirement does not apply to flooding in the DCT sump areas.
Second, the Regulatory Guide states that the most severe flood conditions may
not indicate potential threats to safety related systems that might result from
combination of flood conditions thought to be less severe. The Regulatory Guide
states that reasonable combinations of less severe flood conditions should be
considered to the extent needed. The Regulatory Guide states that such
combinations should be evaluated in cases where the probability of their
existing at the same time and having significant consequences is at lease
comparable to that associated with the most severe hydro-meteorological or
seismically induced flood. We judge that the requirement to consider the SPS
originates from this requirement. Also, since the probability of a SPS and OBE
concurrent was later established to be negligible, we judge that not considering
the SPS concurrent with the OBE is in conformance with the Regulatory Guide.
Standard Review Plan 2.4.3, Revision 2 July 1981
Standard Review Plan 2.4.3 does not have a specific requirement to consider
Standard Review Plan 2.4.3,Section I, states:
Included is a review of the details of site drainage, including the roofs of safety
related structures, resulting from potential PMP probable maximum
precipitation
Standard Review Plan 2.4.3,Section IV, states:
The local PMF resulting from the estimated local PMP was found not to cause
flooding of safety related facilities, since the site drainage system will be capable
of functioning adequately during such a storm.
The fundamental requirement in the Standard Review Plan is that the applicant
ensures that safety related equipment is not adversely impacted form maximum
precipitation.
NRC Safety Evaluation Report, July 1981
The NRC evaluates the effects of a 6-hr duration PMP on the open cooling tower
areas and adjacent roofs. The NRC concludes that, assuming one sump pump
in each area is inoperable and that the roof drainage system is clogged with
debris during the PMP, that the ponding could inundate the transformers and
MCCs in the cooling tower areas.
The Safety Evaluation Report makes no reference to SPS or OB
- E.
FSAR Amendment 25, January 1982
FSAR Section 2.4.2.3.4 was initially added to the FSAR; previously it did not
exist. This FSAR Section is titled, Effects of Standard Project Storm (SPS) on
Cooling Tower Areas.
Two important aspects of the licensing basis are established in this FSAR
Section.
First, a probability evaluation is documented establishing that the occurrence of
an SPS and OBE is 3.6 E-8 and negligible.
Second, FSAR Section states that the SPS was still analyzed, assuming
inoperability of all pumps, in order to determine the time available before levels
are reached that could affect essential equipment in the Cooling Tower Areas.
Safety Evaluation Report, Supplement 4, October 1982
The SER states the following:
An alternative combination which should be considered is an operating basis
earthquake (OBE), which fails the sump pumps, coincident with a rainfall event
less than the PMP. This combination is considered appropriate since the pumps
are not seismically qualified1, and thus cannot be shown to be operable following
a seismic event. The staff therefore, requested that the applicant provide an
analysis of the effects of a standard project storm (SPS)2 assuming all four
pumps in the cooling tower areas are inoperable.
The SER further states:
the staff considered a SPS of 96 hours0.00111 days <br />0.0267 hours <br />1.587302e-4 weeks <br />3.6528e-5 months <br /> duration. This event would produce a
total rainfall of about 23 inches and would result in a ponding depth of about 1.9
ft in the cooling tower areas assuming that all four pumps are inoperable. Since
this is higher than the maximum allowable ponding depth of 1.71 feet, the
applicant has proposed to provide a portable pump with a pumping capacity of
100 gpm and sufficient head to pump over the cooling tower wall. a provision
will be included for emplacing the portable pump within 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> of a seismic
event if the installed pumps fail.
FSAR Amendment 33, September 1983
FSAR Amendment 33 revises Section 2.4.2.3.4 to state the following:
The maximum height to which rainwater can rise in this area before essential
equipment is reached is 1.71 ft (see subsection 2.4.2.3.3d). As shown in Table
2.4-6c, this level would not be reached for over seven hours into the SP
- S.
Furthermore, a portable pump is provided, with a pumping capacity of 100 gpm
and sufficient head to pump over the cooling tower wall. Provisions are included
for emplacing the portable pump within six hours of a seismic event if the
installed pumps fail and heavy rains are expected.
Thus, the FSAR Amendment 33 is in agreement with NRC SER Supplement 4 in
that the fundamental requirement is to protect essential equipment in the cooling
tower areas in the event of a SPS. The specific requirement in FSAR
Amendment 33 is that provisions be made for emplacing the portable sump
pump within 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> of a SPS event and that essential equipment be protected,
by ensuring that the ponding level does not reach 1.71 ft. The seismic event is a
vehicle to postulate the installed pumps are not available; however, important to
the licensing basis is the condition that the electric sump pumps will not be
available and that essential equipment needs to be protected prior to the ponding
level reaching 1.71 ft.
NRC Letter dated December 18 1984, Issuance of Five Percent Power License,
The NRC issues five percent power license, and Section 2.B.2 of the license
approves operation as described in FSAR as supplemented and amended
through Amendment 36.
NRC Letter dated March 16, 1985, Issuance of 100% Power License
The NRC issues 100 percent power license, and Section 2.B.2 of the license
approves operation as described in FSAR as supplemented and amended
through Amendment 36.
Design Change, July 26, 1999
On July 26, 1999, Condition Report CR-WF3-1999-0789 was initiated to identify
that the Dry Cooling Tower sump pump capacities were not sufficient to meet the
original licensing basis.
A new discharge path for the DCT sump pumps was installed via DCP-3251.
The DCP also replaced the 1 portable sump pump that had a capacity of 100
gpm with 2 portable pumps having a capacity of 300 gpm each. The installed
sump pumps capacities were reduced from 325 gpm to 270 gpm due to the new
piping configuration. The revised time frame for ensuring essential equipment is
not flooded was re-established as 3 hours3.472222e-5 days <br />8.333333e-4 hours <br />4.960317e-6 weeks <br />1.1415e-6 months <br /> from the start of SPS (sump high level
alarm). Procedure OP-901-521 instructs Operations to operate the DCT Portable
Sump Pumps in accordance with OP-003-024, Sump Pump Operation within 3
hours of the sump level alarm.
5