IR 05000528/2014004
| ML14317A308 | |
| Person / Time | |
|---|---|
| Site: | Palo Verde  |
| Issue date: | 11/12/2014 |
| From: | Hay M NRC/RGN-IV/DRP/RPB-D |
| To: | Edington R Arizona Public Service Co |
| Hay M | |
| References | |
| IR 2014004 | |
| Download: ML14317A308 (37) | |
Text
UNITED STATES ber 12, 2014
SUBJECT:
PALO VERDE NUCLEAR GENERATING STATION - NRC INTEGRATED INSPECTION REPORT 05000528/2014004, 05000529/2014004, AND 05000530/2014004
Dear Mr. Edington:
On September 30, 2014, the U.S. Nuclear Regulatory Commission (NRC) completed an inspection at the Palo Verde Nuclear Generating Station Units 1, 2, and 3. On October 3, 2014, the NRC inspectors discussed the results of this inspection with Mr. D. Mims and other members of your staff. Inspectors documented the results of this inspection in the enclosed inspection report.
NRC inspectors documented three findings of very low safety significance (Green) in this report.
These findings involved violations of NRC requirements. The NRC is treating these violations as non-cited violations (NCVs) consistent with Section 2.3.2.a of the NRC Enforcement Policy.
If you contest the violations or significance of the NCVs, 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, Region IV; the Director, Office of Enforcement, U.S. Nuclear Regulatory Commission, Washington, DC 20555-0001; and the NRC resident inspectors at the Palo Verde Nuclear Generating Station.
If you disagree with a cross-cutting aspect assignment in this report, you should provide a response within 30 days of the date of this inspection report, with the basis for your disagreement, to the Regional Administrator, Region IV; and the NRC resident inspectors at the Palo Verde Nuclear Generating Station. In accordance with Title 10 of the Code of Federal Regulations (10 CFR) 2.390, Public Inspections, Exemptions, Requests for Withholding, a copy of this letter, its enclosure, and your response (if any) will be available electronically for public inspection in the NRCs Public Document Room or from the Publicly Available Records (PARS) component of the NRC's Agencywide Documents Access and Management System (ADAMS). ADAMS is accessible from the NRC Website at http://www.nrc.gov/reading-rm/adams.html (the Public Electronic Reading Room).
Sincerely,
/RA/
Michael C. Hay, Chief Project Branch D Division of Reactor Projects Docket Nos.: 50-528, 50-529, 50-530 License Nos: NPF-41, NPF-51, NPF-74 Enclosure: Inspection Report 05000528/2014004, 05000529/2014004, and 05000530/2014004 w/ Attachment: Supplemental Information
ML14317A308 SUNSI Review ADAMS Publicly Available Non-Sensitive By: MCH Yes No Non-Publicly Available Sensitive OFFICE SRI:DRP SRI:DRP RI:DRP SPE:DRP C:DRS C:DRS C:DRS NAME TBrown/dll DReinert DYou BHagar GMiller TFarnholtz GWerner SIGNATURE /RA/ /RA/ /RA/ /RA/ /RA/ /RA/ /RA/
DATE 11/3/14 11/3/14 11/3/14 11/3/14 11/5/14 11/12/14 11/5/14 OFFICE C:DRS C:DRS C:DRS C:DRP NAME VGaddy MHaire HGepford MCHay SIGNATURE /RA/ /RA/ /RA/ /RA/
DATE 11/12/14 11/6/14 11/6/14 11/12/14
U.S. NUCLEAR REGULATORY COMMISSION
REGION IV
Docket: 05000528, 05000529, 05000530 License: NPF-41, NPF-51, NPF-74 Report: 05000528/20140004, 05000529/20140004, 05000530/20140004 Licensee: Arizona Public Service Company Facility: Palo Verde Nuclear Generating Station Location: 5801 South Wintersburg Road Tonopah, Arizona 85354 Dates: July 1 through September 30, 2014 Inspectors: T. Brown, Senior Resident Inspector D. Reinert, Acting Senior Resident Inspector D. You, Resident Inspector B. Parks, Project Engineer S. Makor, Reactor Inspector J. Watkins, Reactor Inspector Approved Michael C. Hay By: Chief, Project Branch D Division of Reactor Projects-1- Enclosure
SUMMARY
IR 05000528, 529, 530/2014004; 07/01/2014 - 09/30/2014; Palo Verde Nuclear Generating
Station; Operability Determinations/Functionality Assessments, and Component Design Basis Inspection The inspection activities described in this report were performed between July 1 and September 30, 2014, by the resident inspectors at Palo Verde Nuclear Generating Station and inspectors from the NRCs Region IV office . Three finding(s) of very low safety significance (Green) are documented in this report. All of these findings involved violations of NRC requirements. The significance of inspection findings is indicated by their color (Green, White, Yellow, or Red),
which is determined using Inspection Manual Chapter 0609, Significance Determination Process. Their cross-cutting aspects are determined using Inspection Manual Chapter 0310,
Components Within the Cross-Cutting Areas. Violations of NRC requirements are dispositioned in accordance with the NRC Enforcement Policy. The NRC's program for overseeing the safe operation of commercial nuclear power reactors is described in NUREG-1649, Reactor Oversight Process.
Cornerstone: Mitigating Systems
- Green.
The inspectors identified a Green non-cited violation of 10 CFR Part 50, Appendix B, Criterion III, Design Control, for the failure to correctly translate the mission time of the essential spray pond system into a procedure used to determine operability. In response to the inspectors concerns, the licensee re-evaluated essential spray pond operability determinations that had used the erroneous 26-day mission time and concluded that acceptable margin was available to ensure the system would remain operable for the 30-day mission time. The licensee entered this issue into the corrective action program as Palo Verde Action Request 4550539.
The failure to ensure that design basis information associated with the mission time of the essential spray pond system was correctly translated into a procedure used to determine operability was a performance deficiency. This performance deficiency was more than minor because if left uncorrected, it had the potential to lead to a more significant safety concern. Specifically, the failure to use the correct mission time when determining operability could establish nonconservative results that could lead to the essential spray pond system not being able to meet its design safety function. The inspectors performed an initial screening of the finding in accordance with NRC Manual Chapter IMC 0609,
Appendix A, The Significance Determination Process (SDP) for Findings At-Power. Using IMC 0609, Appendix A, Exhibit 2, Mitigating Systems Screening Questions, dated July 1, 2012, this finding is of very low safety significance (Green) because it: (1) was not a deficiency affecting the design or qualification of a mitigating system; (2) did not represent a loss of system and/or function; (3) did not represent an actual loss of function of a single train for greater than its technical specification allowed outage time; and (4) does not represent an actual loss of function of one or more non-technical specification trains of equipment designated as high safety-significant in accordance with the licensees maintenance rule program for greater than 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />. This finding has a cross-cutting aspect in the area of human performance because the licensee failed to create and maintain complete, accurate, and up-to-date documentation. Specifically, after initially recognizing the adverse condition, the licensee did not document a standing order or temporary procedure change to prevent operability evaluations from using the incorrect essential spray pond mission time [H.7]. (Section 1R15).
- Green.
The inspectors identified a Green non-cited violation of 10 CFR Part 50 Appendix B,
Criterion V, Instructions, Procedures, and Drawings, for the licensees failure to provide an adequate technical justification for continued operation of a degraded structure, system, or component. Specifically, after discovering that the turbine driven auxiliary feedwater pump exhaust line did not have any tornado missile protection, operators performed an immediate operability determination and declared the system operable. The inspectors determined that the licensee did not provide adequate technical justification for continued operation with this condition because: (1) the evaluation relied on a probabilistic risk assessment that assumed the turbine driven auxiliary feedwater pump fails due to impact from a tornado missile, and (2) the evaluation assumed that a future analysis would provide satisfactory results. In response to the inspectors concerns, plant personnel subsequently completed an analysis that provided a reasonable expectation that the turbine driven auxiliary feedwater pump would be able to perform its safety function if impacted by a tornado missile. The licensee entered this issue into the corrective action program as Palo Verde Action Request 4255816.
The inspectors concluded that the failure of plant personnel to adequately evaluate the operability of a safety-related structure, system, or component was a performance deficiency. The inspectors concluded the performance deficiency is more than minor because it affected the equipment performance attribute of the Mitigating Systems Cornerstone objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. The inspectors performed the initial significance determination for the performance deficiency using NRC Inspection Manual 0609, Appendix A, Exhibit 4, External Events Screening Questions, dated July 1, 2012. The finding required a detailed risk evaluation because the turbine driven auxiliary feedwater pump is one train of a system that supports a risk significant function. Therefore, a Region IV senior reactor analyst performed a bounding detailed risk evaluation. The change to the core damage frequency was determined to be 7E-10/year (Green). The dominant core damage sequences included a tornado induced loss of offsite power initiating event, failure of the turbine driven auxiliary feedwater pump, and random failures of the motor driven auxiliary feedwater pumps. The low frequency for the tornado-induced loss of offsite power initiating event helped to minimize the risk significance. The inspectors determined this finding has a cross-cutting aspect in the area of human performance because the licensee failed to utilize a conservative bias in its evaluation of the missing tornado missile protection, considering the risk significance of the turbine driven auxiliary feedwater pump and lack of any technical evaluation [H.14] (Section 1R15).
- Green.
The team identified a Green non-cited violation of 10 CFR Part 50, Appendix B,
Criterion III, "Design Control," for the licensees failure to assure the adequacy of degraded voltage relay (DVR) setpoints. Specifically, the team identified that the licensee failed to perform calculations to demonstrate the voltage setpoints for the installed degraded voltage relays would afford adequate voltage to safety-related loads during worst case accident loading.
The failure to assure the adequacy of DVR setpoints for voltage and the time delay by performing adequate voltage drop calculations was a performance deficiency. This finding is more than minor because it was associated with the design control attribute of the Mitigating Systems cornerstone and it adversely impacted to the cornerstone objective to ensure the availability, reliability, and capability of systems that respond to initiating events.
Specifically, the failure to properly ensure that safety-related electrical devices had adequate voltage could impact their safety function. The basis for this conclusion was that despite the non-conservative voltage inputs to voltage calculations and, therefore, loss of design margin for available voltage, there was still adequate voltage for the circuits to perform their safety function based on worst case voltage as demonstrated in the updated calculations. The licensee developed design basis calculations for its DVR voltage setpoints and committed to develop a plant design change and an associated license amendment to shorten the existing time delay in Technical Specication 3.3.7.3(a). There is no cross-cutting aspect associated with this finding because it is a historical condition and not indicative of current performance. (Section 1R21)
PLANT STATUS
Unit 1 operated at essentially full power during the inspection period.
Unit 2 began the inspection period at essentially full power. On August 22, 2014, operators reduced power to approximately 80 percent, for planned maintenance to repair a heater drain pump motor. The licensee completd repairs and operators returned Unit 2 to essentially full power on August 27, 2014. Unit 2 operated at essentially full power for the remainder of the inspection period.
Unit 3 operated at essentially full power during the inspection period.
REPORT DETAILS
REACTOR SAFETY
Cornerstones: Initiating Events, Mitigating Systems, and Barrier Integrity
1R01 Adverse Weather Protection
.1 Readiness for Seasonal Extreme Weather Conditions
a. Inspection Scope
On July 22, the inspectors completed an inspection of the stations readiness for seasonal extreme weather conditions. The inspectors reviewed the licensees adverse weather procedures for summer monsoon season and evaluated the licensees implementation of these procedures. The inspectors verified that prior to the onset of summer monsoon season, the licensee had corrected weather-related equipment deficiencies identified during the previous summer monsoon season.
The inspectors selected one risk-significant system that were required to be protected from high dust loading:
- Emergency diesel generator combustion air intake The inspectors reviewed the licensees procedures and design information to ensure the systems would remain functional when challenged by adverse weather. The inspectors verified that operator actions described in the licensees procedures were adequate to maintain readiness of these systems. The inspectors walked down portions of these systems to verify the physical condition of the adverse weather protection features.
These activities constituted one sample of readiness for seasonal adverse weather, as defined in Inspection Procedure 71111.01.
b. Findings
No findings were identified.
.2 Readiness for Impending Adverse Weather Conditions
a. Inspection Scope
On August 21, the inspectors completed an inspection of the stations readiness for impending adverse weather conditions. The inspectors reviewed the licensees procedures to respond to severe rainfall, and the licensees implementation of these procedures. The inspectors evaluated operator staffing and accessibility of controls and indications for those systems required to control the plant.
These activities constituted one sample of readiness for impending adverse weather conditions, as defined in Inspection Procedure 71111.01.
b. Findings
No findings were identified.
1R04 Equipment Alignment
.1 Partial Walkdown
a. Inspection Scope
The inspectors performed partial system walk-downs of the following risk-significant systems:
- July 23, Unit 3, auxiliary feedwater system, train A and train B
- August 14, Unit 3, emergency diesel generator, train A
- September 17, Unit 1, essential chilled water system, train A The inspectors reviewed the licensees procedures and system design information to determine the correct lineup for the systems. They visually verified that critical portions of the trains were correctly aligned for the existing plant configuration.
These activities constituted three partial system walk-down samples as defined in Inspection Procedure 71111.04.
b. Findings
No findings were identified.
1R05 Fire Protection
Quarterly Inspection
a. Inspection Scope
The inspectors evaluated the licensees fire protection program for operational status and material condition. The inspectors focused their inspection on four plant areas important to safety:
- July 23, Unit 2, Main steam support structure, 80 feet elevation
- July 23, Unit 3, Main steam support structure, 80 feet elevation
- August 28, Unit 1, Control building, 100 feet elevation
- September 17, Unit 1, Control building, 74 feet elevation For each area, the inspectors evaluated the fire plan against defined hazards and defense-in-depth features in the licensees fire protection program. The inspectors evaluated control of transient combustibles and ignition sources, fire detection and suppression systems, manual firefighting equipment and capability, passive fire protection features, and compensatory measures for degraded conditions.
These activities constituted four quarterly inspection samples, as defined in Inspection Procedure 71111.05.
b. Findings
No findings were identified.
.2 Annual Inspection
a. Inspection Scope
On September 30, the inspectors completed their annual evaluation of the licensees fire brigade performance. This evaluation included observation of an unannounced fire drill for quarterly proficiency demonstration on September 25, 2014.
During this drill, the inspectors evaluated the capability of the fire brigade members, the leadership ability of the brigade leader, the brigades use of turnout gear and fire-fighting equipment, and the effectiveness of the fire brigades team operation. The inspectors also reviewed whether the licensees fire brigade met NRC requirements for training, dedicated size and membership, and equipment.
These activities constituted one annual inspection sample, as defined in Inspection Procedure 71111.05.
b. Findings
No findings were identified.
1R06 Flood Protection Measures
a. Inspection Scope
On August 27 and September 25, the inspectors completed an inspection of underground bunkers susceptible to flooding. The inspectors selected two underground vaults that contained risk-significant or multiple-train cables whose failure could disable risk-significant equipment:
- Unit 3, essential spray pond A flow transmitter vault
- Unit 2, emergency diesel generator B fuel oil storage vault The inspectors observed the material condition of the cables and splices contained in the vaults and looked for evidence of cable degradation due to water intrusion. The inspectors verified that the cables and vaults met design requirements.
These activities constitute completion of one bunker/manhole sample, as defined in Inspection Procedure 71111.06.
b. Findings
No findings were identified.
1R11 Licensed Operator Requalification Program and Licensed Operator Performance
.1 Review of Licensed Operator Requalification
a. Inspection Scope
On July 24, the inspectors observed an evaluated simulator scenario performed by an operating crew. The inspectors assessed the performance of the operators and the evaluators critique of their performance.
These activities constitute completion of one quarterly licensed operator requalification program sample, as defined in Inspection Procedure 71111.11.
b. Findings
No findings were identified.
.2 Review of Licensed Operator Performance
a. Inspection Scope
On August 21, the inspectors observed the performance of on-shift licensed operators in the plants main control room. At the time of the observations, the plant was in a period of heightened risk due to down powering Unit 2 to approximately 80 percent for repairs to the B heater drain pump motor. During this activity the plant also experienced problems with rod control, specifically the group 5 controlling group assemblies were non-responsive. The inspectors observed the operators performance of the following activities:
- Pre-job reactivity control briefing
- Licensed operator response to an unresponsive control element assembly during the planned downpower In addition, the inspectors assessed the operators adherence to plant procedures, including procedure 40OP-9ZZ05 Power Operations and other operations department policies.
These activities constitute completion of one quarterly licensed operator performance sample, as defined in Inspection Procedure 71111.11.
b. Findings
No findings were identified.
1R12 Maintenance Effectiveness
a. Inspection Scope
The inspectors reviewed two instances of degraded performance or condition of safety-related structures, systems, and components (SSCs):
- July 23, Unit 1, high pressure safety injection train B injection isolation valve to reactor coolant loop 2B, SI-626, review of maintenance history and reliability
- August 8, Unit 3, pressurizer level control system, review of level control reliability The inspectors reviewed the extent of condition of possible common cause SSC failures and evaluated the adequacy of the licensees corrective actions. The inspectors reviewed the licensees work practices to evaluate whether these may have played a role in the degradation of the SSCs. The inspectors assessed the licensees characterization of the degradation in accordance with 10 CFR 50.65 (the Maintenance Rule), and verified that the licensee was appropriately tracking degraded performance and conditions in accordance with the Maintenance Rule.
These activities constituted completion of two maintenance effectiveness samples, as defined in Inspection Procedure 71111.12.
b. Findings
No findings were identified.
1R13 Maintenance Risk Assessments and Emergent Work Control
a. Inspection Scope
The inspectors reviewed two risk assessments performed by the licensee prior to changes in plant configuration and the risk management actions taken by the licensee in response to elevated risk:
- September 3, Unit 1 Fukushima Modification FLEX Electrical Connections
- September 23, Station Blackout Generator Software Changes The inspectors verified that these risk assessment were performed timely and in accordance with the requirements of 10 CFR 50.65 (the Maintenance Rule) and plant procedures. The inspectors reviewed the accuracy and completeness of the licensees risk assessments and verified that the licensee implemented appropriate risk management actions based on the result of the assessments.
The inspectors also observed portions of two emergent work activities that had the potential to affect the functional capability of mitigating systems.
- July 31, Unit 3, troubleshooting and repair of main steam isolation signal (MSIS)channel C failure
- August 4, Unit 1, troubleshooting and repairs to emergency diesel generator A fuel oil transfer pump A The inspectors verified that the licensee appropriately developed and followed a work plan for these activities. The inspectors verified that the licensee took precautions to minimize the impact of the work activities on unaffected structures, systems, and components (SSCs).
These activities constitute completion of four maintenance risk assessments and emergent work control inspection samples, as defined in Inspection Procedure 71111.13.
b. Findings
No findings were identified.
1R15 Operability Determinations and Functionality Assessments
a. Inspection Scope
The inspectors reviewed seven operability determinations that the licensee performed for degraded or nonconforming structures, systems, or components (SSCs):
- July 1, operability determination for Unit 2 abnormal spray pond water color
- July 9, functionality assessment of Units 1,2, and 3 atmospheric dump valve nitrogen header relief lock tabs
- July 16, operability determination of inadequate seismic qualification of Unit 1 Fukushima modifications to emergency diesel generator fuel oil day tank piping
- July 30, operability determination for inadvertent closure of Unit 1 containment isolation valve, 1JGRBUV0002
- August 20, operability determination and SR 3.0.3 entry for missed surveillance testing of Unit 2 and Unit 3 class 1E batteries
- August 27, operability determination of Unit 3 essential spray pond A and B declining flow trend
- September 2, operability determination of Units 1, 2, and 3 turbine driven auxiliary feedwater pump exhaust vent and recirculation line design without required tornado missile protection The inspectors reviewed the timeliness and technical adequacy of the licensees evaluations. Where the licensee determined the degraded SSC to be operable, the inspectors verified that the licensees compensatory measures were appropriate to provide reasonable assurance of operability. The inspectors verified that the licensee had considered the effect of other degraded conditions on the operability of the degraded SSC.
These activities constitute completion of seven operability and functionality review samples, as defined in Inspection Procedure 71111.15.
b. Findings
.1 Failure to Translate Design Basis Requirements for Establishing Operability of Spray
Pond System
Introduction.
The inspectors identified a Green non-cited violation of 10 CFR Part 50, Appendix B, Criterion III, Design Control, for the failure to ensure that regulatory requirements and the design basis are correctly translated into specifications, drawings, procedures, and instructions. Specifically, the licensee did not correctly translate the mission time of the essential spray pond system into a procedure used to determine operability.
Description.
On February 5, 2014, NRC inspectors identified that the licensee had erroneously translated the mission time of the essential spray pond system into Study 13-NS-C088, Mission Times for EW, SP, SI, AF, and DG systems. This reference document states the mission time of the essential spray pond system and other safety-related systems. The licensee had incorrectly specified that the mission time of the essential spray pond system was 26 days, rather then 30 days as required by their licensing basis. The inspectors identified multiple instances in which operability determinations had used the 26-day mission time specified in the mission time study to justify a components operability. The inspectors issued noncited violation 05000528; 529; 530/2013009-01 for the failure to ensure that design basis information associated with the mission time of the spray pond system was correctly translated into instructions, procedures, and drawings.
The licensee entered the issue into their corrective action program and initated actions to address the violation. On February 12, 2014, the Shift Technical Advisor section leader sent an email to all shift technical advisors and shift managers advising them to ensure that operability was evaluated for 30 days. This email was not associated with any formal corrective action item and the licensee did not issue a formal night order to document this interim instruction. On March 5, 2014, the licensee initiated corrective action item 4509317 to revise Study 13-NS-C088 to reflect the mission time for the essential spray pumps and motors as 30 days. The licensee established a due date for revising the study of July 5, 2014. Despite having established long-range plans to correct the erroneous mission time study, the licensee did not establish and document any formal compensatory measures to ensure licensee personnel would use the correct mission time until Study 13-NS-C088 was revised.
On June 25, 2014, while reviewing a condition related to Unit 2 essential spray pond chemistry, the inspectors identified the licensee used the inappropriate spray pond mission time of 26 days. The operability determination associated with Palo Verde Action Request 4548907 stated, There is no reduction in the spray pond/ultimate heat sink system heat removal capability and the system remains capable of meeting its 26-day mission time as specified in Study 13-NS-C088. The inspectors then identified another example associated with Palo Verde Action Request, 4539335, Declining Trend Identified in 3A and 3B Spray Pond Flow, dated May 27, 2014 that also inappropriately referenced a 26-day mission time for the essential spray pond system. In response to the inspectors concerns, the licensee re-evaluated these operability determinations that had used the erroneous 26-day mission time and concluded that acceptable margin was available to ensure the system would remain operable for the 30-day mission time.
Mission Time Study 13-NS-C088 was updated on June 25, 2014.
On July 23, 2014, the inspectors identified that another section of the licensees operability determination procedure still explicitly stated that the mission time of the essential spray pond was 26 days. Procedure 40DP-9OP26, Operations PVAR Processing and Operability Determination/Functional Assessment, Appendix K, Section 3.5 stated that, the immediate operability determination/functional assessment should consider the implication on SSC performance for the full mission time of the SSC should the accident occur prior to restoration within specification. For instance, would scaling occur on the essential cooling water heat exchanger tubes of the 26-day mission time for the current essential spray pond system. The inspectors challenged that the continued use of a nonconservative 26-day mission time could lead the licensee to nonconservative operability conclusions. Licensee personnel had previously identified the need to change this section of the procedure and had issued Procedure Change Request 4546715 on June 20, 2014. However, the licensee had not taken compensatory measures to ensure that the correct mission time would be used until the procedure was formally revised. The licensee revised Procedure 40DP-9OP26 on August 14, 2014 to reflect the correct 30-day mission time. The licensee entered this issue into the corrective action program as Palo Verde Action Request 4550539.
Analysis.
The inspectors determined that the failure to ensure that design basis information associated with the mission time of the essential spray pond system was correctly translated into a procedure used to determine operability was a performance deficiency. This performance deficiency was more than minor because if left uncorrected, it had the potential to lead to a more significant safety concern. Specifically, the failure to use the correct mission time when determining operability could establish nonconservative results that could lead to the essential spray pond system not being able to meet its design safety function. The inspectors performed an initial screening of the finding in accordance with NRC Manual Chapter IMC 0609, Appendix A, The Significance Determination Process (SDP) for Findings At-Power. Using IMC 0609, Appendix A, Exhibit 2, Mitigating Systems Screening Questions, dated July 1, 2012, this finding is of very low safety significance (Green) because it:
- (1) was not a deficiency affecting the design or qualification of a mitigating system;
- (2) did not represent a loss of system and/or safety function;
- (3) did not represent an actual loss of function of a single train for greater than its technical specification allowed outage time; and
- (4) does not represent an actual loss of function of one or more non-technical specification trains of equipment designated as high safety-significant in accordance with the licensees maintenance rule program for greater than 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />. The inspectors determined this finding has a cross-cutting aspect in the area of human performance because the licensee failed to create and maintain complete, accurate, and up-to-date documentation. Specifically, after initially recognizing the adverse condition, the licensee did not document a standing order or temporary procedure change to prevent operability evaluations from using the incorrect essential spray pond mission time [H.7].
Enforcement.
10 CFR Part 50, Appendix B, Criterion III, Design Control, requires, in part, that measures shall be established to assure that applicable regulatory requirements and the design basis, as defined in 10 CFR 50.2 and as specified in the license application, for those components to which this appendix applies, are correctly translated into specifications, drawings, procedures, and instructions. Contrary to the above, prior to June 25, 2014, the licensee failed to establish measures to assure that applicable regulatory requirements and the design basis are correctly translated into specifications, drawings, procedures, and instructions. Specifically, the licensee translated a 26-day mission time into Study 13-NS-C088, Mission Times for EW, SP, SI, AF, and DG systems, instead of a 30-day availability time as required by Regulatory Guide 1.27, Ultimate Heat Sink For Nuclear Power Plants, and approved in their safety evaluation report. Consequently, in spray pond system operability determinations performed per Procedure 40DP-9OP26, Operations PVAR Processing and Operability Determination/ Functional Assessment, the licensee used the incorrect mission time. In response to this issue, the licensee reviewed the operability determinations in question using 30 days for the mission time and confirmed that the spray pond system had remained operable and had maintained an adequate safety margin. Because this finding is of very low safety significance and has been entered into the licensees corrective action program as PVAR 4550539, this violation is being treated as a non-cited violation in accordance with Section 2.3.2 of the Enforcement Policy: NCV 05000528; 529; 530/2014004-01, Failure to Translate Design Basis Requirements for Establishing Operability of Spray Pond System.
.2 Failure to Provide Adequate Technical Justification for Operability
Introduction.
The inspectors identified a Green non-cited violation of 10 CFR Part 50 Appendix B, Criterion V, Instructions, Procedures, and Drawings, for the failure of operations and engineering personnel to follow station procedures to provide an adequate technical justification for continued operation of a degraded structure, system, or component. Specifically, after discovering that the turbine driven auxiliary feedwater pump exhaust line did not have adequate tornado missile protection, operators failed to provide reasonable assurance that the system would be able to perform its safety function if impacted by a tornado missile.
Description.
On August 25, 2014, the licensee discovered that the turbine driven auxiliary feedwater (TDAFW) exhaust line did not have adequate tornado missile protection and relied on a probabilistic risk methodology (Calculation 13-NC-AF-0201, Terry Turbine Exhaust Stack Tornado Missile Evaluation) that the NRC explicitly allowed only for use in evaluating the ultimate heat sink design. As a result, the licensee performed an immediate operability determination (IOD) for the non-conforming condition, as required by procedure 40DP-9OP26, Operations PVAR Processing and Operability Determination/Functional Assessment, Revision 38. Operators concluded that the TDAFW system remained operable because, in part:
- (1) other licensees had performed evaluations to show that missile impact would not result in a complete loss of the ability of their pump to operate, and therefore Palo Verde personnel believed this method of evaluation would lead to a similar conclusion, and
- (2) the current methodology (Calculation 13-NC-AF-0201), while not approved by the NRC, added to the reasonable expectation of full operability during a tornado design basis event.
The inspectors concluded the operability determination lacked a valid technical basis.
First, section 2.4 of procedure 40DP-9OP26 allows the use of alternate analytical methods for use in operability determinations. However, the inspectors identified that the licensee had not performed any alternate analysis. Instead, the licensee presumed operability based on the future results of an analysis that had not been performed.
Additionally, the inspectors identified that the use of a probabilistic risk assessment (PRA) was not allowed by the licensees procedure. Step 2.8.1 of procedure 40DP-9OP26 states the use of PRA or probabilities of the occurrence of accidents or external events is not consistent with the assumption that the event occurs, and is not acceptable for making operability evaluations. Also, the inspectors identified that Calculation 13-NC-AF-0201 assumes the TDAFW pump fails because of an impact from a tornado missile, which contradicted the licensees determination that the TDAFW pump would remain operable if impacted by a tornado missile. The inspectors also noted that the IOD had been reviewed by the licensee on August 29, 2014. The review identified a deficiency in the IOD that credited the fact that missile impact was highly unlikely. The licensees review explicitly stated the use of probabilistic risk analysis was specifically prohibited by procedure. However, the inspectors concluded that the licensee failed to recognize that the calculation relied upon in the IOD was a probabilistic risk analysis and was also not allowed by procedure.
In response to the inspectors operability concerns, the licensee revised the immediate operability determination on September 3, 2014 to provide a technical justification for continued operation. The evaluation relied on preliminary finite element analysis modeling and additional margin due to the vent line diameter being larger than required by the design. The inspectors reviewed the revised evaluation and did not identify any additional concerns. The licensee completed a prompt operability determination to validate the conclusions of the immediate operability determination.
The inspectors concluded that the licensee should have complied with step 1.4 of the procedure, which states in part, if reasonable expectation does not exist, the SSC must be declared inoperable. Because a reasonable expectation did not exist, the licensee should have declared the TDAFW pump inoperable and entered Technical Specification 3.7.5, Auxiliary Feedwater System, until a reasonable expectation of operability could be justified.
The inspectors determined that the most significant contributor to this issue was the failure of the licensee to utilize a conservative bias in its evaluation of the missing tornado missile protection, considering the risk significance of the turbine driven auxiliary feedwater pump and lack of any technical evaluation. The licensee entered this issue into their corrective action program as Palo Verde Action Request 4255816 to evaluate the issue and identify appropriate corrective actions.
Analysis.
The inspectors concluded that the failure of plant personnel to adequately evaluate the operability of the TDAFW pump was a performance deficiency. The inspectors concluded the performance deficiency is more than minor because it affected the equipment performance attribute of the Mitigating Systems Cornerstone objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. The inspectors performed the initial significance determination for the performance deficiency using NRC Inspection Manual 0609, Appendix A, Exhibit 4, External Events Screening Questions, dated July 1, 2012.
The finding required a detailed risk evaluation because the turbine driven auxiliary feedwater pump is a one train system that supports a risk significant function.
Therefore, a Region IV senior reactor analyst performed the bounding detailed risk evaluation described below.
About one out of every three tornadoes (29%) is classified as "strong." Strong tornadoes have an average path length of 9 miles and a path width of 200 yards (approximately 1 square mile of land is affected). Although very rare, about 2% are violent. Violent tornadoes can last for hours. Average path lengths and widths are 26 miles and 425 yards, respectively. (See http://www.weatherexplained.com/Vol-1/Tornadoes.html).
Since Palo Verde is located in the least severe region for tornados (Region III, see Regulatory Guide 1.76, Design-Basis Tornado and Tornado Missiles) the analyst determined that the risk from violent tornados was negligible. The analyst conservatively assumed that all possible tornados at Palo Verde were strong and impacted approximately 1 square mile.
The average number of tornados in the state of Arizona per year was 4 (See http://www.erh.noaa.gov/cae/svrwx/tornadobystate.htm).
The total area for the state of Arizona was 114,000 square miles (See http://www.enchantedlearning.com/usa/states/area.shtml).
The analyst assumed that each Palo Verde unit (including the associated switchyard)occupied one square mile of land. This was conservative, in that the site footprint that contained the vulnerable equipment was much smaller. The analyst conservatively assumed that a tornado on site would cause a loss of offsite power.
The frequency of a tornado hitting any one Palo Verde Nuclear Generating Station unit and causing a loss of offsite power was:
= (4 tornados/year
- 1 sq. mile area) /114,000 sq. miles = 3.5E-5/yr.
The analyst evaluated the condition where the turbine driven auxiliary feedwater pump exhaust stack was struck with a tornado generated missile such that the stack was pinched shut. With the stack pinched closed, the turbine driven pump would fail. The analyst conservatively assumed pump failure 100% of the time when a tornado appeared on site.
The analyst used the NRCs Palo Verde Nuclear Generating Station Standardized Plant Analysis Risk model, Revision 8.20, with a truncation limit of E-11 to evaluate this finding. The analyst assumed the maximum allowed exposure period of one year.
The analyst calculated the change to the incremental conditional core damage probability (ICCDP) considering a tornado initiated loss of offsite power coincident (probability = 1.0) with the conditional failure of the turbine driven auxiliary feedwater pump. The analyst set the failure-to-start basic event for the pump to a value of 1.0.
The analyst allowed the emergency diesel generator and offsite power recovery events to occur. The analyst solved only the loss of offsite power sequences. Assuming the immediate failure of the pump, the CCDP was 2.2E-5. When the baseline risk was removed, the ICCDP was 2.0E-5.
Considering the ICCDP and the tornado initiating event frequency, the Delta-CDF was:
Delta-CDF = 3.5E-5/year
- 2E-5 = 7E-10/year Therefore, the finding was of very low safety significance (Green). The dominant core damage sequences included a tornado induced loss of offsite power initiating event, failure of the turbine driven auxiliary feedwater pump, and random failures of the motor driven auxiliary feedwater pumps. The low frequency for the tornado induced loss of offsite power initiating event helped to minimize the risk significance.
Since the delta-CDF was less than E-7, no evaluation of the change to the large early release frequency was required.
The inspectors determined this finding has a cross-cutting aspect in the area of human performance because the licensee failed to utilize a conservative bias in its evaluation of the missing tornado missile protection, considering the risk significance of the turbine driven auxiliary feedwater pump and lack of any technical evaluation [H.14].
Enforcement.
Title 10 CFR Part 50, Appendix B, Criterion V, Instructions, Procedures, and Drawings, requires, in part, that activities affecting quality be prescribed by documented instructions, procedures, or drawings, of a type appropriate to the circumstances and be accomplished in accordance with these instructions, procedures, or drawings. Procedure 40DP-9OP26, Operations PVAR Processing and Operability Determination/Functional Assessment, Revision 38, provided guidelines and instructions for evaluating the operability of safety-related structures, systems, or components, when degraded and non-conforming conditions were identified. Appendix E, Step 1.7, requires that the licensees immediate operability determination provide the basis for a reasonable expectation of operability. Contrary to the above, between August 25, 2014 and September 3, 2014, plant personnel failed to accomplish an activity affecting quality in accordance with the prescribed instructions, procedures, and drawings. Specifically, plant personnel did not provide a reasonable expectation of operability following discovery that the turbine driven auxiliary feedwater pump exhaust vent did not have tornado missile protection. Because this finding is of very low safety significance and has been entered into the licensees corrective action program as PVAR 4255816, this violation is being treated as a non-cited violation in accordance with Section 2.3.2 of the Enforcement Policy: NCV 05000528;05000529;05000530/2014004-02, Failure to Provide Adequate Technical Justification for Operability.
1R18 Plant Modifications
Permanent Modifications
a. Inspection Scope
On September 3, 2014, the inspectors reviewed a permanent modification involving the installation of alternate electrical connections implemented as a post-Fukushima plant improvement.
The inspectors reviewed the design and implementation of the modification. The inspectors verified that work activities involved in implementing the modification did not adversely impact operator actions that may be required in response to an emergency or other unplanned event. The inspectors verified that post-modification testing was adequate to establish the operability of the SSCs as modified.
These activities constitute completion of one sample of permanent modifications, as defined in Inspection Procedure 71111.18.
b. Findings
No findings were identified.
1R19 Post-Maintenance Testing
a. Inspection Scope
The inspectors reviewed five post-maintenance testing activities that affected risk-significant structures, systems, or components (SSCs):
- July 18, 2014, Unit 1, high pressure safety injection valve, SI-626
- August 5, 2014, Unit 1, emergency diesel generator A
- August 19, 2014, station blackout generator No.1
- June 13, 2014, Unit 3, pressurizer level master controller
- September 18, 2014, Unit 1, essential chiller B head pressure control valve The inspectors reviewed licensing and design-basis documents for the SSCs and the maintenance and post-maintenance test procedures. The inspectors observed the performance of the post-maintenance tests to verify that the licensee performed the tests in accordance with approved procedures, satisfied the established acceptance criteria, and restored the operability of the affected SSCs.
These activities constitute completion of five post-maintenance testing inspection samples, as defined in Inspection Procedure 71111.19.
b. Findings
No findings were identified.
1R21 Component Design Basis Inspection
a. (Closed) Unresolved Item (URI) 05000528; 05000529;05000530/2009008-01, Failure to Perform Adequate Calculations for Degraded Voltage Relay Setpoints In November 2009, the NRC identified a URI with two aspects related to the degraded voltage protection scheme. The first aspect involved the time delay for the degraded voltage protection scheme. Specifically, the time delay of 35 seconds for transfer of safety buses to the on-site power supplies may be too long to prevent core damage in the case of a sustained degraded voltage condition concurrent with an accident. The second involved the lack of calculations to support the degraded voltage relay voltage setpoint. This issue was documented in Inspection Report 2009008 (ML093240524).
Since the licensee had taken the position that formal calculations to support the design basis for the degraded voltage relays need not be performed, this item was considered an unresolved item pending further review.
During a focused baseline inspection in 2014, the licensee presented the team with updated calculations performed using ETAP software at the dropout setpoint. The team reviewed the inputs and outputs to validate that the approach was acceptable, that ETAP software was used correctly, and reviewed the licensees plans to address the time delay. The calculation demonstrated that the safety-related devices would have adequate voltage to perform their function.
The team determined that at the time the URI was opened in 2009, the licensee did not have adequate calculations to support the degraded voltage relay (DVR) voltage setpoints. Following documentation of the URI, the licensee developed design basis calculations for its DVR setpoints. The team determined that these calculations were adequate. The licensees failure to perform adequate calculations prior to 2009 was a performance deficiency, which is addressed in the finding below.
For the time delay, the team determined that it was inconsistent with the licensees accident analysis. The licensee had submitted a license amendment request, dated December 16, 1998, that proposed technical specification (TS) changes involving administrative controls aimed at preventing the spurious separation of safety buses during an accident. The Updated Final Safety Analysis Report (UFSAR),
Section 6.3.3.3.2 accident analysis assumes 30 seconds from safety injection actuation signal to the time safety injection flow is delivered to the core, but the high time delay setpoint found in TS 3.3.7 is set at 35 seconds, which is before the load sequencing is initiated. The licensee has committed to changing its time delay setpoint by amending its DVR technical specification (ML14276A032).
Based on the licensees updated design basis calculation supporting the DVR voltage setpoints and the commitment to amend the technical specifications to address the degraded voltage relay time delay, URI 05000528; 05000529; and 05000530/2009008-01 is closed.
b. Findings
Introduction.
The team identified a Green non-cited violation (NCV) of 10 CFR Part 50, Appendix B, Criterion III, "Design Control," for the licensees failure to assure the adequacy of degraded voltage relay setpoints. Specifically, the team identified that the licensee failed to perform calculations to demonstrate the voltage setpoints for the installed degraded voltage relays would afford adequate voltage to safety-related loads during worst case accident loading.
Description.
During the 2009 component design basis inspection, the NRC identified a URI identifying potential deficiencies in the Palo Verde's degraded voltage protection scheme. One potential deficiency involved the lack of calculations to support the degraded voltage relay voltage setpoint.
In 2009 and 2014, the team performed a detailed review of the record relating to the original licensing of the degraded voltage relays in the early 1980s and to a License Amendment Request, dated December 16, 1998, related to the TS 3.8.1 change that implemented administrative controls to limit vulnerability to spurious grid separation.
The team noted that the calculations of record in 2009 did not establish the adequacy of the degraded voltage relay voltage setpoints as described in FSAR Table 7.3-11A, NSSS Engineered Safety Features Actuation System Setpoints and Margins to Actuation, and TS 3.3.7, Diesel Generator (DG) Loss of Voltage Start (LOVS),
Additionally, the team noted that load flow calculation 01-EC-MA-0221, AC Distribution, analyzed voltage available to safety-related loads based on the minimum voltage described in Technical Specification 3.8.1, Condition G.
In 2009, the licensees approach was that the operators would administratively control the voltage on the 4160 V bus by coordinating with transmission and distribution system operators to prevent the switchyard voltages from dropping below a certain threshold.
By doing this, the 4160 V bus could never drop low enough to activate the degraded voltage relays. Using this approach the licensee felt that since the bus could not degrade to the degraded voltage setpoint of 3697 V, there was no requirement to provide an analysis or perform calculations that showed that the required equipment could operate at the degraded voltage relay dropout setpoint. Instead the licensee assumed that the bus voltage would always be maintained at or above the degraded voltage relay reset setpoint of 3805 V.
The licensee failed to provide an analysis or perform calculations that demonstrated that the setpoints of the degraded voltage relays would provide adequate voltage support for all of the safety-related equipment during all operating conditions and design basis accidents. The licensee's degraded voltage relay setpoints were not based on the manufacturer-specified minimum operating voltages at the terminals of the equipment, nor were they based on any transient degradation of bus voltage, such as voltage drops during the starting of large motors.
In 2014, the licensee used ETAP to model and calculate the plant distribution system voltages on the 4160 V bus and the associated 480 V buses under transient and accident conditions. The results of these calculations showed that the system voltage levels and equipment terminal voltage levels were, in fact, well below the assumed values from the licensees historical approach. Since ETAP does not model or calculate voltages below the 480 V distribution system, the licensee developed spreadsheets for each piece of equipment using the ETAP-generated bus levels in order to determine whether the control circuits which typically operate at 120 V would have adequate voltage to support the devices connected to the control circuits, and whether the new increased currents would be supported by the existing control circuit fuses. In addition, the licensee used software developed specifically for motor operated valves to determine if the valve operators would have adequate voltage to provide the required torque to open and close the associated valves.
The licensee provided material specifications and procurement documents for all motors showing that the motors could accelerate the connected load at 75 percent of equipment voltage rating and be able to continuously run at 90 percent of equipment voltage rating. The licensee provided pump and fan curves showing the results of these tests and provided data that showed the motor operated valves would also successfully operate under these very low voltage conditions. Even though these special testing and procurement requirements were in place for the equipment, there were several instances where special analysis had to be performed to verify that the equipment would perform satisfactorily. In some instances, enough margin was lost to require equipment modification.
Prior to 2009, Palo Verde did not have calculations to show that the estimated DVR setpoints could protect the equipment. The calculation had been done at the prevention strategy value of 3805 V, not the more conservative dropout setpoint. The licensee had not performed the calculation at the conservative value and did not have a voltage drop calculation that went all the way to the load point from the power source.
Analysis.
The failure to assure the adequacy of degraded voltage relay setpoints for voltage and the time delay by performing adequate voltage drop calculations was a performance deficiency. This finding was more than minor because it was associated with the design control attribute of the mitigating systems cornerstone and it adversely impacted the cornerstone objective to ensure the availability, reliability, and capability of systems that respond to initiating events. The inspectors performed an initial screening of the finding in accordance with NRC Manual Chapter 0609, Appendix A, The Significance Determination Process (SDP) for Findings At-Power, and determined this finding to be of very low safety significance (Green) because the finding affected the design, but the sytem remained operable. The basis for this conclusion was that despite the non-conservative voltage inputs to voltage calculations and, therefore, loss of design margin for available voltage, there was still adequate voltage for the circuits to perform their safety function based on worst case voltage as demonstrated in the updated calculations. There is no cross-cutting aspect associated with this finding because it is not indicative of current performance.
Enforcement.
Title 10 CFR Part 50, Appendix B, Criterion III, Design Control, requires, in part, that measures shall be established to assure that the design basis for safety-related structures, systems, and components is correctly translated into specifications, drawings, procedures, and instructions. Contrary to this requirement, prior to July 6, 2009, the licensee failed to establish measures to assure that the design basis for safety-related structures, systems, and components was correctly translated into specifications, drawings, procedures, and instructions. Specifically, as of July 6, 2009, the licensee did not have calculations to demonstrate that the degraded voltage relay setpoints were based on the voltage requirements of the safety-related loads at all on-site system distribution levels. The licensee developed design basis calculations for its DVR voltage setpoints and committed to address the technical basis and interim actions in a commitment letter for their corrective actions. Because this violation was of very low safety significance, was not repetitive or willful, and was entered into the licensees corrective action program as PVAR 3354296, this violation is being treated as a non-cited violation, consistent with Section 2.3.2.a of the NRC Enforcement Policy:
NCV 05000528; 529; 530/2014004-03, Inadequate Calculations to Support the Degraded Voltage Relay Setpoint.
1R22 Surveillance Testing
a. Inspection Scope
The inspectors observed four risk-significant surveillance tests and reviewed test results to verify that these tests adequately demonstrated that the structures, systems, and components (SSCs) were capable of performing their safety functions:
In-service tests:
- July 21, Unit 3, auxillary feedwater pump B inservice test
- August 27, Unit 3, essential spray pond pump A comprehensive inservice test Other surveillance tests:
- August 18, Unit 2, containment building temperature surveillance test
- September 19, Unit 3, reactor coolant system chemistry sample and analysis The inspectors verified that these tests met technical specification requirements, that the licensee performed the tests in accordance with their procedures, and that the results of the test satisfied appropriate acceptance criteria. The inspectors verified that the licensee restored the operability of the affected SSCs following testing.
These activities constitute completion of four surveillance testing inspection samples, as defined in Inspection Procedure 71111.22.
b. Findings
No findings were identified.
OTHER ACTIVITIES
Cornerstones: Initiating Events, Mitigating Systems, Barrier Integrity, Emergency Preparedness, Public Radiation Safety, Occupational Radiation Safety, and Security
4OA1 Performance Indicator Verification
.1 Reactor Coolant System Specific Activity (BI01)
a. Inspection Scope
The inspectors reviewed the licensees reactor coolant system chemistry sample analyses for the period of third quarter 2013 through second quarter 2014 to verify the accuracy and completeness of the reported data. The inspectors observed a chemistry technician obtain and analyze a reactor coolant system sample on September 19, 2014.
The inspectors used definitions and guidance contained in Nuclear Energy Institute Document 99-02, Regulatory Assessment Performance Indicator Guideline, Revision 7, to determine the accuracy of the reported data.
These activities constituted verification of the reactor coolant system specific activity performance indicator for Units 1, 2, and 3, as defined in Inspection Procedure 71151.
b. Findings
No findings were identified.
.2 Reactor Coolant System Identified Leakage (BI02)
a. Inspection Scope
The inspectors reviewed the licensees records of reactor coolant system identified leakage for the period of third quarter 2013 through second quarter 2014 to verify the accuracy and completeness of the reported data. The inspectors used definitions and guidance contained in Nuclear Energy Institute Document 99-02, Regulatory Assessment Performance Indicator Guideline, Revision 7, to determine the accuracy of the reported data.
These activities constituted verification of the reactor coolant system leakage performance indicator for Units 1, 2, and 3, as defined in Inspection Procedure 71151.
b. Findings
No findings were identified.
4OA2 Problem Identification and Resolution
.1 Routine Review
a. Inspection Scope
Throughout the inspection period, the inspectors performed daily reviews of items entered into the licensees corrective action program and periodically attended the licensees condition report screening meetings. The inspectors verified that licensee personnel were identifying problems at an appropriate threshold and entering these problems into the corrective action program for resolution. The inspectors verified that the licensee developed and implemented corrective actions commensurate with the significance of the problems identified. The inspectors also reviewed the licensees problem identification and resolution activities during the performance of the other inspection activities documented in this report.
b. Findings
No findings were identified.
.2 Annual Follow-up of Selected Issues
a. Inspection Scope
The inspectors selected one issue for an in-depth follow-up:
- On August 19, the licensees response to observations made by the biennial NRC problem identification and resolution inspection team and documented in NRC Inspection Report 05000528;529;530/2014007.
The inspectors assessed the licensees problem identification threshold, cause analyses, extent of condition reviews and compensatory actions. The inspectors verified that the licensee appropriately prioritized the planned corrective actions and that these actions were adequate to address the concerns.
These activities constitute completion of one annual follow-up sample, as defined in Inspection Procedure 71152.
b. Findings
No findings were identified.
4OA3 Follow-up of Events and Notices of Enforcement Discretion
These activities constitute completion of two event follow-up samples, as defined in Inspection Procedure 71153.
.1 (Closed) Licensee Event Report 05000529/2012-002-01, Condition Prohibited by
Technical Specification Due to Low Pressure Safety Injection System Drain Pipe Leak
a. Inspection Scope
On October 8, 2012, Unit 2 was in Mode 5 during refueling outage 2R17, shutdown cooling train A was declared inoperable in accordance with TS 3.4.7 due to a leak on a low pressure safety injection train A drain pipe during operation. The leakage source was a weld defect on the low pressure safety injection pipe drain connection upstream of drain Valve SIA-V908. The leakage was first discovered on October 7, 2012, when water on the floor adjacent to the pipe was first found, but not identified as leakage through the drain pipe weld until insulation was removed on October 8, 2012.
A configuration control problem in the early 1990s allowed contact between the drain pipe and a pipe hanger when the shutdown cooling was in operation. This resulted in a weld defect being introduced due to the high cyclic stresses from the contact. The configuration control problem was corrected in May 1993; but, the weld defect propagated slowly during periods of shutdown cooling operations until the leak occurred in the 2R17 outage. The licensee determined the cause was inadequate guidance to ensure temporary fittings on safety-related fluid systems were removed prior to placing the system in service. To prevent recurrence, procedures were revised to require that systems with capped pipe ends be returned to their design configuration following maintenance.
The licensee issued this LER supplement to provide additional information from the completed cause evaluation, including the results of the structural evaluations and corrective actions. Inspectors previously reviewed the original LER and dispositioned this issue as a self-revealing, Green non-cited violation in Section 4OA3 of inspection report 05000528;529;530/2013002. The inspectors reviewed this LER supplement and did not identify any additional concerns. This LER is closed.
.2 (Closed) Licensee Event Report 05000528;05000529;05000530/2012-005-01, Condition
Prohibited by Technical Specifications Due to Remote Shutdown System Control Circuit Deficiencies
a. Inspection Scope
On December 14, 2012, during a review of remote shutdown system control circuits, the licensee identified a deficiency which could prevent proper isolation of the train B pressurizer backup heater controls during a control room fire. On January 29, 2013, further review identified similar deficiencies for two chemical and volume control system isolation valves. On August 7, 2013, during extent of condition reviews, the licensee identified five additional control circuits with similar deficiencies. The licensee determined the cause to be original latent design deficiencies. The licensee revised Procedure 40AO-9ZZ19, Control Room Fire, to provide alternate methods for isolating or controlling the affected circuits during a control room fire event. The licensee also plans design modifications to permanently address the issues.
The licensee issued this LER supplement to provide additional information from the completed cause evaluation, including the additional affected circuits identified during extent of condition reviews and corrective actions. Inspectors previously reviewed the original LER and dispositioned this issue as a licensee-identified violation in Section 4OA7 of inspection report 05000528;529;530/2013008. The inspectors reviewed this LER supplement and did not identify any additional concerns. This LER is closed.
These activities constitute completion of two event follow-up samples, as defined in Inspection Procedure 71153.
4OA6 Meetings, Including Exit
Exit Meeting Summary
On September 24, the inspector conducted a telephonic exit meeting to present the results of the focused baseline inspection of the unresolved item to Mr. D. Mims, Senior Vice President, Nuclear Regulatory Affairs and Oversight, and other members of the licensee staff. The licensee acknowledged the issues presented.
On October 3, the inspectors presented the inspection results to Mr. D. Mims, Senior Vice President, Nuclear Regulatory Affairs and Oversight, and other members of the licensee staff.
The licensee acknowledged the issues presented. The licensee confirmed that any proprietary information reviewed by the inspectors had been returned or destroyed.
SUPPLEMENTAL INFORMATION
KEY POINTS OF CONTACT
Licensee Personnel
- N. Aaronscooke, Engineer, Nuclear Regulatory Affairs
- R. Bement, Senior Vice President, Nuclear Operations
- R. Berryman, VP Nuclear Operations and Plant Manager, Nuclear Production
- J. Cadogan, Engineering Vice President, Engineering
- R. Doyle, Engineer, Electrical Design Engineering
- S. Dornsief, Compliance, Nuclear Regulatory Affairs
- D. Elkington, Senior Consultant, Regulatory Affairs
- T. Hook, Section Leader, Probability Risk Assessment
- A. Hartwig, Department Leader, Design Engineering
- D. Hautala, Senior Engineer, Regulatory Affairs
- K. House, Director, Engineering
- M. Hypse, Engineer, Worley Parson
- C. Karlson, Section Leader, Design Engineering
- E. Kozo, Engineer, Electrical Design
- M. Lacal, Vice President, Operations Support
- D. Marley, Senior Engineer, System Engineering
- M. McGhee, Department Leader, Compliance
- D. Mims, Senior Vice President, Nuclear Regulatory Affairs and Oversight
- F. Oreshack, Consultant, Regulatory Affairs
- J. Rodriguez, Licensing Engineer, Nuclear Regulatory Affairs
- T. Weber, Department Leader, Nuclear Regulatory Affairs
- D. Wheeler, Director, Performance Improvement Department
- D. Vogt, Manager, Operations
LIST OF ITEMS OPENED, CLOSED, AND DISCUSSED
Opened and Closed
- 05000528;
- 05000529; Failure to Translate Design Basis Requirements for Establishing NCV
- 05000530/2014004- Operability of Spray Pond System (Section 1R15)
- 05000528;
- 05000529; Failure to Provide Adequate Technical Justification for Operability NCV
- 05000530/2014004- (Section 1R15)
- 05000528;
- 05000529; Inadequate Calculations to Support the Degraded Voltage Relay NCV
- 05000530/2014004- Setpoint (Section 1R21)
Attachment
Closed
Condition Prohibited by Technical Specification 5000529/2012-002-01 LER Due to Low Pressure Safety Injection System Drain Pipe Leak (Section 4OA3)
Condition Prohibited by Technical Specifications
- 05000528;05000529;05000530/2012-
LER Due to Remote Shutdown System Control Circuit 005-01 Deficiencies (Section 4OA3)
- 05000528;
- 05000529;
- 05000530/ Failure to Perform Adequate Calculations for URI 2009008-01 Degraded Voltage Relay Setpoints