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05000285/FIN-2014002-072014Q1Fort CalhounInadequate 10 CFR 50.59 Screening for Containment Spray Design ChangeA cited violation of 10 CFR 50, Appendix B, Criterion XVI, Corrective Action, was identified involving the failure to take timely corrective action for a condition adverse to quality. Specifically, the licensee failed to restore compliance following NRC identification of the licensees failure to correct a runout condition of the containment spray system (CS) documented in NCV 05000285/2008003-05, in August 2008. Licensee corrective actions to correct the issue included completion of an analysis of containment spray pump operation during the main steam line break (MSLB) event; revision of CS design documentation; analysis of motor performance by an electrical vendor; and completion of a temporary modification to throttle the CS pump discharge valves to provide additional system resistance preventing pump runout. Future corrective actions include a permanent design change to prevent CS pump runout. The licensee initiated CR 2014-02242 on February 19, 2014, to document this failure to restore compliance. This finding was more than minor because it adversely impacted the Barrier Integrity cornerstone objective to provide reasonable assurance that physical design barriers (containment) protect the public from radionuclide releases caused by accidents or events. The inspectors reviewed NRC IMC 0609, Attachment 4, Initial Characterization of Findings , Table 3 SDP Appendix Router. While this issue was identified during a refueling outage, the inspectors determined that the majority of the exposure time for this violation occurred with the reactor at power and should be evaluated using the Significance Determination Process in accordance with IMC 0609, The Significance Determination Process (SDP) for Findings at- Power, Appendix A, Exhibit 3, Barrier Integrity Screening Questions. The inspectors determined that the finding did not represent an actual open pathway in containment or containment isolation logic, nor did the finding represent an actual reduction in the function of containment hydrogen igniters. Based on the guidance in the Exhibit 3 checklist the inspectors determined that the finding was of very low safety significance. The inspectors determined that the finding had a cross-cutting aspect of avoiding complacency in the human performance area, because the licensees staff failed to recognize latent issues even while expecting successful outcomes.
05000285/FIN-2014002-012014Q1Fort CalhounFailure to Make Required 10 CFR 50.46 Report Within Required TimeA Severity Level IV non-cited violation of 10 CFR 50.46, Acceptance criteria for emergency core cooling systems (ECCS) for light-water nuclear power reactors, was identified involving the failure to submit a report within 30 days of discovery of a significant change in the application of the ECCS model that affected the peak cladding temperature. The licensee submitted the required 10 CFR 50.46 report late on September 20, 2013 (ML13266A108). This report was subsequently reviewed by the NRC staff date October 2, 2013, and determined to be acceptable. The NRC staff determined that while the configuration change to the HPSI system resulted in a higher peak cladding temperature, it is within the regulatory requirements of 10 CFR 50.46(b)(1). The licensee initiated CRs-2014-00674 and 2014-01356 to address issuance of the late report. This performance deficiency was determined to be subject to traditional enforcement because it impeded the regulatory process, in that the failure to submit a timely report of significant ECCS analytical changes prevented the NRC technical staff from independently evaluating the potential safety implications of reductions in safety injection flow into the reactor during an accident. This violation was determined to be a Severity Level IV violation because it is consistent with the examples in Paragraph 6.9.d of the NRC Enforcement Policy. Because this violation is subject to traditional enforcement, no cross-cutting aspects have been assigned.
05000285/FIN-2014002-022014Q1Fort CalhounFailure to Translate HPSI Pump Design Requirements to Design Documents (Section 4OA3.2)A non-cited violation of 10 CFR 50, Appendix B, Criterion III, Design Control, was identified involving the failure to translate the High Pressure Safety Injection (HPSI) pump design and runout characteristics to design documents such as the Updated Safety Analysis Report or design calculations. On June 21, 2013, the licensee completed Engineering Change 59874, which permanently installed flow-limiting orifices in the discharge line of each pump, effectively preventing HPSI runout conditions from occurring for all plant conditions. This finding was more than minor because it adversely impacted the design control attribute of the Mitigating Systems Cornerstone objective of ensuring the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. The inspectors reviewed NRC IMC 0609, Attachment 4, Initial Characterization of Findings, Table 3 SDP Appendix Router. While this issue was identified during a refueling outage, the inspectors determined that the majority of the exposure time for this violation occurred with the reactor at power. As such, the inspectors determined the finding should be evaluated using the SDP in accordance with IMC 0609, The Significance Determination Process (SDP) for Findings at-Power, Appendix A, Exhibit 2, Mitigating Systems Screening Questions. The finding required a detailed risk evaluation because the high pressure safety injection system was inoperable for some of the large break loss of coolant accident scenarios (at reactor pressures less than 100 psi). A Region IV senior reactor analyst performed a bounding detailed risk evaluation. The change to the core damage frequency was 8E-8/year and, therefore, determined to be of very low safety significance (Green). The dominant core damage sequences included loss of coolant accidents where the high and low pressure safety injection systems failed during recirculation. The non-degraded low pressure safety injection system contributed to minimize the risk. The inspectors determined there was no cross-cutting aspect associated with this finding because events related to identification of needed procedures and specifications occurred in the 1970s and are not indicative of current performance.
05000285/FIN-2014002-032014Q1Fort CalhounFailure to Maintain Design Control of HPSI Injection ValveTwo examples of a non-cited violation of 10 CFR 50, Appendix B, Criterion III, Design Control, were identified. The first example involved the failure to establish procedures or Technical Specifications to accomplish required HPSI injection flow balancing. The second example involved the failure to provide controls or testing to ensure that replacement parts for HPSI injection valves were suitable for the application and were capable of supporting the safety-related functions of the HPSI system. The licensee has since implemented Engineering Change 59874 which included throttling of the HPSI loop injection valves. This change was completed on August 20, 2013, restoring the original plant design and overcoming the configuration control errors introduced on three of the eight injection valves. Post-work testing for the completed modification included flow balance testing for the HPSI loop injection lines. The inspectors reviewed the results of this testing and determined that the UFSAR assumptions regarding balanced loop flows were adequately addressed by licensee corrective actions. This finding was more than minor because it adversely impacted the design control attribute of the Mitigating Systems Cornerstone objective of ensuring the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. The inspectors reviewed NRC IMC 0609, Attachment 4, Initial Characterization of Findings, Table 3 SDP Appendix Router. While this issue was identified during a refueling outage, the inspectors determined that the majority of the exposure time for this violation occurred with the reactor at power. As such, the inspectors determined the finding could be evaluated using the SDP in accordance with IMC 0609, The SDP for Findings at-Power, Appendix A, Exhibit 2, Mitigating Systems Screening Questions. The inspectors answered yes to the question of Does the finding represent a loss of system and/or function? The inspectors determined the finding required a detailed risk evaluation per IMC 0609 Paragraph 6.0, because the operability of the high pressure safety injection system (both trains) was in question. A Region IV senior reactor analyst performed a detailed risk evaluation and determined the flow imbalance did not result in a loss of safety function. Since the high pressure safety injection system was capable of meeting the functional success criteria, there was no quantifiable change to the core damage frequency and therefore was determined to be of very low safety significance (Green). The inspectors determined there was no cross-cutting aspect associated with this finding because events related to identification of needed procedures and specifications occurred in the 1970s and are not indicative of current performance. Additionally, the errant replacement of parts of three HPSI injection valves occurred between 1993 and 2006, and are also not indicative of current performance.
05000285/FIN-2014002-042014Q1Fort CalhounFailure to Request a License Amendment for Required Change to Technical SpecificationsA Severity Level IV non-cited violation of 10 CFR 50.59, Changes, Tests, and Experiments, and an associated Green finding was identified involving the failure to request a license amendment for a facility change that required a change to the Technical Specifications. This issue is also associated with a Green finding related to the licensees failure to follow Procedure NOD-QP-3, 10 CFR 50.59 and 10 CFR 72.48 Reviews, and Procedure FCSG-23, 10 CFR 50.59 Resource Manual, both of which require submittal of a license amendment request prior to making a facility change that requires a change to Technical Specifications. The licensee initiated CR 2014-01029 on January 23, 2014, to document this violation and track corrective actions. This performance deficiency was considered to be of more than minor safety significance because it was associated with the procedure quality attribute of the mitigating systems cornerstone and it adversely affected the cornerstone objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. Specifically, the failure to follow station procedures for the 10 CFR 50.59 process caused the Technical Specifications to become insufficient to ensure that the limiting conditions for operation will be met. Using Inspection Manual Chapter 0609 Appendix G, Checklist 4, the inspectors determined that the finding did not result in the loss of any accident mitigation capability and did not require a quantitative risk assessment. This finding was determined to be of very low risk significance. This performance deficiency was also determined to be subject to traditional enforcement because it impeded the regulatory process, in that the failure to submit a license amendment and add required surveillance testing was in violation of 10 CFR 50.59(c)(1)(i) and caused the NRC-approved Technical Specifications to be out of alignment with the safety analysis for the facility. This violation is associated with a finding that has been evaluated by the SDP and communicated with an SDP color reflective of the safety impact of the deficient licensee performance. The SDP, however, does not specifically consider the regulatory process impact. Thus, although related to a common regulatory concern, it is necessary to address the violation and finding using different processes to correctly reflect both the regulatory importance of the violation and the safety significance of the associated finding. This violation was determined to be a Severity Level IV violation, because it is consistent with the examples in Paragraph 6.1.d of the NRC Enforcement Policy. The finding had a cross-cutting aspect in the training aspect of the human performance cross-cutting area because the licensees staff failed to understand and misapplied NRC generic guidance related to discovery of inadequate Technical Specifications
05000285/FIN-2014002-082014Q1Fort CalhounFailure to Adequately Design Anchorage for Containment Spray and Raw Water System Pipe SupportsDuring a previous inspection, the NRC reviewed multiple calculations for pipe supports on the raw water and containment spray systems and found that the calculations had several errors related to the design requirements for anchorage. The NRC issued an apparent violation AV 05000285/2013012-08, Failure to adequately design anchorage for containment spray and raw water system pipe supports in NRC Inspection Report 05000285/2013-012 (ML 13144A772). The licensee performed an operability determination for the affected calculations and found that the anchorage for the raw water and containment spray piping supports were operable. The NRC reviewed the evaluations and concluded that reasonable assurance of operability existed for the affected components. The inspectors determined that the failure to ensure adequacy of the anchorage of the aforementioned Containment Spray Pipe Supports and Raw Water Pipe Supports was not in accordance with design basis requirements and was a performance deficiency. The performance deficiency was determined to be more than minor because it required calculations to be re-performed to prove the system was operable, and it was associated with the Mitigating Systems cornerstone attribute of design control and affected the cornerstone objective of ensuring the availability, reliability, and capability of the containment spray system and raw water system. Using Inspection Manual Chapter 0609, Attachment 4 Initial Characterization of Findings, and Appendix A The Significance Determination Process (SDP) for findings at-power, both dated 6/19/12, the inspectors determined the performance deficiency affected the mitigating systems cornerstone and screened to Green because the finding affected the design and qualification of a mitigating SSC but remained operable. The inspectors used the at-power SDP because the condition existed since construction and while the plant was predominantly at power. The inspectors determined there was no cross-cutting aspect associated with this finding because the calculations were from the 1980s and therefore were not reflective of current performance. Title 10 CFR Part 50, Appendix B, Criterion III, Design Control states, in part, that the design control measures shall provide for verifying or checking the adequacy of design, such as by the performance of design reviews, by the use of alternate or simplified calculational methods, or by the performance of a suitable testing program. Contrary to this requirement the inspectors identified that calculations FC00607, FC01785, FC01786, FC01791, FC01864, FC01691, FC01902, FC02409, FC02412, FC04228, FC02433, FC02436, and FC02425 for the raw water and containment spray systems failed to ensure adequacy of the design. Specifically, these anchorage calculations did not conform to applicable design requirements from approximately 1980 until June 2013. The licensee entered these issues into the corrective action program as CR 2013-05304 and performed an operability determination as immediate actions. Long term actions to resolve the errors in the calculations are also implemented by the referenced CR. This violation is being treated as an NCV, consistent with Section 2.3.2.a of the Enforcement Policy.
05000285/FIN-2014002-092014Q1Fort CalhounFailure to Adequately Implement Design Requirements for Containment Air Cooler Pipe SupportsA non-cited violation of 10 CFR Part 50, Appendix B, Criterion III, Design Control, was identified involving the failure to ensure the adequacy of the U-bolts for containment air cooler pipe supports VAS-1 and VAS-2. Specifically the U-bolt design was non-conservative with respect to the design basis requirements. The licensee entered these issues into the corrective action program as CR 2013-03722. The licensee revised the calculation to support operability. In addition, the licensee generated engineering change EC59570 to fix the degraded VAS-1 and VAS-2 supports. The performance deficiency was determined to be more than minor because it was associated with the Mitigating Systems cornerstone attribute of design control and affected the cornerstone objective of ensuring the availability, reliability, and capability of several safety injection tank valves. Specifically, the one-directional U-bolts for VAS-1 and VAS-2 are not designed to withstand two-directional loading and the condensate drain piping line has the potential to adversely impact the safety injection tank discharge isolation valves HCV-2934 and HCV-2974 during a design basis event. The licensee updated calculation FC05918 and provided an operability evaluation to address the degraded condition. The inspectors reviewed the information and did not find any issues. Using Inspection Manual Chapter 0609, Attachment 4 Initial Characterization of Findings, and Appendix A The Significance Determination Process (SDP) for findings at-power, both dated June 19, 2012, the inspectors determined performance deficiency affected the mitigating systems cornerstone and screened to Green because the finding affected the design and qualification of a mitigating SSC but remained operable. The inspectors used the at-power SDP because the condition existed since construction and while the plant was predominantly at power. The inspectors determined there was no cross-cutting aspect associated with this finding because the calculation was from the 1980s, and therefore was not reflective of current performance.
05000285/FIN-2014002-062014Q1Fort CalhounFailure to Restore Compliance for Containment Spray Runout ConditionsA cited violation of 10 CFR 50, Appendix B, Criterion XVI, Corrective Action, was identified involving the failure to take timely corrective action for a condition adverse to quality. Specifically, the licensee failed to restore compliance following NRC identification of the licensees failure to correct a runout condition of the containment spray system (CS) documented in NCV 05000285/2008003-05, in August 2008. Licensee corrective actions to correct the issue included completion of an analysis of containment spray pump operation during the main steam line break (MSLB) event; revision of CS design documentation; analysis of motor performance by an electrical vendor; and completion of a temporary modification to throttle the CS pump discharge valves to provide additional system resistance preventing pump runout. Future corrective actions include a permanent design change to prevent CS pump runout. The licensee initiated CR 2014-02242 on February 19, 2014, to document this failure to restore compliance. This finding was more than minor because it adversely impacted the Barrier Integrity cornerstone objective to provide reasonable assurance that physical design barriers (containment) protect the public from radionuclide releases caused by accidents or events. The inspectors reviewed NRC IMC 0609, Attachment 4, Initial Characterization of Findings , Table 3 SDP Appendix Router. While this issue was identified during a refueling outage, the inspectors determined that the majority of the exposure time for this violation occurred with the reactor at power and should be evaluated using the Significance Determination Process in accordance with IMC 0609, The Significance Determination Process (SDP) for Findings at- Power, Appendix A, Exhibit 3, Barrier Integrity Screening Questions. The inspectors determined that the finding did not represent an actual open pathway in containment or containment isolation logic, nor did the finding represent an actual reduction in the function of containment hydrogen igniters. Based on the guidance in the Exhibit 3 checklist the inspectors determined that the finding was of very low safety significance. The inspectors determined that the finding had a cross-cutting aspect of avoiding complacency in the human performance area, because the licensees staff failed to recognize latent issues even while expecting successful outcomes.
05000456/FIN-2013003-052013Q2BraidwoodInadequate Functionality Evaluations for a Degraded Unit 1 BAST BladderA finding of very low safety significance was self-revealed when licensee personnel performed inadequate functionality evaluations after previously identifying that the Unit 1 Boric Acid Storage Tank (BAST) bladder was degraded. The licensee entered this issue into their CAP as IR 1498696, Secured Boric Acid Tank Transfer Earlier Than Expected. Corrective actions included the replacement of the Unit 1 and Unit 2 BAST bladders. The inspectors determined that the failure to adequately evaluate Unit 1 BAST system functionality after identifying that the Unit 1 BAST bladder had substantially degraded was a performance deficiency. The inspectors determined the performance deficiency was more than minor because it was associated with the Equipment Performance attribute of the Mitigating Systems Cornerstone and adversely affected the cornerstone objective of ensuring the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences (i.e., core damage). The inspectors screened the finding using IMC 0609, Appendix A, The Significance Determination Process (SDP) for Findings At-Power. The inspectors answered No to all of the Mitigating System Screening questions for Reactivity Control Systems, therefore the finding screened as having very low safety significance. This finding had a cross-cutting aspect in the Operating Experience component of the PI&R cross-cutting area because the licensee failed to implement and institutionalize Operating Experience that specifically discussed the potential adverse consequences that a degraded tank bladder could have on plant safety.
05000456/FIN-2013003-042013Q2BraidwoodImplementation of Lake Chemistry Management ProgramThe inspectors identified an URI associated with the licensees implementation of station procedural standards to notify Senior Site Management and Operations at the first sign of a lake softening event, and to implement AOP BwOA-ENV-7, Adverse Cooling Lake Conditions, when pre-determined calcium precipitation rate limits were exceeded on three occasions from March 2012 through April 2013. The licensees root cause analysis performed following a 2004 Braidwood Lake Precipitation Event (IR 199206, Lake Chemistry Trend Calcium Carbonate Issue, Assignment 13) identified that the Lake Chemistry Plan had not been formalized into operational procedures and, as a result, guidelines for administrative controls, actions limits and levels, and contingency actions had not been established for managing lake chemistry. As one of the corrective actions to address this issue, the licensee developed and implemented AOP BwOA-ENV-7, Adverse Cooling Lake Conditions, to address any future adverse lake precipitation event (IR 199206, Assignment #35). On November 10, 2004, BwOA-ENV-7, Adverse Cooling Lake Conditions, was approved, placed within the station procedures, and was required to be followed in accordance with station standards. This AOP stated that prompt actions may be required to minimize any adverse effects on plant operation. Procedure BwOA-ENV-7 required that several actions be performed to minimize the impact of a significant lake precipitation event. For example, the procedure directed numerous actions to determine whether there had been an adverse impact on plant systems. These actions included the observation of traveling screen operation, monitoring of safety-related and nonsafety-related service water system strainer performance, trending of main condenser pressure, and the monitoring of component cooling system heat exchanger performance, fire protection jockey pump performance, and reactor containment fan cooler service water flow. Upon the identification of any adverse impact, the procedure directed notification of the Braidwood Station Duty Team to ensure appropriate actions would be taken commensurate with safety. Additionally, immediately following entry, BwOA-ENV-7 required that the Emergency Director evaluate Emergency Plan conditions. The procedure also required that the licensee minimize SX and auxiliary feedwater pump, main control room chiller, and EDG operation to preclude chemical or biological fouling. Following issuance, BwOA-ENV-7 had been revised numerous times to modify the thresholds and standards for informing Senior Site Management and Operations of lake precipitation events and to specify the standards upon which Operations would be notified to implement the procedure. For the period of January 2012 through May 2013, CY-BR-120-412, Lake Chemistry Data Sheet, Revision 7 was in effect and required the following: At the first sign of a precipitation event or natural softening, NOTIFY Senior Site Management and Operations (Reference Section 3.5). COMPARE Calcium Hardness and Total Alkalinity trends to determine behavior of these parameters during period of softening and non-softening. (Reference Section 4.6.5) - REVIEW CW Makeup and blowdown flow history, as well as recent weather precipitation. - If lake softening rate exceeds 15 ppm (parts per million) Calcium Hardness in a 2-3 day period, NOTIFY Operations to enter BwOA-ENV-7. The inspectors reviewed Braidwood Lake chemistry data from January 2012 through April 2013. The inspectors identified that the licensee appeared to have not followed the standards discussed above for three of the five potential lake softening events during this period. Specifically, the inspectors identified that Senior Site Management and Operations notification and entry into procedure BwOA-ENV-7, Adverse Cooling Lake Conditions, was delayed for up to several days after the licensee had performed lake water sampling, had analyzed the sample, and had documented the results. The following specific examples were identified: 2012 First Lake Softening Event (BwOA-ENV-7 Entered on March 5, 2012 3 Days After Entry Conditions were Present Date Calcium Delta Between Prior Day Sample 2/29/2012 257 3/2/2012 231 (26) - 2012 Third Lake Softening Event (BwOA-ENV-7 Entered on April 15, 2012 2 Days After Entry Conditions were Present) Date Calcium Delta Between Prior Day Sample 4/11/2012 194 4/13/2012 167 (27) - 2013 Second Lake Softening Event (BwOA-ENV-7 Entered on April 4, 2012 1 Day After Entry Conditions were Present) Date Calcium Delta Between Prior Day Sample 4/1/2013 209 4/3/2013 191 (18) The inspectors determined through interviews with licensee personnel and through the review of Operations logs that the licensee had not notified Senior Management and Operations at the first signs of the listed lake softening events or had implemented BwOA-ENV-7 earlier than was documented in the Operations logs. As a result of not implementing BwOA-ENV-7, Adverse Cooling Lake Conditions, when required, the licensee did not appear to perform the actions required by the AOP in a time frame commensurate with station standards. Therefore, the licensee failed to meet the standards that they had originally developed and modified over the years to minimize the possible adverse effects of lake precipitation events. The inspectors discussed this issue of concern with licensee staff, management, and senior management who disagreed with the inspectors assessment. The main points of the disagreement were on the meaning of the term at the first sign and on the acceptability of allowing a sample to be taken and analyzed on one day but not reviewed by a supervisor through the Lake Chemistry Control Program until chemistry staff were available, potentially several days later. The inspectors inferred from the term at the first sign that actions were required to be performed without an undue delay and that these actions were not dependent upon readily available chemistry staff. In the past two lake precipitation events, plant equipment was adversely impacted relatively soon after the onset of the event. The inspectors recognized that the elevated differential calcium concentration samples identified during this inspection did not actually result in a lake precipitation event. As of the end of the inspection period, the licensee planned to determine the impact of a 2-3 day delay in implementing BwOA-ENV-7 on the ability to mitigate a lake softening event. Pending a review of this information, this issue is considered a URI. (URI 05000456/2013003-04; 05000457/2013003-04, Implementation of Lake Chemistry Management Program)
05000456/FIN-2013003-032013Q2BraidwoodImplications of Control Room Ventilation Monthly SurveillanceThe inspectors identified an Unresolved Item (URI) regarding the use of TS Limiting Condition for Operation (LCO) 3.7.10 during the monthly control room ventilation system surveillance. Specifically, the inspectors questioned whether a step in procedure 0BwOSR 3.7.10.1-1, Control Room Ventilation Filtration Surveillance (Train A), to realign the VC suction source, and which appeared to defeat an automatic engineered safety feature (ESF) realignment, impacted the filtration system (Condition A) or control room envelope (CRE) boundary (Condition B) of the LCO. At 4:05 p.m. on May 8, 2013, the licensee commenced a routine monthly surveillance of the A VC filtration train using procedure 0BwOSR 3.7.10.1-1, Control Room Ventilation Filtration Surveillance (Train A). During performance of the surveillance, at 7:09 p.m., the licensee noted that B VC train damper 0VC08Y was unexpectedly open when it should have been closed. Approximately 25 minutes later, the damper repositioned closed. Operators were dispatched to inspect the damper and heard an abnormal grinding noise coming from the hydramotor. Consultation with the system engineer indicated that the grinding noise was likely caused by a degraded bearing. As a result, the licensee declared the B train of VC inoperable and entered LCO 3.7.10, Condition A, One VC Filtration System Train Inoperable for Reasons Other Than Condition B. Condition B stated, One or More VC Filtration System Trains Inoperable Due to Inoperable CRE Boundary in Mode 1, 2, 3, or 4. The licensee elected to continue with the routine surveillance on the A VC train. Step F5.1 of procedure 0BwOSR 3.7.10.1-1 directed Operations to enter LCO 3.7.10, Condition A, for the A VC train while the makeup filter selector switch was repositioned from auto to outside air then turbine building and back to auto as part of a contact check. The licensee entered LCO 3.7.10, Condition A, for the A VC train at 4:33 a.m. on May 9, 2013, and exited that Condition at 4:35 a.m. For those 2 minutes, both Units also entered LCO 3.0.3, since the A and B VC trains were simultaneously inoperable due to LCO 3.7.10, Condition A. During plant status activities on the morning of May 9, 2013, the inspectors noted discussions among senior plant personnel about whether LCO 3.7.10, Condition B (not Condition A) was actually the correct Condition to be entered while performing Step F5.1 of procedure 0BwOSR 3.7.10.1-1. The inspectors reviewed the TSs and discussed the system design with the VC system engineer. The VC system is designed such that when the makeup air suction is from outside air, the system would automatically realign the source air to the turbine building upon an air intake high radiation signal or a safety injection signal. When the makeup filter selector switch is not in the auto position, this automatic realignment will not occur, and manual actions would be required for the system to perform its ESF function. Additionally, the inspectors reviewed the licensees Control Room Habitability Program (CRHP), which included the following definitions: CONTROL ROOM ENVELOPE (CRE) BOUNDARY: A combination of walls, floor, roof, ducting, doors, penetrations, and equipment that physically form the CRE. CONTROL ROOM HABITABILITY SYSTEMS (CRHS): The plant systems that help ensure CRE habitability. This includes the Control Room emergency ventilation/filtration system and the Control Room HVAC systems. The CRE boundary is considered as an integral part of the CRHS, since it is critical to maintaining CRE habitability. The inspectors view was that the automatic realignment feature of the A VC train, which was blocked at the time the switch was not in auto, did not constitute part of the CRE boundary as defined in the CRHP. In addition, manual actions were required for the safety-related system to perform its ESF design function. As a result, the inspectors communicated to licensee management their view that Condition A was the correct Technical Specification Action Statement (TSAS) to be entered when performing the surveillance. Following this discussion, the licensee continued to believe that Condition B was the correct TSAS to enter when performing this surveillance. The inspectors also communicated their concerns that main control room logs, as officially recorded, did not completely and accurately capture the events that occurred on the night shift from May 8 to May 9, 2013. During plant status activities on May 9, the inspectors reviewed the main control room operating logs at approximately 6:30 a.m., and noted the log entries for entering LCO 3.7.10, Condition A, for the 0A VC train, and LCO 3.0.3, at 4:33 a.m. and exiting those LCOs at 4:35 a.m. However, later that morning when the logs were reviewed again, the inspectors noted those log entries had been revised. The log entries were annotated with, Late Entry 1030 5/9/13, and referenced entry into LCO 3.7.10, Condition B, and made no mention of LCO 3.0.3. There was no indication that anything had been revised or that LCO 3.0.3 had been entered. As a result of the inspectors concerns, the licensee generated IR 1519660, Lack of Detail in Log Entries, on May 30, 2013. Additionally, an Operations Noteworthy Event briefing sheet was created on June 12, 2013, and discussed with all Operating crews. The Noteworthy Event briefing sheet included the statement, Initially, LCO 3.0.3 was entered, but was retracted on days. LCO 3.7.10, Condition B, was determined to be the correct LCO entry. On July 8, 2013, the licensee again performed the monthly VC surveillance. Upon review of the main control room logs, the inspectors noted that LCO 3.7.10, Condition A, had been entered from 11:14 a.m. to 11:33 a.m. while alternating the suction source between outside and turbine building air. When questioned why the Noteworthy Event briefing sheet instructed Operating crews to enter Condition B and yet the crews entered Condition A, the licensee stated they were waiting for a more comprehensive review of the issue before revising the surveillance procedure. At the end of the inspection period, the inspectors were in the process of discussing the issue with NRC staff in the Office of NRR, reviewing the licensees determination of LCO applicability, and reviewing control room ventilation system design documentation. Pending additional information from the NRR staff, a complete understanding of the licensees position, and a more detailed understanding of the VC system design, this issue is considered a URI. (URI 05000456/2013003-03; 05000457/2013003-03, Implications of Control Room Ventilation Monthly Surveillance)
05000456/FIN-2013003-082013Q2BraidwoodFailure to Account for PZR PORV Accumulator Leakage During Hot Standby and Subsequent Cooldown Period Following a Postulated EarthquakeThe inspectors identified a finding of very low safety significance and an associated non-cited violation of 10 CFR Part 50, Appendix B, Criterion III, Design Control, when licensee personnel failed to account for PZR PORV accumulator air system leakage during the assumed 2 hour time spent in hot standby following a limiting seismic event. The licensee entered this issue into their CAP as IR 1481590, NRC Question Regarding Pressurizer PORV Accumulator Leakage. As part of their corrective actions, the licensee planned to revise procedures and seek clarification from the NRC concerning the licensing basis of the auxiliary spray system. The inspectors determined that the failure to ensure that the PZR PORVs could perform their credited safety function following a limiting seismic event was a performance deficiency. The inspectors determined that the performance deficiency was more than minor because it was associated with the Design Control attribute of the Mitigating Systems Cornerstone and adversely affected the cornerstone objective of ensuring the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences (i.e., core damage). The inspectors evaluated this finding using IMC 0609, Appendix A, The Significance Determination Process (SDP) for Findings At-Power, and determined that the finding was of very low safety significance because the issue was determined to not be a confirmed loss of operability or functionality. This finding had a cross-cutting aspect in the Corrective Action Program component of the PI&R cross-cutting area because the licensee failed to thoroughly evaluate a problem such that the resolution addressed causes and extent of condition, as necessary. Specifically, the licensee failed to adequately evaluate not accounting for PZR PORV air accumulator leakage in the natural circulation cooldown current licensing basis (CLB) due to the reliance on another system to provide the credited safety function.
05000456/FIN-2013003-072013Q2BraidwoodInadvertent Removal of the Design Basis Requirement to Commence a Cooldown Within 2 Hours Following the Establishment of Natural Circulation Conditions and Loss of Air to ContainmentThe inspectors identified a finding of very low safety significance and an associated non-cited violation of 10 CFR Part 50, Appendix B, Criterion III, Design Control, when licensee personnel failed to maintain the procedural requirement to commence a reactor coolant system (RCS) cooldown within 2 hours following a design basis seismic event that included a reactor trip, failure of all nonsafety-related equipment, and limiting single active failure. The licensee entered this issue into their CAP as IR 1496506, NRC Identified PZR (Pressurizer) PORV (Power-Operated Relief Valve) Natural Circulation Cooldown Analysis. Corrective actions included development of a revised instruction in the Emergency Operating Procedures (EOPs). The inspectors determined that the failure to adequately revise an EOP was a performance deficiency. Specifically, the licensee removed a procedural requirement to commence an RCS natural circulation cooldown if instrument air was lost to containment, which inadvertently could adversely affect a safety-related PZR PORV function. The inspectors determined that the performance deficiency was more than minor because it was associated with the Procedural Quality attribute of the Mitigating Systems Cornerstone and adversely affected the cornerstone objective of ensuring the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences (i.e, core damage.) The inspectors evaluated this finding using IMC 0609, Appendix A, The Significance Determination Process (SDP) for Findings At-Power, and determined that this finding was of very low safety significance because the issue was determined to not be a confirmed loss of operability or functionality. This finding had a cross-cutting aspect in the Corrective Action Program component of the PI&R cross-cutting area because licensee personnel failed to thoroughly evaluate a problem and ensure that the resolution adequately addressed the cause and extent of condition, as necessary. Specifically, the licensee failed to adequately evaluate a prior NRC finding such that the corrective actions adequately addressed the problem.
05000456/FIN-2013003-062013Q2BraidwoodInadequate Control of a Special Lifting DeviceThe inspectors identified a finding of very low safety significance and an associated NCV of 10 CFR Part 50, Appendix B, Criterion III, Design Control, when licensee personnel failed to adhere to design requirements specified for a special lifting device used to handle a transfer cask containing spent nuclear fuel in the vicinity of the spent fuel pool. The licensee entered this issue into their CAP as IR 1509204, Required NDE (Nondestructive Examination) Not Performed on Lift Yoke, and IR 1509602, Lift Yoke Stud Nuts Not Lock Wired. As part of their corrective actions, the licensee performed required tests and installed lock wire in accordance with design drawings prior to conducting additional lifts with the special lifting device. The inspectors determined that the failure to adhere to design drawings and American National Standards Institute (ANSI) requirements for annual testing of a special lifting device was a performance deficiency. The inspectors determined that the performance deficiency was more than minor because it was associated with the Design Control attribute of the Barrier Integrity Cornerstone and adversely impacted the cornerstone objective of providing reasonable assurance that physical design barriers protect the public from radioactive releases caused by accidents or events. The inspectors evaluated the finding using IMC 0609, Appendix A, Exhibit 3, Barrier Integrity Screening Questions. The inspectors answered No to all the screening questions in Appendix A, Exhibit 3, and therefore the finding screened as having very low safety significance. This finding had a cross-cutting aspect in the Resources component of the Human Performance cross-cutting area since the licensee failed to have complete, accurate, and up-to-date design documentation and procedures that ensured personnel, equipment, procedures, and other resources were available and adequate to assure nuclear safety. Specifically the licensees procedures for annual testing of a special lifting device lacked specific guidance, and design changes were made that conflicted with design drawings.
05000456/FIN-2013003-022013Q2BraidwoodFailure to Scope Nonsafety-Related Turbine Building to Auxiliary Building Sump Pump Discharge Check Valves into the Maintenance RuleThe inspectors identified a finding of very low safety significance and an associated non-cited violation of 10 CFR 50.65(b)(2)(ii) when licensee personnel failed to scope four Unit 1 and Unit 2 Essential Service Water (SX) pump room sump pump discharge check valves and eight Unit 1 and Unit 2 DOST room sump pump discharge check valves into the Maintenance Rule as required. The licensee entered this issue into their CAP as IR 1498897, Review 1/2WF040A/B Valves for Inclusion Into MRule (Maintenance Rule), and planned to scope the components into the Maintenance Rule. The inspectors determined that the failure to scope the Unit 1 and Unit 2 SX pump room sump pump discharge check valves and Unit 1 and Unit 2 DOST room sump pump discharge check valves into the Maintenance Rule was a performance deficiency. The inspectors determined that the performance deficiency was more than minor because, if left uncorrected, the performance deficiency would have the potential to lead to a more significant safety concern. Since a degraded SX or DOST sump check valve would degrade one or more trains of a system that supported a risk-significant system or function, a detailed risk evaluation was performed that determined the finding was of very low safety significance. This finding had a cross-cutting aspect in the Decision-Making component of the Human Performance cross-cutting area because the licensee failed to use conservative assumptions readily available in the applicable guidance document to demonstrate that not scoping the components into the Maintenance Rule was in accordance with Maintenance Rule requirements and therefore maintained safety.
05000454/FIN-2013003-022013Q2ByronFailure to Establish a Procedure to Control the Spent Fuel Pool Cooling SystemA finding of very low safety significance and an associated NCV of Technical Specification (TS) 5.4.1 was self-revealed when a configuration control error during a local leak rate test (LLRT) resulted in the inadvertent draining of the spent fuel pool (SFP). The licensee entered this issue into their CAP as IR 1506862, SFP Level Reduced. Licensee corrective actions included isolating the leak and restoring SFP level to normal. The inspectors determined that the performance deficiency was more than minor because it was associated with the Human Performance attribute of the Barrier Integrity Cornerstone and adversely impacted the cornerstone objective of providing reasonable assurance that physical design barriers (fuel cladding, reactor coolant system, and containment) protect the public from radionuclide releases caused by accident or events. The finding was screened in accordance with IMC 0609, Attachment 4, Phase 1 Initial Screening and Characterization of Findings, and was determined to be of very low safety significance since the finding was not associated with the loss of cooling to the SFP that would have precluded restoration prior to boiling, a fuel handling error, or loss of SFP inventory below the minimum analyzed level limit specified in the site-specific licensing basis. This finding had a cross-cutting aspect in the Work Practices component of the Human Performance cross-cutting area because operators did not use human error prevention techniques commensurate with the risk of the assigned task nor did personnel stop work in the face of uncertainty.
05000456/FIN-2013003-012013Q2BraidwoodFailure to Identify and Correct Degraded DOST Room Sump Pump Discharge Check ValvesThe inspectors identified a finding of very low safety significance when licensee personnel failed to identify degraded Diesel Oil Storage Tank (DOST) room sump discharge check valves in 2013 and after performing periodic testing in 2005. The licensee entered this issue into their Corrective Action Program (CAP) as Issue Report (IR) 1526652, IR Not Generated as Required 2005 OD Check Valve UT (Ultrasonic Testing) Results. Corrective actions included the repair of the degraded DOST room sump check valves. The inspectors determined that the failure to identify issues associated with degraded DOST room sump pump discharge check valves was a performance deficiency. The inspectors determined that the performance deficiency was more than minor because it was associated with the Protection Against External Factors attribute of the Mitigating Systems Cornerstone and adversely affected the cornerstone objective of ensuring the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences (i.e., core damage). Since the finding resulted in the potential for a loss of the emergency power function during a turbine building flooding event, and based upon an actual DOST room sump check valve failure, a detailed risk evaluation was performed, which determined that the finding was of very low safety significance. This finding had a cross-cutting aspect in the Corrective Action Program component of the Problem Identification and Resolution (PI&R) cross-cutting area because the licensee failed to take appropriate corrective actions in a timely manner to address degraded DOST room sump check valves.
05000454/FIN-2013003-012013Q2ByronInaccurate Risk AssessmentA finding of very low safety significance and an associated NCV of 10 CFR 50.65, Requirements for Monitoring the Effectiveness of Maintenance at Nuclear Power Plants, was identified by the inspectors when licensee personnel removed both the 2B and 2D Reactor Containment Fan Coolers (RCFCs) from service without entering an elevated on-line risk status (Yellow) as required by licensee procedure WC-BY-101- 1006, On-Line Risk Management and Assessment. The licensee entered this issue into their Corrective Action Program (CAP) as Issue Report (IR) 01519964, 2B and 2D RCFC OLR (On-Line Risk) Not Communicated. As part of the licensees corrective actions, on-line risk was revised to accurately reflect the removal of the 2B and 2D RCFCs from service. The inspectors determined that the performance deficiency was more than minor because it was similar to IMC 0612, Appendix E, Examples of Minor Issues, Example 7(e) that identified a failure to perform an adequate risk assessment when required by 10 CFR 50.65(a)(4) was not minor if the overall elevated plant risk placed the plant into a higher risk category established by the licensee. The inspectors determined the finding could be evaluated using the Significance Determination Process (SDP) in accordance with IMC 0609, Appendix K, Maintenance Risk Assessment and Risk Management Significance Determination Process. In accordance with IMC 0609, Appendix K, and because the calculated Incremental Core Damage Probability Deficit (ICDPD) was not greater than 1E-6, the finding was determined to be of very low safety significance. This finding had a cross-cutting aspect in the Work Control component of the Human Performance cross-cutting area because coordination efforts between the departments responsible for evaluating and communicating on-line risk failed to identify and communicate a risk increase associated with maintenance on the 2B and 2D RCFCs.
05000456/FIN-2013002-052013Q1BraidwoodNonSafety-Related Turbine Building Waste Disposal System to Safety-Related Essential Service Water Pump Room Sump Design InteractionOn January 21, 2013, the licensee documented in IR 1465027, 1WF040A Not Seating Properly, that SX sump pump discharge check valves 1WF040A and/or 1WF040B might be leaking by based on data that indicated that when the TB sump pump(s) operated, the Unit 1 and Unit 2 A train SX pump room sump pump(s) would start shortly after. This condition suggested that the TB sump pump(s) were filling the Unit 1 and Unit 2 A train SX sump to a level that caused the SX sump pump(s) to start. The licensees prompt operability evaluation was documented in IR 1473152, Single Point Vulnerability for SX Pump Room Flooding, and concluded that the SX pumps were operable since the SX pump room sump pumps can pump water out of the SX pump room sumps and, therefore, prevent water from accumulating in the SX pump room. However, the inspectors noted that previous IRs indicated degraded performance of both A train SX pump room sump pumps (IR 1426946, 1WF06PB Does Not Develop Adequate Discharge Pressure, and IR 1464644, 1WF06PA and B Degraded Insufficient Urgency to Correct. ) On February 13, 2013, the licensee updated their operability review to credit isolating the TB from the SX pump rooms by closing nonsafety-related isolation valves 1WF055 and 2WF055 until the final operability evaluation was complete. On February 14, 2013, the licensee documented that alarm response procedure BwAR OPL02J-2-A6, TB Floor Drain Sump Level High High, was being revised to provide operator direction to align the SX pump room sump to the Radioactive Waste system in the event of TB flooding. Additionally, credit was given to the nonsafety-related SX pump room sump high level alarm to alert operators to an off-normal level condition. The licensee credited the SX pump room sump pumps to be able to pump against the head pressure from the flood water in the TB, though reference was not given to their degraded condition. Issue Report 1473152 referenced UFSAR 10.4.5, Circulating Water System, and identified that the worst case flood in the TB could theoretically reach 396 feet. The lowest elevation of the SX sump pumps was 322 feet. The IR stated that the discharge of the SX room sump pumps was given as 100 gpm at 106 feet which would prevent inflow from the TB. The IR also stated that the NRC Standard Review Plan (SRP) requirement to prevent flooding of a safety-related area was maintained. On March 18, 2013, WO 1497423 was performed and identified that the disc for 1WF040B (SX sump discharge check valve) was stuck in the mid-position. NRC SRP 3.6.1, Plant Design for Protection Against Postulated Piping Failures in Fluid Systems Outside Containment, BTP SPLB 3-1 B.3.b, stated, In analyzing the effects of postulated piping failures, the following assumptions should be made with regard to the operability of systems and components: (1) Offsite power should be assumed to be unavailable if a trip of the turbine-generator system or reactor protection system is a direct consequence of the postulated piping failure; (2) A single active component failure should be assumed in systems used to mitigate consequences of the postulated piping failure and to shut down the reactor, except as noted in Item B.3.b.(3) below. The single active component failure is assumed to occur in addition to the postulated piping failure and any direct consequences of the piping failure, such as unit trip and loss of off-site power (LOOP). Additionally, SRP 9.3.3, Equipment and Floor Drainage System, required that the equipment and floor drainage system be capable of preventing a backflow of water that might result from maximum flood levels to areas of the plant containing safety-related equipment. SRP 10.4.5, Circulating Water System, required compliance with General Design Criteria 4, Environmental and Dynamic Effects Design Bases, based on meeting the following: 1) Means should be provided to prevent or detect and control flooding of safety-related areas so that the intended safety function of a system or component will not be precluded due to leakage from the Circulating Water system; and 2) Malfunction or a failure of a component or piping of the Circulating Water system including an expansion joint should not have unacceptable adverse effects on the functional performance capabilities of safety-related systems or components. Based on the above, the inspectors questioned whether the failure of the 1WF040B check valve would result in water from a postulated TB flood to backflow into the common Unit 1 and Unit 2 A train SX pump room sumps resulting in the loss of the 1A and 2A SX Pumps. The inspectors were unable to determine during the inspection whether the licensees justification was acceptable and therefore this issue will be considered an URI pending further NRC review.
05000456/FIN-2013002-062013Q1BraidwoodCurrent Licensing Basis Requirements for RCS Pressure Control Function During a Postulated Seismic Event in Reference to NRC RSB BTP 5-1The inspectors identified an URI regarding the licensees interpretation of their CLB requirements pertaining to the RCS Pressure Control Safety Function during a postulated seismic event and assumed 2 hour period in hot standby. Specifically, the inspectors identified three issues of concern that questioned the licensees ability to maintain RCS pressure control without the reliance of the primary safety valves and in a manner that could accomplish an RCS cooldown within a timeframe required by RSB BTP 5-1. Description: The licensees CLB utilized the standards in NRC BTP RSB 5-1, Design Requirements of the Residual Heat Removal System, Revision 2, dated July 1981, to meet aspects of 10 CFR Part 50, Appendix A, General Design Criteria (GDC) 19 and GDC 34. In summary, the station was licensed to demonstrate the capability to reach a cold shutdown condition assuming a design basis earthquake resulting in a LOOP and the failure of all non-safety, non-seismically qualified equipment. Design functions necessary to maintain hot standby and cold shutdown conditions include inventory control, reactivity management, decay heat removal, and RCS pressure control. The three issues of concern discussed in this URI are related to the RCS pressure control function during the assumed 2 hour hot standby period. The licensees Analysis of Record (AOR) assumed the following: 1) the time spent in hot standby will be limited to 2 hours, 2) the safety-related PZR PORV and associated instrument air accumulators could maintain RCS pressure in hot standby without the reliance on the RCS code safety valves, and 3) every attempt would be made to open key CVCS valves needed for auxiliary spray in the case that the PZR PORVs were not available. Since instrument air was considered nonsafety-related, instrument air was assumed to be unavailable during this postulated seismic event. The licensees UFSAR stated, however, that every attempt would be made to either restore the instrument air compressors (in the case of a LOOP) or to utilize nitrogen bottles to open the necessary air valves to restore the nonsafety-related auxiliary spray system if the PZR PORVs were not available. Issue of Concern 1: Inadvertent Removal of the Design Basis Requirement to Commence a Cooldown within 2 Hours Following the Establishment of Natural Circulation Conditions and Loss of Instrument Air to Containment...... Issue of Concern 2: Failure to Account for Allowable PZR PORV Accumulator Air Leakage During 2 Hour Hot Standby Period. .....Issue of Concern 3: No Procedures for Crediting the Use Auxiliary Spray Utilizing Portable Nitrogen Bottles. ....Based d on the above, the inspectors questioned whether the licensee had appropriately addressed the issues both individually and collectively to the standards required by NRC regulations. At the conclusion of the inspection period, the inspectors were reviewing the licensees CLB. This URI will remain open pending additional review. (URI 05000456/2013002-06, 05000457/2013002-06, Current Licensing Basis Requirements for RCS Pressure Control Function During a Postulated Seismic Event in Reference to NRC RSB BTP 5-1)
05000456/FIN-2012004-012012Q3BraidwoodFailure to Adequately Evaluate Operations Crew Performance for a Reactor Trip and Failure to Adequately Evaluate Emergency Operating Procedure StandardsThe inspectors identified a finding of very low safety significance (Green) when licensee personnel failed to implement a Caution Note in Emergency Operating Procedure (EOP) 2BwEP ES-0.1, Reactor Trip Response, during a July 30, 2009, Unit 2 reactor trip; failed to identify that deficiency during a 4.0 Crew Critique to evaluate Operations response to that event; and failed to adequately evaluate a concern identified during this inspection period that was entered into the Corrective Action Program (CAP) related to the requirement to follow the EOP guidance. In particular, licensee personnel incorrectly concluded that a reactor trip involving reactor coolant system (RCS) natural circulation would not require the initiation of an RCS cooldown within 2 hours following the shutdown despite the licensees Analysis of Record (AOR) and Technical Specification (TS) bases documents that required a cooldown be initiated within 2 hours to ensure that an adequate volume of water was available in the Condensate Storage Tank (CST) to cool down the RCS without utilizing the Ultimate Heat Sink (UHS). Corrective actions included revising 1/2BwEP ES-0.1 to relocate the Caution Note in the procedure and alleviate any future confusion with the cooldown requirement. Additionally, the Caution Note was modified to be consistent with the Current Licensing Basis (CLB) analysis of the CST and Operations management discussed the issue with the Operations crew staff and supervision to ensure that the Caution Note would be performed as required by 1/2BwEP ES-0.1. The inspectors determined that the failure to follow the EOP Caution Note during the July 30, 2009 Unit 2 reactor trip; the failure to identify this deficiency during the 4.0 Crew Critique assessment associated with this reactor trip, and the failure to adequately evaluate an issue entered into the CAP regarding this requirement was a performance deficiency. The inspectors determined that the performance deficiency was more than minor because it was associated with the Human Performance and Design Control attributes of the Mitigating Systems Cornerstone and adversely affected the cornerstone objective of ensuring the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences (i.e. core damage). The inspectors evaluated this finding using the SDP in accordance with IMC 0609, Significance Determination Process, Attachment 0609.04, Initial Characterization of Findings, which directed the finding to be screened using IMC 0609, Appendix A, The Significance Determination Process (SDP) for Findings at Power. The inspectors determined that because the station operated and nominally maintained CST level significantly above the minimum CST TS level prior to the June 30, 2009 Unit 2 reactor trip, the CST maintained its operability and functionality, and therefore this finding was of very low safety significance (Green). This finding had a cross-cutting aspect in the CAP component of the Problem Identification and Resolution cross-cutting area because the licensee failed to adequately evaluate Operations response to the July 30, 2009, reactor trip and subsequently failed to adequately evaluate an issue identified within the CAP.
05000456/FIN-2012008-012012Q3BraidwoodFailure to Install Foam-Water Sprinklers In Accordance With Sprinkler StandardThe inspectors identified a finding of very low safety significance associated with cited violation of License Condition 2.E for the licensees failure to implement the approved Fire Protection Program by failing to install foam-water sprinklers in accordance with the standard for installing sprinklers. Specifically, the licensee failed to correct significant obstructions to foam-water sprinklers in the Unit 2 2B diesel oil storage tank room that were previously identified by the NRC in a Non-Cited Violation in May 2010. The licensee entered this issue into their corrective action program and planned to survey each of the four diesel oil storage tank rooms for obstructions to determine the scope of physical changes needed to bring each room into compliance with the standard for installing sprinklers. The licensee will address corrective actions as part of their response to the Notice of Violation. The inspectors identified a finding of very low safety significance associated with cited violation of License Condition 2.E for the licensees failure to implement the approved Fire Protection Program by failing to install foam-water sprinklers in accordance with the standard for installing sprinklers. Specifically, the licensee failed to correct significant obstructions to foam-water sprinklers in the Unit 2 2B diesel oil storage tank room that were previously identified by the NRC in a Non-Cited Violation in May 2010. The licensee entered this issue into their corrective action program and planned to survey each of the four diesel oil storage tank rooms for obstructions to determine the scope of physical changes needed to bring each room into compliance with the standard for installing sprinklers. The licensee will address corrective actions as part of their response to the Notice of Violation.
05000456/FIN-2012003-062012Q2BraidwoodMSIV Hydraulic System DesignOn May 28, 2012, the 1A MSIV active-side hydraulic accumulator pressure was found at 3450 psig, which was below the operability limit of 4800 psig. This prevented manual isolation of the 1A main steam line via the main control room switch, which required the active-side accumulator and is required by Technical Requirements Manual (TRM) 3.3.y Condition D. Each MSIV also has a standby accumulator that could redundantly close the valve if an ESFAS signal was received, but not from the individual isolation control switch. The 1A MSIV standby accumulator pressure was 5400 psig, thus the 1A MSIV could have been closed by an ESFAS signal. The Action Statement for TRM 3.3.y Condition D required restoration of the individual steam line isolation capability within 48 hours. If that was not done, Condition D required the MSIV to be declared inoperable and TS.3.7.2 Condition A.1 to be entered, which required the MSIV to be returned to an operable status within 8 hours, or enter Condition B.1, which required the Unit to be in Mode 2 within 6 hours. During troubleshooting of the 1A MSIV active-side accumulator pressure issue, the licensee became concerned that they would not find and repair the active-side hydraulic problem prior to the requirement to enter Mode 2. As a result, the licensee elected to remove TRM 3.3.y Condition D from the TRM through the 10 CFR 50.59 evaluation process. As a result, the licensee was not required to declare the 1A MSIV inoperable provided the standby accumulator pressure was within operability limits. The inspectors reviewed the control logic for the MSIV control switches in the main control room and the remote shutdown panel. The inspectors noted that the MSIV control switches on the remote shutdown panels used only the active-side accumulator to reposition the MSIV. When the licensee removed TRM 3.3.y Condition D, they effectively removed any requirement to maintain the ability to close MSIVs from the remote shutdown panel. The inspectors reviewed procedures 0BwOA PRI-5, Control Room Inaccessibility Unit 0; 1BwOA PRI-5, Control Room Inaccessibility Unit 1; and 2BwOA PRI-5, Control Room Inaccessibility Unit 2; and did not identify a requirement to close the MSIVs prior to main control room evacuation. As a result, any MSIV with an active-side accumulator inoperable, which was allowed indefinitely by current site procedures, would not be closed prior to evacuating the main control room and would not be able to be closed from the remote shutdown panel. The licensees position was that there was no reason, purpose, or requirement for the MSIV control switches on the remote shutdown panel and no condition that would require repositioning them from the remote shutdown panel following evacuation of the main control room. The inspectors noted that Step 13.c of procedures 1(2)BwOA PRI-5 directed operators to close all MSIVs if RCS temperature dropped below 557oF. This step would need to be performed from the remote shutdown panel since the main control room was evacuated at Step 9. In addition, the inspectors questioned whether allowing one inoperable accumulator on each MSIV for an unlimited period of time had an effect on the ability of the ESFAS system to perform its safety function. Although only one of the two hydraulic accumulators was necessary to reposition each MSIV, each ESFAS train was assigned to a specific accumulator for each MSIV. For example, the A ESFAS train was assigned to the active-side accumulator on two MSIVs and the standby-side accumulator on the other two MSIVs. The B ESFAS train controlled the MSIVs using the opposite accumulators. As a result, there were certain combinations of accumulators that could be out of service on multiple MSIVs such that an inoperable ESFAS train would fail to close multiple MSIVs. At the end of the inspection period, the inspectors were reviewing whether this allowance satisfied the requirements of TS 3.3.2 and TS 3.7.2. At the conclusion of the inspection period, the inspectors had not completed their review of licensing documents related to this issue. As a result, this URI will remain open pending a review of the stations CLB and requirements associated with the remote shutdown panel and MSIVs.
05000456/FIN-2012003-072012Q2BraidwoodRemoval of TRM 3.3.y Requirement Via 10 CFR 50.59 EvaluationOn May 28, 2012, the 1A MSIV active-side hydraulic accumulator pressure was found at 3450 psig, which was below the operability limit of 4800 psig. This prevented manual isolation of the 1A steam line via the main control room switch, which required the active-side accumulator and was required by TRM 3.3.y Condition D. Each MSIV also had a standby-side accumulator that could redundantly close the valve if an ESFAS signal was received, but not from the individual isolation control switch. The 1A MSIV standby accumulator pressure was 5400 psig, thus the 1A MSIV could have been closed by an ESFAS signal and therefore remained operable. The action statement for TRM 3.3.y Condition D required restoration of the individual steam line isolation capability within 48 hours. If that was not done, Condition D required the MSIV to be declared inoperable and TS 3.7.2 Condition A.1 to be entered, which required the MSIV to be operable within 8 hours or enter Condition B.1, which required the Unit to be in Mode 2 within 6 hours. During troubleshooting of the 1A MSIV active-side accumulator pressure issue, the licensee became concerned that they would not find and repair the active-side hydraulic problem prior to the requirement to enter Mode 2. As a result, the licensee elected to remove TRM 3.3.y Condition D from the TRM through the 10 CFR 50.59 evaluation process. As a result, the licensee would not be required to declare the 1A MSIV inoperable provided the standby-side accumulator pressure was within operability limits. The inspectors reviewed the 10 CFR 50.59 evaluation of this change and questioned the licensees response to Question 2, which asked, Does the proposed activity result in a more than minimal increase in the likelihood of occurrence of a malfunction of an SSC important to safety previously evaluated in the UFSAR? The licensee concluded that it did not. However, the inspectors noted that TRM 3.3.y Condition D was the only requirement for any particular MSIV accumulator, standby or active, to be operable. The inspectors were concerned that removing the requirement increased the likelihood that an active-side hydraulic accumulator would be inoperable, which increased the likelihood that the hydraulic system would fail to operate the 1A MSIV, which would constitute an increase in the likelihood of a malfunction of the 1A MSIV. Furthermore, the inspectors noted that the licensees response to Question 2 credited the redundancy of the hydraulic system (active and standby accumulators) in coming to the conclusion that the change does not increase the likelihood of a malfunction of an SSC, despite removing the only requirement which helped ensure that redundancy. At the end of the inspection period, the inspectors had not completed their review of the 10 CFR 50.59 evaluation. As a result, this URI will remain open pending a full review of the applicable documentation.
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