IR 05000368/2013012

IR 05000313; 05000368-13-012; on 07/15/2013 - 02/10/2014; Arkansas Nuclear One; Augmented Inspection Team Follow-up Report; Inspection Procedure 71153, Follow-up of Events and Notices of Enforcement Discretion

ML14083A409
Person / Time
Site:	Arkansas Nuclear
Issue date:	03/24/2014
From:	Dapas M NRC Region 4
To:	Jeremy G. Browning Entergy Operations
G. Werner
References
71153, EA-14-008 IR-13-012
Download: ML14083A409 (87)

Text

March 24, 2014

SUBJECT:

ARKANSAS NUCLEAR ONE - NRC AUGMENTED INSPECTION TEAM FOLLOW-UP INSPECTION REPORT 05000313/2013012 AND 05000368/2013012; PRELIMINARY RED AND YELLOW FINDINGS

Dear Mr. Browning:

On February 10, 2014, the U.S. Nuclear Regulatory Commission (NRC) completed the Augmented Inspection Follow-up Inspection at the Arkansas Nuclear One, Units 1 and 2. The enclosed inspection report presents the results of this inspection. A final exit briefing was conducted with you and other members of your staff on February 10, 2014.

The enclosed inspection report discusses two findings, one that has preliminarily been determined to be Red with high safety significance for Unit 1, and one that has preliminary been determined to be Yellow with substantial safety significance for Unit 2, that may require additional regulatory oversight. As described in Section 4OA3.9 of the enclosed report, the findings are associated with the March 31, 2013, Unit 1 stator drop that affected safety-related equipment on both units.

The cause for the stator drop was not following a quality-related procedure, in that, the overhead temporary hosting assembly was not properly designed; the associated calculation was not reviewed; and the assembly was not load tested as required. During the movement of the Unit 1 stator, the overhead temporary hoisting assembly collapsed, causing the 525-ton stator to fall on and extensively damage portions of the Unit 1 turbine deck and subsequently to fall over 30 feet into the train bay. The stator drop resulted in a Unit 1 loss of offsite power for 6 days and a Unit 2 reactor trip and loss of offsite power to one vital bus. The dropped stator ruptured a common fire main header in the train bay, which caused flooding in Unit 1 and water damage to the electrical switchgear for Unit 2. The alternate alternating current diesel generator (station blackout) electrical supply cables to both units were pulled out of the electrical switchgear and the diesel was therefore not available to either unit. In addition, there was one fatality and eight individuals were injured. The Occupational Safety and Health Administration (OSHA) conducted an independent inspection focusing on industrial safety aspects of the event and issued four separate Citations and Notification of Penalties on September 26, 2013, with proposed fines to the three involved contractors and Entergy Operations, Incorporated. Your staff conducted extensive reviews of this event in the root cause evaluation, documented in Condition Report CR-ANO-C-2013-00888. Corrective actions included: repairing the damaged Unit 1 turbine structure, fire main system, and both Unit 1 and Unit 2 electrical systems; modifying procedures related to handling of heavy loads; training your staff on the revised requirements for handling heavy loads; and providing additional oversight for the subsequent Unit 1 replacement stator lift. The NRC inspectors observed many of the repair activities, including the removal of the dropped stator and the subsequent Unit 1 replacement stator lift. We noted that in your root cause evaluation, your staff did not address Entergys oversight of the contractors involved with the stator lift. The NRC independently determined that Entergy did not ensure adequate supervisory and management oversight of the contractors and other supplemental personnel involved with the stator lift, and this contributed to the event.

These findings were assessed based on the best available information, using the applicable Significance Determination Process. The final resolution of these findings will be conveyed in separate correspondence. These findings also constitute an apparent violation of NRC requirements which is being considered for escalated enforcement action in accordance with the NRC Enforcement Policy, which appears on the NRCs Web site at:

http://www.nrc.gov/about-nrc/regulatory/enforcement/enforce-pol.html.

In accordance with NRC Inspection Manual Chapter 0609, Significance Determination Process, we intend to complete our evaluation and issue our final determination of safety significance within 90 days from the date of this letter. The NRCs significance determination process is designed to encourage an open dialogue between your staff and the NRC; however, the dialogue should not affect the timeliness of our final determination.

During the exit meeting, conducted on February 10, 2014, you requested a regulatory conference to discuss these findings. As such, a regulatory conference to discuss the apparent violation has been scheduled for Thursday, May 1, 2014, from 1 - 5 p.m. at the Nuclear Regulatory Commission Region IV office in Arlington, Texas. We encourage you to submit supporting documentation at least one week prior to the conference in an effort to make the conference more efficient and effective. This conference will be open to public observation in accordance with Section 2.4, Participation in the Enforcement Process, of the NRC Enforcement Policy. The NRC will issue a public meeting notice and press release to announce this conference. At the February 10th exit meeting, both you and your staff expressed concerns that the NRC was not providing any credit for B.5.b mitigation equipment in the NRCs preliminary risk analysis. As part of our risk analysis, we acknowledged that some credit may be appropriate. We encourage you to be prepared to discuss, at the regulatory conference, what range of credit should be applied and the supporting basis, to include such things as procedures, training, pre-staging of equipment, etc.

Please contact Gregory Werner at 817-200-1574, and in writing, within 10 days from the issue date of this letter to confirm your intentions to attend a regulatory conference as described above. If we have not heard from you within 10 days, we will continue with our final significance determination and enforcement decision.

Because the NRC has not made a final determination in this matter, no Notice of Violation is being issued for these inspection findings at this time. In addition, please be advised that the number and characterization of the apparent violation may change based on further NRC review.

In addition, the NRC inspectors documented three findings of very low safety significance (Green) in this report. Two of these findings involve violations of NRC requirements. The NRC is treating these violations as non-cited violations (NCVs) consistent with Section 2.3.2.a of the Enforcement Policy.

If you contest these non-cited violations, you should provide a response within 30 days of the date of this inspection report, with the basis for your denial, to the U.S. Nuclear Regulatory Commission, ATTN: Document Control Desk, Washington DC 20555-0001; with copies to the Regional Administrator, Region IV; the Director, Office of Enforcement, U.S. Nuclear Regulatory Commission, Washington, DC 20555-0001; and the NRC resident inspector at the Arkansas Nuclear One.

If you disagree with a cross-cutting aspect assignment or a finding not associated with a regulatory requirement 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 inspector at the Arkansas Nuclear One.

In accordance with 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 Web site at http://www.nrc.gov/reading-rm/adams.html (the Public Electronic Reading Room).

Sincerely,

/RA/

Marc L. Dapas Regional Administrator

Docket Nos: 50-313, 50-368 License Nos: DRP-51, NPF-6

Enclosure: Inspection Report 05000313/2013012 and 05000368/2013012 w/Attachment 1: Supplemental Information w/Attachment 2: Unit 1 Outage Detailed Risk Evaluation w/Attachment 3: Unit 2 At-Power Detailed Risk Evaluation

Electronic Distribution to Arkansas Nuclear One

SUMMARY

IR 05000313; 05000368/2013012; 07/15/2013 - 02/10/2014; Arkansas Nuclear One;

Augmented Inspection Team Follow-up Report; Inspection Procedure 71153, Follow-up of Events and Notices of Enforcement Discretion.

The inspection activities described in this report were performed by four inspectors from the NRCs Region IV office. One preliminary finding of high safety significance (Red), one preliminary finding of substantial safety significance (Yellow), and three findings of very low safety significance (Green) are documented in this report. Both of the preliminary findings constitute an apparent violation and two of the Green 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: Initiating Events

• Unit 1 Apparent Violation. The inspectors reviewed a self-revealing apparent violation of 10 CFR 50, Appendix B, Criterion V, Instructions, Procedures and Drawings, which states, in part, that activities affecting quality shall be prescribed by documented instructions, procedures, or drawings, of a type appropriate to the circumstances and shall be accomplished in accordance with these instructions, procedures or drawings. The licensee did not follow the requirements specified in Procedure EN-MA-119, Material Handling Program, in that, the licensee did not perform an adequate review of the subcontractors lifting rig design calculation and the licensee failed to conduct a load test of the lifting rig prior to use. The licensee initiated Condition Report CR-ANO-C-2013-00888 to capture this issue in the corrective action program.

The licensees corrective actions included repairing damage to the Unit 1 turbine deck, fire main system, and electrical system. In addition, changes were made to various procedures including Procedure EN-DC-114, Project Management, to provide guidance on review of calculations, quality requirements, and standards associated with third party reviews.

The inspectors determined that the finding was more than minor because it was associated with the procedural control attribute of the initiating event cornerstone, and adversely affected the cornerstones objective to limit the likelihood of events that upset plant stability and challenge critical safety functions during shutdown, as well as power operations. The stator drop affected offsite power to Unit 1, resulting in a loss of offsite power for approximately 6 days and a loss of the alternate AC diesel generator. The inspectors used Inspection Manual Chapter 0609, Attachment 0609.04, Initial Characterization of Findings, dated June 19, 2012, to evaluate the significance of the finding. Since the plant was shutdown, the inspectors were directed to Inspection Manual Chapter 0609,

Appendix GProperty "Inspection Manual Chapter" (as page type) with input value "NRC Inspection Manual 0609,</br></br>Appendix G" contains invalid characters or is incomplete and therefore can cause unexpected results during a query or annotation process., Attachment 1, Shutdown Operations Significance Determination

Process Phase 1 Operational Checklists for Both PWRs and BWRs, Checklist 4, dated May 25, 2004. Using Appendix G, Attachment 1, Checklist 4, the inspectors concluded that this finding represented a degradation of the licensees ability to add reactor coolant system inventory when needed since a loss of offsite power occurred and therefore, this finding required a Phase 3 analysis. A shutdown risk model was developed by modifying the at-power Arkansas Nuclear One Unit 1 Standardized Plant Analysis Risk Model, Revision 8.19. The NRC risk analyst assessed the significance of shutdown events by calculating an instantaneous conditional core damage probability. The results were dominated by two sequences. The largest risk contributor (approximately 97 percent) was based on a failure of the emergency diesel generators without recovery. The second largest risk contributor was the failure to recover decay heat removal.

The result of the analysis was an instantaneous conditional core damage probability of 3.8E-4; therefore, this finding was preliminarily determined to have high safety significance (Red).

This finding had a cross-cutting aspect in the area of human performance associated with field presence, because the licensee did not ensure adequate supervisory and management oversight of work activities, including contractors and supplemental personnel. Specifically, the licensee did not provide a sufficient level of oversight in that, the requirements in Procedure EN-MA-119, for design approval and load testing of the temporary hoisting assembly, were not followed [H.2] (Section 4OA3.9).

• Unit 2 Apparent Violation. The inspectors reviewed a self-revealing apparent violation of 10 CFR 50, Appendix B, Criterion V, Instructions, Procedures and Drawings, which states, in part, that activities affecting quality shall be prescribed by documented instructions, procedures, or drawings, of a type appropriate to the circumstances and shall be accomplished in accordance with these instructions, procedures or drawings. The licensee did not follow the requirements specified in Procedure EN-MA-119, Material Handling Program, in that, the licensee did not perform an adequate review of the subcontractors lifting rig design calculation and the licensee failed to conduct a load test of the lifting rig prior to use. The licensee initiated Condition Report CR-ANO-C-2013-00888 to capture this issue in the corrective action program.

The licensees corrective actions included repairing damage to the Unit 1 turbine deck, fire main system, and electrical system. In addition, changes were made to various procedures including Procedure EN-DC-114, Project Management, to provide guidance on review of calculations, quality requirements, and standards associated with third party reviews.

The inspectors determined that this finding was more than minor because it was associated with the procedural control attribute of the initiating event cornerstone, and adversely affected the cornerstones objective to limit the likelihood of events that upset plant stability and challenge critical safety functions during shutdown, as well as power operations. The stator drop caused a reactor trip on Unit 2 and damage to the fire main system which resulted in water intrusion into the electrical equipment causing a loss of startup transformer 3. This resulted in the loss of power to various loads, including reactor coolant pumps, instrument air compressors, and the safety-related Train B vital electrical bus. The inspectors used Inspection Manual Chapter 0609, Attachment 0609.04, Initial

Characterization of Findings, dated June 19, 2012, and Appendix A, The Significance Determination Process (SDP) for Findings At-Power, dated June 19, 2012, to evaluate the significance of the finding. Since this was an initiating event, the inspectors used Exhibit 1 of Appendix A and determined that Section C, Support System Initiators, was impacted because the finding involved the loss of an electrical bus and a loss of instrument air. The inspectors determined that Section E, External Event Initiators, of Exhibit 1 should also be applied because the finding impacted the frequency of internal flooding. Since Sections C and E were impacted, a detailed risk evaluation was required. The NRC risk analyst used the Arkansas Nuclear One, Unit 2 Standardized Plant Analysis Risk Model, Revision 8.21, and hand calculation methods to quantify the risk. The model was modified to include additional breakers and switching options, and to provide credit for recovery of emergency diesel generators during transient sequences. Additionally, the analyst performed additional runs of the risk model to account for consequential loss of offsite power risks that were not modeled directly under the special initiator. The largest risk contributor (approximately 96 percent) was a loss of all feedwater to the steam generators, with a failure of once-through cooling. The result of the analysis was a conditional core damage probability of 2.8E-5; therefore, this finding was preliminarily determined to have substantial safety significance (Yellow).

This finding had a cross-cutting aspect in the area of human performance associated with field presence, because the licensee did not ensure adequate supervisory and management oversight of work activities, including contractors and supplemental personnel. Specifically, the licensee did not provide a sufficient level of oversight in that, the requirements in Procedure EN-MA-119, for design approval and load testing of the temporary hoisting assembly, were not followed [H.2] (Section 4OA3.9).

Cornerstone: Mitigating Systems

Green.

The inspectors reviewed a self-revealing, non-cited violation of Unit 1 Technical Specification 5.4.1.a and Unit 2 Technical Specification 6.4.1.a, involving the licensees failure to develop and implement procedural controls for response to internal flooding. Specifically, the licensee did not incorporate any instructions for the operation of the permanently installed temporary fire pump into procedures, which resulted in flooding due to the ruptured fire main header and not securing the temporary fire pump for approximately 50 minutes. The licensees corrective actions included changing Checklist 1104.032, Fire Protection Systems, Revision 76, to include guidance for securing the temporary fire pump in the event of a leak or rupture in the fire main header and provided personnel training on this change. This issue was entered into the corrective action program as Condition Reports CR-ANO-C-2013-01072 and CR ANO-C-2013-01962.

The inspectors determined that the licensees failure to develop and implement adequate procedural controls for the permanently installed temporary fire pump was a performance deficiency. The performance deficiency was more than minor because it was associated with the procedural quality attribute of the mitigating systems cornerstone and affected the cornerstones objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences (i.e. core damage).

Specifically, if the necessary flood prevention/mitigation actions cannot be completed in the time required, much of the stations accident mitigation equipment could be adversely impacted.

Unit 1 Analysis:

Inspection Manual Chapter 0609, Attachment 0609.04, Initial Characterization of Findings, dated June 19, 2012, Table 3, Section A, directs the user to Appendix G. The inspectors used Inspection Manual Chapter 0609, Appendix G,

Attachment 1, Shutdown Operations Significance Determination Process Phase 1 Operational Checklists for Both PWRs and BWRs, dated May 25, 2004,

Checklist 4, to evaluate the significance of the finding. The inspectors determined that the finding was of very low safety significance (Green) because the finding did not: (1) increase the likelihood of a loss of reactor coolant system inventory, (2) degrade the licensees ability to terminate a leak path or add reactor coolant system inventory when needed, or (3) degrade the licensees ability to recover decay heat removal once it is lost.

Unit 2 Analysis:

Inspection Manual Chapter 0609, Attachment 0609.04, Initial Characterization of Findings, dated June 19, 2012, Table 3, Section E, Step 2, directs the user to Appendix F, Fire, Protection Significance Determination Process, dated September 20, 2013. The inspectors used Appendix F, to evaluate the significance of the finding. The finding involved a fixed fire protection system and the fire water supply (temporary fire pump). The finding was screened against the qualitative screening question in Appendix F, Task 1.3.1 and the inspectors determined it was of very low safety significance (Green), because the reactor was able to reach and maintain safe shutdown.

The finding had a cross-cutting aspect in area of the human performance associated with documentation, because the licensee failed to create and maintain complete, accurate, and up-to-date documentation for the use of the temporary fire pump [H.7] (Section 4OA3.1).

Green.

The inspectors reviewed a self-revealing finding for the licensees failure to provide appropriate work instructions for the replacement of the main feedwater regulating valve 2CV-0748 linear variable differential transformer 2ZT-0748. Specifically, the licensee failed to translate vendor recommendations for use of a thread sealant, and torqueing of the adjustment nuts on the linear variable differential transformer 2ZT-0748 into procedural steps to be accomplished and verified. The failure to follow these recommendations resulted in the nuts falling off because of vibration. The licensee initiated Condition Report CR-ANO-2-2013-00423 and Work Order WT-WTANO-2013-00039 to update the work instructions and perform maintenance to repair the valve position indication by adding thread sealant and torqueing the adjustment nuts to prevent them from loosening.

The inspectors determined that the failure to provide instructions to properly perform maintenance on linear variable differential transformer 2ZT-0748 was a performance deficiency. The performance deficiency was more than minor because it was associated with the procedure quality attribute of the mitigating systems cornerstone. It adversely affected the cornerstone objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences and is therefore a finding. The inspectors used Inspection Manual Chapter 0609, Attachment 0609.04, Initial Characterization of Findings, dated June 19, 2012, and Appendix A, The Significance Determination Process (SDP) for Findings At-Power, dated June 19, 2012, to evaluate the significance of the finding. The inspectors determined the finding was of very low safety significance (Green) because the finding did not: (1) result in an actual loss of operability or functionality, (2)represent a loss of system and/or function, (3) represent an actual loss of function of a single train for greater than its technical specification allowed outage time, (4) represent an actual loss of function of one or more non-technical specification trains of equipment designated as high safety-significant for greater than 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />, and (5) involve the loss or degradation of equipment or function specifically designed to mitigate a seismic, flooding, or severe weather event.

The finding had a cross-cutting aspect in the area of the problem identification and resolution associated with operating experience, because although the licensee had collected and evaluated the operating experience, it was not implemented as procedural steps in linear variable differential transformer replacement work instructions [P.5] (Section 4OA3.4).

Green.

The NRC identified a non-cited violation of 10 CFR 50.65(b)(2)(i) for the licensees failure to monitor non-safety-related structures, systems, or components that are relied upon to mitigate accidents or transients. Specifically, the Unit 1 decay heat removal pump room level switches, which were credited for mitigating the effects of internal flooding, were not being monitored as part of the maintenance rule. The licensees corrective actions included developing a preventative maintenance task to test the operation of the level switches. This issue was entered into the corrective action program as Condition Report CR-ANO-1-2013-03168.

The inspectors determined that the failure to effectively monitor the performance of both Unit 1 decay heat removal room level switches in accordance with 10 CFR 50.65(a)(1) was a performance deficiency. The performance deficiency was determined to be more than minor because it affected the equipment performance attribute of the mitigating systems cornerstone and directly affected the cornerstone objective of ensuring the availability and reliability of systems that respond to initiating events to prevent undesirable consequences, in that it called into question the reliability of flood mitigation equipment. The inspectors used Inspection Manual Chapter 0609, Attachment 0609.04, Initial Characterization of Findings, dated June 19, 2012, and Appendix A, The Significance Determination Process (SDP) for Findings At-Power, dated June 19, 2012, to evaluate the significance of the finding. The inspectors determined the finding was of very low safety significance (Green) because the finding did not: (1) result in an actual loss of operability or functionality, (2)represent a loss of system and/or function (3) represent an actual loss of function of a single train for greater than its technical specification allowed outage time, (4) represent an actual loss of function of one or more non-technical specification trains of equipment designated as high safety-significant for greater than 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />, and (5) involve the loss or degradation of equipment or function specifically designed to mitigate a seismic, flooding, or severe weather event.

This finding did not have a cross-cutting aspect since the switches were installed and evaluated in 2003, and therefore it is not indicative of current performance (Section 4OA3.5.2).

REPORT DETAILS

OTHER ACTIVITIES

Cornerstones: Initiating Events, Mitigating Systems, Barrier Integrity, Emergency Preparedness, Public Radiation Safety, Occupational Radiation Safety, and Physical Protection

4OA3 Follow-up of Events and Notices of Enforcement Discretion

.1 (Closed) Unresolved Item 05000313/2013011-001, Control of Temporary Modification

Associated with Temporary Fire Pump

The Augmented Inspection Team identified an unresolved item associated with operator control of the water supply to the station fire suppression system and the control of a temporary fire pump modification. Specifically, following the stator drop, a significant fire water leak occurred in the turbine building train bay as a result of a ruptured eight-inch fire water header. The Augmented Inspection Team determined that additional inspection was needed to assess the timeliness of the licensees actions to secure the fire pumps and terminate the supply of water to the fire main rupture in the turbine building train bay.

Observations and Findings

Introduction.

The Augmented Inspection Team, Follow-up Team (inspectors) reviewed a self-revealing, Green non-cited violation of Unit 1 Technical Specification 5.4.1.a and Unit 2 Technical Specification 6.4.1.a, involving the licensees failure to develop and implement procedural controls for response to internal flooding.

Description.

In 1999, the licensee installed a temporary fire pump that could be used during outages or other times when the permanently installed fire pumps were out of service. The power supply for this electric fire pump was from the London 13.8 kV line, which is an additional offsite power source not included in the plant Technical Specifications. This temporary fire pump allowed the licensee to perform maintenance on installed fire pumps and still maintain fire water suppression capability for the site. At the time of the event, the temporary electric fire pump was in service and supplying water from the intake canal to the station fire suppression system.

The collapse of the temporary hoisting assembly and the drop of the generator stator ruptured an eight-inch fire main in the train bay. As designed, the diesel-driven fire pump started when the system pressure dropped below 95 psig. The permanently installed electric fire pump was not available due to the loss of offsite power, but the temporary electric fire pump continued to operate since the London 13.8 kV line was unaffected by the event. The two operating pumps were each capable of supplying approximately 2,500 gpm at rated system pressure.

At 8:03 a.m., an entry in the control room log stated that all firewater pumps, including the temporary firewater pump were secured. However, several subsequent log entries reflected significant water flow from the fire suppression system in the turbine building and into the Unit 1 auxiliary building. A log entry, made 67 minutes after the event, stated that fire hydrant 1 was cycled opened then shut in an attempt to lower fire header pressure and slow firewater into the train bay. A log entry five minutes later stated that the temporary fire pump was secured.

The Augmented Inspection Team confirmed through interviews with the operators that the diesel-driven pump was secured first, and the temporary pump was secured at a later time following the cycling of fire hydrant 1. The Augmented Inspection Team reviewed video taken inside the turbine building following the event and confirmed that the diesel-driven pump was secured at a time consistent with the entry in the station log.

However, the Augmented Inspection Team also identified indications of system pressure consistent with an operating pump approximately 40 minutes after the event.

Based on uncertainties associated with the time line for operator response, the inspectors examined the licensees revised sequence of events for securing the supply of water to the fire main rupture in the turbine building train bay, conducted system walk downs, and reviewed the available video records of the stator drop event. As a result of these reviews, the inspectors determined that the initial timeline for securing the temporary firewater pump, documented in Corrective Action 1, of Condition Report CR-ANO-C-2013-01072, was at least 10 minutes longer than the previously estimated time of 8:19 a.m. Specifically, review of video evidence established that the temporary firewater pump was secured between 8:29 a.m. and 8:38 a.m. This time frame was predicated on observed flow in the video recording at 8:24 a.m. with pressure beginning to drop at approximately 8:29 a.m. and no firewater flow from the ruptured pipe evident at 8:38 a.m.

The inspectors also reviewed the temporary fire pump installation procedure, the associated 10 CFR 50.59 evaluation, the associated operations training material, and the corrective actions identified in Condition Report CR-ANO-C-2013-01072. From these reviews, the inspectors determined that subsequent to the event, extensive corrective actions had been developed to address the prolonged operator response time for securing the temporary fire pump. However, the inspectors determined that prior to the event, there were no specific procedural controls, guidance, or standing orders which directed operations personnel to secure firewater pumps in the event of flooding caused by a fire system leak. The licensees corrective actions included changing Checklist 1104.032, Fire Protection Systems, Revision 76, to include guidance for securing the temporary fire pump in the event of a rupture in the fire main and provided training on this change. This issue was entered into the corrective action program as Condition Reports CR-ANO-C-2013-01072 and CR-ANO-C-2013-01962.

Analysis.

The inspectors determined that the licensees failure to develop and implement adequate procedural controls for the permanently installed temporary fire pump was a performance deficiency. The performance deficiency was more than minor because it impacted the procedural quality attribute of the mitigating systems cornerstone and affected the cornerstones objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences (i.e. core damage). Specifically, if the necessary remedial actions cannot be completed in the time required, some of the stations accident mitigation equipment could be adversely impacted.

Unit 1

Analysis:

Inspection Manual Chapter 0609, Attachment 0609.04, Initial Characterization of Findings, dated June 19, 2012, Table 3, Section A, directs the user to Appendix G. The inspectors used Inspection Manual Chapter 0609, Appendix G, Attachment 1, Shutdown Operations Significance Determination Process Phase 1 Operational Checklists for Both PWRs and BWRs, dated May 25, 2004, Checklist 4, to evaluate the significance of the finding. The inspectors determined that the finding was of very low safety significance (Green) because the finding did not:

(1) increase the likelihood of a loss of reactor coolant system inventory,

(2) degrade the licensees ability to terminate a leak path or add reactor coolant system inventory when needed, and

(3) degrade the licensees ability to recover decay heat removal once it is lost.

Unit 2

Analysis:

Inspection Manual Chapter 0609, Attachment 0609.04, Initial Characterization of Findings, dated June 19, 2012, Table 3, Section E, Step 2, directs the user to Appendix F, Fire, Protection Significance Determination Process dated September 20, 2013. The inspectors used Appendix F, to evaluate the significance of the finding. The finding involved a fixed fire protection system and the fire water supply (temporary fire pump). The finding was screened against the qualitative screening question in Appendix F, Task 1.3.1 and the inspectors determined it was of very low safety significance (Green), because the reactor was able to reach and maintain safe shutdown.

The finding had a cross-cutting aspect in area of the human performance associated with documentation, because the licensee failed to create and maintain complete, accurate, and up-to-date documentation for the use of the temporary fire pump [H.7]

(Section 4OA3.1).

Enforcement.

Unit 1 Technical Specification 5.4.1.a and Unit 2 Technical Specification 6.4.1.a, state that, Written procedures shall be established, implemented, and maintained covering the following activities: The applicable procedures recommended in Regulatory Guide 1.33, Revision 2, Appendix A, February 1978.

Regulatory Guide 1.33, Quality Assurance Program Requirements (Operation),

February 1978, Appendix A, Section 6.r, requires, in part, implementation of approved procedures for combating emergencies and other significant events, including other expected transients that may be applicable. Contrary to the above, since 1999, the licensee failed to establish a procedure to address the requirements of Regulatory Guide 1.33, Appendix A, Section 6.r. Specifically, Procedure 1104.032, Fire Protection Systems, Revision 75, did not contain specific controls or guidance to secure the temporary fire pump in the event of flooding caused by a fire system leak. Since this finding is of very low safety significance and has been entered into the corrective action program as Condition Reports CR-ANO-C-2013-01072 and CR-ANO-C-2013-01962, this violation is being treated as a non-cited violation consistent with Section 2.3.2.a of the NRC Enforcement Policy: NCV 05000313/20130012-01; 05000368/20130012-01; Failure to Adequately Develop and Implement Adequate Procedural Controls to Remediate the Anticipated Effects of Internal Flooding for Either Unit.

.2 (Closed) Unresolved Item 05000313/2013011-002; 05000368/2013011-002, Damage to

Unit 1 and Unit 2 Structures, Systems and Components

The Augmented Inspection Team concluded that the licensee had appropriate plans in place to identify affected equipment, control access to the affected areas, and commence debris removal and repair activities after the stator drop occurred. However, since a full assessment of the damage to Unit 1 and Unit 2 structures, systems, components following the dropped stator was not possible until debris had been removed, an unresolved item was opened to assess the damage.

Observations and Findings

The inspectors reviewed Condition Reports CR-ANO-1-2013-00868 and CR-ANO-2-2013-00620, and performed visual inspections of walls, floors, structural supports, and ceilings. The inspectors visually inspected support beams, conduit, cable raceways, ventilation ducting, hydrogen piping, carbon dioxide piping, instrument air piping, and equipment in the affected areas.

The inspectors discussed with the licensee the effect of the dropped stator on electrical busses, raceways and cabling, and the acceptance testing the licensee performed on the affected cables. The inspectors also reviewed and discussed the post-installation testing the licensee performed on the repaired Unit 1 4160 Vac switchgear.

The inspectors toured affected areas, looking at the turbine building structures and components. Acceptance testing of the repaired switchgear was ongoing, but was mostly completed by the time of the inspection. The inspectors concluded that the turbine building structures were repaired to the same condition as they were prior to the stator drop, with exceptions, that included:

The non-load bearing masonry block wall between the machine shop and the train bay was not replaced. The licensee relocated the machine shop equipment to a different facility outside the protected area, and intends to use the area between the train bay and former machine shop as a storage area during future refueling outages.

The inspectors concluded that the repairs to the turbine building structures and components were effective.

No findings were identified.

.3 (Closed) Unresolved Item 05000313/2013011-003, Procedural Controls Associated with

Unit 1 Steam Generator Nozzle Dams

The Augmented Inspection Team identified an unresolved item associated with the procedural controls for the backup air supply systems to the Unit 1 nozzle dams. The inspectors concluded that additional inspection was required to assess the procedural controls associated with the primary and backup pressure sources for the steam generator nozzle dams.

a. Observations and Findings

On March 28, 2013, the Unit 1 steam generator nozzle dams were installed. The nozzle dams consisted of one rigid plug and two inflatable dams, installed in the reactor coolant system piping that provided access for work inside the steam generators while maintaining water inventory in the reactor coolant system. The inflatable nozzle dams are pressurized to a normal operating pressure of approximately 75 psig. On a loss of seal pressure, the design of the nozzle dams limits the maximum leakage through the seals to approximately 2 gpm. The normal system lineup included a regulated 90 psig primary supply with an independent 80 psig backup pressure source. At the time of the stator drop event, the primary supply for the nozzle dams consisted of a portable electric air compressor with the backup supply provided by a second portable electric air compressor powered by a different train of non-safety-related electrical power. In the event of loss of both air supplies, the licensees contingency plan provided for the use of the instrument air system.

The stator drop event resulted in the loss of offsite electrical power to Unit 1 and most of the power to the containment building, including loss of power to both air compressors for the nozzle dams. The nozzle dams began to lose pressure, due to the check valves on the air supply lines leaking. At approximately 9:30 a.m., personnel entered containment and observed nozzle dam pressure was approximately 50 psig and falling.

The licensees steam generator engineer requested nitrogen bottles be brought into containment. While waiting for the nitrogen bottles, nozzle dam pressures approached 25 psig, at which point the nozzle dam seals were subject to reactor coolant system leakage. The steam generator engineer connected the local instrument airline to the nozzle dams; however, instrument air pressure was reduced to approximately 50 psig due to the trip of the instrument air compressors following the startup transformer 3 lockout and partial loss of offsite power to Unit 2. Compressed nitrogen bottles were subsequently taken into containment and aligned to the nozzle dam consoles and seal pressure was restored to approximately 70 psig. However, as a result of degraded seal pressure, a small amount of reactor coolant system inventory leaked past the nozzle dam seals.

Recovery efforts also included connecting a line to the nozzle dams from a distribution air center supplied by the refueling air compressor. The refueling air compressor was located outside the containment building and was powered from the London 13.8kV line, which was not affected by the stator drop event. The refueling air compressor was placed into service as the primary source of air for nozzle dam seal pressurization with the nitrogen bottles as the backup source. The licensee established local nozzle dam checks on a two-hour frequency. The inspectors determined the licensees response to this event was appropriate.

The inspectors reviewed design documents and industry information associated with the nozzle dam design. Unit 1 Safety Analysis Report Section 4.2.2.2, Steam Generator, indicated that the nozzle dams prevent water from entering the steam generators.

Section 4.2.2.2 also stated that the nozzle dams serve no safety function. Engineering Evaluation ER981203 E101, Engineering Evaluation of the ANO-1 Steam Generator Nozzle Dams, dated January 1999, documented that the nozzles dam structure consisted of two redundant inflatable seals and one passive emergency backup seal.

The design of the seals was for the inflatable seals to provide the primary and normal backup seal and in the unlikely event of both inflatable seals failing, the passive seal would limit leakage to less than 2 gpm, as stated above. The design of the seal was consistent with industry guidance to limit leakage on the event of a catastrophic inflatable seal failure. The inspectors reviewed the original procurement Specification ANO-M-434, Specification for Arkansas Nuclear One Russellville, Arkansas OTSG

[Once-Through Steam Generator] Nozzle Dams, dated April 20, 1990. The nozzle dams, including the seals, were procured as non-quality related.

As documented in Condition Report CR-ANO-1-2013-00917, the corrective actions included leak testing of the nozzle dam check valves and having nitrogen bottles as a backup source of air in case of loss of electrical power to the air compressors. One of the contributors to the loss of seal pressure was that in 2010, Procedure OP-5120.504, OTSG Nozzle Dam Training, Testing and Installation/Removal, Revision 6, was revised to allow various options for maintaining seal pressure, and nitrogen bottles were no longer used based on the operational convenience of not bringing the bottles into containment. The inspectors determined that the change in 2010, to remove the nitrogen bottles, was non-conservative.

No findings were identified.

.4 (Closed) Unresolved Item 05000368/2013011-004, Main Feedwater Regulating Valve

Maintenance Practices

The Augmented Inspection Team identified an unresolved item associated with licensee maintenance practices involving the main feedwater regulating valves. The inspectors concluded that additional inspection was required to assess the effectiveness of the licensee maintenance practices for the main feedwater regulating valves.

Following the Unit 2 reactor trip on March 31, 2013, operators identified that main feedwater regulating valve A failed to indicate closed. This indication resulted in the operators tripping main feedwater pump A and manually initiating the emergency feedwater actuation system. Operators subsequently placed the auxiliary feedwater system in service, which required operators to manually inhibit the emergency feedwater system, rendering both trains of emergency feedwater inoperable and requiring entry into Technical Specification 3.0.3 for a short period of time. The licensee later determined that the regulating valve actually had closed, and the valve indication was in error.

Observations and Findings

Introduction.

The inspectors reviewed a Green self-revealing finding associated with a failure to provide sufficient work instructions for the replacement of the main feedwater regulating valve 2CV-0748 linear variable differential transformer 2ZT-0748.

Specifically, the licensee failed to translate vendor recommendations to use a thread sealant and torqueing the adjustment nuts on the linear variable differential transformer 2ZT-0748, into procedural steps to be accomplished and verified. The failure to use thread sealant and torque the adjustment nuts resulted in the nuts loosening and falling off because of vibration. The licensee initiated corrective actions, Condition Report CR-ANO-2-2013-00423 and Work Order WT-WTANO-2013-00039 to perform maintenance to add thread sealant, and torque the nuts to prevent the nuts from loosening.

Description.

Following the Unit 2 reactor trip on March 31, 2013, operators identified that main feedwater regulating valve 2CV-0748 went closed; however, the digital indications provided from the valve linear variable differential transformer and limit switches falsely showed the valve to be 7.7 percent open. These indications resulted in the operators tripping main feedwater pump A and manually initiating the emergency feedwater actuation system in accordance with Procedure 2002-001, ANO standard Post Trip Action, Revision 13. Operators subsequently placed the auxiliary feedwater system in service, which required operators to manually inhibit the emergency feedwater system, rendering both trains inoperable and requiring entry into Technical Specification 3.0.3 for a short period of time. This complicated operator response to the trip.

The licensee later determined that the regulating valve actually had closed, and the valve indication was in error. Based on its investigation, the licensee determined that the lower nut, which holds the LVDT 2ZT-0748, MFW 2P-1A DISCH MAIN REG LVDT on a support plate on which the limit switches were also mounted, was missing. The missing nut caused the linear variable differential transformer and the valve limit switch, which provide digital indication for feedwater loop A main regulating valve position, to show an incorrect valve position indication.

The linear variable differential transformer was replaced during refueling outage 2R22, which occurred in the fall of 2012. Maintenance work order MWO-5024186-01 had a note that required thread sealant for the linear voltage differential transformer rod. The work order did not provide steps for the application of thread sealant for the upper and lower nuts that hold the linear variable differential transformer rod. The use of a note was contrary to Procedure EN-AD-101-01, Nuclear Management Manual Procedure Writer Guide,Section I, Item 7, which specified that, notes are to be used for clarifying information and are not to contain action instructions.

As corrective actions, the licensee torqued and added thread sealant to the nuts that held the linear variable differential transformer rod; modified the work order to add steps to install thread sealant; and, torqued the upper and lower nuts of the linear variable differential transformer rod. The linear variable differential transformer was also calibrated and tested.

Analysis.

The inspectors determined that the failure to provide instructions to properly perform maintenance on linear variable differential transformer 2ZT-0748 was a performance deficiency. The performance deficiency was more than minor because it was associated with the procedure quality attribute of the mitigating systems cornerstone. It adversely affected the cornerstone objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences, and is therefore a finding. The inspectors used Inspection Manual Chapter 0609, Attachment 0609.04, Initial Characterization of Findings, dated June 19, 2012, and Appendix A, The Significance Determination Process (SDP) for Findings At-Power, dated June 19, 2012, to evaluate the significance of the finding.

The inspectors determined that the finding was of very low safety significance (Green)because the finding did not:

(1) result in an actual loss of operability or functionality, (2)represent a loss of system and/or function,

(3) represent an actual loss of function of a single train for greater than its technical specification allowed outage time,

(4) represent an actual loss of function of one or more non-technical specification trains of equipment designated as high safety-significant for greater than 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />, and

(5) involve the loss or degradation of equipment or function specifically designed to mitigate a seismic, flooding, or severe weather event. The finding had a cross-cutting aspect in the area of problem identification and resolution associated with operating experience, because although the licensee had collected and evaluated the operating experience, it was not implemented as procedural steps in linear variable differential transformer replacement work instructions [P.5].

Enforcement.

This finding does not involve a violation, because there is no regulatory requirement associated with this finding. As such, and because the associated performance deficiency is of very low safety significance (Green), it is identified as a finding: FIN 05000368/2013012-002, Main Feedwater Regulating Valve Maintenance Practices.

.5 (Discussed) Unresolved Item 05000313/2013011-005, Flood Barrier Effectiveness

The Augmented Inspection Team noted that following the stator drop, a significant fire water leak occurred in the train bay from a ruptured eight-inch fire header. Due to the approximately 50 minute time before the pipe rupture was isolated, fire water sprayed into the auxiliary building and accumulated in the general area access at the 317 foot elevation. Water also accumulated in the flood protected decay heat vault B, which is also on the 317 foot elevation. The Augmented Inspection Team concluded that additional inspection was required to determine the causes and impact of the failed flood hatches and the partially open decay heat vault B, drain isolation valve.

a. Inspection Scope

Background of Unit 1 and Unit 2 Flood Protection Features

The Arkansas Nuclear One facility was built at a plant grade elevation of 354 feet. The design basis flood water level for both Unit 1 and Unit 2 has a projected flood elevation of 361 feet at the site. Safety-related structures, systems, and components necessary for reaching and maintaining safe shutdown are protected against the design basis flood level. The flood protection features for both units are similar, but Unit 2 has a more robust design.

Both units have safety-related structures, systems, and components necessary to maintain safe shutdown for above the design basis flood water level, including the emergency diesel generators, 4160 Vac vital and non-vital switchgear, service water pump motors, and offsite power feeds. Some of this equipment is located in the auxiliary building below the projected flood level and requires protection. Both units auxiliary building designs incorporate features to keep water out, such as watertight doors, equipment hatches, and concrete plugs with a neoprene seal to prevent water from entering. The incorporated barriers include reinforced concrete walls designed to resist the static and dynamic forces of the projected flood, with special water-stops at construction joints to prevent in-leakage. Pipe penetrations through the walls have special rubber boots or other protective features. In addition, both units have required safety-related structures, systems, and components on the 317 foot elevation partitioned into separate rooms to provide protection in the event of flooding. The partition walls are designed to withstand hydrostatic loading over their full height.

Watertight Rooms in Unit 1 and Unit 2

Unit 1 has two watertight rooms on the 317 foot elevation. Each room contains a train of safety-related equipment, consisting of a decay heat removal pump, a reactor building spray pump, a decay heat removal heat exchanger, and a room cooler. Other Unit 1 safety-related pumps, including the high pressure injection pumps and emergency feedwater pumps, are on the 335 foot elevation and are not in watertight rooms.

Similarly, Unit 2 has watertight rooms for protection of safety-related equipment. Unit 2 has the emergency feedwater pumps protected in watertight rooms located on the 335 foot elevation. Unit 2 has separate trains of low pressure safety injection pumps, high pressure safety injection pumps, and containment spray pumps in separate vaults on the 317 foot elevation. Unit 2 also has a swing high pressure safety injection pump and associated room cooler in a separate vault on the 317 foot elevation.

Any water leakage into the auxiliary building would flow into various floor drains and openings, down to the 317 foot level of each auxiliary building. This leakage would either go into each units respective dirty waste storage tank or into the units auxiliary building sump. Sump pumps are provided to remove any small leakage that could seep through exterior concrete walls and discharge into the dirty waste storage tank. The water can then be transferred out of the dirty waste storage tank to be processed and safely disposed of via each units radioactive waste cleanup system. The auxiliary building sump pumps and dirty waste system are non-safety-related. One sump pump will automatically start on Unit 1 at a specified level, and a second pump that could be started manually is available. Unit 2 sump pumps will both start automatically, depending on Unit 2 sump level.

Augment Inspection Follow-up Team Review

The inspectors reviewed the licensees Condition Report ANO-C-2013-01304 written to address the condition of water entering the Unit 1 auxiliary building, walked down various design features of the auxiliary building, interviewed staff, reviewed records, and associated drawings. Due to the equipment in the turbine building impacted by the stator drop, non-safety-related power was lost and there was no power to the auxiliary building sump pumps and dirty waste storage tank system. The licensee identified about an inch of water in decay heat removal room B and on the general access area of the 317 foot level of the auxiliary building. When water from the broken fire main reached the removable floor plugs, the water leaked past the plugs into the lower auxiliary building elevations, because the plug seals were degraded. The water subsequently reached the 317 foot level of the auxiliary building and filled the auxiliary building sump.

Each decay heat removal room has an isolation valve that allows water in the decay heat removal room to be drained to the auxiliary building sump. The isolation valve for the drain from decay heat removal room B was not fully shut and water from the auxiliary building sump flowed back into the room.

.1 Flood Mitigation Barriers

The inspectors have not completed their evaluation of the licensees extent of condition for the degraded flood barriers. As such, this unresolved item will remain open and will include the consideration of the following items:

(a) Floor Plugs are designed to allow for access and the movement of components into and out of the lower levels of the auxiliary building. Flood protection for these plugs was provided by a neoprene seal. The licensee had no specified frequency for seal replacement. The seal was either too old and it did not seal, or the design was inadequate in that the seal rolled out of place when the plug was set into the floor.

(b) The decay heat removal room drain valves are manually closed to prevent water from entering the vault. During the event, one drain valve indicated closed, but the valve was partially open, allowing water to enter the room. On several occasions after the event, operators attempted to shut the valve, but it did not fully shut. The lack of maintenance on the associated reach rods, and/or position indication not being correct, or a combination of these two conditions, resulted in plant operators not being able to consistently close the train B decay heat removal vault drain valve.

(c) From its extent of condition review, the licensee identified other paths for water to get into the auxiliary building. These included: drains in the turbine building, a sump from the solid radioactive waste storage building (located in the switchyard) to the Unit 1 auxiliary building sump, unprotected penetrations in the auxiliary building annex, unprotected electrical conduits entering into the auxiliary building, unsealed holes in the auxiliary building from the turbine building, and the tendon gallery access hatches. On March 5, 2014, the licensee submitted a non-emergency 10 CFR 50.72 notification, Event Number 49873, to the NRC for the discovery of pathways that could bypass flood barriers. For immediate corrective actions, the licensee installed barriers in the pathways or implemented compensatory measures.

(d) The NRC needs to determine why these items identified in the extent of condition walk down for the flooding event, caused by the stator drop, were not identified as part of the flooding walk downs described in Arkansas Nuclear One letters, dated November 27, 2012 (ML12334A008 and ML ML12334A006), in response to the NRCs Request for Information letter, Request for Information Pursuant to Title 10 of the Code of Federal Regulations 50.54(f) Regarding Recommendations 2.1, 2.3, and 9.3 of the Near-Term Task Force Review of Insights form the Fukushima Dai-ichi Accident, dated March 12, 2012 (ML12053A340).

(e) The safety classification of the vault drain valves as non-safety-related does not appear commensurate with its importance in mitigating a flooding event.

.2 Decay Heat Removal Rooms Flood Level Switches not Scoped into the Maintenance

Rule

Introduction.

The inspectors identified a Green non-cited violation of 10 CFR-50.65(b)(2)(i) associated with the licensees failure to monitor non-safety-related structures, systems, and components that are relied upon to mitigate accidents or transients.

Description.

During inspection of the water intrusion into Unit 1, the inspectors noted that both Unit 1 decay heat removal rooms contain high level alarm switches that are credited, in part, with mitigating the effects of internal flooding caused by a moderate energy line break. Specifically, if there is internal flooding in one of the Unit 1 decay heat removal rooms as indicated by the room level switch, operators are dispatched to ensure that the other Unit 1 train decay heat removal room is isolated. The inspectors noted that the failure of these switches could result in operators failing to take actions to mitigate internal flooding.

The level switches associated with Unit 1 decay heat removal rooms provide a control room alarm. The annunciator response Procedure 1203.012H, Annunciation K09 Corrective Action, Revision 43, directs the operators to verify that the opposite train room floor drain valve is closed. This action helps ensure that two trains of safety-related equipment are not affected by the flooding.

The licensee installed new level switches in 2003, but determined that no preventive maintenance activity was necessary for these switches. Based on their understanding that these non-safety-related switches are credited with mitigating an accident, and the knowledge that the maintenance rule scoping documents did not identify these level alarm switches, the inspectors questioned how they were being controlled and what type of preventative maintenance was being performed. The licensees corrective actions included developing a preventive maintenance task to test the operation of the level switches and the switches operated properly. The licensee entered this issue into the corrective action program as Condition Report CR-ANO-2013-03168.

The inspectors, as part of their independent extent of condition review, looked at how the licensee treats the room level switches in Unit 2 and noted that the licensee had established preventive maintenance tasks to test the operation of the level switches.

Analysis.

The failure to effectively monitor the performance of both Unit 1 decay heat removal room level switches in accordance with 10 CFR 50.65(a)(1) was a performance deficiency. The inspectors determined that the performance deficiency was more than minor because it affected the equipment performance attribute of the mitigating systems cornerstone, and directly affected the cornerstone objective of ensuring the availability and reliability of systems that respond to initiating events to prevent undesirable consequences, in that it called into question the reliability of flood mitigation equipment.

The inspectors used Inspection Manual Chapter 0609, Attachment 0609.04, Initial Characterization of Findings, dated June 19, 2012, and Appendix A, The Significance Determination Process (SDP) for Findings At-Power, dated June 19, 2012, to evaluate the significance of the finding. The inspectors determined the finding was of very low safety significance (Green) because it did not:

(1) result in an actual loss of operability or functionality,

(2) represent a loss of system and/or function,

(3) represent an actual loss of function of a single train for greater than its technical specification allowed outage time,

(4) represent an actual loss of function of one or more non-technical specification trains of equipment designated as high safety-significant for greater than 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />, and

(5) involve the loss or degradation of equipment or function specifically designed to mitigate a seismic, flooding, or severe weather event. This finding did not have a cross-cutting aspect since the switches were installed and evaluated in 2003, and therefore it is not indicative of current performance

Enforcement.

Title 10 CFR 50.65(b)(2)(i) requires, in part, that the scope of the monitoring program specified in paragraph (a)(1) shall include non-safety-related structures, systems, and components that are relied upon to mitigate accidents or transients. Contrary to the above, from initial maintenance rule scoping in 1996 to the present, the Unit 1 decay heat removal room level alarm switches (non-safety-related)were not included in the scope of the monitoring program specified in 10 CFR 50.65(a)(1). The inclusion of the Unit 1 decay heat removal room level alarm switches in the scope of the monitoring program is necessary because these components are relied upon to mitigate accidents or transients. Since this finding is of very low safety significance and has been entered into the corrective action program as Condition Report CR-ANO-1-2013-03168, this violation is being treated as a non-cited violation consistent with Section 2.3.2.a of the NRC Enforcement Policy:

NCV 05000313/2013013-003, Failure to Scope Required Components in the Stations Maintenance Rule Monitoring Program.

.6 (Closed) URI 05000313; 368/2013011-006, Compensatory Measures for Firewater

System Rupture

The Augmented Inspection Team identified an unresolved item associated with the licensees compensatory measures for fire suppression prior to the restoration of the damaged firewater system. The inspectors concluded that additional inspection was needed to fully assess the effectiveness of the compensatory measures and the timeliness of the firewater system restoration.

Observations and Findings

The inspectors conducted interviews with on-shift licensee personnel assigned to establish compensatory measures for the damaged fire main. The inspectors toured the areas impacted by the damaged fire main and reviewed the Unit 1 and Unit 2 Technical Requirements Manual.

The Unit 1 stator drop caused damage to an eight-inch fire main pipe that feeds various fire stations. To control flooding, the fire suppression system was secured until the damaged piping could be isolated.

The licensee did establish compensatory measures while isolating and repairing the damaged fire main system. In addition, before the Unit 2 startup, the licensee established compensatory measures to meet conditions specified in the Unit 2 Technical Requirements Manual. The inspectors reviewed the compensatory measures implemented by the licensee and determined that they were appropriate.

No findings were identified.

.7 (Closed) URI 05000368/2013011-007, Timeliness of Emergency Action Level

Determination

The Augmented Inspection Team identified an unresolved item involving the timeliness of the emergency declaration of a Notification of Unusual Event based on the information available to the control room operators. The inspectors concluded that additional follow-up inspection was required to assess the timeliness of the emergency classification given the information available to the control room operators.

Observations and Findings

The inspectors conducted interviews with on-shift licensee personnel and physically observed the damaged electrical area in order to make an independent assessment of the information needed to determine if criteria was met for an emergency declaration.

The inspectors concluded that a correct and timely emergency declaration was made by the licensee.

The Unit 1 stator drop caused damage to an eight-inch fire main and a wall adjacent to the Unit 2 4160 Vac non-vital switchgear. The spray from the damaged fire main piping impacted the Unit 2 switchgear breaker enclosures and accumulated on the floor. The water spray and/or the water accumulation caused breaker 2A-113 to short and explode, vaporizing the components within the breaker cubicle.

The initial report to the control room at 9:25 a.m. was that one of the breaker doors on switchgear bus 2A1 has been knocked open, but licensee personnel were unable to determine at that time which breaker had been impacted. Light smoke with no visible fire, from the back of one breaker in switchgear bus 2A2, was reported. There was standing water around the switchgear. The March 31, 2013, dayshift Unit 2 Shift Manager walked the inspectors around the Unit 2 non-vital switchgear explaining the conditions observed in the area after the Unit 1 stator drop event. At the time of the event, the licensee determined that it was unsafe for personnel to approach the breaker.

Approximately one hour later, conditions were such that licensee personnel could observe the breaker cubicle to make a preliminary assessment. The licensee noted metal splatter on the inside of the door that would indicate a high-energy event, i.e.

explosion, from possible water intrusion into the breaker cubicle. According to the Unit 2 station logs, when these observations were reported to the control room operators, the shift manager declared an emergency declaration of a Notice of Unusual Event at 10:34 a.m. Initial notifications of the Notice of Unusual Event were completed at 10:48 a.m.

per the logs. The inspectors determined that upon identification of the explosion of breaker 2A-113, the shift manager made the emergency declaration notification to offsite parties within 15 minutes of the initial emergency declaration.

No findings were identified.

.8 (Closed) Unresolved Item 05000313/2013011-008, Effectiveness of Shutdown Risk

Management Program

The Augmented Inspection Team determined that additional inspection was necessary to assess the effectiveness of the licensees risk mitigating measures associated with the stator move.

Observations and Findings

The inspectors reviewed Condition Reports CR-ANO-1-2013-00132 and CR-ANO-1-2013-01028, as well as Procedures EN-FAP-OU-100, Refueling Outage Preparation and Milestones, Revision 1 and EN-OU-108, Shutdown Safety Management Program, Revision 5. These procedures provided a process to assess the overall impact of plant maintenance on plant risk to satisfy the requirements of 10 CFR 50.65(a)(4) during the cold shutdown and refueling modes of reactor operation. Procedure EN-OU-108, Step 5.4, described two types of contingency plans that needed to be developed. The stator move fell under the definition of an outage risk contingency plan. Procedure EN-FAP-OU-100 also described the level of contingency planning necessary based on the probability of an issue/problem occurring and the potential impact the issue/problem could have. Plant history, industry experience, and worker knowledge were used to evaluate probability and impact. Probabilities of an issue/problem were further delineated into High, Medium, or Low, and the impacts of an issue were also delineated as High, Medium, or Low.

The movement of the stator was a high impact, but low probability event. The inspectors noted that Procedure EN-FAP-OU-100, Section 7.7, did not require a contingency plan because of the low probability of the event. The inspectors reviewed Regulatory Guide 1.182, Assessing and Managing Risk before Maintenance Activities at Nuclear Power Plants, dated May 2000, which endorses NUMARC 93-01, Industry Guideline for Monitoring the Effectiveness of Maintenance at Nuclear Power Plants, dated February 11, 2000, Section 11, Assessment of Risk Resulting from Performance of Maintenance Activities. NUMARC 93-01, Section 11, references NUMARC 91-06, Guidelines for Industry Actions to Assess Shutdown Management, Section 4.0, Shutdown Safety Issues.

The inspectors determined that while no specific contingency plan for the stator move was developed, the licensee did develop a contingency plan for the protection of spent fuel cooling. The inspectors concluded that no contingency plans were procedurally required to be developed by the licensee for the stator move and this was consistent with NUMARC 93-01.

No findings were identified.

.9 (Closed) Unresolved Item 05000313/2013011-009, Effectiveness of Material Handling

Program

The Augmented Inspection Team identified an unresolved item associated with the licensees implementation of Procedure EN-MA-119, Material Handling Program. The inspectors determined that the design and test process applied to the crane did not conform to applicable procedures and standards. However, the inspectors concluded that additional inspection was needed to assess the effectiveness of the material handling program implementation in mitigating risk associated with the stator movement activities.

a. Observations and Findings

Introduction.

The NRC identified an apparent violation of 10 CFR 50, Appendix B, Criterion V, Instructions, Procedures and Drawings, applicable to both Unit 1 and Unit 2. Criterion V states, in part, that activities affecting quality shall be prescribed by documented instructions, procedures, or drawings, of a type appropriate to the circumstances and shall be accomplished in accordance with these instructions, procedures or drawings. The licensee did not follow the requirements specified in Procedure EN-MA-119, in that, the licensee did not perform an adequate review of the subcontractors lifting rig design calculation, and the licensee did not conduct a load test of the lifting rig prior to use. The licensee initiated Condition Report CR-ANO-C-2013-00888 to capture this issue in its corrective action program. The licensee's corrective actions included repairing damage to the Unit 1 turbine deck, fire main system, and electrical system. In addition, changes were made to various procedures including Procedure EN-DC-114, Project Management, to provide guidance on review of calculations, quality requirements, and standards associated with third party reviews.

Description.

The Augmented Inspection Team evaluated the effectiveness of measures to reduce the potential for a load drop consistent with the program requirements specified in Procedure EN-MA-119. They determined through interviews and documentation reviews, that the licensees pre-outage evaluations were primarily focused on ensuring that the temporary hoisting assembly did not overload the existing plant structures. The Augmented Inspection Team also established that the project management organization considered the temporary crane installed by the subcontractor in the turbine building to be a temporary hoisting assembly. Procedure EN-MA-119, Section 5.2, Load Handling Equipment Requirements, Item 7, stated, in part, that the following measures were to be used to establish the temporary hoisting assemblies structural integrity:

• Licensee engineering support personnel shall approve the design of vendor supplied temporary overhead cranes.

• The temporary overhead crane shall be designed for 125 percent of the projected hook load and shall be load tested in all configurations for which it will be used.

• Load bearing welds are required to be inspected before and after the load test.

Section 5.2, Item 7, also included a note indicating that specially designed lifting devices may be designed and tested to other approved standards.

Based on the results of the Augmented Inspection Teams evaluation of the material handling program, the inspectors determined that the temporary hoisting assembly had not been load tested. The Augmented Inspection Team also established that although the note in Procedure EN-MA-119 allowed the use of alternate standards in lieu of load testing, the licensee could not identify objective evidence to demonstrate that an alternate approved standard had been used for the design and testing of the temporary hoisting assembly.

The inspectors, based on their independent review, determined that the temporary hoisting assembly design was based, in part, on an incorrect assumption, and the frame was not designed to support the stator load. The licensee concluded that one of the root causes for the temporary lift assembly collapse was that the sub-contractors design did not ensure that the lift assembly north tower could support the loads anticipated for the lift.

In addition, the licensee, based on its root cause evaluation, concluded that the subcontractor failed to conduct the required load testing of their modified temporary lift assembly before its use. Specifically, the licensee concluded that:

• The north tower structure of the temporary lift assembly had not been subject to a load test or previously used in lifts of equal or greater capacity to that of the Unit 1 stator.

• Occupational Safety and Health Administration (OSHA) regulation CFR 29.1910.179 (k)(1) required that prior to initial use of a new or altered crane, the crane shall be tested to insure compliance with this section.

• The industry consensus standard, American Society of Mechanical Engineers NQA-1-2008, to which the subcontractor designed the temporary lift assembly, required load testing to ensure the structural and mechanical capacity of new or modified cranes.

Based on the results of their review, the inspectors concluded that the licensee failed to properly implement the requirements specified in Procedure EN-MA-119. Specifically, the inspectors identified that the licensee failed to:

• Adequately review and approve the subcontractors design Calculation 27619-C1 as required by Section 5.2[7](a).

• Ensure that a load test of the assembly to at least 125 percent of the projected hook load was conducted, and that the assembly be load tested in all configurations for which it will be used, as required by Section 5.2[7](b).

The licensee initiated Condition Report CR-ANO-C-2013-00888 to capture this issue in its corrective action program. The licensees corrective actions included repairing damage to the Unit 1 turbine deck, fire main system, and electrical system. In addition, changes were made to various procedures including Procedure EN-DC-114, Project Management, to provide guidance on review of calculations, quality requirements, and standards associated with third party reviews.

Unit 1:

Analysis.

The inspectors determined that the failure to implement the requirements of Procedure EN-MA-119 was a performance deficiency. Specifically, the licensee failed to:

(1) independently review the subcontractors calculation for the design of the temporary hoisting assembly as specified in Procedure EN-MA-119, Section 5.2[7](a),and

(2) perform a load test of the assembly to 125 percent of the projected hook load and load test the assembly in all configurations for which it will be used, as required by Procedure EN-MA-119 Section 5.2[7](b). The finding was more than minor because it was associated with the procedural control attribute of the initiating event cornerstone, and adversely affected the cornerstones objective to limit the likelihood of events that upset plant stability and challenge critical safety functions during shutdown, as well as power operations. The stator drop affected offsite power to Unit 1, resulting in a loss of offsite power for approximately 6 days and a loss of the alternate AC diesel generator.

The inspectors used Inspection Manual Chapter 0609, Attachment 0609.04, Initial Characterization of Findings, dated June 19, 2012, to evaluate the significance of the finding. Since the plant was shutdown, the inspectors were directed to Inspection Manual Chapter 0609, Appendix G, Attachment 1, Shutdown Operations Significance Determination Process Phase 1 Operational Checklists for Both PWRs and BWRs, Checklist 4, dated May 25, 2004. Using Appendix G, Attachment 1, Checklist 4, the inspectors concluded that this finding degraded the licensees ability to add reactor coolant system inventory when needed since a loss of offsite power occurred, and therefore, this finding required a detailed risk analysis. A shutdown risk model was developed by modifying the at-power Arkansas Nuclear One Unit 1 standardized plant analysis risk (SPAR) model, Revision 8.19. The NRC risk analyst assessed the significance of shutdown events by calculating an instantaneous conditional core damage probability. The results were dominated by two sequences. The largest risk contributor (approximately 97 percent) was from a failure of the emergency diesel generators without recovery. The second largest risk contributor was the failure to recover decay heat removal. The result of the analysis was an instantaneous conditional core damage probability of 3.8E-4; therefore, this finding was preliminarily determined to have high safety significance (Red). Refer to Attachment 2 for the Unit 1 outage detailed risk evaluation.

This finding had a cross-cutting aspect in the area of human performance associated with field presence, because the licensee did not ensure adequate supervisory and management oversight of work activities, including contractors and supplemental personnel. Specifically, the licensee did not provide a sufficient level of oversight in that, the requirements in Procedure EN-MA-119, for design approval and load testing of the temporary hoisting assembly, were not followed [H.2].

Unit 2:

Analysis.

The inspectors determined that the failure to implement the requirements of Procedure EN MA-119 was a performance deficiency. Specifically, the licensee failed to:

(1) independently review the subcontractors calculation for the design of the temporary hoisting assembly as specified in Procedure EN-MA-119, Section 5.2[7](a),and

(2) perform a load test of the assembly to 125 percent of the projected hook load and load test the assembly in all configurations for which it will be used, as required by Procedure EN-MA-119 Section 5.2[7](b). The finding was more than minor because it was associated with the procedural control attribute of the initiating event cornerstone, and adversely affected the cornerstones objective to limit the likelihood of events that upset plant stability and challenge critical safety functions during shutdown, as well as power operations. The stator drop caused a reactor trip on Unit 2 and damage to the fire main system which resulted in water intrusion into the electrical equipment causing a loss of startup transformer 3. This resulted in the loss of power to various loads, including reactor coolant pumps, instrument air compressors, and the safety-related Train B vital electrical bus. The inspectors used Inspection Manual Chapter 0609, 0609.04, Initial Characterization of Findings, dated June 19, 2012, and Appendix A, The Significance Determination Process (SDP) for Findings At-Power, dated June 19, 2012, to evaluate the significance of the finding. Since this was an initiating event, the inspectors used Exhibit 1 of Appendix A and determined that Section C, Support System Initiators, was impacted because the finding involved the loss of an electrical bus and a loss of instrument air. The inspectors determined that Section E, External Event Initiators, of Exhibit 1 should also be applied because the finding impacted the frequency of internal flooding. Since Sections C and E were impacted, a detailed risk evaluation was required. The NRC risk analyst used the Arkansas Nuclear One, Unit 2 Standardized Plant Analysis Risk Model, Revision 8.21, and hand calculation methods to quantify the risk. The model was modified to include additional breakers and switching options, and to provide credit for recovery of emergency diesel generators during transient sequences. Additionally, the analyst performed additional runs of the SPAR model to account for consequential loss of offsite power risks that were not modeled directly under the special initiator. The largest risk contributor (approximately 96 percent) was a loss of all feedwater to the steam generators, with a failure of once-through cooling. The result of the analysis was a conditional core damage probability of 2.8E-5; therefore, this finding was preliminarily determined to have substantial safety significance (Yellow). Refer to Attachment 3 for the Unit 2 at-power detailed risk evaluation.

This finding had a cross-cutting aspect in the area of human performance associated with field presence, because the licensee did not ensure adequate supervisory and management oversight of work activities, including contractors and supplemental personnel. Specifically, the licensee did not provide a sufficient level of oversight in that, the requirements in Procedure EN-MA-119, for design approval and load testing of the temporary hoisting assembly, were not followed [H.2].

Enforcement (Unit 1 and Unit 2). Title 10 of the Code of Federal Regulations (CFR)

Part 50, Appendix B, Criterion V, Instructions, Procedures and Drawings, states, in part, that activities affecting quality shall be prescribed by documented instructions, procedures, or drawings, of a type appropriate to the circumstances and shall be accomplished in accordance with these instructions, procedures, or drawings. Quality Procedure EN-MA-119, Material Handling Program, Section 5.2[7], Temporary Hoisting Assemblies, Step

(a) states, in part, that vendor supplied temporary overhead cranes or supports, winch-driven hoisting or swing equipment, and other assemblies are required to be designed or approved by engineering support personnel. The design is required to be supported by detailed drawings, specifications, evaluations, and/or certifications. Quality Procedure EN-MA-119, Material Handling Program, Section 5.2[7] Temporary Hoisting Assemblies, Step

(b) states, in part, that the assembly shall be designed for at least 125 percent of the projected hook load and should be load tested and held for at least five minutes at 125 percent of the actual load rating before initial use. The assembly shall be load tested in all configurations for which it will be used.

Contrary to the above, on March 31, 2013, the licensee did not accomplish the stator lift and move, an activity affecting quality, as prescribed by documented instructions and procedures. Specifically:

a. The licensee approved a design for the temporary hoisting assembly that was not supported by detailed drawings, specifications, evaluations, and/or certifications. In addition, the temporary hoisting assembly was not adequately designed for at least 125 percent of the projected hook load. The licensee failed to identify the load deficiencies in vendor Calculation 27619-C1, Heavy Lift Gantry Calculation, and the incorrectly sized component in the north tower structure of the temporary hoisting assembly.

b. The licensee failed to perform a load test in all configurations for which the temporary hoisting assembly would be used.

As a result, on March 31, 2013, while lifting and transferring the main generator stator, the temporary overhead crane collapsed, causing the 525-ton stator to fall on and extensively damage portions of the plant.

For Unit 1:

The Unit 1 finding has been preliminary determined to be of high safety significance (Red) and will be treated as an apparent violation and tracked as AV 05000313/20130012-004; Unit 1 - Failure to Follow the Materials Handling Program during the Unit 1 Generator Stator Move.

For Unit 2:

The Unit 2 finding has been preliminary determined to be of substantial safety significance (Yellow) and will be treated as an apparent violation and tracked as AV 05000368/20130012-005; Unit 2 - Failure to Follow the Materials Handling Program during the Unit 1 Generator Stator Move.

.10 (Closed) URI 05000313/2013011-010, Causes and Corrective Actions Associated with

the Dropped Heavy Load Event

The Augmented Inspection Team identified an unresolved item associated with the licensees identified causes and planned corrective actions for the March 31, 2013, temporary crane failure. The root cause evaluation effort was still in progress at the conclusion of the inspection. The Augmented Inspection Team concluded additional follow-up inspection was necessary to assess the adequacy of the licensees identified causes and corrective actions when completed.

Observations and Findings

Condition Report CR-ANO-C-2013-00888, documented the root cause evaluation for the Unit 1 Main Turbine Generator Stator, drop that occurred on March 31, 2013. The licensee identified a total of two root causes and four contributing causes, with the two root causes and two of the four contributing causes being attributed to the contractor performance. The report was finalized on July 22, 2013.

The stator contractor, Siemens Energy, Inc. (Siemens), and their heavy lift subcontractor, Bigge Crane and Rigging Co. (Bigge), declined to participate on the root cause evaluation team. The root cause team concluded that, if it had full access to material, personnel, and records from the two vendors, the team might have identified additional contributing causes along with corrective actions. However, the root cause team did conclude that enough information was available to it and that information was sufficiently adequate to identify why the event occurred and to establish the associated corrective actions.

The root cause team evaluated a number of different areas, including: extent of condition, extent of cause, operating experience, safety culture, vendor oversight, and organizational and programmatic weakness. Actual nuclear safety and radiological safety were also evaluated. The licensee concluded that the event was mitigated by safety-related equipment and appropriate operator response. Control room operators, in both units, were able to respond and take necessary corrective actions to mitigate the effects of equipment damage from the stator drop. The structures, systems, and components for both units responded as designed with no significant challenge to nuclear or radiological safety.

The root causes were:

1. The root cause of the temporary lift assembly collapse was that the Bigge design

did not ensure the lift assembly north tower could support the loads anticipated for the lift.

2. Bigge failed to perform required load testing of the temporary lift assembly prior

to its use in accordance with OSHA regulation.

The four contributing causes were:

1. Siemens and Bigge inaccurately represented that the hoist assembly had been

used at other electric power stations to lift components that exceeded the anticipated weight of the Unit 1 stator.

2. Siemens failed to provide adequate oversight and control of Bigges

performance.

3. Procedure EN-MA-119 does not provide clear guidance regarding independent

reviews of special lift equipment.

4. Supplemental Project personnel lacked sufficient knowledge of OSHA and ASME

NQA-1 application to temporary lift assemblies and accepted Bigges assertion that load testing was not required based on a combination of engineering analysis and previous use.

The inspectors determined that the root causes did identify why the temporary hoisting assembly failed. The inspectors noted that contributing causes identified various inadequacies in procedures, oversight of the subcontractor by the primary contractor, and knowledge of applicable standards by supplemental personal. However, it was not clear to the inspectors that the root causes or contributing causes addressed the licensees oversight of contractors. The NRC conducted an independent review of the event, and as part of its review of Unresolved Item 2013011-009, Effectiveness of Material Handling Program, the NRC identified a cross-cutting aspect H.2, Field Presence, associated with the licensee not ensuring adequate supervisory and management oversight of work activities, including contractors and supplemental personnel.

The licensee implemented appropriate corrective actions to ensure the subsequent lift of the dropped stator and the Unit 1 replacement stator were performed safely considering lessons-learned from the root cause evaluation. Actions were implemented to ensure the safety of personnel and equipment during the lift of the replacement stator from the train bay to the generator pedestal.

No findings were identified.

4OA6 Meetings, Including Exit

Exit Meeting Summary

On February 10, 2014, the inspectors presented the inspection results to Mr. J. Browning, Site Vice President, and other members of the licensee staff. The licensee acknowledged the issues presented. Proprietary information was provided to the team and the information is being handled in accordance with NRC policies.

SUPPLEMENTAL INFORMATION

KEY POINTS OF CONTACT

Licensee Personnel

J. Browning, Site Vice President

J. McCoy, Engineering Director

D. Perkins, Maintenance Manager

L. Blocker, Nuclear Oversight Manager

D. James, Regulatory and Performance Improvement Director

S. Pyle, Regulatory Assurance Manager

N. Mosher, Licensing Specialist

C. ODell, Production Manager

R. Byford, Training Manager

B. Gordon, Projects and Maintenance Services Manager

T, Evans, Production General Manager

T. Sherrill, Chemistry Manager

R. Harris, Emergency Plan Manager

J. Tobin, Security Manager

P. Williams, Operations Manager

T. Chernivec, Performance Improvement Manager

B. Daibu, Design and Program Engineering Manager

NRC Personnel

K. Kennedy, Division Director (telephonically)

L. Willoughby, Senior Reactor Inspector

B. Latta, Senior Reactor Inspector

J. Melfi, Reactor Inspector

N. Okonkwo, Reactor Inspector

LIST OF ITEMS OPENED, CLOSED, AND DISCUSSED

Opened

05000313/2013012-

004 AV Unit 1 - Failure to Follow the Materials Handling Program during the Unit 1 Generator Stator Move

05000368/2013012-

005 AV Unit 2 - Failure to Follow the Materials Handling Program during the Unit 1 Generator Stator Move

Opened and Closed

05000313;368/

2013012-001 NCV Failure to Adequately Develop and Implement Adequate Procedural Controls to Remediate the Anticipated Effects of Internal Flooding for Either Unit

05000368/2013012-

2 FIN Main Feedwater Regulating Valve Maintenance Practices

Opened and Closed

05000313/2013012-

003 NCV Failure to Scope Required Components in the Stations Maintenance Rule Monitoring Program

Closed

05000313/2013011-

001 URI Control of Temporary Modification Associated with Temporary Fire Pump

05000313;368/

2013011-002 URI Damage to Unit 1 and Unit 2 Structures, Systems and Components

05000313/2013011-

003 URI Procedural Controls Associated with Unit 1 Steam Generator Nozzle Dams

05000368/2013011-

004 URI Main Feedwater Regulating Valve Maintenance Practices

05000313:368/

2013011-006 URI Compensatory Measures for Firewater System Rupture

05000368/2013011-

007 URI Timeliness of Emergency Action Level Determination

05000313/2013011-

008 URI Effectiveness of Shutdown Risk Management Program

05000313/2013011-

009 URI Effectiveness of Material Handling Program

05000313/2013011-

010 URI Causes and Corrective Actions Associated with the Dropped Heavy Load Event

Discussed

05000313/2013011-

005 URI Flood Barrier Effectiveness