IR 05000440/2013008

IR 05000440-13-008; 07/08/2013 - 09/17/2013; Perry Nuclear Power Plant; Evaluations of Changes, Tests, or Experiments and Permanent Plant Modifications

ML13276A131
Person / Time
Site:	Perry
Issue date:	10/03/2013
From:	Robert Daley Engineering Branch 3
To:	Harkness E FirstEnergy Nuclear Operating Co
Nestor Feliz Adorno
References
IR-13-008
Download: ML13276A131 (23)

Text

ctober 3, 2013

SUBJECT:

PERRY NUCLEAR POWER PLANT - EVALUATIONS OF CHANGES, TESTS, OR EXPERIMENTS AND PERMANENT PLANT MODIFICATIONS BASELINE INSPECTION REPORT 05000440/2013008

Dear Mr. Harkness:

On September 17, 2013, the U.S. Nuclear Regulatory Commission (NRC) completed an Evaluations of Changes, Tests, or Experiments and Permanent Plant Modifications Inspection at your Perry Nuclear Power Plant. The enclosed inspection report (IR) documents the inspection results, which were discussed on August 28 and September 17, 2013, with you and other members of your staff.

The inspection examined activities conducted under your license as they relate to safety and compliance with the Commissions rules and regulations and with the conditions of your license.

The inspectors reviewed selected procedures and records, observed activities, and interviewed personnel.

The NRC-identified two findings of very low safety significance involving violations of NRC requirements. One of the findings was associated with a traditional enforcement Severity Level IV violation. However, because of the very low safety significance and because the issues were entered into your Corrective Action Program, the NRC is treating the issues as Non-Cited Violations (NCVs) in accordance with Section 2.3.2 of the NRC Enforcement Policy.

If you contest the violations or significance of these NCVs, you should provide a response within 30 days of the date of this inspection report, with the basis for your denial, to the U.S. Nuclear Regulatory Commission, ATTN: Document Control Desk, Washington, DC 20555-0001; with a copy to the Regional Administrator, U.S. Nuclear Regulatory Commission - Region III, 2443 Warrenville Road, Suite 210, Lisle, IL 60532-4352; the Director, Office of Enforcement, U.S.

Nuclear Regulatory Commission, Washington, DC 20555-0001; and the Resident Inspector office at Perry Nuclear Power Plant. In addition, if you disagree with the cross-cutting aspect assigned to any finding 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 III, and the NRC Resident Inspector at Perry Nuclear Power Plant. In accordance with 10 CFR 2.390 of the NRC's "Rules of Practice," a copy of this letter, its enclosure, and your response (if any), will be available electronically for public inspection in the NRC Public Document Room or from the Publicly Available Records System (PARS)

component of 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/

Robert C. Daley, Chief Engineering Branch 3 Division of Reactor Safety Docket Nos. 50-440 License Nos. NPF-58

Enclosure:

Inspection Report 05000440/2013008 w/Attachment: Supplemental Information

REGION III==

Docket No: 50-440 License No: NPF-58 Report No: 05000440/2013008 Licensee: FirstEnergy Nuclear Operating Company (FENOC)

Facility: Perry Nuclear Power Plant, Unit 1 Location: Perry, Ohio Dates: July 8 through September 17, 2013 Inspectors: N. Féliz Adorno, Reactor Inspector (Lead)

J. Gilliam, Reactor Inspector I. Hafeez, Reactor Inspector Approved by: Robert C. Daley, Chief Engineering Branch 3 Division of Reactor Safety Enclosure

SUMMARY

IR 05000440/2013008; 07/08/2013 - 09/17/2013; Perry Nuclear Power Plant; Evaluations of

Changes, Tests, or Experiments and Permanent Plant Modifications.

This report covers a two-week announced baseline inspection on evaluations of changes, tests, or experiments and permanent plant modifications. The inspection was conducted by three Region III based engineering inspectors. Two findings of very low safety significance were identified by the inspectors. The findings were considered Non-Cited Violations (NCVs) of NRC requirements. One of the findings was associated with a traditional enforcement Severity Level IV violation. The significance of most findings is indicated by their color (Green, White,

Yellow, Red) using Inspection Manual Chapter (IMC) 0609, Significance Determination Process (SDP). Cross-cutting aspects were determined using IMC 0310, Components Within the Cross-Cutting Areas. Findings for which the SDP does not apply may be Green or be assigned a severity level after NRC management review. The NRCs program for overseeing the safe operation of commercial nuclear power reactors is described in NUREG-1649, Reactor Oversight Process, Revision 4, dated December 2006.

NRC-Identified

and Self-Revealed Findings

Cornerstone: Initiating Events

• Severity Level IV: The inspectors identified a finding of very low safety significance and associated Severity Level IV Non-Cited Violation of Title 10 Code of Federal Regulations (CFR) 50.59, Changes, Test, and Experiments, for the failure to perform a written evaluation, which provided the bases for the determination that a change did not require a license amendment. Specifically, the licensee failed to provide a basis for not applying for a license amendment associated with the use of a freeze seal in the reactor coolant pressure boundary when its integrity was required to protect irradiated fuel. The finding was entered into the licensees Corrective Action Program with recommended actions to, in part, revise the associated 10 CFR 50.59 documents.

The inspectors determined that the violation was more than minor because they could not reasonably determine the changes would not have ultimately required NRC prior approval. The finding affected the Initiating Events cornerstone attribute of equipment performance and affected the cornerstone objective to limit the likelihood of events that upset plant stability and challenge critical safety functions during shutdown, as well as power operations. The inspectors determined that the underlying technical issue was of very low safety significance (Green) using a Phase II evaluation. The inspectors did not identify a cross-cutting aspect associated with this finding because it was not confirmed to reflect current performance due to the age of the performance deficiency. (Section 1R17.1.b(1))

Cornerstone: Mitigating Systems

Green: The inspectors identified a finding of very low safety significance and associated Non-Cited Violation of 10 CFR Part 50, Appendix B, Criterion III, Design Control, for the failure to control drainage of the emergency core cooling system room sumps in a manner that prevents common mode flooding of these rooms. Specifically, procedures did not ensure appropriate controls to prevent backflow from the floor drain system. The licensee entered the issue into their Corrective Action Program and revised procedures to prevent opening more than one emergency core cooling system room sump isolation valve at the same time.

The performance deficiency was determined to be more than minor because it was associated with the Mitigating Systems cornerstone attribute of protection against external factors and affected the cornerstone objective of ensuring the availability, reliability, and capability of the emergency core cooling system to respond to initiating events to prevent undesirable consequences. The finding was determined to be of very low safety significance (Green) because it did not result in either the loss of operability or an actual loss or degradation of a function designed to mitigate flooding. Specifically, a review of recent plant history did not find an instance where the configuration of the floor drain system allowed common mode flooding of the emergency core cooling system rooms when operability of this system was required. The inspectors determined that this finding had a cross-cutting aspect in the area of problem identification and resolution because the licensee did not conduct a self-assessment of sufficient depth. Specifically, the licensee evaluated a flooding incident during a self-assessment conducted in 2013 and failed to thoroughly evaluate the cause that resulted in common mode flooding of the rooms. P.3(a) (Section 4OA2.1.b(1))

Licensee-Identified Violations

No violations were identified.

REPORT DETAILS

1R17 Evaluations of Changes, Tests, or Experiments and Permanent Plant Modifications

.1 Evaluation of Changes, Tests, or Experiments

a. Inspection Scope

The inspectors reviewed four safety evaluations performed pursuant to Title 10, Code of Federal Regulations (CFR) 50.59 to determine whether the evaluations were adequate and prior NRC-approval was obtained as appropriate. The minimum sample size of six safety evaluations were not achieved, because the licensee had only performed four safety evaluations during the sample period. The inspectors also reviewed 11 screenings and two applicability determinations where licensee personnel had determined that a 10 CFR 50.59 evaluation was not necessary. The inspectors reviewed these documents to determine if:

• the changes, tests, or experiments performed were evaluated in accordance with 10 CFR 50.59 and that sufficient documentation existed to confirm that a license amendment was not required;

• the safety issue requiring the change, tests or experiment was resolved;

• the licensee conclusions for evaluations of changes, tests, or experiments were correct and consistent with 10 CFR 50.59; and

• the design and licensing basis documentation was updated to reflect the change.

The inspectors used, in part, Nuclear Energy Institute (NEI) 96-07, Guidelines for 10 CFR 50.59 Implementation, Revision 1, to determine acceptability of the completed evaluations, and screenings. The NEI document was endorsed by the NRC in Regulatory Guide 1.187, Guidance for Implementation of 10 CFR 50.59, Changes, Tests, and Experiments, dated November 2000. The inspectors also consulted Part 9900 of the NRC Inspection Manual, 10 CFR Guidance for 10 CFR 50.59, Changes, Tests, and Experiments.

This inspection constituted four samples of evaluations and 13 samples of screenings and/or applicability determinations as defined in Inspection Procedure (IP) 71111.17-04.

b. Findings

(1) 10 CFR 50.59 Evaluation Did Not Consider the Freeze Seal Effect to the Reactor Coolant Pressure Boundary (RCPB)

Introduction:

The inspectors identified a Severity Level IV, Non-Cited Violation of 10 CFR 50.59, Changes, Tests, and Experiments, and an associated finding of very low safety significance (Green) for the licensees failure to perform a written evaluation, which provided the bases for the determination whether a change did not require a license amendment. Specifically, the licensee failed to provide a basis for not applying for a license amendment associated with adding a freeze seal to the RCPB at a time where RCPB integrity was required.

Description:

In 2001, the licensee performed Safety Evaluation (SE) 97-0079, Installation of Piping Freeze Seal for SVI G33-T9131, to evaluate permanently allowing the use of a freeze seal when performing surveillance instruction SVI-G33-T9131, Type C Local Leak Rate Test of 1G33 Penetration P131. This surveillance instruction (SVI) fulfilled the Technical Specification (TS) Surveillance Requirement (SR) 3.6.1.1.1 and SR 3.6.1.3.9 for reactor water cleanup system (RWCU) penetration P131. The conclusion of SE 97-0079 was that the use of a freeze seal during this SVI was acceptable because the RCPB would be isolated by the closure of valves 1-G33-F0101, F0102, F0103, F0106, and F0100. The freeze seal location was outside this boundary.

In 2009, the licensee performed Evaluation 09-01526, Type C Local Leak Rate Test of 1G33 Penetration P131, to evaluate a revision of SVI-G33-T9131 that allowed valve 1-G33-F0101 to remain open. As a result, the freeze seal location was changed to be within the RCPB. The licensee concluded this change was acceptable because an operator would be dedicated to manually close the 1-G33-F0101 valve if the freeze seal resulted in a pipe rupture and, if the valve could not be closed, then the pipe would be crimped. This SVI revision was used on March 24-25, 2009, without irradiated fuel in the upper pool or the reactor vessel, and on April 13-14, 2009, with irradiated fuel in the reactor vessel.

In 2013, the licensee revised Evaluation 09-01526 to limit the performance of SVI-G33-T9131 to MODE 5 with fuel removed from the reactor vessel in order to prevent Operations with Potential to Drain the Reactor Vessel (OPDRV). The evaluation assumed the irradiated fuel would be stored in the upper containment pool fuel racks.

The SVI was also updated to allow the use of a thaxton plug and repair clamp as a contingency if a pipe break occurs while using a freeze seal with the reactor core fully offloaded. This SVI revision was used on April 11-12, 2013, with irradiated fuel in the upper pool.

Updated Safety Analysis Report (USAR) Section 3.1.2.2.5.1, Evaluation Against Criterion 14, stated that, In order to minimize the possibility of brittle fracture within the RCPB, the fracture toughness properties and the operating temperature of ferritic materials are controlled to ensure adequate toughness. In addition, USAR 3.1.2.4.2, Compliance with General Design Criteria 31 - Fracture Prevention of Reactor Coolant Pressure Boundary, stated that, The RCPB is designed, maintained, and tested such that adequate assurance is provided that the boundary will behave in a non-brittle manner throughout the life of the plant. The inspectors were concerned because ferritic steel breaks in a brittle rather than a ductile manner below certain temperature values.

The temperature limit for brittle behavior increases as a function of neutron exposure.

The installation of freeze seals in piping represents a risk of exposing piping to temperatures below this transition point. The inspectors also noted this phenomenon was recognized by procedure GMI-0024, Freeze Seals, in that it stated Frozen pipe is subject to brittle fracture. Thus, the use of a freeze seal within the RCPB was contrary to the USAR descriptions and Evaluation 09-01526 did not address whether using the freeze seal within the RCPB would more than minimally increase the likelihood of a malfunction of the RCPB. In addition, the inspectors noted valve 1-G33-F0101, which was credited to be manually closed in case of RCPB failure, had not been exercised since as early as 2001. The inspectors were also concerned because the 2013 revision of Evaluation 09-01526 did not recognize the upper pool and steam dryer pool inventory would be affected if the RCPB at the freeze seal location were to rupture. Thus, performance of the SVI in this manner would be contrary to procedure IOI-009, Refueling, which stated Operations with a potential for draining the dryer storage pool shall not be performed when irradiated assemblies are seated in the upper containment pool fuel racks.

The licensee captured the inspectors concerns in the Corrective Actions Program (CAP)as CR-2013-11377, CR-2013-11217, and CR-2013-10798 with recommended actions to update SVI-G33-T9131 and associated 50.59 documents.

Analysis:

The inspectors determined that the failure to perform a written evaluation which provided the bases for the determination that a change did not require a license amendment was contrary to 10 CFR 50.59(d)(1) and was a performance deficiency.

Specifically, the licensee failed to provide a basis for not applying for a license amendment associated with increasing the likelihood of RCPB failure due to subjecting it to brittle fracture. The performance deficiency was determined to be more than minor because it was associated with the Initiating Events cornerstone attribute of equipment performance and affected the cornerstone objective to limit the likelihood of events that upset plant stability and challenge critical safety functions during shutdown as well as power operations. Specifically, the RCPB was exposed to brittle fracture under conditions where RCPB integrity was required to protect irradiated fuel. In addition, the associated violation was determined to be more than minor because the inspectors could not reasonably determine the addition of the freeze seal to the RCPB would not have ultimately required NRC prior approval.

Violations of 10 CFR 50.59 are dispositioned using the traditional enforcement process instead of the significance determination process (SDP) because they are considered to be violations that potentially impede or impact the regulatory process. This violation is associated with a finding that has been evaluated by the SDP and communicated with an SDP color reflective of the safety impact of the deficient licensee performance. The SDP, however, does not specifically consider the regulatory process impact. Thus, although related to a common regulatory concern, it is necessary to address the violation and finding using different processes to correctly reflect both the regulatory importance of the violation and the safety significance of the associated finding.

In this case, the inspectors determined the finding could be evaluated using the SDP in accordance with IMC 0609, Significance Determination Process, Attachment 0609.04, Initial Characterization of Findings, dated June 19, 2012. Because the finding was associated with shutdown conditions, the inspectors used IMC 0609, Appendix G, Shutdown Operations Significance Determination Process. The inspectors reviewed Table 1 of Appendix G, "Losses of Control," and determined that none of the conditions constituting a loss of control were met.

The Region III Senior Reactor Analyst (SRA) reviewed Appendix G, Attachment 1, Phase I Operational Checklists for Both PWRs and BWRs. The applicable checklist was Checklist 7, "BWR Refueling Operation with RCS Level > 23'." The SRA determined that the Phase I criterion was met so the risk evaluation progressed to Phase II. The SRAs reviewed Appendix G, Attachment 3, Phase II Significance Determination Process Template for BWR during Shutdown, and determined the exposure time was less than three days. Specifically, the dates the freeze seals were installed April 11 - 12, 2013, and April 13 - 14, 2009. The SRA determined that a bounding risk evaluation could be performed addressing both exposure periods by assuming the more risk significant 2009 configuration. Considering the short exposure time and available mitigation features, the result was an estimated change in core damage frequency (CDF) of 6.2E-07/year. Thus, the finding was of very low safety significance (Green).

In accordance with Section 6.1.d of the NRC Enforcement Policy this violation is categorized as Severity Level IV because the resulting changes were evaluated by the SDP as having very low safety significance (i.e., green finding).

The inspectors did not identify a cross-cutting aspect associated with this finding because the finding was not confirmed to reflect current performance due to the age of the performance deficiency. Specifically, the licensee should have evaluated the addition of the freeze seal to the RCPB in 2009 when they revised SVI-G33-T9131.

Enforcement:

Title 10 CFR 50.59, Changes, Tests, and Experiments, Section (d)(1)requires, in part, the licensee to maintain records of changes in the facility, of changes in procedures, and of tests and experiments made pursuant 10 CFR 50.59(c). It also requires that these records must include a written evaluation which provides a basis for the determination that the change, test, or experiment does not require a license amendment pursuant to10 CFR 50.59(c)(2).

Contrary to the above, from April 2009 until August 28, 2013, the licensee did not provide a written evaluation, which provided the bases for determining that a change, test or experiment made pursuant to 10 CFR 50.59(c) did not require a license amendment. Specifically, the licensee made a change pursuant to 10 CFR 50.59(c) in that the licensee applied a freeze seal to the RCPB subjecting it to brittle fracture at a time where its integrity was required to protect irradiated fuel. The licensee did not provide a written evaluation providing a basis for determining that applying the freeze seal to the RCPB would not result in more than a minimal increase in the likelihood of occurrence of a malfunction of an SSC. At the time of this inspection period, the licensee was still evaluating its planned corrective actions. However, the inspectors determined that the continued non-compliance did not present an immediate safety concern because the SVI procedure was placed on hold until the concerns are resolved.

This violation is being treated as an NCV, consistent with Section 2.3.2 of the Enforcement Policy because it was Severity Level IV and was entered into the licensees corrective action program as CR-2013-10798, CR-2013-11217, and CR-2013-11377 (NCV 05000440/20132008-01, 10 CFR 50.59 Evaluation Did Not Consider the Freeze Seal Effect to the RCPB).

The associated finding was evaluated separately from the traditional enforcement violation; therefore, the underlying finding was assigned a separate tracking number (FIN 05000440/20132008-02, 10 CFR 50.59 Evaluation Did Not Consider the Freeze Seal Effect to the RCPB).

(2) Lack of Alternate Methods of Decay Heat Removal

Introduction:

The inspectors identified an unresolved item (URI) regarding the unavailability of alternate methods of decay heat removal that could be credited to combat a loss of shutdown cooling resulting from emergency service water (ESW)inoperability and while in MODE 4 with high decay heat load.

Description:

On May 21, 2004, the A ESW pump became inoperable due to a failure of the uppermost shaft coupling. Technical Specification Limiting Condition for Operation (LCO) 3.7.1, ESW System - Divisions 1 and 2, required the licensee to restore operability within 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br />. Because this action could not be met, TS required the licensee to be in Mode 3 within 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> and Mode 4 within 36 hours4.166667e-4 days <br />0.01 hours <br />5.952381e-5 weeks <br />1.3698e-5 months <br />. While performing plant shutdown, LCO 3.4.10, Residual Heat Removal (RHR) Shutdown Cooling System - Cold Shutdown, became applicable. It required, in part, two shutdown cooling subsystems operable in MODE 4 when heat losses to the ambient were not sufficient to maintain average reactor coolant temperature below 200oF.

Because ESW is the heat sink of shutdown cooling, the A train of shutdown cooling was also inoperable. With one or two shutdown cooling subsystems inoperable, TS 3.4.10, Required Action A.1, required the licensee to verify an alternate method of decay heat removal was available for each inoperable shutdown cooling subsystem within one hour and once per 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> thereafter. The associated TS Basis described the alternate method as one that re-establishes backup decay heat removal capabilities similar to the requirements of the LCO. However, the licensee was unable to identify an alternate method of decay heat removal to satisfy TS 3.4.10, Required Action A.1. Moreover, during repairs on the ESW 'A' pump, the licensee concluded that sufficient doubt existed regarding the ESW 'B' pump; thus, they declared the pump inoperable. Consequently, the 'B' train of shutdown cooling also became inoperable requiring two alternate methods of decay heat removal available. This incident resulted in an NCV which was documented in IR 05000440/2004011 and Licensee Event Report (LER) 05000440/2004-001.

On October 19, 2009, the B ESW pump tripped off due to failure of the motor power supply cable. Again, the licensee was required to perform a plant shutdown by TS 3.7.1, declared the B shutdown cooling train inoperable when TS 3.4.10 became applicable, and was unable to verify an alternate method of decay heat removal within one hour to satisfy TS 3.4.10, Required Action A.1. This incident was captured in the CAP as CR 2009-66216 and resulted in LER 05000440/2009003.

Following these two incidents, the licensee installed the Alternate Decay Heat Removal (ADHR) system. During this inspection period, the inspectors reviewed the associated 10 CFR 50.59 evaluation (i.e., Evaluation 05-04712, Installation of ADHR System)which stated The intent of the ADHR system is to assure TS compliance in MODE 4 by providing an additional alternate decay heat removal option that does not rely upon RHR or ESW. However, the inspectors noted its design was limited to a heat removal rate which bounds the approximate decay heat production rate of the core 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> after a scram from sustained 100 percent power. During normal shutdown conditions, the licensee transitions from 100 percent power to MODE 4 in a few hours. For instance, this transition occurred in about five hours during refueling outage 1R13. In addition, the licensee revised procedure ONI-E12-2, Loss of Decay Heat Removal, by adding 11, Cold Shutdown Decay Heat Removal by Steaming. This attachment contained instructions to establish an alternate method of decay heat removal independent of ESW. However, the attachment included a note stating, It will be necessary to validate the effectiveness of this attachment to maintain or reduce RPV temperature (by Engineering calculation or demonstration) if qualifying this as an alternate decay heat removal method per TS 3.4.9 and 3.4.10. As a result, the inspectors questioned the effectiveness of this approach given it had not been verified. The licensee consequently, performed a calculation that determined Attachment 11 was limited to a heat removal rate which bounds the approximate decay heat production rate of the core three days after a shutdown from sustained 100 percent power. The procedure contained other alternatives but these either relied on ESW or lacked enough capacity to serve as backup methods during periods of high decay heat loads.

Based on this information, the inspectors were concerned the plant lacked two alternate methods of decay heat removal that have been verified to be effective should a loss of shutdown cooling result from ESW inoperability while in MODE 4 with high decay heat load. The inspectors were particularly concerned because this condition had occurred in the past at least twice. The licensee captured the inspectors concerns in their CAP as CR 2013-11480. This issue is unresolved pending further review and determination of NRC actions to resolve the issue (URI 05000440/2013008-03, Lack of Alternate Methods of Decay Heat Removal).

.2 Permanent Plant Modifications

a. Inspection Scope

The inspectors reviewed five permanent plant modifications that had been installed in the plant or modified during the last three years. This review included in-plant walkdowns for portions of the alternate decay heat removal system installed in the low pressure core spray room; station battery and battery charger rooms; and division 1 emergency diesel generator. The modifications were selected based upon risk significance, safety significance, and complexity. The inspectors reviewed the selected modifications to determine if:

• the supporting design and licensing basis documentation was updated;

• the changes were in accordance with the specified design requirements;

• the procedures and training plans affected by the modification have been adequately updated;

• the test documentation as required by the applicable test programs has been updated; and

• post-modification testing adequately verified system operability and/or functionality.

The inspectors also used applicable industry standards to evaluate acceptability of the modifications. The list of modifications and other documents reviewed by the inspectors is included as an Attachment to this report.

This inspection constituted five permanent plant modification samples as defined in IP 71111.17-04.

b. Findings

No findings were identified.

4OA2 Problem Identification and Resolution

.1 Routine Review of Condition Reports

a. Inspection Scope

The inspectors reviewed several corrective action process documents that identified or were related to 10 CFR 50.59 evaluations and permanent plant modifications. The inspectors reviewed these documents to evaluate the effectiveness of corrective actions related to permanent plant modifications and evaluations of changes, tests, or experiments. In addition, corrective action documents written on issues identified during the inspection were reviewed to verify adequate problem identification and incorporation of the problems into the corrective action system. The specific corrective action documents that were sampled and reviewed by the inspectors are listed in the to this report.

b. Findings

(1) Insufficient Controls to Prevent Common Mode Flooding of Emergency Core Cooling System (ECCS) Rooms

Introduction:

The inspectors identified a finding of very low safety significance (Green)and associated NCV of 10 CFR Part 50, Appendix B, Criterion III, Design Control, for the licensees failure to control drainage of the ECCS room sumps in a manner that prevents common mode flooding of the ECCS rooms. Specifically, the licensees procedures did not ensure appropriate controls to prevent backflow from the floor drain system, which was contrary to the licensees design basis.

Description:

On May 19, 2011, the licensee performed a test of the RHR B/C water leg pump while in MODE 5 following its replacement. During this test, the operators received an unexpected Auxiliary Building floor drain sump water level high alarm.

Approximately four minutes later, the operators received sump high level alarms associated with the RHR A, B, and C, and reactor core isolation cooling (RCIC) pump rooms. The test was stopped and all drain paths to the Auxiliary Building sumps were closed. This incident resulted in water accumulation in each one of these rooms and an entry into Emergency Operating Procedure - 3, Secondary Containment Control and Radioactive Release Control, for about an hour. This condition was captured in the CAP as CR 2011-95107.

In preparation for this inspection, the licensee performed Self-Assessment FO-SA-2012-0031 that evaluated CR 2011-95107 relative to its completeness. After this review, the licensee initiated CR 2013-10119 on July 1, 2013, to document the missed opportunity to evaluate the potential flooding impact from this incident. Specifically, the licensee identified that CR 2011-95107 did not specify the water depth in the affected rooms and did not address the potential flooding impact to plant systems. The licensee subsequently concluded that the maximum amount of water was within the design flood level.

While reviewing a sample of corrective action process documents that identified or were related to plant modifications, the inspectors noted CR 2011-95107 and CR 2013-10119 did not address the cause of the common mode flooding of the ECCS rooms via the floor drain system. The inspectors were concerned because common mode flooding of these rooms was contrary to the design basis of the plant. Specifically, USAR 9.3.3.2.1, Floor Drains, stated common mode flooding of the ECCS equipment rooms (i.e., flooding in one room which results in flooding of redundant ECCS equipment in adjacent rooms)is precluded by the design of the drainage piping. In addition, USAR 9.3.3.3, Safety Evaluation, stated Flooding of the ECCS rooms by backflow through the floor drains from a rupture of non-seismic designed fluid lines is prevented by the installation of a normally closed shutoff valve in the floor drain line from each of the six compartments.

The shutoff valve for each compartment was controlled by Procedure SOI-G61, Liquid Radwaste Sumps. However, the inspectors noted the following procedure deficiencies:

• The procedure allowed multiple ECCS room sump isolation valves to be open at the same time. This configuration did not prevent common mode flooding by backflow through the floor drains.

• The compensatory actions to prevent or mitigate common mode flooding were only required by the procedure when a valve was open and the associated ECCS system was not isolated. This prerequisite considered ECCS as the only potential flood source. That is, it did not consider a rupture of other fluid lines located in these rooms.

• The required compensatory actions were inadequate to prevent or mitigate common mode flooding. Specifically, one of the procedure options was to establish a 1-hour flood watch. However, the inspectors noted backflow to multiple ECCS rooms occurred in a few minutes during the 2011 incident.

The licensee captured the inspectors concerns in their CAP as CR 2013-10825. The corrective actions were, in part, to revise SOI-G61 to prevent opening more than one ECCS room sump isolation valve at the same time.

Analysis:

The inspectors determined that the failure to control drainage of the ECCS sumps in a manner that prevents common mode flooding of the ECCS rooms was contrary to 10 CFR Part 50, Appendix B, Criterion III, Design Control, and was a performance deficiency. The performance deficiency was determined to be more than minor because it was associated with the Mitigating Systems cornerstone attribute of protection against external factors and affected the cornerstone objective of ensuring the availability, reliability, and capability of the ECCS to respond to initiating events to prevent undesirable consequences. Specifically, procedure SOI-G61 did not ensure the availability of ECCS because it contained insufficient instructions to prevent common mode flooding of ECCS rooms by backflow through the floor drains.

In accordance with IMC 0609, Significance Determination Process, Attachment 0609.04, Initial Characterization of Findings, Table 2 the inspectors determined the finding affected the Mitigating Systems cornerstone. As a result, the inspectors determined the finding could be evaluated using Appendix A, The Significance Determination Process (SDP) for Findings At-Power, Exhibit 2, Mitigating Systems Screening Questions. The inspectors determined that the finding was of very low safety significance (Green) because it did not result in the loss of operability nor an actual loss or degradation of a function designed to mitigate flooding. Specifically, a review of recent plant history did not find an instance where the configuration of the floor drain system allowed common mode flooding of the ECCS rooms when operability of these systems was required.

The inspectors determined that this finding had a cross-cutting aspect in the area of problem identification and resolution, self and independent assessments because the licensee did not conduct a self-assessment of sufficient depth. Specifically, the licensee evaluated the problem captured in CR 2011-95107 during a self-assessment, but failed to thoroughly evaluate the causes that permitted multiple ECCS rooms to become flooded. P.3(a)

Enforcement:

Title 10 CFR Part 50, Appendix B, Criterion III, Design Control, requires, in part, that measures shall be established to assure that applicable regulatory requirements and the design basis are correctly translated into specifications, drawings, procedures, and instructions. Section 9.3.3.2.1 of the USAR states that common mode flooding of the ECCS rooms is precluded by the design of the drainage piping.

Section 9.3.3.3 of the USAR states flooding of the ECCS rooms by backflow through the floor drains was prevented by the installation of a normally closed shutoff valve in the floor drain line from each room.

Contrary to the above, from May 19, 2011, to July 16, 2013, the licensee failed to translate the applicable design basis into procedures. Specifically, the licensee did not translate the common mode flooding prevention controls described in the USAR into procedure SOI-G61. As an immediate corrective action, the licensee revised SOI-G61 to prevent opening more than one ECCS room sump valve at the same time. Because this violation was of very low safety significance and was entered into the licensees CAP as CR 2013-10825, this violation is being treated as a Non-Cited Violation, consistent with Section 2.3.2 of the NRC Enforcement Policy (NCV 05000440/2013008-04, Insufficient Controls to Prevent Common Mode Flooding of ECCS Rooms).

4OA6 Meetings

.2 Interim Meeting Summary

On July 26 and August 28, 2013, the inspectors presented the preliminary inspection results to Mr. D. Hamilton and other members of the licensee staff. The licensee acknowledged the issues presented. The inspectors confirmed that none of the potential report input discussed was considered proprietary. The inspectors had outstanding questions that required additional review and a follow-up exit meeting.

.1 Exit Meeting Summary

On September 17, 2013, the inspectors presented the inspection results to Mr. B. Huck and other members of the licensee staff. The licensee personnel acknowledged the inspection results presented and did not identify any proprietary content. The inspectors confirmed that none of the potential report input discussed was considered proprietary.

ATTACHMENT:

SUPPLEMENTAL INFORMATION

KEY POINTS OF CONTACT

Licensee

V. Kaminskas, Site Vice President

D. Hamilton, Plant General Manager

H. Hanson, Performance Improvement Director

T. Veitch, Regulatory Compliance Manager

J. Tufts, Operations Manager

B. Huck, Design Manager

B. Coad, Engineering Analysis Supervisor

Nuclear Regulatory Commission

R. Daley, Chief, Engineering Branch 3, DRS

M. Marshfield, Senior Resident Inspector

LIST OF ITEMS

OPENED AND CLOSED

Opened

05000440/2013008-01 NCV 10 CFR 50.59 Evaluation Did Not Consider the Freeze Seal Effect to the RCPB (Section 1R17.1.b(1))

05000440/2013008-02 FIN 10 CFR 50.59 Evaluation Did Not Consider the Freeze Seal Effect to the RCPB (Section 1R17.1.b(1))

05000440/2013008-03 URI Lack of Alternate Methods of Decay Heat Removal (Section 1R17.1.b(2))

05000440/2013008-04 NCV Insufficient Controls to Prevent Common Mode Flooding of ECCS Rooms (Section 4OA2.1.b(1))

Closed

05000440/2013008-01 NCV 10 CFR 50.59 Evaluation Did Not Consider the Freeze Seal Effect to the RCPB (Section 1R17.1.b(1))

05000440/2013008-02 FIN 10 CFR 50.59 Evaluation Did Not Consider the Freeze Seal Effect to the RCPB (Section 1R17.1.b(1))

05000440/2013008-04 NCV Insufficient Controls to Prevent Common Mode Flooding of ECCS Rooms (Section 4OA2.1.b(1))

Attachment