IR 05000387/2013004

IR 05000387-13-004 & 05000388-13-004, 07/01/2013 - 09/30/2013; Susquehanna Steam Electric Station, Units 1 and 2; Licensed Operator Requalification Program, Maintenance Risk Assessment and Emergent Work Control, Problem Identification and R

ML13318A960
Person / Time
Site:	Susquehanna
Issue date:	11/14/2013
From:	Fred Bower Reactor Projects Region 1 Branch 4
To:	Rausch T Susquehanna
BOWER, FL
References
IR-13-004
Download: ML13318A960 (37)

Text

UNITED STATES NUCLEAR REGULATORY COMMISSION ber 14, 2013

SUBJECT:

SUSQUEHANNA STEAM ELECTRIC STATION - NRC INTEGRATED INSPECTION REPORT 05000387/2013004 AND 05000388/2013004

Dear Mr. Rausch:

On September 30, 2013 the U. S. Nuclear Regulatory Commission (NRC) completed an inspection at your Susquehanna Steam Electric Station (SSES) Units 1 and 2. The enclosed integrated inspection report documents the inspection results, which were discussed on October 10, 2013, with Mr. Jeffrey Helsel, Plant Manager, and other members of your staff.

This 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.

This report documents three NRC-identified and one self-revealing finding of very low safety significance (Green). All of these findings were determined to involve violations of NRC requirements. However, because of the very low safety significance and because they are entered into your corrective action program (CAP), the NRC is treating these findings as non-cited violations (NCVs) consistent with Section 2.3.2 of the NRCs Enforcement Policy. If you contest any NCV in this report, you should provide a response within 30 days of the date of this inspection report, with the basis for your denial, to the Nuclear Regulatory Commission, ATTN.:

Document Control Desk, Washington, D.C. 20555-0001; with copies to the Regional Administrator Region I; the Director, Office of Enforcement, United States Nuclear Regulatory Commission, Washington, D.C. 20555-0001; and the NRC Senior Resident Inspector at the SSES. In addition, if you disagree with the cross-cutting aspect of 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 I, and the NRC Senior Resident Inspector at the SSES. In accordance with the Code of Federal Regulations (10 CFR) 2.390 of the NRCs "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 (PARS) component of the NRCs Agencywide Documents Access 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/

Fred L. Bower, III, Chief Reactor Projects Branch 4 Division of Reactor Projects Docket Nos. 50-387; 50-388 License Nos. NPF-14, NPF-22

Enclosures:

Inspection Report 05000387/2013004 and 05000388/2013004 w/Attachment: Supplemental Information

REGION I==

Docket No: 50-387, 50-388 License No: NPF-14, NPF-22 Report No: 05000387/2013004 and 05000388/2013004 Licensee: PPL Susquehanna, LLC (PPL)

Facility: Susquehanna Steam Electric Station, Units 1 and 2 Location: Berwick, Pennsylvania Dates: July 1, 2013 through September 30, 2013 Inspectors: J. Greives, Senior Resident Inspector P. Finney, Senior Resident Inspector, Salem A. Turilin, Resident Inspector S. Kennedy, Senior Resident Inspector, Calvert Cliffs K. Mangan, Senior Reactor Inspector J. Laughlin, Emergency Preparedness Inspector, NSIR E. Burket, Emergency Preparedness Inspector Approved By: Fred L. Bower, Chief Reactor Projects Branch 4 Division of Reactor Projects Enclosure

SUMMARY OF FINDINGS

IR 05000387/2013004 05000388/2013004 07/01/2013 - 09/30/2013; Susquehanna Steam

Electric Station, Units 1 and 2; Licensed Operator Requalification Program, Maintenance Risk Assessment and Emergent Work Control, Problem Identification and Resolution, Follow-up of Events and Notices of Enforcement Discretion.

The report covered a three-month period of inspection by resident inspectors and announced inspections performed by regional inspectors. Inspectors identified four non-cited violations (NCVs). The significance of most findings is indicated by their color (Green, White, Yellow,

Red) using Inspection Manual Chapter (IMC) 0609, Significance Determination Process(SDP),

dated June 2, 2011. The cross-cutting aspects for the findings were determined using IMC 0310, Components Within The Cross-Cutting Areas, dated October 28, 2011. Findings for which the SDP does not apply may be Green, or be assigned a severity level after Nuclear Regulatory Commission (NRC) management review. All violations of NRC requirements are dispositioned in accordance with NRCs Enforcement Policy, dated June 7, 2012. The NRCs program for overseeing the safe operation of commercial nuclear power reactors is described in NUREG-1649, Reactor Oversight Process (ROP), Revision 4, dated December 2006.

Cornerstone: Mitigating Systems

Green.

The inspectors identified a Green NCV of 10 CFR 50.65(a)(4) because PPL did not adequately assess the risk of performing maintenance in accordance with station procedures. Specifically, PPL did not specify appropriate risk management actions (RMAs)while performing a standby liquid control (SLC) system flow surveillance in conjunction with having the E emergency diesel generator (EDG) unavailable. PPLs immediate corrective actions included entering the issue into their CAP as condition reports (CRs) 1721928 and 1781929, communicating the issue to applicable station personnel, and revising the risk assessment for use in future performance of the maintenance activities.

The performance deficiency is more than minor because it affected the Human Performance attribute of the Mitigating Systems cornerstone objective to ensure the availability of systems that respond to initiating events to prevent undesirable consequences (i.e., core damage).

The item is similar to example 7.e. in NRC IMC 0612 Appendix E, Examples of Minor Issues. This example states, in part, that failure to perform an adequate risk assessment when required by 10 CFR 50.65 (a)(4) is not minor if the overall elevated plant risk would require, under plant procedures, RMAs or additional RMAs. In this case, the SLC flow surveillance was required to be screened as high operational risk due to the short duration limiting condition of operation (LCO) entry and medium or high operational risk due to changing risk to Yellow when performed in conjunction with the E EDG unavailability.

Both of these categories required additional RMAs in accordance with station procedures.

In accordance with IMC 0609.04, Initial Characterization of Findings, and IMC 0609,

Appendix K, Maintenance Risk Assessment and Risk Management Significance Determination Process, the inspectors determined that this finding is of very low safety significance (Green) because the performance deficiency was associated with RMAs only and the incremental core damage probability was < 1E-6 and the incremental large early release probability was < 1E-7. This finding was determined to have a cross-cutting aspect in the area of Human Performance, Work Control in that PPL failed to appropriately plan work activities by not incorporating risk insights. Specifically, PPL did not appropriately assess the risk of performing maintenance activities by including required risk manage actions as specified in station procedures. H.3(a). (Section 1R13)

Green.

The inspectors identified a Green NCV of TS 5.4.1, Procedures, because PPLs emergency operating procedure step for terminating injection sources during a rapid depressurization required for an anticipated transient without scram (ATWS) was inadequate to ensure that cold unborated water was not injected into the core. Specifically,

PPLs emergency operating procedure (EOP) does not terminate injection from the high pressure coolant injection (HPCI) system during the transient and procedural guidance is insufficient to ensure that operators will maintain level in the prescribed ATWS band while injecting with HPCI. In addition to entering the issue into the CAP as CRs 1708885 and 1745775, PPLs immediate corrective actions included issuance of Operations Directive 13-02 which states that HPCI must be controlled, up to and including overriding injection, to ensure that reactor pressure vessel water level is maintained in the prescribed ATWS band during the duration of the rapid depressurization. Planned corrective actions include requiring termination of HPCI injection prior to initiation of a rapid depressurization (Action Request 1719605).

The performance deficiency is more than minor because it was associated with the procedure quality attribute of the Mitigating Systems cornerstone and affected the objective to ensure the availability, reliability and capability of systems that respond to initiating events to prevent undesirable consequences (i.e., core damage). Specifically, the inadequate procedure for terminating injection prior to rapidly depressurizing the reactor during an ATWS could have resulted in operators failing to control level in the prescribed EOP band, potentially resulting in cold unborated water being injected into the core. In accordance with IMC 0609.04, Initial Characterization of Findings, and Exhibit 2 of IMC 0609, Appendix A,

The Significance Determination Process for Findings At-Power, the inspectors determined that this finding is of very low safety significance (Green) because the performance deficiency was not a design or qualification deficiency, did not involve an actual loss of safety function, did not represent actual loss of a safety function of a single train for greater than its Technical Specification (TS) allowed outage time, and did not screen as potentially risk-significant due to a seismic, flooding, or severe weather initiating event. The finding is related to the cross-cutting area of problem identification and resolution (PI&R), in that PPL did not identify a performance issue completely, accurately, and in a timely manner commensurate with the safety significance. Specifically, PPL failed to identify that guidance in EOP basis document was insufficient to ensure that operators maintained level in the EOP band. P.1(a). (Section 1R11)

Cornerstone: Barrier Integrity

Green.

The inspectors identified a green, self-revealing, non-cited NCV of 10 CFR 50 Appendix B, Criterion 5, Instructions, Procedures, and Drawings, which states, in part, that procedures shall include appropriate quantitative or qualitative acceptance criteria for determining that important activities have been satisfactorily accomplished. The inspectors determined that PPLs residual heat removal (RHR) shutdown cooling procedure failed to ensure that water properties (pressure and temperature) in the suction piping was controlled to ensure water hammer event would not happen when establishing a low pressure injection standby lineup. As a result, a water hammer occurred in the piping which caused the suction relief valve to fail open. PPLs immediate corrective actions included entering the issue into their CAP as CRs 1746612 and 1754913, replacing the relief valve, walking down the piping and associated supports and communicating to operations personnel to declare RHR inoperable when aligned to shutdown cooling (SDC) while reactor coolant temperature is above 200 degrees Fahrenheit.

This finding is more than minor because it is associated with the procedure quality attribute of the Barrier Integrity cornerstone and affected the cornerstone objective to provide reasonable assurance that physical design barriers (containment) protect the public from radionuclide releases caused by accidents or events. Specifically, the water hammer event resulted in a stuck open relief valve on the RHR suction piping whose leak rate exceeded the assumed leakage from engineered safeguard systems in PPLs post-event control room dose calculations. Because conditions for RHR system operation had been established, the team assessed this finding in accordance with the NRC Inspection Manual Chapter (IMC)0609, Significance Determination Process, Appendix G, Shutdown Operations Significance Determination Process, using Attachment 1, Checklist 5. The finding did not require a quantitative assessment because none of the checksheet guidelines requiring a phase 2 analysis were affected. Therefore, the finding was determined to be of very low safety significance (Green). The finding had a cross cutting aspect in the problem identification and resolution area associated with operating experience because PPL did not implement and institutionalize operating experience through changes to station processes, procedures, equipment, and training programs. Specifically, PPLs review of IN 2010-11 did not ensure the transition of RHR from SDC to LPCI standby was completed successfully by incorporating adequate steps into the operating procedure. P.2(b). (Section 4OA3)

Cornerstone: Emergency Preparedness

Green.

The inspectors identified a finding of very low safety significance (Green), and an associated NCV of 10 CFR 50.54(q) for failing to follow and maintain an emergency plan that meets the requirements of emergency planning standard 10 CFR 50.47(b)(4).

Specifically, the licensee failed to take timely corrective actions to restore a degraded room flooded alarm in accordance with station procedures. The alarm was out-of-service from December 21, 2012 until September 23, 2013 without adequate compensatory measures in place. PPLs immediate corrective actions included entering the issue into their CAP as CR 1745962, changing the priority of the work order (WO) and listing it as a priority item on their Daily Leadership Alignment Package. PPL replaced the detector on September 23, 2013.

The performance deficiency is more than minor because it was associated with the facilities and equipment attribute of the Emergency Preparedness cornerstone and affected the objective to ensure that the licensee is capable of implementing adequate measures to protect the health and safety of the public in the event of a radiological emergency.

Specifically, the performance deficiency would have resulted in untimely declaration of an Alert OA5 and Notice of Unusual Event (NOUE) OU5. In accordance with NRC IMC 0609,

Appendix B, Emergency Preparedness SDP, the inspectors determined that this finding is of very low safety significance (Green) because it did not result in the loss or degradation of a risk significant planning standard. Specifically, one Alert and one NOUE EAL initiating condition would have been rendered ineffective such that a flooding event would have been declared in a degraded manner. The finding is related to the cross-cutting area of PI&R,

CAP, in that PPL did not take appropriate corrective actions to address safety issues in a timely manner. Specifically, when the detector failed on December 21, 2012, adequate compensatory measures were not specified and the WO was not scheduled for completion for 12 months. P.1(d). (Section 4OA2)

REPORT DETAILS

Summary of Plant Status

Unit 1 began the inspection period at 100 percent power. On July 10, 2013, operators reduced power to approximately 96 percent to mitigate the unexpected closure of a main turbine control valve (CV). Following discussion with the main turbine vendor, operators conducted a further unplanned power reduction to 75 percent on July 16, 2013 due to maintain margin to high pressure turbine blade vibration limits. On July 20, 2013, operators reduced power to 15 percent and removed the main turbine from service to perform planned repairs on the main turbine CV. Operators returned the unit to 100 percent on July 24, 2013. On August 27, 2013, the A reactor feed pump turbine automatically tripped which resulted in a reactor recirculation pump runback and an automatic unplanned power reduction to 65 percent. Operators returned the unit to 100 percent power the following day. On September 12, 2013, operators reduced power to 65 percent for a planned rod sequence exchange, returning to 100 percent the same day. On September 17, 2013, operators reduced power to 85% to allow isolation of a main condenser water box for maintenance. Power was restored to 100 percent on September 19, 2013 and remained at or near 100 percent power for the remainder of the inspection period.

Unit 2 began the inspection period at 100 percent power. On July 5, 2013, an automatic reactor recirculation rundown occurred due to a condensate system perturbation, resulting in a power reduction to 96 percent. Operators restored power to 100 percent the same day. On July 6, 2013, operators reduced power to approximately 65 percent at the request of the grid operator.

Operators returned the unit to 100 percent on July 8, 2013. On July 27, 2013, operators again reduced power to 65 percent at the request of the grid operator. Operators restored power to 100 percent on July 28, 2013. On September 13, 2013, operators commenced a reactor shutdown to perform repairs to the low pressure turbines. On September 14, 2013, operators manually scrammed the reactor during the shutdown when an unexpected reactor water level transient occurred while transitioning the A reactor feed pump from flow control mode to discharge pressure mode. On September 15, 2013, operators received a flood alarm associated with the B RHR room and declared an Unusual Event. Operators terminated the event by isolating appropriate portions of the RHR system. Following the completion of the maintenance activities, operators commenced a reactor startup on September 22, 2013.

Operators returned the unit to 100 percent power on September 27, 2013, and remained at or near 100 percent power for the remainder of the inspection period.

REACTOR SAFETY

Cornerstones: Initiating Events, Mitigating Systems, and Barrier Integrity

1R04 Equipment Alignment

.1 Partial System Walkdowns

a. Inspection Scope

The inspectors performed partial walkdowns of the following systems:

Unit 2, Division II RHR Common, B EDG during A EDG unavailability Unit 2, Division II RHR in response to water hammer transient The inspectors selected these systems based on their risk-significance relative to the reactor safety cornerstones at the time they were inspected. The inspectors reviewed applicable operating procedures, system diagrams, the Updated Final Safety Analysis Report (UFSAR), TSs, WOs, condition reports (CRs), and the impact of ongoing work activities on redundant trains of equipment in order to identify conditions that could have impacted system performance of their intended safety functions. The inspectors also performed field walkdowns of accessible portions of the systems to verify system components and support equipment were aligned correctly and were operable. The inspectors examined the material condition of the components and observed operating parameters of equipment to verify that there were no deficiencies. The inspectors also reviewed whether PPL staff had properly identified equipment issues and entered them into the CAP for resolution with the appropriate significance characterization.

b. Findings

No findings were identified.

1R05 Fire Protection

.1 Resident Inspector Quarterly Walkdowns

a. Inspection Scope

The inspectors conducted tours of the areas listed below to assess the material condition and operational status of fire protection features. The inspectors verified that PPL controlled combustible materials and ignition sources in accordance with administrative procedures. The inspectors verified that fire protection and suppression equipment was available for use as specified in the area pre-fire plan, and passive fire barriers were maintained in good material condition. The inspectors also verified that station personnel implemented compensatory measures for out-of-service (OOS),degraded, or inoperable fire protection equipment, as applicable, in accordance with procedures.

Unit 2, B RHR pump room (Fire Zone 2-1E)

Unit 2, drywell (Fire Zone 1-4F)

Common, B EDG room (Fire Zone 0-41B)

Common, standby gas treatment (SBGT) (Fire Zones 0-30A and 0-29A through D)

Common, A, C, and D EDG Rooms (Fire Zones 0-41A, 0-41C and 0-41D)

b. Findings

No findings were identified.

1R06 Flood Protection Measures

.1 Annual Review of Cables Located in Underground Bunkers/Manholes

a. Inspection Scope

The inspectors conducted an inspection of underground bunkers/manholes subject to flooding that contain cables whose failure could disable risk-significant equipment. The inspectors performed walkdowns of risk-significant areas, including electrical vaults VA0002, VA009, and VA012 containing electrical equipment associated with the ultimate heat sink and the C EDG, to verify that the cables were not submerged in water, that cables appeared intact, and to observe the condition of cable support structures. When applicable, the inspectors verified proper sump pump operation and verified level alarm circuits were set in accordance with station procedures and calculations to ensure that the cables will not be submerged. The inspectors also ensured that drainage was provided and functioning properly in areas where dewatering devices were not installed.

b. Findings

No findings were identified.

1R11 Licensed Operator Requalification Program

.1 Quarterly Review of Licensed Operator Requalification Testing and Training

a. Inspection Scope

The inspectors observed licensed operator simulator training on September 5, 2013, which included a loss of a vital electrical bus, reactor scram with complications and unisolable steam leak outside of primary containment. The inspectors evaluated operator performance during the simulated event and verified completion of risk significant operator actions, including the use of abnormal and emergency operating procedures. The inspectors assessed the clarity and effectiveness of communications, implementation of actions in response to alarms and degrading plant conditions, and the oversight and direction provided by the control room supervisor. The inspectors verified the accuracy and timeliness of the emergency classification made by the shift manager and the TS action statements entered by the shift technical advisor. Additionally, the inspectors assessed the ability of the crew and training staff to identify and document crew performance problems.

b. Findings

Introduction.

The inspectors identified a Green NCV of TS 5.4.1, Procedures, because PPLs EOP step for terminating injection sources during a rapid depressurization required for an ATWS was inadequate to ensure that cold un-borated water was not injected into the core. Specifically, PPLs EOP does not terminate injection from the HPCI system during the transient, as recommended by the EOP guidelines, and EOP guidance is insufficient to ensure that operators will maintain level in the prescribed level band.

Description.

While observing level control actions during a manually initiated rapid depressurization in an evaluated simulator scenario, inspectors observed that operators allowed the HPCI system to continue to inject in automatic control which resulted in a vessel overfeed such that cold, un-borated water was injected into the core. PPL observers documented the issue in CR 1674650. As documented in the CR, observers concluded the crew followed procedural guidance when placing HPCI on minimum flow and in implementing EO-100-112 and EO-100-113. There were no adverse consequences as a result of the HPCI injection. Based on this statement, the station screened the CR to a mechanism outside of the CAP. Inspectors questioned the adequacy of actions taken and the adequacy of EO-1(2)00-113, Level/Power Control, Revision 10. Specifically, inspectors observed that RPV overfeed occurred as a result of the HPCI injection, which resulted in power oscillations. Subsequent to inspector follow-up, operators wrote CR 1681032 which stated that the previous CR was not accurate in that it did not identify that HPCI was maintained in automatic, as is described in the EOPs. This CR was closed with no action taken.

Inspectors reviewed the EOPs, their basis document and the plant specific technical guidelines. PPL took exception to the Boiling Water Reactor Owners Group Emergency Procedure Guidelines which recommend HPCI be terminated prior to initiating a rapid depressurization. PPL evaluated this deviation with NL-92-021, Safety Evaluation for EOPs Affected by the Deviation, Revision 0. The safety evaluation states, in part:

The proposed deviation to the Boiling Water Reactor Owners Group Emergency Procedure Guidelines is limited in scope to allowing HPCI to inject to the RPV as opposed to requiring HPCI.

The governing level control guidance from the Level/Power Control Guideline would remain in effect. HPCI injection flow could be terminated by the operator if it is not necessary to maintain level, but HPCI flow termination would not be required, under the proposed deviation.

The operator will use HPCI as needed to conform with the applicable level control guidance. When directed to perform the RPV depressurization, use of HPCI as permitted by the proposed deviation, would allow the operator to simply retain HPCI flow (at its pre-depressurization set point) throughout the depressurization transient.

Inspectors reviewed how this was translated into the EOPs. Step LQ/L-18 of EO-1(2)00-113 states Stop injection and prevent injection from FW, COND, LPCI and core spray.

The basis states that the intent of this step is to prevent uncontrolled injection of large amounts of cold water as RPV pressure decreases below the shutoff head of operating system pumps. With regard to use of HPCI, the bases state that injection from HPCI is permitted to avoid potential isolation and minimize the transient that may occur when RPV injection is restored. It also helps reduce RPV pressure by spraying cold water into the steam space. Continued operation of the RCIC and HPCI turbines aids in depressurizing the RPV and operation during RPV depressurization is not expected to result in significant injection flowrate variations due to the stability of the system flow controllers.

Based on observations during the simulator evaluation, inspectors questioned whether PPLs technical evaluation to support the deviation was appropriately translated into the EOP basis. PPL generated CR 1708885 to address the inspectors concern. To support this effort, additional simulator runs were performed to validate that operator performance would be consistent with technical evaluation of the deviation. Through this effort, PPL confirmed that maintaining HPCI injection in automatic throughout the transient would result in exceeding the EOP band. Following additional discussions, inspectors concluded that the EOPs did not provide sufficient guidance to ensure operators would control level in the EOP band of -161 to -60 inches during rapid depressurization. Specifically, operation of HPCI in automatic control as specified in the procedure and assumed in the safety evaluation resulted in RPV level exceeding -60 inches. With RPV level above -60 inches, the water from HPCI would not be pre-heated by steam in the downcomer and cold unborated water would be injected into the core.

PPL entered the issue into the CAP as CRs 1708885 and 1745775. PPL also issued Operations Directive 13-02 which states that HPCI must be controlled, up to and including overriding injection, to ensure that RPV water level is maintained in the prescribed ATWS band during the duration of the rapid depressurization. Planned corrective actions include requiring termination of HPCI injection prior to initiation of a rapid depressurization (AR 1719605).

Analysis.

The inspectors determined that PPLs failure to provide adequate procedural guidance to prevent cold unborated water from being injected into the core during an ATWS was a performance deficiency that was within PPLs ability to foresee and correct, and should have been prevented. The performance deficiency is more than minor because it was associated with the procedure quality attribute of the Mitigating Systems cornerstone and affected the objective to ensure the capability of systems that respond to initiating events to prevent undesirable consequences (i.e., core damage).

Specifically, the inadequate procedure for terminating injection prior to rapidly depressurizing the reactor during an ATWS resulted in failing to control level in the prescribed EOP band during observed simulator scenarios and additional simulator validation.

In accordance with IMC 0609.04, Initial Characterization of Findings, and Exhibit 2 of IMC 0609, Appendix A, The SDP for Findings At-Power, the inspectors determined that this finding is of very low safety significance (Green) because the performance deficiency was not a design or qualification deficiency, did not involve an actual loss of safety function, did not represent actual loss of a safety function of a single train for greater than its TS allowed outage time, and did not screen as potentially risk-significant due to a seismic, flooding, or severe weather initiating event.

The finding is related to the cross-cutting area of PI&R, CAP, in that PPL did not identify a performance issue completely, accurately, and in a timely manner commensurate with the safety significance P.1(a). Specifically, PPLs documentation of deficiencies identified during evaluated simulator scenarios was inadequate to identify that guidance in the EOP basis document was insufficient to ensure that operators maintained level in the ATWS band during the duration of a rapid depressurization.

Enforcement.

TS 5.4.1.a, Procedures, require in part, that written procedures shall be established covering the applicable procedures recommended in RG 1.33. RG 1.33, Appendix A, requires procedures for combating emergencies and other significant events. Contrary to the above, before August 27, 2013, PPLs EOP for combating ATWS event was inadequately established to ensure that RPV level was maintained in the prescribed ATWS band (-161 to -60 inches) to ensure cold unborated water from HPCI was not injected into the core. Specifically, the procedure was demonstrated as inadequate when they were followed as written during observed simulator scenarios and additional simulator validation. In addition to entering the issue into the CAP as CRs 1708885 and 1745775, PPLs immediate corrective actions included issuance of an Operations Directive 13-02 which states that HPCI must be controlled, up to and including overriding injection, to ensure that RPV water level is maintained in the prescribed ATWS band during the duration of the rapid depressurization. Because this violation was of very low safety significance (Green), and PPL entered this issue into their CAP, this violation is being treated as an NCV, consistent with Section 2.3.2 of the Enforcement Policy. (NCV 05000387;388/2013004-01, Inadequate Procedural Guidance for Maintaining RPV Level During Anticipated Transient Without Scram)

.2 Quarterly Review of Licensed Operator Performance in the Main Control Room

a. Inspection Scope

The inspectors observed reactor shutdown and cooldown for the Unit 2 maintenance outage on September 14. The inspectors observed pre-shift briefings and reactivity control briefings to verify that the briefings met the criteria specified in OP-AD-002, Standards for Shift Operations, Revision 45, OP-AD-004, Operations Standards for Error and Event Preparation, Revision 29 and OP-AD-338, Reactivity Manipulations Standards and Communication Requirements, Revision 20. Additionally, the inspectors observed crew performance to verify that procedure use, crew communications, and coordination of activities between work groups met established expectations and standards.

b. Findings

No findings were identified.

1R12 Maintenance Effectiveness

a. Inspection Scope

The inspectors reviewed the samples listed below to assess the effectiveness of maintenance activities on structures, systems, and components (SSC) performance and reliability. The inspectors reviewed system health reports, CAP documents, maintenance WOs, and maintenance rule basis documents to ensure that PPL was identifying and properly evaluating performance problems within the scope of the maintenance rule. For the first sample selected, the inspectors verified that the SSC was properly scoped into the maintenance rule in accordance with the Code of Federal Regulations (10 CFR) 50.65 and verified that the (a)(2) performance criteria established by PPL staff was reasonable. As applicable, for SSCs classified as (a)(1), the inspectors assessed the adequacy of goals and corrective actions to return these SSCs to (a)(2).

Additionally, the inspectors ensured that PPL staff was identifying and addressing common cause failures that occurred within and across maintenance rule system boundaries. For the second sample, inspectors reviewed PPLs periodic maintenance rule program assessment to ensure it met regulatory requirements.

Unit 2, RHR thermal relief valves Units 1 and 2, Review of 9th periodic maintenance rule (a)(3) assessment

b. Findings

No findings were identified.

1R13 Maintenance Risk Assessments and Emergent Work Control

a. Inspection Scope

The inspectors reviewed station evaluation and management of plant risk for the maintenance and emergent work activities listed below to verify that PPL performed the appropriate risk assessments prior to removing equipment for work. The inspectors selected these activities based on potential risk significance relative to the reactor safety cornerstones. As applicable for each activity, the inspectors verified that PPL personnel performed risk assessments as required by 10 CFR 50.65(a)(4) and that the assessments were accurate and complete. PPL performed emergent work, the inspectors verified that operations personnel promptly assessed and managed plant risk.

The inspectors reviewed the scope of maintenance work and discussed the results of the assessment with the stations probabilistic risk analyst to verify plant conditions were consistent with the risk assessment. The inspectors also reviewed the TS requirements and inspected portions of redundant safety systems, when applicable, to verify risk analysis assumptions were valid and applicable requirements were met.

Unit 1, yellow risk for standby liquid control (SLC) system testing in conjunction with emergent work on the B EDG Unit 1, unexpected closure of the #3 main turbine control valve (CV)

Unit 1, yellow risk during RHR system outage window Common, yellow risk during planned maintenance on the B EDG Common, yellow risk during planned maintenance on the B loop of emergency service water (ESW)

b. Findings

Introduction.

The inspectors identified a Green NCV of 10 CFR 50.65(a)(4) because PPL did not adequately assess the risk of performing maintenance in accordance with station procedures. Specifically, PPL did not specify appropriate RMAs while performing a SLC system flow surveillance in conjunction with having the E EDG unavailable.

Description.

10 CFR 50.65(a)(4) requires licensees to assess and manage the risk that may result from a proposed maintenance activity prior to performing the maintenance.

PPL implements this with NDAP-QA-1902, Integrated Risk Management, Revision 13, which states that its purpose is to provide administrative controls to assess and manage all aspects of nuclear safety risk associated with performance of work activities.

On July 2, 2013, inspectors reviewed the online risk assessments for maintenance being performed on Unit 1. PPL identified and communicated the online risk as Yellow due to a combination of performing surveillance on the SLC system in conjunction with the E EDG being out-of-service due to emergent maintenance on the B EDG. Inspectors reviewed the RMAs identified for the maintenance activities and determined that the station had not specified any additional RMAs beyond communicating the Yellow risk condition to the station. Specifically, inspectors reviewed the SLC surveillance risk screening and identified that it was screened as low risk. Inspectors reviewed NDAP-QA-1902 to determine if this was appropriate.

D specifies the RMAs that are applied as determined by the risk of the work activity. Each work activity is individually screened as low, medium or high risk in accordance with Attachment C by answering a series of questions. In particular, the SLC surveillance places the unit into a TS with an 8-hour shutdown action statement.

One of the questions included in Attachment C requires an activity to be screened as high risk if it places the unit in a TS shutdown action statement of less than 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.

Inspectors determined that, based on this question, the activity should have been screened as high risk and required 31 additional RMAs, which included a high risk challenge board, designated activity manager, and approval of the General Manager -

Operations to commence the activity.

Additionally, inspectors reviewed Attachment F of NDAP-QA-1902 which is used to screen the schedule to evaluate any aspects of risk not covered by the activity screening of Attachment C. Attachment F states:

Is there any concurrent risk significance activities scheduled that will cause core damage frequency to be Yellow?

If the answer is Yes, then reschedule the appropriate activity or manage the risk using RMAs as an operational medium or high risk activity.

Inspectors determined that PPL should have considered rescheduling the SLC flow surveillance until after the E EDG was returned to service or managed the increased risk by specifying additional RMAs in accordance with station procedures.

Ultimately, the inspectors determined that the risk assessment was inadequate because, if done correctly, it would have required additional RMAs in accordance with station procedures. PPLs immediate corrective actions included entering the issue into their CAP as CRs 1721928 and 1781929, communicating the issue to applicable station personnel, and revising the risk assessment for use in future performance of the maintenance activities.

Analysis.

The inspectors determined that PPLs inadequate assessment of the risk of performing maintenance activities, to include specifying appropriate RMAs, was a performance deficiency that was within PPLs ability to foresee and correct, and should have been prevented. The performance deficiency is more than minor because it affected the Human Performance attribute of the Mitigating Systems cornerstone objective to ensure the availability of systems that respond to initiating events to prevent undesirable consequences (i.e., core damage). The item is similar to example 7.e. in NRC IMC 0612 Appendix E, Examples of Minor Issues. This example states, in part, that failure to perform an adequate risk assessment when required by 10 CFR 50.65 (a)(4) is not minor if the overall elevated plant risk would require, under plant procedures, RMAs or additional RMAs. In this case, the SLC flow surveillance was required to be screened as high operational risk due to the short duration LCO entry and medium or high operational risk due to changing risk to Yellow when performed in conjunction with the E EDG unavailability. Both of these categories required additional RMAs in accordance with station procedures.

In accordance with IMC 0609.04, Initial Characterization of Findings, and IMC 0609, Appendix K, Maintenance Risk Assessment and Risk Management SDP, the inspectors determined that this finding is of very low safety significance (Green) because the performance deficiency was associated with RMAs only and the incremental core damage probability was < 1E-6 and the incremental large early release probability was <

1E-7.

This finding was determined to have a cross-cutting aspect in the area of Human Performance, Work Control in that PPL failed to appropriately plan work activities by not incorporating risk insights H.3(a). Specifically, PPL did not appropriately assess the risk of performing maintenance activities by including required RMAs as specified in station procedures.

Enforcement.

10 CFR 50.65 (a)(4) states, in part, before performing maintenance activities, a licensee shall assess and manage the increase in risk that may result from the proposed maintenance activity. Contrary to the above, on July 2, 2013, PPL did not adequately assess and manage the risk associated with performing SLC system flow surveillance in conjunction with having the E EDG unavailable for substitution.

Specifically, RMAs were not specified for an elevated risk condition in accordance with station procedures. PPLs immediate corrective actions included entering the issue into their CAP as CRs 1721928 and 1781929, communicating the issue to applicable station personnel, and revising the risk assessment for use in future performance of the maintenance activities. Because this violation was of very low safety significance (Green), and PPL entered this issue into their CAP, this violation is being treated as an NCV, consistent with Section 2.3.2 of the Enforcement Policy. (NCV 05000387/2013004-02, Failure to Assess and Manage Risk of Maintenance Activities for a SLC system flow surveillance )

1R15 Operability Determinations and Functionality Assessments

a. Inspection Scope

The inspectors reviewed operability determinations for the following degraded or non-conforming conditions:

Unit 1, grounds on 1D612 Unit 2, number 3 bypass valve (BPV) oscillations Unit 2, elevated drywell leakage Unit 2, high resistance in reactor protection system (RPS) trip relays Common, B EDG inoperability due to power spikes during monthly testing Common, D ESW pump failure during inservice test (IST)

The inspectors selected these issues based on the risk significance of the associated components and systems. The inspectors evaluated the technical adequacy of the operability determinations to assess whether TS operability was properly justified and the subject component or system remained available such that no unrecognized increase in risk occurred. The inspectors compared the operability and design criteria in the appropriate sections of the TSs and UFSAR to PPLs evaluations to determine whether the components or systems were operable. Where compensatory measures were required to maintain operability, the inspectors determined whether the measures in place would function as intended and were properly controlled by PPL. The inspectors determined, where appropriate, compliance with bounding limitations associated with the evaluations.

b. Findings

No findings were identified.

1R19 Post-Maintenance Testing

a. Inspection Scope

The inspectors reviewed the post-maintenance tests (PMTs) for the maintenance activities listed below to verify that procedures and test activities ensured system operability and functional capability. The inspectors reviewed the test procedure to verify that the procedure adequately tested the safety functions that may have been affected by the maintenance activity, that the acceptance criteria in the procedure was consistent with the information in the applicable licensing basis and/or design basis documents, and that the procedure had been properly reviewed and approved. The inspectors also witnessed the test or reviewed test data to verify that the test results adequately demonstrated restoration of the affected safety functions.

Unit 1, Division I RHR system outage window Unit 2, number 3 BPV repair and servo replacement Unit 2, B RHR heat exchanger BPV motor operator repair Common, D EDG governor repairs after inability to reach 110 percent loading Common, B ESW pump replacement Common, E EDG five year periodic overhaul

b. Findings

No findings were identified.

1R20 Refueling and Other Outage Activities

Unit 2 Maintenance Outage

a. Inspection Scope

The inspectors reviewed the stations work schedule and outage risk plan for the Unit 2 maintenance outage, which was conducted September 13 through September 22, 2013.

The inspectors reviewed PPLs development and implementation of outage plans and schedules to verify that risk, industry experience, previous site-specific problems, and defense-in-depth were considered. During the outage, the inspectors observed portions of the shutdown and cooldown processes and monitored controls associated with the following outage activities:

Configuration management, including maintenance of defense-in-depth, commensurate with the outage plan for the key safety functions and compliance with the applicable TSs when taking equipment OOS Implementation of clearance activities and confirmation that tags were properly hung and that equipment was appropriately configured to safely support the associated work or testing Installation and configuration of reactor coolant pressure, level, and temperature instruments to provide accurate indication and instrument error accounting Status and configuration of electrical systems and switchyard activities to ensure that TSs were met Monitoring of decay heat removal operations Reactor water inventory controls, including flow paths, configurations, alternative means for inventory additions, and controls to prevent inventory loss Activities that could affect reactivity Maintenance of secondary containment as required by TSs Tracking of startup prerequisites, walkdown of the drywell to verify that debris had not been left which could block the emergency core cooling system suction strainers, and startup and ascension to full power operation Identification and resolution of problems related to outage activities

b. Findings

No findings were identified.

1R22 Surveillance Testing

a. Inspection Scope

The inspectors observed performance of surveillance tests and/or reviewed test data of selected risk-significant SSCs to assess whether test results TSs, the UFSAR, and PPL procedure requirements. The inspectors verified that test acceptance criteria were clear, tests demonstrated operational readiness and were consistent with design documentation, test instrumentation had current calibrations and the range and accuracy for the application, tests were performed as written, and applicable test prerequisites were satisfied. Upon test completion, the inspectors considered whether the test results supported that equipment was capable of performing the required safety functions. The inspectors reviewed the following surveillance tests:

Unit 2, RCIC quarterly flow verification Unit 2, Main turbine CV testing Unit 2, Shiftly calculation of drywell leakage (RCS)

Units 1 and 2, HPCI quarterly flow verification

b. Findings

No findings were identified.

1EP4 Emergency Action Level and Emergency Plan Changes

a. Inspection Scope

The Office of Nuclear Security and Incident response headquarters staff performed an in-office review of the latest revisions of various Emergency Plan Implementing Procedures and the Emergency Plan located under ADAMS accession number ML13232A326 as listed in the Attachment.

PPL determined that in accordance with 10 CFR 50.54(q), the changes made in the revisions resulted in no reduction in the effectiveness of the Plan, and that the revised Plan continued to meet the requirements of 10 CFR 50.47(b) and Appendix E to 10 CFR Part 50. The NRC review was not documented in a safety evaluation report and did not constitute approval of licensee-generated changes; therefore, this revision is subject to future inspection. The specific documents reviewed during this inspection are listed in the Attachment.

b. Findings

No findings were identified.

4OA2 Problem Identification and Resolution

.1 Routine Review of Problem Identification and Resolution (PI&R) Activities

a. Inspection Scope

As required by Inspection Procedure (IP) 71152, PI&R, the inspectors routinely reviewed issues during baseline inspection activities and plant status reviews to verify that PPL entered issues into the CAP at an appropriate threshold, gave adequate attention to timely corrective actions, and identified and addressed adverse trends. In order to assist with the identification of repetitive equipment failures and specific human performance issues for follow-up, the inspectors performed a daily screening of items entered into the CAP and periodically attended CR screening meetings.

b. Findings

No findings were identified.

.2 Annual Sample: Review of the Operator Workaround (OWA) Program

a. Inspection Scope

The inspectors reviewed the cumulative effects of the existing operator workarounds, operator burdens, existing operator aids and disabled alarms, and open main control room deficiencies to identify any effect on emergency operating procedure operator actions, and any impact on possible initiating events and mitigating systems. The inspectors evaluated whether station personnel had identified, assessed, and reviewed operator workarounds as specified in PPLs procedure OI-AD-096, Operator Burdens, Revision 10.

The inspectors reviewed PPLs process to identify, prioritize and resolve main control room distractions to minimize operator burdens. The inspectors reviewed the system used to track these operator workarounds and recent PPL self assessments of the program. The inspectors also toured the control room and discussed the current operator workarounds with the operators to ensure the items were being addressed on a schedule consistent with their relative safety significance.

b. Findings

Introduction.

The inspectors identified a finding of very low safety significance (Green),and an associated NCV of 10 CFR 50.54(q) for failing to follow and maintain an emergency plan that meets the requirements of emergency planning standard 10 CFR 50.47(b)(4). Specifically, PPL failed to take timely corrective actions to restore a degraded flood alarm in accordance with station procedures. The alarm was out-of-service from December 21, 2012 until September 23, 2013 without adequate compensatory measures in place.

Description.

On December 21, 2012, the Unit 1 HPCI room flood detector (LSH-15640)failed its functional test during routine testing. CR 1654216 was generated and stated that the detector failed to bring in the alarm and appears to have been bumped as there is damage to the casing which is loose. The CR was screened as a Level 4 and WO 1656043 was generated to correct the condition.

Flood detector LSH-15640 is used to assess entry conditions and necessary actions for ON-169-002, Flooding in the Reactor Building and EO-100-104, Secondary Containment Control. Specifically, since maximum normal water level is defined as below this alarm set point, entry into the procedures is required, in part; if the HPCI room flood alarm is received. Additionally, this alarm is used during Emergency Plan implementation for entry into NOUE OU5, Natural or Destructive Phenomenon Affecting the Protected Area and Alert OA5, Natural and Destructive Phenomenon Affecting the Plant Vital Areas.

EP-TP-007, Equipment Important for Emergency Plan Implementation lists this detector as a Category A equipment which requires compensatory measures be in place to assure the Emergency Plan can be implemented. Attachment A to EP-TP-007 states that the detector is used for detection of uncontrolled flooding in a vital area. Use of local reports of flooded condition or system/equipment response required.

On September 13, 2013, inspectors reviewed the operator burdens list and identified that the detector was characterized as an operator challenge and not scheduled for completion until December 2013; the WO was classified as a priority 3. Inspectors noted that the operator burdens list was updated on August 28, 2013 to include a compensatory measure which states would require operator entry into the room to assess and relies on periodic rounds to monitor for flooding as a compensatory action.

Recognizing that operator rounds in this room are only conducted once per shift (i.e.,

every 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br />), inspectors reviewed turnover sheets, logs, other documentation and interviewed operators to assess their understanding of the compensatory action.

Inspectors identified that the faulty detector was only being carried on the control room turnover sheet. The turnover sheets for the Field Unit Supervisor and non-licensed operators that tour the room did not have this issue included on their turnover sheet.

Interview of non-licensed operators indicated that they were unaware how to determine if water level was above normal, requiring entry into the EOPs or Emergency Plan.

Inspectors reviewed the timeliness of corrective actions for the deficient condition.

D of NDAP-QA-0702 states that WOs used to address deficient conditions will get a due date applied by maintenance in accordance with the work management process. Attachment B of NDAP-QA-1903, Work Management Process, Revision 14, provides classification guidance for WO priority to ensure WO due dates are assigned according to their significance. If a component is an operator burden or associated with the Emergency Plan and it represents an equipment failure, PPL staff are required to assign the WO a Priority 2, which requires scheduling at the earliest opportunity within the next three weeks. PSP-30, SSES Tactics for Excellence Through Accountable Management, Revision 11, provides additional requirements for Emergency Plan Implementation Equipment. It states that compensatory measures should be identified in the impacts/effects of the release WO and that equipment should have work scheduled on a one shift, 5 days a week basis. Additionally, Attachment B of PSP-30 requires a Priority 2 be assigned as the WO priority for this flood detector.

Ultimately, inspectors determined that the compensatory actions were inadequate to ensure timely and accurate entry into the Emergency Plan and EOPs and that PPL did not take timely corrective action to restore the equipment to service following discovery of its failure.

10 CFR 50.47(b)(4) requires, in part, that emergency response plans include a standard emergency classification and action level scheme, the bases of which include facility system and effluent parameters. Inspectors determined that the failure to specify appropriate compensatory measures and take timely corrective actions to address a failed instrument necessary for declaration of an NOUE and Alert resulted in the inability of PPL to make a timely declaration of an emergency.

PPLs immediate corrective actions included entering the issue into their CAP as CR 1745962, changing the priority of the WO and listing it as a priority item on their Daily Leadership Alignment Package. PPL replaced the detector on September 23, 2013.

Analysis.

The inspectors determined that PPLs failure to take timely and adequate corrective action to address a failed detector necessary to diagnose and classify an emergency event was a performance deficiency that was within PPLs ability to foresee and correct, and should have been prevented. The performance deficiency is more than minor because it was associated with the facilities and equipment attribute of the Emergency Preparedness cornerstone and affected the objective to ensure that the licensee is capable of implementing adequate measures to protect the health and safety of the public in the event of a radiological emergency. Specifically, the performance deficiency would have resulted in untimely declaration of an Alert OA5 and NOUE OU5.

In accordance with NRC IMC 0609, Appendix B, Emergency Preparedness SDP, the inspectors determined that this finding is of very low safety significance (Green) because it did not result in the loss or degradation of a risk significant planning standard.

Specifically, one Alert and one NOUE EAL initiating condition would have been rendered ineffective such that a flooding event would have been declared in a degraded manner.

The finding is related to the cross-cutting area of PI&R, CAP, in that PPL did not take appropriate corrective actions to address safety issues in a timely manner P.1(d).

Specifically, when the detector failed on December 21, 2012, adequate compensatory measures were not specified and the WO was not scheduled commensurate with its safety significance.

Enforcement.

10 CFR Part 50.54(q) requires that PPL follow and maintain in effect emergency plans which meet the standards in 10 CFR 50.47(b). 10 CFR 50.47(b)(4)requires, in part, that emergency response plans include a standard emergency classification and action level scheme, the bases of which include facility system and effluent parameters. 10 CFR 50.47(b)(8) requires, in part, that adequate emergency equipment to support emergency response be provided and maintained. Contrary to this, from December 21, 2012 through September 23, 2013, PPL did not adequately maintain emergency equipment to support emergency response. Specifically, PPL did not take timely corrective actions to correct a non-functional room flood detector and did not specify adequate compensatory measures. This rendered PPLs emergency plan ineffective such that the EAL classification process would declare Alert OA5 and NOUE OU5 in a degraded manner.

PPLs immediate corrective actions included entering the issue into their CAP as CR 1745962, changing the priority of the WO and listing it as a priority item on their Daily Leadership Alignment Package. The detector was replaced and restored to a functional status on September 23, 2013. Because this violation was of very low safety significance (Green), and PPL entered this issue into their CAP, this violation is being treated as an NCV, consistent with Section 2.3.2 of the Enforcement Policy. (NCV 05000387/2013004-03, Inadequate and Untimely Actions to Address a Failed Instrument Necessary for Diagnosis of Emergency Conditions)c. Observations The Operator Burden process had been previously identified as being ineffective in informing operator decision-making and inadequate in identifying, tracking, evaluating and resolving Operator Burdens. The ineffective use of the Operator Burden process was identified as a causal factor in a reactor scram which occurred on December 19, 2012 as documented in IR 05000388/2013010 (ML13080A158). Prior to the event, PPL failed to identify all operator burdens and, when they were identified, did not specify compensatory measures to limit the burden to operations staff. Subsequent to the scram, PPL implemented corrective actions to address these programmatic weaknesses. Specifically, PPL staff performed systematic reviews of the CAP to ensure all CRs were classified as operator burdens, as appropriate. Additionally, PPL management communicated the importance and requirements of the program to plant staff to increase awareness and sensitivity.

Inspectors reviewed these corrective actions and determined them to be partially effective. Specifically, inspectors determined that PPL staff entered operator burdens into the CAP at an appropriate threshold. Inspectors reviewed the Operator Aggregate Index report for September 2013 and identified that there were 98 operator burdens associated with plant equipment, significantly higher than the station goals as defined in OI-AD-096, Operator Burdens, Revision 10. Inspectors reviewed the data and trend and determined the recovery plan to be appropriate. Inspectors attributed the significant number of operator burdens to three specific factors:

Corrective actions to raise awareness and sensitivity to the program; PPLs low threshold for classification of items as operator burdens; and The size of the corrective and deficient maintenance backlog, which is associated with one of PPLs primary station focus areas of equipment reliability.

However, inspectors determined that PPLs assignment of compensatory measures was, in general, inadequate. Specifically, as part of corrective actions discussed above, PPL required plant staff to review operator burdens as part of shift turnover. Each operator burden is assigned a compensatory measure to limit the burden to operators pending permanent correction. Inspectors determined that compensatory actions were not specific, formal (i.e., proceduralized, documented, etc.) and/or timely. For example:

Several compensatory measures for invalid or failed indicators stated that operators were required to use other indications, but did not specify which alternate indications to use or provide engineering justification that these alternate indications were valid.

One control room deficiency stated that the burden prevented performance of an alarm response procedure, but did not provide guidance for what should be done to compensate for this issue.

Many operator burdens did not list a compensatory measure.

With the exception of the inadequate action addressed in the above finding, inspectors determined that PPLs failure to specify adequate compensatory measures to address operator burdens reviewed was of minor safety significance since there was no affect on the Mitigating Systems cornerstone objective and there were no impacts to PPLs response to an actual event. PPL entered this issue into the CAP as CR 1751294. This failure to comply with procedural requirements for control of operator burdens constitutes a minor violation that is not subject to enforcement action in accordance with the NRCs Enforcement Policy.

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

.1 Plant Events

a. Inspection Scope

For the plant events listed below, the inspectors reviewed and/or observed plant parameters, reviewed personnel performance, and evaluated performance of mitigating systems. The inspectors communicated the plant events to appropriate regional personnel, and compared the event details with criteria contained in IMC 0309, Reactive Inspection Decision Basis for Reactors, for consideration of potential reactive inspection activities. As applicable, the inspectors verified that PPL made appropriate emergency classification assessments and properly reported the event in accordance with 10 CFR 50.72 and 50.73. The inspectors reviewed PPLs follow-up actions related to the events to assure that PPL implemented appropriate corrective actions commensurate with their safety significance.

Unit Common, elevated dose rates during dry fuel storage (DFS) canister loading on August 10, 2013 Unit 2, manual scram on September 14, 2013 due to unexpected rise in reactor water level Unit 2, unusual event declaration on September 15, 2013 for uncontrolled flooding in the reactor building due to a stuck open relief valve on the RHR system

b. Findings

Introduction:

The inspectors identified a green, self-revealing, NCV of 10 CFR 50 Appendix B, Criterion 5, Instructions, Procedures, and Drawings, which states, in part, that procedures shall include appropriate quantitative or qualitative acceptance criteria for determining that important activities have been satisfactorily accomplished.

Specifically, the inspectors determined that PPLs residual heat removal (RHR)shutdown cooling procedure failed to ensure that water properties (pressure and temperature) in the suction piping were controlled to ensure water hammer event would not happen when establishing a low pressure injection lineup. As a result, a water hammer occurred in the piping and caused the suction relief valve to fail open.

Description:

On September 14, 2013, with the unit in Mode 3, operators initiated a forced cooldown of the plant in accordance with OP-249-002, RHR Shutdown Cooling, Revision 55. This procedure was used to reduce primary water temperatures and pressure, from 300 degrees and 75PSIG to less than 200 degrees and atmospheric pressure, by placing the B loop of RHR in the shutdown cooling (SDC) mode.

During this evolution, an equipment failure required operators to shut down the RHR system in accordance with OP-249-002 section 2.5, Shutdown of RHR Loop A(B) in Shutdown Cooling Mode and restore the loop to the low pressure coolant injection (LPCI) standby lineup. When operators performed the procedure, a water hammer occurred in the suction piping of the B RHR pump. The pressure transient from the water hammer caused the suction relief valve to become stuck open. Water drained from the suppression pool through this valve for several hours until a flooding alarm notified operators of the problem. The B RHR loop was isolated from the suppression pool stopping the leak. This event required declaration of an Unusual Event for uncontrolled flooding in the reactor building as reported in event notification 49344.

PPL convened an Issue Response Team (IRT) to evaluate the cause of the event and develop corrective actions. The IRT determined that a water hammer had occurred in the suction piping resulting in a pressure transient that caused the relief valve to fail in the open position. Specifically, the IRT determined that when operators secured the shutdown cooling lineup, water in the RHR system was left at an elevated temperature and pressure (250-290 F and 40-50 psig). Subsequently, when operators realigned the system for LPCI standby, the suction piping was depressurized, resulting in the suction piping water flashing to steam. Finally, when the suction valves to the suppression pool were reopened, cooler water entered the pipe resulting in the water hammer. The IRT concluded that the water hammer pressure transient caused the relief valve to open and most likely caused it to misalign and remain open. PPL noted that with the relief valve stuck open a primary containment bypass pathway was created, which exceeded the leakage from engineered safety feature (ESF) systems assumed in the analysis for post event control room dose. PPL reported this as a seriously degraded condition in accordance with 10 CFR 50.72(b)(3)(ii) (EN 49351). The inspectors reviewed PPLs evaluation of the event and determined it reasonably identified the cause of the stuck open relief valve.

The inspectors also reviewed the adequacy of the implementing procedure and noted that procedure section 2.6, Transfer of Shutdown Cooling Mode to LPCI Operation, had steps requiring operators to isolate the SDC line from the suppression pool suction line prior to venting the suction piping. However, the step to isolate the SDC line in section 2.5, which realigns the system to standby operation, occurs after the system is vented and suction valves had been opened. Additionally, the inspectors determined that neither sections 2.5 and 2.6 had steps to evaluate the water properties in the line to ensure that conditions for a water hammer were not present prior to aligning the system to the suppression pool. This should have been done to ensure that the system was successfully realigned to LPCI standby and maintained in an operable condition.

Additionally, the inspectors reviewed PPLs evaluation of NRC Information Notice (IN)2010-11, Potential for Steam Voiding Causing Residual Heat Removal System Inoperability. The IN informed the industry of the possibility of steam voiding in the RHR system if water temperatures were above 200 degrees when the system was secured. The IN recommended that the RHR system conditions be verified to be below 200 degrees when the system was secured or to provide forced cooling for the water in the RHR system. PPL reviewed the IN under CR 1274633 in and determined that OP-249-002 adequately addressed the concerns discussed in the IN. Inspectors determined that the recommendations in the IN had not been adequately incorporated into the OP-249-002 and that PPLs review of the operating experience was inadequate.

PPLs immediate corrective actions included entering the issue into their corrective action program as CRs 1746612 and 1754913, replacing the relief valve, walking down the piping and associated supports and communicating to operations personnel to declare RHR inoperable when aligned to shutdown cooling (SDC) while reactor coolant temperature is above 200 degrees Fahrenheit. The inspectors found PPLs actions to be reasonable pending identification and implementation of final corrective actions.

Analysis:

The inspectors determined the failure to provide adequate criteria to ensure that a transfer of RHR from SDC to LPCI standby was completed successfully, was a performance deficiency that was within PPLs ability to foresee and correct, and should have been prevented. Specifically, PPL had the opportunity to address the issue during their review of IN 2010-11. This finding is more than minor because it is associated with the procedure quality attribute of the Barrier Integrity cornerstone and affected the cornerstone objective to provide reasonable assurance that physical design barriers (containment) protect the public from radionuclide releases caused by accidents or events. Specifically, the water hammer event resulted in a stuck open relief valve on the RHR suction piping whose leak rate exceeded the assumed leakage from engineered safeguard systems in PPLs post-event control room dose calculations. Because conditions for RHR system operation had been established the team assessed this finding in accordance with the NRC Inspection Manual Chapter (IMC) 0609, Significance Determination Process, Appendix G, Shutdown Operations Significance Determination Process, using Attachment 1, Checklist 5. The team found the finding did not require a quantitative assessment because none of check sheet guidelines requiring a phase 2 analysis were affected. Therefore, the finding was determined to be of very low safety significance (Green).

The finding had a cross cutting aspect in the problem identification and resolution area associated with operating experience because PPL did not implement and institutionalize operating experience through changes to station processes, procedures, equipment, and training programs (P.2(b)). Specifically, PPLs review of IN 2010-11 did not ensure the transition of RHR from SDC to standby or LPCI was completed successfully by incorporating adequate steps into the operating procedure.

Enforcement:

10 CFR 50 Appendix B, Criterion V, Instructions, Procedures, and Drawings, states, in part, that procedures shall include appropriate quantitative or qualitative acceptance criteria for determining that important activities have been satisfactorily accomplished. Contrary to the above, before October 12, 2013, PPLs procedure, OP-249-002, RHR Shutdown Cooling, Revision 55, did not include appropriate criteria to preclude steam voiding in the RHR suction piping were established prior to realigning from SDC to LPCI standby. Specifically, on September 15, 2013, when PPL realigned the RHR system from SDC to standby while in Mode 3, a water hammer event occurred and resulted in a stuck open relief valve on the RHR suction piping. PPLs immediate corrective actions included entering the issue into their corrective action program as CRs 1746612 and 1754913, replacing the relief valve, walking down the piping and associated supports and communicating to operations personnel to declare RHR inoperable when aligned to shutdown cooling (SDC) while reactor coolant temperature is above 200 degrees Fahrenheit. Because this finding is of very low safety significance and because it was entered into the licensees corrective action program, this violation is being treated as an NCV, consistent with Section 2.3.2 of the NRC Enforcement Policy. (NCV 05000388/2013005-04, Procedure Failed to Verify Design Requirements for RHR Suction Piping)

.2 (Closed) Licensee Event Reports (LERs) 05000387/2012-010-00 and 05000387/2012-

010-01: Both Trains of Control Structure HVAC at Susquehanna Were Rendered Inoperable On December 14, 2012 at 1:50 a.m., Operations declared the 'B' common control structure (CS) heating, ventilation and air conditioning (HVAC) system was declared inoperable when the 'B' loop chilled water circulating pump tripped during a swap from the A to the B' train. The A CS HVAC was being started to perform post-maintenance testing from routine maintenance and was considered inoperable pending successful completion of the test. Consequently, both trains of CS HVAC were inoperable simultaneously. This event required entry into TS LCO 3.0.3 for both Units 1 and 2.

This event was reported in accordance with 10 CFR 50.72(b)(2)(i), as a shutdown required by TSs, and 10 CFR 50.72(b)(3)(v)(D), as a loss of a safety function required to mitigate the consequences of an accident, in event notification48595. This event was also reportable as an LER under 10 CFR 50.73(a)(2)(v)(D), as a condition that could have prevented the fulfillment of a safety function, and 10 CFR 50.73(a)(2)(1)(B)as an operation prohibited by TSs.

The LER and associated apparent cause evaluation (ACE) were reviewed for accuracy, the appropriateness of corrective actions, violations of requirements, and generic issues.

The apparent cause was reported as electrical breakdown of the 'B' CS chilled water circulating pump motor such that the motor did not operate within the manufacturers nameplate rating under startup conditions. This resulted in intermittent trips of the circuit breaker supplying the pump. Corrective actions were taken to temporarily raise the breaker setting for the 'B' CS chilled water circulating pump pending long term corrective action to replace the 'B' CS chilled water circulating pump motor. Inspectors determined these corrective actions were reasonable. No findings or violations of NRC requirements were identified. This LER is closed.

.3 (Closed) LER 05000387/2012-009: Multiple Test Failures of Reactor Protection System

Electrical Protection Assembly Breakers In May 2012, three RPS electrical protection assembly (EPA) breakers failed to trip during channel functional testing, thus failing to meet TS Surveillance Requirement 3.3.8.2.1. The vendor of the EPA breakers determined that the cause of all three failures was a calibration issues in the maintenance area which resulted in that the under-voltage release mechanisms drifting out of calibration. The individual RPS power supply circuits containing the EPA breakers that failed to trip remained operable at all times. Testing of the redundant series connected EPA breakers demonstrated that they successfully tripped and would have performed the safety function of the circuits. A subsequent EPA breaker failure to trip was experienced during testing on Unit 2 in January, 2013 and was identified as having failed from the same failure mechanism.

Inspectors determined these failures were reportable as a common cause inoperability of multiple independent trains of RPS electrical power monitoring. Accordingly, a Severity Level IV NCV of 10 CFR 50.73(a)(2)(vii) was documented in IR 05000387;388/2013002 (ML13044A599) for failure to report this common cause inoperability. The vendor completed a 10 CFR Part 21 evaluation which concluded that a postulated EPA under-voltage device common mode failure was not reportable under Part 21 because it does not represent a substantial safety hazard in the RPS EPA application.

The LER and associated ACE were reviewed for accuracy, the appropriateness of corrective actions, violations of requirements, and generic issues. No findings or violations of NRC requirements were identified during this review. This LER is closed.

.4 (Closed) LER 05000388/2012-004: Unit 2 Automatic Scram Due to Low Reactor

Pressure Vessel Level At approximately 5:31 p.m. on December 19, 2012, Unit 2 automatically scrammed on low reactor pressure vessel level while transitioning the 'A' reactor feed pump from discharge pressure mode to flow control mode. All control rods inserted and both reactor recirculation pumps tripped. All safety systems operated as expected.

The scram and associated actuations were reported in accordance with 10 CFR 50.72(b)(2)(iv)(B) and 10 CFR 50.72(b)(3)(iv)(A) in EN 48607. These events are also reportable as an LER in accordance with 10 CFR 50.73(a)(2)(iv)(A).

The root cause assessment was previously reviewed and documented in inspection report 05000388/2013007 (ML13080A158), which documented three findings of very low safety significance (Green) associated with the event. The LER was reviewed for accuracy and consistency with the previous review of the RCA. No findings or violations of NRC requirements were identified. This LER is closed.

4OA6 Meetings, Including Exit

On October 10, 2013, the inspectors presented the inspection results to Mr. Jeffrey Helsel, Plant Manager, and other members of the PPL staff. PPL acknowledged the findings. No proprietary information is contained in this report.

ATTACHMENT:

SUPPLEMENTAL INFORMATION

KEY POINTS OF CONTACT

Licensee Personnel

T. Case, PPL Licensing

M. Christopher, Shift Manager SSES- Off-shift

L. Crawford, Assistant Operations Manager- Shift

R. Day, PPL ISI Program Manager

T. Foust, Inventory and Material Management Support

J. Franke, Site Vice President

J. Grisewood Manager, Performance Indicators

J. Hartzell, Supervisor Plant Analysis

B. Heacock, Senior Engineer

J. Helsel, Plant General Manager

T. Jardine, Operations Manager

M. Lingenfelter, Station Engineering Manager

I. Missien, Senior Emergency Planning Coordinator

S. Muntzenberger, Engineering Supervisor

B. ORourke, Licensing Engineer

P. Scanlan, Programs Engineering Manager

S. Sienkiewicz, Supervisor Programs and Testing

H. Strahley, Assistant Operations Manager, Training

R. Vasquez, PPL Corporate Engineering

T. Walters, Senior Engineer

LIST OF ITEMS OPENED, CLOSED, AND DISCUSSED

Opened/Closed

05000387;388/2013004-01 NCV Inadequate Procedural Guidance for Maintaining RPV Level During Anticipated Transient Without Scram (IR11)

05000387/2013004-02 NCV Failure to Assess and Manage Risk of Maintenance Activities (IR13)

05000387/2013004-03 NCV Inadequate and Untimely Actions to Address a Failed Instrument Necessary for Diagnosis of Emergency Conditions (40A2.2)

05000388/2013003-04 NCV Procedure Failed to Verify Design Requirements for RHR Suction Piping (40A3.1)

Closed

05000387/2012-010-00 LER Both Trains of Control Structure HVAC at Susquehanna Were Rendered Inoperable (40A3.2)

05000387/2012-010-01 LER Both Trains of Control Structure HVAC at Susquehanna Were Rendered Inoperable (40A3.2)

05000387/2012-009 LER Multiple Test Failures of Reactor Protection System Electrical Protection Assembly Breakers 40A3.3)

05000388/2012-004 LER Unit 2 Automatic Scram Due to Low Reactor Pressure Vessel Level (40A3.4)