IR 05000387/2014002
| ML14127A311 | |
| Person / Time | |
|---|---|
| Site: | Susquehanna  |
| Issue date: | 05/06/2014 |
| From: | Fred Bower Reactor Projects Region 1 Branch 4 |
| To: | Rausch T Susquehanna |
| Bower F | |
| References | |
| IR 14-002 | |
| Download: ML14127A311 (33) | |
Text
May 6, 2014
SUBJECT:
SUSQUEHANNA STEAM ELECTRIC STATION - NRC INTEGRATED INSPECTION REPORT 05000387/2014002 AND 05000388/2014002
Dear Mr. Rausch:
On March 31, 2014, 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 April 10, 2014, with Mr. J. Franke, Site Vice President, 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.
The report documents one self-revealing finding of very low safety significance (Green). The finding did not involve a violation of NRC requirements. Further, inspectors documented a licensee-identified violation, which was determined to be of very low safety significance, and listed in the report. The NRC is treating this violation as a noncited violation consistent with Section 2.3.2 of the NRC Enforcement Policy. If you contest the violation or the significance of the NCV, 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 SSES. If you disagree with a cross-cutting aspect assignment or a finding not associated with a regulatory requirement in this report, you should provide a response within 30 days of the date of this inspection report, with the basis for your disagreement, to the Regional Administrator, Region I, and the NRC Senior Resident Inspector at SSES.
As a result of the Safety Culture Common Language Initiative, the terminology and coding of cross-cutting aspects were revised beginning in calendar year (CY) 2014. New cross-cutting aspects identified in CY 2014 will be coded under the latest revision to IMC 0310. Cross-cutting aspects identified in the last six months of 2013 using the previous terminology will be converted to the latest revision in accordance with the cross-reference in IMC 0310. The revised cross-cutting aspects will be evaluated for cross-cutting themes and potential substantive cross-cutting issues in accordance with IMC 0305 starting with the CY 2014 mid-cycle assessment review. 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 NRCs Public Document Room or from the Publicly Available Records 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 05000387/2014002 and 05000388/2014002 w/Attachment: Supplemental Information
REGION I==
Docket No: 50-387, 50-388 License No: NPF-14, NPF-22 Report No: 05000387/2014002 and 05000388/2014002 Licensee: PPL Susquehanna, LLC (PPL)
Facility: Susquehanna Steam Electric Station, Units 1 and 2 Location: Berwick, Pennsylvania Dates: January 1, 2014 through March 31, 2014 Inspectors: J. Greives, Senior Resident Inspector T. Daun, Resident Inspector S. Hansell, Senior Resident Inspector, Peach Bottom B. Smith, Resident Inspector, Peach Bottom F. Arner, Senior Reactor Inspector D. Dodson, Resident Inspector A. Turilin, Project Engineer T. Hedigan, Operations Engineer Approved By: Fred L. Bower, III, Chief Reactor Projects Branch 4 Division of Reactor Projects Enclosure
SUMMARY
IR 05000387/2014002, 05000388/2014002 01/01/2014 - 03/31/2014; Susquehanna Steam
Electric Station, Units 1 and 2; Followup 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. One self-revealing finding of very low safety significance (Green) was identified. The significance of most findings is indicated by their color (i.e., greater than Green, or Green, White, Yellow, Red) and determined using Inspection Manual Chapter (IMC) 0609, Significance Determination Process (SDP), dated June 2, 2011.
Cross-cutting aspects are determined using IMC 0310, Components Within The Cross-Cutting Areas, dated December 19, 2013. All violations of NRC requirements are dispositioned in accordance with the NRCs Enforcement Policy, dated January 28, 2013. The NRCs program for overseeing the safe operation of commercial nuclear power reactors is described in NUREG-1649, Reactor Oversight Process, Revision 5.
Cornerstone: Initiating Events
- Green.
A finding of very low safety significance (Green) for failure to implement work instructions for an engineering change to the Integrated Control System (ICS) was self-revealed when Unit 2 lost control of reactor vessel level on September 14, 2013, requiring insertion of a manual scram. The cause of the loss of level control was determined to be a coding error in the ICS that resulted in the improper transition of feedwater control modes during a reactor shutdown. PPLs immediate corrective actions included entering the issue into their corrective action program (CAP) as condition report 1746169, correcting the coding error, and performing and extent of condition review of the ICS code to ensure no additional errors were present.
The performance deficiency was more than minor because it was associated with the Equipment Performance attribute of the Initiating Events cornerstone and affected its 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 failure to implement work instructions associated with the engineering change resulted in an ICS logic code error which caused a loss of reactor feed requiring a manual reactor scram. The inspectors evaluated the finding in accordance with IMC 0609, Appendix A,
"The SDP for Findings At-Power," Exhibit 1 for the Initiating Events cornerstone. The inspectors determined the finding was of very low safety significance (Green) because it did not cause both a reactor trip and the loss of mitigation equipment. This finding was determined to have a cross-cutting aspect in the area of Human Performance, Work Management because PPL did not implement a process of planning, controlling, and executing work activities such that nuclear safety is the overriding priority, including the identification and management of risk commensurate to the work. Specifically, the work instructions associated with the engineering change lacked the specificity commensurate with the complexity of the work such that it could be accomplished without error. [H.5] (Section 4OA3)
Other Findings
A violation of very low safety significance that was identified by PPL was reviewed by the inspectors. Corrective actions taken or planned by PPL have been entered into PPLs CAP.
This violation and corrective action tracking number are listed in Section 4OA7 of this report.
REPORT DETAILS
Summary of Plant Status
Unit 1 began the inspection period at or near 100 percent rated thermal power (RTP). On February 13, 2014, operators lowered power on Unit 1 to 79 percent for planned maintenance on the condensate system. Power was returned to 100 percent on February 18, 2014. On February 20, 2014, Unit 1 reduced power to 74 percent for a planned rod pattern adjustment and additional condensate system maintenance. Power was restored to 99 percent on February 25, 2014. On March 7, 2014, Unit 1 power was reduced to 85 percent for a planned rod pattern adjustment and was restored to 100 percent the following day. On March 21, 2014, operators reduced power on Unit 1 to 84 percent to perform a planned rod sequence exchange and restored power to 100 percent on March 22. On March 27, 2014, operators reduced power on Unit 1 to 85 percent to perform emergent maintenance to main condenser tubes. Power was restored to 100 percent the following day and Unit 1 ended the inspection period at or near 100 percent power.
Unit 2 began the inspection period at or near 100 percent RTP. On January 8, 2014, power was reduced to 63 percent on Unit 2 for grid-related maintenance and was restored to 100 percent the same day. On January 11, 2014, power was reduced on Unit 2 to 94 percent to comply with technical specification limits for operation with two main turbine bypass valves inoperable. Unit 2 was restored to 100 percent later the same day. On January 18, 2014, operators reduced power on Unit 2 to 84 percent to perform emergent maintenance on the main condenser tubes.
Power was restored to 100 percent the following day. On February 14, 2014, operators reduced power on Unit 2 to 69 percent to perform a planned rod sequence exchange and restored power to 100 percent on February 15. On February 28, 2014, operators commenced a reactor shutdown on Unit 2 to perform repairs to the low pressure turbines. Following the completion of the maintenance activities, operators commenced a reactor startup on March 15, 2014. On March 20, 2014, a steam leak was identified on a feedwater discharge isolation valve requiring a reactor shutdown. Following repairs, a reactor startup was commenced on March 24, 2014.
Power was restored to 100 percent on March 29, 2014 and Unit 2 ended the inspection period at or near 100 percent power.
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, standby liquid control (SBLC) system on February 19, 2014 Common, E emergency diesel generator (EDG) while substituted for C on January 15, 2014 Common, B residual heat removal service water (RHRSW) during A RHRSW flow surveillance on February 13, 2014 Common, A control structure chiller while B out-of-service for planned maintenance on March 5, 2014 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 UFSAR, TSs, work orders (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.
.2 Full System Walkdown
a. Inspection Scope
From March 24 - 27, 2014, the inspectors performed a complete system walkdown of accessible portions of the Unit 1direct current (DC) distribution system to verify the existing equipment lineup was correct. The inspectors reviewed operating procedures, surveillance tests, drawings, equipment line-up check-off lists, and the UFSAR to verify the system was aligned to perform its required safety functions. The inspectors also reviewed electrical power availability, component lubrication, equipment cooling, and operability of support systems. The inspectors performed field walkdowns of accessible portions of the system to verify system components and support equipment were aligned correctly and operable. The inspectors examined the material condition of the DC distribution system components to ensure no deficiencies existed. The inspectors also reviewed the latest surveillance test results to ensure operating parameters were in accordance with the design requirements of the system. Additionally, the inspectors reviewed a sample of related CRs and WOs to ensure PPL appropriately evaluated and resolved any deficiencies.
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, A and B RHR rooms (2-1E and 2-1F)
Unit 2, containment access area (24A-N, 2-4A-W, 2-4A-S)
Units 1 and 2, upper and lower relay rooms (0-27A, 0-27E, 0-24D, 0-24G)
Units 1 and 2, lower cable spreading rooms (0-25A, 0-25E)
Common, A EDG room (Fire Zone 0-41A)
b. Findings
No findings were identified.
1R06 Flood Protection Measures
.1 Internal Flooding Review
a. Inspection Scope
The inspectors reviewed the UFSAR, the site flooding analysis, and plant procedures to assess susceptibilities involving internal flooding of the Common E EDG building on March 13, 2014. The inspectors also reviewed the CAP to determine if PPL identified and corrected flooding problems and whether operator actions for coping with flooding were adequate. The inspectors also verified the adequacy of equipment seals located below the flood line, floor and water penetration seals, watertight door seals, common drain lines and sumps, sump pumps, level alarms, control circuits, and temporary or removable flood barriers.
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 requalification training simulator scenario on February 10, 2014. The inspectors evaluated operator performance during the simulated scram coincident with a small loss of coolant accident with the high pressure coolant injection system unavailable. Inspectors verified completion of risk significant operator actions, including the use of abnormal and emergency operating procedures (EOPs). 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 Unit Supervisor. Additionally, the inspectors assessed the ability of the crew and training staff to identify and document crew performance problems.
b. Findings
No findings were identified.
.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 outage on March 1. The inspectors observed pre-shift briefings and reactivity control briefings to verify that the briefings met the criteria specified in OP-AD-004, Standards for Shift Operations, Revision 45 and OP-AD-338, Reactivity Manipulations Standards and Communication Requirements, Revision 24. 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 assessment to ensure it met regulatory requirements.
Unit 1, B RHR suppression pool cooling isolation valve failure Common, fire protection system a(1) review
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 B emergency service water (ESW) loop pipe repairs on February 20, 2014 Unit 2, shutdown risk assessment during short time to boil, March 3, 2014 Units 1 and 2, Yellow risk during RHRSW maintenance on February 4, 2014 Common, Yellow risk for A ESW/RHRSW maintenance on February 24, 2014
b. Findings
No findings were identified.
1R15 Operability Determinations and Functionality Assessments
a. Inspection Scope
The inspectors reviewed operability determinations for the following degraded or non-conforming conditions:
Unit 1, #3 control valve (CV) closure operability determination and compensatory actions review on February 10, 2014 Unit 2, # 1 bypass valve failed to fast open on January 11, 2014 Unit 2, steam leak from HV20603A on March 20, 2014 Common, secondary containment operability during new fuel receipt on January 20, 2014 Common, inadvertent actuation of sprinkler systems on January 14 and January 18, 2014 Common, secondary containment operability with the 101 bay aligned to Zone I on February 1, 2014 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.
Introduction.
An Unresolved Item (URI) was identified because additional NRC review and evaluation is needed to determine whether implementation of a compensatory measure to restore TS operability required NRC approval prior to implementation and to subsequently determine whether a violation of 10 CFR 50.59, Changes, Tests and Experiments was more than minor.
During a review of a prompt operability determination addressing the inadvertent closure of a main turbine CV, inspectors questioned whether a compensatory measure specified to maintain compliance with TS required NRC approval prior to implementation.
Specifically, to address the degraded condition, PPL implemented a compensatory measure of crediting plant equipment not previously credited in the UFSAR to restore and maintain operability in accordance with TSs 3.2.2, Minimum Critical Power Ratio and 3.2.3, Linear Heat Generation Rate. PPL did not perform an evaluation of this change as required by 10 CFR 50.59(d)(1).
Description.
On July 10, the number 3 main turbine CV on Unit 1, XV-10150C, slowly drifted close while operating at 100 percent rated thermal power (RTP). In response to the issue, the electro-hydraulic control system opened CVs 1, 2 and 4 to maintain reactor pressure stable. Operators reduced power to approximately 96 percent RTP.
Operators also generated CR 1724394 and assessed the condition for operability. PPL performed a prompt operability determination and assessed, in part, the potential affect the degraded condition had on the power distribution limits. Specifically, PPL determined, during discussions with the fuel vendor, that the thermal limits were affected by the number 3 CV being closed. Specifically, with the number 3 CV closed, the steam relieving capacity of the main steam system was below assumed values in the transient analysis for a Recirculation Flow Controller Failure (RFCF). The RFCF is one of the limiting events used to develop the flow-based Minimum Critical Power Ratio and Linear Heat Generation Rate thermal limits. To compensate for this and restore operability per TSs 3.2.2 and 3.2.3, PPL specified crediting the reactor recirculation motor-generator set high speed electrical and mechanical stops to limit the maximum flow assumed in the transient analysis.
Consistent with Inspection Manual Part 9900 Technical Guidance, Operability Determinations & Functionality Assessments for Resolution of Degraded or Nonconforming Conditions Adverse to Quality or Safety and the PPL 50.59 Resource Manual, Revision 6, PPL considered this compensatory measure a change to the facility and assessed whether the change required prior NRC approval in accordance with NDAP-QA-0726, 10 CFR 50.59 and 10 CFR 72.48 Implementation, and PPLs 50.59 Resource Manual.
PPL determined the change did not require evaluation under 10 CFR 50.59 and documented this on a 50.59 Screening Determination. In part, this was based on answering no to the question does the proposed activity involve a change to an SSC that adversely affects an FSAR described design function. The basis for this determination was that the reactor recirculation motor-generator set high speed electrical and mechanical stops are not credited in the FSAR transient analysis and, therefore, have no design function. PPL considered the effect on the design function of the fuel assemblies to not fail during normal operation and anticipated operational occurrences and determined that the compensatory measure ensures that the requirement of the design function is met. PPL concluded that the change did not adversely affect any of the design functions for the fuel.
Inspectors reviewed the 50.59 screening determination and questioned the basis of PPLs conclusion that an evaluation of the change was not required. Specifically, the change had the effect of creating a new design function for the reactor recirculation motor-generator set high speed electrical and mechanical stops to limit flow during a RFCF event. Additionally, a failure of these components could preclude the design function of the fuel from being met. The resource manual provides a definition of adverse effects which states, in part:
Changes that would introduce a new type of accident or malfunction with a different result would screen in.
If a proposed change would reduce the reliability of a design function, this change should be screened in because there is an adverse effect on a design function.
Changes to SSCs that are not explicitly described in the FSAR can have the potential to affect SSCs that are explicitly described in the FSAR and thus may require a 10 CFR 50.59 Evaluation. If for the larger FSAR described SSC, the change affects a FSAR described design function or an evaluation demonstrating that intended design functions will be accomplished, then a 10 CFR 50.59 Evaluation is required.
In this case, the introduction of a new design function for the components and reliance on these components to function to ensure a design function of the fuel was met had an adverse effect by introducing a new potential malfunction that could result in the design function not being met.
Therefore, inspectors determined that PPL should have answered Yes to the screening question Does the proposed activity involve a change to an SSC that adversely affects an FSAR described design function. PPL also should have evaluated whether the change needed prior NRC approval in accordance with 10CFR 50.59(d)(1). Inspectors determined that the issue was a performance deficiency, however, could not determine whether the change would ever have ultimately required NRC approval. Therefore, in accordance with the NRC Enforcement Policy, inspectors could not determine whether the performance deficiency was more than minor.
PPL entered the issue into the CAP as CR-2014-09397 and initiated actions to evaluate the change in accordance with 10 CFR 50.59(d)(1). Pending completion of PPLs 50.59 evaluation and review by inspectors, this is a URI. (URI 05000387/2014002-01, Adequacy of Compensatory Measures to Restore Technical Specification Operability)
1R18 Plant-Modifications
.1 Temporary Modifications
a. Inspection Scope
The inspectors reviewed the temporary modification listed below to determine whether the modification affected the safety functions of systems that are important to safety.
The inspectors reviewed 10 CFR 50.59 documentation and post-modification testing results, and conducted field walkdowns of the modifications to verify that the temporary modifications did not degrade the design bases, licensing bases, and performance capability of the affected systems.
Unit 2, removal of reactor protection system (RPS) fuses for turbine stop valve/turbine control valve (TSV/TCV) closure scram
b. Findings
No findings were identified.
.2 Permanent Modifications
a. Inspection Scope
The following inspection sample examined a modification involving a new piping connection installation into RHRSW, associated with PPLs modifications in response to Japan Lessons Learned Order. The inspection did not address whether the modification satisfactorily addressed the objectives of Order EA-12-049. The inspection scope for the modification was restricted to those elements necessary to satisfy the stated objectives of IP 71111.18, specifically:
To verify that modifications have not affected the safety functions of important safety systems; To verify that the design bases, licensing bases, and performance capability of risk significant SSCs have not been degraded through modifications; and Verify that modifications performed during increased risk-significant configurations did not place the plant in an unsafe condition.
The inspectors evaluated a modification of the RHRSW implemented by engineering change package 1548095, Fukushima Response Action: Installation of Fire Hose Connection in loops A and B of RHRSW for Mitigation Strategy (EA-12-049). The inspectors verified that the design bases, licensing bases, and performance capability of the affected systems were not degraded by the modification. In addition, the inspectors reviewed modification documents associated with the upgrade and design change.
Inspectors reviewed the weld data sheets and discussed radiography results with engineering.
Units 1 and 2, installation of fire protection branch connection on RHRSW
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, hydraulic control unit 58-43 maintenance on February 4, 2014 Unit 2, HV20603A overhaul on March 22, 2014 Common, C EDG overspeed governor replacement test on January 16, 2014 Common, secondary containment repairs on January 30 and January 31, 2014 Common, corrective maintenance on 0V103A on February 5, 2014
b. Findings
No findings were identified.
1R20 Refueling and Other Outage Activities
a. Inspection Scope
The inspectors reviewed the stations work schedule and outage risk plan for the Unit 2 planned maintenance outage, which was conducted March 1 through March 15, 2014, and the Unit 2 forced outage to repair a steam leak on HV20603A, which was conducted from March 20 through March 24, 2014. 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 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 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 1, Division 1 RHR logic system functional test on February 11, 2014 Unit 1, Division 2 RHR flow surveillance on February 7, 2014 Unit 1, HPCI flow verification on March 6, 2014 Unit 2, A core spray quarterly flow verification on January 10, 2014 Unit 2, diesel driven fire pump performance test on February 27, 2014 Unit 2, Division I RHRSW flow surveillance on February 13, 2014 Common, A emergency service water flow surveillance on January 9, 2014 (IST)
b. Findings
No findings were identified.
Cornerstone: Emergency Preparedness
1EP6 Drill Evaluation
a. Inspection Scope
The inspectors evaluated the conduct of a routine PPL emergency drill on February 18, 2014 to identify weaknesses and deficiencies in the classification, notification, and protective action recommendation development activities. The inspectors observed emergency response operations in the simulator to determine whether the event classifications, notifications, and protective action recommendations were performed in accordance with procedures. The inspectors also attended the station drill critique to compare inspector observations with those identified by PPL staff in order to evaluate PPLs critique and to verify whether the PPL staff was properly identifying weaknesses and entering them into the CAP.
b. Findings
No findings were identified.
OTHER ACTIVITIES
4OA1 Performance Indicator Verification
.1 Initiating Events
a. Inspection Scope
The inspectors reviewed PPLs PI data for the period of January 2013 through December 2013 to determine whether the PI data was accurate and complete. The inspectors examined selected samples of PI data, PI data summary reports, and plant records. The inspectors compared the PI data against the guidance contained in Nuclear Energy Institute (NEI) 99-02, Regulatory Assessment PI Guideline, Revision 6.
The following PIs were included in this review:
Units 1 and 2, Unplanned Scrams per 7000 Critical Hours, IE01 Units 1 and 2, Unplanned Power Changes per 7000 Critical Hours, IE03 Units 1 and 2, Unplanned Scrams with Complications, IE04
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.
4OA3 Followup of Events and Notices of Enforcement Discretion
.1 (Closed) Licensee Event Report 05000388/2011-005-00: Core Flow Mis-Calibated
Resulting in Core Flow Above 108 Mlb/Hr
a. Inspection Scope
On August 16, 2012, during the performance of a core flow calibration for Unit 2 PPL identified that total core flow was indicating a nominal 2.3 Mlb/hr lower than the actual core flow. Based on this, PPL determined that core flow exceeded the 108 Mlb/hr limit at various times between July 27, 2011 and August 16, 2012. The maximum three minute average was determined to be 109.09 Mlb/hr. The mismatch in core flows was attributed to a July 27, 2011, Unit 2 core flow calibration. Based on the core flow calibration data results instrumentation gain was adjusted. This gain adjustment resulted in a bias offset with respect to indicated versus actual core flow. PPL determined that the offset was due to the particular core conditions and potential undetected flow fluctuations at the time the data was recorded during the 2011 calibration adjustments. PPLs equipment apparent cause evaluation (CR 1708878)noted that the procedure used, TP-264-032, Core Flow Calibration, Revision 5, was less than adequate because the procedure did not require a reiteration of the procedural steps after the gain adjustments were made. PPL noted this iterative check is standard industry practice and is consistent with core flow calibration procedures described in vendor documents.
PPL considered the miscalibration may have resulted in a condition prohibited by Technical Specifications and reported the condition in accordance with 10 CFR 50.73(a)(2)(i)(B). This was due to concerns that operation had been outside the bounds of the core operating limits report, with respect to the nominal total core flow end-point (108 Mlb/hr) found in the COLR flow dependent curves for thermal limits. PPL also considered the impact to the recirculation loop flow mismatch TS requirements. PPL determined that there were no actual consequences based on preliminary analysis of fuel thermal limits and additional licensing bases considerations, including potential impact to the jet pumps. The LER and associated evaluations were reviewed for accuracy, the appropriateness of corrective actions, violations of requirements, and generic issues. The enforcement aspects of this issue are discussed in Section 4OA7.
This LER is closed.
b. Findings
The inspectors documented a licensee-identified violation associated with the less than adequate core flow calibration procedure in Section 4OA7 of this report.
.2 (Closed) LER 05000388/2013-003-00: Unit 2 Manual Reactor Scram Due to Loss of the
Reactor Feedwater Pumps
a. Inspection Scope
On September 14, 2013, reactor water level rose to +54 inches while transitioning the feedwater ICS for the A' reactor feedwater pump (RFP) from flow control mode to discharge pressure mode, resulting in a trip of the running reactor feed pumps. In response to the transient, operators manually scrammed the reactor. All systems responded appropriately and there were no actual adverse safety consequences as a result of the scream.
The scram was reported in accordance with 10 CFR 50.72(b)(2)(iv)(B) and 10 CFR 50.72(b)(3)(iv)(A) in event notification (EN) 49342. It was also reported as an LER in accordance with 10 CFR 50.73(a)(2)(iv)(A). The inspectors reviewed this LER to determine if PPLs evaluations and associated corrective actions were appropriate. The inspectors also assessed the accuracy of the LER, the timeliness of corrective actions, whether violations of requirements occurred, and if potential generic issues existed.
This LER is closed.
b. Findings
Introduction.
A finding of very low safety significance (Green) for failure to implement work instructions for an engineering change to the ICS was self-revealed when Unit 2 lost control of reactor vessel level on September 14, 2013, requiring insertion of a manual scram. The cause of the loss of level control was determined to be a coding error in the ICS system that resulted in the improper transition of feedwater control modes during a reactor shutdown.
Description.
The ICS is a non-safety-related digital control system that controls components necessary for reactor water level and recirculation flow control. During reactor shutdowns, operators can use ICS to automatically transition flow modes of the RFPs. The required transition is from flow control mode (FCM), which controls reactor water level by varying RFP turbine speed, to discharge pressure mode (DPM), which maintains RFP discharge pressure constant while varying valve position to control reactor level. During this transfer, the startup isolation valve opens to provide a flowpath to the RPV through the startup line. Once this valve is fully opened, the RFP discharge isolation valve will close and the RFP turbine speed will increase to maintain discharge pressure constant.
On September 14, 2013, during a plant shutdown with reactor power at approximately 14 percent RTP, operators used ICS in automatic control to transition the A reactor feed pump from FCM to DPM. During the transition, reactor water level rose to +54 inches, resulting in a trip of all running reactor feed pumps and operators manually scrammed the reactor. In review of the event, PPL identified a coding error in a portion of the ICS logic associated with the 2A RFP transfer from FCM to DPM. Specifically, a block was incorrectly coded AND ~BI08 BO03 when it should have been coded AND BI08 BO03.
By having the inappropriate ~, a coding equivalent of a logical NOT operator, the logic was modified to transfer the 2A RFP to DPM as soon as operators requested the transfer. This occurred prior to opening of the startup isolation valve and closure of the RFP discharge isolation valve.
PPLs root cause evaluation determined that the coding error was made during implementation of engineering change (EC) 1694052, which was designed to address ICS single point vulnerabilities identified during the review of an automatic low reactor water level scram that occurred on December 19, 2012. This modification was designed and approved on May 9, 2013. For the specific line of code discussed above, the EC required the ~ to be removed from the line. System Engineers and Operators successfully completed site acceptance testing on the ICS Simulator (FSIM) and determined that the modification design was correct prior to installation in the plant.
Work order 1694575 was planned by computer engineering for installation of the EC.
On May 10, 2013, the work order was incorrectly implemented in that the specific line of code was not changed which resulted in the loss of feed water and reactor scram during a subsequent reactor flow mode shift. MFP-QA-1220, EC Process Handbook identifies, in part, the activities and requirements for the initiation, design, implementation and return to service of ECs. Step 5.4.5 requires the work group to install and test the EC in accordance with the work instructions. Despite this, not all the changes specified in the EC were made when the work order was implemented.
In review of the work order, PPLs root cause evaluation team determined that the work instructions did not meet the requirements of procedures NSEI-AD-506, Computer System Problem Reporting, and MI-PS-001, Work Package Standard. Specifically, the procedures required the work order to contain step-by-step instructions on how to perform the maintenance activity. Instead the work order had a single step directing the programmer to open the computer program and make the necessary changes specified in the EC. This single step actually required an iterative 3-step process for the 268 changes required by the EC. Additionally, the post maintenance test for the work stated Verify the changes per Hurst CTS. Hurst CTS is a software program that is used to verify code packages for the four ICS modules (Unit 1, Unit 2, FSIM and the simulator).
This program is used, in part, to develop multiple reports that can be used to validate that a change was made correctly. Lacking specific direction, the computer engineer that performed the post maintenance test did not choose the most efficient or effective method of validating the change. Specifically, the individual chose to review a report of changes made to the plant as compared to the modification. Since the error was one of omission (i.e., the individual did not make the change specified in the EC) it was omitted from the report. By performing the PMT with this report only, the programmer would have had to identify that there was a single line of the 268 lines missing. Another report titled Pending Changes Not Implemented would have specifically identified any lines of code that were not changed per the EC, which would have highlighted any errors of omission. Ultimately, PPL determined that the work order lacked the detail necessary to ensure the PMT was performed adequately in accordance with station standards.
PPLs immediate corrective actions included entering the issue into their corrective action program as condition report 1746169, correcting the coding error, and performing and extent of condition review of the ICS code to ensure no additional errors were present.
Analysis.
The inspectors determined that PPLs failure to implement an EC as specified in the work order was a performance deficiency that was within PPLs ability to foresee and correct, and should have been prevented. The performance deficiency was more than minor because it was associated with the Equipment Performance attribute of the Initiating Events cornerstone and affected its 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 failure to implement work instructions associated with the EC resulted in an ICS logic code error which caused a loss of reactor feed requiring a manual reactor scram. The inspectors evaluated the finding in accordance with IMC 0609, Appendix A "The SDP for Findings At-Power," Exhibit 1 for the Initiating Events cornerstone. The inspectors determined the finding was of very low safety significance (Green) because it did cause a reactor trip and the loss of mitigation equipment.
This finding was determined to have a cross-cutting aspect in the area of Human Performance, Work Management because PPL did not implement a process of planning, controlling, and executing work activities such that nuclear safety is the overriding priority, including the identification and management of risk commensurate to the work.
Specifically, the work instructions associated with the EC lacked the specificity commensurate with the complexity of the work such that it could be accomplished without error. [H.5]
Enforcement.
This finding does not involve enforcement action since no regulatory requirement violation was identified. Specifically, since the ICS is non-safety-related and not credited in any accident analysis, implementation of PPLs procedure, MFP-QA-1220, Engineering Change Process Handbook, is not required to be implemented as part of Susquehannas 10 CFR 50, Appendix B, QA Program. Because the finding does not involve a violation of regulatory requirements and has very low safety significance, it is identified as a finding (FIN). (FIN 05000388/2014002-02, Reactor Scram due to Loss of Reactor Feed Pumps)
4OA5 Other Activities
.1 Cross-Cutting Aspects
The table below provides a cross-reference for findings and cross-cutting aspects identified in the last six months of 2013 to the new cross-cutting aspects in Inspection Manual Chapter (IMC) 0310 resulting from the common language initiative. These aspects and any others identified since January 2014 will be evaluated for cross-cutting themes and potential substantive cross-cutting issues in accordance with IMC 0305 starting with the 2014 mid-cycle assessment review.
Finding Old Cross-Cutting Aspect New Cross-Cutting Aspect 05000387;388/2013004-01 P.1(a) P.1 05000387/2013004-02 H.3(a) H.5 05000387/2013004-03 P.1(d) P.3 05000388/2013004-04 P.2(b) P.5 05000387/2013005-01 P.3(a) P.6 05000387;388/2013005-03 H.2(c) H.7 05000387;388/2013005-04 H.2(d) H.1 05000388/2013011-01 P.2(a) P.5
.2 (Closed) Severity Level III NOVs: Medical Issues
a. Inspection Scope
In accordance with IP 92702, Followup on Traditional Enforcement Actions Including Violations, Deviations, Confirmatory Action Letters, Confirmatory Orders, and Alternative Dispute Resolution Confirmatory Orders, the inspectors conducted a followup inspection of two SL III NOVs and one SL IV NOV. The first SL III violation and the SL IV violation involved not restricting licensed operators from performing licensed duties when they had disqualifying medical conditions, and did not properly notify the NRC after learning of changes in licensed operator medical conditions that involved permanent disabilities/illnesses. The second violation involved PPLs submittal of information to the NRC that was not complete and accurate in all material respects.
The inspectors reviewed PPLs root cause report and the actions taken to prevent recurrence of those causes. The inspectors reviewed NDAP-QA-0723, PPL-Susquehanna NRC Operator License and Medical Notification Process, which is the implementing procedure for licensed operator medicals. The inspectors also reviewed PPLs assessment of generic implications of the identified violations.
b. Findings
No findings were identified.
.3 Follow Up Inspection for Three or More Severity level IV Traditional Enforcement
Violations in The Same Area in a 12-Month Period (92723 - 1 Sample)
a. Inspection Scope
From January 1 to December 31, 2012, the NRC issued PPL three SL IV traditional enforcement violations associated with impeding the regulatory process. The three Notices of Violation are listed in the Attachment to this report. The NRC conducted an inspection using IP 92723 to follow up on these violations and informed PPL of the NRCs intent to conduct this inspection via the NRC Annual Assessment letter dated March 4, 2013 (ML13059A425). The NRC conducted similar inspections using IP 92723 at Susquehanna in 2010 and 2012 for violations for impeding the regulatory process.
The inspectors reviewed individual cause evaluations for recent traditional enforcement violations, common cause evaluations associated with the IP 92723 inspections in 2010 and 2012, and the common cause analysis for 14 traditional enforcement violations since 2008 to provide assurance that the causes of multiple SL IV traditional enforcement violations were understood by PPL; to provide assurance that the extent of condition and extent of cause of multiple SL IV traditional enforcement violations were identified; and to provide assurance that PPLs corrective actions to traditional enforcement violations were sufficient to address the causes.
The inspectors also reviewed a sample of CRs that had been evaluated for reportability to determine if the sampled conditions were reported at the appropriate threshold. The inspectors also reviewed selected procedures and interviewed station personnel from operations, engineering, and licensing to assess the effectiveness of implemented corrective actions.
b. Findings and Observations
No findings were identified.
Two common causes were identified during the common cause analysis of the 14 traditional enforcement violations since 2008. PPL determined that expectations for completion of in-depth evaluations for NRC issued violations were not being enforced and that station personnel did not have adequate knowledge of regulations and reporting requirements and subsequently relied on station procedures to contain a finer level of detail. Corrective actions included revision of procedures, periodic refresher training, and periodic self-assessments for NRC performance indicator reporting, NRC event reporting, maintenance rule, operability, and 10 CFR 50.59 Changes, Tests, and Experiments, evaluations.
With some noted minor exceptions, the inspectors determined that PPL generally evaluated each issue appropriately, developed appropriate corrective actions, and implemented those actions in a timely manner. However, the inspectors identified some examples where corrective actions associated with causal evaluations were not always characterized, completed, or documented in accordance with procedures, specifically NDAP-QA-0702, Action Request and Condition Report Process, Revision 40, and NDAP-00-0752, Cause Analysis, Revision 21.
In one example associated with the apparent cause evaluation for CR 1696097, which related to a change to Section 3.8.3, Diesel Fuel Oil, Lube Oil, and Starting Air, the inspectors identified that interim compensatory actions to address one of the causal factors were established, but permanent actions to revise NDAP-00-1600, Technical Task Risk/Managed Defenses Assessment, Pre-Job Brief, Independent Third Party Review, and post-Job Brief, Revision 2, were not characterized appropriately and could have been canceled based on the enhancement actions classification. PPL documented this issue as CR 2014-02596.
In another example associated with the apparent cause evaluation for CR 1671982, which related to PPLs failure to notify the NRC of a valid actuation of the Unit 2 RPS on November 9, 2013 in accordance with 10 CFR 50.72, Immediate Notification Requirements for Operating Nuclear Power Reactors, the inspectors identified a corrective action that was not completed. Specifically, the corrective action to distribute a formal PPL communication addressing operations concerns related to the failure to make a report after a SCRAM signal was not completed. PPL documented this issue as CR 2014-02396.
Finally, no CAP actions were assigned to the extent of cause for one of the apparent causes associated with CR 1663755, which related to PPLs failure to submit an LER in accordance with 10 CFR 50.73(a)(2)(vii). Specifically, an enhancement action, which can be canceled, was created to assess the current operating experience program and determine what is needed to close the apparent gap in station-wide use of internal operating experience. However, corrective actions were not clearly assigned to the extent of cause. PPL documented this issue as CR 2014-02595.
The inspectors evaluated the deficiencies noted above for significance in accordance with the guidance in IMC 0612, Appendix B, Issue Screening, and Appendix E, Examples of Minor Issues. The inspectors determined these issues were deficiencies of minor significance, and therefore, are not subject to enforcement action in accordance with the NRCs Enforcement Policy. Additionally, PPL entered the inspectors observations into the CAP.
4OA6 Meetings, Including Exit
On April 10, 20014, the inspectors presented the inspection results to Mr. J. Franke, Site Vice-President, and other members of the PPL staff. The inspectors verified that no proprietary information was retained by the inspectors or documented in this report.
4OA7 Licensee-Identified Violations
The following violation of very low safety significance (Green) was identified by PPL and is a violation of NRC requirements which meets the criteria of the NRC Enforcement Policy for being dispositioned as an NCV.
10 CFR 50, Appendix B, Criterion V, Instructions, Procedures, and Drawings, requires in part, that activities affecting quality shall be prescribed by documented instructions and procedures of a type appropriate to the circumstances. Contrary to the above, prior to July 6, 2012, it was identified that PPL had not incorporated adequate written guidance in TP-264-032, Core Flow Calibration, Revision 5, to require iteration of the procedural steps used for the calibration check if flow instrumentation summer gains were adjusted. This resulted in core flow for the A recirculation loop being adjusted to approximately 2.4 Mlb/hr below actual loop flow and the B recirculation loop being adjusted to approximately 0.2 Mlb/hr below actual loop flow. PPL entered the issue into the corrective action program as CR 1708878.
Inspectors determined this finding to be of very low safety significance (Green) in accordance with IMC 0609, Attachment 4, Initial Characterization of Findings, and Appendix A, The Significance Determination Process (SDP) for Findings At-Power, because none of the logic questions under the barrier integrity cornerstone applied, indicating the issue screened to Green. Inspectors reviewed PPLs technical evaluation and determined that there was adequate margin in the thermal limit calculations to ensure that no safety or operating limits were exceeded. This issue was discussed in further detail within Section 4OA3 of this report.
ATTACHMENT:
SUPPLEMENTAL INFORMATION
KEY POINTS OF CONTACT
Licensee Personnel
- T. Case, Engineer-Nuclear Regulatory Affairs
- B. ORourke, Senior Engineer-Nuclear Regulatory Affairs
- C. Parks, Site Nurse
- F. Purdy, System Engineer
- P. Scanlan, Systems Engineering Manager
- J. Smith, Fuels Engineer
- H. Strahley, Assistant Operations Manager
- J. Stover, Design Engineer
LIST OF ITEMS OPENED, CLOSED, AND DISCUSSED
Opened
- 05000387/2014002-01 URI Adequacy of Compensatory Measures to Restore Technical Specification Operability (1R15)
Opened/Closed
- 05000388/2014002-02 FIN Reactor Scram due to Loss of Reactor Feed Pumps (4OA3)
Closed
- 05000388/2011-005-00 LER Core Flow Mis-Calibration (4OA3)
- 05000387, 388/2013008-01 NOV Failure to Restrict Operators from Performing Licensed Duties with Medically Disqualifying Conditions and Failure to Notify the NRC Within 30 Days of Discovering Changes in Medical Conditions (4OA5)
- 05000387, 388/2013008-02 NOV Failure to Provide Complete and Accurate Medical Information for Licensed Operator Applications (4OA5)
- 05000387, 388/2011004-01 NOV Violation of 10CFR55.25, Failure to Notify NRC of a Change in Medical Status and Request a Conditional License (4A05)
- 05000388/2013-003-00 LER Unit 2 Manual Reactor Scram Due to Loss of the Reactor Feedwater Pumps (4OA3)