IR 05000440/2012002
| ML12115A138 | |
| Person / Time | |
|---|---|
| Site: | Perry  |
| Issue date: | 04/24/2012 |
| From: | Jack Giessner Reactor Projects Region 3 Branch 4 |
| To: | Kaminskas V FirstEnergy Nuclear Operating Co |
| References | |
| IR-12-002 | |
| Download: ML12115A138 (38) | |
Text
UNITED STATES ril 24, 2012
SUBJECT:
PERRY NUCLEAR POWER PLANT NRC INTEGRATED INSPECTION REPORT 05000440/2012002
Dear Mr. Kaminskas:
On March 31, 2012, the U.S. Nuclear Regulatory Commission (NRC) completed a baseline inspection at your Perry Nuclear Power Plant Unit 1. The enclosed inspection report documents the inspection results which were discussed on April 4, 2012, with you and other members of your staff.
The inspection examined activities conducted under your license as they relate to safety and compliance with the Commissions rules and regulations and with the conditions of your license.
The inspectors reviewed selected procedures and records, observed activities, and interviewed personnel.
Based on the results of this inspection, one self-revealed finding of very low safety significance (Green) was identified. The finding involved a violation of NRC requirements. The NRC is treating this violation as a non-cited violation (NCV) consistent with Section 2.3.2 of the NRC Enforcement Policy.
If you contest the subject or severity of any NCV, you should provide a response within 30 days of the date of this inspection report, with the basis for your denial, to the U.S. Nuclear Regulatory Commission, ATTN: Document Control Desk, Washington, DC 20555-0001, with a copy to the Regional Administrator, U.S. Nuclear Regulatory Commission - Region III, 2443 Warrenville Road, Suite 210, Lisle, IL 60532-4352; the Director, Office of Enforcement, U.S. Nuclear Regulatory Commission, Washington, DC 20555-0001; and the Resident Inspector Office at the Perry Nuclear Power Plant.
If you disagree with a cross-cutting aspect assignment in this report, you should provide a response within 30 days of the date of this inspection report, with the basis for your disagreement, to the Regional Administrator, Region III, and the NRC Resident Inspector at the Perry Nuclear Power Plant. In accordance with 10 CFR 2.390 of the NRC's "Rules of Practice," a copy of this letter, it's enclosure, and the 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 NRC's Agencywide Document Access and Management System (ADAMS). ADAMS is accessible from the NRC Web site at http://www.nrc.gov/reading-rm/adams.html (the Public Electronic Reading Room).
Sincerely,
/RA/
John B. Giessner, Chief Branch 4 Division of Reactor Projects Docket No. 50-440 License No. NPF-58
Enclosure:
Inspection Report 05000440/2012002 w/Attachment: Supplemental Information
REGION III==
Docket No: 50-440 License No: NPF-58 Report No: 05000440/2012002 Licensee: FirstEnergy Nuclear Operating Company (FENOC)
Facility: Perry Nuclear Power Plant, Unit 1 Location: Perry, Ohio Dates: January 1, 2012, through March 31, 2012 Inspectors: M. Marshfield, Senior Resident Inspector T. Hartman, Resident Inspector D. Betancourt-Roldan, Reactor Engineer N. Feliz-Adorno, Reactor Engineer M. Jones, Reactor Engineer J. Nance, Reactor Engineer S. Shah, Reactor Engineer Approved by: John B. Giessner, Chief Branch 4 Division of Reactor Projects Enclosure
SUMMARY OF FINDINGS
Inspection Report (IR) 05000440/2012002; 01/01/2012 - 03/31/2012; Perry Nuclear Power
Plant; Outage Activities.
This report covers a 3-month period of inspection by resident inspectors and announced baseline inspections by regional inspectors. One self-revealed finding of very low safety significance (Green) was identified. The finding was considered a non-cited violation (NCV)of NRC regulations. The significance of most findings is indicated by their color (Green, White,
Yellow, Red) using Inspection Manual Chapter (IMC) 0609, Significance Determination Process (SDP); the cross-cutting aspects were determined using IMC 0310, Components Within the Cross-Cutting Areas. Findings for which the SDP does not apply may be Green or be assigned a severity level after NRC management review. The NRCs program for overseeing the safe operation of commercial nuclear power reactors is described in NUREG-1649, Reactor Oversight Process, Revision 4, dated December 2006.
NRC-Identified
and Self-Revealed Findings
Cornerstone: Initiating Events
- Green.
A self-revealed finding of very low safety significance (Green) and an associated NCV of 10 CFR 50.65(a)(4) was identified for failure to assess and manage risk associated with maintenance activities. Specifically, the licensee planned and conducted maintenance on a stator water cooling system pressure gauge on March 1, 2012, as a lower risk evolution than required, and conducted the maintenance online despite several decision points which indicated that this maintenance should have been conducted with the unit offline. When performed on line, the activity caused a reactor scram. The licensee entered the issue into the corrective action program as Condition Report 2012-03231.
The finding was evaluated using IMC 0612, Appendix E, Examples of Minor Issues, and was determined to be more than minor because it is similar to Example 7.e and resulted in a reactor scram. Additionally, the performance deficiency impacted the Human Performance attribute of the Initiating Events Cornerstone, and adversely affected the cornerstone objective to limit the likelihood of events that upset plant stability and challenge critical safety functions during power operations. In accordance with IMC 0609, Appendix K, Maintenance Risk Assessment and Risk Management Significance Determination Process, a Region III Senior Reactor Analyst performed an analysis of the risk deficit for the unevaluated condition associated with work on a stator water system pressure gauge resulting in a reactor scram. The Perry Standardized Plant Analysis Risk (SPAR) model version 8.15 and SAPHIRE version 8.0.7.18 was used to calculate an Incremental Core Damage Probability Deficit (ICDPD). The result was an ICDPD of less than 7E-8. The dominant core damage sequences involved:
(1) loss of the main condenser, failure of suppression pool cooling, failure of containment spray, failure of the power conversion system, failure of containment venting, and failure of late injection; and (2) failure of the reactor protection system to shutdown the reactor with failure of the recirculation pumps to trip. In accordance with IMC 0609, Appendix K, because the calculated ICDPD was not greater than 1E-6, the finding was determined to be of very low safety significance. This finding was associated with a cross-cutting aspect in the Work Planning (H.3(a)) component of the Human Performance cross-cutting area because the licensee did not incorporate appropriate risk insights into the development of the work package. Specifically, the licensee did not evaluate, during the planning phase of the work preparation, for the impact of re-installation of the pressure gauge and the potential for a pressure spike; a spike which caused a sustained runback of the main turbine generator with a resultant required action by the operators to manually scram the reactor. (1R20)
Licensee-Identified Violations
None.
REPORT DETAILS
Summary of Plant Status
The plant began the inspection period at 100 percent power. On March 1, 2012, at 0224 hours0.00259 days <br />0.0622 hours <br />3.703704e-4 weeks <br />8.5232e-5 months <br /> a manual scram was inserted by the operators because of a generator runback signal caused by maintenance on a manual pressure gauge in the stator water cooling system. Restoring the pressure gauge to service after calibration caused a false low pressure signal to be seen by the generator runback sensing circuitry. On March 3, 2012, at 0212 hours0.00245 days <br />0.0589 hours <br />3.505291e-4 weeks <br />8.0666e-5 months <br /> the reactor plant was placed in startup mode and achieved criticality at 0628 hours0.00727 days <br />0.174 hours <br />0.00104 weeks <br />2.38954e-4 months <br /> on the same day. On March 4, 2012, at 1156 hours0.0134 days <br />0.321 hours <br />0.00191 weeks <br />4.39858e-4 months <br /> the plant generator was synchronized to the grid. With the exception of minor reductions in power to support routine surveillances, the plant remained at full power for the remainder of the quarter.
REACTOR SAFETY
Cornerstones: Initiating Events, Mitigating Systems, and Barrier Integrity
1R01 Adverse Weather Protection
Readiness for Impending Adverse Weather Condition - Severe High Wind Conditions
a. Inspection Scope
Since thunderstorms with potential tornados and high winds were forecast in the vicinity of the facility for February 24, 2012, the inspectors reviewed the licensees overall preparations/protection for the expected weather conditions. The inspectors walked down the electrical distribution systems for the sites normal offsite power systems and the conditions in the vicinity of the Unit 2 Turbine Building de-construction project. In addition, the licensees emergency alternating current (AC) power systems were walked down because of their safety-related functions which could be affected or required as a result of high winds or tornado-generated missiles, or a general loss of offsite power.
The inspectors evaluated the licensees preparations against the sites procedures and determined that the staffs actions were adequate. During the inspection, the inspectors focused on plant-specific design features and the licensees procedures used to respond to specified adverse weather conditions. The inspectors also toured the plant grounds to look for any loose debris that could become missiles during a tornado. The inspectors evaluated operator staffing and accessibility of controls and indications for those systems required to control the plant. Additionally, the inspectors reviewed the Updated Safety Analysis Report (USAR) and performance requirements for systems selected for inspection, and verified that operator actions were appropriate as specified by plant specific procedures. The inspectors also reviewed a sample of corrective action program (CAP) items to verify that the licensee identified adverse weather issues at an appropriate threshold and dispositioned them through the CAP in accordance with station corrective action procedures. Specific documents reviewed during this inspection are listed in the Attachment to this report.
This inspection constituted one sample for readiness for impending adverse weather conditions as defined in Inspection Procedure (IP) 71111.01-05.
b. Findings
No findings were identified.
1R04 Equipment Alignment
a. Inspection Scope
The inspectors performed partial system walkdowns of the following risk-significant systems:
- high-pressure core spray (HPCS);
- 'A' standby liquid control system;
- 'A' control room ventilation and emergency recirculation system; and
The inspectors selected these systems based on their risk-significance relative to the Reactor Safety Cornerstone at the time they were inspected. The inspectors attempted to identify any discrepancies that could impact the function of the system, and, therefore, potentially increase risk. The inspectors reviewed applicable operating procedures, system diagrams, USAR, Technical Specification (TS) requirements, outstanding work orders, condition reports (CRs), and the impact of ongoing work activities on redundant trains of equipment in order to identify conditions that could have rendered the systems incapable of performing their intended functions. The inspectors also walked down accessible portions of the systems to verify system components and support equipment were aligned correctly and operable. The inspectors examined the material condition of the components and observed operating parameters of equipment to verify that there were no obvious deficiencies. The inspectors also verified that the licensee had properly identified and resolved equipment alignment problems that could cause initiating events or impact the capability of mitigating systems or barriers, and entered them into the CAP with the appropriate significance characterization. Documents reviewed are listed in the
.
These inspections constituted four samples for partial system walkdowns as defined in IP 71111.04-05.
b. Findings
No findings were identified.
1R05 Fire Protection
a. Inspection Scope
The inspectors conducted fire protection walkdowns which were focused on availability, accessibility, and the condition of firefighting equipment in the following risk-significant plant areas:
- Fire Zones 1AB-1a/f/g (Auxiliary Building 574 - Low-Pressure Core Spray (LPCS) room , HPCS room, Hallway);
- Fire Zones 1DG-1c & 1CC-3c (Unit 1 - Division 1 Emergency Diesel Generator (EDG) Room and Division 1 4160V and 480V Switchgear Room);
- Fire Zone 0IB-3 (Intermediate Building 620 Elevation).
The inspectors reviewed areas to assess if the licensee had implemented a fire protection program that adequately controlled combustibles and ignition sources within the plant; effectively maintained fire detection and suppression capability; maintained passive fire protection features in good material condition; and implemented adequate compensatory measures for out-of-service, degraded, or inoperable fire protection equipment, systems, or features in accordance with the licensees fire plan. The inspectors selected fire areas based on their overall contribution to internal fire risk as documented in the plants Individual Plant Examination of External Events with later additional insights, their potential to impact equipment which could initiate or mitigate a plant transient, or their impact on the plants ability to respond to a security event. Using the documents listed in the Attachment, the inspectors verified that fire hoses and extinguishers were in their designated locations and available for immediate use; that fire detectors and sprinklers were unobstructed; that transient material loading was within the analyzed limits; and fire doors, dampers, and penetration seals appeared to be in satisfactory condition. The inspectors also verified that minor issues identified during the inspection were entered into the licensees CAP. Documents reviewed are listed in the Attachment to this report.
These activities constituted five quarterly samples for fire protection as defined in IP 71111.05-05.
b. Findings
No findings were identified.
1R07 Triennial Review of Heat Sink Performance
a. Inspection Scope
The inspectors reviewed operability determinations, completed surveillances, vendor manual information, associated calculations, performance test results, and inspection results associated with the 'B' and 'D' residual heat removal (RHR) heat exchangers, 'B' EDG jacket water cooler, and the 'B' emergency service water (ESW) system. These components were chosen based on their risk significance in the licensees probabilistic safety analysis, their important safety-related mitigating system support functions, and their operating history.
For the selected heat exchangers, the inspectors reviewed testing, inspection, maintenance, and monitoring of biotic fouling and macrofouling programs relied upon to ensure proper heat transfer. This was accomplished by verifying:
- (1) the selected test method was consistent with accepted industry practices, or equivalent;
- (2) the test conditions were consistent with the selected methodology; and
- (3) the test acceptance criteria were consistent with the design basis values. In addition, the inspectors reviewed the results of heat exchanger performance testing and verified that the test results appropriately considered:
- (1) differences between testing conditions and design conditions; and
- (2) test instrument inaccuracies. The inspectors also verified trending of test results to confirm that the test frequency was sufficient to detect degradation prior to loss of heat removal capabilities below design basis values. In addition, the inspectors verified the condition and operation of the heat exchangers were consistent with design assumptions in heat transfer calculations and applicable descriptions in the final safety analysis report. The inspectors verified the licensee evaluated the potential for water hammer and established controls and operational limits to prevent heat exchanger degradation due to excessive flow-induced vibration during operation.
For the ESW system, the inspectors reviewed procedures for a loss of ESW system and verified the instrumentation relied upon for decision making was available and functional.
In addition, the inspectors verified macrofouling and biocide treatments were monitored, trended, and controlled by the licensee to prevent clogging.
The inspectors performed a system walkdown of the ESW system to verify the licensees assessment on structural integrity. In addition, the inspectors reviewed available testing and inspections results, disposition of any active thru wall pipe leaks, and history of thru wall pipe leakage to identify any adverse trends since the last NRC inspection. For buried or inaccessible piping, the inspectors reviewed:
- (1) the pipe testing, inspection, and monitoring program intended to verify structural integrity; and
- (2) the disposition of any identified leakage or degradation. The inspectors verified the licensee monitored and resolved any adverse trends for the deep draft vertical pumps by reviewing the operational history and in-service testing vibration monitoring results.
In addition, the inspectors reviewed CRs related to the heat exchangers and heat sink performance issues to verify the licensee had an appropriate threshold for identifying issues and to evaluate the effectiveness of the corrective actions.
The documents that were reviewed are included in the Attachment to this report.
These inspection activities constituted four heat sink inspection samples as defined in IP 71111.07-05.
b. Findings
No findings were identified.
1R11 Licensed Operator Requalification Program
.1 Resident Inspector Quarterly Review of Licensed Operator Requalification
a. Inspection Scope
On January 30, 2012, the inspectors observed a crew of licensed operators in the plants simulator during licensed operator requalification examinations to verify that operator performance was adequate, evaluators were identifying and documenting crew performance problems, and training was being conducted in accordance with licensee procedures. The inspectors evaluated the following areas:
- licensed operator performance;
- crews clarity and formality of communications;
- ability to take timely actions in the conservative direction;
- prioritization, interpretation, and verification of annunciator alarms;
- correct use and implementation of abnormal and emergency procedures;
- control board manipulations;
- oversight and direction from supervisors; and
- ability to identify and implement appropriate TS actions and Emergency Plan actions and notifications.
The crews performance in these areas was compared to pre-established operator action expectations and successful critical task completion requirements. Documents reviewed are listed in the Attachment to this report.
This inspection constituted one quarterly sample for the licensed operator requalification program as defined in IP 71111.11.
b. Findings
No findings were identified.
.2 Resident Inspector Quarterly Observation of Heightened Activity or Risk
On January 14, 2012, the inspectors observed an unscheduled downpower to 85 percent power as a result of a human error while drilling an injection point into the 'B' feedwater pump drain line. The inspectors observed the control room reactivity control actions and feedwater pump removal from service and isolation procedures. On February 4, 2012, the inspectors observed the activities in the control room during a power reduction to conduct turbine stop valve, combined intermediate valve and bypass valve testing. These were both activities which required heightened awareness or were related to increased risk. The inspectors evaluated the following areas:
- licensed operator performance;
- crews clarity and formality of communications;
- ability to take timely actions in the conservative direction;
- prioritization, interpretation, and verification of annunciator alarms;
- correct use and implementation of procedures;
- control board manipulations;
- oversight and direction from supervisors; and
- ability to identify and implement appropriate TS actions.
The performance in these areas was compared to pre-established operator action expectations, procedural compliance and task completion requirements. Documents reviewed are listed in the Attachment to this report.
This inspection constituted one quarterly sample for licensed operator heightened activity/risk as defined in IP 71111.11.
b. Findings
No findings were identified.
1R12 Maintenance Effectiveness
a. Inspection Scope
The inspectors evaluated degraded performance issues involving the following risk-significant systems:
- Division 1 EDG; and
- diesel generator (DG) room ventilation system.
The inspectors reviewed events such as where ineffective equipment maintenance had resulted or could have resulted in valid or invalid automatic actuations of engineered safeguards systems and independently verified the licensee's actions to address system performance or condition problems in terms of the following:
- implementing appropriate work practices;
- identifying and addressing common cause failures;
- scoping of systems in accordance with 10 CFR 50.65(b) of the maintenance rule;
- characterizing system reliability issues for performance;
- charging unavailability for performance;
- trending key parameters for condition monitoring;
- ensuring 10 CFR 50.65(a)(1) or (a)(2) classification or re-classification; and
- verifying appropriate performance criteria for structures, systems, and components/functions classified as (a)(2), or appropriate and adequate goals and corrective actions for systems classified as (a)(1).
The inspectors assessed performance issues with respect to the reliability, availability, and condition monitoring of the system. In addition, the inspectors verified maintenance effectiveness issues were entered into the CAP with the appropriate significance characterization. Documents reviewed are listed in the Attachment to this report.
This inspection constituted two samples for quarterly maintenance effectiveness as defined in IP 71111.12-05.
b. Findings
No findings were identified.
1R13 Maintenance Risk Assessments and Emergent Work Control
a. Inspection Scope
The inspectors reviewed the licensee's evaluation and management of plant risk for the maintenance and emergent work activities affecting risk-significant and safety-related equipment listed below to verify that the appropriate risk assessments were performed prior to removing equipment for work:
- 'A' train of AEGTS exceeding 50 percent of TS limiting condition for operation (LCO) time;
- 'B' train of RHR system;
- irradiated fuel channel coupon cutting;
- condensate storage tank internal cleaning;
- 'E' average power range monitor (APRM) trip card cleaning; and
- control rod drive transponder box 14-55 cable adjustment.
These activities were selected based on their potential risk significance relative to the Reactor Safety Cornerstones. As applicable for each activity, the inspectors verified that risk assessments were performed as required by 10 CFR 50.65(a)(4) and were accurate and complete. When emergent work was performed, the inspectors verified that the plant risk was promptly reassessed and managed. The inspectors reviewed the scope of maintenance work, discussed the results of the assessment with the licensee's probabilistic risk analyst or shift technical advisor, and verified plant conditions were consistent with the risk assessment. The inspectors also reviewed TS requirements and walked down portions of redundant safety systems, when applicable, to verify risk analysis assumptions were valid and applicable requirements were met.
These maintenance risk assessments and emergent work control activities constituted six samples as defined in IP 71111.13-05.
b. Findings
No findings were identified.
1R15 Operability Determinations and Functionality Assessments
a. Inspection Scope
The inspectors reviewed the following issues:
- activity detected in the nuclear closed cooling system;
- crack on Division 2 EDG turbocharger intercooler support gusset plate;
- HPCS suction piping pressurization through suppression pool cooling lines;
- cracks on DG room fan hubs; and
- leak at the bottom of the 5A intermediate pressure feedwater heater The inspectors selected these potential operability issues based on the risk significance of the associated components and systems. The inspectors evaluated the technical adequacy of the evaluations to ensure that 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 TS and USAR to the licensees 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. The inspectors determined, where appropriate, compliance with bounding limitations associated with the evaluations. Additionally, the inspectors reviewed a sampling of corrective action documents to verify that the licensee was identifying and correcting any deficiencies associated with operability evaluations. Documents reviewed are listed in the to this report.
This operability inspection constituted five samples as defined in IP 71111.15-05.
b. Findings
No findings were identified.
1R18 Plant Modifications
a. Inspection Scope
The inspectors reviewed the following modifications:
- condensate minimum flow valve replacement ; and
- alternate decay heat removal system installation.
The inspectors reviewed the configuration changes and associated 10 CFR 50.59 safety evaluation screening against the design basis, the USAR, and the TS, as applicable, to verify that the modification did not affect the operability or availability of the affected system(s). The inspectors, as applicable, observed ongoing and completed work activities to ensure that the modifications were installed as directed and consistent with the design control documents; the modifications operated as expected; post-modification testing adequately demonstrated continued system operability, availability, and reliability; and that operation of the modifications did not impact the operability of any interfacing systems. As applicable, the inspectors verified that relevant procedure, design, and licensing documents were properly updated. Lastly, the inspectors discussed the plant modification with operations, engineering, and training personnel to ensure that the individuals were aware of how the operation with the plant modification in place could impact overall plant performance. Documents reviewed in the course of this inspection are listed in the Attachment to this report.
This inspection constituted two permanent plant modification samples as defined in IP 71111.18-05.
b. Findings
No findings were identified.
1R19 Post-Maintenance Testing
a. Inspection Scope
The inspectors reviewed the following post-maintenance (PM) activities to verify that procedures and test activities were adequate to ensure system operability and functional capability:
- 'A' AEGTS fan motor replacement during the week of January 2, 2012;
- HPCS waterleg pump motor replacement during the week of January 16, 2012;
- reactor core isolation cooling (RCIC) turbine governor maintenance and oil removal inspection during the week of January 30, 2012;
- RCIC valve work during online outage during the week of January 30, 2012;
- DG room fan hub replacements during the week of March 7, 2012; and
- service water pump 'B' retest after refurbishment during the weeks of March 19 and 26, 2012.
These activities were selected based upon the structure, system, or component's ability to impact risk. The inspectors evaluated these activities for the following (as applicable):
the effect of testing on the plant had been adequately addressed; testing was adequate for the maintenance performed; acceptance criteria were clear and demonstrated operational readiness; test instrumentation was appropriate; tests were performed as written in accordance with properly reviewed and approved procedures; equipment was returned to its operational status following testing (temporary modifications or jumpers required for test performance were properly removed after test completion); and test documentation was properly evaluated. The inspectors evaluated the activities against TS, USAR, 10 CFR Part 50 requirements, licensee procedures, and various NRC generic communications to ensure that the test results adequately ensured that the equipment met the licensing basis and design requirements. In addition, the inspectors reviewed corrective action documents associated with PM tests to determine whether the licensee was identifying problems and entering them in the CAP and that the problems were being corrected commensurate with their importance to safety.
Documents reviewed are listed in the Attachment to this report.
This inspection constituted six PM testing samples as defined in IP 71111.19-05.
b. Findings
No findings were identified.
1R20 Other Outage Activities
a. Inspection Scope
The inspectors evaluated outage activities for a forced outage that began on March 1, 2012, and continued through March 4, 2012. The inspectors reviewed activities to ensure that the licensee considered risk in developing, planning, and implementing the outage schedule.
The inspectors observed or reviewed the reactor shutdown and cooldown, outage equipment configuration and risk management, electrical lineups, selected clearances, control and monitoring of decay heat removal, startup and heatup activities, and identification and resolution of problems associated with the outage. The outage was caused by a generator runback which was precipitated by scheduled work on a manual pressure gauge in the stator water cooling system. When the technicians valved in the pressure gauge after completing calibration of the gauge, the pressure signal to the runback signal generating unit dropped below the setpoint and the runback commenced.
When the third of seven turbine bypass valves opened approximately 40 seconds later, the operators took action to manually scram the reactor as required by Perry operating procedures. The inspectors reviewed the licensee scram report and evaluation of cause for the scram event. Restart decision meetings were attended to ensure the licensee remained focused on plant safety during the decision making process. The licensee discovered that the original maintenance evolution, which caused the outage, should have been yellow risk and that the reclassification as such may have generated further management review and possibly led to a conclusion that the maintenance should not have been done while the reactor was at power.
This inspection constituted one other outage sample as defined in IP 71111.20-05.
b. Findings
Introduction:
A self-revealed finding of very low safety significance (green) with an associated NCV of 10 CFR 50.65(a)(4) was identified for the licensees failure to assess and manage risks associated with maintenance activities. Specifically, the licensee planned and conducted maintenance on a stator water cooling system pressure gauge on March 1, 2012, as a lower risk evolution than required, green risk vice yellow risk, and conducted the maintenance online despite several decision points which indicated that this maintenance should have been conducted with the reactor shutdown.
Description:
On March 1, 2012, the control room authorized maintenance on a local reading pressure gauge in the stator water cooling system. The local reading gauge connects into a common sensing line which also provides pressure input to a stator water low-pressure control room alarm and a generator runback low-pressure detection switch. The challenge of safely restoring this system after calibration of the gauge was identified by the technicians during the pre-job brief and was reinforced by management and the shift supervisors that authorized the work. The evaluation of risk category was not challenged at this point in the process. A general discussion was conducted that this was a high risk to generation evolution during the restoration part of the work. This specific maintenance evolution had not been performed online since original startup.
Other plant gauges have been successfully removed from service, calibrated, and restored to service with the plant online, but not this particular gauge.
The stator water cooling system is scoped into the plant maintenance rule program as a system which is non-safety related but whose failure causes a reactor scram or actuates safety systems. The system is tracked as a whole item with system-wide performance criteria. In accordance with the licensees Nuclear Operating Procedure (NOP)-OP-1007, Risk Management, this maintenance procedure should have been classified as a yellow risk evolution. Specifically, the first question of attachment 3 to the procedure, which was not used (but should have been used) to evaluate the risk of this procedure, states that if an activity which is performed incorrectly would cause a reactor trip, then the work is yellow risk. It is possible that if the system had been classified as yellow risk, further management attention and involvement in the planning may have led to a decision not to conduct the maintenance online because of the increased risk.
An additional unknown issue existed in the plant which posed a challenge to successful completion of this maintenance online. The licensee identified after the fact that undocumented on the system drawing, there is a very fine flow restrictor in the common sensing line which leads to the local gauge which was removed for calibration. The flow restrictor was installed during original construction to minimize pulsations in the line.
Despite the precautions taken by the technicians on March 1, 2012, when the gauge was reconnected to the sensing line and the valve slowly cracked open, the air bubble introduced caused a nearly instantaneous system low-pressure alarm and runback of the main generator. The unidentified flow restrictor installed at initial construction severely limited the ability of the gauge line to re-pressurize and clear the low- pressure indications of the alarm and runback functions. The control room operators responded as required by operations procedures and when conditions were met, inserted a manual scram. The plant responded as expected to the initial event and the subsequent scram.
The licensee entered the issue into the corrective action program as CR 2012-03231 and conducted a root cause evaluation. The plants immediate actions were to stabilize the plant and conduct an evaluation of plant performance during the scram and ensure the cause of the scram was understood.
During the root cause evaluation, the licensee identified a precursor event which could have prevented this entire challenge to plant stability. An engineering change completed in the spring 2011 refueling outage changed the reference point of the gauge that was calibrated in this work procedure so that it would read the pressure at a higher point in the system causing the gauge to read intentionally lower than the pressure actually being sensed by the alarm and runback circuitry. The low reading on the gauge was the initial reason for writing a work package to restore proper calibration. In fact, the gauge was properly calibrated during the outage but not adequately documented in plant procedures after completion of the modification, and thus operations personnel thought it was out of calibration when in fact it was calibrated as desired by engineering.
Analysis:
The inspectors determined that the licensees inadequate actions to assess and manage the risks associated with the maintenance activities did not prevent a transient that upset plant stability, resulting in a manual reactor scram, and was a performance deficiency. Specifically, the licensee planned and conducted maintenance on a stator water cooling system local reading pressure gauge on March 1, 2012, as a lower risk evolution than required, and conducted the maintenance online despite several decision points which indicated that this maintenance should have been conducted with the reactor shutdown. The inspectors evaluated the performance deficiency in accordance with IMC 0612, Appendix B, Issue Screening. This deficiency was determined to be more than minor because it is similar to IMC 0612, Appendix E, Example 7.e and resulted in a reactor scram. Additionally, the performance deficiency impacted the human performance attribute of the Initiating Events Cornerstone, and adversely affected the cornerstone objective to limit the likelihood of events that upset plant stability and challenge critical safety functions during power operations.
The inspectors determined that the finding could be evaluated in accordance with IMC 0609, Appendix K, Maintenance Risk Assessment and Risk Management Significance Determination Process. In accordance with IMC 0609, Appendix K, a Region III Senior Reactor Analyst performed an analysis of the risk deficit for the unevaluated condition associated with work on a stator water system pressure gauge resulting in a reactor scram. The Perry Standardized Plant Analysis Risk (SPAR) model version 8.15 and SAPHIRE version 8.0.7.18 was used to calculate an incremental core damage probability deficit (ICDPD). The result was an ICDPD of less than 7E-8. The dominant core damage sequences involved
- (1) loss of the main condenser, failure of suppression pool cooling, failure of containment spray, failure of the power conversion system, failure of containment venting, and failure of late injection, and
- (2) failure of the reactor protection system to shutdown the reactor with failure of the recirculation pumps to trip. In accordance with IMC 0609, Appendix K, because the calculated ICDPD was not greater than 1E-6, the finding was determined to be of very low safety significance.
This finding has a cross-cutting aspect in the work planning component of the human performance cross-cutting area per IMC 0310 (H.3(a)) because the licensee did not incorporate appropriate risk insights into the development of the work package.
Specifically, the licensee did not evaluate, during the planning phase of the work preparation, for the impact of re-installation of the pressure gauge and the potential for a pressure spike; a spike which caused a sustained runback of the main turbine generator with a resultant required action by the operators to manually scram the reactor.
Enforcement:
Title 10 CFR 50.65(a)(4) requires, in part, that before performing maintenance activities, the licensee shall assess and manage the increase in risk that may result from the maintenance activity. The stator water cooling system is scoped into the licensees maintenance rule program as a non-safety related system whose failure causes a reactor scram. Procedure, NOP-OP-1007, Risk Management, implements the sites program for 10CFR 50.65 and considers scram risk as part of risk activities. A specific question in NOP-OP-1007, Risk Management, directs that maintenance which if performed incorrectly would cause a reactor trip should be classified as yellow risk.
Contrary to the above, on March 1, 2012, the licensee failed to correctly assess and manage the risk associated with maintenance on a gauge in the stator water cooling system. The result of this maintenance was an upset to plant stability caused by a generator runback which ultimately required the operators to insert a manual scram.
Because this violation was determined to be of very low safety significance, and the issue was entered into the licensees corrective action program as CR 2012-03231, this violation is being treated as an NCV consistent with section 2.3.2 of the NRC enforcement policy. (NCV 05000440/2012002-01, Reactor Manual Scram Associated With Inadequate Maintenance Risk Evaluation)
1R22 Surveillance Testing
a. Inspection Scope
The inspectors reviewed the test results for the following activities to determine whether risk-significant systems and equipment were capable of performing their intended safety function and to verify testing was conducted in accordance with applicable procedural and TS requirements:
- LPCS pump and valve in-service testing;
- 'A' standby liquid control system pump and valve routine testing;
- 'B' emergency closed cooling system routine testing;
- Division 1 EDG monthly routine testing; and
- APRM 'E' routine channel calibration.
The inspectors observed in-plant activities and reviewed procedures and associated records to determine the following:
- did preconditioning occur;
- were the effects of the testing adequately addressed by control room personnel or engineers prior to the commencement of the testing;
- were acceptance criteria clearly stated, demonstrated operational readiness, and consistent with the system design basis;
- plant equipment calibration was correct, accurate, and properly documented;
- as-left setpoints were within required ranges, and the calibration frequency were in accordance with TS, USAR, procedures, and applicable commitments;
- measuring and test equipment calibration was current;
- test equipment was used within the required range and accuracy;
- applicable prerequisites described in the test procedures were satisfied;
- test frequencies met TS requirements to demonstrate operability and reliability;
- tests were performed in accordance with the test procedures and other applicable procedures;
- jumpers and lifted leads were controlled and restored where used;
- test data and results were accurate, complete, within limits, and valid;
- test equipment was removed after testing;
- where applicable for inservice testing activities, testing was performed in accordance with the applicable version of Section XI, American Society of Mechanical Engineers Code, and reference values were consistent with the system design basis;
- where applicable, test results not meeting acceptance criteria were addressed with an adequate operability evaluation or the system or component was declared inoperable;
- where applicable, actual conditions encountering high resistance electrical contacts were such that the intended safety function could still be accomplished;
- prior procedure changes had not provided an opportunity to identify problems encountered during the performance of the surveillance or calibration test;
- equipment was returned to a position or status required to support the performance of its safety functions; and
- all problems identified during the testing were appropriately documented and dispositioned in the CAP.
Documents reviewed are listed in the Attachment to this report.
This inspection constituted four samples for routine surveillance testing and one sample for inservice testing as defined in IP 71111.22, Sections -02 and -05.
b. Findings
No findings were identified.
Cornerstone: Emergency Preparedness
1EP6 Drill Evaluation - Training Observation
a. Inspection Scope
The inspectors observed a simulator training evolution for licensed operators on January 30, 2012, which required emergency plan implementation by a licensee operations crew. This evolution was planned to be evaluated and included in performance indicator (PI) data regarding drill and exercise performance. The inspectors observed event classification and notification activities performed by the crew.
The inspectors also attended the post-evolution critique for the scenario. The focus of the inspectors activities was to note any weaknesses and deficiencies in the crews performance and ensure that the licensee evaluators noted the same issues and entered them into the CAP. As part of the inspection, the inspectors reviewed the scenario package and other documents listed in the Attachment to this report.
This inspection of the licensees training evolution with emergency preparedness drill aspects constituted one sample as defined in IP 71114.06-05.
b. Findings
No findings were identified.
OTHER ACTIVITIES
Cornerstones: Initiating Events
4OA1 Performance Indicator Verification
.1 Unplanned Scrams per 7000 Critical Hours
a. Inspection Scope
The inspectors sampled licensee submittals for the Unplanned Scrams per 7000 Critical Hours PI for the period from the first quarter 2011 through the fourth quarter 2011. To determine the accuracy of the PI data reported during those periods, PI definitions and guidance contained in the Nuclear Energy Institute (NEI) Document 99-02, Regulatory Assessment Performance Indicator Guideline, Revision 6, was used. The inspectors reviewed the licensees operator narrative logs, issue reports, event reports, and NRC inspection reports (IRs) for the period of first quarter 2011 through the fourth quarter 2011 to validate the accuracy of the submittals. The inspectors also reviewed the licensees issue report database to determine if any problems had been identified with the PI data collected or transmitted for this indicator and none were identified.
Documents reviewed are listed in the Attachment to this report.
This inspection constituted one sample for unplanned scrams per 7000 critical hours as defined in IP 71151-05.
b. Findings
No findings were identified.
.2 Unplanned Scrams with Complications
a. Inspection Scope
The inspectors sampled licensee submittals for the Unplanned Scrams with Complications PI for the period from first quarter 2011 through the fourth quarter 2011.
To determine the accuracy of the PI data reported during those periods, PI definitions and guidance contained in the NEI Document 99-02, Regulatory Assessment Performance Indicator Guideline, Revision 6, was used. The inspectors reviewed the licensees operator narrative logs, issue reports, event reports, and NRC IRs for the period of first quarter 2011 through the fourth quarter 2011 to validate the accuracy of the submittals. The inspectors also reviewed the licensees issue report database to determine if any problems had been identified with the PI data collected or transmitted for this indicator and none were identified. Documents reviewed are listed in the to this report.
This inspection constituted one sample for unplanned scrams with complications as defined in IP 71151-05.
b. Findings
.
No findings were identified.
.3 Unplanned Transients per 7000 Critical Hours
a. Inspection Scope
The inspectors sampled licensee submittals for the Unplanned Transients per 7000 Critical Hours PI for the period from the first quarter 2011 through the fourth quarter 2011. To determine the accuracy of the PI data reported during those periods, PI definitions and guidance contained in the NEI Document 99-02, Regulatory Assessment Performance Indicator Guideline, Revision 6, was used. The inspectors reviewed the licensees operator narrative logs, issue reports, maintenance rule records, event reports, and NRC IRs for the period of first quarter 2011 through the fourth quarter 2011 to validate the accuracy of the submittals. The inspectors also reviewed the licensees issue report database to determine if any problems had been identified with the PI data collected or transmitted for this indicator and none were identified.
Documents reviewed are listed in the Attachment to this report.
This inspection constituted one sample for unplanned transients per 7000 critical hours as defined in IP 71151-05.
b. Findings
No findings were identified.
4OA2 Identification and Resolution of Problems
.1 Routine Review of Items Entered into the Corrective Action Program
a. Inspection Scope
As part of the various baseline IPs discussed in previous sections of this report, the inspectors routinely reviewed issues during baseline inspection activities and plant status reviews to verify that they were being entered into the licensees CAP at an appropriate threshold, that adequate attention was being given to timely corrective actions, and that adverse trends were identified and addressed. Attributes reviewed included: identification of the problem was complete and accurate; timeliness was commensurate with the safety significance; evaluation and disposition of performance issues, generic implications, common causes, contributing factors, root causes, extent-of-condition reviews, and previous occurrences reviews were proper and adequate; and that the classification, prioritization, focus, and timeliness of corrective actions were commensurate with safety and sufficient to prevent recurrence of the issue.
Minor issues entered into the licensees CAP as a result of the inspectors observations are included in the Attachment to this report.
These routine reviews for the identification and resolution of problems did not constitute any additional inspection samples. Instead, by procedure they were considered an integral part of the inspections performed during the quarter and documented in Section 1 of this report.
b. Findings
No findings were identified.
.2 Daily Corrective Action Program Reviews
a. Inspection Scope
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 licensees CAP. This review was accomplished through inspection of the stations daily CR packages.
These daily reviews were performed by procedure as part of the inspectors daily plant status monitoring activities and, as such, did not constitute any separate inspection samples.
b. Findings
No findings were identified.
.3 Semiannual Trend Review
a. Inspection Scope
The inspectors performed a review of the licensees CAP and associated documents to identify trends that could indicate the existence of a more significant safety issue. The inspectors review was focused on repetitive equipment issues, but also considered the results of daily inspector CAP item screening discussed in Section 4OA2.2 above, licensee trending efforts, and licensee human performance results. The inspectors review nominally considered the 6-month period of July 1, 2011, through December 31, 2011, although some examples expanded beyond those dates where the scope of the trend warranted.
The review also included issues documented outside the normal CAP such as in major equipment problem lists, repetitive and/or rework maintenance lists, departmental problem/challenges lists, system health reports, quality assurance audit/surveillance reports, self assessment reports, and maintenance rule assessments. The inspectors compared and contrasted their results with the results contained in the licensees CAP trending reports. Corrective actions associated with a sample of the issues identified in the licensees trending reports were reviewed for adequacy.
This review constituted one semi-annual trend inspection sample as defined in IP 71152-05.
b. Findings
No findings were identified.
.4 Selected Issue Follow-up Inspection: Ventilation Filter Testing Program
a. Inspection Scope
The inspectors selected the following action requests for an in-depth review:
- CR 2012-00098; Annulus Exhaust Gas Treatment Testing Schedule - Minimizing Out-of-Service Time; and
- CR 2012-02121; Coatings Performed in Aux Building without VOC Evaluation or Work Order.
The inspectors discussed the evaluation and associated corrective actions with licensee personnel and verified the following attributes during their review of the above apparent cause evaluation:
- complete and accurate identification of the problem in a timely manner, commensurate with its safety significance and ease of discovery;
- consideration of the extent of condition, generic implications, common cause and previous occurrences;
- classification and prioritization of the resolution of the problem, commensurate with safety significance;
- identification of the root and contributing causes of the problem; and
- identification of corrective actions, which were appropriately focused to correct the problem.
The inspectors discussed the corrective actions and associated action request evaluations with licensee personnel.
This review constituted one in-depth problem identification and resolution samples as defined in IP 71152-05.
a. Findings
No findings were identified.
4OA3 Follow-up of Events and Notices of Enforcement Discretion
.1 (Closed) Licensee Event Report 05000440/2011-002-01: Condition Prohibited by
Technical Specifications and Plant Shutdown Due to Unit 1 Startup Transformer Issues
a. Inspection Scope
On September 26, 2011, at 0158 hours0.00183 days <br />0.0439 hours <br />2.612434e-4 weeks <br />6.0119e-5 months <br />, the Unit 1 startup transformer (SUT) was taken out of service to perform scheduled maintenance. The licensee considered that the Unit 2 SUT and a manual Unit 1 backfeed capability through the auxiliary transformer satisfied TS 3.8.1 which requires two qualified offsite circuits to be operable. Further review and consultation with the NRC determined that the backfeed lineup was not creditable as a qualified offsite circuit. The review further identified that the TS-required actions for 3.8.1 were not completed as required on September 26, 2011. The transformer was restored to service within the original time period allotted for the LCOs in TS 3.8.1. Subsequently on September 29, 2011, the transformer experienced an internal fault and failed at 0529 hours0.00612 days <br />0.147 hours <br />8.746693e-4 weeks <br />2.012845e-4 months <br />. Since repairs would not be completed during the LCO period, the plant was shut down on October 2, 2011, at 0158 hours0.00183 days <br />0.0439 hours <br />2.612434e-4 weeks <br />6.0119e-5 months <br /> to support repairs to the Unit 1 SUT.
This revision to the licensee event report (LER) was reviewed by the inspectors and no additional findings or violations of NRC requirements were identified. The revision updated information on the failure mechanism of the transformer. The transformer failure mechanism was determined to be an internal flash-over between the B phase bushing corona ring and the grounded tank wall. The flash-over resulted from a low transformer oil dielectric and a damaged corona ring on the B phase transformer high-voltage bushing. Documents reviewed are listed in the Attachment. This LER is closed.
This event follow-up review constituted one sample as defined in IP 71153-05.
b. Findings
No findings were identified.
.2 (Closed) Licensee Event Report 05000440/2011-004-00 and 05000440/2011-004-01:
Flooding Calculation Deficiency Results in Unanalyzed Condition
a. Inspection Scope
On November 16, 2011, at 2000 hours0.0231 days <br />0.556 hours <br />0.00331 weeks <br />7.61e-4 months <br />, after conversations with the NRC, the licensee determined that internal flooding calculation JL-083, Revision 2, Flooding Analysis of CCB, IB, and FHB - Floor Elevation 574-10, contained assumptions regarding operator actions required to isolate a postulated break that were not documented. Specifically, the calculation credited operator actions to perform system isolations, but these actions were not translated to appropriate procedures. The calculation had been performed to address the flooding effects of postulated pipe cracks for moderate energy piping in the intermediate, fuel handling, and control complex buildings. The licensee documented the deficiency in CR 11-05217 and conducted a prompt functionality assessment to determine the appropriate corrective actions, which included implementing a temporary modification to install a temporary flood barrier and instituting an operations night order as an interim action until procedure changes were implemented.
Subsequently, the licensee failed to notify NRC upon discovery of the previously mentioned postulated internal flood in the control complex. The postulated flood scenario could result in the loss of single failure capability of safety-related equipment.
Therefore, the condition met the criteria of 50.72(b)(3)(ii)(B), and should have been reported to the NRC within eight hours of discovery, as an unanalyzed condition that significantly degraded plant safety on November 22, 2011. The licensee entered this issue into their CAP (CR-2011-06227 and CR-2011-06530) and reported the unanalyzed condition at 18:29 (EST) on December 7, 2011.
Planned corrective actions include designing and implementing a permanent 18 inch high flood barrier, revising appropriate procedures to include operator actions necessary to deal with the event, reviewing flooding calculations to ensure necessary actions to mitigate a flood are identified and ensuring that the actions can be performed. The LER and apparent cause evaluation were reviewed by the inspectors. Two violations were previously identified for the failure to make a 50.72 report to the NRC and the design control issue. Both violations are contained in Inspection Report 05000440/2011008; no additional findings or violations of NRC requirements were identified. Documents reviewed are listed in the Attachment. These LERs are closed.
This event follow-up review constituted one sample as defined in IP 71153-05.
b. Findings
No findings were identified.
4OA6 Meetings
.1 Exit Meeting Summary
On April 04, 2012, the inspectors presented the inspection results to the Site Vice President, Mr. Vito Kaminskas, and other members of the licensee staff. The licensee acknowledged the issues presented. The inspectors confirmed that none of the potential report input discussed was considered proprietary. Proprietary material received during the inspection was returned to the licensee.
.2 Interim Exit Meetings
On Friday, March 2, 2012, the inspectors presented the inspection results of the triennial heat sink inspection to the Acting Site Vice President, Mr. Eric Larson, and other members of the licensee staff. The licensee acknowledged the issues presented.
The inspectors confirmed that none of the potential report input discussed was considered proprietary.
ATTACHMENT:
SUPPLEMENTAL INFORMATION
KEY POINTS OF CONTACT
Licensee
- V. Kaminskas, Site Vice President
- E. Larson, Acting Site Vice President
- J. Grabnar, Site Operations Director
- R. Fili, Site Engineering Director
- H. Hanson, Performance Improvement Director
- F. Smith, Emergency Preparedness Manager
- J. Tufts, Operations Manager
- J. Veglia, Maintenance Director
Nuclear Regulatory Commission
- A.M. Stone, DRS Branch Chief
- N. Valos, Senior Reactor Analyst
LIST OF ITEMS
OPENED, CLOSED AND DISCUSSED
Opened And
Closed
- 05000440/2012002-01 NCV Reactor Manual Scram Associated With Inadequate Maintenance Risk Evaluation (Section 1R20)
Closed
- 05000440/2011-002-01 LER Condition Prohibited by Technical Specifications and Plant Shutdown Due to Unit 1 Startup Transformer Issues
- 05000440/2011-004-00 LER Flooding Calculation Results in Unanalyzed Condition
- 05000440/2011-004-01 Attachment