IR 05000454/2014003
| ML14206A728 | |
| Person / Time | |
|---|---|
| Site: | Byron  |
| Issue date: | 07/25/2014 |
| From: | Eric Duncan Division Reactor Projects III |
| To: | Pacilio M Exelon Generation Co |
| References | |
| IR-14-003 | |
| Download: ML14206A728 (37) | |
Text
July 25, 2014
SUBJECT:
BYRON STATION, UNITS 1 AND 2, NRC INTEGRATED INSPECTION REPORT 05000454/2014003; 05000455/2014003
Dear Mr. Michael J. Pacilio:
On June 30, 2014, the U.S. Nuclear Regulatory Commission (NRC) completed an integrated inspection at your Byron Station, Units 1 and 2. The enclosed report documents the results of this inspection, which were discussed on July 15, 2014, with Mr. F. Kearney and other members of your staff. The inspectors documented the results of this inspection in the enclosed inspection report.
The NRC inspectors did not identify any findings or violations of more than minor significance.
In accordance with Title 10 of the Code of Federal Regulations 2.390, Public Inspections, Exemptions, Requests for Withholding, of the NRC's "Rules of Practice," a copy of this letter, its enclosure, and your response (if any) will be available electronically for public inspection in the NRC Public Document Room or from the Publicly Available Records System (PARS)
component of NRC's Agencywide Documents Access and Management System (ADAMS).
ADAMS is accessible from the NRC Web site at http://www.nrc.gov/reading-rm/adams.html (the Public Electronic Reading Room).
Sincerely,
/RA/
Eric R. Duncan, Chief Branch 3 Division of Reactor Projects
Docket Nos. 05000454; 05000455 License Nos. NPF-37; NPF-66
Enclosure:
IR 05000454/2014003; 05000455/2014003 w/Attachment: Supplemental Information
REGION III==
Docket Nos:
05000454; 05000455 License Nos:
05000454/2014003; 05000455/2014003 Licensee:
Exelon Generation Company, LLC Facility:
Byron Station, Units 1 and 2 Location:
Byron, IL Dates:
April 1 through June 30, 2014 Inspectors:
J. McGhee, Senior Resident Inspector
J. Draper, Resident Inspector
J. Robbins, Resident Inspector
J. Cassidy, Senior Health Physicist
B. Bartlett, Senior Resident Inspector
J. Benjamin, Senior Resident Inspector
D. Szwarc, Senior Reactor Inspector
C. Thompson, Resident Inspector,
Illinois Emergency Management Agency
Approved by:
E. Duncan, Chief Branch 3 Division of Reactor Projects
SUMMARY OF FINDINGS
Inspection Report 05000454/2014003, 05000455/2014003; 04/01/2014-06/30/2014; Byron
Station, Units 1 & 2; Routine Integrated Inspection.
This report covers a 3-month period of inspection by resident inspectors and announced baseline inspections by regional inspectors. The NRC's program for overseeing the safe operation of commercial nuclear power reactors is described in NUREG-1649, Reactor Oversight Process, Revision 5, dated February 2014.
Inspector-Identified and Self-Revealed Findings No findings were identified.
Licensee-Identified Violations
No violations were identified.
REPORT DETAILS
Summary of Plant Status
Unit 1
The unit began the period at full power and operated at or near full power for the entire inspection period.
Unit 2
The unit began the period at full power and operated at or near full power until April 28, 2014, when a trip of the 2B condensate/condensate booster pump motor with the 2D condensate/condensate booster pump out of service for maintenance resulted in an automatic power reduction (i.e., runback) to 60 percent power. Operators further reduced power to approximately 57 percent to provide margin for feedwater pump suction pressure until one of the condensate/condensate booster pumps could be restored. The 2D condensate/condensate booster pump was returned to service on April 29, 2014, and the unit returned to full power on April 30, 2014. The unit operated at or near full power for the remainder of the inspection period.
REACTOR SAFETY
Cornerstones: Initiating Events, Mitigating Systems, Barrier Integrity and Emergency Preparedness
1R01 Adverse Weather Protection
.1 Readiness of Offsite and Alternate Alternating Current Power Systems
a. Inspection Scope
The inspectors verified that plant features and procedures for operation and continued availability of offsite and alternate alternating current (AC) power systems during adverse weather were appropriate. The inspectors reviewed the licensees procedures affecting these areas and the communications protocols between the Transmission System Operator (TSO) and the plant to verify that the appropriate information was being exchanged when issues arose that could impact the offsite power system.
Examples of aspects considered in the inspectors review included:
- coordination between the TSO and the plant during off-normal or emergency events;
- explanations for the events;
- estimates of when the offsite power system would be returned to a normal state; and
- notification from the TSO to the plant when the offsite power system was returned to normal.
The inspectors also verified that plant procedures addressed measures to monitor and maintain the availability and reliability of both the offsite AC power system and the onsite alternate AC power system prior to or during adverse weather conditions. Specifically, the inspectors verified that licensee procedures addressed the following:
- actions to be taken when notified by the TSO that the post-trip voltage of the offsite power system at the plant would not be acceptable to assure the continued operation of the safety-related loads without transferring to the onsite power supply;
- compensatory actions identified to be performed if it would not be possible to predict the post-trip voltage at the plant for the current grid conditions;
- re-assessment of plant risk based on maintenance activities that could affect grid reliability, or the ability of the transmission system to provide offsite power; and
- communications between the plant and the TSO when changes at the plant could impact the transmission system, or when the capability of the transmission system to provide adequate offsite power was challenged.
The inspectors also reviewed corrective action program (CAP) items to verify that the licensee was identifying adverse weather issues at an appropriate threshold and entering them into their CAP in accordance with station procedures.
This inspection constituted one readiness of offsite and alternate AC power systems sample as defined in Inspection Procedure (IP) 71111.01-05.
b. Findings
No findings were identified.
.2 Summer Seasonal Readiness Preparations
a. Inspection Scope
The inspectors performed a review of the licensees preparations for summer weather for selected systems, including conditions that could lead to an extended drought.
During the inspection, the inspectors focused on plant specific design features and the licensees procedures used to mitigate or respond to adverse weather conditions.
Additionally, the inspectors reviewed the Updated Final Safety Analysis Report (UFSAR)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 CAP items to verify that the licensee was identifying adverse weather issues at an appropriate threshold and entering them into their CAP in accordance with station corrective action procedures. The inspectors reviews focused specifically on the following plant systems:
- Circulating Water System Makeup; and
- System Auxiliary Transformers, Unit Auxiliary Transformers, and Main Power Transformers.
This inspection constituted one seasonal adverse weather sample as defined in IP 71111.01-05.
b. Findings
No findings were identified.
.3 Readiness for Impending Adverse Weather ConditionTornado Watch and Severe
Thunderstorm Warning
a. Inspection Scope
Since thunderstorms with potential tornados and high winds were forecast in the vicinity of the facility for June 30, 2014, the inspectors reviewed the licensees overall preparations and protection for the expected weather conditions. On June 30, 2014, the inspectors walked down the licensees emergency AC power systems because the safety-related functions could be affected as a result of high winds or tornado-generated missiles. The inspectors compared the licensee staffs preparations with the sites procedures and determined whether 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 also reviewed a sample of 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.
This inspection constituted one readiness for impending adverse weather condition sample as defined in IP 71111.01-05.
b. Findings
No findings were identified.
1R04 Equipment Alignment
.1 Quarterly Partial System Walkdowns
a. Inspection Scope
The inspectors performed partial system walkdowns of the following risk-significant systems:
- 2A containment spray (CS) system while the 2B CS system was out of service for planned maintenance;
- 2A emergency diesel generator (EDG) while the 2B EDG was out of service for planned maintenance; and
- 2B auxiliary feedwater (AF) pump and engine following maintenance.
The inspectors selected these systems based on their risk significance relative to the Reactor Safety Cornerstones 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, the UFSAR, Technical Specification (TS) requirements, outstanding work orders (WOs), issue reports, 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.
These activities constituted three partial system walkdown samples as defined in IP 71111.04-05.
b. Findings
No findings were identified.
.2 Semi-Annual Complete System Walkdown
a. Inspection Scope
On June 13, 2014, the inspectors performed a complete system alignment inspection of the 1B AF system to verify the functional capability of the system. This system was selected because it was considered both safety-significant and risk-significant in the licensees probabilistic risk assessment. The inspectors walked down the system to review mechanical and electrical equipment lineups; electrical power availability; system pressure and temperature indications, as appropriate; component labeling; component lubrication; component and equipment cooling; hangers and supports; operability of support systems; and to ensure that ancillary equipment or debris did not interfere with equipment operation. A review of a sample of past and outstanding WOs was performed to determine whether any deficiencies significantly affected the system function. In addition, the inspectors reviewed the CAP database to ensure that system equipment alignment problems were being identified and appropriately resolved.
These activities constituted one complete system walkdown sample as defined in IP 71111.04-05.
b. Findings
No findings were identified.
1R05 Fire Protection
.1 Routine Resident Inspector Tours
a. Inspection Scope
The inspectors conducted fire protection walkdowns that were focused on the availability, accessibility, and condition of firefighting equipment in the following risk-significant plant areas:
- Fire Zone 9.2-2 and 9.3-2, Auxiliary Building, Elevation 401-0, 2A EDG and Day Tank Room;
- Fire Zone 11.4A-2, Auxiliary Building, Elevation 383-0, 2B Auxiliary Diesel Feedwater Pump and Day Tank Room;
- Fire Zone 11.4B-0, Auxiliary Building, Elevation 383-0, Radwaste and Remote Shutdown Panel Ventilation Control Room;
- Fire Zone 11.4C-0, Auxiliary Building, Elevation 383-0, Radwaste and Remote Shutdown Panels;
- Fire Zone 11.4A-1, Auxiliary Building, Elevation 383-0, 1B Auxiliary Diesel Feedwater Pump and Day Tank Room; and
- Fire Zone 9.1-2 and 9.4-2, Auxiliary Building, Elevation 401-0, 2B EDG and Day Tank Room.
The inspectors reviewed these areas and determined whether 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. 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 analyzed limits; and fire doors, dampers, and penetration seals appeared to be in satisfactory condition.
These activities constituted six quarterly fire protection inspection samples as defined in IP 71111.05-05.
b. Findings
No findings were identified.
1R07 Annual Heat Sink Performance
.1 Heat Sink Performance
a. Inspection Scope
The inspectors reviewed the licensees testing of the 1A chemical volume control pump room cubical cooler and the 1B diesel-driven AF pump jacket water heat exchangers to verify that potential deficiencies did not mask the licensees ability to detect degraded performance, to identify any common cause issues that had the potential to increase plant risk, and to ensure that the licensee was adequately addressing problems that could result in initiating events that would cause an increase in plant risk. The inspectors compared the licensees observations with acceptance criteria, the correlation of scheduled testing and the frequency of testing, and the impact of instrument inaccuracies on test results. The inspectors also verified that test acceptance criteria considered differences between design conditions and testing conditions.
This annual heat sink performance inspection constituted one sample 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 April 29, 2014, the inspectors observed a crew of licensed operators in the plants simulator during licensed operator requalification training 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;
- the 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
- the 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.
This inspection constituted one quarterly licensed operator requalification program simulator sample as defined in IP 71111.11.
b. Findings
No findings were identified.
.2 Resident Inspector Quarterly Observation of Heightened Activity or Risk
a. Inspection Scope
On May 1, 2014, the inspectors observed control room operators performing maximum volt-ampere reactive (VAR) testing of the main generator and turbine. This was an activity that required heightened awareness and was related to increased operational risk. The inspectors evaluated the following areas:
- licensed operator performance;
- crews clarity and formality of communications;
- the 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
- the ability to identify and implement appropriate TS actions.
The performance in these areas was compared to pre-established operator action expectations, procedural compliance, and successful task completion requirements.
This inspection constituted one quarterly licensed operator heightened activity/risk sample as defined in IP 71111.11.
b. Findings
No findings were identified.
1R12 Maintenance Effectiveness
.1 Routine Quarterly Evaluations
a. Inspection Scope
The inspectors evaluated degraded performance issues involving the following risk-significant systems:
- 125 Volt Direct Current (VDC) Battery 111;
- Instrument and Service Air Systems; and
- Component Cooling Water (CC) System.
The inspectors reviewed events including those in which ineffective equipment maintenance had 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 (SSCs)/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.
This inspection constituted three quarterly maintenance effectiveness samples as defined in IP 71111.12-05.
b. Findings
No findings were identified.
1R13 Maintenance Risk Assessments and Emergent Work Control
.1 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:
- During the week of April 21, 2014, with the 1B Essential Service Water (SX) and 2B CS pumps out of service, Instrument Bus 212 momentarily failed and the 1B EDG control power fuse failed during connection of a recorder for troubleshooting activities.
- During the week of April 28, 2014, with an extension of a 1B SX room cooler outage, a Unit 0 CC heat exchanger work window was extended to overlap with a residual heat removal (RHR) system work window, and the 2B condensate/condensate booster pump tripped with a subsequent Unit 2 runback to 60 percent power.
- During the week of May 11, 2014, with Unit 2 Instrument Bus 211 direct current battery charger planned maintenance and pressurizer pressure channel testing in progress, the 2B turbine-driven feedwater pump tripped.
- During the week of June 16, 2014, Unit 1 nuclear instrumentation calibrations, 1A solid state protection system testing, and 1A CS system testing were scheduled for Unit 1; and 2A EDG testing was scheduled on Unit 2 concurrent with 2A RHR system maintenance.
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 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 four samples as defined in IP 71111.13-05.
b. Findings
No findings were identified.
1R15 Operability Determinations and Functionality Assessments
.1 Operability Evaluations
a. Inspection Scope
The inspectors reviewed the following issues:
- capacity of the pressurizer power-operated relief valve air accumulators during natural circulation cooldown;
- engineered safety feature cubicle cooler operability with less than all fans available;
- area Radiation Monitor 1AR012J loss of communications to the safety-related monitor;
- control power circuit 0VA01JB supply breaker found open; and
- steam generator low flow isolation valve 1FW039 stroke time near TS limit.
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 UFSAR to the licensees evaluations to determine whether the components or systems were operable. The inspectors determined, where appropriate, compliance with bounding limitations associated with the evaluations.
Additionally, the inspectors reviewed a sample of corrective action documents to verify that the licensee was identifying and correcting any deficiencies associated with operability evaluations.
This operability inspection constituted five samples as defined in IP 71111.15-05.
b. Findings
No findings were identified.
1R18 Plant Modifications
.1 Plant Modifications
a. Inspection Scope
The inspectors reviewed the following modifications:
- EC 389241, Degraded Voltage 5 Minute Timer Resolution-Unit 1; and
The inspectors reviewed the configuration changes and associated 10 CFR 50.59 safety evaluation screening against the design basis, the UFSAR, and the TS, to verify that the modification did not affect the operability or availability of the affected systems. The inspectors, as applicable, observed ongoing and completed work activities to ensure that the modifications were installed as directed and were 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.
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
.1 Post-Maintenance Testing
a. Inspection Scope
The inspectors reviewed the following post-maintenance testing activities to verify that procedures and test activities were adequate to ensure system operability and functional capability:
- Repair hydraulic fluid internal leakage for 2C power operated relief valve; and
- 0B SX makeup pump run following preventative maintenance activities.
These activities were selected based upon the SSC'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; and test documentation was properly evaluated. The inspectors evaluated the activities against TSs, the UFSAR, 10 CFR Part 50 requirements, and licensee procedures 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 post-maintenance tests to determine whether the licensee was identifying problems and entering them into the CAP at the appropriate threshold, and correcting the problems commensurate with their importance to safety.
This inspection constituted two post-maintenance testing samples as defined in IP 71111.19-05.
b. Findings
No findings were identified.
1R22 Surveillance Testing
.1 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:
- Unit 1 reactor coolant system (RCS) water inventory balance surveillance computer calculation;
- 2B solid state protection system surveillance (Routine); and
- Water-tight barrier inspection (Routine).
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, sufficient to demonstrate operational readiness, and consistent with the system design basis;
- was plant equipment calibration correct, accurate, and properly documented;
- were as-left setpoints within required ranges; and was the calibration frequency in accordance with TSs, the UFSAR, plant procedures, and applicable commitments;
- was measuring and test equipment calibration current;
- was the test equipment used within the required range and accuracy, and were prerequisites described in the test procedures satisfied;
- did test frequencies meet TS requirements to demonstrate operability and reliability;
- were tests performed in accordance with the test procedures and other applicable procedures;
- were jumpers and lifted leads controlled and restored where used;
- were test data and results accurate, complete, within limits, and valid;
- was test equipment removed following testing;
- where applicable, for IST activities, was testing performed in accordance with the applicable version of Section XI of the ASME Code, and were reference values consistent with the system design basis;
- was the unavailability of the tested equipment appropriately considered in the performance indicator data;
- where applicable, were test results not meeting acceptance criteria addressed with an adequate operability evaluation, or was the system or component declared inoperable;
- where applicable, for safety-related instrument control surveillance tests, was the reference setting data accurately incorporated into the test procedure;
- was the equipment returned to a position or status required to support the performance of its safety function following testing;
- were all problems identified during the testing appropriately documented and dispositioned in the licensees CAP;
- where applicable, were annunciators and other alarms demonstrated to be functional and were annunciator and alarm setpoints consistent with design documents; and
- where applicable, were alarm response procedure entry points and actions consistent with the plant design and licensing documents.
This inspection constituted two routine surveillance testing samples, three IST samples, and one RCS leak detection inspection sample as defined in IP 71111.22, Sections-02 and-05.
b. Findings
No findings were identified.
1EP6 Drill Evaluation
.1 Emergency Preparedness Drill Observation
a. Inspection Scope
The inspectors evaluated the conduct of two routine licensee emergency drills during this inspection period to identify any weaknesses and deficiencies in classification, notification, and protective action recommendation development activities. The inspectors evaluated a drill on April 17, 2014, involving the licensees B emergency response team and evaluated a drill on May 1, 2014, involving the licensees D emergency response team. The inspectors observed emergency response operations in the control room simulator and the technical support center to determine whether the event classifications, notifications, and protective action recommendations were performed in accordance with procedures. The inspectors also attended the licensee drill critiques to compare any inspector-observed weaknesses with those identified by the licensee staff in order to evaluate the critiques and to verify whether the licensee staff was properly identifying weaknesses and entering them into the CAP.
This inspection constituted two emergency preparedness drill samples as defined in IP 71114.06-05.
b. Findings
No findings were identified.
RADIATION SAFETY
Cornerstones: Occupational and Public Radiation Safety
2RS8 Radioactive Solid Waste Processing and Radioactive Material Handling, Storage, and
Transportation (71124.08) This inspection constituted one complete sample as defined in IP 71124.08-05.
.1 Inspection Planning (02.01)
a. Inspection Scope
The inspectors reviewed the solid radioactive waste system description in the UFSAR, the Process Control Program, and the recent radiological effluent release report for information on the types, amounts, and processing of radioactive waste disposed.
The inspectors reviewed the scope of any quality assurance audits in this area since the last inspection to gain insights into the licensees performance and inform the smart sampling inspection planning.
b. Findings
No findings were identified.
.2 Radioactive Material Storage (02.02)
a. Inspection Scope
The inspectors selected areas where containers of radioactive waste were stored and determined whether the containers were labeled in accordance with 10 CFR 20.1904, Labeling Containers, or controlled in accordance with 10 CFR 20.1905, Exemptions to Labeling Requirements, as appropriate.
The inspectors assessed whether the radioactive material storage areas were controlled and posted in accordance with the requirements of 10 CFR Part 20, Standards for Protection Against Radiation. The inspectors evaluated materials stored or used in the controlled or unrestricted areas and assessed whether they were secured against unauthorized removal and controlled in accordance with 10 CFR 20.1801, Security of Stored Material, and 10 CFR 20.1802, Control of Material Not in Storage, as appropriate.
The inspectors evaluated whether the licensee established a process for monitoring the impact of long-term storage (e.g., buildup of any gases produced by waste decomposition, chemical reactions, container deformation, loss of container integrity, or re-release of free-flowing water) that was sufficient to identify potential unmonitored, unplanned releases or nonconformance with waste disposal requirements.
The inspectors selected containers of stored radioactive material and inspected them for signs of swelling, leakage, or deformation.
b. Findings
No findings were identified.
.3 Radioactive Waste System Walkdown (02.03)
a. Inspection Scope
The inspectors walked down accessible portions of select radioactive waste processing systems to assess whether the current system configuration and operation was consistent with the descriptions in the UFSAR, Offsite Dose Calculation Manual, and Process Control Program.
The inspectors reviewed administrative and/or physical controls (i.e., drainage and isolation of the system from other systems) to assess whether the equipment which was not in service or abandoned in-place would contribute to an unmonitored release path and/or affect operating systems or be a source of unnecessary personnel exposure.
The inspectors assessed whether the licensee reviewed the safety significance of systems and equipment abandoned in place in accordance with 10 CFR 50.59, Changes, Tests, and Experiments.
The inspectors reviewed the adequacy of changes made to the radioactive waste processing systems since the last inspection. The inspectors evaluated whether changes from what was described in the UFSAR were reviewed and documented in accordance with 10 CFR 50.59 as appropriate and to assess the impact on radiation dose to members of the public.
The inspectors selected processes for transferring radioactive waste resin and/or sludge discharges into shipping/disposal containers and assessed whether the waste stream mixing, sampling procedures, and methodology for waste concentration averaging were consistent with the Process Control Program, and provided representative samples of the waste product for the purposes of waste classification as described in 10 CFR 61.55, Waste Classification.
The inspectors evaluated whether the tank recirculation procedures provided sufficient mixing for select systems.
The inspectors assessed whether the licensees Process Control Program correctly described the current methods and procedures for dewatering and waste stabilization (e.g., removal of freestanding liquid).
b. Findings
No findings were identified.
.4 Waste Characterization and Classification (02.04)
a. Inspection Scope
The inspectors selected the following radioactive waste streams for review:
- Dry Active Waste (DAW);
- Cartridge Filters;
- Primary Resin; and
- Primary Filters.
For the waste streams listed above, the inspectors assessed whether the licensees radiochemical sample analysis results (i.e., 10 CFR Part 61" analysis) were sufficient to support radioactive waste characterization as required by 10 CFR Part 61, Licensing Requirements for Land Disposal of Radioactive Waste. The inspectors evaluated whether the licensees use of scaling factors and calculations to account for difficult-to-measure radionuclides was technically sound based on current 10 CFR Part 61 analyses for the selected radioactive waste streams.
The inspectors evaluated whether changes to plant operational parameters were taken into account to:
- (1) maintain the validity of the waste stream composition data between the annual or biennial sample analysis update; and
- (2) ensure that waste shipments continued to meet the requirements of 10 CFR Part 61 for the waste streams selected above.
The inspectors evaluated whether the licensee established and maintained an adequate Quality Assurance Program to ensure compliance with the waste classification and characterization requirements of 10 CFR 61.55 and 10 CFR 61.56, Waste Characteristics.
b. Findings
No findings were identified.
.5 Shipment Preparation (02.05)
a. Inspection Scope
The inspectors reviewed shipment packaging, surveying, labeling, marking, placarding, vehicle checks, emergency instructions, disposal manifest, shipping papers provided to the driver, and licensee verification of shipment readiness. The inspectors assessed whether the requirements of the applicable transport cask certificate of compliance had been met. The inspectors evaluated whether the receiving licensee was authorized to receive the shipment packages. The inspectors evaluated whether the licensees procedures for cask loading and closure procedures were consistent with the vendors currently approved procedures.
The inspectors observed radiation workers during the conduct of radioactive waste processing and radioactive material shipment preparation and receipt activities. The inspectors assessed whether the shippers were knowledgeable of the shipping regulations and whether shipping personnel demonstrated adequate skills to accomplish the package preparation requirements for public transport with respect to:
- NRC Bulletin 79-19, Packaging of Low-Level Radioactive Waste for Transport and Burial, dated August 10, 1979, and
- Title 49 CFR Part 172, Hazardous Materials Table, Special Provisions, Hazardous Materials Communication, Emergency Response Information, Training Requirements, and Security Plans, Subpart H, Training.
Due to limited opportunities for direct observation, the inspectors reviewed the technical instructions presented to workers during routine training. The inspectors assessed whether the licensees training program provided training to personnel responsible for the conduct of radioactive waste processing and radioactive material shipment preparation activities.
b. Findings
No findings were identified.
.6 Shipping Records (02.06)
a. Inspection Scope
The inspectors evaluated whether shipping documents indicated the proper shipping name; emergency response information and a 24-hour contact telephone number; accurate curie content and volume of material; and appropriate waste classification, transport index, and identification number for the following radioactive shipments:
- Radioactive Waste Shipment; RWS-14-001; Cartridge Filters in Cask;
- Radioactive Waste Shipment; RWS-14-007; 20 Shielded Sealand with DAW; and
- Radioactive Material Shipment; RMS-13-009; 40 Sealand with Laundry.
Additionally, the inspectors assessed whether the shipment placarding was consistent with the information in the shipping documentation.
b. Findings
No findings were identified.
.7 Identification and Resolution of Problems (02.07)
a. Inspection Scope
The inspectors assessed whether problems associated with radioactive waste processing, handling, storage, and transportation were identified by the licensee at an appropriate threshold, properly characterized, and properly addressed for resolution in the licensees CAP. Additionally, the inspectors evaluated whether the corrective actions were appropriate for a selected sample of problems documented by the licensee that involved radioactive waste processing, handling, storage, and transportation.
The inspectors the reviewed results of selected audits performed since the last inspection of this program and evaluated the adequacy of the licensees corrective actions for issues identified during those audits.
b. Findings
No findings were identified.
OTHER ACTIVITIES
Cornerstones: Initiating Events, Mitigating Systems, Barrier Integrity, and Emergency Preparedness
4OA1 Performance Indicator Verification
.1 Reactor Coolant System Leakage
a. Inspection Scope
The inspectors sampled licensee submittals for the reactor coolant system (RCS)
Leakage performance indicator (PI) for Unit 1 and Unit 2 for the period from the second quarter of 2013 through the first quarter of 2014. The inspectors used PI guidance contained in Nuclear Energy Institute (NEI) 99-02, Regulatory Assessment Performance Indicator Guideline, Revision 7, dated August 31, 2013, to determine the accuracy of the reported PI data. The inspectors reviewed the licensees operator logs RCS leakage tracking data, issue reports, event reports, and NRC integrated inspection reports for the period of April 1, 2013 through March 31, 2014, to validate the accuracy of the submittals. The inspectors also reviewed the licensees CAP database to determine if any problems had been identified with the PI data collected or transmitted for this indicator.
This inspection constituted two RCS leakage samples as defined in IP 71151-05.
b. Findings
No findings were identified.
4OA2 Identification and Resolution of Problems
Cornerstones: Initiating Events, Mitigating Systems, Barrier Integrity, Emergency Preparedness, Public Radiation Safety, Occupational Radiation Safety, and Physical Protection
.1 Routine Review of Items Entered into the Corrective Action Program
a. Inspection Scope
As part of the various baseline inspection procedures discussed in previous sections of this report, the inspectors routinely reviewed issues during baseline inspection activities and plant status reviews to verify 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 Issue Report 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 Semi-Annual 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 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 December 1, 2013 through May 31, 2014, although some examples expanded beyond those dates where the scope of the trend warranted.
The review also included issues documented outside the normal CAP in major equipment problem lists, repetitive maintenance lists, departmental problem/challenge 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:
Potential Work Hour Rule Violation
a. Inspection Scope
During a review of items entered in the licensees CAP, the inspectors recognized a corrective action item documenting a potential work hour rule violation (non-compliance with 10 CFR 26, Subpart I). A clerk entering hours worked into the station work hour rule tracking database identified that a licensed operator had apparently exceeded the maximum average work hour alternative (i.e.,54-hour Rule) used at Byron Station. All other requirements of the work hour rules were apparently satisfied.
During on-line operations, Byron Station used the averaging requirements of 10 CFR 26.205(d)(7) as an alternative to minimum days off during on-line operations.
The maximum average work hours rule stated that a covered individual may not work more than a weekly average of 54 hours6.25e-4 days <br />0.015 hours <br />8.928571e-5 weeks <br />2.0547e-5 months <br />, calculated using an average period of up to 6 weeks, which advances by 7 consecutive days at the end of every averaging period.
The licensee reviewed site access keycard date/time information to refine the reported information and determined that the original evaluation was overly conservative in logging the hours worked. The licensee determined that the 54-hour average was not exceeded. The inspectors reviewed the keycard data, the individuals work schedule, and the licensees procedures for tracking and documenting work hour rule compliance.
The inspectors concluded that no work hour violation had occurred.
This review constituted one in-depth problem identification and resolution sample as defined in IP 71152-05.
b. Findings
No findings were identified.
4OA3 Follow-Up of Events and Notices of Enforcement Discretion
.1 (Closed) Licensee Event Report (LER) 05000454/2014003-00:
Byron Unit 1 Diesel Generator Actuation Due to System Auxiliary Transformer (SAT) 142-2 Relay Actuation and Loss of Offsite Power (LOOP)
The subject event, which occurred at 11:02 a.m. on Saturday, March 15, 2014, resulted in a loss of offsite power to Unit 1 (i.e., lockout of SAT 142-1 and 142-2) while Unit 1 was in Mode 6 and reactor fuel offload activities were in progress. Both Unit 1 EDGs started in the emergency mode and output breakers closed onto their respective safety-related buses to provide power to safety-related equipment. No fuel movements were in progress at the time and no loads were suspended at the time of the power loss.
In addition, the containment radiation monitor generated a containment isolation signal on loss of power and ventilation components isolated as designed. The event was reported as EN 499919 and the plant response to the event was previously discussed in NRC Integrated IR 05000454/2014002; 05000455/2014002.
Maintenance technicians were replacing relays on the nonsafety-related 6.9 kilovolt (kV)
Bus 158 when the trip occurred. The supply side of this bus was energized from SAT 142-2 at the time. While current transformers normally supplied power to the relay circuits, maintenance procedures utilized test switches to short the current transformers to ground and isolate the relays for testing. The technicians observed that the trip occurred during the installation of the overcurrent relay. Following the bus trip, troubleshooting was conducted to ensure no actual fault condition existed before operators re-energized the SATs, transferred busses back to the normal power alignment, and shutdown the EDGs. The licensee entered the issue into the CAP as Issue Report 1633834.
Inspectors interviewed the maintenance technician that performed the relay replacement and reviewed the work instructions and plant drawings to evaluate the adequacy of the licensees cause evaluation and troubleshooting plan.
The licensees causal review did not identify a definitive root cause for the trip. The root cause team identified the most probable cause as a combination of equipment failures.
The cause evaluation determined that the most probable cause was a test switch failure that allowed an electrical charge to build up in the open but energized current transformer circuit followed by an electrical discharge when the over-current relay was inserted. The licensee postulated that the discharge produced enough current flow to actuate the differential relay resulting in the lockout of the SAT feed breakers. The licensee determined that further troubleshooting of the suspect test switch could not be performed because the switch was not accessible with the SAT energized and the plant configuration did not support de-energizing the SAT. The circuit was verified to be electrically complete and working correctly with the relays installed and the test switch in the LOCAL position. Since the test switch would be moved out of the LOCAL position only for relay testing and administrative controls were in place to restrict switch manipulation, the inspectors determined that there was no impact to the licensees decision to delay further troubleshooting until the next scheduled SAT 142 outage.
Additional actions were implemented to review the scheduling of the relay tasks to ensure that the tasks were scheduled during SAT outage work windows.
If additional troubleshooting challenges the licensees causal evaluation or substantially changes the corrective action, the event reporting guidelines require a supplemental LER be submitted to the NRC. This LER is closed.
This event follow-up review constituted one sample as defined in IP 71153-05.
4OA5 Other Activities
.1 (Closed) Unresolved Item (URI)05000454/2013004-02; 05000455/2013004-02:
Ultimate Heat Sink (UHS) Limiting Design Basis Event As discussed in NRC Integrated IR 05000454/2013004-02; 05000455/2013004-02, the inspectors documented a concern related to the heat removal requirements of the essential service cooling water tower (SXCT). Specifically, the inspectors questioned whether the licensees analysis for a design basis accident on one unit coincident with a shutdown of the non-accident unit was appropriate. This question was documented as URI 05000454/2013004-02; 05000455/2013004-02.
The inspectors reviewed the UFSAR and supporting analyses to understand the heat load impact on the UHS during a design basis accident on one unit coincident with the safe shutdown of the non-accident unit. The inspectors postulated a different heat transfer sequence consisting of a shutdown of the non-accident unit a short time after, but not coincident with a design basis accident on the other unit, which could potentially increase the maximum temperature of the UHS during the event. The licensee entered this issue into their CAP as IR 1524228, NRC Question on the Licensing/Design Bases for the UHS. The licensee concluded that the current licensing basis was clear and that this case was not required to be considered as part of their current licensing basis. The inspectors engaged Office of Nuclear Reactor Regulation (NRR) staff seeking clarification regarding the licensees current licensing basis.
After discussion of the regulatory requirements and the documentation submitted in support of Technical Specification Amendment 54 with the NRR technical staff, the inspectors determined that the Licensing Basis for Byron, as it related to the Ultimate Heat Sink, is as stated in Amendment 54 as approved on May 17, 1993. This URI is closed.
.2 (Closed) URI 05000454/2013004-03; 05000455/2013004-03:
UHS Design Changes As discussed in NRC Integrated IR 05000454/2013004-02; 05000455/2013004-02, the inspectors documented a concern that changes made to the licensing bases description of the SXCTs by the licensee during a design bases reconstitution effort had potentially significantly changed the system design without required prior approval of the NRC.
Specifically, the inspectors questioned changes to the description of the UHS; particularly as associated with a change from a clearly redundant SXCT design to a non-redundant design, without any associated physical SXCT modifications or NRC review and approval.
Original design documents identified that the UHS was designed with sufficient capacity to permit it to perform its safety-related function following a passive failure of one of two SXCTs. In particular, the remaining SXCT was able to provide sufficient cooling to mitigate an accident on one unit coincident with the safe shutdown of the non-accident unit. During a design basis reconstitution of the UHS, the description of the UHS was revised and references to this design redundancy were eliminated. In particular, the final UHS design basis reconstitution report did not mention any intent or need to alter this characteristic of the UHS. Similarly, the safety evaluation associated with the license amendment for the UHS design basis reconstitution did not identify that a change occurred. The licensee entered this issue into their CAP as Issue Report 1551720, NRC Questions Information Provided in 1992. At the end of the inspection period the inspectors were still evaluating whether the change in the description of the SXCTs was reflective of a corresponding change in UHS performance. URI 05000454/2013004-03; 05000455/2013004-03 was opened to track completion of that review.
A review of license amendments associated with the UHS Design Basis Reconstitution was conducted and the inspectors did not identify any case where the licensee specifically sought relief from or was granted relief from the design requirement for redundancy as outlined in Regulatory Guide 1.27, ULTIMATE HEAT SINK FOR NUCLEAR POWER PLANTS, as noted in Revision 1 of UFSAR Section 2.4.11.6, and as noted in Design Analysis ATD-0063, Heat Load to the Ultimate Heat Sink During a Loss of Coolant Accident, Revision 5, Attachment A, Page A4. The inspectors consulted NRR staff regarding the concept of redundancy as discussed in the Regulatory Guide, in particular as it applied to the SXCTs.
The original description of the UHS used plain language to describe the level of redundancy; The ultimate heat sink for the station consists of two redundant essential service [water] cooling towers and basins and their associated makeup systems. This portrayal of the system is readily analyzed; a failure impacting the first tower is non-consequential due to the available capacity of the second (redundant) tower. During the design basis reconstitution effort, the licensee modified the description removing the word redundant and evaluated various equipment failures on a case-by-case basis to verify required redundancy remained available. The inspectors did not identify any cases in which the level of redundancy did not meet regulatory requirements, and therefore no performance deficiency was identified. This URI is closed.
.3 (Closed) URI 05000454/2004005-02; 05000455/2004005-02, Assumption of a Single
Spurious Operation in a Fire Area During the triennial fire protection inspection conducted in 2004, the inspectors identified URI 05000454/2004005-02; 05000455/2004005-02 associated with the licensees application of a single spurious operation per fire area throughout the safe shutdown analysis. Specifically, the licensees position was that their licensing basis only required the consideration of a single spurious operation per fire area during a fire. This did not meet the intent of the requirements of Title 10, Code of Federal Regulations (10 CFR)
Part 50.48(a). As a result, the NRC Region III staff submitted a Task Interface Agreement (TIA) to NRR for an evaluation of the licensees licensing basis with respect to the assumption of a single spurious operation. The NRR staff determined that Byron Station was in compliance with their licensing basis based on specific language in their licensing basis. The NRC had previously accepted, in a safety evaluation report, that the licensee only had to consider one spurious operation for each fire zone. However, the NRR staff also concluded that, from a technical standpoint, the assumption of a single spurious operation was not in compliance with 10 CFR 50.48(a). That determination was documented in TIA 2013-02, Final Response to Task Interface Agreement 2013-02, Single Spurious Assumption for Braidwood and Byron Stations Safe-Shutdown Methodology, dated March 31, 2014 (ADAMS Accession No. ML12194A500). Therefore, the inspectors did not identify a violation of NRC requirements at this time. This URI is closed.
4OA6 Management Meetings
.1
Exit Meeting Summary
On July 15, 2014, the inspectors presented the inspection results to Mr. F. Kearney, Site Vice President, 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.
.2 Interim Exit Meetings
An interim exit was conducted for the inspection conducted for the area of radioactive solid waste processing and radioactive material handling, storage, and transportation with Mr. F. Kearney, Site Vice President, on May 16, 2014.
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.
ATTACHMENT:
SUPPLEMENTAL INFORMATION
KEY POINTS OF CONTACT
Licensee
- F. Kearney, Site Vice President
- T. Chalmers, Plant Manager
- E. Hernandez, Operations Director
- C. Keller, Engineering Director
- J. Fiesel, Maintenance Director
- S. Gackstetter, Regulatory Assurance Manager
- G. Armstrong, Security Manager
- S. Kerr, Training Manager
- L. Zurawski, NRC Coordinator
- B. Barton, Radiation Protection Manager
Nuclear Regulatory Commission
- E. Duncan, Chief, Reactor Projects Branch 3
LIST OF ITEMS
OPENED, CLOSED AND DISCUSSED
Opened
- 05000454/2014003-00 LER Byron Unit 1 Diesel Generator Actuation Due to System Auxiliary Transformer (SAT) 142-2 Relay Actuation and Loss of Offsite Power (LOOP)
Closed
- 05000454/2014003-00 LER Byron Unit 1 Diesel Generator Actuation Due to System Auxiliary Transformer (SAT) 142-2 Relay Actuation and Loss of Offsite Power (LOOP)
- 05000455/2013004-02 URI Ultimate Heat Sink Limiting Design Basis Event
Ultimate Heat Sink (UHS) Design Changes
Assumption of a Single Spurious Operation in a Fire Area