IR 05000237/2017003
| ML17303A276 | |
| Person / Time | |
|---|---|
| Site: | Dresden  |
| Issue date: | 10/30/2017 |
| From: | Jamnes Cameron Reactor Projects Region 3 Branch 4 |
| To: | Bryan Hanson Exelon Generation Co, Exelon Nuclear |
| References | |
| IR 2017003 | |
| Download: ML17303A276 (32) | |
Text
UNITED STATES ober 30, 2017
SUBJECT:
DRESDEN NUCLEAR POWER STATION, UNITS 2 AND 3NRC INTEGRATED INSPECTION REPORT 05000237/2017003 AND 05000249/2017003
Dear Mr. Hanson:
On September 30, 2017, the U.S. Nuclear Regulatory Commission (NRC) completed an integrated inspection at your Dresden Nuclear Power Station, Units 2 and 3. On October 6, 2017, the NRC inspectors discussed the results of this inspection with Mr. P. Karaba and other members of your staff. The results of this inspection are documented in the enclosed report.
The NRC inspectors did not identify any finding or violation of more than minor significance.
This letter, its enclosure, and your response (if any) will be made available for public inspection and copying at http://www.nrc.gov/reading-rm/adams.html and at the NRC Public Document Room in accordance with 10 CFR 2.390, Public Inspections, Exemptions, Request for Withholding.
Sincerely,
/RA/
Jamnes Cameron, Chief Branch 4 Division of Reactor Projects Docket Nos. 50-237; 50-249 License Nos. DPR-19; DPR-25 Enclosure:
IR 05000237/2017003; 05000249/2017003 cc: Distribution via LISTSERV
Letter to Bryan
SUMMARY
Inspection Report 05000237/2017003, 05000249/2017003; 07/01/2017 - 9/30/2017; Dresden
Nuclear Power Station, Units 2 & 3; Integrated Report This report covers a three month period of inspection by resident inspectors and announced baseline inspections by regional inspectors. The U.S. Nuclear Regulatory Commissions (NRC)program for overseeing the safe operation of commercial nuclear power reactors is described in NUREG-1649, Reactor Oversight Process, Revision 6.
The NRC inspectors did not identify any findings or violations of more than minor significance.
REPORT DETAILS
Summary of Plant Status
Unit 2 Unit 2 operated at or near full power until it entered coastdown on August 30, 2017 prior to refueling outage D2R25. On September 26, 2017 with reactor at 88 percent, the 2B reactor recirculation pump tripped due to a failed adjustable speed drive system power cell. Reactor power was lowered to 24 percent in response to this transient. On September 28, 2017, the 2B reactor recirculation loop was recovered and reactor power was increased to 87 percent where it remained until the conclusion of the inspection period.
Unit 3 Unit 3 operated at or near full power for the duration of the inspection period.
REACTOR SAFETY
Cornerstones: Initiating Events, Mitigating Systems, and Barrier Integrity
.1 External Flooding
a. Inspection Scope
The inspectors evaluated the design, material condition, and procedures for coping with the design basis probable maximum flood. The evaluation included a review to check for deviations from the descriptions provided in the Updated Final Safety Analysis Report (UFSAR) for features intended to mitigate the potential for flooding from external factors.
As part of this evaluation, the inspectors checked for obstructions that could prevent draining, checked the material condition of equipment used to implement the licensees flooding strategy and procedures, and determined that barriers required to mitigate the flood were staged and in functional condition. Additionally, the inspectors performed a walkdown of the protected area to identify any modification to the site which would inhibit site drainage during a probable maximum precipitation event or allow water ingress past a barrier. The inspectors also reviewed the abnormal operating procedure for mitigating the design basis flood to ensure it could be implemented as written. Documents reviewed are listed in the Attachment to this report.
This inspection constituted one external flooding sample as defined in Inspection Procedure (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 core spray (CS) with 2B CS out-of-service (OOS);
- U3 emergency diesel generator (EDG) with the 2/3 EDG OOS; and
- 2B CS with Division I and II Unit 2 low pressure coolant injection (LPCI) OOS.
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, UFSAR, Technical Specification (TS) requirements, outstanding work orders (WOs), condition 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 corrective action program (CAP) with the appropriate significance characterization.
Documents reviewed are listed in the Attachment to this report.
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
From September 5-15, 2017, the inspectors performed a complete system alignment inspection of the Unit 3 low pressure coolant injection 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 work orders 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. Documents reviewed are listed in the to this report.
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 which were focused on availability, accessibility, and the condition of firefighting equipment in the following risk-significant plant areas:
- Fire Zone 6.2, Unit 2/3 Comp Room and Auxiliary Electrical Room, Elevation 517;
- Fire Zone 1.1.2.2, Unit 2 Reactor Building, Elevation 517 during hot work operations;
- Fire Zone 8.2.2A, Unit 2 CCSW Pump Area, Elevation 495;
- Fire Zone 1.3.2, Unit 2 Shutdown Cooling Pump Room, Elevation 517; and
- Fire Zone 8.2.8B, Unit 2/3 Reactor Building Ventilation Equipment Area, Elevation 581.
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 to this report, 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 fire protection inspection samples as defined in IP 71111.05-05.
b. Findings
No findings were identified.
1R11 Licensed Operator Requalification Program
.1 Resident Inspector Quarterly Review of Licensed Operator Requalification
a. Inspection Scope
On August 8, 2017 and September 5, 2017, the inspectors observed a crew of licensed operators in the plants simulator during licensed operator requalification training. The inspectors verified that operator performance was adequate, evaluators were identifying and documenting crew performance problems, and that 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 two quarterly licensed operator requalification program simulator samples as defined in IP 71111.11-05.
b. Findings
No findings were identified.
.2 Resident Inspector Quarterly Observation During Periods of Heightened Activity or Risk
(71111.11Q)
a. Inspection Scope
On August 2, 2017, the inspectors observed the operators during a Unit 3 B feed water regulating valve (FWRV) controller failure resulting in level and power excursions. This was an activity that required heightened awareness or was related to increased risk.
Specifically, operators had to control the 3 B FWRV in manual-bypass mode from the main control room operating station ensuring plant power and level remained steady.
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 (if applicable);
- correct use and implementation of procedures;
- control board (or equipment) manipulations;
- oversight and direction from supervisors; and
- ability to identify and implement appropriate TS actions and Emergency Plan actions and notifications (if applicable).
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 licensed operator heightened activity/risk sample as defined in IP 71111.11-05.
b. Findings
No findings were identified.
.3 Annual Operating Test Results
a. Inspection Scope
The inspectors reviewed the overall pass/fail results of the Biennial Written Examination and Annual Operating Test, administered by the licensee from April 26 through June 2, 2017, as required by Title 10 of the Code of Federal Regulations (CFR),
Part 55.59(a). The results were compared to the thresholds established in Inspection Manual Chapter 0609, Appendix I, Licensed Operator Requalification Significance Determination Process (SDP), to assess the overall adequacy of the licensees licensed operator requalification training program to meet the requirements of Title 10 of the Code of Federal Regulations, Part 55.59. (02.02)
This inspection constituted one Annual Licensed Operator Requalification Examination results sample as defined in Inspection Procedure 71111.11-05.
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:
- screen refuse system (scoped into the Maintenance Rule as it is used to cope with a loss of ultimate heat sink casualty) ; and
- Unit 2 core spray (scoped into the Maintenance Rule as a safety-related system).
The inspectors reviewed events such as where 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. Documents reviewed are listed in the Attachment to this report.
This inspection constituted two 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:
- Unit 2 reactor manual control system troubleshooting and system monitoring following rod H-09 inserting one notch without operator demand signal present;
- Emergent repairs of the 2B reactor recirculation pump adjustable speed drive system and restoration of two loop reactor operation.
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 Shift Manager, 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.
Documents reviewed during this inspection are listed in the Attachment to this report.
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 Functional Assessments
.1 Operability Evaluations
a. Inspection Scope
The inspectors reviewed the following issues:
- Unit 3 main steam isolation valve closure bypass key lock switches adverse effect on single fault criteria;
- 2C shutdown cooling pump phase overcurrent relay time out of tolerance;
- 2/3 EDG cooling water pump failure to swap power supplies back to default Unit 2 supply when EDG no longer supplying Unit 3 safety buses;
- 10 CFR Part 21 review for Grayboot connectors; and
- Unit 3 standby liquid control (SLC) with indications of through wall leakage on American Society of Mechanical Engineers (ASME) Code Class 2 piping.
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 Updated Final Safety Analysis Report (UFSAR) 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 Attachment to this report.
This operability inspection constituted five samples as defined in IP 71111.15-05.
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 (PMT) activities to verify that procedures and test activities were adequate to ensure system operability and functional capability:
- Unit 1 diesel fire pump (DFP) following a maintenance window;
- Unit 2 2B core spray (CS) following a maintenance window;
- Unit 3 C/D containment cooling service water (CCSW) vault room cooler following cooler replacement;
- 2/3 emergency diesel generator (EDG) following jacket water system flush; and
- Unit 3 SBLC system following piping and component replacement to fix through wall leak.
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 Technical Specifications (TS), the UFSAR, 10 CFR Part 50 requirements, licensee procedures, and various U.S. Nuclear Regulatory Commission (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 post-maintenance tests to determine whether the licensee was identifying problems and entering them in the corrective action program (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 five PMT samples as defined in IP 71111.19-05.
b. Findings
No findings were identified.
1R20 Outage Activities
.1 Refueling Outage Activities
a. Inspection Scope
The inspectors observed portions of the receipt inspection and final assembly of new reactor fuel in preparation for Unit 2 refueling outage D2R25. The inspectors ensured the licensee followed site procedures for the inspection of new fuel to include those enforcing foreign material exclusion controls.
This inspection performed represents a partial sample of Inspection Procedure 71111.20. The remainder of the inspection sample will be performed in the fourth Quarter 2017 and will be documented in Inspection Report 05000237/2017004 and 05000249/2017004.
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 2 scram discharge volume high level functional test (routine);
- Unit 3 CS pump test with torus availability (routine);
- Unit 3 oscillating power range monitor response time testing (routine);
- Unit 2 Target Rock/Electromatic relief valve pressure switch calibration (routine);and
- Unit 2 EDG endurance run, hot restart, and full load rejection test (routine).
The inspectors observed in-plant activities and reviewed procedures and associated records to determine the following:
- did preconditioning occur;
- the effects of the testing were adequately addressed by control room personnel or engineers prior to the commencement of the testing;
- acceptance criteria were clearly stated, demonstrated operational readiness, and were 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 was in accordance with TSs, the UFSAR, 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 equipment was removed after testing;
- where applicable for in-service 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 for safety-related instrument control surveillance tests, reference setting data were accurately incorporated in the test procedure;
- 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 six routine surveillance testing samples and one in-service test sample as defined in IP 71111.22, Sections-02 and-05.
b. Findings
No findings were identified.
OTHER ACTIVITIES
Cornerstones: Initiating Events, Mitigating Systems, Barrier Integrity, Emergency Preparedness, Public Radiation Safety, Occupational Radiation Safety, and Security
4OA1 Performance Indicator Verification
.1 Mitigating Systems Performance IndexHeat Removal System
a. Inspection Scope
The inspectors sampled licensee submittals for the Mitigating Systems Performance Index - Heat Removal System (MS08) performance indicator for Dresden Nuclear Power Station, Units 2 and 3, for the period from the third quarter of 2016 through the second quarter of 2017. To determine the accuracy of the performance indicator (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 7, dated August 31, 2013, were used. The inspectors reviewed the licensees operator narrative logs, issue reports, event reports and NRC Integrated Inspection Reports for the period of July 1, 2016, through June 30, 2017, to validate the accuracy of the submittals. The inspectors reviewed the Mitigating Systems Performance Index (MSPI) component risk coefficient to determine if it had changed by more than 25 percent in value since the previous inspection, and if so, that the change was in accordance with applicable NEI guidance. 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 two MSPI heat removal system samples as defined in IP 71151-05.
b. Findings
No findings were identified.
.2 Mitigating Systems Performance IndexResidual Heat Removal System
a. Inspection Scope
The inspectors sampled licensee submittals for the MSPI - Residual Heat Removal System (MS09) performance indicator for Dresden Nuclear Power Station, Units 2 and 3, for the period from the third quarter of 2016 through the second quarter of 2017.
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 7, dated August 31, 2013, were used. The inspectors reviewed the licensees operator narrative logs, issue reports, event reports and NRC Integrated Inspection Reports for the period of July 1, 2016, through June 30, 2017, to validate the accuracy of the submittals. The inspectors reviewed the MSPI component risk coefficient to determine if it had changed by more than 25 percent in value since the previous inspection, and if so, that the change was in accordance with applicable NEI guidance. 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 two MSPI residual heat removal system samples as defined in IP 71151-05.
b. Findings
No findings were identified.
.3 Mitigating Systems Performance IndexCooling Water Systems
a. Inspection Scope
The inspectors sampled licensee submittals for the MSPI - Cooling Water Systems (MS10) performance indicator for Dresden Nuclear Power Station, Units 2 and 3, for the period from the third quarter of 2016 through the second quarter of 2017. 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 7, dated August 31, 2013, were used. The inspectors reviewed the licensees operator narrative logs, issue reports, event reports and NRC Integrated Inspection Reports for the period of July 1, 2016, through June 30, 2017, to validate the accuracy of the submittals. The inspectors reviewed the MSPI component risk coefficient to determine if it had changed by more than 25 percent in value since the previous inspection, and if so, that the change was in accordance with applicable NEI guidance. 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 two MSPI cooling water system samples as defined in Inspection Procedure (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 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 corrective action program at an appropriate threshold, adequate attention was being given to timely corrective actions, and adverse trends were identified and addressed. Some minor issues were entered into the licensees corrective action program as a result of the inspectors observations; however, they are not discussed in 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.
b. Findings
No findings were identified.
4OA3 Followup of Events and Notices of Enforcement Discretion
.1 (Opened) Granted Notice of Enforcement Discretion 17-3-001: Limiting Condition for
Operation 3.1.7 Required Action B.1 per TS 3.1.7, Standby Liquid Control System
a. Inspection Scope
The inspectors reviewed the licensees response to and assessment of a through-wall leak that developed on the Unit 3 SLC A pump discharge piping. Specifically, on September 12, 2017, during a system operational pressure test, licensee personnel observed a through-wall leak from the forged body of a 1.5 stainless steel pipe T in the Unit 3 SLC system. The affected component is a part of the ASME Code Class 2 boundary. Due to the piping being ASME Code Class 2, it was required to be immediately isolated in accordance with Technical Requirements Manual 3.4.a, Structural Integrity. Isolating this piping resulted in both trains of the Unit 3 SLC system becoming inoperable as the leak was unisolable from both pumps. With both trains inoperable, the licensee entered Limiting Condition for Operation (LCO) 3.1.7, Required Action B.1 which requires the restoration of at least one train of SLC within 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br />.
The inspectors examined the sites actions to uncover the issue with the Unit 3 SLC system, their actions to address the issue once it was identified, and their compensatory actions associated with the receipt of the Notice of Enforcement Discretion (NOED).
The inspectors also reviewed licensee documents to verify that information contained in the NOED request was accurate. Inspection activities included gathering additional information regarding the licensees bases for requesting the NOED; examining the sites decision-making process for the issue; reviewing the licensees condition evaluation; observing the licensees compensatory actions; and evaluating the licensees operability determination. To correct this issue and exit the NOED, the licensee completed replacement of the affected Unit 3 piping and connections, satisfactorily tested the replaced components, and declared the Unit 3 SLC system operable.
Documents reviewed are listed in the Attachment.
This event follow up review constituted one sample as defined in IP 71153-05.
b. Findings
Introduction:
The inspectors opened an unresolved item associated with a potential noncompliance with TS 3.1.7 Required Action B.1 that occurred on September 12, 2017.
NOED 17-3-001 was granted by the NRC staff agreeing not to enforce compliance with the TS completion time for an additional 35 hours4.050926e-4 days <br />0.00972 hours <br />5.787037e-5 weeks <br />1.33175e-5 months <br />.
Description:
On September 10, 2017, with the Unit 3 SLC system in standby operation, an equipment operator performing rounds noted sodium pentaborate crystallization build-up under piping insulation. The licensee removed the insulation from the potential leak location, and noted a dry sodium pentaborate stain on the back of a forged piping T on the 1.5 stainless steel discharge line of the A SLC pump. The licensee Shift Manager made an immediate operability determination of operable based on the dry nature of the stain and its location being on a forged body, and not at a connection or weld location. The licensees initial evaluation surmised the stain was historical in nature and was from an adjacent valve packing leak. In the event that further investigation of the stain indicated a through-wall leak, the licensee investigated American Society of Mechanical Engineers (ASME) code compliant permanent and temporary repair options, to include the construction of an Engineered Clamp. This method was eventually dismissed as supports required for the clamp would have been impractical based on system configuration. On September 12, 2017, the licensee cleaned the stain off of the piping T and performed a visual inspection for leakage with the system at full operating pressure. During this test, a leak was observed emanating from the body of the piping T. Due to the leak occurring within the ASME Code Class 2 boundary, the licensee was required to isolate it in accordance with Technical Requirements Manual 3.4.a, Structural Integrity. Isolating this piping resulted in both trains of the Unit 3 SLC system becoming inoperable, and therefore the licensee entered LCO 3.1.7, Required Action B.1, with an 8 hour9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> required action. With a through wall leak discovered and the plant in a short duration shutdown LCO, the licensee implemented a repair plan for a permanent piping replacement and requested a NOED from the NRC to complete repairs prior to entering Required Action C.1 and C.2, which require placing the Unit in Mode 3 (hot shutdown) and Mode 4 (cold shutdown) within 12 and 36 hours4.166667e-4 days <br />0.01 hours <br />5.952381e-5 weeks <br />1.3698e-5 months <br />, respectively.
The NRC granted a NOED for an additional 35 hours4.050926e-4 days <br />0.00972 hours <br />5.787037e-5 weeks <br />1.33175e-5 months <br /> at 5:46 p.m. on September 12, 2017. Consistent with NRC policy, the NRC agreed not to enforce compliance with the specific TSs in this instance, but will further review the cause(s) that created the apparent need for enforcement discretion to determine whether there is a performance deficiency, if the issue is more than minor, or if there is a violation of requirements. This issue will be tracked as an unresolved item.
(Unresolved Item 05000249/2017003-01, Granted Notice of Enforcement Discretion 17-3-001: LCO 3.1.7 Required Action B.1 per TS 3.1.7, Standby Liquid Control System)
.2 Unit 2 Single Loop Operations Following a Trip of the 2B Reactor Recirculation Pump
a. Inspection Scope
The inspectors observed the licensees response to the trip of the 2B reactor recirculation pump and the subsequent slow closures of the #1 and #2 turbine control valves. At 1:41 p.m. on September 26, 2017, the 2B reactor recirculation pump tripped due to a failure of the A2 power cell in the adjustable speed drive system. The inspectors reported to the main control room and observed operators manually inserting control rods and subsequently lowering reactor recirculation system flow with the operating 2A reactor recirculation pump in order to avoid the instability region of the boiling water reactor power to flow graph. The inspectors verified licensee actions were in accordance with Technical Specifications and abnormal operating procedures for operation in single loop. Subsequent to the trip of the 2B reactor recirculation pump, the licensee experienced individual slow closure failures of the #1 and #2 turbine control valves. The control valve failures were attributed to loose wiring connections to the servo controller for these valves, which was corrected by the licensee and control valves #1 and #2 were properly tested and recovered for operation. The inspectors validated that the licensee reduced and maintained power < 25 percent in accordance with the Core Operating Limits Report and the Technical Specifications with two failed closed turbine control valves.
This event follow up review constituted one sample as defined in IP 71153-05.
b. Findings
No findings were identified.
4OA6 Management Meetings
.1 Exit Meeting Summary
On October 6, 2017, the inspectors presented the inspection results to Mr. P. Karaba, 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 Meeting Summary
On October 2, 2017, the inspectors reviewed the examination overall pass/fail results with Mr. D. Siuda, Licensed Operator Requal Author and Instructor via telephone. The inspectors confirmed that none of the potential report input discussed was considered proprietary.
ATTACHMENT:
SUPPLEMENTAL INFORMATION
KEY POINTS OF CONTACT
Licensee
- P. Karaba, Site Vice President
- J. Washko, Station Plant Manager
- L. Antos, Manager Site Security
- R. Bauman, Shift Operations Superintendent
- M. Budelier, Senior Engineering Manager
- H. Bush, Radiation Protection Manager
- D. Doggett, Emergency Preparedness Manager
- B. Franzen, Regulatory Assurance Manager
- F. Gogliotti, Director, Site Engineering
- P. Hansett, Operations Director
- S. Matzke, Corrective Action Program Coordinator
- A. McMartin, Manager Site Chemistry, Environment & Radwaste
- J. Quinn, Director, Site Maintenance
- W. Remiasz, Work Control Director
- B. Sampson, Organizational Effectiveness Manager
- D. Siuda, Licensed Operator Requal Author and Instructor
- D. Thomas, Director, Site Training
- D. Walker, Regulatory Assurance - Senior NRC Coordinator
U.S. Nuclear Regulatory Commission
- J. Cameron, Chief, Division of Reactor Projects, Branch 4
- M. Porfirio, Resident Inspector, Illinois Emergency Management Agency
LIST OF ITEMS OPENED, CLOSED, AND DISCUSSED
Opened
- 05000249/2017003-01 URI Granted Notice of Enforcement Discretion 17-3-001:
LCO 3.1.7 Required Action B.1 per TS 3.1.7, Standby Liquid Control System (SLC)