IR 05000373/2009003
| ML092190790 | |
| Person / Time | |
|---|---|
| Site: | LaSalle  |
| Issue date: | 08/07/2009 |
| From: | Kenneth Riemer NRC/RGN-III/DRP/B2 |
| To: | Pardee C Exelon Generation Co, Exelon Nuclear |
| References | |
| IR-09-003 | |
| Download: ML092190790 (45) | |
Text
UNITED STATES ust 7, 2009
SUBJECT:
LASALLE COUNTY STATION, UNITS 1 AND 2 NRC INTEGRATED INSPECTION REPORT 05000373/2009003; 05000374/2009003
Dear Mr. Pardee:
On June 30, 2009, the U.S. Nuclear Regulatory Commission (NRC) completed an inspection at your LaSalle County Station, Units 1 and 2. The enclosed inspection report documents the inspection results, which were discussed on July 21, 2009, with the Site Vice President, Mr. Dave Wozniak, and other members of your staff.
The inspection examined activities conducted under your license as they relate to safety and compliance with the Commissions rules and regulations and with the conditions of your license.
The inspectors reviewed selected procedures and records, observed activities, and interviewed personnel.
Based on the results of this inspection, one finding of very low safety significance was identified.
The NRC is treating this violation as a non-cited violation (NCV) consistent with Section VI.A.1 of the NRC Enforcement Policy because of the very low safety significance of the violation and because it is entered into your corrective action program. In addition, a violation of your Operating License was self-revealed but did not constitute a performance deficiency, and as such, based on management discretion it was determined to have a very low safety significance.
If you contest the subject or severity of an NCV, you should provide a response within 30 days of the date of this inspection report, with the basis for your denial, to the U.S. Nuclear Regulatory Commission, ATTN: Document Control Desk, Washington, DC 20555-0001, with a copy to the Regional Administrator, U.S. Nuclear Regulatory Commission - Region III, 2443 Warrenville Road, Suite 210, Lisle, IL 60532-4352; the Director, Office of Enforcement, U.S. Nuclear Regulatory Commission, Washington, DC 20555-0001; and the Resident Inspector Office at the LaSalle County Station. In addition, if you disagree with the characterization of any finding in this report, you should provide a response within 30 days of the date of this inspection report, with the basis for your disagreement, to the Regional Administrator, Region III, and the NRC Resident Inspector at the LaSalle County Station. The information that you provide will be considered in accordance with Inspection Manual Chapter 0305. In accordance with 10 CFR 2.390 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 (PARS) component of NRC's document system (ADAMS). ADAMS is accessible from the NRC Website at http://www.nrc.gov/reading-rm/adams.html (the Public Electronic Reading Room).
Sincerely,
/RA/
Kenneth Riemer, Chief Branch 2 Division of Reactor Projects Docket Nos. 50-373; 50-374 License Nos. NPF-11; NPF-18 Enclosure: Inspection Report 05000373/2009003; 05000374/2009003 w/Attachment: Supplemental Information cc w/encl: Site Vice President - LaSalle County Station Plant Manager - LaSalle County Station Manager Regulatory Assurance - LaSalle County Station Senior Vice President - Midwest Operations Senior Vice President - Operations Support Vice President - Licensing and Regulatory Affairs Director - Licensing and Regulatory Affairs Manager Licensing - Braidwood, Byron and LaSalle Associate General Counsel Document Control Desk - Licensing Assistant Attorney General J. Klinger, State Liaison Officer, Illinois Emergency Management Agency Chairman, Illinois Commerce Commission
SUMMARY OF FINDINGS
IR 05000373/2009-003, 05000374/2009-003; 4/01/2009 - 6/30/2009; LaSalle County Station,
Units 1 & 2; Fire Protection and Maintenance Effectiveness.
The inspection was conducted by the resident inspectors. The report covers a 3-month period of resident inspection. One Green finding and one violation without performance deficiency were identified, of which all were non-cited violations (NCVs). The significance of most findings is indicated by their color (Green, White, Yellow, Red) using Inspection Manual Chapter (IMC) 0609 Significance Determination Process (SDP). Cross-cutting aspects were determined using IMC 0305, "Operating Reactor Assessment Program." Findings for which the SDP does not apply may be "Green," or be assigned a severity level after NRC management review. The NRC's program for overseeing the safe operation of commercial nuclear power reactors is described in NUREG-1649, "Reactor Oversight Process," Revision 4, dated December 2006.
NRC-Identified
and Self-Revealed Findings
- Green.
A finding of very low safety significance and associated NCV of Technical Specifications (TS) was identified by the inspectors for the failure to implement a fire protection program procedure for combustible controls. Specifically, the inspectors identified three examples where transient combustible materials were staged adjacent to cable risers contrary to the licensees procedure for combustible controls. The licensee subsequently removed the transient combustible materials and entered the issue into their corrective action program (CAP).
The finding was determined to be more than minor because, the finding was similar to IMC 0612, Appendix E, Example 4.k, in that the transient combustibles presented credible fire scenarios, which could affect equipment important to safety. The issue was of very low safety significance because the finding represented a low degradation of the licensees combustible controls program. Additionally, this finding has a cross-cutting aspect in the area of Problem Identification and Resolution (PI&R) for the CAP component because the licensee did not thoroughly evaluate the problem such that the resolution addressed the cause and extent of condition of the problem.
P.1(c) (Section 1R05).
Licensee-Identified Violations
No violations of significance were identified.
REPORT DETAILS
Summary of Plant Status
Unit 1 The unit began the inspection period operating at full power. On May 21, 2009, the reactor scrammed due to a failure of a lightning arrestor in the 1W main power transformer (MPT).
Following repairs, Unit 1 was restarted and on May 25, 2009, the Unit 1 generator was synchronized to the grid. On May 27, 2009, during power ascension to full power, the ganged flow controller associated with the reactor recirculation (RR) flow control valves (FCV)malfunctioned and as a result power rose to 104.6 percent. Power was immediately reduced to less than 100 percent to conduct troubleshooting. Full power was achieved on May 27, 2009.
On May 30, 2009, power was reduced to 78 percent for control rod pattern adjustments and was restored to 100 percent the same day. On June 23, 2009, a fuel leak was identified and as a result power was reduced to 75 percent on June 27, 2009, for power suppression testing. The unit was returned to full power on June 28, 2009, where it remained for the rest of the inspection period.
Unit 2 The unit began the inspection period operating at full power. On April 12, 2009, power was reduced to 83 percent for motor-driven reactor feed pump (MDRFP) testing following maintenance. The unit was returned to full power the same day. On May 21, 2009, due to a scram in Unit 1 that caused several electrical perturbations to both units, two Unit 2 low pressure feedwater heaters shutdown and as such, power was reduced to 84 percent. On May 22, 2009, power was decreased to 65 percent for rod pattern adjustment and the unit was returned to full power the same day. On May 30, 2009, power was reduced to 63 percent for control rod sequence exchange and turbine control valve testing. The unit was returned to full power on May 31, 2009, where it operated 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 AC 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
- notifications 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 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 the 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 which 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 performed a detailed walkdown of the switchyard, relay house and transformer yards to ensure the adequate material condition of all AC power systems and to identify potential hazards such as the existence of loose debris or transient equipment in these areas.
Documents reviewed are listed in the Attachment to this report. 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 CAP 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 of significance 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. Specific documents reviewed during this inspection are listed in the Attachment to this report.
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 CAP procedures. The inspectors reviews focused specifically on the following plant systems:
- diesel generator (DG) room ventilation;
- control room and auxiliary electrical equipment room ventilation; and
- cycled condensate (CY) system tank heaters.
This inspection constituted one seasonal adverse weather sample as defined in IP 71111.01-05.
b. Findings
No findings of significance were identified.
.3 Readiness For Impending Adverse Weather Condition - Severe Thunderstorm Watch
a. Inspection Scope
Since thunderstorms with potential tornados and high winds were forecast in the vicinity of the facility for June 2, 2009, the inspectors reviewed the licensees overall preparations/protection for the expected weather conditions. On June 2, 2009, the inspectors walked down the switchyard and transformer systems, in addition to the licensees emergency alternating current (AC) power systems, because their safety-related functions could be affected or required as a result of high winds or tornado-generated missiles or the loss of offsite power. The inspectors evaluated the licensee staffs preparations against the sites procedures and determined that the staffs actions were adequate. During the inspection, the inspectors focused on plant specific design features and the licensees procedures used to respond to specified adverse weather conditions. The inspectors also toured the plant grounds to look for any loose debris that could become missiles during a tornado. The inspectors evaluated operator staffing and accessibility of controls and indications for those systems required to control the plant. Additionally, the inspectors reviewed the 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 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 CAP procedures. Specific documents reviewed during this inspection are listed in the Attachment to this report.
This inspection constituted one readiness for impending adverse weather condition sample as defined in IP 71111.01-05.
b. Findings
No findings of significance 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 residual heat removal (RHR) train during B/C maintenance window;
- 2B control rod drive (CRD) train during A work window;
- 2B DG; and
- Unit 2 high pressure core spray during reactor core isolation cooling (RCIC) work window.
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, 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 CAP with the appropriate significance characterization. Documents reviewed are listed in the to this report.
These activities constituted four partial system walkdown samples as defined in IP 71111.04-05.
b. Findings
No findings of significance were identified.
.2 Semi-Annual Complete System Walkdown
a. Inspection Scope
On April 18, 2009, the inspectors performed a complete system alignment inspection of Unit 1 and 2s standby gas treatment (SBGT) systems 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. 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 of significance were identified.
1R05 Fire Protection
.1 Routine Resident Inspector Tours
a. Inspection Scope
The inspectors conducted programmatic reviews and fire protection walkdowns which were focused on availability, accessibility, and the condition of firefighting equipment in the following risk-significant plant areas:
- Unit 1 auxiliary electrical equipment room 731 foot elevation (Fire Zone 4E1);
- Unit 2 auxiliary electrical equipment room 731 foot elevation (Fire Zone 4E2);
- Unit 1 turbine building 663 foot elevation (Fire Zone 5E1);
- pre-plan review to ensure all spaces were accurately accounted for;
- Unit 2 reactor building 820 foot elevation (Fire Zone 3B2); and
- Unit 1 reactor building 761 foot elevation (Fire Zone 2E).
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 had 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 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 to this report.
These activities constituted six quarterly fire protection inspection samples as defined in IP 71111.05-05.
b. Findings
- (1) Unauthorized Transient Combustibles
Introduction:
A finding of very low safety significance and associated NCV of TS was identified by the inspectors for the failure to implement a fire protection program procedure for combustible controls. Specifically, the inspectors identified three examples where transient combustible materials were staged adjacent to cable risers contrary to Procedure OP-AA-201-009, Control of Combustible Material, Revision 7.
Description:
On June 24, 2009, during a fire protection walkdown, the inspectors identified three examples of transient combustible material staged adjacent to cable risers in the Unit 1 and Unit 2 reactor buildings. Specifically, the inspectors found a cabinet containing oil absorbing pads that was staged adjacent to safety-related cable risers in the 761 foot elevation of the Unit 2 reactor building. The inspectors also identified a cart with the same contents (oil absorbing pads) in the 761 foot elevation of the Unit 1 reactor building; however, this cart also contained anti-contamination clothing and mop heads. In addition, the inspectors identified a third example in the 820 foot elevation of the Unit 2 reactor building where a maintenance cart containing welding equipment was staged near a safety-related cable riser. The carts containing transient combustible materials described in the three examples were staged less than two feet from the safety-related cable risers. The licensee placed the issue into their CAP as Action Request (AR) 934986, NRC Identified: Transient Combustibles Near Cable Riser and subsequently removed the carts and cabinets with combustible material from all three locations.
Procedure OP-AA-201-009 is the site procedure for combustible controls which, in part, implements the site fire protection program. Procedure OP-AA-201-009, Section 4.4.2, Paragraph 6, directs licensee personnel to avoid staging exposed Class A combustible material immediately adjacent to (i.e., within approximately three feet) cable risers. The inspectors noted that National Fire Protection Association 10, Standard for Portable Fire Extinguishers, defined Class A fires as fires in ordinary combustible materials, such as wood, cloth, paper, rubber, and many plastics. As such, the inspectors considered the identified materials to be Class A materials located in manner contrary to site implementing procedures for the fire protection program.
Analysis:
The inspectors determined that staging combustible materials adjacent to cable risers was contrary to site implementing procedures for the fire protection program and was a performance deficiency. Specifically, the inspectors identified three examples where Class A combustible materials were staged near cable risers contrary to Procedure OP-AA-201-009.
The finding was determined to be more than minor because the finding was similar to IMC 0612, Appendix E, Example 4.k. The Class A transient combustible materials (i.e., oil absorbing pads, anti-contamination clothing, and mop heads) were not in approved temporary storage locations approved by an engineering evaluation.
Specifically, the transient combustibles were located near a wall within the zone of influence for a 200 kilowatt fire for the thermoset cables located within the vertical cable risers (IMC 0609, Appendix F, Fire Protection Significance Determination Process, dated February 28, 2005, Table 2.3.3. Consequently, the transient combustibles created credible fire scenarios that could affect equipment important to safety (such as the safety-related cables and/or cables required for safe shutdown, within the vertical cable risers). Therefore, this performance deficiency impacted the Initiating Events Cornerstone objective of limiting the likelihood of those events that upset plant stability and challenge critical safety functions during plant operations.
The inspectors reviewed IMC 0609, Appendix A, and determined that since the finding affected administrative controls for fire protection, a significance determination evaluation under IMC 0609, Appendix F, was required. The inspectors completed a significance determination of this issue using IMC 0609, Appendix F, Attachment 2, Degradation Rating Guidance Specific to Various Fire Protection Program Elements, dated February 28, 2005. The inspectors determined that the staging of Class A combustibles was a low degradation finding against the combustible controls program because the identified materials would not cause a fire from existing sources of heat or electrical energy. Question 1 of IMC 0609, Appendix F, Task 1.3.1, Qualitative Screening for All Finding Categories, showed that the finding was of very low safety significance (Green) due to the low degradation rating.
This finding has a cross-cutting aspect in the area of PI&R for the CAP component because the licensee did not thoroughly evaluate the problem such that the resolution addressed the cause and extent of condition of the problem. Specifically, on November 2008, the inspectors identified a similar issue where the licensee had staged transient combustibles near safety-related cable risers. A finding, where three examples of unauthorized staging of transient combustibles were identified, was documented in IR 05000373/2008007. (Example P.1(c)).
Enforcement:
Technical Specification, Section 5.4.1 required, in part, that written procedures shall be established, implemented, and maintained for fire protection program implementation. The licensee established Procedure OP-AA-201-009 as the implementing procedure for combustible controls for their fire protection program.
Section 4.4.2, Paragraph 6, of Procedure OP-AA-201-009 directed licensee personnel to avoid staging exposed Class A combustible material immediately adjacent to (i.e., within approximately three feet) cable risers.
Contrary to the above, on June 24, 2009, the licensee failed to implement a procedure for fire protection program implementation in that Class A combustible materials were staged adjacent to cable risers contrary to OP-AA-201-009. Specifically, a cabinet containing oil absorbing pads was located adjacent to safety-related cable risers in the 761 elevation of the Unit 2 reactor building, a cart with oil absorbing pads, anti-contamination clothing and mop heads was adjacent to safety-related cable riser in the 761 elevation of the Unit 1 reactor building and a maintenance cart containing welding equipment was staged near a safety-related cable riser in the 820 elevation of the Unit 2 reactor building. Once identified, the licensee removed the transient combustible materials and entered the issue into their CAP (AR 924268924268. Because this violation was of very low safety significance and it was entered into the licensees corrective action program, this violation is being treated as an NCV, consistent with Section VI.A.1 of the NRC Enforcement Policy (NCV 05000373/2009003-01; 05000374/2009003-01).
1R06 Flood Protection
.1 Internal Flooding
a. Inspection Scope
The inspectors reviewed selected risk important plant design features and licensee procedures intended to protect the plant and its safety related equipment from internal flooding events. The inspectors reviewed flood analyses and design documents, including the UFSAR, engineering calculations, and abnormal operating procedures to identify licensee commitments. The specific documents reviewed are listed in the to this report. In addition, the inspectors reviewed licensee drawings to identify areas and equipment that may be affected by internal flooding caused by the failure or misalignment of nearby sources of water, such as the fire suppression or the circulating water systems. The inspectors also reviewed the licensees corrective action documents with respect to past flood-related items identified in the CAP to verify the adequacy of the corrective actions. The inspectors performed a walkdown of the following plant area to assess the adequacy of watertight doors and verify drains and sumps were clear of debris and were operable, and that the licensee complied with its commitments:
- Units 1 and 2 core standby cooling system rooms.
This inspection constituted one internal flooding sample as defined in IP 71111.06-05.
b. Findings
No findings of significance were identified.
1R11 Licensed Operator Requalification Program
.1 Resident Inspector Quarterly Review
a. Inspection Scope
On June 2, 2009, the inspectors observed a crew of licensed operators in the plants simulator during licensed operator training scenarios to verify that operator performance was adequate, instructors were identifying and documenting crew performance problems and training was being conducted in accordance with licensee procedures. The inspectors evaluated the following areas:
- licensed operator performance;
- crews clarity and formality of communications;
- ability to take timely actions in the conservative direction;
- prioritization, interpretation, and verification of annunciator alarms;
- correct use and implementation of abnormal and emergency procedures;
- control board manipulations;
- oversight and direction from supervisors; and
- ability to identify and implement appropriate TS actions and Emergency Plan actions and notifications.
The crews performance in these areas was compared to pre-established operator action expectations and successful critical task completion requirements. Documents reviewed are listed in the Attachment to this report.
This inspection constituted one quarterly licensed operator requalification program sample as defined in IP 71111.11.
b. Findings
No findings of significance were identified.
1R12 Maintenance Effectiveness
.1 Routine Quarterly Evaluations
a. Inspection Scope
The inspectors evaluated degraded performance issues involving the following risk-significant systems:
- ventilation systems; and
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 or 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
On May 27, 2009, LaSalle Unit 1 was being restored to full power after experiencing a reactor scram on May 21, 2009, due to a failure in the 1W main power transformer.
Control room operators were raising power to full power in 15 MWe increments using the RR system. When power was being raised from approximately 1150 to 1165 MWe, the ganged flow controller associated with the RR FCVs did not respond as expected.
Specifically, the operator noticed that the RR flow continued to increase even though the control room operator was no providing a demand signal to the ganged flow controller.
As a result, the Units power rose above the maximum license-allowed power of 3489 MWth and was greater than 100 percent for one minute. The maximum power recorded by the Plant Process Computer was 104.6 percent. The control room operators immediately lowered power to 98 percent and placed the FCV controllers in manual, defeating the gang flow controllers ability to operate both FCVs simultaneously. The inspectors did not identify a performance deficiency for this event because the control room operators could not have reasonably been able to foresee or prevent this overpower condition since the FCV gang controller spuriously malfunctioned. In addition, the operators responded appropriately by immediately lowering power and entering the appropriate Abnormal Operating Procedures. However, exceeding 3489 MWth is a violation of LaSalles operating license that is greater than minor because, if left uncorrected, it had the potential to lead to a more significant safety concern. In addition, it affects the Barrier Integrity Cornerstone objective of protecting the integrity of the fuel cladding and was associated with the Barrier Integrity Cornerstone attributes of thermal limits and reactivity control. Based on management discretion this violation is of very low safety significance (Green).
LaSalle Operating License Condition C(1) states that the licensee is authorized to operate the facility at reactor core power levels not in excess of full power (3489 MWth).
Contrary to the above, on May 27, 2009, LaSalle Unit 1 reached 104.6 percent power when the RR gang flow controller spuriously malfunctioned while the control room operators were raising power. However, because a performance deficiency was not identified, no enforcement action is warranted for this violation of NRC requirements in accordance with the NRCs Enforcement Policy. Further, because licensee actions did not contribute to this violation, it will not be considered in the assessment process or NRCs Action Matrix.
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:
- yellow risk in both units during Unit 1 Division 3 undervoltage relay calibration and Unit 2 MDRFP outage;
- Unit 1 loss of Division 2 control room annunciators;
- Unit 2 yellow during Division 2 work window;
- 2VR05YA emergent repairs during secondary containment surveillance LOS-SC-01;
- yellow risk during Unit 1 RCIC and low pressure core spray (LPCS) work window; and
- yellow risk during Unit 2 LPCS work window.
These activities were selected based on their potential risk significance relative to the Reactor Safety Cornerstones. As applicable for each activity, the inspectors verified that risk assessments were performed as required by 10 CFR 50.65(a)(4) and were accurate and complete. When emergent work was performed, the inspectors verified that the plant risk was promptly reassessed and managed. The inspectors reviewed the scope of maintenance work, discussed the results of the assessment with the licensee's probabilistic risk analyst or shift technical advisor, and verified plant conditions were consistent with the risk assessment. The inspectors also reviewed TS requirements and walked down portions of redundant safety systems, when applicable, to verify risk analysis assumptions were valid and applicable requirements were met.
These maintenance risk assessments and emergent work control activities constituted six samples as defined in IP 71111.13-05.
b. Findings
No findings of significance were identified.
1R15 Operability Evaluations
.1 Operability Evaluations
a. Inspection Scope
The inspectors reviewed the following issues:
- Unit 2 reactor vessel bottom head drain to reactor water cleanup system degraded flow;
- Unit 1 jet pump 19 flow low;
- 2A RHR pump seal cooler degraded flow;
- 1B RR pump seal degradation;
- 1A DG erratic reactive power output due to oxidized potentiometer; and
- Unit 1 failed fuel indications and subsequent power suppression testing with degraded 1B RR pump seal.
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. 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 also reviewed a sampling of CAP 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 six samples as defined in IP 71111.15-05
b. Findings
No findings of significance were identified.
1R18 Plant Modifications
.1 Temporary Plant Modifications
a. Inspection Scope
The inspectors reviewed the following temporary modification:
- Unit 1 turbine lube oil purification centrifuge following water intrusion into the lube oil reservoir.
The inspectors compared the temporary configuration changes and associated 10 CFR 50.59 screening and evaluation information against the design basis, the UFSAR, and the TS, as applicable, to verify that the modification did not affect the operability or availability of the affected systems. The inspectors also compared the licensees information to operating experience information to ensure that lessons learned from other utilities had been incorporated into the licensees decision to implement the temporary modification. The inspectors, as applicable, performed field verifications to ensure that the modifications were installed as directed; the modifications operated as expected; 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. Lastly, the inspectors discussed the temporary modification with operations, engineering, and training personnel to ensure that the individuals were aware of how extended operation with the temporary modification in place could impact overall plant performance. Documents reviewed in the course of this inspection are listed in the Attachment to this report.
This inspection constituted one temporary modification sample as defined in IP 71111.18-05.
b. Findings
No findings of significance 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:
- 1A DG fuel oil transfer pump;
- 0B diesel fire pump (DFP);
- 2A reactor building closed cooling water (WR) heat exchanger and relief valve leak testing;
- 1B CRD pump;
- 2A RHR seal cooler flow rate test; and
- Unit 2 LPCS testing following breaker and motor clean and inspect.
These activities were selected based upon the structure, system, or component's ability to impact risk. The inspectors evaluated these activities for the following (as applicable):
the effect of testing on the plant had been adequately addressed; testing was adequate for the maintenance performed; acceptance criteria were clear and demonstrated operational readiness; test instrumentation was appropriate; tests were performed as written in accordance with properly reviewed and approved procedures; equipment was returned to its operational status following testing (temporary modifications or jumpers required for test performance were properly removed after test completion), and test documentation was properly evaluated. The inspectors evaluated the activities against TS, the UFSAR, 10 CFR Part 50 requirements, licensee procedures, and various NRC generic communications to ensure that the test results adequately ensured that the equipment met the licensing basis and design requirements. In addition, the inspectors reviewed CAP documents associated with PMT to determine whether the licensee was identifying problems and entering them in the CAP and that the problems were being corrected commensurate with their importance to safety. Documents reviewed are listed in the Attachment to this report.
This inspection constituted six PMT samples as defined in IP 71111.19-05.
b. Findings
No findings of significance 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:
- LOS-MS-M2; Unit 1 main steam isolation valve (MSIV) alternate leakage path verification (Routine);
- LOS-VC-SR2; Control room envelope in-leakage test using tracer gas (Routine);
- LOS-LP-Q1; Unit 2 LPCS inservice test (Routine); and
The inspectors observed in plant activities and reviewed procedures and associated records to determine the following:
- did preconditioning occur;
- were the effects of the testing adequately addressed by control room personnel or engineers prior to the commencement of the testing;
- were acceptance criteria clearly stated, demonstrated operational readiness, and consistent with the system design basis;
- plant equipment calibration was correct, accurate, and properly documented;
- as-left setpoints were within required ranges; and the calibration frequency were in accordance with TSs, the Updated Safety Analysis Report, procedures, and applicable commitments;
- measuring and test equipment calibration was current;
- test equipment was used within the required range and accuracy; applicable prerequisites described in the test procedures were satisfied;
- test frequencies met TS requirements to demonstrate operability and reliability; tests were performed in accordance with the test procedures and other applicable procedures; jumpers and lifted leads were controlled and restored where used;
- test data and results were accurate, complete, within limits, and valid;
- test equipment was removed after testing;
- where applicable for IST 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 three routine surveillance testing samples and one IST sample as defined in IP 71111.22, Sections -02 and -05.
b. Findings
No findings of significance were identified.
1EP6 Drill Evaluation
.1 Emergency Preparedness Drill Observation
a. Inspection Scope
The inspectors evaluated the conduct of a routine licensee emergency drill on June 30, 2009, to identify any weaknesses and deficiencies in classification, notification, and protective action recommendation development activities. The inspectors observed emergency response operations in the control room simulator and technical support center (TSC) to determine whether the event classification, notifications, and protective action recommendations were performed in accordance with procedures. The inspectors also attended the licensee drill critique to compare any inspector-observed weakness with those identified by the licensee staff in order to evaluate the critique and to verify whether the licensee staff was properly identifying weaknesses and entering them into the CAP. As part of the inspection, the inspectors reviewed the drill package and other documents listed in the Attachment to this report.
This emergency preparedness drill inspection constituted one sample as defined in IP 71114.06-05.
b. Findings
No findings of significance were identified.
OTHER ACTIVITIES
Cornerstones: Initiating Events, Mitigating Systems, Barrier Integrity, and Emergency Preparedness
4OA1 Performance Indicator Verification
.1 Reactor Coolant System Specific Activity
a. Inspection Scope
The inspectors sampled licensee submittals for the reactor coolant system (RCS)specific activity performance indicator (PI) for Units 1 and 2 for the period from the second quarter 2008 through the first quarter 2009. To determine the accuracy of the PI data reported during those periods, PI definitions and guidance contained in the Nuclear Energy Institute (NEI) Document 99-02, Regulatory Assessment Performance Indicator Guideline, Revision 5, were used. The inspectors reviewed the licensees RCS chemistry samples, TS requirements, issue reports, event reports and NRC Integrated Inspection Reports for the period of April 2008 through March 2009 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 and none were identified. In addition to record reviews, the inspectors observed a chemistry technician obtain and analyze a RCS sample. Documents reviewed are listed in the Attachment to this report.
This inspection constituted two RCS specific activity samples as defined in IP 71151-05.
b. Findings
No findings of significance were identified.
.2 Reactor Coolant System Leakage
a. Inspection Scope
The inspectors sampled licensee submittals for the RCS Leakage PI for Units 1 and 2 for the period from the second quarter 2008 through the first quarter 2009. 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 5, were used. 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 2008 through March 2009 to validate the accuracy of the submittals. The inspectors also reviewed the licensees issue report database to determine if any problems had been identified with the PI data collected or transmitted for this indicator and none were identified. Documents reviewed are listed in the Attachment to this report.
This inspection constituted two RCS leakage samples as defined in IP 71151-05.
b. Findings
No findings of significance 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
.3 Routine Review of items Entered Into the Corrective Action Program
a. 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 that they were being entered into the licensees CAP at an appropriate threshold, that adequate attention was being given to timely corrective actions, and that adverse trends were identified and addressed. Attributes reviewed included: the complete and accurate identification of the problem; that timeliness was commensurate with the safety significance; that 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 attached List of Documents Reviewed. 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 of significance were identified.
.4 Daily Corrective Action Program Reviews
a. 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 condition 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 of significance were identified.
.5 Semi-Annual Trend Review
a. Scope
The inspectors performed a review of the licensees CAP and associated documents to identify trends that could indicate the existence of a more significant safety issue. The inspectors review was focused on repetitive equipment issues, but also considered the results of daily inspector CAP item screening discussed in Section 4OA2.2 above, licensee trending efforts, and licensee human performance results. The inspectors review nominally considered the six month period of January 2009 through June 2009, 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 and/or rework maintenance lists, departmental problem/challenges lists, system health reports, quality assurance audit/surveillance reports, self assessment reports, and Maintenance Rule assessments. The inspectors compared and contrasted their results with the results contained in the licensees CAP trending reports. Corrective actions associated with a sample of the issues identified in the licensees trending reports were reviewed for adequacy.
This review constituted a single semi-annual trend inspection sample as defined in IP 71152-05.
b. Findings
No findings of significance were identified.
.6 Selected Issue Follow-Up Inspection: Review of Rod Control Management System 50.59
Evaluation
a. Scope
The inspectors reviewed the Rod Control Management System (RCMS), installed in Unit 2 during the spring 2009 refueling outage. The licensee installed the system under the 10 CFR 50.59 process. The inspectors reviewed EC 349628, Rev 9, Replace U2 RMCS/RPIS/RWM with RCMS. Specifically, the inspectors reviewed the architecture, installation, and function of the RCMS. The inspectors also reviewed the associated 50.59 screening and evaluation No. L-06-036, Rev 1. The review focused on the use of guidance documents including NEI 01-01, Guideline on Licensing Digital Upgrades, and NEI 96-07, Guidelines for 10 CFR 50.59 Implementation. The inspectors reviewed various documents and interviewed licensee staff. Additional documents reviewed are listed in the Attachment to this report.
This review constituted one in-depth problem identification and resolution sample as defined in IP 71152-05.
b. Findings
Introduction:
The inspectors identified an unresolved item (URI) associated with a potential failure to conduct an adequate 10 CFR 50.59 evaluation for the U2 RCMS.
This item remains unresolved pending further review by the NRC staff.
Description:
The inspectors identified a URI associated with the 50.59 evaluation for the U2 RCMS. Specifically, Revision 1 of L-06-036 did not specifically address the example questions contained in NEI 01-01 Appendix A, Supplemental Questions for Addressing 10 CFR 50.59 Evaluation Criteria for all allowed fuel loading conditions. The RCMS was designed and built to allow gangs of up to four rods to be moved simultaneously.
The licensee confirmed that the software installed within the RCMS is currently configured to allow control of four rods, but the capability to control more than one rod was disabled, the software password protected and the capability additionally prevented via operating procedures. The inspectors were concerned that the licensee had not properly evaluated questions associated with software common cause failure and the potential for uncommanded withdrawal of four control rods. Subsequently the licensee revised the evaluation and addressed the supplemental questions in Revision 3 of L-06-036, and Revision 11 of EC 349628.
In response to concerns about the potential consequences of uncommanded rod withdrawal, the licensee provided analytic results to the inspection team. These analyses considered spurious, ganged control rod withdrawal in both at-power and low-power/startup conditions and demonstrated acceptable performance following this type of reactivity anomaly for the current fuel cycle.
The at-power analyses consider bundle minimum critical power ratios and fuel enthalpy for comparison to licensing and design limits to demonstrate acceptable fission product barrier performance during the postulated transient. These parameters were evaluated using the MICROBURN-B2 code system. The initial conditions assumed for the transient pertained directly to operating conditions present in or planned for the LSCS Unit 2 13th fuel cycle, which is the current LSCS Unit 2 operating cycle. The analyses assumed that the postulated transients would be terminated by the high flux reactor trip.
The analyses for the at-power conditions demonstrated that the high flux trip would terminate the postulated, spurious, high-worth control rod withdrawal error without exceeding the minimum critical power ratio or the linear heat generation rate safety limits. The inspectors did not identify any significant issues precluding these analyses from justifying continued operation for the current fuel cycle at LSCS Unit 2.
The low-power analyses consider fuel enthalpy as a demonstration of acceptable fission product barrier performance, instead of the linear heat generation rate and minimum critical power ratio, because the fuel enthalpy is a generally accepted indicator for fuel cladding performance at low-power conditions. The licensee used the RAMONA5-FA transient thermal-hydraulic computer code to evaluate the low-power cases, demonstrating that fuel enthalpy addition would not exceed 170 calories per gram for the postulated transients.
These low-power analyses were also specific to the LSCS Unit 2 13th fuel cycle, and the inspection team did not identify any issues precluding these analyses from justifying continued operation in a low-power condition during the LSCS Unit 2 13th fuel cycle, or subsequent restart following an unplanned reactor shutdown during the 13th fuel cycle.
An unresolved item is open pending further review by the NRC staff.
4OA3 Follow-Up of Events and Notices of Enforcement Discretion
.1 Unit 1 Automatic Reactor Scram
a. Inspection Scope
The inspectors responded to the site and reviewed the plants response to a Unit 1 reactor scram on May 21, 2009. With the reactor operating at 100 percent rated thermal power and the mode switch in Run, a lightning arrestor on the 1W main power transformer (MPT) failed resulting in a voltage perturbation on the grid which caused a main generator lockout and subsequent reactor scram. The 1W MPT fire deluge system immediately initiated and put out any resulting fire following the lightning arrestor failure.
Additional complications due to the voltage perturbation included a reactor water cleanup isolation on both units, a reactor building ventilation partial isolation along with a trip of the previously running SBGT train (monthly surveillance was in progress) resulting in a loss of secondary containment operability, a seismic monitoring system trip, a lockup of the 2A RR FCV, and a loss of two strings of low pressure feedwater heaters on Unit 2 which required the licensee to derate Unit 2 to 84 percent. Unit 1 experienced an expected reactor pressure spike when its main turbine stop and control valves shut on the generator/ turbine trip resulting in the S and U safety relief valves (SRVs) lifting and reseating once reactor pressure was lowered. The licensee determined the lightning arrestor shorted due to a manufacturing defect in the component. The lightning arrestor was replaced and the Unit was subsequently restarted on May 25, 2009.
The inspectors observed the operators response from the main control room to the scram and associated complications. The inspectors noted the use of emergency and plant operating procedures and the general environment in the control room. The inspectors also observed the licensees review of the emergency action level matrix for applicability. Documents reviewed in this inspection are listed in the Attachment to this report.
This event follow-up review constituted one sample as defined in IP 71153-05.
b. Findings
No findings of significance were identified.
4OA6 Management Meetings
.1 Exit Meeting Summary
On July 21, 2009, the inspectors presented the inspection results to Mr. D. Wozniak, 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.
4OA7 Licensee-Identified Violations
None.
ATTACHMENT:
SUPPLEMENTAL INFORMATION
KEY POINTS OF CONTACT
Licensee
- D. Wozniak, Site Vice President
- D. Rhoades, Plant Manager
- K. Aleshire, Exelon EP Programs Manager
- D. Amezaga, GL 89-13 Program Owner
- J. Bashor, Site Engineering Director
- L. Blunk, Operations Training Manager
- J.C. Feeney, NOS Lead Assessor
- B. Ginter, Engineering Programs Manager
- F. Gogliotti, System Engineering Senior Manager
- D. Henly, Design Engineer
- W. Hilton, Engineering Supervisor - Mechanical/Structural
- K. Ihnen, Nuclear Oversight Manager
- R. Leasure, Radiation Protection Manager
- S. Marik, Operations Director
- B. Rash, Maintenance Director
- J. Rommel, Design Engineering Senior Manager
- K. Rusley, Emergency Preparedness Manager
- J. Shields, ISI Program Supervisor
- T. Simpkin, Regulatory Assurance Manager
- K. Taber, Work Management Director
- J. Vegara, Regulatory Assurance
- H. Vinyard, Shift Operations Superintendent
- J. White, Site Training Director
- G. Wilhelmsen, Design Manager
- S. Wilkinson, Chemistry Manager
- C. Wilson, Station Security Manager
Nuclear Regulatory Commission
- D. Anthony, NDE Level III
- K. Riemer, Chief, Reactor Projects Branch 2
Attachment
LIST OF ITEMS
OPENED, CLOSED AND DISCUSSED
Opened
- 05000373/2009003-01; NCV Unauthorized Transient Combustibles
- 05000374/2009003-02 URI Review of Rod Control Management System 50.59 Evaluation
Closed
- 05000373/2009003-01; NCV Unauthorized Transient Combustibles
- 05000374/2009003-01 Attachment