IR 05000373/2011008

IR 05000373-11-008 & 05000374-11-008, on July 11-29, 2011, LaSalle County Station, Biennial Baseline Inspection of the Identification and Resolution of Problems

ML11237A112
Person / Time
Site:	LaSalle
Issue date:	08/25/2011
From:	Kenneth Riemer NRC/RGN-II/DRS/EB2
To:	Pacilio M Exelon Generation Co, Exelon Nuclear
References
IR-11-008
Download: ML11237A112 (30)

Text

ust 25, 2011

SUBJECT:

LASALLE COUNTY STATION UNITS 1 AND 2 PROBLEM IDENTIFICATION AND RESOLUTION INSPECTION REPORT 05000373/2011008; 05000374/2011008

Dear Mr. Pacilio:

On July 29, 2011, the U.S. Nuclear Regulatory Commission (NRC) completed a Problem Identification and Resolution (PI&R) inspection at LaSalle County Station Units 1 and 2.

The enclosed report documents the inspection results, which were discussed on April 29, 2011, with the Plant Manager, Mr. Peter Karaba, 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.

The inspection concluded that your staff was effective at identifying problems and incorporating them into the corrective action program. In general, issues were appropriately prioritized, evaluated, and corrected, audits and self-assessments were thorough and probing, and operating experience was appropriately screened and disseminated. Your staff was aware of the importance of having a strong safety-conscious work environment and expressed a willingness to raise safety issues.

Based on the results of this inspection, two NRC-identified findings of very low safety significance were identified. The findings involved violations of NRC requirements. However, because of their very low safety significance, and because the issues were entered into your corrective action program, the NRC is treating the issues as non-cited violations (NCVs) in accordance with Section 2.3.2 of the NRC Enforcement Policy.

If you contest the subject or severity of any of these NCVs, 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 cross-cutting aspect assigned to 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 LaSalle County Station.

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 System (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 05000373/2011008; 05000374/2011008 w/Attachment: Supplemental Information

REGION III==

Docket Nos: 50-373; 50-374 License Nos: NPF-11; NPF-18 Report No: 05000373/2011008; 05000374/2011008 Licensee: Exelon Generating Company, LLC Facility: LaSalle County Station, Units 1 and 2 Location: Marseilles, IL Dates: July 11 - 29, 2011 Inspectors: N. Shah, Project Engineer - Team Lead R. Ruiz, Senior Resident Inspector - LaSalle P. Smagacz, Reactor Engineer R. Edwards, Reactor Engineer J. Yesinowski, Illinois Dept. of Emergency Management Approved by: Kenneth Riemer, Chief Branch 2 Division of Reactor Projects Enclosure

SUMMARY OF FINDINGS

IR 05000373/2011008; 05000374/2011008 (July 11 - 29, 2011), LaSalle County Station;

Biennial Baseline Inspection of the Identification and Resolution of Problems.

This team inspection was performed by three regional inspectors and the senior resident inspector. Two Green findings and two Severity Level IV violations were identified by the inspectors. These findings were considered non-cited violations (NCVs) of Nuclear Regulatory Commission (NRC) regulations. The significance of most findings is indicated by their color (Green, White, Yellow, Red) using Inspection Manual Chapter (IMC) 0609, Significance Determination Process (SDP); the cross-cutting aspects were determined using IMC 0310,

Components Within the Cross-Cutting Areas. Findings for which the SDP does not apply may be Green or be assigned a severity level after NRC management review. The NRCs program for overseeing the safe operation of commercial nuclear power reactors is described in Nuclear Regulatory Guide (NUREG) 1649, Reactor Oversight Process, Revision 4, dated December 2006.

Identification and Resolution of Problems Overall, the corrective action program (CAP) was appropriately identifying, evaluating, and correcting issues. Workers were generally encouraged to raise issues and felt comfortable doing so. Operating experience was recognized as valuable and was being well communicated.

The Nuclear Oversight (NOS) group was maintaining a good oversight role and self-assessments were generally good.

However, there were several examples of inadequate Effectiveness Reviews and two examples where corrective actions were either not timely or inadequate. These issues were entered into the licensees CAP for resolution.

The licensee had a strong safety culture and workers were comfortable with raising issues with station management. However, the inspectors had some observations regarding the efficacy of the safety culture surveys and the licensees monitoring of contractor employee concern programs (ECP). These issues were also documented in the licensees CAP.

NRC-Identified

and Self-Revealed Findings

Cornerstone: Mitigating Systems

Green.

A finding of very low safety significance (Green) and associated non-cited violation of Technical Specifications (TS) was identified by the inspectors for the licensees failure to follow station procedure OP-AA-108-115,

Operability Determinations, Revisions 8 and 10. Specifically, the licensee failed to follow their operability determination procedure during loss of shutdown cooling (SDC)events occurring on July 20, 2009, and February 2, 2011. These events were caused by the closure of the residual heat removal (RHR) common suction valve. These events also resulted in the violation of TS 3.4.9, 3.4.10, and 3.0.2. The licensee entered this issue into its CAP as Issue Report (IR) 1248293.

The finding was considered more than minor because it was associated with the Mitigating Systems Cornerstone attribute of Equipment Performance and affected the cornerstone objective of ensuring the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences (i.e., core damage). Specifically, failing to follow the Operability Determinations procedure caused the licensee to incorrectly assess the RHR SDC systems capability to perform its safety function, and also led the licensee to make a specific TS required isolation feature unavailable. This finding has a cross-cutting aspect in the area of human performance, decision making, because the licensee used non-conservative assumptions when confronted with unexpected system failures. H.1(b) (Section 4OA2.1(1))

Green.

A finding of very low safety significance and associated NCV of 10 CFR 50,

Appendix B, Criterion XVI, Corrective Action, was identified by the inspectors for the licensees failure to develop and implement adequate corrective action to prevent recurrence (CAPR) in response to a significant condition adverse to quality (SCAQ)associated with work activities on the 1D RHR service water (WS) pump. The licensee entered this issue into their CAP as IR 1241118.

The finding was considered more than minor because it impacted the Reactor Safety Mitigating Systems Cornerstone objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences and affected the cornerstone attribute of Equipment Performance.

Specifically, the inadequate corrective action allowed for recurrence of this issue during similar work on other safety-related components. A cross-cutting aspect associated with Problem Identification and Resolution was also assigned to this finding. P.1(d)

(Section 4OA2.1(3))

Licensee-Identified Violations

None.

REPORT DETAILS

4OA2 Problem Identification and Resolution

The activities documented in Sections

.1 through .4 constituted one biennial sample of

Problem Identification and Resolution (PI&R) as defined in Inspection Procedure (IP) 71152.

.1 Assessment of the Corrective Action Program Effectiveness

a. Inspection Scope

The inspectors reviewed the licensees CAP implementing procedures and attended selected CAP program meetings to assess the implementation of the CAP by site personnel.

The inspectors reviewed risk and safety-significant issues in the licensees CAP since the last NRC PI&R inspection in 2009. The items selected ensured an adequate review of issues across the NRC cornerstones. The inspectors used issues identified through NRC generic communications, department self-assessments, licensee audits, operating experience reports, and NRC-documented findings as sources to select issues.

Additionally, the inspectors reviewed CAP items generated as a result of licensee staff performance in daily plant activities. The inspectors also reviewed CAP items and a selection of completed investigations from the licensees various investigation methods, including apparent (ACE), common (CCE) and root cause (RCE) evaluations.

The inspectors performed a more extensive review of licensee efforts to resolve seal failures on the recirculation pumps and fuel failures on units 1 and 2. These reviews consisted of a five year search of related issues identified in the CAP and discussions with appropriate licensee staff to assess the licensees efforts in addressing identified concerns.

The inspectors attended meetings of the Station Oversight (SOC) and Management Review Committees (MRC) to observe how issues were being screened and evaluated and to obtain insights into the licensees oversight of the CAP program.

During the reviews, the inspectors evaluated whether the licensees actions were in compliance with the facilitys CAP and 10 CFR Part 50, Appendix B requirements.

Specifically, the inspectors evaluated if licensee personnel were identifying plant issues at the proper threshold, entering the plant issues into the stations CAP in a timely manner, and assigning the appropriate prioritization for resolution of the issues.

The inspectors also assessed whether the licensee staff assigned the appropriate investigation method to ensure the proper determination of root, apparent, and contributing causes. The inspectors also reviewed the timeliness and effectiveness of corrective actions for selected IRs, completed investigations, and NRC findings, including NCVs.

b. Assessment

(1) Effectiveness of Problem Identification Issues were generally being identified at a low threshold, evaluated appropriately, and corrected in the CAP. Workers were familiar with the CAP and felt comfortable raising concerns. This was evident by the large number of CAP items generated annually; which were reasonably distributed across the various departments. A shared, computerized database was used for creating individual reports and for subsequent management of the processes of issue evaluation and response. These processes included determining the issues significance, addressing such matters as regulatory compliance and reporting, and assigning any actions deemed necessary or appropriate.

The inspectors determined that the station was generally effective at trending low level issues to prevent larger issues from developing. A review of specific trend evaluations did not identify any concerns.

Findings Technical Specification Violation Due to Failures to Follow Operability Determinations Procedure

Introduction:

A finding of very low safety significance (Green) and associated non-cited violation of TS was identified by the inspectors for the licensees failure to follow station procedure OP-AA-108-115, Operability Determinations, Revisions 8 and 10.

Description:

The inspectors identified that the licensee had failed to follow their operability determination procedure during loss of SDC events occurring on July 20, 2009, and February 2, 2011. These events were caused by the closure of the RHR common suction valve. These events also resulted in the violation of TS 3.4.9, 3.4.10, and 3.0.2.

As background, in 1990 the licensee had experienced a spurious closure of the RHR common suction valve resulting in a loss of SDC. This valve was required to close upon a high pressure/high flow condition that may be indicative of a pipe break. The licensee identified that a sudden perturbation in RHR suction flow (such as by starting a pump)likely caused the spurious closure of the valve due to a perceived high flow condition by the controlling relay. To prevent this, the licensee installed new relays with a one second time delay. The licensee also revised applicable procedures to allow for the installation of jumpers to bypass the relay (preventing valve closure). These jumpers were then removed in order to restore the high pressure/high flow isolation function.

On July 20, 2009, Unit 1 was in cold shutdown (Mode 4) with the A train of the RHR system operating in the SDC configuration. For dose reduction purposes, the licensee chose to also start the B loop of RHR. Prior to the start, the licensee had jumpered out the relay to prevent spurious closure of the common suction valve.

Once both pumps were running, the licensee removed the jumper.

During the removal, technicians noted a spark from the jumper to the relay; no other abnormal indications were observed. The technicians finished removing the jumper, secured the panel, verified the relay position was correct, and left the area.

Within one minute of leaving, bystanders heard the relay change state, and the control room observed the closure of the 1E12-F009 common suction isolation valve. With the valve closed, both RHR SDC pumps tripped and a complete loss of SDC occurred.

The control room operators entered LOA-RH-101, Unit 1 RHR Abnormal, Revision 11, and checked for any decrease in reactor vessel level, inspected the RHR SDC suction piping outside the drywell for leakage, determined the isolation was spurious, reset the containment isolation logic, re-opened the suction valve, and restarted the A RHR pump. The licensee later attributed the valve closure to degradation of the relay exacerbated by the sparking occurring during removal of the jumpers.

The licensee did not consider RHR SDC inoperable during this event, as it was able to be manually restored within two hours. This was based on their interpretation of the Bases for TS 3.4.10 which permitted both RHR SDC subsystems and recirculation pumps to not be in operation for a period of 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> in an 8 hour9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> period. However, this interpretation was erroneous, as this statement was not intended for troubleshooting activities. This was confirmed by the inspectors during a discussion with NRC technical staff in the office of Nuclear Reactor Regulation.

The licensee should have declared RHR SDC inoperable and entered TS 3.4.10, until a reasonable expectation of operability was established. This was consistent with the guidance in NRC Inspection Manual Part 9900 Technical Guidance -

Operability Determinations/Functionality Assessments for Resolution of Degraded or Nonconforming Conditions Adverse to Quality or Safety, and with step 4.1.6 of OP-AA-108-115, which required operability to be immediately determined based on a detailed examination of the deficiency.

On February 2, 2011, Unit 1 was in hot shutdown (Mode 3), following an unexpected scram occurring the previous day. The licensee was in the process of placing the B train of SDC in operation. After the pump was started, the common suction valve closed resulting in a complete loss of SDC. The licensee declared both trains of SDC inoperable and entered TS 3.4.9.

The licensee initiated system restoration in accordance with LOP-RH-07, Attachment A, Defeating Shutdown Cooling High Flow Isolation in Modes 2 or 3, Revision 62.

This included a walkdown of the RHR SDC system piping to verify no leaks in order to determine that the isolation was spurious, followed by the instructions to jumper out the affected relay. Subsequently, the licensee concluded that the isolation was spurious, exited TS 3.4.9 by declaring both trains of SDC operable, and proceeded to bypass the affected relay and restart the pump. The licensee then proceeded with reactor cooldown.

However, the inspectors determined that the licensee had not established a reasonable expectation of operability consistent with the NRC Part 9900 guidance and OP-AA-108-115, prior to exiting TS LCO 3.4.9. Specifically, the circumstances surrounding this loss of SDC were significantly different than those occurring in 1990 and 2009. The licensee had not experienced a spurious loss of SDC, since the installation of the time delayed relays after the 1990 event. Also, as stated above, the July 2009 event was caused by a degraded relay exacerbated by sparking during removal of the jumpers. Therefore, the unexpected spurious isolation in 2011 should have been treated as an unknown condition requiring an operability evaluation.

The inspectors also noted that installing the jumpers disabled the safety-functions required by TS 3.3.6.1 (function 5.b, Primary Containment Isolation Instrumentation -

Unit 1 Division II Reactor Vessel Pressure-High isolation safety function) and TS 3.6.1.3 (Primary Containment Isolation Valves, Condition A). This was not an issue during the July 20, 2009 event, as these functions were only required in Modes 1-3.

Bypassing these safety-functions for operational convenience (i.e., to enable the restoration of SDC) was prohibited by TS 3.0.2.

Analysis:

The failure to adequately assess operability for the loss of SDC events on July 20, 2009, and February 2, 2011, was considered a performance deficiency warranting a significance evaluation in accordance with IMC 0612, Appendix B, Issue Disposition Screening.

The performance deficiency was considered more than minor and a finding because it was associated with the Mitigating Systems Cornerstone attribute of Equipment Performance and affected the cornerstone objective of ensuring the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences (i.e., core damage). Specifically, failing to follow the Operability Determinations procedure caused the licensee to incorrectly assess the RHR SDC systems capability to perform its safety function, and also led the licensee to make a specific TS required isolation feature unavailable.

The inspectors determined the finding could be evaluated using the SDP in accordance with IMC 0609, Significance Determination Process, Attachment 0609.04, Phase 1 -

Initial Screening and Characterization of Findings, Table 3b for the Mitigating Systems Cornerstone. Because the plant had met the entry conditions for RHR and the reactor coolant system pressure was less than RHR cut-in permissive, Table 3b directs the finding to be processed through IMC 0609, Appendix G, Shutdown Operations SDP.

The NRC Region III Senior Reactor Analyst (SRA) reviewed IMC 0609 Appendix G checklists for boiling water reactor hot shutdown and cold shutdown and determined that this finding met the criteria for a phase 2 evaluation because both the 2009 and 2011 events resulted in an actual loss of RHR SDC. The SRA completed a modified phase 2 evaluation using worksheet 4, SDP Worksheet for a BWR Plant - Loss of Operating Train of RHR in Plant Operating State 1. For this evaluation, the inspectors determined that all other emergency core cooling systems were available, including the low pressure coolant injection function. Since the RHR function was recoverable well within the time to reactor coolant system pressurization above RHR pump shutoff head in both events, the SRA determined that the operator action credit for recovering RHR should be adjusted from a 3 to a 4. As a result, the finding was determined to be of very low safety significance or Green.

The dominant sequence was a loss of RHR SDC, failure to recover RHR, and the failure to vent containment.

The SRA also reviewed the 2011 event as a finding that potentially increased the likelihood of a loss of inventory event because the automatic isolation function of the RHR SDC system was disabled for approximately 11 minutes with the SDC suction valves in the open position. However, the SRA determined that due to the short duration that the function was disabled, the likelihood of a loss of inventory event was very low and the risk due to the loss of SDC event would be the dominant core damage scenario.

The inspectors determined that the failures to follow the Operability Determination procedure were caused by numerous non-conservative decisions made by the licensee.

Specifically:

• the licensees conclusion that the RHR SDC system remained operable on July 20, 2009, due to an erroneous interpretation of the bases for TS 3.4.10;

• the licensees assumption that the February 2, 2011, loss of RHR SDC was due to the exact condition previously experienced in 1990 and 2009; and

• the use of a proceduralized workaround (i.e., installing jumpers) to address the relay design deficiency, instead of properly evaluating the cause and instituting corrective actions, which also resulted in the disabling of TS required safety features for operational convenience.

This finding has a cross-cutting aspect in the area of human performance, decision making, because the licensee used non-conservative assumptions when confronted with unexpected system failures. [ H.1(b)

Enforcement:

TS 3.4.9 and 3.4.10 requires, in part, that Two RHR shutdown cooling subsystems shall be OPERABLE.

TS 3.0.2 requires, in part, that Upon discovery of a failure to meet an LCO, the Required Actions of the associated Condition shall be met. The Bases for this TS states in part, that Intentional entry into ACTIONS should not be made for operational convenience.

Contrary to the above, the licensee violated TS requirements on the following occasions:

• on July 20, 2009, by failing to declare the Unit 1 RHR SDC subsystem inoperable, as required by TS 3.4.10;

• on February 2, 2011, by improperly exiting TS 3.4.9, prior to establishing operability of the Unit 1 RHR SDC subsystem; and

• on February 2, 2011, from 5:52 p.m. to 6:03 p.m. by failing to comply with TS 3.0.2 by bypassing the safety-functions required by TS 3.3.6.1 and 3.6.1.3, for operational convenience in order to allow the restoration of Unit 1 SDC.

Because this violation was of very low safety significance and it was entered into the licensees CAP as IR 1248293, this violation is being treated as an NCV, consistent with Section 2.3.2 of the NRC Enforcement Policy (NCV 05000373/2011008-01, Technical Specification Violation Due to Failures to Follow Operability Determinations Procedure.).

(2) Effectiveness of Prioritization and Evaluation of Issues The inspectors observed that the majority of issues identified were of low-level and were either closed to trend or at a level appropriate for a condition evaluation. Issues were being appropriately screened by both the SOC and MRC and the inspectors had no concerns with those items assigned an ACE, CCE, or RCE. There were no items in the operations, engineering, or maintenance backlogs that were risk-significant, individually or collectively.

The inspectors identified some concerns with the screening of IRs 1238180, 1238398 and 1238699 during SOC and MRC meetings on July 13 and 14, respectively.

For example, IR 1238180 concerned a door with an inoperable opening and locking mechanism. During screening, the licensee treated this as a low level issue and closed it to a work request. However, the inspectors questioned whether the door was the only access into the affected area and whether the inability to properly secure the door was a potential safety issue (i.e., an individual could be prevented from exiting a potential confined space area). The IR did not address this concern. The inspectors identified similar examples with the other two IRs. The licensee subsequently brought all three IRs back to the MRC for rescreening based on the inspectors concerns. The inspectors subsequently verified that the specific concerns had been addressed by the MRC.

The inspectors noted that IR 1068805 was closed without addressing all the concerns that had been documented. The IR was issued after the station entered an Orange risk configuration due to thunderstorms passing through the area. One of the concerns was that the licensee had received conflicting weather information during the event.

However, this issue was never addressed in the IR. The licensee issued IR 1245239 to evaluate this concern.

The inspectors also noted that the licensee did not have clear guidance regarding what issues constituted a SCAQ. Although defined in the CAP procedures, there were no listed examples of issues considered a SCAQ. Some licensee staff stated that only items assigned a root cause were SCAQs while others stated that only those classified as significance level 1 or 2 met the criteria. For example, an issue involving the recirculation pump thermal barriers (a non-safety related system) was classified as a significance level 2 and assigned a root cause. However, licensee staff gave conflicting opinions of whether this issue was a SCAQ. The inspectors did not identify any examples where SCAQs were not addressed. The licensee issued IR 1241186 to document this issue.

Findings No findings were identified.

(3) Effectiveness of Corrective Actions Corrective actions were generally appropriate for the identified issues. Over the two year period encompassed by the inspection, the inspectors identified no significant examples where problems recurred.

Issues closed to a work request or to another CAP report, generally had the necessary verbiage to document the interrelationship. However, the inspectors identified one example where cross-referenced issue was inappropriately closed.

IR 947835, Working with High Rad Material outside the Schedule, was closed to IR 9521830, which was written after the NOS group had identified a negative performance trend. IR 9521830 was then closed to a CCE assigned as part of IR 9511830. However, the inspectors noted that the CCE did not adequately address the concerns documented in IR 947835. The licensee issued IR 1245389 to evaluate this concern.

The inspectors found several examples of inadequate Effectiveness Reviews.

For example, IR 994136 was written to perform an RCE following an adverse trend in human performance events. The Effectiveness Review was to evaluate whether the corrective actions resulted in a 25% decrease in the number of these events. However, since the licensee had never defined an acceptable number of human performance events, it was unclear how this review was to be applied. Another example was the review for IR 997150, which documented a RCE following several fuel failures on Unit 2.

The Effectiveness Review was to verify that there were no additional failed fuel events six months after completion of the corrective actions. However, a more appropriate monitoring period would have been one complete operating cycle (i.e., two years).

Several other examples identified by the inspectors were also discussed with licensee staff. The licensee issued IRs 1245384 and 1245247 to evaluate this concern.

The licensee failed to take timely corrective action to address an operability issue with the Public Address (PA) system. In February 2010, the licensee had received Operating Experience regarding a potential operability issue with the PA system speakers due to inappropriate testing. In April 2010, the licensees corporate office required that the licensee make substantive changes to the surveillance test procedure to address this concern. The licensee made the changes, but did not test the speakers until the next scheduled interval in June 2011. In the interim, other licensee facilities subject to the same concern had identified a high failure rate of the speakers after testing.

Despite this, the licensee did not evaluate rescheduling the testing date. Finally, during the June 2011 testing, the licensee experienced a similar high failure rate on the speakers. The failure to take timely corrective action to address this issue was not considered a violation because the PA speakers were not safety-related and the licensee immediately implemented appropriate compensatory measures after discovery such that the emergency response capability was not degraded. The licensee issued IR 1230327 to evaluate this concern.

Findings Failure to Implement Adequate Corrective Action to Prevent Recurrence to Address a Significant Condition Adverse to Quality

Introduction:

The inspectors identified a finding of very low significance and a NCV of 10 CFR 50, Appendix B, Criterion XVI, Corrective Action, for the licensees failure to develop and implement an adequate CAPR in response to a SCAQ associated with work activities on the 1D RHR WS pump. A cross-cutting aspect associated with Problem Identification and Resolution (P.1(d)) was also assigned to this finding.

Description:

On February 19, 2010, the licensee identified that the mounting bolts for the 1D RHR WS pump had sheared following work to replace the pump suction valve.

Because this pump was safety-related, the licensee considered this issue a SCAQ and initiated a RCE. The cause was the failure to properly account for dimensional changes in the piping during the work. Specifically, the pump mounting bolts had sheared after being displaced about 0.325 inches (approximately 50% of their diameter), from a combination of weld shrinkage (from two field welds necessary to install the valve) and bolting of the valve flange to the pump. A single CAPR was initiated which consisted of revising procedure NSWP-M-02, Fabrication and Installation of Piping and Tubing, to include the following statement: In areas where components are or could be highly restrained evaluate weld execution and fit up sequence to prevent possible equipment damage or distortion.

The inspectors concluded that this guidance was insufficient to prevent a similar event from recurring. Specifically, the type of evaluation was not defined nor was it required to be documented. Licensee staff stated that the evaluation was an informal, skill of the craft activity, and that it was expected that workers would report any observed anomalies to their supervision for evaluation. For example, a welder would be expected to report any unacceptable weld shrinkage to their supervision; unacceptable shrinkage being informally determined based on the welders skill and experience. The inspectors also noted that workers were not required to record dimensional changes from work activities unless an anomaly was noted. For example, welders did not have to document the observed weld shrinkage, if no problems were observed. Therefore, it was unclear how the aggregate affects of work on a component would be evaluated. The inspectors noted that that the workers involved in the 1D RHR WS work had not raised any concerns with their work. Therefore, it was reasonable to conclude that they believed that the welding and fit-up activities were acceptable. However as stated, it was the aggregate affects of the welding and bolting that eventually resulted in the shearing of the pump mounting bolts. These aggregate affects were not evaluated until after the licensee had identified the sheared bolts.

Analysis:

The failure to implement an adequate corrective action was considered a performance deficiency warranting a significance evaluation in accordance with IMC 0612, Appendix B, Issue Disposition Screening. The inspectors determined that the performance deficiency was more than minor and a finding because it impacted the Reactor Safety Mitigating Systems Cornerstone objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences and affected the cornerstone attribute of Equipment Performance. Specifically, the inadequate corrective action allowed for recurrence of this issue during similar work on other safety-related components.

The inspectors evaluated the finding using IMC 0609, Appendix A, Attachment 1, Significance Determination of Reactor Inspection Findings for At-Power Situations, using the Phase 1 Worksheet for the Initiating Events Cornerstone. Since the inspectors answered No to all of the Exhibit 1, Table 4a Mitigating Systems questions, the inspectors concluded that the finding was of very low safety significance.

The inspectors determined that this finding also affected the cross-cutting aspect of Problem Identification and Resolution. Specifically, that the licensee takes corrective actions to address safety issues and adverse trends in a timely manner, commensurate with their safety significance and complexity.( P.1(d)).

Enforcement:

10 CFR Part 50, Appendix B, Criterion XVI, Corrective Action, requires, in part, that measures shall be established to assure that conditions adverse to quality, such as failures, malfunctions, deficiencies, deviations, defective material and equipment, and non-conformances are promptly identified and corrected. In the case of SCAQs, the measures shall assure that the cause of the condition is determined and corrective action taken to preclude repetition.

Contrary to the above, as of July 29, 2011, the licensee had failed to take corrective action to preclude repetition for a SCAQ associated with the 1D RHR WS pump.

Specifically, the revision to procedure NSWP-M-02 was not sufficient to ensure that the licensee would be able to identify and respond to conditions similar to those that caused the 1D RHR SW pump SCAQ. Because this violation was of very low safety significance and was entered into the licensees CAP (IR 1241188), it is being treated as an NCV, consistent with Section VI.A.1 of the NRC Enforcement Policy.

(NCV 05000373/2011008-02; 05000374/2011008-02, Failure to Implement A Corrective Action To Prevent Recurrence to Address a Significant Condition Adverse to Quality)

.2 Assessment of the Use of Operating Experience

a. Inspection Scope

The inspectors reviewed the licensees implementation of the facilitys operating experience (OE) program. Specifically, the inspectors reviewed OE program procedures, observed daily meetings for the use of OE information, and reviewed completed evaluations of OE issues and events. The intent was to determine if the licensee was effectively integrating OE experience into the performance of daily activities, whether evaluations of issues were proper and conducted by qualified personnel, whether the licensees program was sufficient to prevent future occurrences of previous industry events, and whether the licensee effectively used the information in developing departmental assessments and facility audits. The inspectors also assessed if corrective actions, as a result of OE experience, were identified and implemented effectively and in a timely manner.

b. Assessment In general, OE was effectively used at the station. The inspectors observed that OE was discussed as part of the daily station and pre-job briefings. Industry OE was effectively disseminated across the various plant departments and no issues were identified during the inspectors review of licensee OE evaluations. During interviews, several licensee personnel commented favorably on the use of OE in their daily activities. The inspectors also noted that the quality of OE review in ACE and RCEs had improved since the 2009 PI&R inspection.

Findings No findings were identified.

.3 Assessment of Self-Assessments and Audits

a. Inspection Scope

The inspectors assessed the licensee staffs ability to identify and enter issues into the CAP program, prioritize and evaluate issues, and implement effective corrective actions through efforts from departmental assessments and audits.

b. Assessment The inspectors considered the quality of the NOS audits to be thorough and critical.

The department self-assessments were acceptable but were not of the same level of quality as the NOS audits. The inspectors observed that CAP items had been initiated for issues identified through the NOS audits and self-assessments.

One of the indicators that the licensee used to monitor CAP performance was called the Site Engagement Ratio. This indicator was a ratio of the total number of individuals writing a CAP divided by the total number of individuals in a particular department.

The inspectors noted that this ratio may not provide an effective indicator, as it did not account for staff who relied on others (such as supervisors) to input issues into the CAP process. For example, the security officers typically relied on their supervisors to input issues into the CAP due to the inability to access a computer during routine rounds. This has resulted in the Security group indicating a lower proclivity towards using the CAP than was otherwise the case. The licensee initiated IR 1245237 to evaluate this observation.

Findings No findings were identified.

.4 Assessment of Safety-Conscious Work Environment

a. Inspection Scope

The inspectors assessed the licensees safety-conscious work environment (SCWE)through the reviews of the facilitys ECP, implementing procedures, discussions with ECP coordinators, interviews with personnel from various departments, and reviews of IRs. The inspectors also reviewed the results of licensee safety culture surveys.

The inspectors also reviewed the selected ECP case files (titles redacted) from 2009 to 2011 involving potential cases of harassment and intimidation for raising safety issues.

b. Assessment The inspectors determined that the plant staff were aware of the importance of having a strong SCWE and expressed a willingness to raise safety issues. No one interviewed had experienced retaliation for safety issues raised or knew of anyone who had failed to raise issues. All persons interviewed had an adequate knowledge of the CAP process.

These results were similar with the findings of the licensees safety culture surveys.

Based on these limited interviews, the inspectors concluded that there was no evidence of an unacceptable SCWE.

The inspectors determined that the ECP process was being effectively implemented.

The inspectors noted that the licensee had appropriately investigated and taken constructive actions to address issues involving potential cases of harassment and intimidation for raising issues. However, the inspectors did identify a potential vulnerability in the licensees oversight of contractor ECP programs. Specifically, there was no formal requirement for the licensee to monitor contractor ECP programs.

This may result in a potential nuclear safety/quality issue raised via the contractor program to not be communicated to the site. This licensee issued IR 1244215 to evaluate this observation.

Although the licensee has scored well on the internal safety culture surveys, the inspectors had some concerns with their overall effectiveness. The licensee corporate staff sent the safety culture surveys to staff on a biennial basis. The responses were then collated before being sent to the individual sites for evaluation. The inspectors noted that the questions have not changed in the past several years, which could potentially bias the results. Additionally, there were no defined trigger levels to resolve potential inconsistencies. For example, in the 2009 survey, 15% of respondents stated that their work group sometimes or rarely uses self-assessments, benchmarking or OE to improve processes. Although this contradicted the results of other internal self-assessments, the licensee had not done an assessment to determine if this was a real concern. Similar issues were also seen in the responses to the 2011 survey, which was still being evaluated by the licensee. The licensee initiated IR 1250626 to evaluate these observations.

Findings No findings were identified.

4OA6 Management Meetings

.1 Exit Meeting Summary

On July 29, 2011, the inspectors presented the inspection results to Mr. Karaba and other members of the licensee staff. The licensee acknowledged the issues presented.

The inspectors returned to the licensee the results of the 2009 safety culture survey, which was the only item considered proprietary.

ATTACHMENT:

SUPPLEMENTAL INFORMATION

KEY POINTS OF CONTACT

Licensee

N. Darrow, Nuclear Oversight Manager

K. Lyons, Chemistry Manager

P. Karaba, Plant Manager

T. Simpkin, Regulatory Assurance Manager

B. Speek, Exelon CorporateNuclear Oversight

J. Williams, OperationsShift Operations Superintendent

H. Vinyard, Engineering Director

Nuclear Regulatory Commission

K. Riemer, Chief, Branch 2, Division of Reactor Projects

Attachment

LIST OF ITEMS

Opened

05000373/2011008-01 NCV Technical Specification Violation Due to Failures to Follow Operability Determinations Procedure

05000373/2011008-02 NCV Failure to Implement A Corrective Action To Prevent

05000374/2011008-02 Recurrence to Address a Significant Condition Adverse to Quality

Closed

05000373/2011008-01 NCV Technical Specification Violation Due to Failures to Follow Operability Determinations Procedure

05000373/2011008-02 NCV Failure to Implement A Corrective Action To Prevent

05000374/2011008-02 Recurrence to Address a Significant Condition Adverse to Quality

Discussed

None Attachment