IR 05000456/2010004

IR 05000456-10-004 & 05000457-10-004, on 07/01/2010 - 09/30/2010, Braidwood Station, Units 1 & 2, Temporary Plant Modifications; Surveillance Testing

ML103120173
Person / Time
Site:	Braidwood
Issue date:	11/05/2010
From:	Eric Duncan Region 3 Branch 3
To:	Pacilio M Exelon Generation Co, Exelon Nuclear
References
IR-10-004
Download: ML103120173 (49)

Text

November 5, 2010

SUBJECT:

BRAIDWOOD STATION, UNITS 1 AND 2, NRC INTEGRATED INSPECTION REPORT 05000456/2010004; 05000457/2010004

Dear Mr. Pacilio:

On September 30, 2010, the U.S. Nuclear Regulatory Commission (NRC) completed an integrated inspection at your Braidwood Station, Units 1 and 2. The enclosed report documents the results of this inspection, which were discussed on October 1, 2010, with Mr. A. Shahkarami 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 NRC-identified finding and one self-revealed finding of very low safety significance were identified. Both findings involved a violation 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.

Additionally, two licensee-identified violations are listed in Section 4OA7 of this report.

If you contest the subject or severity 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 Braidwood 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 the Braidwood 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/

Eric R. Duncan, Chief Branch 3 Division of Reactor Projects Docket Nos. 50-456; 50-457 License Nos. NPF-72; NPF-77

Enclosure:

Inspection Report 05000456/2010004; 05000457/2010004 w/Attachment: Supplemental Information

REGION III==

Docket Nos: 50-456; 50-457 License Nos: NPF-72; NPF-77 Report No: 05000456/2010004; 05000457/2010004 Licensee: Exelon Generation Company, LLC Facility: Braidwood Station, Units 1 and 2 Location: Braceville, IL Dates: July 1 through September 30, 2010 Inspectors: J. Benjamin, Senior Resident Inspector M. Thorpe-Kavanaugh, Acting Resident Inspector D. Betancourt-Roldan, Acting Resident Inspector T. Go, Health Physics Inspector M. Perry, Resident Inspector Illinois Emergency Management Agency Approved by: E. Duncan, Chief Branch 3 Division of Reactor Projects Enclosure

SUMMARY OF FINDINGS

IR 05000456/2010004, 05000457/2010004; 07/01/2010 - 09/30/2010; Braidwood Station,

Units 1 & 2; Temporary Plant Modifications; Surveillance Testing.

This report covers a 3-month period of inspection by resident inspectors and announced baseline inspection by a regional inspector. One Green finding was identified by the inspectors and one Green finding was self-revealed. The findings were considered Non-Cited Violations of NRC regulations. The significance of most findings is indicated by their color (Green, White,

Yellow, Red) using Inspection Manual Chapter (IMC) 0609, Significance Determination Process (SDP). Findings for which the SDP does not apply may be Green or be assigned a severity level after NRC management review. The NRCs program for overseeing the safe operation of commercial nuclear power reactors is described in NUREG-1649, Reactor Oversight Process, Revision 4, dated December 2006.

NRC-Identified

and Self-Revealed Findings

Cornerstone: Mitigating Systems

Green.

The inspectors identified a Green finding and an associated Non-Cited Violation of 10 CFR Part 50, Appendix B, Criterion V, Instructions, Procedures, and Drawings, related to the control of temporary scaffolds. Specifically, the licensees procedure for the installation, modification, and removal of scaffolds was not followed on a routine basis for temporary scaffolds that remained in the plant for greater than 90 days. The licensee entered this issue into the Corrective Action Program (CAP) as Issue Report (IR) 1095900. Corrective actions for this issue included walk downs of temporary scaffolds that had been in place for greater than 90 days utilizing the permanent scaffold checklist, and an assignment to ensure the procedure was followed in the future.

The inspectors determined that this issue was more than minor in accordance with IMC 0612, Appendix E, Examples of Minor Issues. Specifically, this issue was similar to the more than minor criteria in Example 4.a, Insignificant Procedural Errors, in that the licensee failed to perform engineering evaluations on similar issues, or if the later evaluation determined that safety-related equipment was adversely affected. The finding was of very low safety significance because there was not a confirmed loss of operability of any mitigating system component. This finding was associated with the cross-cutting aspect of Decision-Making in the Human Performance cross-cutting area.

Specifically, the licensee had not made safety-significant or risk significant decisions by utilizing the systematic scaffolding construction process to ensure adequate quality and therefore adequate safety was maintained (H.1(a)). (Section 1R18.1)

Green.

A self-revealed Green finding and an associated Non-Cited Violation of 10 CFR Part 50, Appendix B, Criterion V, Instructions, Procedures, and Drawings, was identified after the licensee failed to follow procedures during an essential service water inservice test on August 24, 2010. Specifically, during the section of the procedure utilized to establish testing conditions, the licensee throttled the wrong valve resulting in an unplanned reduction in flow to safety-related structures, systems, and components.

This flow reduction resulted in the Train B equipment being declared inoperable for approximately 5 minutes. The licensee entered this issue into the CAP as IR 1105448.

Corrective actions for this issue included returning the Unit 2 essential service water system to operable status by restoring the required valve lineup and a corrective action assignment to provide additional training to the operating crews on the use of human error prevention techniques.

The inspectors determined that this finding was more than minor, because it was associated with the Human Performance attribute of the Mitigating Systems Cornerstone and impacted the cornerstone objective of ensuring the availability of systems that respond to initiating events to prevent undesirable consequences. This finding was determined to be of very low safety significance based on a Phase 3 Significance Determination Process analysis that conservatively bounded the risk of this event to be less than 1.0E-7/yr. The inspectors concluded that this finding was associated with the cross-cutting aspect of Work Practices in the Human Performance cross-cutting area because adequate human error prevention techniques were not effectively used to ensure that the surveillance activity was performed properly (H.4(a)). (Section 1R22.1)

Licensee-Identified Violations

Violations of very low safety significance that were identified by the licensee have been reviewed by inspectors. Corrective actions planned or taken by the licensee have been entered into the licensees corrective action program. These violations and corrective action tracking numbers are listed in Section 4OA7 of this report.

REPORT DETAILS

Summary of Plant Status

Unit 1 operated at or near full power for the entire report period with two exceptions.

On August 16, 2010, a reactor trip occurred. The unit returned to 100 percent power on August 23, 2010. A second reactor trip occurred on September 20, 2010, with the unit returning to approximately 95 percent power on September 24, 2010. The unit remained at approximately this power level for the remainder of the period.

Unit 2 operated at or near full power for the entire report period, except for a reactor trip on August 16, 2010. The unit returned to 100 percent power on August 24, 2010, and operated at full power for the remainder of the period.

REACTOR SAFETY

Cornerstone: Initiating Events, Mitigating Systems, Barrier Integrity and

Emergency Preparedness

1R01 Adverse Weather Protection

.1 Readiness For Impending Adverse Weather Condition - Extreme Heat Conditions

a. Inspection Scope

The inspectors performed a detailed review of the licensees procedures and preparations for operating the facility during an extended period of time when ambient outside temperature was high and the ultimate heat sink was experiencing elevated temperatures. The inspectors focused on plant specific design features and implementation of the procedures for responding to or mitigating the effects of these conditions on the operation of the facilitys essential service water cooling systems.

Inspection activities included a review of the licensees adverse weather procedures, daily monitoring of the off-normal environmental conditions, and verification that operator actions specified by plant specific procedures were appropriate to ensure operability of the facilitys normal and emergency cooling systems. Documents reviewed are listed in the Attachment to this report.

This inspection constituted one readiness for impending adverse weather condition sample as defined in Inspection Procedure (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:

• 2B Chemical and Volume Control Pump While the Redundant 2A Pump was Out-of-Service;

• Unit 1 Main Steam System Following the August 16 Dual Unit Trip; and

• 2B Component Cooling (CC) System Alignment While the Redundant 2A System was Out-of-Service.

The inspectors selected these systems based on their risk significance relative to the Reactor Safety Cornerstones at the time they were inspected. The inspectors attempted to identify any discrepancies that could impact the function of the system, and, therefore, potentially increase risk. The inspectors reviewed applicable operating procedures, system diagrams, the Updated Final Safety Analysis Report (UFSAR), Technical Specification (TS) requirements, outstanding work orders, condition reports, and the impact of ongoing work activities on redundant trains of equipment in order to identify conditions that could have rendered the systems incapable of performing their intended functions. The inspectors also walked down accessible portions of the systems to verify system components and support equipment were aligned correctly and operable. The inspectors examined the material condition of the components and observed operating parameters of equipment to verify that there were no obvious deficiencies. The inspectors also verified that the licensee had properly identified and resolved equipment alignment problems that could cause initiating events or impact the capability of mitigating systems or barriers and entered them into the Corrective Action Program (CAP) with the appropriate significance characterization. Documents reviewed are listed in the Attachment to this report.

These activities constituted three partial system walkdown samples as defined in IP 71111.04-05.

b. Findings

No findings of significance were identified.

1R05 Fire Protection

.1 Routine Resident Inspector Tours

a. Inspection Scope

The inspectors conducted fire protection walkdowns which were focused on availability, accessibility, and the condition of firefighting equipment in the following risk-significant plant areas:

• 2B Auxiliary Feedwater Pump Room;

• Division 12 Cable Penetration Area;

• Lake Screen House;

• Engineered Safety Feature Switchgear Rooms;

• Unit 2 Cable Tunnel; and

• Turbine Building Following the August 16 Dual Unit Trip.

The inspectors reviewed areas to assess if the licensee had implemented a fire protection program that adequately controlled combustibles and ignition sources within the plant, effectively maintained fire detection and suppression capability, maintained passive fire protection features in good material condition, and implemented adequate compensatory measures for out-of-service, degraded or inoperable fire protection equipment, systems, or features in accordance with the licensees fire plan. The inspectors selected fire areas based on their overall contribution to internal fire risk as documented in the plants Individual Plant Examination of External Events, with later additional insights, their potential to impact equipment which could initiate or mitigate a plant transient, or their impact on the plants ability to respond to a security event. Using the documents listed in the Attachment, the inspectors verified that fire hoses and extinguishers were in their designated locations and available for immediate use; that fire detectors and sprinklers were unobstructed; that transient material loading was within the analyzed limits; and fire doors, dampers, and penetration seals appeared to be in satisfactory condition. The inspectors also verified that minor issues identified during the inspection were entered into the licensees CAP. Documents reviewed are listed in the Attachment to this report.

These activities constituted six quarterly fire protection inspection samples as defined in IP 71111.05-05.

b. Findings

No findings of significance were identified.

.2 Annual Fire Protection Drill Observation

a. Inspection Scope

On September 10, 2010, the inspectors observed an unannounced fire drill and fire brigade activation during a simulated hot work fire in the proximity of the station air compressors. Based on this observation, the inspectors evaluated the readiness of the plant fire brigade to fight fires. The inspectors verified that the licensee staff identified deficiencies; openly discussed them in a self-critical manner at the drill debrief, and took appropriate corrective actions. Specific attributes evaluated were:

• proper wearing of turnout gear and self-contained breathing apparatus;

• proper use and layout of fire hoses;

• employment of appropriate fire fighting techniques;

• sufficient firefighting equipment brought to the scene;

• effectiveness of fire brigade leader communications, command, and control;

• search for victims and propagation of the fire into other plant areas;

• smoke removal operations;

• utilization of pre-planned strategies;

• adherence to the pre-planned drill scenario; and

• accomplishment of drill objectives.

Documents reviewed are listed in the Attachment to this report.

These activities constituted one annual fire protection inspection sample as defined in IP 71111.05-05.

b. Findings

No findings of significance were identified.

1R06 Flooding

.1 Internal Flooding

a. Inspection Scope

The inspectors reviewed selected risk significant 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 document reviewed is 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 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 applicable commitments:

• Turbine Building (Following the Condensate Storage Tank Vent Line Overflow Event that Occurred During the August 16, 2010, Dual Unit Trip.)

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 July 21, 2010, the inspectors observed a crew of licensed operators in the plants simulator during licensed operator requalification examinations to verify that operator performance was adequate, evaluators were identifying and documenting crew performance problems, and training was being conducted in accordance with licensee procedures. The inspectors evaluated the following areas:

• licensed operator performance;

• crews clarity and formality of communications;

• ability to take timely actions in the conservative direction;

• prioritization, interpretation, and verification of annunciator alarms;

• correct use and implementation of abnormal and emergency procedures;

• control board manipulations;

• oversight and direction from supervisors; and

• ability to identify and implement appropriate TS actions and Emergency Plan actions and notifications.

The crews performance in these areas was compared to pre-established operator action expectations and successful critical task completion requirements. The document reviewed is 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 system:

• 2B Main Feedwater Pump The inspectors reviewed events where ineffective equipment maintenance 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 component 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 one quarterly maintenance effectiveness sample as defined in IP 71111.12-05.

b. Findings

No findings of significance were identified.

1R13 Maintenance Risk Assessments and Emergent Work Control

.1 Maintenance Risk Assessments and Emergent Work Control

a. Inspection Scope

The inspectors reviewed the licensee's evaluation and management of plant risk for the maintenance and emergent work activities affecting risk-significant and safety-related equipment listed below to verify that appropriate risk assessments were performed prior to removing equipment for work:

• Yellow Risk with the 1A Containment Spray System Out-of-Service;

• Green Risk Following the August 16, 2010 Dual Unit Trip;

• Yellow Risk with the Unit 1 Condensate Storage Tank Inoperable; and

• Yellow Risk with Emergent Switchyard Transformer Work.

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 re-assessed and managed. The inspectors reviewed the scope of maintenance work, discussed the results of the assessment with the licensee's probabilistic risk analyst and/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. Documents reviewed are listed in the Attachment to this report.

These maintenance risk assessments and emergent work control activities constituted four samples as defined in IP 71111.13-05.

b. Findings

No findings of significance were identified.

1R15 Operability Evaluations

.1 Operability Evaluations

a. Inspection Scope

The inspectors reviewed the following issues:

• Effects of Bryozoa on the Essential Service Water (SX) system;

• Component Cooling Piping Class Break Analysis Inadequacy;

• 2B SX Low Discharge Header Pressure During Surveillance; and

• Effects of Seismic Activities on Auxiliary Feedwater Recirculation Line.

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 reviewed a sampling of corrective action documents to verify that the licensee was identifying and correcting any deficiencies associated with operability evaluations. Documents reviewed are listed in the to this report.

This operability inspection constituted four 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 modifications:

• Sample of Temporary Scaffolds Left in the Plant for Greater than 90 Days (Issue Report (IR) 1073578, 1081977, 1081934, 1083041 and 1063870)

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 system. 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 are listed in the Attachment to this report.

This inspection constituted one temporary modification sample as defined in IP 71111.18-05.

b. Findings

(1) Failure to Follow Procedure for Temporary Scaffolds

Introduction:

The inspectors identified a Green finding and an associated NCV of 10 CFR Part 50, Appendix B, Criterion V, Instructions, Procedures, and Drawings, related to an inadequate quality review of temporary and permanently constructed scaffolds installed throughout the plant. Specifically, the licensee failed to follow procedural requirements for installed temporary scaffolds prior to reaching 90 days inservice. In addition, the licensee failed to ensure that a Fire Marshal review was accomplished for each permanently constructed scaffold consistent with a basis provided in the procedures 10 CFR 50.59 evaluation.

Description:

From April 30, 2010 to June 18, 2010, the licensee identified five instances in which the temporary constructed scaffolds had remained in the plant for over 90 days.

The licensee entered these individual deficiencies into the CAP as IR 1073578, 1081977, 1081934, 1083041, and 1063870. The inspectors reviewed the IRs and noted that although these scaffolds had been entered into the corrective action process, the corrective action assignments for these IRs did not align with the required actions established in the applicable station procedure.

Specifically, Step 2.11 of quality procedure MA-AA-716-025, Scaffold Installation, Modification, and Removal Request Process, Revision 7B, defined a temporary scaffold as follows:

Scaffold - Temporary access structures erected in support of Maintenance or Operations activities that are to be removed at the completion of the activities.

These temporary access structures are not intended to be left in place for more than 90 days of power plant operations.

Additionally, Step 3.6 of the procedure required the following:

Scaffold Coordinator/Designee - Is responsible for the coordination of erection and removal of all scaffolds on site. Maintaining a log or electronic equivalent of the status of all scaffolds, and reviewing the log to ensure that any scaffolds approaching their 90 day limit are removed or converted to a permanent scaffold or requesting that an individual 10 CFR 50.59 review be performed for the individual scaffold required to be left in place beyond 90 days.

The inspectors reviewed the corrective actions for the documented IRs and noted that although these issues were generically being tracked in the CAP, no assignment was completed or planned to comply with the requirement of Step 3.6.

The inspectors questioned the difference between the stations procedural requirements and the prescribed generic CAP action to correct the deficiencies. The inspectors interviewed engineering staff and management and understood it was the licensees position that there was no specific requirement that temporary scaffolds be disassembled prior to exceeding an inservice life of 90 days. A generic 10 CFR 50.59 evaluation had previously been completed that was applicable to all temporary scaffolds, which allowed those scaffolds to be erected more than 90 days (ref: NSWP-A-24, dated July 23, 1998).

The inspectors reviewed this 10 CFR 50.59 evaluation and concluded that this evaluation was not an individual 10 CFR 50.59 review for an individual scaffold as required by the procedure. The inspectors concluded that this 10 CFR 50.59 review was broad in nature and did not have a level of review consistent with an individual analysis.

Therefore, the inspectors concluded that the 10 CFR 50.59 evaluation, NSWP-A-24, was not sufficient to satisfy the requirements of Step 2.11 and Step 3.6 of MA-AA-716-025.

The inspectors reviewed and evaluated the difference in the level of details between the procedural requirements for the construction of a temporary and permanent scaffold.

The inspectors conducted this review to determine if the performance deficiency for not following the procedure was administrative in nature. The inspectors identified that a significant difference between the two processes was related to Engineering involvement.

In particular:

• The permanent scaffold process required that Engineering review and evaluate the technical impact of the scaffold and identify any special instructions. By contrast, engineering review was optional for the temporary constructed scaffold process.

• The procedural steps for erecting a temporary scaffold contained a pre-erection review that consisted of eight [Yes/No] check boxes for blocking of fire suppression equipment, seismic considerations, and access to equipment. By contrast, the procedural steps for erecting permanent scaffolding consisted of two pages of questions to guide a reviewer through what to consider when conducting a review.

The inspectors concluded that the station routinely failed to follow Step 3.6 of Station Procedure MA-AA-716-025 and had not met the intent of Step 2.11. The inspectors determined that this was not an administrative issue based on a detailed review of the procedures, a review of the applicable 10 CFR 50.59 evaluation, and discussions with licensee staff.

The inspectors reviewed the generic 10 CFR 50.59 evaluation that was utilized to provide a basis for the process used to install permanent scaffolding in the plant (Ref: BRW-SE-2000-1193). The inspectors identified that this 10 CFR 50.59 evaluation asserted that all permanent scaffolds were reviewed by Engineering, Operations, and the Fire Marshall, and were only approved at locations that would not interfere with safe operations of the plant. The inspectors identified that station procedure MA-AA-716-025, Revisions 7B and 8, did not require the Fire Marshall to review permanent scaffolds.

Therefore, the inspectors determined that this aspect of the procedure was inadequate.

Analysis:

The inspectors identified a performance deficiency, in that the licensee was routinely not following a 10 CFR 50, Appendix, B, quality procedure, MA-AA-716-025, as it related to the control of temporary scaffolding. In addition, the inspectors identified that the procedure for construction of permanent scaffolding was inadequate because it did not require a Fire Marshal review consistent with the supportive 10 CFR 50.59 analysis. The performance deficiency affected the Mitigating Systems Cornerstone.

The inspectors determined that this issue was more than minor in accordance with IMC 0612, Appendix E, Examples of Minor Issues. Specifically the inspectors concluded that this issue was similar to the more than minor criteria established in Example 4.a, Insignificant Procedural Errors, as described below:

A scaffold erected between safety-related plant service water strainers was wedged tightly between the system piping. Licensee procedures required an engineering evaluation be performed for all scaffolding located above or near safety-related equipment. No engineering evaluation was performed to assess the seismic impact of the scaffold.

Minor if: A later engineering evaluation determined that there is no safety concern.

Not minor if: The licensee routinely failed to perform engineering evaluations on similar issues, or if the later evaluation determined that safety-related equipment was adversely affected.

This finding was associated with the Decision-Making aspect in the Human Performance cross-cutting area. Specifically, the licensee had not made safety-significant or risk-significant decisions by utilizing the systematic scaffolding construction process to ensure adequate quality and therefore adequate safety was maintained (H.1(a)).

Enforcement:

10 CFR Part 50, Appendix B, Criterion V, Instructions, Procedures, and Drawings, requires, in part, that activities affecting quality be prescribed by instructions, procedures, or drawings, of a type appropriate to the circumstance and shall be accomplished in accordance with these instructions, procedures, or drawings. Step 3.6 of quality procedure MA-AA-716-025, Scaffold Installation, Modification, and Removal Request Process, Revision 7B, required that temporary constructed scaffold be removed or converted to a permanent scaffold or an individual 10 CFR 50.59 review be performed for the individual scaffold required to be left in place beyond 90 days.

Contrary to the above, from April 30, 2010 to June 18, 2010, the licensee failed to follow Step 3.6 of quality procedure, MA-AA-716-025, in five instances that temporary constructed scaffolds remained in the plant for greater than 90 days and without a individual 10 CFR 50.59 evaluation or converted to a permanent scaffold.

Because this violation was of very low safety significance, was not repetitive or willful, and was entered into the licensees CAP (IR 1095900), this violation is being treated as an NCV, consistent with Section 2.3.2 of the NRC Enforcement Policy. Corrective actions included performance of Step 3.6 of MA-AA-716-025, by converting all temporarily constructed scaffolds to a permanent scaffold utilizing the applicable section of the procedure and an assignment to ensure the procedure requires the appropriate level of review for permanently constructed scaffolds. (NCV 05000456/2010004-01; 05000457/2010004-01, Failure to Follow Procedure for Temporary Scaffolds)

Temporary Scaffolding Process Quality

Introduction:

The inspectors identified an Unresolved Item (URI) related to the stations quality control for constructing temporary scaffolding. Specifically, the inspectors opened this URI to determine whether the licensees procedures for constructing temporary scaffolding provided an adequate level of quality to ensure the stations licensing basis was maintained.

Description:

The inspectors conducted a review of quality procedure MA-AA-716-025, Scaffold Installation, Modification, and Removal Request Process. This procedure was utilized to construct both temporary and permanent scaffolds. With respect to temporarily constructed scaffolds, this procedure was utilized regardless of whether the scaffold was for support of maintenance or for other reasons. As discussed in Section 1R18.b(1) of this report, the procedure required the use of eight [Yes/No] check boxes for evaluating blockage of fire suppression equipment, seismic considerations, and access to equipment to determine if the temporary scaffold could be erected. The inspectors also reviewed the approval process for these structures.

At the end of the inspection period, it was unclear if the licensee scaffold procedure ensured an adequate level of quality for temporary scaffolding such that all licensing bases were maintained.

This URI will remain open pending a more detailed review of the licensees processes utilized to construct temporary scaffolding and a review and field walkdown of actual scaffolds constructed in the plant. (URI 05000456/2010004-02; 05000457/2010004-02, Temporary Scaffold Quality Control Process)

.2 Permanent Plant Modifications

a. Inspection Scope

The following engineering design package was reviewed and selected aspects were discussed with engineering personnel:

• Condensate Storage Tank Manual Hotwell Reject.

The inspectors examined the adequacy of the 10 CFR 50.59 safety evaluation screening, the adequacy of the design parameters considered, the implementation of the modification, and the post-modification testing completed. The inspectors also determined whether relevant procedures, design, and licensing documents were properly updated. The inspectors observed ongoing and completed work activities to verify that installation was consistent with the design control documents. The modification changed the method of rejecting water from the stations main condenser to the condensate storage tank from an automatic method to a manual method. This modification was put in place to address multiple post-trip water overflow events. In addition to the review described above, the inspectors reviewed the implementation of this modification after the September 20, 2010, Unit 1 trip. Documents reviewed are listed in the Attachment to this report.

This inspection constituted one permanent plant modification sample as defined in IP 71111.18-05.

b. Findings

No findings of significance were identified.

1R19 Post-Maintenance Testing

a. Inspection Scope

The inspectors reviewed the following post-maintenance testing activities to verify that procedures and test activities were adequate to ensure system operability and functional capability:

• Containment Spray Sump Suction Isolation Valve 2CS009B Actuator Rebuild;

• Charging Flowing Control Valve 1CV121 Packing Replacement;

• 1C Steam Generator Power Operated Relief Valve Work;

• Diesel Driven Fire Pump Relief Valve Replacement; and

• 1B SX Pump Work.

These activities were selected based upon the structure, system, or component's impact on 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 corrective action documents associated with post-maintenance tests to determine whether the licensee was identifying problems and entering them in the CAP and that the problems were being corrected commensurate with their importance to safety. Documents reviewed are listed in the Attachment to this report.

This inspection constituted five post-maintenance testing samples as defined in IP 71111.19-05.

b. Findings

No findings of significance were identified.

1R20 Outage Activities

Unit 1 and Unit 2 Non-refueling Outage Activities

a. Inspection Scope

The inspectors evaluated outage activities for an unscheduled Unit 1 and 2 outage that began on August 16, 2010, and continued through August 21, 2010. The inspectors reviewed activities to ensure that the licensee considered risk in developing, planning, and implementing the outage schedule. Documents reviewed are listed in the to this report.

The inspectors observed:

• portions of the plant shutdown and cooldown processes;

• Mode 3 as-left containment closeout tour;

• post-trip transient review evaluations;

• mode transitions;

• reactor startups;

• power ascensions;

• Plant Operations Review Committee meetings;

• shift turnovers; and

• fatigue management.

This inspection constituted one other outage sample as defined in IP 71111.20-05.

b. Findings

No findings of significance were identified.

.2 New Fuel Receipt

a. Inspection Scope

On August 12, 2010, the inspectors observed new fuel receipt inspections in anticipation of the Unit 1 refueling outage, which was scheduled to begin on October 3, 2010. The inspectors verified the licensee performed inspections in accordance with their procedures and that any issues were appropriately dispositioned.

This inspection did not constitute an outage sample as defined in IP 71111.20-05, but will be a part of the Unit 1 refueling outage sample planned for next quarter. Documents reviewed are listed in the Attachment to this report

c. 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:

• Unit 1 Train A Emergency Diesel Generator Monthly Surveillance (Routine);

• Unit 1 Train B Emergency Diesel Generator Monthly Surveillance (Routine);

• Unit 1 Main Steam Safety Valve Operability Test (Routine);

• 2A Chemical and Volume Control American Society of Mechanical Engineers (ASME) Test (Inservice Testing);

• 2A SX ASME Test (Inservice Testing); and

• 2B SX ASME Test (Inservice Testing).

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 UFSAR, procedures, and applicable commitments;

• measuring and test equipment calibration was current;

• test equipment was used within the required range and accuracy; applicable prerequisites described in the test procedures were satisfied;

• test frequencies met TS requirements to demonstrate operability and reliability;

• tests were performed in accordance with the test procedures and other applicable procedures;

• jumpers and lifted leads were controlled and restored where used;

• test data and results were accurate, complete, within limits, and valid;

• test equipment was removed after testing;

• where applicable for inservice testing activities, testing was performed in accordance with the applicable version of Section XI, ASME codes, 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 three inservice testing samples as defined in IP 71111.22, Sections -02 and -05.

b. Findings

Unplanned Cooling Water Flow Reduction During Essential Service Water Inservice Testing Surveillance Test

Introduction:

A self-revealed Green finding and an associated Non-Cited Violation of 10 CFR 50, Appendix B, Criterion V, Instructions, Procedures, and Drawings, was identified during a 2B SX pump inservice testing (IST) surveillance that resulted in an unplanned loss of TS equipment operability. Specifically, during the section of the procedure utilized to set the proper flow conditions, the wrong valve was throttled, resulting in a drop of SX system pressure and reduction of cooling water flow to dependent plant safety-related equipment.

Description:

On August 24, 2010, Operations was performing 2B SX IST surveillance in accordance with Procedure 2BwOSR5.5.8.SX-3B, Group A IST Requirements for 2B Essential Service Water Pump (2SX01PB). To establish test flow conditions, the operators were to throttle open the Unit 2 CC heat exchanger outlet valve to establish a flow rate of 24,000 gallons per minute (gpm) at the pumps discharge. Instead of observing the flow rate at the pumps discharge per Step 3B of the procedure, operators performing this evolution used a flow meter that measured the flow rate at the inlet of the 2B CC heat exchanger. As a result of this error, the total flow at the pump discharge approached 36,000 gpm and the header pressure rapidly lowered from approximately 90 pounds per square inch (psig) to 65 psig. A low discharge pressure alarm was received in the control room and operators took prompt action to restore the discharge pressure to 90 psig by re-throttling close the Unit 2 CC heat exchanger outlet valve. This action took approximately 5 minutes. During this time, Operations entered multiple TS Limiting Conditions for Operations due to one inoperable SX train and two inoperable containment cooling trains.

The licensee entered this issue into their CAP. Subsequently, the licensee reviewed plant data recorders and determined that the maximum discharge flow achieved by the 2B SX pump was approximately 36,000 gpm and that the maximum flow established to the Unit 2 CC heat exchanger was approximately 22,000 gpm. The licensee performed an operability evaluation to evaluate whether the 2B SX pump and/or the Unit 2 CC heat exchanger had been damaged. The licensee determined that the 2B SX pump did not exceed pump run out hydraulic conditions and therefore was not damaged. This conclusion was based on examining the 2B SX pumps pump curve, conversations with the vendor, and the field observations that no pump cavitations were observed. With respect to the Unit 2 CC heat exchanger, the licensee concluded that the excess flow through the heat exchanger was within the vendor specifications that the heat exchanger was capable of successfully passing twice the nominal flow capacity of 19,900 gpm in emergency situations for short period of times without damage.

At the end of the inspection period, the licensee was evaluating past operability and the ability of the SX system to meet its safety function during the brief period of time the incorrect valve was operated.

Analysis:

The inspectors determined that the licensees failure to adequately implement an IST surveillance procedure was a performance deficiency. This issue was determined to be more than minor because it was associated with the Human Performance attribute in the Mitigating Systems Cornerstone and adversely affected the cornerstones objective of ensuring the availability of systems that respond to initiating events to prevent undesirable consequences.

The inspectors evaluated the finding in accordance with IMC 0609, Safety Significance Process. The inspectors determined that a Phase 2 evaluation was required because the finding represented a potential loss of the SX system safety function. The inspectors performed an SDP Phase 2 evaluation using the pre-solved SDP worksheets for Braidwood. The Phase 2 SDP worksheets indicated a potentially greater than Green finding based on a loss of function with a less-than-3-day exposure time.

An SDP Phase 3 analysis was performed based on the conservative Phase 2 results.

The Phase 3 analysis assumed a bounding complete loss of safety function for 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br />.

The increase in core damage probability was conservatively calculated to be less than 1.0 E-7. The dominant sequence was a transient followed by the loss of SX and a failure to provide alternate reactor coolant pump seal cooling which resulted in a seal Loss of Coolant Accident event that would not be recoverable.

The finding had a cross-cutting aspect in the Human Performance area, Work Practice component. Specifically, licensee programmatic human error prevention techniques were not effectively used to ensure that the surveillance activity was performed in a planned safe manner (H.4(a)).

Enforcement:

10 CFR Part 50, Appendix B, Appendix B, Criterion V, Instructions, Procedures, and Drawings, requires, in part, that activities affecting quality shall be prescribed by documented instructions, procedures, or drawings, of a type appropriate to the circumstances and shall be accomplished in accordance with these instructions, procedures, or drawings.

Contrary to the above, on August 24, 2010, the licensee failed to follow Step 3B of Procedure 2BwOSR 5.5.8.SX-3B, Group A Inservice Testing Requirements for 2B SX Pump (2SX01PB), Revision 1. This temporarily rendered the Unit 2 SX system inoperable for approximately 5 minutes. Because this violation was of very low safety significance, was not repetitive or willful, and it was entered into the licensees CAP as IR 01105448, this violation is being treated as an NCV, consistent with Section 2.3.2 of the NRC Enforcement Policy. Corrective actions for this issue included returning the Unit 2 SX system to operable status by restoring the required valve lineup and a corrective action assignment to provide additional training to the operating crews on the use of human error prevention techniques. (NCV 05000456/2010004-03; 05000457/2010004-03, Unplanned Cooling Water Flow Reduction during Essential Service Water IST Surveillance)

1EP6 Drill Evaluation

Emergency Preparedness Drill Observation

a. Inspection Scope

The inspectors evaluated the conduct of a routine licensee emergency drill on July 21, 2010, to identify any weaknesses and deficiencies in classification, notification, and protective action recommendation development activities. The inspectors observed emergency response operations in the simulated control room 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

Potentially Inadequate Emergency Preparedness Critique

Introduction:

An URI was identified to determine whether the licensees critique process adequately identified the appropriate weaknesses associated with a Drill & Exercise Performance (DEP) PI failure on July 21, 2010.

Description:

The Emergency Preparedness Cornerstone licensee response band was established by the PI scheme and the licensees CAP. Identified weaknesses come from drill and exercise critiques. The baseline inspection program was based on identification and correction of these performance weaknesses and on accurate PI data.

The DEP PI was based on the licensees ability to determine whether a PI opportunity was successful.

On July 21, 2010, the licensee conducted a combined simulator, TSC, and Operational Support Center emergency preparedness full-scale drill. The NRC inspectors observed this drill from the TSC and the simulator. The licensee concluded that the overall performance during the drill was satisfactory, including successfully demonstrating seven of eight DEP PIs.

The licensee identified one drill deficiency for the inappropriate inject by the TSC lead controller. The licensee determined that this inject caused the general emergency classification to be rated as a failure for the DEP PI.

The NRC inspectors questioned the adequacy of the critique process regarding the basis of this DEP PI failure. According to the licensees final critique, the scenario was designed such that the first indication for meeting the General Emergency declaration threshold (Time T=0) was based on Controller Message, CM-10. Accordingly, at the time CM-10 was given to the drill players, there was no indication available to the players that a General Emergency was required to be declared.

In the next 15 minutes, TSC players did not declare a General Emergency. After 17 minutes, the lead controller informed the Station Emergency Director that the time limit for classification of the General Emergency was exceeded and instructed the Emergency Director to declare a General Emergency. Based on this, the Station Emergency Director declared a General Emergency, as expected in the scenario.

However, the licensees final critique determined that the Station Emergency Director did not have sufficient evidence that plant conditions could not be recovered such that the threshold for a General Emergency was met. Therefore, the licensee concluded that the Station Emergency Director was correct in not declaring the General Emergency.

Furthermore, the licensee determined that the reason for the DEP PI failure was due to the improper inject provided by the lead controller.

The inspectors opened this URI to determine whether a performance deficiency exists regarding the licensees ability to observe, identify, evaluate, and critique a weakness associated with a risk significant planning standard. This URI will remain open pending a review of the licensees critique process to determine if it adequately identified the appropriate weakness(es) associated with the failure of the DEP PI.

(URI 05000456/2010004-04; 05000457/2010004-04, Potentially Inadequate Emergency Preparedness Critique)

RADIATION SAFETY

Cornerstones: Occupational and Public Radiation Safety

2RS8 Radioactive Solid Waste Processing and Radioactive Material Handling, Storage, and

Transportation (71124.08) This inspection constituted one sample as defined in IP 71124.08 05.

.1 Inspection Planning

a. Inspection Scope

The inspectors reviewed the solid radioactive waste system description in the UFSAR, the Process Control Program (PCP), and the recent radiological effluent release report for information on the types, amounts, and processing of radioactive waste disposed.

The inspectors reviewed the scope of any quality assurance (QA) audit in this area since the last inspection to gain insights into the licensees performance and inform the smart sampling inspection planning.

b. Findings

No findings of significance were identified.

.2 Radioactive Material Storage

a. Inspection Scope

The inspectors selected areas where containers of radioactive waste were stored in the Braidwood radwaste building, and evaluated whether the containers were labeled in accordance with 10 CFR 20.1904, Labeling Containers, or controlled in accordance with 10 CFR 20.1905, Exemptions to Labeling Requirements, as appropriate.

The inspectors assessed whether the radioactive materials storage areas were controlled and posted in accordance with the requirements of 10 CFR Part 20, Standards for Protection against Radiation. For materials stored or used in the controlled or unrestricted areas, the inspectors evaluated whether they were secured against unauthorized removal and controlled in accordance with 10 CFR 20.1801, Security of Stored Material, and 10 CFR 20.1802, Control of Material Not in Storage, as appropriate.

The inspectors evaluated whether the licensee established a process for monitoring the impact of long term storage (e.g., buildup of any gases produced by waste decomposition, chemical reactions, container deformation, loss of container integrity, or re-release of free-flowing water) that was sufficient to identify potential unmonitored, unplanned releases or nonconformance with waste disposal requirements.

The inspectors inspected several containers of stored radioactive materials for signs of swelling, leakage, and deformation.

b. Findings

No findings of significance were identified.

.3 Radioactive Waste System Walkdown

a. Inspection Scope

The inspectors walked down accessible portions of selected radioactive waste processing systems to assess whether the current system configuration and operation was consistent with descriptions in the UFSAR, offsite dose calculation manual, and PCP.

The inspectors reviewed administrative and physical controls (i.e., drainage and isolation of the system from other systems) to verify that equipment that was not-in-service or abandoned in place would not contribute to an unmonitored release path, affect operating systems, or be a source of unnecessary personnel exposure. The inspectors assessed whether the licensee reviewed the safety significance of systems and equipment abandoned in place in accordance with 10 CFR 50.59, Changes, Tests, and Experiments.

The inspectors reviewed the adequacy of changes made to the radioactive waste processing systems since the last inspection. The inspectors evaluated whether changes from what was described in the UFSAR were reviewed and documented in accordance with 10 CFR 50.59, as appropriate, and assessed the impact on radiation doses to members of the public.

For selected processes for transferring radioactive waste resin and/or sludge discharges into shipping/disposal containers, the inspectors assessed whether the waste stream mixing, sampling procedures, and methodology for waste concentration averaging were consistent with the PCP, and provided representative samples of the waste product for the purposes of waste classification as described in 10 CFR 61.55, Waste Classification.

The inspectors evaluated whether the tank recirculation procedures provided sufficient mixing for systems that provide tank recirculation.

The inspectors assessed whether the licensees PCP correctly described the current methods and procedures for dewatering and waste stabilization (e.g., removal of freestanding liquid).

b. Findings

No findings of significance were identified.

.4 Waste Characterization and Classification

a. Inspection Scope

The inspectors selected the following Braidwood radioactive waste streams for review:

• Dry Active Waste Stream;

• Primary Filter Stream; and

• Radwaste Filter Stream.

For the waste streams listed above, the inspectors assessed whether the licensees radiochemical sample analysis results (i.e., 10 CFR Part 61" analysis) were sufficient to support radioactive waste characterization as required by 10 CFR Part 61, Licensing Requirements for Land Disposal of Radioactive Waste. The inspectors evaluated whether the licensees use of scaling factors and calculations to account for difficult-to-measure radionuclides was technically sound and based on current 10 CFR Part 61 analyses for the selected radioactive waste streams.

The inspectors evaluated whether changes to plant operational parameters were taken into account to:

(1) maintain the validity of the waste stream composition data between the annual or biennial sample analysis update; and

(2) assure that waste shipments continued to meet the requirements of 10 CFR Part 61 for the waste streams selected above.

The inspectors evaluated whether the licensee had established and maintained an adequate QA program to ensure compliance with the waste classification and characterization requirements of 10 CFR 61.55 and 10 CFR 61.56, Waste Characteristics.

b. Findings

No findings of significance were identified.

.5 Shipment Preparation

a. Inspection Scope

The inspectors observed shipment packaging, surveying, labeling, marking, placarding, vehicle checks, emergency instructions, disposal manifest, shipping papers provided to the driver, and licensee verification of shipment readiness. The inspectors assessed through reviews whether the requirements of applicable transport cask certificate of compliance had been met. The inspectors evaluated whether the receiving licensee was authorized to receive the shipment packages. The inspectors evaluated whether the licensees procedures for cask loading and closure procedures were consistent with the vendors current approved procedures.

The inspectors observed radiation workers during the conduct of radioactive waste processing and radioactive material shipment preparation and receipt activities. The inspectors assessed whether the shippers were knowledgeable of the shipping regulations and whether shipping personnel demonstrated adequate skills to accomplish the package preparation requirements for public transport with respect to:

• the licensees response to NRC Bulletin 79-19, Packaging of Low-Level Radioactive Waste for Transport and Burial, dated August 10, 1979; and

• 49 CFR Part 172, Hazardous Materials Table, Special Provisions, Hazardous Materials Communication, Emergency Response Information, Training Requirements, and Security Plans, Subpart H, Training.

Additionally, due to limited opportunities for direct observation, the inspectors reviewed the technical instructions presented to workers during a routine radwaste operation. The inspectors assessed whether the licensees training program provided to personnel responsible for the conduct of radioactive waste processing and radioactive material shipment preparation activities.

b. Findings

No findings of significance were identified.

.6 Shipping Records

a. Inspection Scope

The inspectors assessed whether the shipping documents indicated the proper shipper name; emergency response information and a 24-hour contact telephone number; accurate curie content and volume of material; and appropriate waste classification, transport index, and United Nation number for several radioactive shipments that occurred between January 2009 and July 2010. Additionally, the inspectors assessed whether the shipment placarding was consistent with the information in the shipping documentation.

b. Findings

No findings of significance were identified.

.7 Identification and Resolution of Problems

a. Inspection Scope

The inspectors assessed whether problems associated with radioactive waste processing, handling, storage, and transportation, were being identified by the licensee at an appropriate threshold, were properly characterized and were properly addressed for resolution in the licensee CAP. Additionally, the inspectors assessed whether the corrective actions were appropriate for a selected sample of problems documented by the licensee that involve radioactive waste processing, handling, storage, and transportation.

The inspectors reviewed results of selected audits performed since the last inspection of this program and evaluated the adequacy of the licensees corrective actions for issues identified during those audits.

b. Findings

No findings of significance were identified.

4OA1 Performance Indicator Verification

.1 Safety System Functional Failures

a. Inspection Scope

The inspectors sampled licensee submittals for the Safety System Functional Failures performance indicator (PI) for both Unit 1 and Unit 2 for the period from the third quarter 2009 to the second quarter 2010. To determine the accuracy of the PI data reported during those periods, PI definitions and guidance contained in the Nuclear Energy Institute (NEI) Document 99-02, Regulatory Assessment Performance Indicator Guideline, Revision 6, dated October 2009, and NUREG-1022, Event Reporting Guidelines 10 CFR 50.72 and 10 CFR 50.73," definitions and guidance, were used.

The inspectors reviewed the licensees operator narrative logs, operability assessments, maintenance rule records, maintenance work orders, IRs, event reports and NRC Integrated Inspection Reports for the period of July 1, 2009, through June 30, 2010, 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. Documents reviewed are listed in the to this report.

This inspection constituted two safety system functional failures PI samples as defined in IP 71151-05.

b. Findings

No findings of significance were identified.

.2 Mitigating Systems Performance Index - Emergency Alternating Current Power System

a. Inspection Scope

The inspectors sampled licensee submittals for the Mitigating Systems Performance Index (MSPI) - Emergency Alternating Current Power System PI for both Unit 1 and Unit 2 for the period from the third quarter 2009 to the second quarter 2010. To determine the accuracy of the PI data reported during those periods, PI definitions and guidance contained in the NEI Document 99-02, Regulatory Assessment Performance Indicator Guideline, Revision 6, dated October 2009, were used. The inspectors reviewed the licensees operator narrative logs, MSPI derivation reports, issue reports, event reports and NRC Integrated Inspection Reports for the period of July 1, 2009 through June 30, 2010, to validate the accuracy of the submittals. The inspectors reviewed the MSPI component risk coefficient to determine if it had changed by more than 25 percent in value since the previous inspection, and, if so, verified that the change was in accordance with applicable NEI guidance. The inspectors also reviewed the licensees IR database to determine if any problems had been identified with the PI data collected or transmitted for this indicator. Documents reviewed are listed in the to this report.

This inspection constituted two emergency ac power system PI samples as defined in IP 71151-05.

b. Findings

No findings of significance were identified.

.3 Mitigating Systems Performance Index - High Pressure Injection Systems

a. Inspection Scope

The inspectors sampled licensee submittals for the MSPI - High Pressure Injection Systems PI for Braidwood Unit 1 and Unit 2 for the period from the fourth quarter 2009 to the second quarter 2010. To determine the accuracy of the PI data reported during those periods, PI definitions and guidance contained in the NEI Document 99-02, Regulatory Assessment Performance Indicator Guideline, Revision 6, dated October 2009, were used. The inspectors reviewed the licensees operator narrative logs, IRs, MSPI derivation reports, event reports and NRC Integrated Inspection Reports for the period of October 1, 2009, through June 30, 2010, to validate the accuracy of the submittals. The inspectors reviewed the MSPI component risk coefficient to determine if it had changed by more than 25 percent in value since the previous inspection, and if so, verified that the change was in accordance with applicable NEI guidance. The inspectors also reviewed the licensees IR 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 high pressure injection system PI samples as defined in IP 71151-05.

b. Findings

No findings of significance were identified.

.4 Mitigating Systems Performance Index - Heat Removal System

a. Inspection Scope

The inspectors sampled licensee submittals for the MSPI - Heat Removal System PI for Braidwood Unit 1 and Unit 2 for the period from the fourth quarter 2009 to the second quarter 2010 to determine the accuracy of the PI data reported during those periods, PI definitions and guidance contained in the NEI Document 99-02, Regulatory Assessment Performance Indicator Guideline, Revision 6, dated October 2009, were used. The inspectors reviewed the licensees operator narrative logs, IRs, event reports, MSPI derivation reports, and NRC Integrated Inspection Reports for the period of October 1, 2009, through June 30, 2010, to validate the accuracy of the submittals. The inspectors reviewed the MSPI component risk coefficient to determine if it had changed by more than 25 percent in value since the previous inspection, and if so, verified that the change was in accordance with applicable NEI guidance. The inspectors also reviewed the licensees issue report database to determine if any problems had been identified with the PI data collected or transmitted for this indicator and none were identified.

Documents reviewed are listed in the Attachment to this report.

This inspection constituted two heat removal system PI samples as defined in IP 71151-05.

b. Findings

No findings of significance were identified.

.5 Mitigating Systems Performance Index - Residual Heat Removal System

a. Inspection Scope

The inspectors sampled licensee submittals for the MSPI - Residual Heat Removal System PI for Braidwood Unit 1 and Unit 2 for the period from the first quarter 2010 to the second quarter 2010. To determine the accuracy of the PI data reported during those periods, PI definitions and guidance contained in the NEI Document 99-02, Regulatory Assessment Performance Indicator Guideline, Revision 6, dated October 2009, were used. The inspectors reviewed the licensees operator narrative logs, IRs, MSPI derivation reports, event reports and NRC Integrated Inspection Reports for the period of January 1, 2010, through June 30, 2010, to validate the accuracy of the submittals. The inspectors reviewed the MSPI component risk coefficient to determine if it had changed by more than 25 percent in value since the previous inspection, and if so, verified that the change was in accordance with applicable NEI guidance. The inspectors also reviewed the licensees issue report database to determine if any problems had been identified with the PI data collected or transmitted for this indicator and none were identified. Documents reviewed are listed in the Attachment to this report.

This inspection constituted two residual heat removal system PI samples as defined in IP 71151-05.

b. Findings

No findings of significance were identified.

.6 Mitigating Systems Performance Index - Cooling Water Systems

a. Inspection Scope

The inspectors sampled licensee submittals for the MSPI - Cooling Water Systems PI for Braidwood Unit 1 and Unit 2 for the period from the first quarter 2010 to the second quarter 2010. To determine the accuracy of the PI data reported during those periods, PI definitions and guidance contained in the NEI Document 99-02, Regulatory Assessment Performance Indicator Guideline, Revision 6, dated October 2009, were used. The inspectors reviewed the licensees operator narrative logs, IRs, MSPI derivation reports, event reports and NRC Integrated Inspection Reports for the period of January 1, 2010, through June 30, 2010, to validate the accuracy of the submittals. The inspectors reviewed the MSPI component risk coefficient to determine if it had changed by more than 25 percent in value since the previous inspection, and if so, verified that the change was in accordance with applicable NEI guidance. The inspectors also reviewed the licensees issue report database to determine if any problems had been identified with the PI data collected or transmitted for this indicator and none were identified. Documents reviewed are listed in the Attachment to this report.

This inspection constituted two cooling water system PI samples as defined in IP 71151-05.

b. Findings

No findings of significance were identified.

.4 Occupational Exposure Control Effectiveness

a. Inspection Scope

The inspectors sampled licensee submittals for the Occupational Radiological Occurrences PI for the period from the first quarter 2009 through first quarter 2010.

The inspectors used PI definitions and guidance contained in the NEI Document 99-02, Regulatory Assessment Performance Indicator Guideline, Revision 5 to determine the accuracy of the PI data reported during those periods. The inspectors reviewed the licensees assessment of the PI for occupational radiation safety to determine if indicator related data was adequately assessed and reported. To assess the adequacy of the licensees PI data collection and analyses, the inspectors discussed with radiation protection staff, the scope, and breadth of its data review, and the results of those reviews. The inspectors independently reviewed electronic dosimetry dose rate and accumulated dose alarm and dose reports and the dose assignments for any intakes that occurred during the time period reviewed to determine if there were potentially unrecognized occurrences. The inspectors also conducted walkdowns of locked high radiation area entrances to determine the adequacy of the controls in place for these areas. Documents reviewed are listed in the Attachment to this report.

This inspection constituted one occupational radiological occurrences PI sample as defined in IP 71151-05.

b. Findings

No findings of significance were identified.

.5 Radiological Effluent Technical Specifications/Offsite Dose Calculation Manual

Radiological Effluent Occurrences

a. Inspection Scope

The inspectors sampled licensee submittals for the Radiological Effluent Technical Specifications (RETS)/ Offsite Dose Calculation Manual (ODCM) Radiological Effluent Occurrences PI for the period between the first quarter of 2009 and the first quarter of 2010. The inspectors used PI definitions and guidance contained in the NEI Document 99-02, Regulatory Assessment Performance Indicator Guideline, Revision 5 to determine the accuracy of the PI data reported during those periods. The inspectors reviewed the licensees issue report database and selected individual reports generated since this indicator was last reviewed to identify any potential occurrences such as unmonitored, uncontrolled, or improperly calculated effluent releases that may have impacted offsite dose. The inspectors reviewed gaseous effluent summary data and the results of associated offsite dose calculations for selected dates between January 2009 and May 2010 to determine if indicator results were accurately reported. The inspectors also reviewed the licensees methods for quantifying gaseous and liquid effluents and determining effluent dose. Documents reviewed are listed in the Attachment to this report.

This inspection constituted one RETS/ODCM radiological effluent occurrences PI sample 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

.1 Routine Review of Items Entered into the Corrective Action Program

a. Inspection Scope

As part of the various baseline inspection procedures discussed in previous sections of this report, the inspectors routinely reviewed issues during baseline inspection activities and plant status reviews to verify 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 Attachment to this report.

These routine reviews for the identification and resolution of problems did not constitute any additional inspection samples. Instead, by procedure they were considered an integral part of the inspections performed during the quarter and documented in Section 1 of this report.

b. Findings

No findings of significance were identified.

.2 Daily Corrective Action Program Reviews

a. Inspection Scope

In order to assist with the identification of repetitive equipment failures and specific human performance issues for followup, 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.

4OA3 Followup of Events and Notices of Enforcement Discretion

Fire Brigade and Operations Response to a Small Fire in the Turbine Building

c. Inspection Scope

On August 22, 2010, at 3:29 p.m., equipment operators identified a small fire originating from lagging on a 2B feedwater pump steam line. The operators immediately reported the fire to the main control room and extinguished the fire within 3 minutes by utilizing a locally staged fire extinguisher. The main control room announced the fire and took action to start the 2A feedwater pump and then tripped the running 2B feedwater pump in accordance with station procedures. The station fire brigade was dispatched and responded promptly after the station fire alarm was sounded. Additional mitigating actions were taken to cool the lagging with water and a reflash watch was stationed.

The resident inspectors verified that the station followed the appropriate procedures to address both a fire and prompt transfer of running feedwater pumps. Additionally, the inspectors verified that Operations had reviewed the stations emergency action levels and had an adequate basis to support not declaring a station event. The fire was extinguished in less than 15 minutes and did not affect or pose a challenge to any safety-related equipment. Additionally, the inspectors verified that the licensee had entered the condition into the CAP.

This event followup review constituted one sample as defined in IP 71153-05.

d. Findings

No findings of significance were identified.

.6 Unit 2 Trip on August 16, 2010 - Dual Unit Plant Trip

a. Inspection Scope

On August 16, 2010, at 2:06 a.m., the Unit 2 reactor tripped due to a main generator lockout relay actuation. Following the reactor trip, all safety systems functioned as designed with the exception of one auxiliary feedwater flow control valve, which failed in its safety-related open position.

Following the reactor trip, the Unit 2 main condenser hotwell began to rise, as expected, as steam was exhausted into the condenser. After the hotwell level reached a high level setpoint, the hotwell level control valves automatically opened to send water to the units condensate storage tank. During this transfer, water from open-ended risers then was released on the 451 elevation and impacted a Unit 1 motor control center. The resulting loss of this motor control center caused a loss of two circulating water pumps on Unit 1.

The resident inspectors discussed the cause of the reactor trip with operations, engineering and licensee management personnel to gain an understanding of the event and assess follow-up actions. The inspectors also discussed the event with the licensees root cause analysis team and assessed the teams actions to gather, review, and assess information regarding the cause of the reactor trip. The inspectors later reviewed the initial investigation and cause determination to assess the detail of review, the adequacy of the root cause and the proposed corrective actions prior to unit restart.

The licensees preliminary investigation identified that the cause of the trip was a ground fault in the turbine. Also, the resident inspectors observed operations personnel in the control room, reviewed procedures, sequence of event logs, narrative logs and emergency response computer system data. The inspectors also used this information to determine whether operations personnel had responded appropriately following the reactor trip.

This event followup review constituted one sample as defined in IP 71153-05.

b. Findings

No findings of significance were identified.

.7 Unit 1 Trip on August 16, 2010 - Dual Unit Plant Trip

a. Inspection Scope

On August 16, 2010, following the Unit 2 reactor trip, at 2:19 a.m., the Unit 1A and 1C circulating water pumps tripped, which caused a Unit 1 automatic reactor trip on low condenser vacuum. Due to the loss of the condenser, operators maintained Unit 1 temperature and pressure using steam generator power operated relief valves.

Following the Unit 1 reactor trip, the 1D steam generator safety relief valve stuck partially open. The resident inspectors discussed the cause of the reactor trip with operations, engineering and licensee management personnel to gain an understanding of the event and assess follow-up actions. The inspectors met with the licensees root cause analysis team and assessed the teams actions to gather, review, and assess information regarding the cause of the reactor trip. The inspectors later reviewed the initial investigation and cause determination to assess the detail of review, the adequacy of the root cause and the proposed corrective actions prior to unit restart. The licensees preliminary investigation identified that the cause of the trip was related to water intrusion into a motor control center. The water originated from an open-ended vent riser on the Unit 2 auxiliary feedwater suction piping.

The resident inspectors observed operations personnel in the control room, reviewed procedures, sequence of event logs, narrative logs and emergency response computer system data. Also, the inspectors discussed the cause of the reactor trip with operations, engineering and licensee management personnel to gain an understanding of the event and assess follow-up actions. The inspectors also used this information to determine whether operations personnel had responded appropriately following the reactor trip.

This event followup review constituted one sample as defined in IP 71153-05.

b. Findings

No findings of significance were identified

.8 Unit 1 Trip on September 20, 2010

a. Inspection Scope

On September 20, 2010, at 5:04 p.m., Braidwood Unit 1 experienced an automatic reactor trip. When the trip occurred, two surveillances were taking place, a power range N43 calibration and a calibration of the 1C steam generator narrow level range channel.

The resident inspectors discussed the cause of the reactor trip with operations, engineering and licensee management personnel to gain an understanding of the event and assess follow-up actions. The inspectors also discussed this event with the licensees root cause analysis team and assessed the teams actions to gather, review, and assess information regarding the cause of the reactor trip. The inspectors later reviewed the initial investigation and cause determination to assess the detail of review, the adequacy of the root cause and the proposed corrective actions prior to unit restart.

The licensees preliminary investigation identified that the cause of the trip was related to a failed Solid State Protection System universal card that provided the two out of four logic with a second channel out due to the surveillance.

The inspectors observed operations personnel in the control room, reviewed procedures, sequence of event logs, narrative logs and emergency response computer system data, and held discussions with licensee personnel to determine the cause of a Unit 1 automatic reactor trip. The inspectors also used this information to determine whether operations personnel had responded appropriately following the reactor trip.

This event followup 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 October 1, 2010, the inspectors presented the inspection results to Mr. A. Shahkarami, and other members of the licensee staff. The licensee acknowledged the issues presented. The inspectors confirmed that none of the potential report input discussed was considered proprietary.

.2 Interim Exit Meetings

On July 16, 2010, an interim exit was conducted for the radioactive solid waste processing and radioactive material handling, storage, and transportation inspection and two PI verifications under the Public and Occupational Radiation Safety Cornerstones with Mr. A. Shahkarami and other members of the licensee staff.

The inspectors confirmed that none of the potential report input discussed was considered proprietary. Proprietary material received during the inspection was returned to the licensee.

4OA7 Licensee-Identified Violations

The following violations of very low safety significance (Green) were identified by the licensee and are violations of NRC requirements which meet the criteria of Section 2.3.2 of the NRC Enforcement Policy for being dispositioned as NCVs.

• 10 CFR 50.65(a)(4) requires, in part, that before performing maintenance activities (including but not limited to surveillance, post-maintenance testing, and corrective and preventive maintenance), the licensee shall assess and manage the increase in risk that may result from the proposed maintenance activities.

Contrary to the above, on July 7, 2010, the licensee failed to assess and manage the increase in risk with the main steam dump valve 1MS004E and steam generator power operated relief valve 1MS018D out-of-service for maintenance at the same time. This issue was determined to be of very low safety significance and was entered into the licensees CAP (IR1102435).

• 10 CFR 50.65(a)(4) requires, in part, that before performing maintenance activities (including but not limited to surveillance, post-maintenance testing, and corrective and preventive maintenance), the licensee shall assess and manage the increase in risk that may result from the proposed maintenance activities.

Contrary to the above, on August 16, 2010, the licensee failed to assess and manage the increase in risk following a dual unit trip. Specifically, a Yellow risk configuration was not identified by the licensee in accordance with station procedures after the main power transformer breakers were opened following an August 16, 2010, dual unit trip. This issue was determined to be of very low safety significance and was entered into the licensees CAP (IR1102435).

ATTACHMENT:

SUPPLEMENTAL INFORMATION

KEY POINTS OF CONTACT

Licensee

A. Shahkarami, Site Vice President

L. Coyle, Plant Manager

D. Evans, Security Operations Manager

S. Butler, Emergency Preparedness Manager

P. Daly, Radiation Protection Manager

R. Gadbois, Maintenance Manager

G. Galloway, Work Control Manager

R. Gaston, Regulatory Assurance Manager

J. Knight, Nuclear Oversight Manager

M. Marchionda, Operations Manager

J. Moser, Radiation Protection Manager

T. Schuster, Chemistry/Environmental Manager

M. Smith, Engineering Manager

Nuclear Regulatory Commission

E. Duncan, Chief, Branch 3, Division of Reactor Projects

B. Dickson, Chief, Plant Support Team, Division of Reactor Safety

LIST OF ITEMS

Opened

05000456/2010004-01; NCV Failure to Follow Procedure for Temporary Scaffolds

05000457/2010004-01 (Section 1R18.1.b(1))

05000456/2010004-02; URI Temporary Scaffold Quality Control Process

05000457/2010004-02 (Section 1R18.1.b(2))

05000456/2010004-03; NCV Unplanned Cooling Water Flow Reduction during

05000457/2010004-03 Essential Service Water IST Surveillance (Section 1R22.1.b)

05000456/2010004-04; URI Potentially Inadequate Emergency Preparedness Critique

05000457/2010004-04 (Section 1EP6.b)

Closed

05000456/2010004-01; NCV Failure to follow Procedures for Temporary Scaffolds

05000457/2010004-01 (Section 1R18.1)

05000456/2010004-0X; NCV Unplanned Cooling Water Flow Reduction during

05000457/2010004-0X Essential Service Water IST Surveillance (Section 1R22.1)

Discussed

None Attachment