IR 05000456/2008003

H. 4.(c)) because the licensee did not ensure that supervisory and management oversight of the procedure was adequate to assure nuclear safety. (Section 2

BR-654, "Unit 1(2) Containment Access Facility Liquid and Air Sampling and Disposal Requirements, Revision 0," as written, did not direct the required sampling frequency. The licensee took immediate corrective action by sampling the temporary storage tank, revising the scheduling tool to ensure that the tanks are sampled at least every seven days when radioactive material is being added to the tank,

and planning to revise the sampling procedure. The finding involved an occurrence in the licensee's radioactive material control program that is contrary to the licensee's procedures. The finding was more than minor because it impacted the program and process attribute of the Public Radiation Safety Cornerstone and affected the cornerstone objective to ensure adequate protection of public health and safety from exposure to radioactive material release into the public

domain, in that the failure to measure the levels of radioactivity in the temporary storage

Enclosure tanks had the potential to impact the licensee's effluent program. The inspectors applied the

IMC [[0609, Appendix D, "Public Radiation Safety Significance Determination Process" to this finding. The finding is in the licensee's radiological effluent monitoring program. The finding did not involve a failure to implement the effluent release program nor did public dose exceed Appendix I, Criterion, or 10]]

CFR 20.1302(e) and the finding was determined to be of very low safety significance. The primary cause of this

PS2.1) B. Licensee-Identified Violations No violations of significance were identified.

Enclosure

REPORT [[]]

DETAILS Summary of Plant Status Unit 1 operated at or near full power for the entire inspection period. Unit 2 operated at or near full power until about April 15, 2008, when a gradual power coast down was started toward a refueling outage. The unit was brought from 95 percent of full power to 80 percent on April 17 for main steam relief valve testing and then back to 92 percent of full

power on April 18. The unit continued to coast down until being shutdown from 90 percent power on April 20, 2008, for the refueling. The unit was made critical at the end of the outage on May 16, 2008, the generator was placed on line on May 17, 2008, and the power was gradually increased, reaching full power on May 25, 2008. The unit operated at or near full power for the remainder of the inspection period. 1.

REACTO R

SAFETY Cornerstone: Initiating Events, Mitigating Systems, and Barrier Integrity 1R01 Adverse Weather Protection (71111.01) .1 Summer Readiness of Offsite and Alternating Current Power Systems a. Inspection Scope The inspectors verified that plant features and procedures for operation and continued availability of offsite and alternating current (AC) power systems during adverse weather

were appropriate. The inspectors reviewed the licensee's procedures affecting these areas and the communications protocols between the transmission system operator (TSO) and the plant to verify that the appropriate information was being exchanged when issues arose that could impact the offsite power system. Examples of aspects considered in the inspectors' review included: * coordination between the

TSO and the plant during off-normal or emergency events; * explanations for the events; * estimates of when the offsite power system would be returned to a normal state; and * notifications from the

TSO to the plant when the offsite power system was returned to normal. The inspectors also verified that plant procedures addressed measures to monitor and maintain availability and reliability of both the offsite

AC power system and the onsite alternate

AC power system prior to or during adverse weather conditions. Specifically, the inspectors verified that the procedures addressed the following: * the actions to be taken when notified by the TSO that the post-trip voltage of the offsite power system at the plant would not be acceptable to assure the continued operation of the safety-related loads without transferring to the onsite power supply;

Enclosure * the compensatory actions identified to be performed if it would not be possible to predict the post-trip voltage at the plant for the current grid conditions; * a re-assessment of plant risk based on maintenance activities which could affect grid reliability, or the ability of the transmission system to provide offsite power; and * the communications between the plant and the

TSO [[when changes at the plant could impact the transmission system, or when the capability of the transmission system to provide adequate offsite power was challenged. Documents reviewed were listed in the Attachment. The inspectors also reviewed corrective action program (]]

CAP ) items to verify that the licensee was identifying adverse weather issues at an appropriate threshold and entering them into their

CAP in accordance with station corrective action procedures. This inspection constituted one readiness of offsite and alternate

AC [[power systems sample as defined in Inspection Procedure (IP) 71111.01-05. b. Findings No findings of significance were identified. .2 Readiness for Summer Seasonal Extreme Weather Conditions a. Inspection Scope The inspectors performed a review of the licensee's preparations for summer weather for selected systems, including conditions that could lead to an extended drought as a result of high temperatures. During the inspection, the inspectors focused on plant specific design features and the licensee's procedures used to mitigate or respond to adverse weather conditions. Additionally, the inspectors reviewed the Updated Final Safety Analysis Report (UFSAR) and performance requirements for systems selected for inspection, and verified that operator actions were appropriate as specified by plant specific procedures. The inspectors also reviewed]]

CAP items to verify that the licensee was identifying adverse weather issues at an appropriate threshold and entering them into their

CAP in accordance with station corrective action procedures. Documents reviewed were listed

in the Attachment. The inspectors' reviews focused specifically on the following plant systems: * cooling water lake (ultimate heat sink); * transformer yard; and * turbine oil system. This inspection constituted one seasonal adverse weather sample as defined in

IP 71111.01-05. b. Findings Introduction: The inspectors identified a Non-Cited Violation (

NCV) of Technical Specifications (TS) 5.4.1.a having very low safety significance (Green) for unauthorized

Enclosure and improper storage of unsecured material in the designated material exclusion area around the Units 1 and 2 transformers. Description: On April 30, 2008, the inspectors identified three metal scaffold poles and a large floor rug in the exclusion area of the Unit 1 transformer yard. The inspectors notified the shift manager who immediately had the material removed and entered the issue into the

CAP as Issue Report (

IR) 770357. The Shift Manager indicated that he

had not given permission, as required by Procedure

AA-716-026, "Station Housekeeping/Material Condition Program," for the material to be in the exclusion area. On May 22, 2008, the inspectors identified four metal stanchions and associated garden hoses staged, two each, in the Units 1 and 2 transformer yards. The material had been staged as a contingency for providing supplemental cooling to the main power

transformers as a summer readiness action, but the material was not secured. Although the staging had the permission of the Shift Manager, it was not done in accordance with the applicable Procedure, BwOP MP-26, "Supplemental Main Power Transformer Cooling," which required that all hoses in the transformer area be properly secured to prevent the hoses from becoming wind-generated hazards that may cause a loss of offsite power. The inspectors notified the Work Execution Center Supervisor who immediately had the material properly secured with sandbags and entered the issue into

the

IR 778589. On May 28, 2008, the Illinois Department of Emergency Management (IEMA) inspector identified a metal stanchion with a radiation warning sign in the Unit 2 transformer yard. The sign had apparently been removed from the turbine building during floor refinishing and placed in the transformer yard without the permission of the Shift Manager as

required by Procedure

IEMA inspector notified the Work Execution Center Supervisor who immediately had the material removed and entered the issue into the

AA -716-026. The

CAP as IR 780318. On May 29, 2008, the inspectors identified two pieces of a metal door threshold in the exclusion area of the Unit 2 transformers. The material was brought to the attention of

an operations supervisor who immediately removed the material and entered the issue into the

IR 780777. The inspectors noted that this instance, as well as some of the previously mentioned ones, was probably the result of contractors working on turbine building floor refinishing, and clearing material off the floor by putting it through the turbine building door into the exclusion area. The inspectors noted that there were

multiple information signs explaining the exclusion area rules on most of the entry paths into the exclusion areas except that there were no signs on the doors from the turbine building directly into the areas. This observation was also entered into the licensee's

CAP as part of

IR 780777. Analysis: The inspectors determined that the identification of multiple examples of improperly placing unsecured material in the transformer yard exclusion zones was a performance deficiency warranting a significance evaluation. The finding was more than minor because it involved the external factors attribute of the Initiating Events cornerstone and affected the cornerstone objective of limiting the likelihood of those events that could upset plant stability. The inspectors applied the Phase 1 Screening Worksheet of the Significance Determination Process (SDP) and determined that the issue screened out as a Green finding because it did not contribute to both the likelihood

of a reactor trip and the likelihood that mitigating equipment or functions would not be

Enclosure available. The material in the transformer yards could have affected the main power transformers and caused a unit trip, or it could have affected the station auxiliary transformers and increased the likelihood of a loss of mitigating systems, but it was not reasonable that it was enough material to affect both simultaneously. The finding had a cross-cutting aspect in the area of Human Performance in the Work Practices component (H.4.(b)). Multiple groups, including contractors and operators failed to

properly implement the procedures for control of material in the transformer exclusion zones. The preliminary cause appeared to be inadequate supervisory and management oversight of work activities. Enforcement: Technical Specification 5.4.1.a stated that written procedures shall be established, implemented, and maintained covering the applicable procedures

recommended in Regulatory Guide (RG) 1.33, Revision 2, Appendix A, February 1978. Section 1.c of Appendix A recommended procedures for equipment control. Among the procedures the licensee used to implement that requirement were

MP -26. Under the "Storage Practices" section of Attachment 1 of

AA -716-026 and BwOP

MA-AA-716-026 were requirements that no material be brought into or stored inside the exclusion zone areas unless prior permission is received from the Shift Manager, that material shall be secured in the exclusion zone to prevent damage in the event of adverse

weather conditions, and that unsecured scaffold parts must be secured in a manner that will prevent them from becoming missile hazards in the event of severe weather. For the supplemental cooling equipment, BwOP MP-26 contained Precaution D.3, which required that all hoses in the transformer area must be properly secured to prevent the hoses from becoming wind-generated hazards that may cause loss of offsite power, and

Step F.7, which directed the operators to secure the hoses that will be used to provide cooling to the main power transformers. Contrary to the above, on three occasions during the inspection period, the inspectors identified unsecured material in the transformer exclusion areas that were placed in the areas without the Shift Manager's approval or were not properly secured. Because the failure to properly implement the

material control procedures was of very low safety significance, and has been entered into the licensee's

CAP , this violation was treated as an

NCV consistent with Section

VI.A. 1, of the

NRC Enforcement Policy. (NCV 05000456/2008003-01; 05000457/2008003-01) .3 Readiness for Impending Adverse Weather Conditions a. Inspection Scope On May 30, 2008, the plant experienced a tornado watch as well as high winds and thunderstorms in the area. The inspectors reviewed the preparations and actions of site personnel for protection of risk-significant equipment. The inspectors evaluated the implementation of the licensee's adverse weather procedures, risk assessment, and

compensatory actions. No actual tornado occurred in the area during this time period. Documents reviewed were listed in the Attachment. The inspection constitutes one readiness for impending adverse weather conditions sample as defined in IP 71111.01-05, b. Findings No findings of significance were identified.

Enclosure 1R04 Equipment Alignment (71111.04) .1 Quarterly Partial System Walkdowns a. Inspection Scope The inspectors performed partial system walkdowns of the following risk-significant systems: * 2B diesel generator (DG) while 2A

DG was out of service for governor replacement; * 1A

DG while 2A

DG was out of service for planned maintenance; and * 1A auxiliary feedwater (

AFW [[) train while the 1B train was out of service for troubleshooting and repair of the over speed trip circuit. 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; * reviewed applicable operating procedures, system diagrams,]]

UFSAR ,

TS requirements, Administrative

TS , outstanding work orders (

WO [[s), 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; * walked down accessible portions of the systems to verify system components and support equipment were aligned correctly and operable; * examined the material condition of the components and observed operating parameters of equipment to verify that there were no obvious deficiencies; and * verified that the licensee had properly identified and resolved equipment alignment problems that could cause initiating events, or impact the capability of mitigating systems or barriers, and entered them into the]]

CAP with the appropriate significance characterization. Documents reviewed were listed in the Attachment. These activities constituted three partial system walkdown samples as defined by

IP 71111.04-05. b. Findings No findings of significance were identified.

Enclosure 1R05 Fire Protection (71111.05) .1 Routine Resident Inspector Tours (71111.05Q) 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: * engineered safety features switchgear room, Division 11 (Zone 5.1-1); * engineered safety features switchgear room, (Zone 5.2-1); * station auxiliary

DG [[room and diesel oil tank room (Zones 8.7A-0 and 8.7B-0); * auxiliary building elevation 426 (Zone 11.6-0); and * compensatory actions for loss of various Appendix R light packs during Bus 234V outage. The inspectors reviewed areas to assess if the licensee had implemented a fire protection program (]]

FPP) that: * adequately controlled combustibles and ignition sources within the plant; * effectively maintained fire detection and suppression capability; * maintained passive fire protection features in good material condition; and * had implemented adequate compensatory measures for out-of-service, degraded or inoperable fire protection equipment, systems, or features in accordance with the licensee's fire plan. The inspectors selected fire areas based on their overall contribution to internal fire risk as documented in the plant's 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 plant's 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 licensee's

CAP. These activities constituted five quarterly fire protection inspection samples as defined by

IP71111.05-05. b. Findings No findings of significance were identified.

Enclosure 1R06 Flooding (71111.06) .1 Internal Flooding a. Inspection Scope The inspectors performed a walkdown of the following plant area to assess the adequacy of watertight doors and verify drains and sumps were clear of debris and were operable, and that the licensee complied with its commitments: * Essential service water (SX) pump rooms. The inspectors reviewed: * selected risk important plant design features and licensee procedures intended to protect the plant and its safety related equipment from internal flooding events; * flood analyses and design documents, including the

UFSAR [[, engineering calculations, and abnormal operating procedures to identify licensee commitments; * 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; and * the licensee's]]

CAP documents with respect to past flood-related items identified in the

CAP to verify the adequacy of the corrective actions. The specific documents reviewed were listed in the Attachment to this report. This inspection constituted one internal flooding sample as defined in

IP 71111.06-05. b. Findings Introduction: The inspectors identified an

NCV of 10

CFR Part 50, Appendix B, Criterion V, having very low significance (Green) related to a plant barrier impairment (PBI) procedure. Specifically, the procedure did not contain steps to ensure that compensatory measures in the B Train room of SX were maintained, while required

access covers were removed. Description: The

SX was a safety related system needed to remove decay heat in the event of an accident. The

SX pumps were located in the lowest level of the Auxiliary Building. The system was designed to prevent failure from flooding by separation of components and by designing flood barriers in the doors, walls and ceiling. In order to maintain access to equipment in the room, several removable access covers existed. When installed, those access covers were designed to prevent flooding from system

failures in the areas above the

SX [[pump rooms from leaking into the room. With the covers removed, sump leak detection and high level alarms were depended upon to warn operators should a leak from above the room occur. When the access covers were removed, several compensatory measures were directed to be put in place in accordance with Procedure Bw]]

AP 1110-3, "Plant Barrier Impairment

Program." The compensatory measures were pre-evaluated for each cover.

Enclosure On April 2, 2008,

PBI 10586 was authorized to remove equipment cover 2

SXFSO 2-3. This hatch had a pre-defined compensatory action to ensure that the room sump alarms were available. On April 7, 2008, while the

PBI was still in effect, operators determined that the room sump alarms were not functioning. This was documented in the licensee's

WO ) 103501 was initiated to repair the alarm function. The

IR 760446. Work Order (

WO was completed on April 21. The covers remained removed and the

PBI in

effect until after the

WO was completed, thus the warning for flooding from sources above the

SX pump room was known to be unavailable for up to fifteen days while an access cover was removed. Analysis: The inspectors determined that the failure to ensure the compensatory measures remained viable was a performance deficiency warranting a significance

evaluation. The inspectors concluded that the finding was finding was greater than minor in accordance with Inspection Manual Chapter (IMC) 0612, "Power Reactor Inspection Reports," Appendix B, "Issue Disposition Screening," because the licensee failed to effectively manage prescribed compensatory measures related to a cornerstone objective. The increase in flooding hazard affected the protection against external factors attribute of the Initiating Events cornerstone. Using the SDP Phase 1 Screening Worksheet of

IMC 0609, Table 4a, the inspectors determined the finding screened as Green because the finding did not increase the likelihood of an external or internal flood. The finding was related to the cross-cutting area of Human Performance. This finding was associated with the cross-cutting aspect of Resources (H.2.(c)) because the barrier impairment procedure was not adequate because it did not ensure safety margins were

maintained by providing instructions to periodically verify that the compensatory measures were still available. Enforcement: Title

10 CFR Part 50, Appendix B, Criterion V, required, in part, that activities affecting quality be prescribed by documented procedures of a type appropriate to the circumstances. Contrary to the above, Bw

AP 1110-3 was not adequate because

it did not ensure that the sump flooding alarms remained operational while the flood barrier covers are removed. Once identified, the licensee entered the finding into their

IR 766773, "PBI Compensatory Actions Changed, Not Identified by Shift." Because the finding was of very low safety significance, and has been entered into the licensee's

CAP , this violation was treated as an

NCV consistent with Section

VI.A. 1 of the

NRC Enforcement Policy. Corrective actions included repairing the sump alarms and planned revision to the

PBI procedure. (

NCV 05000456/2008003-02; 05000457/2008003-02) 1R07 Annual Heat Sink Performance (71111.07) .1 Heat Sink Performance Annual Review a. Inspection Scope The inspectors reviewed the licensee's cleaning and eddy current (ET) testing of the Unit 2 component cooling heat exchanger to verify that potential deficiencies did not

Enclosure mask the licensee's ability to detect degraded performance, to identify any common cause issues that had the potential to increase risk, and to ensure that the licensee was adequately addressing problems that could result in initiating events that would cause an increase in risk. The inspectors reviewed the licensee's observations as compared against acceptance criteria, the correlation of scheduled testing and the frequency of testing, and the impact of instrument inaccuracies on test results. Inspectors also verified that test acceptance criteria considered differences between test conditions, design conditions, and testing conditions. The inspectors also reviewed the licensee's calculation to justify continued operability of the heat exchanger with the additional tubes plugged as a result of these activities. Documents reviewed were listed in the Attachment. This inspection constituted one sample of the annual requirement as defined in

IP 71111.07-05. b. Findings No findings of significance were identified. 1R08 In-service Inspection (

ISI) Activities (71111.08) For Unit 2, from April 28, 2008, through May 6, 2008, the inspectors conducted a review of the implementation of the licensee's ISI Program for monitoring degradation of the

reactor coolant system (RCS), steam generator (SG) tubes, emergency feedwater systems, risk significant piping and components and containment systems. The inspections described in Sections 1R08.1, 1R08.2, R08.3, 1R08.4 and 1R08.5 below counted as one inspection sample as defined by

IP 71111.08-05. .1 Piping Systems

ISI a. Inspection Scope The inspectors observed the following nondestructive examinations (NDE) required by the American Society of Mechanical Engineers (ASME) Code, Section

XI , to evaluate compliance with the

ASME Code,Section XI and Section V requirements and if any indications and defects were detected, to determine if these were dispositioned in

accordance with the

ASME Code or an

NRC approved alternative requirement. * ultrasonic examination (UT) of reactor vessel inlet nozzle-to-safe end weld (2RV-01-024) at the 113 degrees azimuth; *

UT of ultrasonic examination upper shell weld (2

RV -01-004) and lower shell weld (2RV-02-001); and *

UT of safety injection system piping welds (1-

SI -01-03 and

2SI -30-15). The inspectors reviewed a record of the following

NDE required by the

XI to evaluate compliance with the

XI and Section V requirements and if any indications and defects were detected, to determine if these were dispositioned in accordance with the

ASME Code or an

NRC approved alternative requirement.

Enclosure * Magnetic particle examination of

SG feedwater nozzle weld (2

SG-03-SGN-02). The licensee did not identify surface or volumetric examinations completed during the previous outage with relevant/recordable conditions/indications accepted for continued

service. Therefore, no

NRC [[review was completed for this inspection attribute. The inspectors observed fabrication of the following pressure boundary welds (overlay repairs) completed for pressure boundary risk significant systems during the current Unit 2 refueling outage. The inspectors also reviewed weld related documents to determine if the licensee applied the preservice]]

NDE and acceptance criteria required by

the construction Code, and an

NRC approved Relief Request 12R-48. Additionally, the inspectors reviewed the welding procedure specification and supporting weld procedure qualification records to determine if the weld procedures were qualified in accordance with the requirements of the

IX * weld overlay repair of the pressurizer safety "A," nozzle-to-safe end weld (2

PZR Upper Head Penetration Inspection Activities a. Inspection Scope For the Unit 2 vessel head, no examination was required pursuant to]]

NRC Order

EA-03-009 and the licensee did not complete one during the current

refueling outage. Therefore, no

NRC review was completed for this

IP attribute. b. Findings No findings of significance were identified. .3 Boric Acid Corrosion Control a. Inspection Scope The inspectors observed licensee boric acid corrosion control visual examinations for portions of the reactor coolant and/or emergency core cooling systems (ECCS) within

containment to determine if these visual examinations emphasized locations where boric acid leaks can cause degradation of safety significant components. The inspectors reviewed the following licensee evaluations of RCS components with boric acid deposits to determine if degraded components were documented in the corrective action system. The inspectors also evaluated corrective actions for any

degraded

RCS components to determine if they met the licensee's boric acid program procedures and the

ASME Code, Section XI:

Enclosure * reactor coolant pump 2B No. 1 seal flow element; * reactor coolant loop 2A pump suction leg isolation valve; and * 2B

RCS loop drain isolation valve. The inspectors reviewed the following corrective actions related to evidence of boric acid leakage to determine if the corrective actions completed were consistent with the requirements of the

ASME Code Section

XI and 10

CFR Part 50, Appendix B, Criterion

XVI. *

IR 566386, boric acid leak

2RH 01

CA -16 bolted connection; *

IR 566370, boric acid leak 2

RH 01CB-16 flanged connection; and *

IR 543851, boric acid leak 2

CV 04AA inlet flange. b. Findings No findings of significance were identified. .4

SG Tube Inspection Activities a. Inspection Scope The

NRC inspectors observed acquisition of

ET data, interviewed

ET data analysts, and reviewed documentation related to the

SG [[]]

ISI program to determine if: * in-situ

SG tube pressure testing screening criteria used were consistent with those identified in the Electric Power Research Institute (

EPRI) TR 1014983, "Steam Generator In-Situ Pressure Test Guidelines," and that these criteria were

properly applied to screen degraded

SG tubes for in-situ pressure testing; * the numbers and sizes of

SG tube flaws/degradation identified was bound by the licensee's previous outage Operational Assessment predictions; * the

SG tube

ET examination scope and expansion criteria were sufficient to meet the

TS s, and the

EPRI 1003138, "Pressurized Water Reactor Steam Generator Examination Guidelines," Revision 6; * the

SG tube

ET examination scope included potential areas of tube degradation identified in prior outage

SG tube inspections and/or as identified in

NRC generic industry operating experience applicable to these

SG [[tubes; * the licensee identified new tube degradation mechanisms and implemented adequate extent of condition inspection scope and repairs for the new tube degradation mechanism; * the licensee implemented repair methods which were consistent with the repair processes allowed in the plant]]

TS requirements and to determine if qualified depth sizing methods were applied to degraded tubes accepted for continued

service; * the licensee implemented an inappropriate "plug on detection" tube repair threshold (e.g., no attempt at sizing of flaws to confirm tube integrity); * the licensee primary-to-secondary leakage (e.g.,

SG tube leakage) was below 3 gallons-per-day or the detection threshold during the previous operating cycle; * the

ET probes and equipment configurations used to acquire data from the

SG tubes were qualified to detect the known/expected types of

SG tube degradation in accordance with Appendix H, "Performance Demonstration for Eddy Current

Enclosure Examination," of

EPRI 1003138, "Pressurized Water Reactor Steam Generator Examination Guidelines," Revision 6; * the licensee performed secondary side

SG inspections for location and removal of foreign materials; and * the licensee implemented repairs for

SG tubes damaged by foreign material. The licensee did not perform in-situ pressure testing of

SG tubes. Therefore, no

NRC review was completed for this inspection attribute. b. Findings No findings of significance were identified. .5 Identification and Resolution of Problems a. Inspection Scope The inspectors performed a review of

CAP and conducted interviews with licensee staff to determine if: * the licensee had established an appropriate threshold for identifying

ISI and pressure boundary integrity. The inspectors performed these reviews to evaluate compliance with 10

CFR 50, Appendix B, Criterion XVI, "Corrective Action," requirements. The corrective action documents reviewed by the inspectors were listed in the Attachment to this report. b. Findings No findings of significance were identified. 1R11 Licensed Operator Requalification Program (71111.11) .1 Resident Inspector Quarterly Review (71111.11Q) a. Inspection Scope On May 27, 2008, the inspectors observed a crew of licensed operators in the plant's 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; * crew's clarity and formality of communications; * ability to take timely actions in the conservative direction; * prioritization, interpretation, and verification of annunciator alarms;

Enclosure * 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 crew's performance in these areas was compared to pre-established operator action expectations and successful critical task completion requirements. This inspection constituted one quarterly licensed operator requalification program sample as defined in]]

IP [[71111.11. b. Findings No findings of significance were identified. 1R12 Maintenance Effectiveness (71111.12) .1 Routine Quarterly Evaluations a. Inspection Scope The inspectors evaluated degraded performance issues involving the following risk significant system: * service air. The inspectors reviewed events such as where ineffective equipment maintenance had resulted in valid or invalid automatic actuations of engineered safeguards systems and independently verified the licensee's actions to address system performance or condition problems in terms of the following: * implementing appropriate work practices; * identifying and addressing common cause failures; * scoping of systems in accordance with]]

10 CFR 50.65(b) of the maintenance rule; * characterizing system reliability issues for performance; * charging unavailability for performance; * trending key parameters for condition monitoring; * ensuring 10

CFR [[50.65(a)(1) or (a)(2) classification or re-classification; and * verifying appropriate performance criteria for structures, systems, and components/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 were listed in the Attachment. This inspection constituted one quarterly maintenance effectiveness samples as defined in

IP 71111.12-05.

Enclosure b. Findings No findings of significance were identified. 1R13 Maintenance Risk Assessments and Emergent Work Control (71111.13) .1 Maintenance Risk Assessments and Emergent Work Control a. Inspection Scope The inspectors reviewed the licensee's evaluation and management of plant risk for the maintenance and emergent work activities affecting risk-significant and safety-related equipment listed below to verify that the appropriate risk assessments were performed prior to removing equipment for work: * planned work on the Unit 2 component cooling heat exchanger with emergent work on the 1A containment spray train; * change from Mode 4 to Mode 3 with the 2B

AFW pump unavailable; * emergent troubleshooting on the 2E main power transformer cooling fan power transfer circuit; * emergent work on 2A emergency

DG; and * Bus 242 outage during refueling outage. These activities were selected based on their potential risk significance relative to the reactor safety cornerstones. As applicable for each activity, the inspectors verified that risk assessments were performed as required by 10 CFR 50.65(a)(4) and were accurate and complete. When emergent work was performed, the inspectors verified that the plant risk was promptly reassessed and managed. The inspectors reviewed the scope

of maintenance work, discussed the results of the assessment with the licensee's probabilistic risk analyst or shift technical advisor, and verified plant conditions were consistent with the risk assessment. The inspectors also reviewed TS requirements and walked down portions of redundant safety systems, when applicable, to verify risk analysis assumptions were valid and applicable requirements were met. Documents

reviewed were listed in the Attachment. These activities constituted five samples as defined by IP 71111.13-05. b. Findings No findings of significance were identified. 1R15 Operability Evaluations (71111.15) .1 Operability Evaluations a. Inspection Scope The inspectors reviewed the following issues: * control room heating ventilation and air conditioning issues;

Enclosure * Unit 2 containment integrity with equipment hatch removed during fuel movements; * 1A

DG after failure of 1

SX169A to automatically open as expected during a monthly surveillance test; * revision due to extended corrective action dates for AFW tunnel cover modifications; and * 1A containment spray motor oil leak. 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

UFS [[]]

AR to the licensee's evaluations, to determine whether the components or systems were operable. Where compensatory measures

were required to maintain operability, the inspectors determined whether the measures in place would function as intended and were properly controlled. The inspectors determined, where appropriate, compliance with bounding limitations associated with the evaluations. Additionally, the inspectors also reviewed a sampling of corrective action documents to verify that the licensee was identifying and correcting any deficiencies

associated with operability evaluations. Documents reviewed were listed in the Attachment. This inspection constituted five samples as defined in

IP 71111.15-05 b. Findings (Open) Unresolved Item (

URI ) 05000456/2008003-03; 05000457/2008003-03:

AFW Tunnel Hatch Margin to Safety The inspectors reviewed Operability Evaluation 07-007, Revision 2. This operability evaluation was performed because the licensee identified that the design analysis for evaluation of the

AFW tunnel flood seal covers did not include the effects of a high energy line break in the main steam isolation valve tunnels. Following this review, the inspectors questioned why a dynamic load factor as a result of the impulse pressure following a high energy line break had not been considered in an analytic calculation

perform to support the operability evaluation. The licensee documented the inspectors concerns in

IR 783849. Additionally, following a review of a subsequent revision of this operability evaluation, the inspectors questioned the licensee's conclusion that the operability of the

AFW hatches continued to be supported despite analytical results showing a factor of safety for the

concrete expansion anchors supporting the hatches of less than 2.0, which is contrary to the guidance provided in

NRC Bulletin 79-02, "Pipe Support Base Plate Designs Using Concrete Expansion Anchors." Additionally, the inspectors noted that the operability evaluation did not address Section C.13 of

NRC Technical Guidance 9900, "Operability Determinations & Functionality Assessment for Resolution of Degraded or

Nonconforming Conditions Adverse to Quality or Safety." Specifically, Section C.13 stated that if a structure was degraded, the licensee should assess the structure's capability of performing its specified function. As long as the identified degradation did not result in exceeding acceptance limits specified in applicable design codes and

Enclosure standards referenced in the design basis documents, the affected structure was either operable or functional. At the close of the inspection period temporary modifications had been

implemented at both units that restored the margin of safety to greater than 2.0. Pending additional follow-up by the inspectors for the timeliness of corrective actions, extent of condition, corrective actions and past operability, this item will remain open. (URI 005000456/2008003-03;05000457/2008003-03) Included in the

NRC [[review will be the licensees' evaluations of structural degradations to determine their technical adequacy and conformance to licensing and regulatory requirements. 1R18 Plant Modifications (71111.18) .1 Temporary Plant Modifications a. Inspection Scope The inspectors reviewed the following temporary modification: * temporary modification on 1B]]

AFW [[pump (substitution of automatic over speed trip function with manual operator actions to trip diesel on over speed); and * main steam isolation valve tunnel blowout panel/AFW hatch temporary modification. The inspectors compared the temporary configuration change 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, as applicable, performed field verifications to ensure that the modification was installed as directed; the

modification operated as expected; modification testing adequately demonstrated continued system operability, availability, and reliability; and that operation of the modification 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. This inspection constituted two samples as defined in IP71111.18-05. b. Findings No findings of significance were identified. 1R19 Post Maintenance Testing (71111.19) .1 Post Maintenance Testing a. Inspection Scope The inspectors reviewed the following post-maintenance activities to verify that procedures and test activities were adequate to ensure system operability and functional capability:

Enclosure * 2B

DG following repairs to governor and lube oil pump; * 2B

SX pump following motor replacement; * 2C heater drain pump after replacement and rework on shaft packing; * 2B feedwater pump after work on the stop valve; and * 1B

AFW [[pump following troubleshooting of failure of the over speed trip. These activities were selected based upon the structure, system, or component's ability to impact risk. The inspectors evaluated these activities for the following (as applicable): * the effect of testing on the plant had been adequately addressed; * testing was adequate for the maintenance performed; * acceptance criteria were clear and demonstrated operational readiness; * test instrumentation was appropriate; * tests were performed as written in accordance with properly reviewed and approved procedures; * equipment was returned to its operational status following testing (temporary modifications or jumpers required for test performance were properly removed after test completion), and test documentation was properly evaluated. The inspectors evaluated the activities against]]

TS , the

UFSAR , 10

CFR Part 50 requirements, licensee procedures, and various

NRC [[generic communications to ensure that the test results adequately ensured that the equipment met the licensing basis and design requirements. In addition, the inspectors reviewed 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 were listed in the Attachment to this report. This inspection constituted five samples as defined in IP 71111.19-05. b. Findings No findings of significance were identified. 1R20 Outage Activities (71111.20) .1 Refueling Outage Activities a. Inspection Scope The inspectors reviewed the Shutdown Safety Management Plan for the Unit 2 refueling outage, conducted April 20, 2008, to May 17, 2008, to confirm that the licensee had

appropriately considered risk, industry experience, and previous site-specific problems in developing and implementing a plan that assured maintenance of defense-in-depth. During the refueling outage, the inspectors observed portions of the shutdown and cooldown processes and monitored licensee controls over the outage activities listed below. Documents reviewed during the inspection were listed in the Attachment to this

report.

Enclosure * Licensee configuration management, including maintenance of defense-in-depth commensurate with the safety plan for key safety functions and compliance with the applicable

TS [[when taking equipment out of service. * Implementation of clearance activities and confirmation that tags were properly hung and equipment appropriately configured to safely support the work or testing. * Installation and configuration of reactor coolant pressure, level, and temperature instruments to provide accurate indication, accounting for instrument error. * Controls over the status and configuration of electrical systems to ensure that]]

TS [[and safety plan requirements were met, and controls over switchyard activities. * Monitoring of decay heat removal processes, systems, and components. * Controls to ensure that outage work was not impacting the ability of the operators to operate the spent fuel pool cooling system. * Reactor water inventory controls including flow paths, configurations, and alternative means for inventory addition, and controls to prevent inventory loss. * Controls over activities that could affect reactivity. * Maintenance of containment integrity as required by]]

TS. [[* Refueling activities, including fuel handling and sipping to detect fuel assembly leakage. * Startup and ascension to full power operation, tracking of startup prerequisites, walkdown primary containment to verify that debris had not been left which could block]]

ECCS suction strainers, and reactor physics testing. * Licensee identification and resolution of problems related to refueling outage activities. This inspection constituted one refueling outage sample as defined in

IP 71111.20-05. b. Findings No findings of significance were identified. .2 Review of Operating Experience Smart Sample Fiscal Year 2007-03, Revision 1, Crane and Heavy Lift Inspection, Supplemental Guidance for

IP71111.20 a. Inspection Scope The inspectors used the above referenced smart sample to review the reactor head lift procedures and load drop analysis to confirm that the procedures contained limitations which bounded the assumptions and conclusions of the load drop analysis. The inspectors also witnessed the actual head lift during the Unit 2 outage, using remote live video, to confirm that the procedures were followed correctly. These observations

included pre-job briefs and relaying of instructions from the supervisor and crane signalman to the crane operator. This inspection was part of the outage activities sample discussed in Section 1R20.1 above and did not constitute a separate sample. b. Findings No findings of significance were identified.

Enclosure 1R22 Surveillance Testing (71111.22) .1 Routine 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: * 1A monthly

DG surveillance; * 1B

DG bypass of automatic trips; and * 2B Residual Heat Removal (

RHR )

ASME [[surveillance. The inspectors observed in-plant activities and reviewed procedures and associated records to determine whether: * any preconditioning occurred; * effects of the testing were adequately addressed by control room personnel or engineers prior to the commencement of the testing; * acceptance criteria were clearly stated, demonstrated operational readiness, and were consistent with the system design basis; * plant equipment calibration was correct, accurate, and properly documented; * as left setpoints were within required ranges; * the calibration frequency was in accordance with]]

TS , 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, 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 the safety functions; and * all problems identified during the testing were appropriately documented and dispositioned in the

CAP. Enclosure Documents reviewed were listed in the Attachment. This inspection constituted three routine surveillance testing sample as defined in

IP [[71111.22, Sections -02 and -05. b. Findings No findings of significance were identified. .2 Inservice Testing Surveillance 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: * main steam safety valves operability test; and * low flow feedwater isolation valve stroke test. The inspectors observed activities and reviewed procedures and associated records to determine whether: * any preconditioning occurred; * effects of the testing were adequately addressed by control room personnel or engineers prior to the commencement of the testing; * acceptance criteria were clearly stated, demonstrated operational readiness, and were consistent with the system design basis; * plant equipment calibration was correct, accurate, and properly documented; as left setpoints were within required ranges; * and the calibration frequency were in accordance with]]

TS s, 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]]

ASME Code,Section XI, 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;

Enclosure * 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 were listed in the Attachment. This inspection constituted two inservice testing samples as defined in

IP [[71111.22-05. b. Findings No findings of significance were identified. .3 Containment Isolation Valve Testing The inspectors reviewed the test results for the following activity to determine whether the risk-significant system 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 containment emergency air lock hatch gasket interspaces. The inspectors observed in-plant activities and reviewed procedures and associated records to determine whether: any preconditioning occurred; effects of the testing were

adequately addressed by control room personnel or engineers prior to the commencement of the testing; acceptance criteria were clearly stated, demonstrated operational readiness, and were consistent with the system design basis; plant equipment calibration was correct, accurate, and properly documented; as left setpoints were within required ranges; and the calibration frequency 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, test results not meeting acceptance criteria were addressed with an adequate operability evaluation or the system or component was declared inoperable; 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 were listed in the Attachment.

Enclosure This inspection constituted one containment isolation valve inspection sample as defined in

IP 71111.22-05. b. Findings No findings of significance were identified. 2.

RADIAT ION

SAFETY Cornerstone: Occupational Radiation Safety 2

OS [[1 Access Control to Radiologically Significant Areas (71121.01) .1 Review of Licensee Performance Indicators (PIs) for the Occupational Exposure Cornerstone a. Inspection Scope The inspectors reviewed the licensee's occupational exposure control cornerstone]]

PI s to determine whether the conditions resulting in any

PI occurrences had been evaluated and whether identified problems had been entered into the

CAP for resolution. Documents reviewed were listed in the Attachment. This inspection constituted one sample as defined in

IP project; *]]

SG [[]]

ET testing and all tube repairs; * reactor head component disassembly and reassembly; and * split pin modifications. The inspectors reviewed the RWPs and work packages used to access these areas and other high radiation work areas to identify the work control instructions and control barriers that had been specified. Electronic dosimeter alarm set points for both integrated dose and dose rate were evaluated for conformity with survey indications and

plant policy. Workers were interviewed to verify that they were aware of the actions required when their electronic dosimeters noticeably malfunctioned or alarmed.

Enclosure In addition, the inspectors walked down and surveyed (using an

NRC survey meter) these areas to verify that: * prescribed

RWP, procedure, and engineering controls were in place; * licensee surveys, and postings were complete and accurate; and * air samplers were properly located. The inspectors reviewed RWPs for airborne radioactivity areas to verify barrier integrity

and engineering controls performance (e.g., high-efficiency particulate air ventilation system operation) and to determine if there was a potential for individual worker internal exposures of greater than 50 millirem committed effective dose equivalent. Work areas having a history of, or the potential for, airborne transuranics were evaluated to verify that the licensee had considered the potential for transuranic isotopes and

provided appropriate worker protection. The adequacy of the licensee's internal dose assessment process for internal exposures greater than 50 millirem committed effective dose equivalent was assessed. There were no internal exposures greater than 50 millirem committed effective dose equivalent. Documents reviewed were listed in the Attachment. This inspection constituted five samples as defined in

IP 71121.01-5. b. Findings No findings of significance were identified. .3 Problem Identification and Resolution a. Inspection Scope The inspectors reviewed a sample of the licensee's self-assessments, audits, Licensee Event Reports (

LERs), and Special Reports related to the access control program to verify that identified problems were entered into the CAP for resolution. The inspectors reviewed corrective action reports related to access controls and high radiation area radiological incidents (issues that did not count as performance indicator occurrences identified by the licensee in high radiation areas less than 1R/hr). Staff

members were interviewed and corrective action documents were reviewed to verify follow-up activities were being conducted in an effective and timely manner commensurate with their importance to safety and risk based on the following: * initial problem identification, characterization, and tracking; * disposition of operability/reportability issues; * evaluation of safety significance/risk and priority for resolution; * identification of repetitive problems; * identification of contributing causes; * identification and implementation of effective corrective actions;

Enclosure * resolution of

NCV s tracked in the corrective action system; and * implementation/consideration of risk significant operational experience feedback. Documents reviewed were listed in the Attachment. This inspection constituted two samples as defined in

IP [[71121.01-5. b. Findings No findings of significance were identified. .4 Job-In-Progress Reviews a. Inspection Scope The inspectors observed the following three jobs that were being performed in radiation areas, airborne radioactivity areas, or high radiation areas for observation of work activities that presented the greatest radiological risk to workers: * pressurizer weld overlay project; *]]

SG [[]]

ET testing and all tube repairs; and * reactor head component disassembly and reassembly. The inspectors reviewed radiological job requirements for these activities, including

RWP requirements and work procedure requirements, and attended as-low-as-is-reasonably-achievable (

ALARA) job briefings. Job performance was observed with respect to these requirements to assess whether radiological conditions in the work area were adequately communicated to workers through pre-job briefings and postings. The inspectors also evaluated the adequacy of

radiological controls including required radiation, contamination, and airborne surveys for system breaches; radiation protection job coverage, including any applicable audio and visual surveillance for remote job coverage; and contamination controls. Radiological work in high radiation work areas having significant dose rate gradients was reviewed to evaluate the application of dosimetry to effectively monitor exposure to

personnel and to assess the adequacy of licensee controls. These work areas involved areas where the dose rate gradients were severe thereby increasing the necessity of providing multiple dosimeters or enhanced job controls. Documents reviewed were listed in the Attachment. This inspection constituted three samples as defined in IP 71121.015. b. Findings No findings of significance were identified.

Enclosure .5 High Risk Significant, High Dose Rate, High Radiation Area and Very High Radiation Area Controls a. Inspection Scope The inspectors conducted plant walkdowns to assess the posting and locking of entrances to high dose rate, high radiation area and very high radiation area. Specifically, the inspectors reviewed the transient locked high radiation area and

potentially very high radiation area controls during the core barrel lift. Documents reviewed were listed in the Attachment. This inspection constituted one sample as defined in

IP [[71121.01-5. b. Findings No findings of significance were identified. .6 Radiation Worker Performance a. Inspection Scope During job performance observations, the inspectors evaluated radiation worker performance with respect to stated radiation protection work requirements and evaluated whether workers were aware of the significant radiological conditions in their workplace, of the]]

RWP controls and limits in place, and of the level of radiological hazards present. The inspectors also evaluated if worker performance accounted for these radiological

hazards. Documents reviewed were listed in the Attachment. This inspection constituted one sample as defined in

IP [[71121.01-5. b. Findings No findings of significance were identified. .7 Radiation Protection Technician Proficiency a. Inspection Scope During job performance observations, the inspectors evaluated radiation protection technician performance with respect to radiation protection work requirements and evaluated whether they were aware of the radiological conditions in their workplace, the]]

RWP [[controls, and limits in place, and if their performance was consistent with their training and qualifications with respect to the radiological hazards and work activities. Documents reviewed were listed in the Attachment. This inspection constituted one sample as defined in]]

IP71121.01-5.

Enclosure b. Findings No findings of significance were identified.

2OS 2

ALARA [[Planning And Controls (71121.02) .1 Inspection Planning a. Inspection Scope The inspectors reviewed plant collective exposure history, current exposure trends, ongoing and planned activities in order to assess current performance and exposure challenges. This included determining the plant's current three-year rolling average for collective exposure in order to help establish resource allocations and to provide a perspective of significance for any resulting inspection finding assessment. The inspectors reviewed the outage work scheduled during the inspection period and associated work activity exposure estimates for the following five work activities, which were likely to result in the highest personnel collective exposures: * pressurizer weld overlay insulation shielding and support activities; * pressurizer weld overlay project; *]]

SG [[]]

ET testing and all tube repairs; * reactor head component disassembly and reassembly; and * split pin modifications. The inspectors reviewed documents to determine if there were site-specific trends in collective exposures and source-term measurements.

The inspectors reviewed procedures associated with maintaining occupational exposures

ALA [[]]

RA and processes used to estimate and track work activity specific exposures. Documents reviewed were listed in the Attachment.

This inspection constituted four required samples as defined in IP 71121.02-5. b. Findings No findings of significance were identified. .2 Radiological Work Planning. a. Inspection Scope The inspectors evaluated the licensee's list of work activities ranked by estimated exposure that were in progress and reviewed the following five work activities of highest exposure significance: * pressurizer weld overlay insulation shielding and support activities; * pressurizer weld overlay project;

Enclosure *

SG [[]]

ET testing and all tube repairs; * reactor head component disassembly and reassembly; and * split pin modifications. For these five activities, the inspectors reviewed the

ALA [[]]

RA work activity evaluations, exposure estimates, and exposure mitigation requirements in order to verify that the licensee had established procedures and engineering and work controls that were based on sound radiation protection principles in order to achieve occupational exposures that

were

ALARA. [[This also involved determining if the licensee had reasonably grouped the radiological work into work activities, based on historical precedence, industry norms, and/or special circumstances. The inspectors compared the results achieved including dose rate reductions and person-rem used with the intended dose established in the licensee's]]

ALARA planning

for these five work activities. Reasons for inconsistencies between intended and actual work activity doses were reviewed. Documents reviewed were listed in the Attachment. This inspection constituted three required samples as defined in IP 71121.025. b. Findings No findings of significance were identified. .3 Verification of Dose Estimates and Exposure Tracking Systems a. Inspection Scope The inspectors reviewed the assumptions and bases for the current annual collective exposure estimate including procedures, in order to evaluate the licensee's methodology

for estimating work activity-specific exposures and the intended dose outcome. Dose rate and man-hour estimates were evaluated for reasonable accuracy. The licensee's process for adjusting exposure estimates or re-planning work, when unexpected changes in scope, emergent work or higher than anticipated radiation levels were encountered, was evaluated. This included determining that adjustments to estimated exposure (intended dose) were based on sound radiation protection and

ALA [[]]

RA principles and not adjusted to account for failures to control the work. The

frequency of these adjustments was reviewed to evaluate the adequacy of the original

ALARA planning process. Documents reviewed were listed in the Attachment. This inspection constituted two required samples as defined in

IP 71121.02-5. a. Findings No findings of significance were identified.

Enclosure .4 Job Site Inspections and

ALARA [[Control Inspection Scope The inspectors observed the following five jobs that were being performed in radiation areas, airborne radioactivity areas, or high radiation areas for observation of work activities that presented the greatest radiological risk to workers: * pressurizer weld overlay insulation shielding and support activities; * pressurizer weld overlay project; *]]

SG [[]]

ET testing and all tube repairs; * reactor head component disassembly and reassembly; and * split pin modifications. The licensee's use of

ALARA controls for these work activities was evaluated using the following: The licensee's use of engineering controls to achieve dose reductions was evaluated to verify that procedures and controls were consistent with the licensee's

ALARA [[reviews, that sufficient shielding of radiation sources was provided for and that the dose expended to install/remove the shielding did not exceed the dose reduction benefits afforded by the shielding. Documents reviewed were listed in the Attachment. This inspection constituted one required sample as defined in]]

IP [[71121.02-5. b. Findings No findings of significance were identified. .5 Radiation Worker Performance a. Inspection Scope Radiation worker and radiation protection technician performance was observed during work activities being performed in radiation areas, airborne radioactivity areas, and high radiation areas that presented the greatest radiological risk to workers. The inspectors evaluated whether workers demonstrated the]]

ALA [[]]

RA philosophy in practice by being

familiar with the work activity scope and tools to be used, by utilizing

ALARA [[low dose waiting areas and by complying with work activity controls. Also, radiation worker training and skill levels were reviewed to determine if they were sufficient relative to the radiological hazards and the work involved. Documents reviewed were listed in the Attachment. This inspection constituted one required sample as defined in]]

IP 71121.02-5. b. Findings No findings of significance were identified.

Enclosure Cornerstone: Public Radiation Safety 2PS1 Radioactive Gaseous and Liquid Effluent Treatment and Monitoring Systems (71122.01) .1 Review of Blowdown Line Operations and Tritium Remediation Efforts a. Inspection Scope The inspectors continued to monitor the licensee's activities resulting from historical inadvertent leaks of tritiated liquid from the blowdown line. The inspectors continued to

accompany licensee employees and contractors during their collection of water samples at 23 monitoring locations of interest. The inspectors verified by direct observation that the water samples were being taken from the locations specified, that proper sampling protocols were followed, and that split samples were properly obtained and labeled. The inspectors took direct custody of the split samples and maintained a chain of custody as

the samples were sent to the

NRC 's contract laboratory. The inspectors also reviewed the results of December 12, 2007, split samples to ensure that the results from the licensee's and

NRC 's contract laboratories matched within normal statistical variance. Documents reviewed were listed in the Attachment. This inspection does not constitute a sample as defined in

IP 71122.02-5. b. Findings No findings of significance were identified. 2

PS2 Radioactive Material Processing and Transportation (71122.02) .1 Radioactive Waste System Walkdowns a. Inspection Scope The inspectors reviewed changes to the waste processing system to verify the changes were reviewed and documented in accordance with 10 CFR 50.59 and to assess the

impact of the changes on radiation dose to members of the public. Documents reviewed were listed in the Attachment. This inspection does not constitute a sample as defined in IP 71122.02-5. b. Findings One finding of very low safety significance was identified.

Failure to Sample a Temporary Tank at the Required Periodicity Introduction: The inspectors identified a finding of very low safety significance (Green) and an

NCV of

TS 5.4, and Technical Requirements Manual (TRM), Appendix L, for failure to sample temporary waste water tanks at the Unit 2 Containment Access facility.

Enclosure Description: On May 1, 2008, the inspectors identified that the licensee had failed to sample the temporary wastewater storage tanks that were installed for the Unit 2 refueling outage to hold shower and wash water from the Unit 2 Containment Access Facility at the required frequency of seven days. This failure resulted in two missed samples of the Unit 2 Containment Access Facility shower tanks. The licensee's corrective measures consisted of immediately collecting and monitoring the required

sample. The results of this sample indicated that the quantity of radioactive material was well below the limits provided in the

TRM. Additionally, the licensee started the process to review and revise Procedure

RP-BR-654, Revision 0. This revision was necessary to reflect the temporary tank sampling requirement of TRM, Appendix L, implemented to limit the quantity of radioactive material contained in outside temporary tanks and verify

the compliance with the limits by sampling the contents at least once per seven days when in use. The inspectors observed that Procedure

BR -654, as written, did not direct the required sampling frequency as outlined in

TRM , Appendix L. After identification by the inspectors, the licensee documented the issue in

IR 770446, conducted the required sampling, revised the scheduling tool to ensure the tank is sampled at least every seven days, and planned to revise Procedure

BR-654. Analysis: The inspectors determined that the failure to sample the contents in the outdoor liquid radwaste storage tanks did not meet the requirements of TRM, Appendix L and was a performance deficiency that warranted a significance evaluation. The finding involves an occurrence in the licensee's radioactive material control program that is contrary to the licensee's procedures. The finding was more than minor because it impacted the program and process attribute of the Public Radiation Safety Cornerstone and affected the cornerstone objective to ensure adequate protection of

public health and safety from exposure to radioactive material released into the public domain, in that the failure to measure the levels of radioactivity in the temporary storage tanks had the potential to impact the licensee's effluent program. The inspectors applied the IMC 0609, Appendix D, to this finding. The finding is in the licensee's radiological effluent monitoring program. The finding did not involve a failure

to implement the effluent release program nor did public dose exceed Appendix I, Criterion, or

10 CFR [[20.1302(e) and the finding was determined to be of very low safety significance (Green). This conclusion was based on no tank contents being released or discharged without sampling, and the total content limits were not exceeded. The primary cause of this sampling failure was related to the cross-cutting component of Human Performance, Work Practices (Item H.4.C of]]

IMC 0305) because the licensee did not ensure that supervisory and management oversight of procedure development was adequate to assure nuclear safety, specifically, procedures that are complete, accurate. Enforcement: Technical Specification 5.4.1(a) requires written procedures be established, implemented and maintained covering the applicable procedures

TRM [[, Appendix L, required the quantity of radioactive material contained in any outside temporary tank be determined to be within the acceptance criteria by analyzing a representative sample of the tank's contents at least once per seven days when radioactive materials are being added to the tank. Procedure]]

TRM. Enclosure Contrary to the above, as of May 1, 2008, the licensee's Procedure

BR-654 was written to implement the requirements of the

VI.A. 1 of the Enforcement Policy (

BR [[-654 did not include the requirement for sampling at least once per seven days. Consequently, the licensee failed to sample decontamination drain waste tanks, temporary tanks, adjacent to the Unit 2 Containment Access Facility at least once per seven days. Because of the very low safety significance of this finding and because the issue was entered into the licensee's]]

CAP (

IR 770446), it was treated as an NCV, consistent with

Section

NCV 05000456/2008003-04; 05000457/2008003-04). 4.

OTHER [[]]

ACTIVITIES Cornerstones: Initiating Events, Mitigating Systems, Barrier Integrity, Emergency Preparedness, Public Radiation Safety, Occupational Radiation Safety, and

Physical Protection

4OA 1 Performance Indicator Verification (71151) .1

RCS Specific Activity a. Inspection Scope The inspectors sampled licensee submittals for the

RCS Specific Activity

PI for Braidwood, Units 1 and 2. To determine the accuracy of the

PI data reported during those periods, the

PI definition and guidance contained in the Nuclear Energy Institute

(NEI) Document 99-02, "Regulatory Assessment Performance Indicator Guideline," Revision 5, was used. The inspectors reviewed the licensee's

RCS chemistry samples,

TS requirements,

IR s,

LERs, and NRC Integrated Inspection reports for the period of April 1, 2007, to March 31, 2008 to validate the accuracy of the submittals. The inspectors also reviewed the licensee's 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. In addition to record reviews, the inspectors observed a chemistry technician obtain and analyze a

RCS sample. Specific documents reviewed were described in the Attachment. This inspection constituted two

RCS specific activity samples as defined by

IP 71151-05. b. Findings No findings of significance were identified. .2

RCS Leakage a. Inspection Scope The inspectors sampled licensee submittals for the

RCS Leakage

PI for Braidwood, Units 1 and 2. To determine the accuracy of the

PI data reported during those periods, the

PI definition and guidance contained in the

NEI Document 99-02, Revision 5, was used. The inspectors reviewed the licensee's operator logs,

RCS leakage tracking data,

IR s,

LER s, and

NRC Integrated Inspection Reports for the period of April 1, 2007, to March 31, 2008, to validate the accuracy of the submittals. The inspectors also

reviewed the licensee's issue report database to determine if any problems had been

Enclosure identified with the

PI data collected or transmitted for this indicator and none were identified. Specific documents reviewed were described in the Attachment. This inspection constituted two

RCS leakage samples as defined by

IP 71151-05. b. Findings No findings of significance were identified. 4

OA 2 Identification and Resolution of Problems (71152) .1 Routine Review of items Entered Into the

CAP [[a. Scope As part of the various baseline inspection procedures discussed in previous sections of this report, the inspectors routinely reviewed issues during baseline inspection activities and plant status reviews to verify that they were being entered into the licensee's]]

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 licensee's

CAP [[as a result of the inspectors' observations are included in the attached list of documents reviewed. These routine reviews for the identification and resolution of problems did not constitute any additional inspection samples. Instead, by procedure they were considered an integral part of the inspections performed during the quarter and documented in the Attachment. b. Findings No findings of significance were identified. .2 Daily]]

CAP Reviews a. Scope In order to assist with the identification of repetitive equipment failures and specific human performance issues for follow-up, the inspectors performed a daily screening of items entered into the licensee's CAP. This review was accomplished through inspection of the station's daily condition report packages.

Enclosure 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. .3 Semi-Annual Trend Review a. Scope The inspectors performed a review of the licensee's

CAP and associated documents to identify trends that could indicate the existence of a more significant safety issue. The inspectors' review was focused on repetitive equipment issues, but also considered the results of daily inspector

CAP item screening discussed in Section 4OA2.2 above,

licensee trending efforts, and licensee human performance results. The inspectors' review nominally considered the six month period of September 1, 2007 through March 31, 2008, although some examples expanded beyond those dates where the scope of the trend warranted. The review also included issues documented outside the normal

CAP [[in major equipment problem lists, repetitive and/or rework maintenance lists, departmental problem/challenges lists, system health reports, quality assurance audit/surveillance reports, self assessment reports, and Maintenance Rule assessments. The inspectors compared and contrasted their results with the results contained in the licensee's]]

CAP trending reports. Corrective actions associated with a sample of the issues identified in the licensee's trending reports were reviewed for adequacy. Documents reviewed were listed in the Attachment.

This review constituted a single semi-annual trend inspection sample as defined in Inspection Procedure 71152-05. b. Findings No findings of significance were identified. 4OA3 Follow-up of Events and Notices of Enforcement Discretion (71153) .1 Seismic Event a. Inspection Scope The inspectors reviewed the plant's response to a seismic event felt at the plant due to an earthquake in southern Illinois on April 18, 2008. Although the ground motion was felt in the plant, the motion was apparently not strong enough to activate the seismic

monitoring system and annunciators. The inspectors collected the information necessary to communicate the event details to regional supervision, observed plant parameters and licensee activities, confirmed that the licensee had properly classified the event, and conducted independent walkdowns of risk significant plant areas to verify

Enclosure that no damage had occurred. The walkdowns included an inspection of all blowdown line vacuum breaker vaults, the areas over the buried blowdown piping, and the tritium mitigation pumping systems. Documents reviewed in this inspection were listed in the Attachment. This inspection constituted one sample as defined in

IP 71153-05. b. Findings No findings of significance were identified. 4

OA 5 Other Activities .1 (Closed)

NRC Temporary Instruction (

TI [[) 2515/166, "Pressurized Water Reactor Containment Sump Blockage (NRC Generic Letter [GL] 2004-02)" - Units 1 and 2 a. Inspection Scope The inspectors reviewed the station implementation of the licensee's commitments documented in their December 31, 2007, response to]]

GL 2004-02, "Potential Impact of Debris Blockage on Emergency Recirculation during Design Basis Accidents at Pressurized Water Reactors." The inspectors reviewed the Engineering Change Packages associated with the sump strainer modifications and the 10

CFR 50.59 evaluations for these Engineering Change Packages (ECs). The inspectors also reviewed documentation from the licensee and vendor pertaining to the strainer

assembly specifications. In addition, the inspectors reviewed three samples of the completed and approved for use changes for the

UFSAR , Revision 12, that have not been incorporated yet and one sample already incorporated in Revision 11. The documents reviewed were listed at the end of the report. The inspection was conducted in accordance with

TI 2515/166. Inspection Documentation The inspectors determined the following answers to the Reporting Requirements detailed in the

TI 2515/166: (1) Did the licensee implement the plant modifications and procedure changes committed to in their

GL 2004-02 responses? The licensee has implemented the plant modifications and procedure changes committed to in their

GL 2004-02 response with the exception of the installation and testing of

ECCS (ECCS) throttle valves for Unit 2 for which an extension for completion until Spring 2008 was requested and approved. In addition, the licensee cancelled the cyclone separator modification for Unit 2 because test

results showed that they are not susceptible to blockage as documented in

EC 364979, "Evaluation of Wyle Test Report." The commitments included: * Installation of permanent modification of the sump strainer assemblies including modification of the

ECCS throttle valves and replacement of the fibrous insulation with reflective metal insulation within the zone of influence at Unit 1.

Enclosure This commitment was previously reviewed and documented in

NRC [[Inspection Reports 05000456/2007006 and 05000457/2006005. The licensee has received approval for an extension regarding the downstream effects portion of their modification for Unit 2. Structural analyses of the new strainer assemblies were performed through]]

BRW -06-0015-M, "Design Loads and Sizing Limitations for the

EC [[]]

CS Containment Sump Trash Racks;"

BRW -06-0030-S, "Evaluation of Auxiliary Steel for Sump Strainer Upper Sizing Restraints;" and 3

SA-096.016, "CCI Structural Analysis of Strainer and Support Structure." * Perform latent debris walkdowns, and debris generation and transport analyses. The results of containment walkdowns were documented in analysis S040-BRW-6042, "[Generic Safety Issue] GSI-191 Latent Debris

Collection." The debris generation was estimated and analyzed by

BRW -05-0059-M, "

GSI -191 Post

LOCA (loss of coolant accident) Debris Generation." Debris transportation was analyzed through

BRW -05-0060-M, "Post

LOCA Debris Transport Evaluation for Resolution of

GSI 191." * Perform evaluation of strainer performance including chemical effects. Strainer performance was evaluated in calculation

3SA -096.018, "Head Loss Calculation," which received inputs from strainer head loss testing documented in

CCI Test Report 680/41222, "Chemical Filter Performance

Report." In addition, the following tests were performed: (1)

DIT -

BRW -2006-0007, "Results of Test Debris Concentrations"; (2)

Q. 003.87 748, "Large Size Filter Performance Test Specification"; and (3)

CCI Test Report 680/41134, "Large Size Filter Performance Test Report." * Perform evaluation of downstream and upstream effects. Downstream effects were evaluated by calculation

BRW -05-0084-M, "Byron Units 1 and 2, and Braidwood Units 1 and 2,

GSI-191 Downstream

Effects - Vessel Blockage and Fuel Evaluation." Downstream wear and blockage was evaluated by calculation

BRW -05-0063-M, "

GSI -191 Evaluation of Long Term Downstream Effects." Testing of wear and blockage to the

ECCS throttle valves and

CSS cyclone separator was documented in

WL [[]]

TR53637, "Wyle Test Report on Debris Latent Test

Results of 1 1/2" Copes Volcan Control Valve (SI 8810), A 2" Copes Volcan Control Valve (SI 8816), A 2" Copes Volcan Control Valve (SI 8822) and Cyclone Separator." Upstream effects were evaluated by S040-BRW-6054, "GSI-191 Debris Generation Walkdown." * Determine minimum available net positive suction head margin for the

RHR pumps at switchover to sump recirculation. Minimum available net positive suction head margin was determined by

BRW -06-0035-M, "NPSHA for

RHR and containment spray pumps during Post

LOCA Recirculation." The hydraulic model of the

EC [[]]

CS was

Enclosure performed by

BRW 06-0016-M, "

SI /RHR/CS/CV System Hydraulic Analysis in Support of

GSI 191." * Establish programmatic controls to ensure that potential sources of debris introduced into containment are assessed for adverse affects. The licensee performed an enhancement to

CC-AA-102, "Design Input and Configuration Change Impact Screening," to introduce a requirement to review the impact of a proposed change on the documentation that forms the design basis for their response to GL 2004-02. In addition, the

licensee upgraded

OP -

AA -116-101, "Equipment Labeling," and committed to use 1BwOS

TRM 2.5.b.1, "Unit 1 Containment Loose Debris Inspection;" 2Bw

OS [[]]

TRM 2.5.b.1, "Unit 2 Containment Loose Debris Inspection;" and

CC-AA-205, "Control of Undocumented/Unqualified Coatings Inside Containment" as administrative controls for limiting debris

sources inside containment. Also,

IR [[282077 is tracking the creation of a procedure for latent debris measurements inside containment every four refueling outages. This activity was tracked by Service Request No. 53465. (2) Has the licensee updated its licensing bases to reflect the corrective actions taken in response to]]

GL 2004-02? The licensee has updated its licensing bases to reflect the corrective actions taken in response to

GL 2004-02 with the exception of the portions relative to the

ECCS throttle valves modification at Unit 2 scheduled in Spring 2008. (3) If the licensee or plant has obtained an extension past the completion date of this

TI , document what actions have been completed and what actions are outstanding. The licensee requested and received approval for an extension until Spring 2008 to complete the installation and testing of

ECCS throttle valves for Unit 2. Completed actions are: * installation of new strainer assemblies for both units; * installation of modified

ECCS [[throttle valves at Unit 1; * replacement of fibrous insulation with reflective metal insulation within the zone of influence at Unit 1; * programmatic controls had been put in place; * associated analyses and testing; and * licensing bases update of the pertinent completed actions. Outstanding actions are: * installation of modified]]

ECCS throttle valves at Unit 2; * update of licensing bases associated with installation of new strainer assemblies for both units; and

Enclosure * IR 282077 is tracking the creation of a procedure for latent debris measurements inside containment every four refueling outages. This activity is being currently tracked by Service Request

No. 53465. This

TI is closed for both units. This documentation of

TI -2515/166 completion as well as any results of sampling audits of licensee actions will be reviewed by the

NRC staff (Office of Nuclear Reactor Regulation -

NRR) as input along with licensee's GL 2004-02 responses to support

closure of

GL 2004-02 and

GSI -191 "Assessment of Debris Accumulation on Pressurized-Water Reactor (PWR) Sump Performance." The

NRC will notify each licensee by letter of the results of the overall assessment as to whether

GSI -191 and

GL 2004-02 have been satisfactorily addressed at that licensee's plants. b. Findings No findings of significance were identified. .2

DMBW mitigation and inspection program to determine if it was implemented in accordance with the industry self-imposed mandatory requirements of Materials Reliability Program (

MRP) -139, "Primary System

Piping Butt Weld Inspection and Evaluation Guidelines." This review was conducted in accordance with

TI [[2515/172, "Reactor Coolant System Dissimilar Metal Butt Welds" for both Units 1 and 2. The documents reviewed by the inspector for this inspection were listed in the Attachment. From April 28, 2008, through May 6, 2008, the inspectors performed a review in accordance with]]

TI -172 which included the following: (1) Licensee's Implementation of the

MRP -139 Baseline Inspections The inspectors performed a review of the licensee's

DMBW program to determine: * if the licensee's inspection program for

DMBW s included applicable welds exposed to pressurizer, hot let and cold leg temperatures; * if the schedules for these baseline inspections were consistent with the requirements stated in

MRP -139; * if the baseline inspection schedules deviated from

MRP -139 guidelines; * the basis for any planned deviations from

MRP-139 baseline inspection schedules; and

Enclosure * the inspectors verified that the licenses had completed weld overlays on all Unit 2 pressurizer

DMBW s during the Spring 2008 refueling outage. (2) Volumetric Examinations The inspectors observed and/or reviewed records for the following volumetric examinations for: * Unit 1, the inspectors performed a review of

UT records from the Fall 2007 for the unmitigated reactor vessel outlet nozzle-to-safe end Inconel weld (1RV 01-22) at the 22 degree azimuth location; and * Unit 2, the inspectors observed the licensee's vendor acquiring and analyzing

UT data for the unmitigated reactor vessel inlet nozzle-to-safe end Inconel weld (2

RV -01-24) at the 113 degree azimuth location. The inspectors reviewed records of the following weld overlay volumetric examinations for: * Unit 1, the inspectors performed a review of

UT records from the Fall 2007 outage for the weld overlay repair of the pressurizer surge nozzle

DMBW (1PN 01-SW-1) and the adjacent stainless steel safe-end to pipe/fitting welds; and * Unit 2, the inspectors performed a records review from the current outage of the

UT data for the weld overlay repair of two pressurizer safety nozzle

DMBW s (2PN-04-SW-4 and

2PN -06-

SW -6) and the adjacent stainless steel safe-end to pipe/fitting welds. The inspectors performed the reviews of volumetric examinations identified above to determine if: * the examinations were performed in accordance with the guidelines in

MRP -139 Section 5.1; * the examinations were performed consistent with the

NRC staff relief request authorization for the weld overlay; * the examination coverage warranted further evaluation and if so, the inspector reviewed the licensee's basis for achieving the inspection coverage credited; * the volumetric examinations were performed by qualified personnel; and * deficiencies were appropriately dispositioned. (3) Weld Overlays For Unit 1, the inspectors performed a review of licensee records for the pressurizer surge nozzle (1-PN-01-SW-1) weld overlay completed in the Fall 2007.

Enclosure For Unit 2, the inspectors observed the weld overlay repairs completed for the pressurizer safety nozzle "A" (2PZR-01-SE-02) and safety nozzle "B" (2PZR-01-SE-04). The inspectors performed the review of weld overlays identified above to determine if: * the overlays were performed in accordance with

ASME Code requirements as modified by

NRC staff relief request authorizations; * the licensee submitted appropriate relief requests and obtained

NRR staff authorization to install the weld overlays; * the overlay welding was performed by qualified personnel; and * deficiencies were appropriately dispositioned, and resolved. (4) Mechanical Stress Improvement (

SI ) There were no stress improvement activities performed or planned by the licensee. Therefore, the inspectors did not perform a review for this inspection attribute. (5)

ISI Program The inspectors performed a review of the licensee's

DMBW inspection program to determine if: * it included the applicable welds required by

MRP -139; * the welds were identified with inspection categories consistent with the

MRP -139 guidelines; * the licensee's

DMBW program and procedures required inspection frequencies consistent with Tables 6-1 and 6-2 of

MRP -139; * any

DMBW [[s were categorized as "H" or "I" and for these welds, the licensee's basis for this categorization and the licensee's plans to address the potential for primary water stress corrosion cracking; and * deviations were planned from the inspection guidelines of]]

MRP -139. b. Observations Summary: Braidwood Units 1 and 2 are Westinghouse four loop design plants. For each unit, the licensee had identified a population of

DM [[]]

BWs susceptible to primary

water stress corrosion cracking in accordance with

MRP -139 guidelines. The licensee had completed mitigation by weld overlay repairs to the pressurizer

DMBW s on both units. The licensee had not decided on mitigation methods for the remaining

DMBW susceptible to primary water stress corrosion cracking (e.g.,

MRP-139 categories "D" and "E").

Enclosure For Unit 1, during the Fall 2007 outage, the licensee completed baseline examinations of the pressurizer

DMBW s after completing weld overlay repairs and had not deviated from the

MRP -139 inspection guidelines. For Unit 2, the licensee had previously taken a deviation from

MRP -139 for the

DMBW on the pressurizer surge line, since it was not inspected or mitigated by December 31, 2007. The licensee completed weld overlay repairs on the pressurizer

DMBW s during the current outage including the

DMBW at the pressurizer surge line. The inspectors confirmed that the licensee performed appropriate weld overlay repairs and

UT to the pressurizer surge line weld such that a deviation from the

MRP -139 guidelines no longer existed. In accordance with requirements of

TI 2515/172, Revision 0, the inspectors evaluated and answered the following questions: (1) Licensee's Implementation of the

MRP -139 Baseline Inspections 1. Have the baseline inspection been performed or are they scheduled to be performed in accordance with

MRP -139 guidance? Yes. Baseline inspections of all hot and cold leg

DMBW s were completed. Were the baseline inspections of the pressurizer temperature

DMBW s of the nine plants listed in 03.01.b completed during the spring outages? Yes. Baseline inspections of the Braidwood Unit 2 pressurizer

DMBW s were completed after applying weld overlay repairs during the Spring 2008 outage. 2. Is the licensee planning to take any deviations from the

MRP -139 baseline inspection requirements? If so, what deviations are planned, what is the general basis for the deviation, and was the

NEI- 03-08 process for filing a deviation followed? No. The licensee was not planning to take any further deviations from the MRP-139 baseline inspection requirements. For Unit 2, the

licensee had previously taken a deviation from MRP-139 for the

pressurizer

DMBW 's, since they were not inspected or mitigated by December 31, 2007. The basis for this deviation was the low susceptibility of the material and the timing of the Spring 2008 refueling outage. The

NEI -03-08 process for filing the deviation was followed. The licensee completed weld overlay repairs on the pressurizer

DM [[]]

BWs during the current outage. The inspectors confirmed that the licensee performed appropriate weld overlay

repairs and

UT to the pressurizer

DMBW's such that a deviation from the MRP-139 guidelines no longer existed.

Enclosure (2) Volumetric Examinations 1. Performed in accordance with the examination guidelines in

MRP -139, Section 5.1, for unmitigated welds or mechanical stress improvement welds and consistent with

NRC staff relief request authorization for weld overlaid welds? Yes. For Unit 1, the inspectors performed a records review of the

UT data for the unmitigated reactor vessel outlet nozzle-to-safe end Inconel weld at the 22 degree azimuth location. The licensee's vendor use a Performance Demonstrated Initiative (

PDI ) qualified automated

UT technique and achieved the

XI required weld volume. Yes. For Unit 2, the inspectors observed the licensee's vendor acquiring and analyzing

UT data for the unmitigated reactor vessel inlet nozzle-to-safe end Inconel weld at the 113 degree azimuth location. The licensee's vendor used a

PDI qualified automated

UT technique and achieved the

ASME Code Section

XI required weld volume. 2. Performed by qualified personnel? (Briefly describe the personnel training/qualification process used by the licensee for this activity.) Yes. For both Units, the licensee's vendor staff that analyzed the

UT data for the unmitigated reactor coolant loop nozzle-to-safe end welds, were certified to

UT Level II requirements in accordance

with a vendor procedure (WDP-9.2 WesDyne International Qualification and Certification of Personnel in Nondestructive Examination) to meet the training and certification requirements of the

ASME Code Section

XI , Appendix

VII and

VIII. For Unit 2, the inspectors also confirmed that the two dayshift vendor UT analysts

had certification records issued by the

PDI program established by

EPRI , which documented successful performance testing required to meet the applicable

ASME Code welding requirements and consistent with

XI , Appendix

VIII [[supplement for examination of these welds. 3. Performed such that deficiencies were identified, dispositioned, and resolved? Not applicable. No deficiencies or recordable indications were identified in the unmitigated nozzle-to-safe end Inconel welds. (3) Weld Overlays 1. Performed in accordance with]]

NRC staff relief request authorizations? Has the licensee submitted a relief request and obtained

NRR staff authorization to install the weld overlays?

Enclosure Yes. For each Unit, the weld overlays were performed in accordance with

ASME Code welding requirements and consistent with the approved

NRC relief request. Yes. For each Unit, the licensee submitted a relief request and obtained

NRR [[staff authorization to install the weld overlays. 2. Performed by qualified personnel? (Briefly describe the personnel training/qualification process used by the licensee for this activity.) Yes. For the weld overlays reviewed by the inspectors in each Unit, the welders fabricating the overlay had performed an]]

ASME Code,Section IX - Welder Performance Qualification in accordance with the vendor's program for the weld overlay activities performed.

The welder qualification records were transmitted to Exelon for review and concurrence in support of the A2R13 weld overlay work. The inspectors reviewed the welder qualification records including the welders'

ASME Code - Welder Maintenance Log. 3. Performed such that deficiencies were identified, dispositioned, and resolved? Yes. For Unit 1, rejectable surface indications were identified during the final weld overlay dye penetrant examination (

PT ). The licensee removed a small amount of weld material to remove these indications (e.g., buffed out) and reperformed a final

PT to accept the weld overlay repairs. The inspectors reviewed the final

PT records for the weld overlays affected and considered these

deficiencies appropriately dispositioned and resolved. Yes. For Unit 2, the licensee's vendor encountered problems resulting in loss of shielding gas during weld overlay fabrication. The licensee's vendor ground out affected weld metal and rewelded portions of the overlay repair. Similar to the Unit 1 overlay, the

licensee identified rejectable indications during the final weld overlay

PT examinations for Unit 2. The licensee removed a small amount of weld material to remove these indications (e.g., buffed out) and reperformed a final

PT to accept the weld overlay repairs. The inspectors reviewed the final PT records for the weld overlays

affected and considered these deficiencies appropriately dispositioned and resolved. For Unit 2, during fabrication of the "B" safety nozzle, the licensee vendor identified that the overlap for the sacrificial layer weld was not in accordance with the weld procedure. The licensee removed

(e.g., ground off) the incorrect weld overlap, completed a PT of the ground area, and then completed a proper weld overlap. The inspectors concluded that the licensee had taken appropriate corrective actions to resolve this deficiency.

Enclosure (4) Mechanical Stress Improvement No stress improvement activities have been performed for

DMBW s nor did the licensee plan to perform mechanical stress improvement as a mitigation strategy for

DMBW s. (5)

ISI Program 1. Has the licensee prepared an

ISI program? If not, briefly summarize the licensee's basis for not having a documented program and when the licensee plans to complete preparation of the program. No. The licensee had not prepared a separate

ISI program. However, the licensee had scheduled baseline and

ISI s of

DMBW s at frequencies consistent with the

MRP-139 guidelines

and the

XI requirements. 2. In the

ISI program, are the welds appropriately categorized in accordance with

MRP -139? If any welds are not appropriately categorized, briefly explain the discrepancies. Yes. For each Unit, the

DMBW s were categorized in accordance with

MRP -139. 3. In the

ISI frequencies, which may differ between the first and second intervals after the

ISI program, are the

MRP -139 baseline inspection, consistent with the

ISI frequencies called for by

MRP -139? Yes. The

ISI frequencies, for

DMBW s in each Unit, were consistent with the

ISI frequencies required by

MRP -139. 4. If any welds are categorized as H or I, briefly explain the licensee's basis of the categorization and the licensee's plans for addressing potential

PWSCC. For Unit 2, the pressurizer welds were categorized as "H" prior to the application of a structural weld overlay. The Category H was assigned due the difficulty of performing a

PDI [[]]

UT examination of these welds.

After completing the weld overlay repairs, the licensee indicated that these

DMBW s would be re-categorized as Category F in accordance with

MRP -139 guidance. For Unit 1, the licensee did not have

DMBW s in the "H" or "I" Categories. 5. If the licensee is planning to take deviations from the

ISI "requirements" of

MRP -139, what are the deviations and what are the general bases for the deviations? Was the

NEI 03-08 process for filing deviations followed? Not applicable. The licensee was not planning to take deviations from the MRP-139 guidelines.

Enclosure c. Findings No findings of significance were identified. .3 (Closed)

URI 05000456/2008001-01; 05000457/2008001-01, Failure to Control Regulatory Guide 1.97 Instrumentation Marking a. Inspection Scope During an initial operator licensing examination documented in Examination Report 05000456/2007301(

DRS ); 05000457/2007301(DRS),

NRC inspectors identified a

URI concerning the lack of procedural controls for labeling Regulatory Guide (RG) 1.97 post-accident indications on the main control room control panels. The inspectors opened

URI 05000456/2008001-01; 05000457/2008001-01, "Failure to Control

RG 1.97 Instrumentation Marking," to track this possible violation of

NRC requirements. The licensee then found and provided copies of letters to the

NRC and other information documenting commitments, current status, and corrective actions to be taken for post-accident instrument labeling deficiencies. The inspectors reviewed the corrective action document (IR 688723), the licensee's plans to revise Procedures 1BwOSR 3.3.3.1, "Unit One Accident Monitoring Instrumentation Channel Checks" and 2BwOSR 3.3.3.1, "Unit Two Accident Monitoring Instrumentation Channel Checks," and Training Requests submitted to ensure familiarity

with equipment included in Braidwood

TS , Table 3.3.3-1, "Post Accident Monitoring Instrumentation." b. Findings Introduction: The inspectors identified a finding of very low safety significance (Green) and associated

NCV of TS 5.4.1, for failure to maintain adequate procedural controls for

labeling

RG 1.97 post-accident indicators on the control panels. Description:

UFSAR Appendix A1 described an

NRC submittal for Braidwood Station's

RG 1.97 instruments dated September 1, 1987. This letter committed the licensee to identifying post-accident instruments per RG 1.97, Revision 3, as part of their Detailed Control Room Design Review. Currently, no Braidwood Station procedure describes or

controls these markings, which consist of a black dot on the panel next to the indicator. The markings were intended to indicate qualification for reliability under accident conditions. Therefore, if multiple indications conflicted during an accident, the operators should prefer the indicators with a black dot. The inspectors identified that markings existed for numerous post-accident indications on both units' control panels and the simulator. When questioned about how these markings were controlled, the licensee stated that they were informally controlled as part of the

PASSPO [[]]

RT database panels and was initially unable to provide a list of marked instruments due to the large number of

RG 1.97 instruments and unmarked subcomponents which were also contained in the

PASSPO RT database. To address the concern regarding the accuracy of these markings, the licensee walked down the panels, and reviewed the source documents and

PASSPO [[]]

RT further. It was

Enclosure determined that there were errors in both the Unit 1 and Unit 2 control rooms and the simulator, which included the following discrepancies: * Control Room Indicator

1PI -405A, Unit 1 wide range

RCS pressure, was not labeled with a black dot; * Control Room Indicator

1LI -930, Unit 1 Refueling Water Storage Tank (

RWST ) level, was not labeled with a black dot; * Control Room Indicator

1LI -931, Unit 1

RWST level, was not labeled with a black dot; * Control Room Indicator

1LI -932, Unit 1

RWST level, was not labeled with a black dot; * Control Room Indicator

1LI -933, Unit 1

RWST level, was not labeled with a black dot; * Control Room Indicator

2LI -930, Unit 2

RWST level, was not labeled with a black dot; * Control Room Indicator

2LI -931, Unit 2

RWST level, was not labeled with a black dot; * Control Room Indicator

2LI -932, Unit 2

RWST level, was not labeled with a black dot; * Control Room Indicator

2LI -933, Unit 2

RWST level, was not labeled with a black dot; and * Simulator Indicator,

1PI -405A, Unit 1 wide range

RCS pressure, was not labeled with a black dot. The licensee initiated

IR [[688723, corrected the discrepancies identified by labeling the appropriate post-accident instruments and initiated Training Requests to evaluate the need for familiarization on post-accident monitoring instrumentation. In addition, the licensee planned to revise Procedures 1Bw]]

OSR 3.3.3.1, "Unit One Accident Monitoring

Instrumentation Channel Checks" and 2BwOSR 3.3.3.1, "Unit Two Accident Monitoring Instrumentation Channel Checks" to validate RG 1.97 labeling periodically. The procedure revisions were being tracked by action tracking item 709180-02. Analysis: The inspectors determined that the licensee's failure to perform adequate procedural controls was a performance deficiency warranting a significance evaluation in

accordance with

IMC [[0612, Appendix B. The inspectors concluded that the finding was greater than minor because it could become a more significant safety issue if left uncorrected. Inaccurately labeled control room indicators of post-accident instrumentation could lead to confusion and hamper operator response if conflicting indications resulted due to accident conditions. Using]]

IMC [[0609.04, the inspectors concluded that this issue was of very low safety significance (Green) because the finding was did not represent; a design or structure, system and component qualification deficiency; a loss of system safety function; an actual loss of safety function or exceed]]

TS allowed outage time; an actual loss of safety function of one or more non-

TS, risk-significant trains; or a potentially risk-significant

scenario related to external initiating events. The inspectors did not identify a cross-cutting aspect to this finding.

Enclosure Enforcement: Technical Specification 5.4.1 required, in part, that written procedures be established and implemented for activities provided in

RG 1.33, Revision 2, Appendix A, February 1978. Procedures specified in

RG 1.33 included administrative procedures for equipment control.

UFSAR 13.5, "Plant Procedures," stated that a formalized system of written procedures containing administrative and operating instructions in conformance with

RG 1.33 was employed to ensure that all abnormal or emergency activities were

conducted in a safe manner. Contrary to the above, the inspectors identified that the licensee failed to control labeling of control panels for uniquely identifying RG 1.97 equipment. Specifically, the licensee failed to control labeling on both units' control panels and the simulator, resulting in improperly marked post-accident indicators. However, because this violation was of

very low safety significance and was entered into the licensee's

CAP , this violation was treated as a

NCV , consistent with Section

VI.A of the

NRC Enforcement Policy. (NCV 05000456/2008003-05; 05000457/2008003-05) This URI (05000456/2008001-01; 05000457/2008001-01) is closed. .4 Quarterly Resident Inspector Observations of Security Personnel and Activities a. Inspection Scope During the inspection period, the inspectors conducted observations of security force personnel and activities to ensure that the activities were consistent with licensee security procedures and regulatory requirements relating to nuclear plant security. These observations took place during both normal and off-normal plant working hours. These quarterly resident inspector observations of security force personnel and activities did not constitute any additional inspection samples. Rather, they were considered an

integral part of the inspectors' normal plant status review and inspection activities. b. Findings No findings of significance were identified.

4OA [[6 Management Meetings .1 Exit Meeting Summary On July 9, 2008, the inspectors presented the inspection results to Mr. B. Hanson, 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 Interim exits were conducted for: * On April 2, 2008, the inspectors presented the]]

TI 2515/166, "PWR Containment Sump Blockage (NRC GL 2004-02)," results to Mr. J. Petty, and other members of the licensee staff. The licensee acknowledged the issues presented.

Enclosure * The results of the Access Control to Radiologically Significant Areas and

ALARA Planning And Controls inspection with the Site Vice President, Mr. B. Hanson, on May 2, 2008. * The results of the

ISI Procedure 71111.08 and TI 72 with Mr. B. Hanson, Site Vice President on May 6, 2008. The inspectors returned proprietary information reviewed during the inspection prior to leaving the site. * Licensed Operator Requalification Program Unresolved Item Inspection with Mr. G. Golwitzer, Acting Regulatory Assurance Manager, Braidwood Station, June 23, 2008, via telephone. The inspectors confirmed that none of the potential report input discussed was considered proprietary.

Attachment

SUPPLE [[]]

MENTAL [[]]

INFORM [[]]

ATION [[]]

KEY [[]]

POINTS [[]]

OF [[]]

CONTACT Licensee B. Hanson, Site Vice President L. Coyle, Plant Manager K. Aleshire, Emergency Preparedness Manager

D. Burton, Licensed Operator Requalification Training Group Lead S. Butler, Operations Training Manager B. Casey, Inservice Inspection Program G. Dudek, Site Training Director R. Gadbois, Maintenance Director

G. Golwitzer, Acting Regulatory Assurance Manager D. Gullott, Regulatory Assurance Manager K. Hall, Operations J. Knight, Nuclear Oversight Manager T. McCool, Operations Director J. Moser, Radiation Protection Manager J. Neybart, Maintenance Department

G. Panici, Senior Engineer J. Petty, Licensing Engineer L. Sanna, Maintenance Department J. Sanchez, Operations Department B. Schipiour, Work Management

M. Sears, Steam Generator Engineer M. Smith, Engineering Director T. Tierney, Chemistry, Environmental, and Radioactive Waste Manager Nuclear Regulatory Commission R. Skokowski, Chief, Reactor Projects Branch 3

LIST [[]]

OF [[]]

ITEMS [[]]

OPENED ,

CLOSED [[]]

AND [[]]

DISCUS SED Opened 05000456, 457/2008003-03

URI [[]]

AFW Tunnel Hatches Margins of Safety (Section 1R15) Opened and Closed 05000456, 457/2008003-01

NCV Failure to Properly Implement Material control Procedures (Section 1R01) 05000456, 457/2008003-02

NCV Inadequate Procedure (Section 1R06) 05000456, 457/2008003-04

NCV Failure to Sample a Temporary Tank at the Required Periodicity (Section 2

PS2)

Attachment 05000456, 457/2008003-05

NCV Failure to Control Labeling on Both Units' Control Panels and Simulator (Section 4

OA 5) Closed 05000456, 457/2008001-01

URI Failure to Control

RG 1.97 Instrumentation Marking (Section 1R15)

Attachment

LIST [[]]

OF [[]]

DOCUME [[]]

NTS [[]]

REVIEW [[]]

ED The following is a partial list of documents reviewed during the inspection. Inclusion on this list does not imply that the

NRC inspector reviewed the documents in their entirety, but rather that selected sections or portions of the documents were evaluated as part of the overall inspection effort. Inclusion of a document on this list does not imply

NRC acceptance of the document or any part of it, unless this is stated in the body of the inspection report.

Section 1R01: Adverse Weather Protection - 0BwOA

ENV -1; Adverse Weather Conditions Unit 0; Revision 106 - 0Bw

OS [[]]

XHT -A1; Unit Common High Temperature Equipment Protection Surveillance; Revision 2 - Bw

OP [[]]

MP -26; Supplemental Main Power Transformer Cooling; Revision 0 -

EN -BR-402-0005; Extreme Heat Implementation Plan; Revision 1 -

AA -718-026; Station Housekeeping/Material Condition Program; Revision 5 -

WC -

AA -107; Seasonal Readiness; Revision 5 - Exelon Nuclear Letter; Certification of 2008 Braidwood Summer Readiness; May 15, 2008 -

IR 752473;

NOS Identified Summer Readiness Procedure Action Dates Not Met, March 20, 2008 -

IR 758730; Procedure Enhancement for 0Bw

OA [[]]

ENV [[-1; April 3, 2008 []]

IEMA [[-Identified] -]]

IR 763083; 2

CW 003B Summer Readiness Action Not Being Performed in A2R13; April 4, 2008 -

IR 767822; Safety - Flying Debris On Site; April 25, 2008 -

IR 767858; Adverse Weather Conditions - Entered BwOA ENV-1; April 25, 2008

-

IR [[770357; Three Scaffold Poles and Material in Unit 1 Transformer Yard; May 1, 2008 []]

NRC [[-Identified] -]]

IR 771219; 0/1/2/

ENV -1 Entry; May 2, 2008 -

IR 775201; Unit 1 Turbine Oil Transient; May 13, 2008 -

IR [[778589; Main Power Transformer Supplemental Cooling Not Secured Properly; May 22, 2008 [NRC-Identified] -]]

IR 780318;

IEMA [[Inspector Identified Housekeeping Concerns; May 28, 2008 [IEMA-Identified] -]]

IR 780777;

NRC [[Identified Miscellaneous Debris in Transformer Yard; May 29, 2008 [NRC-Identified] -]]

IR 780979; Entry Into 0Bw

OA [[]]

ENV -1, 1Bw

OA [[]]

ENV -1, and 2Bw

OA ENV-1; May 30, 2008

-

IR 781334; Security Camera 9 Went Out Due to Severe Weather; May 30, 2008 -

IR 781339; Security Camera 5 Went Out Due to Severe Thunderstorm; May 30, 2008 -

IR 781352; Entry Into 0/1/2 Bw

OA [[]]

ENV -1; May 30, 2008 -

IR 781363; Received Annunciator 0-38-E5, Accelerograph Acceleration High; May 30, 2008 -

IR 781945;

IEMA Identified Discharge Flex Hose Broken on

2VE [[09S; June 2, 2008 []]

IEMA [[-Identified] -]]

IR [[782644; Replace D-181 Door Threshold; June 4, 2008 []]

NRC [[-Identified] - 0BwOA]]

ELEC -1 Abnormal Grid Conditions Unit 0; Revision 6 -

OP -AA-108-107-1001 Station Response to Grid Capacity Conditions; Revision 2 -

OP -

AA -108-107 Switchyard Control; Revision 2 Section 1R04: Equipment Alignment - BwOP

DG -M4; Operating Mechanical Lineup Unit 2 2B D/G; Revision 11 - Bw

OP [[]]

DG -E4; Electrical Lineup - Unit 2 2B Diesel Generator; Revision 5 - Bw

OP DG-M1; Operating Mechanical Lineup Unit 1 1A D/G; Revision 14

Attachment - BwOP

DG -E1; Electrical Lineup - Unit 1 2A Diesel Generator; Revision 6 - Bw

OP [[]]

AF -E1; Electrical Lineup - Unit 1 Operating; Revision 11 - Bw

OP [[]]

AF -M!; Operating Mechanical Lineup Unit 1; Revision 10 -

IR 787664;

NRC [[Identified - Add Hand Switch Equipment Part Numbers to Shutdown Panel Labels; June 18, 2008 []]

NRC [[-Identified] Section 1R05: Fire Protection - Byron/Braidwood Nuclear Stations Fire Protection Report; Amendment 22; December 2006 -]]

GOCAR Required Compensatory Measures Action Response Appendix R Emergency Lighting; May 5, 2008 -

CC-AA-211; Fire Protection Program; Revision 2 - BwAP 110-1; Fire Protection Program System Requirements; Revision 28

-

IR 760766;

NRC Pump Room; April 8, 2008 [NRC-Identified] -]]

IR [[761728; Material Found Behind Fuel Oil Line on 2A Diesel Generator; April 10, 2008 []]

NRC [[-Identified] -]]

IR [[761734; Material Left in 2A Safety Injection Pump Room; April 10, 2008 []]

NRC [[-Identified] -]]

IR 761778;

IEMA Inspector Told the Work Execution Center the Back of

MCC [[133V4 Was Open; April 10, 2008 []]

IEMA [[-Identified] -]]

IR 764634;

IEMA [[Inspector Identified Issues in 2A Safety Injection Pump Room; April 17, 2008 [IEMA-Identified] -]]

IR [[771999; Appendix R Lights Almost Dead During 234V Bus Outage; May 5, 2008 []]

NRC [[-Identified] -]]

IR 772946;

IEMA Identified Transient Combustible Material Behind

MCC [[233V5; May 7, 2008 []]

IEMA [[-Identified] -]]

IR 787368;

NRC [[Identified Door D-226 Not Latching Closed Following Passage; June 17, 2008 [NRC-Identified] Section 1R06: Flooding - BwAP 1110-3; Plant Barrier Impairment Program; Revision 15 -]]

IR 760446; Unit 2

SX Room Sump Alarm not Alarming; April 7, 2008 -

IR [[766773; Plant Barrier Impairment Compensatory Actions Changed, Not Identified by Shift; April 23, 2008 []]

IEMA [[-Identified] -]]

IR 771437; Missed Flood Watch on 2

SXFS 02-1 For Entire 12 Hour Shift; May 2, 2008 Section 1R07: Heat Sink Performance - Calculation

BRW -97-1072-M; Component Cooling Heat Exchanger Tube Plugging Evaluation; Revision 0 - Engineering Change

EC 357161; Heat Exchanger Visual Inspection Acceptance Criteria; Revision 0 -

IR 760868; 2

CC 01A - Unit 2 Component Cooling Heat Exchanger East Head Flange Degradation Increasing; April 9, 2008 -

IR 761744; Cleaning Scrappers Stuck in Three Tubes in Unit 2 Component Cooling Heat Exchanger; April 10, 2008 -

IR 761765; Seacure Tubing Eddy Current Inspection

2CC 01A; April 10, 2008 -

IR 763185; 2CC01A - 8 Tubes Plugged Per Eddy Current Test Data - Total = 49 Tubes; April 14, 2008

Attachment Section 1R08:

ISI Activities -

IR 547480; Incorrect

ISI Weld Inspected; October 22, 2006 -

IR 550299;

FME Event Steam Generator; October 28, 2006 -

IR 552261; Steam Generator Chemistry Action Level 1; November 2, 2006 -

IR 566370; Boric Acid Leak 2

RH 01CB-16 Flanged Connection; December 7, 2006 -

IR 543851; Boric Acid Leak 2

CV04AA Inlet Flange; October 13, 2006

-

IR 549559;

UT of 5 Welds Deferred to A2R13; October 26, 2006 -

IR 576532; Degradation of Hydraulic Snubber Fluid; January 5, 2007 -

IR 628474; Through-Wall Leakage

2SX 27

DA -10; May 11, 2007 -

IR 628554; Misapplication of

CGI Gaskets; October 10, 2007 -

IR 664847; 2

RC8037A Boric Acid Leakage; August 23, 2007

-

IR 664853; 2

RC 8037B Boric Acid Leakage; August 27, 2007 -

IR 681083;

FME Event Steam Generator; October 6, 2007 -

IR 681801;

FME Event Steam Generator; October 8, 2007 -

IR 684599;

FME Event Reactor Vessel; October 14, 2007 -

IR 768257; Flaw Evaluation not Scheduled; April 29, 2008 -

IR 679564;

PT Indication Discovered on Base Metal Exam on "C" Nozzle; October 3, 2007 -

IR 679792; PT Indication Discovered on the A Safety Nozzle; October 3, 2007

-

IR 684405; Weld Overlay Rejectable

PT Indication; October 13, 2007 -

IR 549140;

NDE Indications Found During Weld Exam for

VLV 2

SI 8952B; October 26, 2006 -

IR 768009; Pressurizer Weld Overlay Anomaly; April 26, 2008 -

UT Calibration Sheet A2R13-UT-045; Elbow-to-pipe Weld

2SI -01-03; April 29, 2008 -

UT Calibration Sheet A2R13-UT-044; Elbow-to-pipe Weld 2SI-30-15; April 29, 2008

- Surface Examination Data (Magnetic Particle Examination); Steam Generator 16-inch Feedwater Nozzle to Stub Barrel; May 3, 2008 -

UT Calibration Sheet A2R13-

PN -04-SW-4; Pressurizer Safety "A"

SWOL ; May 4, 2008 -

UT Calibration Sheet A2R13-PN-06-SW-6; Pressurizer Safety "C"

SWOL ; May 5, 2008 -

PT Examination Sheets; Pressurizer Safety Nozzle A (PN-04-A); May 4, 2008

-

PT Examination Sheets; Pressurizer Safety Nozzle C (

PN -04-C); May 3, 2008 -

UT Calibration Sheet A1R13-

PN -01-SW-1; Pressurizer Surge Nozzle

SWOL ; October 14, 2007 - 900638-

PT -008 (PT Examination Sheets); Pressurizer Surge Nozzle to Pipe

1PN -01-

SW -1; Pressurizer Surge Nozzle to Pipe

1PN -01-

SW -1 -

ISI -

PDI -UT-2; Ultrasonic Examination of Austenitic Piping Welds in Accordance with

ISI -70; Magnetic Particle Examination; Revision 2 -

UT -2; Revision 4 -

EXE -

ISI -254-SE; Remote Inservice Examination of Reactor Vessel Nozzle to Safe End, Nozzle to Pipe and Safe End; Revision 2 -

ISI -254; Remote Inservice Examination of Reactor Shell Welds; Revision 7 -

AP -420-0051; Conduct of Steam Generator Management Program Activities; Revision 11 -

AP -331; Boric Acid Corrosion Control (BACC)Program; Revision 3 -

BACC Locations, Implementation and Inspection Guidelines; Revision 3 -

AP -331-1001;

ER -AP-331;

BACC Program Identification, Screening and Evaluation; Revision 3 -

GDP -9.7; Liquid Penetrant Examination and Acceptance Standards for Welds, Base Materials and Cladding; Revision 11 -

PS -03;

GQP 9.7 Procedure Supplement; March 13, 2008 -

EXE -

PDI -UT-108; Ultrasonic Examination of Weld Overlay Similar and Dissimilar Welds in Accordance with

BWR -08-003; Braidwood Unit 2 Steam Generator Inspection Degradation Assessment and Condition Monitoring Input Checklist for A2R13; April 14, 2008 - Report

UT -8; Revision 1 -

WDI -

STD-1016; Generic Procedure for the Ultrasonic Informational Only Examinations of Weld Overlay Material Using Straight Bea (0o) and Angle Beam Probes; Revision 1

Attachment -

WDI -

SSP [[-1112; Procedure for Acquiring Material Thickness and Circumference Measurements of Liquid Penetrant Examination; Revision 4 - Examination Plan; 2008 - 10 Year Reactor Vessel Examination Program Plan (Scan Plan); Revision 0 - Report; Steam Generator Condition Monitoring Operational Assessment Report; Revision 0 - Report]]

ED -

ED -

BWR-08-005; Braidwood Unit 2 Steam Generator Inspection Degradation Assessment and Condition Monitoring Inp Use of Appendix H Qualified Techniques at Braidwood Unit 2 A2R13 Outage; March 10, 2008 - Boric Acid Evaluation; RCP 2B No 1 Seal Flow Element; January 15, 2007

- Boric Acid Evaluation; 2B Reactor Coolant System Loop Drain Isolation Valve; December 7, 2007 -

ETSS [[]]

CDE -001-0408; 0.610 Bobbin

40 IPS ; Revision 0 -

ETSS [[]]

CDE -002-0408; 0.590 Bobbin 24

IPS ; Revision 0 -

ETSS [[]]

CDE -003-0408; 3 Coil +Point; Revision 0 -

ETSS [[]]

CDE -004-0408; 3 Coil +Point (Dent); Revision 0 -

ETSS [[]]

CDE-005-0408; 3 Coil +Point (Mag Bias); Revision 1

-

ETSS [[]]

CDE -006-0408; Low Row U-Bend +Point; Revision 1 -

ETSS [[]]

CDE -007-0408; High Row U-Bend +Point; Revision 0 -

WDI -

PJF -1303502-TR-003; Investigation on the Variation in Reference Sensitivity Between Nominal 3/32-Inch (0.094) Diameter Side-Drilled Holes with Diameter Increases Up to 0.0025-Inch; Revision 0 -

CMTR ; Inconel Filler Metal 52M .045 x 10Spl; June 1, 2007 -

WPS [[]]

MC -GTAW; Revision 3 -

PQR 062 R/3;

WPS 8

MC -GTAW; Revision 3 -

PQR 600;

WPS 8-MN-GTAW/SMAW; Revision 3 -

WPS 8

MC-GTAW; Revision 4

-

WPS 8-

MN -GTAW/SMAW; Manual

WO 00985967; Weld Overlay for Unit 1 Pressurizer Surge Nozzle (

PN -01); September 27, 2007 - Contract 00412187; Transmittal of

PCI Welder Qualification Records for A2R13 Pressurizer

SWOL ; April 16, 2008 -

WO 01078103-04; Weld Overlay Traveler for Pressurizer Unit 2 "A" Nozzle Overlay; March 14,

WO 01078103-08; Weld Overlay Traveler for Pressurizer Unit 2 "C" Nozzle Overlay; March 14, 2008 -

WEG -

SWOL -01; Determination of

SW [[]]

OL Weld Track Travel Speed; Revision 0

-

TB [[]]

SWOL (P3-P8); Revision 7 -

GTAW -N638; Machine

GTAW for

PQR 677;

TB [[]]

GTAW -N638; April 9, 2001 -

PQR 750;

TB [[]]

GTAW -N638; Revision 1 -

PQR 770;

TB [[]]

GTAW -N638; Revision 4 Section 1R12: Maintenance Effectiveness - BwOP

SA -1; Startup and Operation of Station Air Compressors; Revision 36 -

IR 772936;

NRC Identified Maintenance Rule Website Not Up-to-Date For

SA [[System; May 7, 2008 [NRC-Identified} -]]

IR 352740; Unit 1 Station Air Compressor Tripped During Start Attempt; July 15, 2005 -

IR 502360; U-2

SAC has High Vibes; June 21, 2006 -

IR 503175; Unit 2 SAC Tripped on High Vibrations; June 24, 2006

Attachment -

IR 501537; U-2

SAC Tripped on Hi Oil Temperature; June 19, 2006 -

IR 613656; Unit 0

SAC High Speed Vib was Noted Higher During Post Maintenance Testing; April 4, 2007 -

IR 659297; Unexpected Alarm, High

CO content in Service Air; August 10, 2007 -

IR 577250; Corrective Actions from

EACE Not incorporated into

SAC Work; January 10, 2007 -

IR 601858; U2 SAC Tripped on Driver Fault During Run After Maintenance; March 10, 2007

-

IR 618457; Unit 2

SA System Exceeding

MR Unavailability; April 17, 2007 -

IR 640810; Service Air Drop Drain is Clogged; June 15, 2007 -

IR [[502397-04;(a)(1) Determination; April 24, 2007 Section 1R13: Maintenance Risk Assessments and Emergent Work Control - Unit 2 Component Cooling Heat Exchanger Work Window Protected Equipment; April 7, 2008 - Braidwood Operating Department Memorandum 3-04; Physical Posting of Protected Equipment; Revision 3 -]]

TS 3.0.4.b Evaluation - Mode 3 Entry With

2AF 01

PB Unavailable; Revision 0 -

AA -600-1042; On-Line Risk Management; Revision 4 - Protected Equipment List; 2B

AFW Pump Unavailable During Mode 3 Entry; May 15, 2008 -

WO 1135330-05; Troubleshoot 2E Main Power Transformer Transfer Circiut -

IR 775470; 2B

AFW Pump did not Start While Performing Testing; May 14, 2008

-

IR 775798; 2B

AFW Pump Gear Box Auxiliary Lube Oil Pump did not Shut Off; May 15, 2008 -

IR 776054; 3.0.4.B Risk Assessment - 2

AF [[01PB Wrong Revision Referenced; May 15, 2008 [NRC-Identified] -]]

IR 776288; Bolting Issue with 2B

AFW Pump Gear Driven New Pump, May 16, 2008 -

IR 776728; 2E Main Power Transformer Cooling Fans Will Not Auto-Transfer; May 16, 2008 Section 1R15: Operability Evaluations - Bw

AP 2200-2; Shutdown Safety Contingency Plan for the Reactor Head Reassembly Sequence; Revision 0 - 1BwEP-0 Reactor Trip or Safety Injection Unit 1; Revision 2 - BwMP 3300-005; Primary Containment Equipment Hatch Removal and Installation; Revision 5

- 2BwOA

PRI -10; Loss of

RH Cooling Unit 2; Revision 102 - 2BwOS

XPC -W1; Unit 2 Containment Penetration Status Weekly Surveillance; Revision 15 -

ER-AA-1200; Critical Component Failure Clock; Revision 4 - Shaw A2R13 Containment Closure Plan; April 24, 2008 - EC 369245; Auxiliary Feedwater Tunnel Flood Seal Cover Modification, Unit 1; Revision 0

- Design Analysis 5.6.3-BRW-08-0045-S; Structural Evaluation of the Flood Seal Cover Support in the Main Steam Isolation Valve Rooms, Unit 1, Per

EC 369245; Revision 0 -

IR 620080 (Byron); Auxiliary Feedwater Tunnel Cover Bolt Uses Non-Standard Safety Factor; April 21, 2007 - IR 623323 (Byron); Request Permission to Look For Problem; April 30, 2007

-

IR 629677 (Byron); Difference in Professional Opinion on Jet Impingement; May 15, 2007 -

IR 653093 (Byron); The Auxiliary Feedwater Tunnel Covers do not Meet Expected Safety Factors (July 24, 2007 -

IR 654270; Auxiliary Feedwater Tunnel Cover Bolt Evaluation Uses Non-Standard Safety Factors; July 26, 2007 -

IR 759038;

0VC 21

YC Damper Does not open when required; April 3, 2008 -

IR 759803 1

CS01PA-M Lower Motor Oil Reservoir Shows Low oil; April 6, 2008

-

IR 762106; 1

SX 169A Failed to Open when 1A D/G was Started -

IR 763028 1A

CS Add Flow Surveillance invalid- Test Gauge Failed Post Cal; April 14, 2008

Attachment -

IR 763179 1

CS 021A- U1

TR A

CS Spray Add Flow Test As-Found Unsat; April 14, 2008 -

IR 764362; Small Oil Leak on 2

CV [[01PA; April 17, 2008 [IEMA-Identified} -]]

IR 764527 (Byron); Unit 1 Auxiliary Feedwater Tunnel Cover Modification -

WO Needs Research; April 17, 2008 -

IR 772939;

NRC [[Identified Enhancement for A2R13 Containment Closure Plan; May 7, 2008 [NRC-Identified] -]]

IR [[780531; Confusion Regarding Traceability of Past Operability Determinations; May 29, 2008 []]

IEMA [[-Identified] -]]

IR [[783849; Load Factor Not Used For Evaluation of Auxiliary Feedwater Tunnel Cover; June 6, 2008 []]

NRC [[-Identified] Section 1R19: Post Maintenance Testing - BwOP]]

FW -1; Start up of a Turbine Driven Main Feedwater Pump ;Revision 27 - 2Bw

OS [[]]

DG -2B; 2B Diesel Generator Overspeed Trip Test; Revision 2 - 2Bw

OSR 3.8.1.2-2; Unit 2 2B Diesel Generator Operability Surveillance; Revision 21 - BwVSR 900-35; Diesel Generator Governor Set-Up Following Governor Replacement; Revision 6 - 2BwVSR 5.5.8.SX.2

ASME Surveillance Requirements for 2B Essential Service Water Pump; Revision 7 -

IR 771344;

2DG 01

KB - A Lube Oil Pump Trips on Thermals; May 3, 2008 -

IR 771613; 2B

DG - No Lube Oil Pressure After Start; May 4, 2008 -

IR 771646; 2B

DG Lube Oil Pressure; May 5, 2008 -

IR 772525; 2B

DG Electronic Governor did not Control; May 6, 2008 -

IR 773044; 2B

DG Turbocharger Oil Pressure Requires Adjustment; May 8, 2008

-

IR 771363; Moderate Corrosion Found on 2B

SX [[]]

PP Suction Piping; May 3, 2008 -

IR 772055; Minor Corrosion Identified on Piping Associated with

2SX 001B; May 5, 2008 -

IR 774321;

2SX 01

PB Suction Flange Torque Incorrect in

WO ; May 11, 2008 -

IR 774334; Minor Oil and Water Leaks on 2B

SX Pump; May 11, 2008 -

IR 782115; Poor Coordination of Heater Drain Pump Post Maintenance Test; June 2, 2008

-

IR 782163 2B

FW [[]]

PP Oil Pressure Up Light Anomaly- 2

FW 01PB-A; June 2, 2008 -

IR 782558; Evaluate the 2C Heater Drain Pump Return to Service Process; June 3, 2008 -

IR 788991;

1FW 039A Exceeds Operability Stroke Time; June 21, 2008 -

MA -AA-716-004; Attachment 1 Troubleshooting Log; Revision 6 -

AA -114; 1BwOSR 3.6.3.5.FW-3, Low Low Feedwater Isolation Valve

AA-716-004; Attachment 1 Troubleshooting Log; Revision 7

-

WC -

1FW 039 Valve Stroke Surveillance; Revision 16 -

WO 113913;

2BMFP Stop Valve -

WO [[]]

436515 MM -

SX Pump/Motor Replacement; April 21, 2008 Section 1R20: Outage Activities - 2BwGP 100-2; Plant Startup; Revision 23 - 2BwGP 100-3; Power Ascension 5 Percent to 100 Percent; Revision 44 - 2BwGP 100-4; Power Descension; Revision 26 - 2BwGP 100-5; Plant Shutdown and Cooldown; Revision 31 - BwVS 500-6; Low Power Physics Test Program - A2R13 Shutdown Safety Management Plan; Revision 0 - A2R13 Containment Load Path Risk Assessment; Revision 0

- A2R13 Containment Atmosphere Management Plan; Revision 0

Attachment - Operating Experience Smart Sample

FY 2007-03; Crane and Heavy Lift Inspection, Supplemental Guidance for

IP -71111.20; Revision 1 -

IR 779213; A2R13 In-Mast Sipping Identified Two Leaking Fuel Assemblies; May 1, 2008 -

IR 770869;

IEMA [[Identified Issues With Risk Colors on Unit 2; May 2, 2008 {]]

IEMA [[-Identified] -]]

IR [[772605; 2B Tendon Tunnel Sump Pump Discharge Flange Leak; May 7, 2008 []]

NRC [[-Identified] -]]

IR [[772453; Primary Containment Tendon End Cover V320 Grease Leakage; May 6, 2008 []]

NRC [[-Identified] Section 1R22: Surveillance Testing - BwOP]]

PC -1; Local Leak Rate Flowmeter Monitor Operation; Revision 12 - Bw

OP DG-12; Diesel Generator Shutdown; Revision 24

- BwOP

DG -11; Diesel Generator Startup; Revision 34 - Bw

OP [[]]

RH -5;

RH system Startup for Recirculation; Revision 20 - 1BwOSR 3.6.2.1-4; Unit One Primary Containment Type B Local Leakage Rate Test of the Emergency Hatch Airlock Door Gasket Interspaces; Revision 8 - 1BwOSR 3.7.5.4-2; U1 Diesel Driven Auxiliary Feedwater Pump Surveillance; Revision 14 - 1BwOSR 3.8.1.2-1; Unit One 1A Diesel Generator Operability Surveillance; Revision 23 - 1BwOSR 3.8.1.13-2; Diesel Generator Bypass of Automatic Trip Surveillances; Revision 7

- 1BwOSR 3.8.1.13-2; 1B Diesel Generator Bypass of Automatic Trip Surveillance; Revision 7 - BwVSR 3.7.1.1; Main Steam Safety Valves Operability Test; Revision 5 - 1BwVSR 5.5.8.AF.2; U1 Diesel Driven Auxiliary Feedwater Pump

ASME Quarterly Surveillance; Revision 12 - 2Bw

VSR 5.5.8.RH.2;

ASME Surveillance Requirements for Residual Heat Removal Pump 2

RH 01PB; Revision 7 - BwMP 3305-107; Main Steam Safety Valves Lift Point Verification Using the Furmanite Trevitest System; Revision 13 -

IR 726426; 2B

RH Recirc flow Below the Acceptance Criteria; January 24, 2008 -

IR 762106; 1

SX 169A Failed to Open When 1A Diesel Generator Was Started; April 11, 2008 -

IR 762445; 1A Diesel Generator Failed to Run for 5 Minutes in Cooldown; April 11, 2008 -

IR [[763170; Potential Local Leak Rate Test Issue on Emergency Hatch Surveillance; April 14, 2008 [NRC-Identified] -]]

IR 777831; 1B D/G Running Without being Able to Use Proper

VC Alignment; May 20, 2008 -

IR 787525; 1B

AFW Pump Maintenance run Results -

1AF 01

PB; June 18, 2008

-

WO 9629213; Main Steam Safety Valves Operability Test -

WO 1122729 01; September

ASME Surveillance Requirement for 2B Residual Heat Removal Pump; June 25, 2008 Section 2

OS 1: Access Control to Radiologically Significant Areas -

IR 760253; Detector Maximum Dose Rate in

UFSAR Higher Than Seen in; A1R13; April 7, 2008 -

IR 767338; Hydrogen Alarms Occurring in Unit 2 Containment Cause Delays; April 24, 2008 -

RP -AA-376; Radiological Postings, Labeling, and Markings; Revision 2 -