IR 05000254/2011004

IR 05000254-11-004, 05000265-11-004, on 07/01/11 - 09/30/11, Quad Cities Nuclear Power Station, Units 1 & 2, Equipment Alignment, Plant Modifications, and Other Activities

ML11305A175
Person / Time
Site:	Quad Cities
Issue date:	11/01/2011
From:	Ring M NRC/RGN-III/DRP/B1
To:	Pacilio M Exelon Generation Co, Exelon Nuclear
References
IR-11-004
Download: ML11305A175 (56)

Text

vember 1, 2011

SUBJECT:

QUAD CITIES NUCLEAR POWER STATION, UNITS 1 AND 2, NRC INTEGRATED INSPECTION REPORT 05000254/2011004; 05000265/2011004

Dear Mr. Pacilio:

On September 30, 2011, the U.S. Nuclear Regulatory Commission (NRC) completed an integrated inspection at your Quad Cities Nuclear Power Station, Units 1 and 2. The enclosed report documents the results of this inspection, which were discussed on October 4, 2011, with Mr. M. Prospero, and other members of your staff.

The inspection examined activities conducted under your license as they relate to safety and compliance with the Commissions rules and regulations and with the conditions of your license.

The inspectors reviewed selected procedures and records, observed activities, and interviewed personnel.

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

Additionally, a licensee-identified violation is listed in Section 4OA7 of this report.

If you contest the subject or severity of these NCVs, you should provide a response within 30 days of the date of this inspection report, with the basis for your denial, to the U.S. Nuclear Regulatory Commission, ATTN: Document Control Desk, Washington, DC 20555-0001, with a copy to the Regional Administrator, U.S. Nuclear Regulatory Commission - Region III, 2443 Warrenville Road, Suite 210, Lisle, IL 60532-4352; the Director, Office of Enforcement, U.S. Nuclear Regulatory Commission, Washington, DC 20555-0001; and the Resident Inspector Office at the Quad Cities Nuclear Power Station. In addition, if you disagree with the cross-cutting aspect assigned to any finding in this report, you should provide a response within 30 days of the date of this inspection report, with the basis for your disagreement, to the Regional Administrator, Region III, and the NRC Resident Inspector at the Quad Cities Nuclear Power Station. In accordance with 10 CFR 2.390 of the NRC's "Rules of Practice," a copy of this letter, its enclosure, and your response (if any) will be available electronically for public inspection in the NRC Public Document Room or from the Publicly Available Records System (PARS)

component of NRC's document system (ADAMS). ADAMS is accessible from the NRC Website at http://www.nrc.gov/reading-rm/adams.html (the Public Electronic Reading Room).

Sincerely,

/RA/

Mark A. Ring, Chief Branch 1 Division of Reactor Projects Docket Nos. 50-254; 50-265;72-053 License Nos. DPR-29; DPR-30

Enclosure:

Inspection Report 05000254/2011004; 05000265/2011004 w/Attachment: Supplemental Information

REGION III==

Docket Nos: 50-254; 50-265;72-053 License Nos: DPR-29; DPR-30 Report No: 05000254/2011004 and 05000265/2011004 Licensee: Exelon Generation Company, LLC Facility: Quad Cities Nuclear Power Station, Units 1 and 2 Location: Cordova, IL Dates: July 1 through September 30, 2011 Inspectors: J. McGhee, Senior Resident Inspector B. Cushman, Resident Inspector A. Dahbur, Senior Reactor Inspector R. Edwards, Reactor Inspector M. Mitchell, Health Physicist M. Munir, Reactor Inspector M. Phalen, Senior Health Physicist L. Rodriguez, Reactor Engineer C. Mathews, Illinois Emergency Management Agency Approved by: Mark Ring, Chief Branch 1 Division of Reactor Projects Enclosure

SUMMARY OF FINDINGS

IR 05000254/2011004, 05000265/2011004; 07/01/11 - 09/30/11; Quad Cities Nuclear Power

Station, Units 1 & 2; Equipment Alignment, Plant Modifications, and Other Activities.

This report covers a 3-month period of inspection by resident inspectors and announced inspections by regional inspectors. In addition to baseline inspections performed this quarter, an operating phase inspection of the independent spent fuel storage installation was conducted, and an engineering review of Unresolved Item 05000254/2000016-04; 05000265/2000016-04,

Associated Circuits Issue, was performed. Four Green findings were identified by the inspectors. Three of the findings were considered non-cited violations (NCVs) of NRC regulations. The significance of most findings is indicated by their color (Green, White, Yellow,

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

Revision 4, dated December 2006.

NRC-Identified

and Self-Revealed Findings

Cornerstone: Initiating Events

Green.

A self-revealed finding of very low safety significance with an associated NCV of Technical Specification (TS) 5.4.1.a was identified for failure to properly track the abnormal position of the waste sample tanks or floor drain sample tanks to waste collector tank valve, 1/2-2001-54. On August 12, 2011, an operator failed to position the valve in accordance with the operating procedure and did not follow station administrative procedures for tracking components that deviate from expected position.

On August 17, a second operator transferred contaminated water to an unintended tank because of this deviation. This issue has been entered into the licensees corrective action program as Issue Report (IR) 1252370. The 1/2-2001-54 valve was shut immediately on discovery to stop water transfer.

The performance deficiency was more than minor since it can reasonably be viewed as a precursor to a more significant event because mispositioned components could reasonably be expected to result in liquid spills or significant personnel exposure.

This performance deficiency also adversely affected the Initiating Events Cornerstone objective to limit the likelihood of those events that upset plant stability and challenge critical safety functions in that a large, uncontrolled spread of contamination as a result of a mispositioned valve in the liquid radioactive waste system would impact access to plant areas and would complicate operator response. Using IMC 0609, Table 4a, under the Initiating Events Cornerstone, all questions were answered No. This issue was screened as Green, or very low safety significance. Inspectors concluded that this issue had a cross-cutting aspect in the area of Human Performance - Decision Making.

The operator made a decision outside his authority, in that, senior reactor operator approval is required to leave the 1/2-2001-54 valve open and the operator did not engage supervision to obtain that authorization (H.1(a)). (Section 1R04.1.b(2))

Green.

NRC inspectors identified a finding of very low safety significance when analysis performed for installation of a small bore instrument sensing line modification for Unit 1 main turbine thermal performance testing did not include all applicable stresses as required by the USA Standards B31.1.0-1967 Code. On June 13, 2011, that line failed, resulting in an emergency downpower and reactor scram. The issue was incorporated into the corrective action program (CAP) as IR 1227884. Immediate corrective actions removed the leaking sensing lines on Unit 1 and permanently plugged the pipe penetrations.

The performance deficiency was more than minor because it affected the Initiating Events Cornerstone objective to limit the likelihood of those events that upset plant stability and challenge critical safety functions during power operations as described in IMC 0612, Appendix B. The key attribute impacted was design control for plant modifications. The inspectors performed a SDP phase 1 screening for the finding using IMC 0609, Table 4a, and answered all of the questions No. Therefore, the finding screened as very low safety significance, or

Green.

Inspectors determined that a significant contributor to this finding was the failure of the individual and supervisor performing the acceptance review of the contractor generated modification to engage the appropriate engineering expertise to evaluate the adequacy of the modification design before the modification was implemented. As a result, inspectors identified this issue as cross-cutting in the area of Human Performance - Work Practices in that the licensee did not ensure supervisory and management oversight of work activities, including contractors, such that nuclear safety was supported (H.4(c)). (Section 1R18)

Cornerstone: Mitigating Systems

Green.

A self-revealed finding of very low safety significance with an associated NCV of 10 CFR 50, Appendix B, Criterion V, Instructions, Procedures, and Drawings, was identified when a service water leak occurred on the Unit 1 emergency diesel generator cooling water pump cubicle cooler on April 19, 2011. Inspectors determined that the licensees failure to identify wall thinning resulting from areas of excessive corrosion within the coolers safety-related service water piping during periodic heat exchanger inspections was not in compliance with the licensees program requirements and was a performance deficiency. The issue was entered into the CAP as IR 1204785.

Immediate corrective actions included repair of the hole in the piping, completion of an engineering assessment of other areas of the piping that were identified as below the minimum wall thickness, and performing extent of condition walkdowns of similar coolers.

Inspectors concluded that the performance deficiency was more than minor using the questions in IMC 0612, Appendix B, because the Mitigating Systems Cornerstone objective of ensuring availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences, and equipment operability were impacted by the resulting leakage. The inspectors performed a SDP phase 1 screening for the finding using IMC 0609, Table 4a, and answered all of the questions No.

The finding screened as very low safety significance, or

Green.

Inspectors did not assign a cross-cutting aspect because the licensee had suspended use of the deficient inspection procedure in December 2010 and had not performed any inspections in the past three years. (Section 4OA3.2)

Cornerstone: Public Radiation Safety

Green.

An NRC-identified finding of very low safety significance with an associated NCV of 10 CFR 20.1302 was identified for failure to take action to prevent a potential unmonitored release on August 3, 2011, when the turbine building differential pressure indicated positive on the building differential pressure indication in the main control room. This issue was entered into the licensees corrective action program as IR 1247501. Immediate corrective action included determination that the turbine building was still at a negative differential pressure and no unmonitored release path existed.

The performance deficiency was more than minor because it adversely affected the Public Radiation Safety Cornerstone objective to ensure adequate protection of public health and safety from exposure to radioactive materials released into the public domain as a result of routine civilian nuclear reactor operation. Failure to perform surveys when indicated conditions warrant increases the possibility that an unmonitored release could occur. Using IMC 0609, Appendix D, Public Radiation Safety Significance Determination Process, radioactive material control program flowchart, there was no public exposure, and this finding was screened as Green, or very low safety significance.

The inspectors identified that this finding had a cross-cutting aspect in the area of Human Performance - Work Practices because operators failed to follow the steps of the annunciator response procedure (H.4(b)). (Section 1R04.1.b(1))

Licensee-Identified Violations

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

REPORT DETAILS

Summary of Plant Status

Unit 1 Unit 1 operated at 100 percent thermal power throughout the evaluated period from July 1 through September 30, 2011, with the exception of planned power reductions for routine surveillances, main condenser flow reversals, planned equipment repair, and control rod maneuvers.

Unit 2 Unit 2 operated at 100 percent thermal power throughout the evaluated period from July 1 through September 30, 2011, with the exception of planned power reductions for routine surveillances, main condenser flow reversals, planned equipment repair, and control rod maneuvers.

REACTOR SAFETY

Cornerstones: Initiating Events, Mitigating Systems, and Barrier Integrity

1R04 Equipment Alignment

.1 Quarterly Partial System Walkdowns

a. Inspection Scope

The inspectors performed partial system walkdowns of the following risk significant systems:

• Unit 2 reactor core isolation cooling;

• Unit 2B core spray; and

• Unit 1 turbine building ventilation.

The inspectors selected these systems based on their risk significance relative to the Reactor Safety Cornerstones at the time they were inspected. The inspectors attempted to identify any discrepancies that could impact the function of the system and, therefore, potentially increase risk. The inspectors reviewed applicable operating procedures, system diagrams, Updated Final Safety Analysis Report (UFSAR), Technical Specification (TS) requirements, outstanding work orders (WOs), condition reports, and the impact of ongoing work activities on redundant trains of equipment in order to identify conditions that could have rendered the systems incapable of performing their intended functions. The inspectors also walked down accessible portions of the systems to verify system components and support equipment were aligned correctly and operable.

The inspectors examined the material condition of the components and observed operating parameters of equipment to verify that there were no obvious deficiencies.

The inspectors also verified that the licensee had properly identified and resolved equipment alignment problems that could cause initiating events or impact the capability of mitigating systems or barriers and entered them into the corrective action program (CAP) with the appropriate significance characterization. Documents reviewed are listed in the Attachment to this report.

These activities constituted three partial system walkdowns sample as defined in Inspection Procedure (IP) 71111.04-05.

b. Findings

(1) Turbine Building Differential Pressure Indicating Positive

Introduction:

An NRC-identified finding of very low safety significance (Green) with an associated non-cited violation (NCV) of 10 CFR 20.1302 was identified for failure to take action to prevent a potential unmonitored release on August 3, 2011, when the turbine building differential pressure indicated positive on the building differential pressure indication in the main control room.

Description:

During the week of August 1, 2011, hot weather was present in the Quad Cities area. In an effort to maintain cooler temperatures in the emergency diesel generator rooms located in the turbine building, operators turned on the emergency diesel generator room vent fan during the early morning to cool off the room. The vent fan was then turned off before the mid-day heat to prevent hot air from being pulled into the room and negating the cooling accomplished earlier in the morning.

Ventilation in the shared turbine building was operated to maintain the building at negative pressure with respect to atmospheric pressure so that if there was any open leak path, the direction of air flow would be into the building. Each time the diesel room vent fan was started, an annunciator was received in the main control room for Unit 1 turbine building low differential pressure. At the same time, the indication in the main control room showed that the turbine building was at a positive pressure.

Immediate actions in the annunciator response procedure, QOA 912-5 C-2, for this alarm, state, in part:

Notify Radiation Protection (RP) Supervision to discuss corrective actions, expected duration and instruct RP to:

a. Ensure Cams are operating at Trackways 1 and 2, or take air samples.

b. Evaluate ongoing work that may need to be stopped/altered because of positive pressure condition in the Turbine Building.

Operators determined that the low differential pressure in the turbine building was an expected condition with the vent fan running. The annunciator response procedure was exited with no further actions taken. Radiation Protection supervision was not contacted by Operations to perform actions as described in the annunciator response procedure.

On August 3, 2011, inspectors questioned the Unit 2 unit supervisor about the lit annunciator for the turbine building low differential pressure. The unit supervisor informed the inspectors that the turbine building low differential pressure would be expected because the Unit 2 emergency diesel vent fan was running. The inspectors verified that the operators had not notified RP that the alarm had activated or that building pressure indicated positive.

After the inspectors questioned the alarm, an operations supervisor and an RP technician went to the Unit 1 trackway to investigate if a potential unmonitored release path was present. The technician verified air was still coming into the building.

This confirmed that the turbine building was still at a negative differential pressure and no potential release path existed with the emergency diesel vent fan running and the slightly positive differential pressure indication in the main control room.

Analysis:

The inspectors concluded the failure to take action to prevent a potential unmonitored release or verify that an unmonitored release path did not exist when a positive building pressure was indicated was a performance deficiency and a finding.

The performance deficiency was more than minor because it adversely affected the Public Radiation Safety Cornerstone objective to ensure adequate protection of public health and safety from exposure to radioactive materials released into the public domain as a result of routine civilian nuclear reactor operation. In this circumstance, the Program and Process Attribute of the cornerstone was adversely affected if surveys and actions to mitigate the event are not promptly implemented.

Using Inspection Manual Chapter (IMC) 0609, Appendix D, Public Radiation Safety Significance Determination Process, Radioactive Material Control Program Flowchart, inspectors determined that, since there was no public exposure, this finding was screened as Green, or very low safety significance.

The inspectors identified that this finding has a cross-cutting aspect in the area of Human Performance - Work Practices because operators failed to follow the steps of the annunciator response procedure (H.4(b)).

Enforcement:

Title 10 CFR 20.1302(a) requires, in part, that the licensee shall make or cause to be made, as appropriate, surveys of radiation levels in effluents released to unrestricted areas to demonstrate compliance with the dose limits for individual members of the public.

Contrary to the above, on August 3, 2011, the licensee failed to perform surveys or take other action to identify a potential unmonitored release or verify an unmonitored release path did not exist when the turbine building differential pressure indicated positive when read from the main control room. The licensee did not recognize the potential impact of these conditions and would have continued to operate under these conditions without the intervention of the inspectors. Because this violation was determined to be of very low safety significance, and this issue was entered into the licensees corrective action program as Issue Report (IR) 1247501, this violation is being treated as an NCV consistent with Section 2.3.2 of the NRC Enforcement Policy (NCV 05000254/2011004-01; 05000265/2011004-01, Turbine Building Differential Pressure Indicating Positive). Immediate corrective action included determination the turbine building was still at a negative differential pressure and no unmonitored release path existed.

(2) Valve Out of Position in Radwaste

Introduction:

A self-revealed finding of very low safety significance (Green) and associated NCV of TS 5.4.1.a was identified for the licensees failure to track the abnormal position of the waste sample tanks or floor drain sample tanks to waste collector tank valve, 1/2-2001-54, on August 12, 2011, in accordance with station procedures, resulting in transfer of contaminated water to an unintended location.

Description:

On August 17, 2011, the radwaste equipment operator (EO) was making preparations to transfer water from the B floor drain sample tank to the contaminated condensate storage tanks. Per procedure QOP 2010-19, Pumping A or B Floor Drain Sample Tank to Contaminated Storage Tanks, the EO verified the valve checklist was complete in the radwaste control room. After starting the transfer, the EO and operations field supervisor verified the B floor drain sample tank was lowering as expected. A corresponding rise in level of the contaminated condensate storage tanks was not immediately verifiable because of the much greater volume of those tanks.

Shortly after starting the water transfer, the EO identified that the waste collector tank (another water collection tank in the liquid radwaste system) was rising unexpectedly.

When the EO went to investigate, he found the 1/2-2001-54 valve open. This valve directs flow from the waste sample tanks or floor drain sample tanks to the waste collector tank and should not have been open for the transfer to the contaminated condensate storage tanks. The 1/2-2001-54 valve was closed, stopping water flow to the waste collector tank.

The 1/2-2001-54 valve was last manipulated on August 12, 2011, during performance of QOP 2010-20, Pumping A/B Floor Drain Sample Tank to the Waste Collector Tank, to pump water from a floor drain sample tank to the waste collector tank. Step F.14 of QOP 2010-20 directs closure of the 1/2-2001-54 valve after the transfer is complete.

Because the level of total organic carbon in the water made the water unacceptable to be transferred to the contaminated condensate storage tanks, this water was transferred back to the waste collector tank for reprocessing. The EO responsible for this transfer decided to leave the 1/2- 2001-54 valve open because the valve was located in a high radiation area and he perceived it to be highly likely that the next tank he processed would again have to be reprocessed due to organics. He reasoned that leaving the valve open would be a dose savings and would be the appropriate action. The EO did not request authorization from his supervisor to deviate from the procedure or initiate other authorized methods of tracking position for the valve. The EO did not place QOP 2010-20 in the procedure-in-progress book in the radwaste control room per OP-QC-108-1002, Procedures in Progress Book Guidance, or initiate an abnormal component position sheet per OP-AA-108-101, Control of Equipment and System Status, to track the position of the valve. As a result, when the operators transferred water the next time, five days later, the water went to an unintended tank.

Analysis:

The inspectors concluded that the failure to track the position of the 1/2-2001-54 valve in accordance with station procedures was a performance deficiency and a finding. The performance deficiency was more than minor because it could reasonably be viewed as a precursor to a more significant event because mispositioned components could reasonably be expected to result in contaminated liquid spills or significant personnel exposure. This performance deficiency also adversely affected the Initiating Events Cornerstone objective to limit the likelihood of those events that upset plant stability and challenge critical safety functions in that a large, uncontrolled spread of contamination as a result of a mispositioned valve in radwaste would impact access to plant areas and complicate operator response.

The inspectors performed a Significance Determination Process (SDP) phase 1 screening for the finding using IMC 0609, Table 4a, and answered the questions under the Initiating Events Cornerstone No. Therefore, the finding screened as very low safety significance, or Green.

Inspectors determined that a significant contributor to this finding was the failure of the individual performing the task to engage the appropriate supervisor and obtain approval for leaving the valve open. Approval of a supervisor (senior reactor operator licensed individual) was required to allow the EO to deviate from the written procedure and implement alternate position tracking tools. As a result, inspectors identified that this issue had a cross-cutting aspect in the area of Human Performance - Decision Making.

The EO made a decision outside his authority, in that, senior reactor operator approval is required to leave the 1/2-2001-54 valve open and the operator did not engage supervision to obtain that authorization (H.1(a)).

Enforcement:

Technical Specifications 5.4.1.a required that written procedures be established, implemented, and maintained covering the applicable procedures recommended in Regulatory Guide 1.33, Quality Assurance Program Requirements (Operation).

Regulatory Guide 1.33, Appendix A, Section 7, Procedures for Control of Radioactivity, listed the liquid radioactive waste system as one of the specified procedures.

At Quad Cities, QOP 2010-20, Pumping A/B Floor Drain Sample Tank to the Waste Collector Tank, performed that function in this instance.

Contrary to the above, on August 12, 2011, the licensee failed to implement QOP 2010-20 as written and shut the 1/2-2001-54 valve, or initiate the appropriate administrative measures to track the abnormal position of the valve allowed by station procedure. Because this violation was determined to be of very low safety significance, and this issue has been entered into the licensees corrective action program as IR 1252370, this violation is being treated as an NCV consistent with Section 2.3.2 of the NRC Enforcement Policy (NCV 05000254/2011004-02; 05000265/2011004-02, Valve Out of Position in Radwaste). Immediate corrective action was to shut the 1/2-2001-54 valve to stop water flow to the waste collector tank.

.2 Semi-Annual Complete System Walkdown

a. Inspection Scope

On September 1, 2011, the inspectors performed a complete system alignment inspection of the safe shutdown makeup pump system to verify the functional capability of the system. This system was selected because it was considered both safety significant and risk significant in the licensees probabilistic risk assessment.

The inspectors walked down the system to review mechanical and electrical equipment lineups; electrical power availability; system pressure and temperature indications, as appropriate; component labeling; component lubrication; component and equipment cooling; hangers and supports; operability of support systems; and to ensure that ancillary equipment or debris did not interfere with equipment operation. A review of a sample of past and outstanding work orders was performed to determine whether any deficiencies significantly affected the system function. In addition, the inspectors reviewed the CAP database to ensure that system equipment alignment problems were being identified and appropriately resolved. Documents reviewed are listed in the to this report.

These activities constituted one complete system walkdown sample as defined in IP 71111.04-05.

b. Findings

No findings were identified.

1R05 Fire Protection

.1 Routine Resident Inspector Tours

a. Inspection Scope

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

• Fire Zone 8.2.8.B, Unit 1/2 Turbine Building, Elevation 639-0," 480V SWGR, 18/19 4kV SWGR, 13-1 MG Set 1A;

• Fire Zone 1.1.1.5.A, Unit 1/2 Turbine Building, Elevation 658-0, 4kV SWGR, 13-1/24-1;

• Fire Zone 1.1.1.6.A, Unit 1/2 Turbine Building, Elevation 678-0,"

Reactor Building Vent Floor;

• Fire Zone 8.2.4, Unit 1 Turbine Building, Elevation 580-0," Cable Tunnel; and

• Fire Zone 8.2.5, Unit 1/2 Turbine Building, Elevation 580-0," Unit 2 Cable Tunnel.

The inspectors reviewed areas to assess if the licensee had implemented a fire protection program that adequately controlled combustibles and ignition sources within the plant, effectively maintained fire detection and suppression capability, maintained passive fire protection features in good material condition, and implemented adequate compensatory measures for out-of-service, degraded or inoperable fire protection equipment, systems, or features in accordance with the licensees fire plan.

The inspectors selected fire areas based on their overall contribution to internal fire risk as documented in the plants Individual Plant Examination of External Events with later additional insights, their potential to impact equipment which could initiate or mitigate a plant transient, or their impact on the plants ability to respond to a security event.

Using the documents listed in the Attachment to this report, the inspectors verified that fire hoses and extinguishers were in their designated locations and available for immediate use; that fire detectors and sprinklers were unobstructed; that transient material loading was within the analyzed limits; and fire doors, dampers, and penetration seals appeared to be in satisfactory condition. The inspectors also verified that minor issues identified during the inspection were entered into the licensees CAP. Documents reviewed are listed in the Attachment to this report.

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

b. Findings

No findings were identified.

.2 Annual Fire Protection Drill Observation

a. Inspection Scope

On August 10, 2011, the inspectors observed fire brigade activation for a fire in MCC 19-3. Based on this observation, the inspectors evaluated the readiness of the plant fire brigade to fight fires. The inspectors verified that the licensee staff identified deficiencies, openly discussed them in a self-critical manner at the drill debrief, and took appropriate corrective actions. Specific attributes evaluated were:

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

• proper use and layout of fire hoses;

• employment of appropriate fire fighting techniques;

• sufficient firefighting equipment brought to the scene;

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

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

• smoke removal operations;

• utilization of pre-planned strategies;

• adherence to the pre-planned drill scenario; and

• drill objectives.

Documents reviewed are listed in the Attachment to this report.

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

b. Findings

No findings were identified.

1R06 Flooding

.1 Underground Vaults

a. Inspection Scope

The inspectors selected underground bunkers/manholes subject to flooding that contained cables whose failure could disable risk-significant equipment. The inspectors determined that the appropriate cable support structures were in place. In those areas without dewatering devices, the inspectors verified that drainage of the area was available, or that the cables were qualified for submergence conditions. The inspectors also reviewed the licensees corrective action documents with respect to past submerged cable issues identified in the corrective action program to verify the adequacy of the corrective actions. The inspectors performed a maintenance review for the following underground bunkers/manholes subject to flooding:

• Manholes #3 and #4 containing switchyard control power cables.

This inspection constituted one underground vaults sample as defined in IP 71111.06-05.

b. Findings

No findings were identified.

1R11 Licensed Operator Requalification Program

.1 Resident Inspector Quarterly Review

a. Inspection Scope

On August 15, 2011, the inspectors observed a crew of licensed operators in the plants simulator during licensed operator requalification examinations to verify that operator performance was adequate, evaluators were identifying and documenting crew performance problems, and training was being conducted in accordance with licensee procedures. The inspectors evaluated the following areas:

• licensed operator performance;

• crews clarity and formality of communications;

• ability to take timely actions in the conservative direction;

• prioritization, interpretation, and verification of annunciator alarms;

• correct use and implementation of abnormal and emergency procedures;

• control board manipulations;

• oversight and direction from supervisors; and

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

The crews performance in these areas was compared to pre-established operator action expectations and successful critical task completion requirements. Documents reviewed are listed in the Attachment to this report.

This inspection constituted one quarterly licensed operator requalification program sample as defined in IP 71111.11.

b. Findings

No findings were identified.

1R12 Maintenance Effectiveness

.1 Routine Quarterly Evaluations

a. Inspection Scope

The inspectors evaluated degraded performance issues involving the following risk-significant systems:

• Z3000: Main Steam, and

• Z5711: Room Coolers.

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 are listed in the Attachment to this report.

This inspection constituted two quarterly maintenance effectiveness samples as defined in IP 71111.12-05.

b. Findings

No findings were identified.

1R13 Maintenance Risk Assessments and Emergent Work Control

.1 Maintenance Risk Assessments and Emergent Work Control

a. Inspection Scope

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

• Work Week (11-35-10): 1D residual heat removal service water (RHRSW)pump LP elbow replacement, 1-1001-36B division II torus cooling suction valve, U1 emergency diesel generator (EDG) inoperable for monthly surveillance; and

• Work Week (11-38-13): 2A RHRSW pump LP elbow replacement, 2B residual heat removal (RHR) pump seal replacement, 2-1001-16A A residual heat removal heat exchanger (RHRHX) bypass valve, 2-1001-18A A loop minimum flow valve, 2-1001-5A RHRHX service water discharge valve.

These activities were selected based on their potential risk significance relative to the Reactor Safety Cornerstones. As applicable for each activity, the inspectors verified that risk assessments were performed as required by 10 CFR 50.65(a)(4) and were accurate and complete. When emergent work was performed, the inspectors verified that the plant risk was promptly reassessed and managed. The inspectors reviewed the scope of maintenance work, discussed the results of the assessment with the licensee's probabilistic risk analyst or shift technical advisor, and verified plant conditions were consistent with the risk assessment. The inspectors also reviewed TS requirements and walked down portions of redundant safety systems, when applicable, to verify risk analysis assumptions were valid and applicable requirements were met.

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

b. Findings

No findings were identified.

1R15 Operability Evaluations

.1 Operability Evaluations

a. Inspection Scope

The inspectors reviewed the following issues:

• Engineering Change (EC) 384132: Minimum Wall Thickness for Unit 1 DGCW Cubicle Cooler 2 Header Line (IR 1205479);

• EC 374953: Evaluation of IR 894200 Unlatched 4kV Switchgear Upper Cubicle Doors;

• IR 1239480: Core Spray/RHR Fill System Failure Alarm During QCOS 1400-01;

• ECR 401305: Evaluate the 1A RHRSW Pump Alignment; and

• EC 385654: SC-11-04 Seismic Impact on Fuel Channel Distortion, GE Hitachi 10 CFR Part 21 Issue.

The inspectors selected these potential operability issues based on the risk significance of the associated components and systems. The inspectors evaluated the technical adequacy of the evaluations to ensure that TS operability was properly justified and the subject component or system remained available such that no unrecognized increase in risk occurred. The inspectors compared the operability and design criteria in the appropriate sections of the TS and UFSAR to the licensees evaluations to determine whether the components or systems were operable. Where compensatory measures were required to maintain operability, the inspectors determined whether the measures in place would function as intended and were properly controlled. The inspectors determined, where appropriate, compliance with bounding limitations associated with the evaluations. Additionally, the inspectors reviewed a sampling of corrective action documents to verify that the licensee was identifying and correcting any deficiencies associated with operability evaluations. Documents reviewed are listed in the to this report.

This operability inspection constituted five samples as defined in IP 71111.15-05.

b. Findings

No findings were identified.

1R18 Plant Modifications

.1 Plant Modifications

a. Inspection Scope

The inspectors reviewed the following modification(s):

• EC 385110: Removing Point #6 (1B inboard MSIV pilot valve) from Temperature Recorder 1-5741-130 (Temporary);

• EC 377709: Installation of Permanent Portions of Thermal Performance Test Instrumentation; and

• EC 384874: Use Service Water to Pressurize 1A RHRHX (Residual Heat Removal Heat Exchanger).

The inspectors reviewed the configuration changes and associated 10 CFR 50.59 safety evaluation screening 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(s). The inspectors, as applicable, observed ongoing and completed work activities to ensure that the modifications were installed as directed and consistent with the design control documents; the modifications operated as expected; post-modification testing adequately demonstrated continued system operability, availability, and reliability; and that operation of the modifications did not impact the operability of any interfacing systems. As applicable, the inspectors verified that relevant procedure, design, and licensing documents were properly updated. Lastly, the inspectors discussed the plant modification with operations, engineering, and training personnel to ensure that the individuals were aware of how the operation with the plant modification in place could impact overall plant performance. Documents reviewed in the course of this inspection are listed in the Attachment to this report.

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

b. Findings

Introduction:

NRC inspectors identified a finding of very low safety significance (Green)when analysis performed for installation of a small bore instrument sensing line modification for main turbine thermal performance testing did not include all applicable stresses as required by the USA Standards B31.1.0-1967 Code. The modification was installed in May 2011. On June 13, 2011, that line failed, resulting in an emergency downpower and reactor scram of Unit 1.

Description:

Installation of the pressure instrument sensing line was completed May 20, 2011, during refueling outage Q1R21 within the scope of EC 377709; Installation of Permanent Portions of Thermal Performance Test Instrumentation.

Pressure Transmitters (PTs) 13 and 14 were installed to measure steam pressure downstream of the turbine control valves and upstream of the high pressure turbine.

Instrument taps were installed on the main steam lines downstream of the control valves and stainless steel sock-o-lets were welded to the non-safety related steam piping.

Each instrument's sensing line assembly consisted of an isolation valve, tubing, and a coupling connected to the main steam lines by short pipe stubs welded to the sock-o-lets (creating a cantilevered assembly on the steam pipe.).

The Unit 1 turbine generator was synchronized to the grid on June 9, 2011, at the end of Q1R21. The turbine was tripped a short time later due to the unexpected position of turbine control valve #4. The following morning, June 10, the Unit 1 turbine generator was synchronized to the grid again. Ten minutes later, steam pressure, as indicated by PT 14, dropped. Two minutes later, the pressure indicated by PT 13 also dropped, indicating that both sensing lines had failed and the pressure transmitters were sensing atmospheric pressure. Steam leaks in the low pressure heater bay were reported from the sensing line assemblies.

The tubing for PT 13 failed. This leak was stopped by closing the isolation valve.

The tubing for PT 14 had also failed, but at a different location near a capped connection. The leak on this assembly, however, could not be isolated since the isolation valve itself had failed at a threaded connection between the valve insert and body. Engineering Change 377709 was revised to include a repair method that involved removing the failed sensing line assemblies and welding a new capped pipe stub assembly in each of the existing sock-o-lets. The repair was performed under WO 1445679, and the Unit 1 generator was synchronized to the grid at 1:00 p.m.

The following morning on June 13, 2011, at 04:45 a.m., while Unit 1 was operating at 61 percent power (561 MWe), station personnel reported a large steam leak in the Unit 1 low pressure heater bay near the main turbine control valves. Operators started an emergency load drop and then inserted a manual scram on Unit 1 at 05:10 a.m.

The emergency load drop and subsequent reactor scram are discussed in more detail in Section 4OA3.3 of this report. The leak repair downstream of the #1 control valve failed when the reused sock-o-let ejected the capped stub tube. Post-failure examination of the sock-o-let revealed the failure was due to a previously undetected flaw on the internal diameter of the sock-o-let that ran parallel to the surface prepared for the welds.

When the flaw propagated, the sock-o-let failed and the stub tube was ejected, creating the steam leak. Metallurgists analysis of the failed sock-o-let indicated the flaw was the result of a fatigue-induced crack that propagated when steam pressure was applied.

The plant change was prepared by a contract engineering firm where the process included Electrical, Mechanical and Structural discipline reviews. The owner's acceptance review of the Unit 1 modification was performed by a licensee employee with an instrumentation and controls background, and no additional Exelon Design Engineering discipline reviews were performed.

The owners acceptance review process was used to provide assurance that the product prepared by an external contract design engineering firm was technically adequate, met the plant design and licensing basis, and could be implemented. Guidance for the review was contained in CC-AA-103-1003, Owner's Acceptance Review of External Engineering Technical Products. Step 4.2.1 of the procedure stated, in part, that "Special emphasis should be placed on reviewing critical inputs, assumptions and Engineering judgments." The responsible engineer was expected to provide this assurance, but was not expected to possess all of the knowledge required to complete the review. Additional description of the supervisors role in this process was provided in step 4.7.2.1 of CC-AA-103-1003 and discussed obtaining a supplemental review if additional technical expertise was required.

High cycle fatigue failures caused by flow induced vibration was a known issue at Quad Cities and examples of these failures were included in the licensees root cause analysis. This issue led directly to the failure of the initial instrument line assembly and stub tube leak repair. The licensee concluded that the high cycle vibration induced fatigue concern was not properly evaluated because additional discipline reviews were not performed by Exelon personnel knowledgeable in this area. Specifically, the design consideration summary for EC 377709 contained the general statement:

"Vibration will not be a concern for the new taps and valves because the pipe spools are all short (2"), and the valves are lightweight (under 5 lbs), resulting in a very rigid assembly. As an additional measure, all welds are to be 2:1 welds to keep the stress intensification as low as possible."

This statement was based on engineering judgment and, in the case of the pressure instrument taps in the vicinity of the control valves, was not correct. First, the piping was located in an area where previous high cycle fatigue failures had occurred, and second, the design added a cantilevered assembly to the piping that amplified the effects the vibration. As a result, the change should have been a concern that received a detailed analysis.

In this instance, the responsible engineer did not have the knowledge and experience to determine that the judgment used in this statement was inadequate and he did not obtain a review from anyone at the plant knowledgeable in this field. Quad Cities mechanical design engineering personnel knowledgeable about high cycle fatigue determined that this was an inadequate level of justification for accepting installation of this type of assembly on a steam line. Specific guidance for identification, assessment, testing, and mitigation of piping susceptible to high cycle fatigue was included in mechanical design standard NES-MS-03.04, Small Bore Piping Design for High Cycle Fatigue. Use of this or a similar standard was expected, as a minimum, for this design given the history of high cycle fatigue failures in the immediate vicinity of these connections.

NES-MS-03.04, Small Bore Piping Design for High Cycle Fatigue, stated, in part, that all small bore modifications involving socket-welded connections shall be reviewed for susceptibility to high cycle fatigue from vibration sources and if found susceptible to potential vibration, the design should be assessed or mitigated using the methods provided in the standard. The standard went on to say that all cantilevered connections such as high point vents, low point drains, pressure taps, and instrumentation taps located on or near sources of vibration are particularly susceptible to vibration failure.

Analysis:

Non-safety related main steam piping at Quad Cities was designed in accordance with USA Standards B31.1.0 - 1967, Power Piping, and maintained according the guidance in that standard. Paragraph 122.3.2, Take-Off Connections, of that standard states, in part, that take-off connections for instrument piping attached to power piping shall be designed to withstand full line pressure and temperature and all stresses including those induced by cyclic loading. Contrary to that requirement, EC 37709, as implemented, did not contain a detailed analysis that determined the stresses due to high cycle vibration and did not mitigate those stresses using one the methodologies described in NES-MS-03.04. Failure to perform applicable analysis during design of this modification to non-safety related main steam (power) piping as required by the B31.1 Code and implement the mitigating actions provided in the mechanical design standard for small bore piping is a performance deficiency and a finding. The inspectors determined that the finding was more than minor because the issue adversely affected the Initiating Events Cornerstone objective to limit the likelihood of those events that upset plant stability and challenge critical safety functions during power operations as described in IMC 0612, Appendix B, when as a result of the inadequate analysis, an instrumentation connection failed due to impact of high cycle vibration on June 13, 2011, resulting in a significant steam leak, an emergency downpower, and a reactor scram on Unit 1. The key attribute impacted was design control for plant modifications. The inspectors performed an SDP phase 1 screening for the finding using IMC 0609, Table 4a, and answered all of the questions No.

The finding screened as very low safety significance, or Green.

Inspectors determined that a significant contributor to this finding was the failure of the individual and supervisor performing the owners acceptance review to engage the appropriate engineering expertise to evaluate the adequacy of the modification design before the modification was implemented. The appropriate supervisory engagement in the task assignment or interaction between the engineering supervisor and the engineer would have identified the additional resource requirements and ensured the appropriate quality engineering product was implemented. As a result, inspectors identified this issue as cross-cutting in the area of Human Performance - Work Practices in that the licensee did not ensure supervisory and management oversight of work activities, including contractors, such that nuclear safety was supported (H.4(c)).

Enforcement action does not apply because the performance deficiency did not involve a violation of a regulatory requirement. Because this finding did not involve a violation of regulatory requirements and has very low safety significance, it is identified as FIN 05000254/2011004-03, Non-Safety Related Main Steam Modification Failure.

1R19 Post-Maintenance Testing

.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:

• Work Order 1447689: SBGT Operability (B Train);

• Work Order 1446612: Control Room Emergency Filtration System Test (IST);

• Work Order 1447674: SBO DG Load Test;

• Work Order 1448615: 2B RHR Pump Seal Replacement;

• Work Order 1437525: OP PMT U1 DG CW PMP Cubicle Cooler following Tube Bundle Replacement; and

• Work Order 1449647: DG Cooling Water Pump Group B Flow test following Rotating Element Replacement.

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 TSs, the UFSAR, 10 CFR Part 50 requirements, licensee procedures, and various NRC generic communications to ensure that the test results adequately ensured that the equipment met the licensing basis and design requirements. In addition, the inspectors reviewed corrective action documents associated with post-maintenance tests to determine whether the licensee was identifying problems and entering them in the CAP and that the problems were being corrected commensurate with their importance to safety. Documents reviewed are listed in the Attachment to this report.

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

b. Findings

No findings were identified.

1R22 Surveillance Testing

.1 Surveillance Testing

a. Inspection Scope

The inspectors reviewed the test results for the following activities to determine whether risk significant systems and equipment were capable of performing their intended safety function and to verify testing was conducted in accordance with applicable procedural and TS requirements:

• QCOS 0202-23: Reactor Recirculation Pump Runout Limits Determination and Setting (Routine);

• QCOS 1100-07: SBLC Pump Flow Rate Test (IST); and

• QCOS 1600-07: Reactor Coolant Leakage in the Drywell (RCS).

The inspectors observed in-plant activities and reviewed procedures and associated records to determine the following:

• did preconditioning occur;

• were the effects of the testing adequately addressed by control room personnel or engineers prior to the commencement of the testing;

• were acceptance criteria clearly stated, demonstrated operational readiness, and consistent with the system design basis;

• plant equipment calibration was correct, accurate, and properly documented;

• as-left setpoints were within required ranges; and the calibration frequency was in accordance with TSs, the USAR, procedures, and applicable commitments;

• measuring and test equipment calibration was current;

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

• test frequencies met TS requirements to demonstrate operability and reliability; tests were performed in accordance with the test procedures and other applicable procedures; jumpers and lifted leads were controlled and restored where used;

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

• test equipment was removed after testing;

• where applicable for inservice testing activities, testing was performed in accordance with the applicable version of Section XI, American Society of Mechanical Engineers Code, and reference values were consistent with the system design basis;

• where applicable, test results not meeting acceptance criteria were addressed with an adequate operability evaluation or the system or component was declared inoperable;

• where applicable for safety-related instrument control surveillance tests, reference setting data were accurately incorporated in the test procedure;

• where applicable, actual conditions encountering high resistance electrical contacts were such that the intended safety function could still be accomplished;

• prior procedure changes had not provided an opportunity to identify problems encountered during the performance of the surveillance or calibration test;

• equipment was returned to a position or status required to support the performance of its safety functions; and

• all problems identified during the testing were appropriately documented and dispositioned in the CAP.

Documents reviewed are listed in the Attachment to this report.

This inspection constituted one routine surveillance testing sample, one inservice testing sample, and one reactor coolant system leak detection inspection sample as defined in IP 71111.22, Sections -02 and -05.

b. Findings

No findings were identified.

2RS1 Radiological Hazard Assessment and Exposure Controls

This inspection constituted one complete sample as defined in IP 71124.01-05.

.1 Inspection Planning (02.01)

a. Inspection Scope

The inspectors reviewed all licensee performance indicators for the occupational exposure cornerstone for followup. The inspectors reviewed the results of radiation protection program audits (e.g., licensees quality assurance audits or other independent audits). The inspectors reviewed any reports of operational occurrences related to occupational radiation safety since the last inspection. The inspectors reviewed the results of the audit and operational report reviews to gain insights into overall licensee performance.

b. Findings

No findings were identified.

.2 Radiological Hazard Assessment (02.02)

a. Inspection Scope

The inspectors determined if there have been changes to plant operations since the last inspection that may result in a significant new radiological hazard for onsite workers or members of the public. The inspectors evaluated whether the licensee assessed the potential impact of these changes and has implemented periodic monitoring, as appropriate, to detect and quantify the radiological hazard.

The inspectors reviewed the last two radiological surveys from selected plant areas and evaluated whether the thoroughness and frequency of the surveys were appropriate for the given radiological hazard.

The inspectors conducted walkdowns of the facility, including radioactive waste processing, storage, and handling areas to evaluate material conditions and performed independent radiation measurements to verify conditions.

The inspectors selected the following radiologically risk-significant work activities that involved exposure to radiation:

• Rx Vessel - IVVI/Dryer Inspection (Q1R21), RWP 10011978, Revision 00;

• 2-2001-173 QA/B Repair, RWP 10012017, Revision 02;

• IRM/SRM Troubleshoot/Repair/Replace, RWP 10012158, Revision 02;

• Radwaste Basement Maintenance; RWP 10012198; Revision 00; and

• 2011 Spent Fuel Dry Cask Storage Project, RWP 10012851, Revision 00.

For these work activities, the inspectors assessed whether the pre-work surveys performed were appropriate to identify and quantify the radiological hazard and to establish adequate protective measures. The inspectors evaluated the radiological survey program to determine if hazards were properly identified, including the following:

• identification of hot particles;

• the presence of alpha emitters;

• the potential for airborne radioactive materials, including the potential presence of transuranics and/or other hard-to-detect radioactive materials (This evaluation may include licensee planned entry into non-routinely entered areas subject to previous contamination from failed fuel.);

• the hazards associated with work activities that could suddenly and severely increase radiological conditions and that the licensee has established a means to inform workers of changes that could significantly impact their occupational dose; and

• severe radiation field dose gradients that can result in non-uniform exposures of the body.

The inspectors observed work in potential airborne areas and evaluated whether the air samples were representative of the breathing air zone. The inspectors evaluated whether continuous air monitors were located in areas with low background to minimize false alarms and were representative of actual work areas. The inspectors evaluated the licensees program for monitoring levels of loose surface contamination in areas of the plant with the potential for the contamination to become airborne.

b. Findings

No findings were identified.

.3 Instructions to Workers (02.03)

a. Inspection Scope

The inspectors selected various containers holding non-exempt licensed radioactive materials that may cause unplanned or inadvertent exposure of workers, and assessed whether the containers were labeled and controlled in accordance with 10 CFR 20.1904, Labeling Containers, or met the requirements of 10 CFR 20.1905(g), Exemptions To Labeling Requirements.

The inspectors reviewed the following radiation work permits used to access high radiation areas and evaluated the specified work control instructions or control barriers:

• Rx Vessel - IVVI/Dryer Inspection (Q1R21), RWP 10011978, Revision 00;

• 2-2001-173 QA/B Repair, RWP 10012017, Revision 02;

• IRM/SRM Troubleshoot / Repair / Replace, RWP 10012158, Revision 02;

• Radwaste Basement Maintenance, RWP 10012198, Revision 00; and

• 2011 Spent Fuel Dry Cask Storage Project, RWP 10012851, Revision 00.

For these radiation work permits, the inspectors assessed whether allowable stay times or permissible dose (including from the intake of radioactive material) for radiologically significant work under each radiation work permit were clearly identified. The inspectors evaluated whether electronic personal dosimeter alarm setpoints were in conformance with survey indications and plant policy.

The inspectors reviewed selected occurrences where a workers electronic personal dosimeter noticeably malfunctioned or alarmed. The inspectors evaluated whether workers responded appropriately to the off-normal condition. The inspectors assessed whether the issue was included in the corrective action program and dose evaluations were conducted as appropriate.

For work activities that could suddenly and severely increase radiological conditions, the inspectors assessed the licensees means to inform workers of changes that could significantly impact their occupational dose.

b. Findings

No findings were identified.

.4 Contamination and Radioactive Material Control (02.04)

a. Inspection Scope

The inspectors observed locations where the licensee monitors potentially contaminated material leaving the radiological control area and inspected the methods used for control, survey, and release from these areas. The inspectors observed the performance of personnel surveying and releasing material for unrestricted use and evaluated whether the work was performed in accordance with plant procedures and whether the procedures were sufficient to control the spread of contamination and prevent unintended release of radioactive materials from the site. The inspectors assessed whether the radiation monitoring instrumentation had appropriate sensitivity for the type(s) of radiation present.

The inspectors reviewed the licensees criteria for the survey and release of potentially contaminated material. The inspectors evaluated whether there was guidance on how to respond to an alarm that indicates the presence of licensed radioactive material.

The inspectors reviewed the licensees procedures and records to verify that the radiation detection instrumentation was used at its typical sensitivity level based on appropriate counting parameters. The inspectors assessed whether or not the licensee has established a de facto release limit by altering the instruments typical sensitivity through such methods as raising the energy discriminator level or locating the instrument in a high-radiation background area.

The inspectors selected several sealed sources from the licensees inventory records and assessed whether the sources were accounted for and verified to be intact.

The inspectors evaluated whether any transactions, since the last inspection, involving nationally tracked sources were reported in accordance with 10 CFR 20.2207.

b. Findings

No findings were identified.

.5 Radiological Hazards Control and Work Coverage (02.05)

a. Inspection Scope

The inspectors evaluated ambient radiological conditions (e.g., radiation levels or potential radiation levels) during tours of the facility. The inspectors assessed whether the conditions were consistent with applicable posted surveys, radiation work permits, and worker briefings.

The inspectors evaluated the adequacy of radiological controls, such as required surveys, radiation protection job coverage (including audio and visual surveillance for remote job coverage), and contamination controls. The inspectors evaluated the licensees use of electronic personal dosimeters in high noise areas as high radiation area monitoring devices.

The inspectors assessed whether radiation monitoring devices were placed on the individuals body consistent with licensee procedures. The inspectors assessed whether the dosimeter was placed in the location of highest expected dose or that the licensee properly employed an NRC-approved method of determining effective dose equivalent.

The inspectors reviewed the application of dosimetry to effectively monitor exposure to personnel in high-radiation work areas with significant dose rate gradients.

The inspectors reviewed the following radiation work permits for work within airborne radioactivity areas with the potential for individual worker internal exposures.

• Rx Vessel - IVVI/Dryer Inspection (Q1R21), RWP 10011978, Revision 00;

• 2-2001-173 QA/B Repair, RWP 10012017, Revision 02;

• IRM/SRM Troubleshoot/Repair/Replace, RWP 10012158, Revision 02;

• Radwaste Basement Maintenance, RWP 10012198, Revision 00; and

• 2011 Spent Fuel Dry Cask Storage Project, RWP 10012851, Revision 00.

For these radiation work permits, the inspectors evaluated airborne radioactive controls and monitoring, including potential for significant airborne levels (e.g., grinding, grit blasting, system breaches, entry into tanks, cubicles, and reactor cavities). The inspectors assessed barrier (e.g., tent or glove box) integrity and temporary high efficiency particulate air ventilation system operation.

The inspectors examined the licensees physical and programmatic controls for highly activated or contaminated materials (nonfuel) stored within spent fuel and other storage pools. The inspectors assessed whether appropriate controls (i.e., administrative and physical controls) were in place to preclude inadvertent removal of these materials from the pool.

The inspectors examined the posting and physical controls for selected high radiation areas and very high radiation areas to verify conformance with the occupational performance indicator.

b. Findings

No findings were identified.

.6 Risk-Significant High Radiation Area and Very High Radiation Area Controls (02.06)

a. Inspection Scope

The inspectors discussed with the radiation protection manager the controls and procedures for high-risk high radiation areas and very high radiation areas.

The inspectors discussed methods employed by the licensee to provide stricter control of very high radiation area access as specified in 10 CFR 20.1602, Control of Access to Very High Radiation Areas, and Regulatory Guide 8.38, Control of Access to High and Very High Radiation Areas of Nuclear Plants. The inspectors assessed whether any changes to licensee procedures substantially reduced the effectiveness and level of worker protection.

The inspectors discussed the controls in place for special areas that have the potential to become very high radiation areas during certain plant operations with first-line health physics supervisors (or equivalent positions having backshift health physics oversight authority). The inspectors assessed whether these plant operations require communication beforehand with the health physics group, so as to allow corresponding timely actions to properly post, control, and monitor the radiation hazards including re-access authorization.

The inspectors evaluated licensee controls for very high radiation areas and areas with the potential to become very high radiation areas to ensure that an individual was not able to gain unauthorized access to the very high radiation area.

b. Findings

No findings were identified.

.7 Radiation Worker Performance (02.07)

a. Inspection Scope

The inspectors observed radiation worker performance with respect to stated radiation protection work requirements. The inspectors assessed whether workers were aware of the radiological conditions in their workplace and the radiation work permit controls/limits in place, and whether their performance reflected the level of radiological hazards present.

The inspectors reviewed radiological problem reports since the last inspection that found the cause of the event to be human performance errors. The inspectors evaluated whether there was an observable pattern traceable to a similar cause. The inspectors assessed whether this perspective matched the corrective action approach taken by the licensee to resolve the reported problems. The inspectors discussed with the radiation protection manager any problems with the corrective actions planned or taken.

b. Findings

No findings were identified.

.8 Radiation Protection Technician Proficiency (02.08)

a. Inspection Scope

The inspectors observed the performance of the radiation protection technicians with respect to all radiation protection work requirements. The inspectors evaluated whether technicians were aware of the radiological conditions in their workplace and the radiation work permit controls/limits, and whether their performance was consistent with their training and qualifications with respect to the radiological hazards and work activities.

The inspectors reviewed radiological problem reports since the last inspection that found the cause of the event to be radiation protection technician error. The inspectors evaluated whether there was an observable pattern traceable to a similar cause.

The inspectors assessed whether this perspective matched the corrective action approach taken by the licensee to resolve the reported problems.

b. Findings

No findings were identified.

.9 Problem Identification and Resolution (02.09)

a. Inspection Scope

The inspectors evaluated whether problems associated with radiation monitoring and exposure control were being identified by the licensee at an appropriate threshold and were properly addressed for resolution in the licensees corrective action program.

The inspectors assessed the appropriateness of the corrective actions for a selected sample of problems documented by the licensee that involve radiation monitoring and exposure controls. The inspectors assessed the licensees process for applying operating experience to their plant.

b. Findings

No findings were identified.

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

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

.1 Inspection Planning (02.01)

a. Inspection Scope

The inspectors reviewed the solid radioactive waste system description in the Final Safety Analysis Report, the process control program, and the recent radiological effluent release report for information on the types, amounts, and processing of radioactive waste disposed.

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

b. Findings

No findings were identified.

.2 Radioactive Material Storage (02.02)

a. Inspection Scope

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

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

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

The inspectors selected containers of stored radioactive material, and assessed for signs of swelling, leakage, and deformation.

b. Findings

No findings were identified.

.3 Radioactive Waste System Walkdown (02.03)

a. Inspection Scope

The inspectors walked down accessible portions of select radioactive waste processing systems to assess whether the current system configuration and operation agreed with the descriptions in the Final Safety Analysis Report, Offsite Dose Calculation Manual, and process control program.

The inspectors reviewed administrative and/or physical controls (i.e., drainage and isolation of the system from other systems) to assess whether the equipment which is not in service or abandoned in place would not contribute to an unmonitored release path and/or affect operating systems or be a source of unnecessary personnel exposure.

The inspectors assessed whether the licensee reviewed the safety significance of systems and equipment abandoned in place in accordance with 10 CFR 50.59, Changes, Tests, and Experiments.

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

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

For those systems that provide tank recirculation, the inspectors evaluated whether the tank recirculation procedures provided sufficient mixing.

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

b. Findings

No findings were identified.

.4 Waste Characterization and Classification (02.04)

a. Inspection Scope

The inspectors selected the following radioactive waste streams for review:

• resin, and

• dry active waste.

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

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

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

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

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

b. Findings

No findings were identified.

.5 Shipment Preparation (02.05)

a. Inspection Scope

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

The inspectors observed radiation workers during the conduct of radioactive waste processing and radioactive material shipment preparation and receipt activities.

The inspectors assessed whether the shippers were knowledgeable of the shipping regulations and whether shipping personnel demonstrated adequate skills to accomplish the package preparation requirements for public transport with respect to:

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

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

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

b. Findings

No findings were identified.

.6 Shipping Records (02.06)

a. Inspection Scope

The inspectors evaluated whether the shipping documents indicated the proper shipper name; emergency response information and a 24-hour contact telephone number; accurate curie content and volume of material; and appropriate waste classification, transport index, and UN number for the following radioactive shipments:

• QC-11-706, Surface Contaminated Object (SCO) Turbine Casing;

• QC-11-723, Solid Metals Gaskets LSA II;

• QC 10-115, Dry Active Waste LSA II; and

• QC-10-072, Type B, Resin LSA-II.

Additionally, the inspectors assessed whether the shipment placarding was consistent with the information in the shipping documentation.

b. Findings

No findings were identified.

.7 Identification and Resolution of Problems (02.07)

a. Inspection Scope

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

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

b. Findings

No findings were identified.

OTHER ACTIVITIES

Cornerstones: Initiating Events, Mitigating Systems, Barrier Integrity, and Emergency Preparedness

4OA1 Performance Indicator Verification

.1 Safety System Functional Failures

a. Inspection Scope

The inspectors sampled licensee submittals for the Safety System Functional Failures performance indicator for Quad Cities Units 1 and 2 for the period from the second quarter of 2010 through the third quarter of 2011. To determine the accuracy of the performance indicator (PI) data reported during those periods, PI definitions and guidance contained in the Nuclear Energy Institute (NEI) Document 99-02, Regulatory Assessment Performance Indicator Guideline, Revision 6, dated October 2009, and NUREG-1022, Event Reporting Guidelines 10 CFR 50.72 and 50.73" definitions and guidance, were used. The inspectors reviewed the licensees operator narrative logs, operability assessments, maintenance rule records, maintenance work orders, issue reports, event reports, and NRC integrated inspection reports for the period of July 1, 2010, through June 30, 2011, to validate the accuracy of the submittals. The inspectors also reviewed the licensees issue report database to determine if any problems had been identified with the PI data collected or transmitted for this indicator, and none were identified.

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

b. Findings

No findings were identified.

.2 Occupational Exposure Control Effectiveness

a. Inspection Scope

The inspectors sampled licensee submittals for the Occupational Radiological Occurrences Performance Indicator for the period from April 2010 through June 2011.

To determine the accuracy of the PI data reported during those periods, PI definitions and guidance contained in the NEI Document 99-02, Regulatory Assessment Performance Indicator Guideline, Revision 6, were used. The inspectors reviewed the licensees assessment of the PI for occupational radiation safety to determine if indicator related data was adequately assessed and reported. To assess the adequacy of the licensees PI data collection and analyses, the inspectors discussed with radiation protection staff, the scope and breadth of its data review, and the results of those reviews. The inspectors independently reviewed electronic dosimetry dose rate and accumulated dose alarm reports and the dose assignments for any intakes that occurred during the time period reviewed to determine if there were potentially unrecognized occurrences. The inspectors also conducted walkdowns of locked high radiation area entrances to determine the adequacy of the controls in place for these areas.

Documents reviewed are listed in the Attachment to this report.

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

b. Findings

No findings were identified.

.3 Reactor Coolant System Specific Activity

a. Inspection Scope

The inspectors sampled licensee submittals for the reactor coolant system specific activity PI for Quad Cities Nuclear Units 1 and 2 for the period from the second quarter 2010 through the second quarter 2011. The inspectors used PI definitions and guidance contained in the NEI Document 99-02, Regulatory Assessment Performance Indicator Guideline, Revision 6, dated October 2009 to determine the accuracy of the PI data reported during those periods. The inspectors reviewed the licensees reactor coolant system chemistry samples, TS requirements, issue reports, event reports, and NRC Integrated Inspection Reports for the period of second quarter 2010 through the second quarter 2011 to validate the accuracy of the submittals. The second quarter inspectors also reviewed the licensees issue report database to determine if any problems had been identified with the PI data collected or transmitted for this indicator and none were identified. In addition to record reviews, the inspectors observed a chemistry technician obtain and analyze a reactor coolant system sample.

Documents reviewed are listed in the Attachment to this report.

This inspection constituted two reactor coolant system specific activity samples as defined in IP 71151-05.

b. Findings

No findings were identified.

.4 Radiological Effluent Technical Specification/Offsite Dose Calculation Manual

Radiological Effluent Occurrences

a. Inspection Scope

The inspectors sampled licensee submittals for the radiological effluent Technical Specification/Offsite Dose Calculation Manual radiological effluent occurrences PI for the period from the second quarter 2010 through the second quarter 2011. The inspectors used PI definitions and guidance contained in the NEI Document 99-02, Regulatory Assessment Performance Indicator Guideline, Revision 6, dated October 2009, to determine the accuracy of the PI data reported during those periods.

The inspectors reviewed the licensees issue report database and selected individual reports generated since this indicator was last reviewed to identify any potential occurrences such as unmonitored, uncontrolled, or improperly calculated effluent releases that may have impacted offsite dose. The inspectors reviewed gaseous effluent summary data and the results of associated offsite dose calculations for selected dates between the second quarter 2010 through the second quarter 2011 to determine if indicator results were accurately reported. The inspectors also reviewed the licensees methods for quantifying gaseous and liquid effluents and determining effluent dose.

Documents reviewed are listed in the Attachment to this report.

This inspection constituted one Radiological Effluent Technical Specification/Offsite Dose Calculation Manual radiological effluent occurrences sample as defined in IP 71151 05.

b. Findings

No findings were identified.

4OA2 Identification and Resolution of Problems

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

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

a. Inspection Scope

As part of the various baseline inspection procedures discussed in previous sections of this report, the inspectors routinely reviewed issues during baseline inspection activities and plant status reviews to verify that they were being entered into the licensees CAP at an appropriate threshold, that adequate attention was being given to timely corrective actions, and that adverse trends were identified and addressed. Attributes reviewed included: identification of the problem was complete and accurate; timeliness was commensurate with the safety significance; evaluation and disposition of performance issues, generic implications, common causes, contributing factors, root causes, extent of condition reviews, and previous occurrences reviews were proper and adequate; and that the classification, prioritization, focus, and timeliness of corrective actions were commensurate with safety and sufficient to prevent recurrence of the issue.

Minor issues entered into the licensees CAP as a result of the inspectors observations are included in the Attachment to this report.

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

b. Findings

No findings were identified.

.2 Daily Corrective Action Program Reviews

a. Inspection Scope

In order to assist with the identification of repetitive equipment failures and specific human performance issues for followup, the inspectors performed a daily screening of items entered into the licensees CAP. This review was accomplished through inspection of the stations daily condition report packages.

These daily reviews were performed by procedure as part of the inspectors daily plant status monitoring activities and, as such, did not constitute any separate inspection samples.

b. Findings

No findings were identified.

4OA3 Followup of Events and Notices of Enforcement Discretion

.1 (Closed) Licensee Event Report (LER) 05000254/2011-001: Loss of Both Divisions of

Residual Heat Removal System

a. Inspection Scope

This event, which occurred on April 19, 2011, resulted in safety-related equipment inoperability when a water leak was discovered on the Unit 1 emergency diesel generator cooling water pump (EDGCWP) room cooler. The leak developed in the coolers internal distribution piping and was caused by under-deposit corrosion on the service water return piping in a vertical run of pipe. The licensees evaluation determined that the cubicle cooling function would have been met, but leakage into the vault could have prevented both the EDGCWP and the 1D residual heat removal service water pump from meeting their post-accident mission times. As a result of the flooding impact to the EDGCWP, the Unit 1 emergency diesel generator (EDG) would not have been available to meet its post accident mission time; the remaining Division II residual heat removal (RHR) components would not have had an emergency power supply in a Loss of Offsite Power scenario.

Concurrent with the identification of the cubicle cooler leak, the Division I train of RHR was inoperable and unavailable due to planned maintenance on the Division I RHR room cooler. As a result of the concurrent maintenance and the leak, both divisions of RHR were simultaneously unavailable for a Loss of Offsite Power/Loss of Coolant Accident scenario, and the potential loss of RHR safety function existed until the Division I room cooler was restored, approximately four hours later.

The licensee performed external visual inspections of similar cooler configurations in other trains and systems, and these inspections did not reveal any other issues that would affect short-term operability. The leak was repaired, and the cooler was later replaced with a new unit. Other corrective actions included changes to the room cooler inspection guidance to include ultrasonic testing of susceptible piping and scheduling replacement of the other two EDGCWP coolers. Inspectors evaluated the corrective action plan and concluded that the actions would reasonably prevent recurrence.

Documents reviewed as part of this inspection are listed in the Attachment to this report.

This LER is closed.

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

b. Findings

Introduction:

A self-revealed finding of very low safety significance (Green) with an associated NCV of 10 CFR 50, Appendix B, Criterion V, Instructions, Procedures, and Drawings, was identified when a service water leak occurred on the Unit 1 EDGCWP cubicle cooler on April 19, 2011. Inspectors concluded that failure to inspect the safety-related service water piping within the cooler enclosure with sufficient rigor to identify under-deposit corrosion and pipe wall thinning did not meet the program requirements requiring identification and evaluation of wall as required by the stations program procedure.

Description:

On April 19, 2011, operators identified a 3-gallon per minute leak from the Unit 1 EDGCWP cubicle cooler, 1-5749. The Unit 1 EDGCWP and Unit 1 EDG were declared inoperable and required actions were accomplished according to TSs.

A walkdown of the cubicle cooler revealed a small hole in the heat exchanger return water header.

On April 20, 2011, ultrasonic thickness (UT) measurements were performed on the heat exchanger return water header. Several locations on the heat exchanger return water header were below the minimum wall thickness of 0.10 inch. The licensee repaired the hole by welding a flush patch on the return header piping and inspectors verified that the patch was of sufficient size and configuration to represent an appropriate repair to American Society of Mechanical Engineers (ASME) Class III piping. The other minimum wall thickness locations were evaluated by Engineering in EC 384132, and the operability assessment of the degraded condition was documented in IR 1205479.

The engineering evaluation determined the minimum wall thickness for operability of the piping to be 0.012 inch and recommended replacement of the affected piping before the end of 2011 to ensure adequate margin remained to prevent another failure.

Following the repair and post-maintenance testing on April 21, 2011, for WO 1430440, the Unit 1 EDG and EDGCWP were declared operable.

The preventive maintenance (PM) task to clean/inspect the EDGCWP cubicle cooler was a visual inspection performed on a 4-year frequency as part of the licensees service water heat exchanger program implemented in response to Generic Letter 89-13, Service Water System Problems Affecting Safety-Related Equipment. The inspection was last performed in September 2007 using WO 854383. Due to the limited access to the heat exchanger internals, the clean/inspect of this type of cooler was not as rigorous as the clean/inspect that has been performed on other room coolers with better access. This room cooler was not designed with either an inlet or outlet area that can be fully opened to allow inspection of all the tubes and tube sheet. When the inlet flange was opened the only internal visual inspection that could be performed without special equipment is only a few tubes in the coil and not the full length of either the inlet or outlet header areas.

The PM template for heat exchanger inspection tasks lists UT measurements as a method that could be used to determine wall thickness; however, the work instructions for cleaning and inspecting the EDGCWP cubicle cooler did not require the use of UT measurements on normally inaccessible piping inside the room cooler, and no UT measurements were taken. Interviews indicated that the inspections performed were visual only and focused on potential flow blockage concerns as opposed to inspecting to identify significant corrosion and potential areas of wall thinning. No UT inspections were performed on this piping until the failure occurred.

Analysis:

Inspectors concluded that failure to inspect the safety-related service water piping within the cooler enclosure with sufficient rigor to identify under-deposit corrosion and pipe wall thinning was a performance deficiency. The visual inspection performed for this safety-related heat exchanger was not adequate to meet program requirements in that unless the piping is directly observable visually, non-destructive testing is required to evaluate wall thinning potential in the pressure boundary components. Step 4.7.2.2 of ER-AA-340-1002, Service Water Heat Exchanger Inspection Guide, requires, in part, that in areas where significant corrosion is apparent, pipe wall thickness should be verified within code allowance values or verified acceptable by an appropriate engineering evaluation. If the piping cannot be observed visually, areas experiencing significant corrosion are not observable, and other methods are required to meet the procedural requirements. Inspectors concluded that the performance deficiency was more than minor using the questions in IMC 0612, Appendix B, because it adversely affected the Mitigating Systems Cornerstone objective of ensuring availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences and equipment operability was impacted by the resulting leakage.

Inspectors performed an SDP phase 1 review using IMC 0609, Table 4a, and the clarifying guidance of Appendix A to that manual chapter to answer all screening questions for Mitigating Systems Cornerstone as No. Utilizing the guidance in Appendix A, only the impact of the performance deficiency is addressed in the SDP (i.e., the planned maintenance activity associated with Division I is not assessed in the SDP evaluation of the finding.) The performance deficiency impacted only the Unit 1 EDG and Division II of RHR which in this case is one train of a two train function so the finding does not represent a loss of system safety function. Since the planned maintenance activity that affected Division 1 is not part of the performance deficiency, no loss of safety function occurred that is attributable to the performance deficiency.

This determination was reviewed with the Region III senior reactor analyst to ensure the inspectors evaluation was consistent with current policy.

Inspectors concluded this issue was primarily caused by a deficiency in the site inspection procedure and that the deficiency was not a current issue because the licensee had suspended use of the site inspection procedure in December 2010 and had not performed any inspections in the past three years.

Enforcement:

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

Licensee procedure ER-AA-340-1002, Service Water Heat Exchanger Inspection Guide, requires, in part, that in areas where significant corrosion is apparent, pipe wall thickness should be verified within code allowance values or verified acceptable by an appropriate engineering evaluation. If the piping cannot be observed visually, areas experiencing significant corrosion are not observable, and other methods are required to meet the procedural requirements.

Contrary to the above, in September 2007, the individual performing the inspection for the inlet and outlet piping within the room cooler enclosure did not follow the procedural requirement to identify areas of significant corrosion because the piping was not inspected beyond the small portion of the piping that was immediately observable without using other assessment tools or techniques. As a result, wall thinning continued unevaluated until a through-the-wall leak developed on April 19, 2011, resulting in system unavailability. Because this violation was of very low safety significance and it was entered into the CAP as IR 1204785, this violation is being treated as an NCV consistent with Section 2.3.2 of the NRC Enforcement Policy (NCV 05000254/2011004-04, Failure to Appropriately Inspect Safety-Related Room Cooler).

Immediate corrective actions included extent of condition inspections, repair of the hole in the piping and completion of an engineering assessment of other areas of the piping that were identified as below the minimum wall thickness before restoring the system to service. The licensee replaced the room cooler in September 2011 using WO 1437525.

.2 (Closed) Licensee Event Report (LER) 05000254/2011-002-00: Unit 1 Manual Reactor

Scram Due to Steam Leak On June 13, 2011, with the unit at 61 percent and raising power following a refueling outage, a steam leak was identified on the main steam line between the #1 turbine control valve (1-5699-CV1) and the high pressure turbine. Operators reduced reactor power to approximately 34 percent power before they determined that the turbine should be tripped to isolate the steam leak. At that time, the operators appropriately inserted a manual reactor scram and tripped the main turbine. Operator actions were appropriate and the plant responded as expected. The steam leak was determined to have occurred at the site of an instrument line connection that had been repaired on June 12, 2011.

Two instrument lines were attached to the A and B main steam line piping during the refueling outage as part of a modification intended to measure the thermal performance of the newly installed low pressure main turbine rotors. The steam lines at this location are non-safety related and are constructed to ASME B31.1, Power Piping Code dated 1967. The sensing line assemblies were connected to the main steam line by short pipe studs welded to new sock-o-lets that were welded to the main steam piping. Each line consisted of an isolation valve with a transition to tubing through a coupling and was then attached via tubing to a separately supported pressure transmitter. During the power plant startup on June 10, 2011, both of these lines were identified to have failed, causing steam leaks in the low pressure heater bay. The turbine was taken out of service, and both lines were repaired by cutting the stub tube out of the sock-o-let and welding a capped 5-inch pipe stub to the sock-o-let. On the morning of June 12, the repairs were completed and the turbine was returned to service. The main generator was synchronized to the grid and power ascension to 100 percent began. On June 13, the repair downstream of the #1 control valve failed when the reused sock-o-let failed and ejected the capped stub tube. Post-failure examination of the sock-o-let revealed the failure was due to a previously undetected flaw on the internal diameter of the sock-o-let that ran parallel to the surface prepared for the repair welds. When the flaw propagated, the sock-o-let failed and the stub tube was ejected creating the steam leak.

Because the potential for an existing flaw at the base of the weld was not anticipated, the repair design did not specify any additional special requirements beyond code minimum for the repair. The licensees root cause investigation was thorough and, in addition to performing the post-mortem examination of the failed components, reviewed the initial modification design and the initial steam leak repair. Additional information on the modification design is included in Section 1R18 of this report.

The corrective actions included replacement of the sock-o-lets in both steam lines with welded gamma plugs to restore the pressure boundary.

Documents reviewed as part of this inspection are listed in the Attachment to this report.

This LER is closed.

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

4OA5 Other Activities

.1 (Closed) Unresolved Item (URI)05000254/2000016-04; 05000265/2000016-04:

Associated Circuits Issue - Single Spurious Operation, Including Effect of Automatic Depressurization System Failures on the Time Line During the 1998 NRC fire protection inspection, inspectors identified an URI regarding the licensee's post-fire safe shutdown circuit analysis not being sufficiently comprehensive to comply with 10 CFR Part 50, Appendix R, Section III.G, and III.L.

Specifically, the licensees analysis assumed that only one spurious operation would occur as a result of a fire in any given area, regardless of the number, type, or location of affected cables and circuits. The inspectors concluded that this assumption had a significant effect on the time available for operator actions due to multiple automatic depressurization system (ADS) valves having cabling in the same fire zone/area, TB-II.

A review of the safe shutdown analysis and discussion with the licensee indicated that only one of the five ADS valves was assumed to spuriously open due to fire damage, prior to it being isolated by operator actions. Based on this assumption, the spurious opening of one ADS valve for 10 minutes was assumed to be the worst case spurious operation that would occur due to a fire in the turbine building (TB-II).

This concern was identified as Item 01d of URI 98011-01. During the 2000 triennial fire protection inspection, this item was closed to URI 2000016-04, pending completion of the NRC/industry review and resolution of associated circuit issues affecting safe shutdown.

The fire protection design basis at Quad Cities was challenged by the NRC during a 1988 Appendix R audit. During that audit, a concern was raised regarding the routing of several ADS conductors in the same cable. The NRC indicated that when evaluating spurious operations of the ADS, multiple shorts do not need to be considered, but multiple shorts within a given cable should be considered. Based on this guidance, the licensee implemented design changes to separate individual cables to preclude multiple spurious operations of the ADS valves at Quad Cities. In a July 6, 1989, NRC safety evaluation report, the NRC reviewed the modifications and found them to be acceptable to address the issue.

The current safe shutdown report at Quad Cities considers a single ADS valve actuation in evaluating the timeline requirements for establishing injection. The safe shutdown procedure also requires a 10-minute action to de-energize the ADS system.

The inspectors determined that the licensing basis for Quad Cities did not require consideration of more than one spurious operation from the time that the alternate shutdown procedure is entered until the control of safe shutdown equipment is transferred to the remote shutdown panel, a total of 10 minutes. The feasibility and reliability of the operator actions as specified in Safe Shutdown Procedure QCARP 0000-01 were not reviewed as part of this issue because it was not part of the scope for the URI.

In view of the above discussion, the inspectors determined that the issue of taking timely actions, within a 10-minute period, to preclude multiple spurious actions was addressed by the safe shutdown procedure; therefore, URI 05000254/2000016-04; 05000265/2000016-04 is closed.

The inspectors review of this issue was considered to be a part of the original inspection effort, and as such did not constitute any additional inspection samples.

The inspectors determined that transitioning from Emergency Operating Procedure (EOP) to Safe Shutdown Procedure QCARP was questionable as to the time frame when this occurs (t=0). Entry into QCARP from EOP is symptom, severe and uncontrolled fire based, and therefore, the inspectors determined that the time of this transition was not defined. Additionally, the inspectors surmised that from the inception of fire until entry into QCARP, it could be any length of time and any number of spurious operations before the transition takes place. This issue is discussed in greater detail in Section 4OA5.2 of this report.

.2 (Open) Unresolved Item (URI)05000254/2011004-05; 05000265/2011004-05:

Transition from Emergency Operating Procedure to Appendix R Safe Shutdown Procedure -Time Zero Issue In 1998, the NRC was concerned that there was no clear guidance for when to transition from EOP to Appendix R Safe Shutdown Procedure, QCARP. In the timeframe between 1998 and 2000, there was significant discussion between the licensee and the NRC on the subject of time zero. In 1998, the NRC opened an inspector followup item (IFI) in Inspection Report 98-017 dated November 5, 1998. The IFI pertained specifically to establishing conditions for QCARP entry since premature entry could jeopardize a response to design basis events, while delayed entry could jeopardize the ability to safely shutdown in the event of an Appendix R fire. During this inspection, the inspectors discussed the transition from EOP to QCARP with the licensee operations personnel. Based on this discussion, the inspectors ascertained that the determination to make such a transition would be based on reports of the impact of the fire and ability to control the plant using the EOPs. The inspectors noted that Procedure QCOA 0010-12, Fire/Explosion, provided Operations personnel with information on what the protected and analyzed safe shutdown equipment was and what equipment could be potentially affected by fire for any given area. Such equipment was already specified as an option for use by the EOP. Based upon this information, the inspectors concluded that this inspection followup item could be closed out.

A review of the Safe Shutdown Procedure QCARP, Revision 8, indicated that the entry into this procedure from EOP was based on symptom of severe and uncontrolled fire which reflected the operations philosophy as indicated earlier. This procedure was acceptable to the NRC only as a means of taking timely actions, within 10 minutes, to preclude multiple spurious actions. However, from the standpoint of the time frame of transition from EOP to QCARP, this procedure was still questionable. In this connection, the inspectors opined that from the inception of fire until entry into QCARP, it could be any length of time and any number of spurious operations before the transition takes place. The inspectors concluded that the time of this transition was undefined, and therefore, the inspectors were not sure whether this procedure was really acceptable.

In view of this concern, and the prior closure by the NRC of a similar issue, the inspectors determined that the issue of transition time frame (t=0) from EOP to QCARP needs to be re-evaluated and addressed. As result of this assessment, the inspectors are opening a new URI 05000254/2011004-05; 05000265/2011004-05 to address this issue.

.3 Operation of an Independent Spent Fuel Storage Installation at Operating Plants

(60855.1)

a. Inspection Scope

The inspectors observed and evaluated select licensee loading, processing, and transfer operations of the third canister during the licensees 2011 dry fuel storage campaign to verify compliance with the applicable certificate of compliance conditions, the associated TS, and independent spent fuel storage installation (ISFSI) procedures. Specifically, the inspectors observed: loading and independent verification of the fuel assemblies into the multi-purpose canister; lifting of the transfer cask (HI-TRAC) from the spent fuel pool; decontamination and surveying; weld verification of the multi-purpose canister (MPC) lid; draining of water; vacuum drying; lowering of the HI-TRAC on top of the storage cask (HI-STORM) into a restrained stack-up configuration; and transfer of the MPC from the HI-TRAC into the HI-STORM. The licensee uses the Holtec International HI-STORM 100 cask system.

The inspectors performed tours of the ISFSI pad to assess the material condition of the pad and the loaded HI-STORM casks. The inspectors observed ISFSI pad surface spalling and degradation, all of it above the top layer of rebar, and locations where the licensee implemented surface repairs. The inspectors reviewed a current licensee evaluation of flammable materials near the ISFSI and their radiation monitoring program.

Additionally, the inspectors performed independent radiation surveys around the ISFSI pad and loaded HI-STORM casks. The inspectors reviewed the contamination and radiation levels from a previously loaded multi-purpose canister during the campaign to determine whether they were below the regulatory limits.

The inspectors reviewed select documents, in part, after the licensee completed certain loading activities, and a review of the fuel selection documentation was performed to verify the fuel placed in the multi-purpose canister met the TS requirements.

The inspectors reviewed applicable heavy loads procedures and inspection documentation to determine compliance with the sites heavy loads program.

In addition, the inspectors reviewed a number of condition reports and the associated corrective actions since the last ISFSI inspection. The inspectors also reviewed 72.48 screenings and changes to the licensees 10 CFR 72.212 evaluations since the last ISFSI inspection.

b. Findings

No findings were identified.

.4 Institute of Nuclear Power Operations (INPO) Plant Assessment Report Review

a. Inspection Scope

The inspectors reviewed the final report for the INPO plant assessment conducted during the weeks of February 21 and February 28 of 2011. The inspectors reviewed the report to ensure that issues identified were consistent with the NRC perspectives of licensee performance and to verify if any significant safety issues were identified that required further NRC followup.

b. Findings

No findings were identified.

4OA6 Management Meetings

.1 Exit Meeting Summary

On October 4, 2011, the inspectors presented the inspection results to M. Prospero, 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:

• The results of Radiological Hazard Assessment and Exposure Controls program inspection with Mr. M. Prospero, plant manager, and other licensee staff on August 5, 2011.

• The ISFSI operational inspection included an interim exit meeting on August 12, 2011. The inspectors presented the inspection results to members of the licensee management and staff. Licensee personnel acknowledged the information presented.

• The results of the review of Unresolved Item 05000254/2000016-04; 05000265/2000016-04 concerning licensees Post-Fire Safe Shutdown circuit analysis not being sufficiently comprehensive to satisfy the requirements of 10 CFR Part 50, Appendix R, Section III.G and III.L were discussed with Mr. Mathew Rice, on August 25, 2011.

• The Radioactive Waste and Transportation inspection results were discussed on September 16, 2011, with Mr. T. Hanley and other licensee staff.

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

4OA7 Licensee-Identified Violations

The following violation of very low significance (Green) or Severity Level IV was identified by the licensee and is a violation of NRC requirements which meets the criteria of the NRC Enforcement Policy for being dispositioned as an NCV:

• Technical Specification 5.4.1.d requires the license to establish, implement, and maintain written procedures covering implementation of programs specified in Technical Specifications 5.5. Technical Specification 5.5.8 details requirements for the Explosive Gas and Storage Tank Radioactivity Monitoring Program.

The program requires, in part, a surveillance program to ensure the limits are maintained appropriate to the systems design criteria. Contrary to the above, the licensee failed to implement surveillances within the frequency as allowed by Surveillance Requirement 3.0.2 that ensured off gas hydrogen was maintained in accordance with the Explosive Gas and Storage Tank Radioactivity Monitoring Program. Specifically, the Unit 1 1B off gas hydrogen analyzer surveillance was not completed prior to exceeding the grace period. A review of the surveillance work history revealed that the surveillance was late on September 3, 2011.

This condition was discovered on September 6, 2011. Upon discovery, the hydrogen analyzer was declared inoperable and the surveillance was performed prior to any required actions per the applicable Technical Requirements Manual (TRM) Limiting Condition for Operation (LCO) in accordance with Surveillance Requirement 3.0.3. This issue was documented in IR 1259998. This issue is more than minor because the performance deficiency affected the Mitigating Systems Cornerstone objective to ensure the availability, reliability and capability of systems to prevent undesirable consequences. The finding is of very low safety significance or Green because the hydrogen analyzer met the surveillance requirements and there was reasonable assurance that the hydrogen analyzer would have been able to function properly. Therefore, this finding screened as Green in accordance with IMC 0609.

ATTACHMENT:

SUPPLEMENTAL INFORMATION

KEY POINTS OF CONTACT

Licensee

T. Hanley, Site Vice President

M. Prospero, Plant Manager

W. Beck, Regulatory Assurance Manager

D. Collins, Radiation Protection Manager

S. Darin, Engineering Director

J. Garrity, Work Control Director

V. Neels, Chemistry/Environ/Radwaste Manager

K. OShea, Acting Operations Director

T. Scott, Work Management Director

S. Piepenbrink, Security Manager

K. Moser, Training Director

Nuclear Regulatory Commission

M. Ring, Chief, Reactor Projects Branch 1

Attachment

LIST OF ITEMS

Opened

05000254/2011004-01; NCV Turbine Building Differential Pressure Indicating Positive

05000265/2011004-01 (Section 1R04.1.b(1))

05000254/2011004-02; NCV Valve Out of Position in Radwaste (Section 1R04.1.b(2))

05000265/2011004-02

05000254/2011004-03 FIN Non-Safety Related Main Steam Modification Failure (Section 1R18.1)

05000254/2011004-04 NCV Failure to Appropriately Inspect Safety-Related Room Cooler (Section 4OA3.1)

05000254/2011004-05; URI Transition from Emergency Operating Procedure to

05000265/2011004-05 Appendix R Safe Shutdown Procedure - Time Zero Issue (Section 4OA5.2)

Closed

05000254/2011004-01 NCV Turbine Building Differential Pressure Indicating Positive

05000265/2011004-01 (Section 1R04.1.b(1))

05000254/2011004-02 NCV Valve Out of Position in Radwaste (Section 1R04.1.b(2))

05000265/2011004-02

05000254/2011004-03 FIN Non-Safety Related Main Steam Modification Failure (Section 1R18.1)

05000254/2011004-04 NCV Failure to Appropriately Inspect Safety-Related Room Cooler (Section 4OA3.1)

05000254/2011-001-00 LER Loss of Both Divisions of Residual Heat Removal System (Section 4OA3.1)

05000254/2011-002-00 LER Unit 1 Manual Reactor Scram Due to Steam Leak (Section 4OA3.2)

05000254/2000016-04; URI Associated Circuits Issue - Single Spurious Operation,

05000265/2000016-04 Including Effect of Automatic Depressurization System Failures on the Time Line (Section 4OA5.1)

Discussed

None.

Attachment