IR 05000387/2011003

IR 05000387-11-003, 05000388-11-003, on 04/01 12011 - 061301201 1, Susquehanna Steam Electric Station, Units 1 & 2, Equipment Alignment, Maintenance Risk Assessments & Emergent Work Control, Identification and Resolution of Problems

ML112220409
Person / Time
Site:	Susquehanna
Issue date:	08/10/2011
From:	Darrell Roberts Division Reactor Projects I
To:	Rausch T Susquehanna
Krohn P
References
EA-11-097 IR-11-003
Download: ML112220409 (65)

Text

UNITED STATES NUCLEAR REGULATORY COMMISSION

REGION I

475 ALLENDALE ROAD

SUBJECT:

SUSQUEHANNA STEAM ELECTRIC STATION - NRC INTEGRATED tNSPECTlON REPORT 05000387/201 1 003 AND 0500038812011 003 AND EXERCISE OF ENFORCEMENT DISCRETION

Dear Mr. Rausch:

On June 30,2011, the U. S. Nuclear Regulatory Commission (NRC) completed an inspection at your Susquehanna Steam Electric Station Units 1 and 2. The enclosed integrated inspection report presents the inspection results, which were discussed on July 21, 2011, with you and other members of your staff.

This inspection examined activities completed under your license as they relate to safety and compliance with the Commission's rules and regulations and with the conditions of your license.

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

This report documents two NRC-identified findings (Green) and one self-revealing finding (Green), all of very low safety significance, All of these findings were determined to involve violations of NRC requirements. Additionally, three licensee-identified violations, which were determined to be of very low safety significance, are listed in this report. However, because of the very low safety significance and because they are entered into your correction action program (CAP), the NRC is treating these findings as non-cited violations (NCVs) consistent with Section 2.3.2 of the NRC's Enforcement Policy. lf you contest any NCV in this report, you should provide a response within 30 days of the date of this inspection report, with the basis for your denial, to the Nuclear Regulatory Commission, ATTN.: Document Control Desk, Washington, D.C. 20555-0001; with copies to the Regional Administrator Region l; the Director, Office of Enforcement, United States Nuclear Regulatory Commission, Washington, D.C. 20555-0001; and the NRC Resident Inspector at the Susquehanna Steam Electric Station. In addition, if you disagree with the cross-cutting aspect of any finding in this report, you should provide a response within 30 days of the date of this inspection report, with the basis for your disagreement, to the Regional Administrator, Region l, and the NRC Resident Inspector at the Susquehanna Steam Electric Station. The information you provide will be considered in accordance with Inspection Manual Chapter 0305.

Additionally, the inspectors reviewed Licensee Event Report (LER) 5Q-38712010-001-00, which described the details associated with exceeding the Technical Specification (TS) limit for as-found minimum pathway secondary containment bypass leakage. Although this issue constitutes a violation, the NRC concluded that this issue was not in PPL's ability to foresee and correct, PPL's actions did not contribute to the degraded condition, and that actions taken were reasonable to address this matter. As a result, the NRC did not identify a performance deficiency. A risk evaluation was performed and the issue was determined to be of very low safety significance, Based on the results of the NRC's inspection and assessment, I have been authorized, after consultation with the Director, Office of Enforcement, to exercise enforcement discretion in accordance with Section 3 of the NRC Enforcement Policy, "Use of Enforcement Discretion."

In accordance with 10 CFR 2.390 of the NRC's "Rules of Practice," a copy of this letter, its enclosure, and your response (if any), will be available electronically for public inspection in the NRC Public Document Room or from the Publicly Available Records (PARS) component of the NRC's document system (ADAMS). ADAMS is accessible from the NRC Web site at http://www.nrc.qov/readinq-rm/adams,html (the Public Electronic Reading Room).

Sincerely, Division of Reactor Projects DocketNos. 50-387;50-388 License Nos. NPF-14, NPF-22

Enclosures:

Inspection Report 05000387/201 1003 and 05000388/201 1003 Attachment: Supplemental Information

REGION I Docket No: 50-387, 50-388 License No: NPF-14, NPF.22 Report No: 05000387/201 1003 and 05000388/201 1003 Licensee: PPL Susquehanna, LLC Facility: Susquehanna Steam Electric Station, Units 1 and 2 Location: Benivick, Pennsylvania Dates: April 1 ,2011through June 30, 2011 Inspectors: P. Finney, Senior Resident Inspector J. Greives, Resident lnspector E. Torres, Project Engineer J. Furia, Senior Health Physicist A. Rosebrook, Senior Project Engineer J. Brand, Reactor Engineer P. Kaufman, Senior Reactor Inspector Approved By: Paul G. Krohn, Chief Projects Branch 4 Division of Reactor Projects Enclosure

REPORT DETAILS Summarv of Plant Status Susquehanna Steam Electric Station (SSES) Unit 1 began the inspection period at 100 percent reactor thermal power (RTP). The unit was shutdown on May 16 to support extent of condition inspections on its low pressure main turbine blades. On June 22, a reactor startup was commenced. Unit 1 reached full RTP on the last day of the inspection period.

Unit 2 began the inspection period at 89 percent RTP in a refueling power coastdown. The unit was shutdown on April 4 for a refueling outage. On June 26, a reactor startup was commenced and power ascension from 16 percent RTP was in progress when the inspection period ended.

Note: The licensed RTP for both units is 3952 megawatts thermal. The Extended Power Uprate (EPU) License Amendment for SSES was approved in January 30, 2008, and was implemented for both units in accordance with the issued license conditions. The authorized power level for Unit 1 is 100 percent of the EPU licensed power limit. For the purposes of this report and the remainder of current operating cycle, the authorized power level for Unit 2 is 100 percent of the EPU licensed power limit.

1. REACTORSAFETY Gornerstones: Initiating Events, Mitigating Systems, and Barrier Integrity 1R01 Adverse Weather Protection Summer Readiness of Offsite and Alternatinq Current (AC) Power Svstems (71111.01 -

1 Grid Stability sample)

a. Inspection Scope The inspectors reviewed plant features and procedures for operation and continued availability of offsite and alternate AC power systems. The review included procedures affecting the operation or reliability of these systems as well as communications protocols between the transmission system operator and the plant. The inspectors evaluated the material condition of the associated equipment through interviews, review of related items in CAP, and walkdowns of the 500kV and 230 kV switchyards.

Documents reviewed are listed in the Attachment.

. Common, summer readiness of offsite and alternate AC power systems.

b. Findinos No findings were identified.

Enclosure

1R04 EouipmentAliqnment

.1 Partial Walkdown (71111.04Q - 3 samples)

a. Inspection Scope The inspectors performed partial walkdowns to verify system and component alignment and to identify any discrepancies that would impact system operability. The inspectors verified that selected portions of redundant or backup systems or trains were available while certain system components were out-of-service (OOS). The inspectors reviewed selected valve positions, electrical power availability, and the general condition of major system components. Documents reviewed are listed in the Attachment. The walkdowns included the following systems:

. Unit 1, SCIVs;

. Unit 2, supplemental decay heat removal (SDHR); and

. Common, Unit 1 service water supply to Unit 2 turbine building closed cooling water (TBCCW) heat exchanger (HX).

Findinos lntroduction: The inspectors identified a Green NCV of Susquehanna Units 1 and 2 TS 3.6.4.2, "Secondary Containment lsolation Valves" and TS 5.4.1, "Procedures" for an inadequate surveillance procedure for implementing TS surveillance requirements and action statements. Specifically, the procedure failed to ensure that SCIVs were verified administratively when in a high radiation areas as required. Thus, the requirements of TS action statement 3.6.4.2 A.2 were not met when two temporary systems were installed and the associated blind flanges, credited as passive SClVs, were removed.

Description: On March 2, 2011, penetrations flanges were removed to support installation of temporary systems, SDHR and temporary drywell (DW) cooling. The six flanges that were removed are listed in Unit 1 and 2 TS 3.6.4.2, "SClVs" under Table B 3.6.4.2-2 as SCIV Passive lsolation Valves or Devices. Unit 1 and 2 TSs 3.6.4.2 requires that each required SCIV be operable in Modes 1, 2, and 3 as well as during movement of irradiated fuel assemblies in the secondary containment, during core alterations and during operations with the potential to drain the reactor vessel. At the time of flange removal, both Unit 1 and Unit 2 were in Mode 1, and the TS requirements were applicable.

Surveillance Requirement (SR) 3.6.4.2.1specifies that each secondary containment isolation manual valve and blind flange that is required to be closed during accident conditions be verified closed every 31 days. This SR is modified by two notes that state that 1) valves and blind flanges in high radiation areas may be verified by use of administrative means; and 2) that the SR is not required to be met for SCIVs that are open under administrative controls. PPL implements this SR by use of three implementing procedures, SO-000-010, Revision 23, "Monthly Zone lll lntegrity," SO-100-010, Revision 24, "Monthly Zone 1 Integrity Verification," and SO-200-010, Revision 24, "Monthly Zone ll lntegrity Verification."

Enclosure

The TS bases define blind flanges, such as the six removed, as passive devices.

Additionally, TS bases state that "blind flanges are considered operable when . . . they are in place." Therefore, when the flanges were removed, they should have been declared inoperable and the required actions per the appropriate TS action statement followed. For these devices, since the flow paths they isolate have two SClVs, required action A.1 and A.2 should have been followed. Action statement A.1 requires that the affected flow path be isolated "by use of at least one closed and deactivated automatic valve, closed manual valve, or blind flange" within 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br />. Action statement A.2 requires that the affected flow path be verified as isolated once per 31 days. This action statement is modified by a note that states "isolation devices in high radiation areas may be verified by use of administrative means."

On May 11, 2011, the inspectors recognized that PPL was not tracking adherence with TS 3.6.4.2 and questioned plant operators regarding how the flanges were being considered operable. PPL responded that the implementing procedures for SR 3.6.4,2.1 requires the blind flanges to be installed, but is allowed by a note to be "N/A" if the penetration is in use in accordance with a plant procedure/work document. Engineering Work Request (EWR) 1405162 was generated to verify the justification for allowance to

"N/A" verification of the removed flanges.

Upon review of the completed EWR, the inspectors continued to question the validity of the response as it pertained to TS 3.6.4.2. Specifically, PPL stated that because the second valve in each flow path was shut, the standby gas treatment systems (SGTSs)

would be able to draw down containment as required and thus secondary containment was operable. Though the EWR addressed how secondary containment was operable per TS 3.6.4.1 "Secondary Containment," the inspectors questioned how the practice was allowed and met the TS requirements for SClVs. Following additional questions by the inspectors, CR 1423156 was generated to evaluate the note in the surveillance procedure. PPL's response concluded that the blind flanges were not required to be operable since the second isolation valve was shut and controlled by a work activity.

PPL contended that this allowed the practice of not requiring the flanges be checked during the monthly secondary containment verification.

The inspectors reviewed PPL's response, consulted with the Nuclear Reactor Regulation Technical Specification staff, and determined that this was an inappropriate interpretation of the TSs. As discussed in the TS Bases, the blind flanges were inoperable as passive SCIVs and the appropriate required action should have been performed. During review of the activity, the inspectors determined that required action A.1 was met, though unintentionally, because the flow paths are normally isolated by closed manual valves as required by the maintenance action plan. However, the isolation valves were not verified every 31 days as required by required action A.2. As discussed previously, this action is modified by a note that allows verifying valves in high radiation areas by administrative means. This was implemented by the surveillance procedures by a note that states "Enter'N/A" if component is not accessible due to as low as is reasonably achievable (ALARA) concerns." The inspectors determined that this was inappropriate since no active verification by administrative means was performed. Since several of the valves that were serving the function of isolating the secondary containment flow paths are inside high radiation areas, no active verification of valve position was performed for the period from March 2,2011 until Mode 4 was achieved and the TS was no longer applicable, April 5 for Unit 2 and May 17 for Unit 1.

Enclosure

The inspectors also discovered while required valves located outside of high radiation areas were verified by the surveillance procedure, the frequency exceeded 31 days.

PPL had incorrectly applied a grace period to the SR; however, since this SR also was being used to meet the requirements of a TS action statement the application of a grace period is not permitted. Thus, the required action statement was not met.

After additional review of the SR implementing procedures, the inspectors determined that the deficiency that allowed the performer to enter N/A for valves due to ALARA concerns was previously recognized in July 2005 and entered into PPL's CAP as CR 694160. The evaluation performed concluded that the practice of entering "N/A" without amplifying the administrative means that were used to verify position was inadequate and created ARyOPG 694156 to update the SOs. However, this action was not started until January 2011 and was only partially completed, in that only one page of one of the SOs was updated. The inspectors determined that if the corrective actions had been implemented as required, the SR would not have been missed and the required action A.2 would also have been completed, though coincidentally. PPL entered this issue in their CAP as CRs 1421356 and 1431750.

Analysis: Failure to have an adequate procedure to implement TS SRs and Action Statements is a performance deficiency which was reasonably within PPL's ability to foresee and correct. The finding is more than minor because it was similar to example 3.d in IMC 0612, Appendix E, "Examples of Minor lssues" in that the failure to implement a requirement of TS is not minor if the action had not been conducted. In this case, the valves inside of high radiation areas had not been verified in their closed position as required by TS 3.6.4.2 Required Action A.2 and SR 3.6.4.2.1. Additionally, it is associated with the procedure quality attribute of the Barrier Integrity cornerstone objective to provide reasonable assurance that physical design barriers protect the public from radionuclide releases caused by accidents or events. Specifically, the inadequate surveillance procedure resulted in a violation of TS 3.6.4.2, "SClVs" since valves that were closed to isolate a pathway due to an inoperable blind flange were not verified in the correct position as required. The finding was evaluated for significance using IMC 0609, Attachment 4, "Phase 1 - Initial Screening and Characterization of Findings." Since the finding only represented a degradation of the radiological barrier function provided for the RB (i.e. secondary containment), the finding was determined to be of very low safety significance (Green).

This finding is related to the cross-cutting area of Human Performance - Resources because PPL did not ensure that personnel, equipment, procedures, and other resources were available and adequate to assure nuclear safety. Specifically, the surveillance procedures SO-000-010, Revision 23, "Monthly Zone lll Integrity," SO-100-010, Revision 24, "Monthly Zone 1 Integrity Verification" and "SO-200-010," Revision 24,

"Monthly Zone ll Integrity Verification," did not ensure surveillance requirements or actions statements required by TS 3.6.4.2 were implemented. (H.2(c))

Enforcement: Susquehanna Units 1 and 2 TS 3.6.4.2 , "Secondary Containment lsolation Valves," requires that each required SCIV be operable as specified by the applicability statement, and requires specific action be taken if any SCIV is determined to be inoperable. TS 5.4.1, "Procedures," requires that written procedures be established, implemented and maintained as recommended in Regulatory Guide 1.33, Revision 2, Appendix A, February 1978. Regulatory Guide 1.33, Appendix A, requires implementing procedures for each surveillance listed in TSs. Contrary to the above, passive secondary containment isolation devices specified as SCIVs were made Enclosure

inoperable to install a temporary outage system without the appropriate actions statement being followed. The SR implementing procedure inappropriately allowed entering "N/A" if the device was removed per a procedure or work document.

Specifically, the surveillance procedures SO-000-010, Revision 23, "Monthly Zone lll Integrity," SO-100-010, Revision 24, "Monthly Zone 1 lntegrity Verification" and "SO-200-010," Revision 24, "Monthly Zone ll Integrity Verification," did not ensure surveillance requirements or actions statements required by TS 3.6.4.2 were implemented. As a result, SR 3.6.4.2.1 and required action statement A.2 were not performed for valves inside high radiation areas because the implementing procedure allowed entering "N/A" for valves due to ALARA concerns. Because this finding is of very low safety significance and has been entered into PPL's corrective action program (CRs 1421356 and 1431750), this violation is being treated as an NCV consistent with section 2.3.2 of the NRC Enforcement Policy. (NCV 05000387&38812011003-01, lnadequate Surveillance Procedure Results in Failure to Meet Required Action of Technical Specifications for Secondary Containment lsolation Valves)

.2 Complete Walkdown (71111.04S - 1 sample)

a. Inspection Scope The inspectors performed a detailed review of the alignment and condition of Division ll of the Unit 1 RHR system. The inspectors reviewed operating procedures, checkoff lists, and system piping and instrumentation drawings. Walkdowns of accessible portions of the systems were performed to verify components were in their correct positions and to assess the material condition of systems and components. The inspectors evaluated ongoing maintenance and outstanding CRs associated with the RHR system to determine the effect on system health and reliability. The inspectors verified proper system alignment and looked at system operating parameters. The walkdown included the following system:

. Unit 1, Division ll of RHR.

b. Findinqs No findings were identified.

1R05 Fire Protection

.1 Fire Protection - Tours (71111.05Q - 6 samples)

a. Inspection Scope The inspectors reviewed PPL's fire protection program to evaluate the specified fire protection design features, fire area boundaries, and combustible loading requirements for selected areas. The inspectors walked down these areas to assess PPL's control of transient combustible material and ignition sources, fire detection and suppression capabilities, fire barriers, and any related compensatory measures. The inspected areas included:

. Unit 1, HPCI and reactor core isolation cooling (RCIC) rooms (Fire Zones 1-1C and 1-1D; Enclosure

o Unit 1, RB elevation 749'-1", (Fire Zone 1-SA-N, S, W, 1-SH);

o Unit 1, A emergency diesel generator (EDG) bay (Fire Zone D-41A), elevations 677',

660" 750';

r Unit 2, condenser bay (Fire Zone 2-32D and 2-31D);

o Unit 2, DW during 2x1 weld overlays (Fire Zone 2-4F); and

. Common, fire pumps and fire supply (Tl-183).

b. Findinqs No findings were identified.

1R06 Flood Protection Measures

.1 Internal Floodino (71111.06 - 1 sample)

a. Inspection Scope The inspectors reviewed documents, interviewed plant personnel, and walked down structures, systems and components (SSCs) to evaluate the adequacy of PPL's internal flood protection measures. The inspection focused on verifying that PPL's flooding mitigation plans and equipment were consistent with the design requirements and risk analysis assumptions. The material condition of credited components such as watertight plugs, floor drains, flood detection equipment, and alarms were also assessed to determine whether the components were capable of performing their intended function.

The inspectors also verified that adequate procedures were in place to identify and respond to floods. Documents reviewed are listed in the Attachment. The following area was reviewed:

. Unit 1, RB - 683'

b. Findinos No findings were identified.

1R07 Heat Sink Performance Heat Sink Annual Review (71111.07A-'1 sample)

a. lnspection Scope The inspectors selected the 28 RHR HX for review to determine its readiness and availability to perform its safety functions. This review was performed to ensure the performance capability for the 28 RHR HX was consistent with design assumptions.

The inspectors conducted a visual inspection of the tubesheet and endplate before and after cleaning as well as a review of eddy current test data. Finally, the inspectors reviewed the tube plugging repair work order. Documents reviewed are listed in the Attachment.

. Unit 2, 28 RHR HX.

Enclosure

b. Findinqs No findings of significance were identified.

1R08 Inservice Inspection - Unit 2 Susouehanna (71111.08 - 1 sample)

a. Inspection Scope A review of implementation of inservice inspection (lSl) program activities for monitoring degradation of the reactor coolant system boundary and risk significant piping system boundaries for SSES Unit 2 was conducted from April 1 1-14,2011. The sample selection was based on the inspection procedure objectives and risk priority of those components and systems where degradation would result in a significant increase in risk of core damage. The inspectors reviewed documentation, observed in-process nondestructive examinations (NDE) and interviewed inspection personnel to verify that the activities were performed in accordance with the requirements of 10 CFR 50.55a, American Society of Mechanical Engineers (ASME) Boiler and Pressure Vessel Code Section Xl, 2001 Edition, 2003 Addenda, and SSES risk informed lSl program.

Nondestructive Examination (NDE) Activities:

The inspectors performed direct observations of various NDE activities in-process and reviewed documentation of NDEs listed below during the SSES Unit 2 refueling outage 1SRtO:

Volumetric examination - Ultrasonic Testing (UT) and Radiographic Testing (RT):

Direct field observation of manual performance demonstration initiative (PDl}-UT of NSB core spray nozzle dissimilar metal (DM) safe-end to safe-end extension weld; Record reviews - UT examination data sheets of NSA (UT-1 1-001) and NSB (UT-11-002) core spray DM safe-end to safe-end extension welds; and Record and Radiographic film reviews - RT inspection report lsl-09-111 (FW-29);

lsl-09-069 (FW-27); and lSl-09-070 (DM FW-34) for the installation of manual isolation ADHR 20" llex gate valve 251133.

Surface Examinations - Penetrant Testinq (PT):

. Record reviews - PT examination sheets of NSA (BOP-PT-11-099) and NSB (BOP-PT-11-097) core spray DM welds after the welds were ground down to meet PDI-UT-1 0 requirements; and o Record review - PT examination sheet of FW 26A - replacement of excess flow check valve XV243F010C reactor recirculation pump 2A suction line'

Visual - VisualTestinq (W):

r Direct observation of in-vessel visual inspection (lwl) of various reactor pressure vessel (RPV) internal components performed remotely to assess the structural integrity of components in accordance with station procedure NDE-W-005 and BWRVIP requirements; and

. Record reviews - visual examination records of drywell floor/diaphragm slab upper surface (W-11-32, 33, 35, 36, and 37).

Enclosure

The inspectors reviewed a sample of visual inspection results of reactor vessel components to evaluate the level of examiner skill, test eguipment performance, examination technique, and inspection environment (water clarity) and reviewed certifications of several technicians performing NDE and verified that the examinations were performed in accordance with approved procedures and inspection records appropriately evaluated by certified Level lll NDE personnel.

As a followup lSl inspection activity, the inspectors performed an onsite inspection to observe, review, and evaluate the repair performed ol a 4.5" through-wall vertical crack in the SSES Unit 2 steam dryer skirt panel extending into the mid-support ring weld at the 4-degree seismic block location. The inspectors reviewed customer notification report lwl-11-59 and PPL CR 1389037 initiated to report the indication (crack) in the steam dryer skirt panel. The inspectors confirmed that the crack identified was new since the Unit 2 dryer was recently fabricated and was inservice for one cycle, and that General Electric Hitachi Nuclear Energy has undertaken a cause evaluation to determine the cause of the crack. The inspectors reviewed the preliminary cause evaluation NEDC-33645P, "Steam Dryer Inspections Susquehanna Unit 2 Repair Compliance with BWRVIP-181," Revision 0, May 2011, which concluded the crack indications in the dryer skirt are most likely fatigue cracks caused by fabrication induced anomalies of the seismic blocK to skirt weld.

The inspectors verified that the repair of stop drilling was in accordance with the guidance of BWRVIP 181, Steam Dryer Repair Design Criteria, Section 13.1.1, and PPL Engineering Change 1390749, which provided additional details including the grinding/polishing/blending used to remove portions of the crack. The inspectors confirmed that the implemented repair approach of stop drilling was to produce a hole at the crack tips in order to arrest the continued propagation of the crack.

ModificationiRepair/Replacement Activities Consistinq of Weldinq on Pressure Boundarv Risk Sionificant Systems:

Review was performed by the inspectors to verify specifications and control of the welding processes, weld procedures, welder qualifications and NDE examinations were in accordance with ASME Section lll, V, lX, and Xl code requirements:

Review of work order package (PCWO 1168514)for the cut out and replacement of an ASME, Class 1 , excess flow check valve XY243F010C - reactor recirculation pump 2A suction line - FW 264; and Review of PCWO 1041669 for removal of 24" HBB-211 piping to support the installation of new manual isolation ADHR 20" flex gate valve 251133.

There were no samples available for review during this inspection that involved examinations with recordable indications that have been accepted for continued service from the previous SSES Unit 2 14RlO throughlSRlO outage.

b. Findinqs No findings were identified.

Enclosure

1R11 Licensed Operator Requalification Proqram

.1 Resident lnspector Quarterlv Review (71111.11Q - 1 sample)

a. Inspection Scope On May 31, the inspectors observed licensed operator simulator performance. The inspectors compared their observations to TSs and the use of system operating procedures. The inspectors also evaluated PPL's critique of the operators' performance to identify discrepancies and deficiencies in operator training. Documents reviewed are listed in the Attachment. The following training was observed:

. Common, OP002 11-03-01A, Integrated Control System (lCS) Manipulation, Reactivity Addition and Stratification Control.

b. Findinqs No findings were identified.

1R12 Maintenance Effectiveness (71111.12- 2 samples)

a. Inspection Scope The inspectors evaluated PPL's work practices and followup corrective actions for selected SSC issues to assess the effectiveness of PPL's maintenance activities. The inspectors reviewed the performance history of those SSCs and assessed PPL's extent of condition determinations for those issues with potential common cause or generic implications to evaluate the adequacy of PPL's corrective actions. The inspectors reviewed PPL's Pl&R actions for these issues to evaluate whether PPL had appropriately monitored, evaluated, and dispositioned the issues in accordance with PPL procedures and the requirements of 10 CFR 50.65, "Requirements for Monitoring the Effectiveness of Maintenance." In addition, the inspectors reviewed selected SSC classification, performance criteria and goals, and PPL's corrective actions that were taken or planned, to verify whether the actions were reasonable and appropriate.

Documents reviewed are listed in the Attachment. The following systems were reviewed:

o Unit 1, 18 RHRSW; and o Unit 2, HPCI steam valves.

b. Findinos No findings were identified.

1 R1 3 Maintenance Risk Assessments and Emerqerlt Work Control (7 1111 .1 3 - 5 samples)

a. Inspection Scope The inspectors reviewed the assessment and management of selected maintenance activities to evaluate the effectiveness of PPL's risk management for planned and Enclosure

emergent work. The inspectors compared the risk assessments and risk management actions to the requirements of 10 CFR Part 50.65(a)(4) and the recommendations of NUMARC 93-01, Section 11, "Assessment of Risk Resulting from Performance of Maintenance Activities." The inspectors evaluated the selected activities to determine whether risk assessments were performed when specified and appropriate risk management actions were identified.

The inspectors reviewed scheduled and emergent work activities with licensed operators and work-coordination personnelto evaluate whether risk management action threshold levels were correctly identified. In addition, the inspectors compared the assessed risk configuration to the actual plant conditions and any in-progress evolutions or external events to evaluate whether the assessment was accurate, complete, and appropriate for the emergent work activities. The inspectors performed control room and field walkdowns to evaluate whether the compensatory measures identified by the risk assessments were appropriately performed. Documents reviewed are listed in the Attachment. The selected maintenance activities included:

o Unit 2, elevated risk (Yellow) when RHR in shutdown cooling (SDC) in Mode 3; o Unit 2, maintenance plan to ensure 213 core coverage during JP 12 mixer removal and recirculation suction weld overlays; o Units 1 and 2, Yellow risk while swapping 'E'for'A' EDG; o Units 1 and 2, Orange risk during Unit 2 Division I loss of offsite power/loss of coolant accident (LOOP/LOCA) testing; and o Units 1 and 2, dual unit Orange risk during ventilation system maintenance.

b. Findinos lntroduction: The inspectors identified a Green NCV of 10 CFR 50.65(a)(a), related to the failure by PPL to manage risk for Reactor Building (RB) Plenum maintenance, as assessed, on June 1,2011 . Specifically, PPL determined that the maintenance would result in an Orange risk for both units. Risk management actions (RMAs) designated in its risk assessment, such as protecting risk significant equipment, were developed as required. However, during an equipment walkdown, the inspectors identified that a significant number of these RMAs were not implemented while the maintenance activity was being preformed. Specifically, the inspectors identified that none of the core spray divisions or safety relief valves (SRVs) on either unit had been protected. The inspectors also identified that Unit 1 Division ll low pressure coolant injection system (LPCI) had not been protected and Unit 2 Division I LPCI was only partially protected. Finally, the inspectors identified that some Unit 1 Division ll residual heat removal (RHR) shutdown cooling equipment listed as protected in the Station Leadership Report had not been protected.

Description: PPL had scheduled an entry into the RB recirculation plenum for inspections and maintenance while both units were shutdown in Mode 4. The recirculation plenum is common to both units and the work required both recirculation fans and the Standby Gas Treatment System (SGTS) to be taken OOS. PPL evaluated the risk associated with the activity in accordance with 10 CFR 50.65(aXa) and their Equipment Out of Service (EOOS) software under Action Report (AR) 1411088 and determined the risk to be Orange for both units. PPL's EOOS software consists of both an online and a shutdown risk program that calculate risk quantitatively and qualitatively.

Based on readiness and the time to implement the recommended RMAs, the activity Enclosure

was rescheduled for June 1,2011. As part of the risk assessment, PPL had developed RMAs that included a list of protected equipment, review of off-normal procedures, a contingency plan, prohibition of fuel moves or operations with potential to drain the reactor vessel, rescheduled activities, and elevated the evolution's management oversight. The protected equipment RMAs included offsite power transformers T-10 and T-20, Unit 1 and Unit 2 RHR shutdown cooling equipment and power supplies, alternate DH (decay heat) removal, emergency core cooling system (ECCS) equipment and power supplies, and to maintain primary containment integrity. This list of protected equipment was distributed to employees on orange cards as they entered the site that morning. In the shutdown configuration of both units, alternate DH removal was considered to be core spray, RHR in the LPCI mode, and SRVs as identified in the Station Leadership Report. ECCS for both units was considered LPCI and core spray.

The inspectors reviewed the risk assessment and performed walkdowns to verify that RMAs were properly implemented. During a walkdown, the inspectors identified that none of the core spray divisions or SRVs on either unit had been protected. The inspectors also identified that Unit 1 Division ll LPCI had not been protected and Unit 2 Division I LPCI was only partially protected. Finally, the inspectors identified that some Unit 1 Division ll RHR shutdown cooling equipment listed as protected in the Station Leadership Report had not been protected to include breakers for both Division ll RHR pumps, the 1D residual heat removal service water (RHRSW) pump, power for the swing bus and its motor generator (MG) sets, and power for RHR Division ll valves. ln this latter case, the protected equipment in the field was in agreement with PPL's protected equipment tracking forms but remained in disagreement with the Station Leadership Report. During subsequent questioning, PPL confirmed that the expectation was that all recommended protected equipment actions in a risk assessment would be implemented.

In addition, the inspectors determined that the protected equipment item to "maintain primary containment integrity" was not being implemented by protecting all containment penetrations but through administrative means. The inspectors concluded that this item was essentially another RMA but that containment was not protected equipment per PPL procedures. This issue was documented in PPL's CAP as CR 1441159.

PPL procedures, NDAP-QA-1902, Revision 2, "Maintenance Rule Risk Assessment and Management Program," and NDAP-QA-0340, Revision 8, "Protected Equipment Program," implement the requirements of 10 CFR 50.65(a)(a) at the station. NDAP-QA-1902, Section 6.3.3 states that the work week manager or outage organization "will provide a list of protected equipment and/or compensatory actions/risk management actions" when assessed risk is above RMA threshold, defined by colors. The procedure also provides a list of RMAs that can be used to manage the impact of increased risk.

One of the RMAs described is implementation of the protected equipment program as described in NDAP-QA-0340. NDAP-QA-0340, Revision 10, "Protected Equipment Program," Section 6.5.2 states that "protected equipment is to be clearly identified to prevent inadvertent work on or near the protected equipment" and Section 6.6.1.c ensures the plant protected equipment section of the Station Leadership Report is updated.

The inspectors observed that required RMAs were not implemented prior to entry into the period of elevated Orange risk. Failing to manage risk associated with maintenance activities is a violation of 10 CFR 50.65(aX4), was within PPL's ability to foresee and correct, and should have been prevented.

Enclosure

PPL has had repetitive issues in the area of risk assessment as evidenced by this quarter being the fifth consecutive quarter with an NCV of 10 CFR 50.65(aXa). This trend is discussed further in section 4OA2 of this report. During this period, the outage organization was staffed with an Outage Risk Assessor position as a corrective action from a previous violation of 10 CFR 50.65(aX4) documented in the NRC Integrated lnspection Report, lR 05000387;38812010003 issued August 13,2010 (ML102250028).

The inspectors determined that this corrective action was ineffective at preventing this error.

Analvsis: Failing to manage risk associated with maintenance activities is a violation of 10 CFR 50.65(aXa) and is a performance deficiency. The inspectors determined that the performance deficiency is similar to examples 3.j and 3.k of IMC 0612, Appendix E,

"Examples of Minor lssues." These examples state, in part, that an issue is more than minor if significant programmatic issues were identified that could lead to worse errors if uncorrected. The issue also affected the human performance attribute of the Mitigating Systems cornerstone and its associated objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences and its. Specifically, the issue was programmatic based on the extent of protected equipment deficiencies, and five consecutive quarters of 10 CFR 50.65(a)(4)

violations. The issue affected the Mitigating Systems cornerstone attribute and objective because the timing of the violation during dual unit Orange risk, and that if left uncorrected could lead to more significant issues such as pre-event human error that impacts mitigating equipment availability during a subsequent initiating event with already elevated plant risk. The guidance of IMC 0612, Appendix K, "Maintenance Risk Assessment and Risk Management Significance Determination Process," Flowchart 2 applies. Since the exposure time of the deficiency was limited to four hours and with consideration of the other RMAs taken by PPL, incremental core damage probability (ICDP) and incremental large early release probability (ILERP)were determined not to be greater than 1E-6 and 1E-7 respectively. Therefore, this finding is determined to be of very low safety significance (Green).

This finding was determined to have a cross-cutting aspect in Pl&R, CAP, in that a licensee takes appropriate corrective actions to address safety issues and adverse trends in a timely manner, commensurate with their safety significance and complexity.

Specifically, although PPL had recognized the negative trend with execution of an RCA, interim corrective actions for the adverse trend of 10 CFR 50.65(a)( ) violations proved inadequate to prevent another violation of this regulation for the fifth consecutive quarter.

(P.1 (d))

Enforcement: 10 CFR 50.65(a)(a)states, in part, that before performing maintenance activities, "The licensee shall access and manage the increase in risk that may result from the proposed maintenance activities.' PPL procedures NDAP-QA-1902, Revision 2, "Maintenance Rule Risk Assessment and Management Program," and NDAP-QA-0340, Revision 8, "Protected Equipment Program," implement the requirements of 10 CFR 50.65a4) at the station. Contrary to the above, on June 1, 2011, a four hour period of Orange risk existed on both units that required implementation of RMAs to manage risk and PPL did not implement all RMAs while maintenance was conducted.

Specifically, PPL did not protect: the core spray divisions or safety relief valves on either unit; the Unit 1 Division ll low pressure coolant injection (LPCI) system; and portions of the Unit 2 Division I LPCI system. Finally, the inspectors identified that some Unit 1 Division ll residual heat removal (RHR) shutdown cooling equipment listed as protected Enclosure

in the Station Leadership Report had not been protected. Because of the very low safety significance of this finding and because the finding was entered into PPL's CAP as CR 1417135, this violation is being treated as an NCV, consistent with Section 2.3.2 of the NRC Enforcement Policy. (NCV 05000387&388/2011003-02, Failure to lmplement Risk Management Actions during Dual Unit Elevated Risk)

1R15 Operabilitv Evaluations (71111.15 - 3 samples)

a. Inspection Scope The inspectors reviewed operability determinations that were selected based on risk insights to assess the adequacy of the evaluations, the use and control of compensatory measures, and compliance with TSs. ln addition, the inspectors reviewed the selected operability determinations to evaluate whether the determinations were performed in accordance with NDAP-QA-0703, "Operability Assessments." The inspectors used the TSs, Technical Requirements Manual (TRM), Final Safety Analysis Report (FSAR), and associated Design Basis Documents as references during these reviews. Documents reviewed are listed in the Attachment. The issues reviewed included:

. Unit 1, DW to Suppression Pool (SP) vacuum breaker actuation piston installed without cushion cap; e Unit 2, HPCI steam supply valve HV255F001; and

. Unit 2, SP cooling/SP spray operability while RHR aligned for SDC in Mode 3.

b. Findinqs No findings were identified.

1R18 Plant Modifications

.1 Temporarv Plant Modifications (71111.18 - 2 samples)

a. Inspection Scope The inspectors reviewed temporary plant modifications to determine whether the changes adversely affected system or support system availability, or adversely affected a function important to plant safety. The inspectors reviewed the associated system design bases, including the FSAR, TSs, and assessed the adequacy of the safety determination screening and evaluation. The inspectors also assessed configuration control of the changes by reviewing selected drawings and procedures to verify that appropriate updates had been made. The inspectors compared the actual installation to the modification documents to determine whether the implemented change was consistent with the approved documents. The inspectors reviewed selected post-installation or removal test results as appropriate to evaluate whether the actual impact of the change or removal had been adequately demonstrated by the test. The following modifications were included in the review:

o Unit 1, turbine first stage pressure relay fuses pulled; and

. Common, 'E'DG operable with heating, ventilation and air-conditioning (HVAC)

supply fan removed.

Enclosure

b. Findinos No findings were identified.

1R19 Post-Maintenance Testino (71111.19 - 4 samples)

a. Inspection Scope The inspectors observed portions of post-maintenance test (PMT) activities in the field to determine whether the tests were performed in accordance with the approved procedures. The inspectors assessed the test adequacy by comparing the test methodology to the scope of maintenance work performed. In addition, the inspectors evaluated acceptance criteria to determine whether the test demonstrated that components satisfied the applicable design and licensing bases and TS requirements.

The inspectors reviewed the recorded test data to determine whether the acceptance criteria were satisfied.

The inspectors reviewed PMT activities relating to EPU design changes for the reactor feed pump turbine speed control unit. Specifically, the review included the initial reactor feed pump turbine (RFPT) uncoupled operational tests.

o Unit 2,2X240 VAC transformer replacement; o Unit 2, Suppression Chamber-to-DW vacuum breakers;

. Unit 2, RCIC overhaul; and r Unit 2, RFPT uncoupled runs (EPU).

b. Findinqs No findings were identified.

1R20 Refuelino and Other Outaqe Activities (71111.20 - 2 samples)

.1 Unit 2 Refuel Outaqe (RFO)

a. Inspection Scope The Unit 2 RFO (2R15) was conducted from April 5 through June 29, 2011. During the outage and through reactor startup, as appropriate, inspectors performed the activities below to verify PPL's controls over outage activities:

o Outage Plan - reviewed the outage risk plan and work schedules for staff on both the operating unit and the shutdown unit;

. Shutdown activities - monitored the shutdown, cooldown, and transfer to the shutdown cooling mode of decay heat removal;

. Outage activity control - monitored or verified the following:

1) Clearance activities; 2) RCS Instrumentation; 3) Electrical power; 4) DH removal and spent fuel pool cooling; 5) Inventory and reactivity control; 6) Containment Closure; and Enclosure

7) Fatigue management.

o DW and suppression chamber - walkdowns after shutdown; o Refueling activities - independent review of core alterations;

. Monitoring of Heatup and Startup Activities;

. lmplementation of EPU testing plan; ldentification and Resolution of Problems - reviewed CAP entries to verify an adequate threshold for issues and appropriate corrective actions; and lmplementation of the EPU testing plan During the conduct of the refueling inspection activities, the inspectors reviewed the associated documentation to ensure that the tasks were performed safely and in accordance with plant TS requirements and operating procedures.

b. Findinos No findings were identified.

,2 Unit 1 Low Pressure Turbine Outaqe Inspection Scope A Unit 1 forced outage was conducted from May 16 through June 24, 2011 , to support extent of condition inspections on the associated low pressure main turbine blades. The inspectors observed the plant shutdown, maintenance, inspection, and radiological control activities associated with the low pressure main turbine. No inspections of primary containment occurred as PPL did not make an entry into the primary containment. During the outage and through reactor startup, as appropriate, inspectors performed the activities below to verify PPL's controls over outage activities:

. Outage Plan - reviewed the outage risk plan and work schedules for staff;

. Shutdown activities - monitored the shutdown, cooldown, and transfer to the shutdown cooling mode of DH removal;

. Outage activity control - monitored or verified the following:

1 Clearance activities; 2 RCS Instrumentation; 3 Electrical power; 4 DH removal and spent fuel pool cooling; 5 Inventory and reactivity control; 6 Containment Closure; and 7 Fatigue management.

o Monitoring of Heatup and Startup Activities; and

. ldentification and Resolution of Problems - reviewed CAP entries to verify an adequate threshold for issues and appropriate corrective actions.

Findinqs No findings were identified.

Enclosure

1R22 Surveillance Testinq (71111.22 - 6 samples; 4 routine surveillance and 2 isolation valves)

a. Inspection Scope The inspectors observed portions of selected surveillance test activities in the control room and in the field and reviewed test data results. The inspectors compared the test results to the established acceptance criteria and the applicable TS or TRM operability and surveillance requirements to evaluate whether the systems were capable of performing their intended safety functions. The observed or reviewed surveillance tests included:

o Unit 1, low power range monitor (LPRM) calibration and validation; r Unit 1, reactor vessel level quarterly surveillance test;

. Unit 2, HPCI turbine penetration, (PCIV);

o Unit 2, 'B' Feedwater line penetration, (PCIV);

. Unit 2, Division I LOOP/LOCA testing; and .

. Unit 2, Division ll RHR logic system functional test.

b. Findinqs No findings were identified.

lEPO Drill Evaluation (71114.06 - 1 EP Drill sample)

a. Inspection Scope The inspectors reviewed the combined functional drill scenario and observed selected portions of the drill in the emergency operations facility. The inspection focused on PPL's ability to properly conduct emergency action level (EAL) classification, notification, and protective action recommendation activities and on the evaluators' ability to identify observed weaknesses andlor deficiencies within these areas. Ten performance indicator (Pl) opportunities were included in the scenario.

The inspectors attended the post-drill critique and compared identified weaknesses and deficiencies including missed Pl opportunities against those identified by PPL to determine whether PPL was properly identifying weaknesses and failures in these areas.

The drill evaluation sample included:

. Common, HP Drill (Green Team), June 28, 2011.

b. Findinqs No findings were identified.

Enclosure

RADIATION SAFETY Occupational/Public Radiation Safety (PS)

2RS1 Radioloqical Hazard Assessment and Exposure Controls (71124.01)

a. Inspection Scope Radioloqical Hazard Assessment The inspectors selected radiologically risk-significant work activities that involved exposure to radiation. The inspectors verified that appropriate pre-work surveys were performed which 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:

. ldentification of hot particles;

. The presence of alpha emitters; r The potentialfor airborne radioactive materials, including the potential presence of transuranics and/or other hard-to-detect radioactive materials; o The hazards associated with work activities that could suddenly and severely increase radiological conditions; and

. Severe radiation field dose gradients that can result in non-uniform exposures of the bodY.

Radiolooical Hazards Control and Work Coveraqe During tours of the facility and review of ongoing work selected above, the inspectors evaluated ambient radiological conditions. The inspectors verified that existing conditions were consistent with posted surveys, radiation work permits (RWPs), and worker briefings, as applicable.

During job performance observations, the inspectors verified the adequacy of radiological controls, such as required surveys, radiation protection job coverage, and contamination controls. The inspectors evaluated PPL's means of using electronic personnel dosimeters in high noise areas as high radiation area monitoring devices.

The inspectors verified that radiation monitoring devices were placed on the individual's body consistent with the method that PPL was employing to monitor dose from external radiation sources. The inspectors verified that the dosimeter was placed in the location of highest expected dose or that PPL was properly employing an NRC-approved method of determining effective dose equivalent.

For high-radiation work areas with significant dose rate gradients (a factor of 5 or more),

the inspectors reviewed the application of dosimetry to effectively monitor exposure to personnel. The inspectors verified that PPL controls were adequate. The inspectors reviewed RWPs for work within airborne radioactivity areas with the potential for individual worker internal exposures, The inspectors evaluated airborne radioactive controls and monitoring, including potentials for significant airborne contamination. For these selected airborne radioactive material areas, the inspectors verified barrier integrity and temporary high-efficiency particulate air ventilation system operation.

Enclosure

The inspectors examined PPL's physical and programmatic controls for highly activated or contaminated materials stored within spent fuel and other storage pools. The inspectors verified that appropriate controls were in place to preclude inadvertent removal of these materials from the pool.

The inspectors conducted selective inspection of posting and physical controls for high radiation areas and very high radiation aieas, to the extent necessary to verify conformance with the occupational Pl.

Radiation Worker Performance During job performance observations, the inspectors observed radiation worker performance with respect to stated radiation protection work requirements. The inspectors determined that workers were aware of the significant radiological conditions in their workplace and the RWP controls/limits in place and that 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 determined that there was no observable pattern traceable to a similar cause. The inspectors determined that this perspective matched the corrective action approach taken by PPL to resolve the reported problems. The inspectors discussed with the radiation protection manager any problems with the corrective actions planned or taken.

Radiation Protection Technician Proficiencv During job performance observations, the inspectors observed the performance of the radiation protection technician with respect to radiation protection work requirements.

The inspectors determined that technicians were aware of the radiological conditions in their workplace and the RWP controls/limits and that 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 determined that there was no observable pattern traceable to a similar cause. The inspectors determined that this perspective matched the corrective action approach taken by PPL to resolve the reported problems.

b. Findinqs No findings were identified.

2RS2 Occupational ALARA Plannino and Controls (7 1 124.02)

a. Inspection Scope Verification of Dose Estimates and Exposure Trackinq Svstems The inspectors evaluated PPL's method of adjusting exposure estimates, or re-planning work, when unexpected changes in scope or emergent work were encountered. The Enclosure

inspectors determined that adjustments to exposure estimates were based on sound radiation protection and ALARA.

Rad iation Worker Performa nce The inspectors observed radiation worker and radiation protection technician performance during work activities being performed in radiation areas, airborne radioactivity areas, or high radiation areas. The inspectors concentrated on work activities that present the greatest radiological risk to workers. The inspectors determined that workers demonstrate the ALARA philosophy in practice and that there were no procedure compliance issues.

b. Findinos No findings were identified.

2RS7 Radioloqical Environmental Monitorino Proqram (REMP) (71124.07) (1 sample)

a. lnspection Scope The inspectors reviewed the annual radiological environmentaloperating reports, and the results of any PPL assessments since the last inspection, to verify that the REMP was implemented in accordance with the plant technical specifications (TS) and the off-site dose calculation manual (ODCM). The inspectors reviewed the report for changes to the ODCM with respect to environmental monitoring, commitments in terms of sampling locations, monitoring and measurement frequencies, land use census, interlaboratory comparison program, and analysis of data.

The inspectors reviewed the ODCM to identify locations of environmental monitoring stations. The inspectors reviewed the FSAR for information regarding the environmental monitoring program and meteorological monitoring instrumentation. The inspectors also reviewed the annual effluent release report and the 10 CFR Part 61, "Licensing Requirements for Land Disposal of Radioactive Waste," report to determine if PPL was sampling, as appropriate, for the predominant and dose-causing radionuclides likely to be released in effluents.

Site lnspection The inspectors walked down air sampling stations and thermoluminescent dosimeter (TLD) monitoring stations and determined that they were located as described in the ODCM and determined the equipment material condition to be acceptable. For the air samplers and TLDs selected, the inspectors reviewed the calibration and maintenance records to verify that they demonstrate adequate operability of these components.

Additionally, the inspectors reviewed the calibration and maintenance records of composite water samplers. The inspectors also verified that PPL had initiated sampling of other appropriate media upon loss of a required sampling station.

The inspectors observed the collection and preparation of environmental samples from different media. The inspectors verified that environmental sampling was representative of the release pathways as specified in the ODCM and that sampling techniques were in accordance with procedures. Based on direct observation and review of records, the inspectors verified that the meteorological instruments were operable, calibrated, and Enclosure

maintained in accordance with guidance contained in the FSAR, NRC Regulatory Guide 1.23, "Meteorological Monitoring Programs for Nuclear Power Plants," and PPL procedures. The inspectors verified that the meteorological data readout and recording instruments in the control room and at the tower were operable.

The inspectors verified that missed and or anomalous environmental samples were identified and reported in the annual environmental monitoring report. The inspectors reviewed PPL's assessment of any positive sample results (i.e., licensed radioactive material detected above the lower limits of detection (LLD)).

The inspectors selected SSC that involved or could reasonably involve licensed material for which there is a credible mechanism for licensed material to reach ground water, and verified that PPL had implemented a sampling and monitoring program sufficient to detect leakage of these SSCs to ground water.

The inspectors verified that records, as required by 10 CFR 50.75(g), of leaks, spills, and remediation since the previous inspection were retained in a retrievable manner.

The inspectors reviewed any significant changes made by PPL to the ODCM as the result of changes to the land census, long{erm meteorological conditions (3-year average), or modifications to the sampler stations since the last inspection. The inspectors reviewed technicaljustifications for any changed sampling locations. The inspectors verified that PPL performed the reviews required to ensure that the changes did not affect its ability to monitor the impacts of radioactive effluent releases on the environment, The inspectors verified that the appropriate detection sensitivities with respect to TS/ODCM were used for counting samples (i.e., the samples meet the TS/ODCM required LLDs). The inspectors reviewed quality control charts for maintaining radiation measurement instrument status and actions taken for degrading detector performance.

The inspectors reviewed the results of PPLs' interlaboratory comparison program to verify the adequacy of environmental sample analyses performed by PPL. The inspectors verified that the interlaboratory comparison test included the media/nuclide mix appropriate for the facility.

ldentification and Resolution of Problems The inspectors verified that problems associated with the REMP are being identified by PPL at an appropriate threshold and were properly addressed for resolution in PPL's CAP. The inspectors verified the appropriateness of the corrective actions for a selected sample of problems documented by PPL that involved the REMP.

b. Findinqs No findings were identified.

Enclosure

4. OTHER ACTIVITIES 4OA1 Performance lndicator Verification

.1 Initiatinq Events (71151- 2 samples)

a. Inspection Scope The inspectors reviewed PPL's Pl data for the period of January 2010 through December 2010 to determine whether the Pl data was accurate and complete. The inspectors examined selected samples of Pl data, Pl data summary reports, and plant records. The inspectors compared the Pl data against the guidance contained in Nuclear Energy Institute (NEl) 99-02, "Regulatory Assessment Performance lndicator Guideline," Revision 6. The following performance indicators were included in this review:

. Units 1 and 2, Unplanned Scrams per 7000 Critical Hours (1E01).

b. Findinqs and Observations No findings were identified as a result of this sample review. However, on May 3, 2011, the NRC issued PPL an Annual Assessment Follow-Up Letter (M1111230066), which identified that, "The NRC's review of Susquehanna Unit 1 determined that the Unplanned Scrams per 7000 Critical Hours performance indicator (Pl) has crossed the Green-to-White threshold (i.e., greater than three unplanned scram per 7000 critical hours). Specifically, Unit t had unplanned scrams on April 22,May 14, and July 16, 2010, as well as January 25,2011. The first quarter 2011 Pl was reported to the NRC on April 21,2011."

The two scrams from the 2nd quarter 2010 (April 22, and May 14, 2010), will no longer be considered for purposes of the Pl when the 2no quarter 2011 Pl are reported to the NRC.

Thus the Unplanned Scrams per 7000 Critical hours Pl would return to Green from White. However for assessment purposes, per NRC Inspection Manual Chapter 0305, the White Pl would still be considered until the Supplemental Inspection using NRC Inspection Procedure 95002 is completed thereby closing the issue.

4c.42 fdentification and Resolution of Problems (71152)

.1 Review of ltems Entered into the Corrective Action Proqram a. lnspection Scope As specified by lP 71152, "ldentification and Resolution of Problems," and in order to help identify risk significant, repetitive, long-term or latent equipment failures, cross-cutting components or adverse performance trends for followup, the inspectors performed screening of all items entered into PPL's CAP. This was accomplished by reviewing the description of each new CR, attending management committee meetings, and viewing computerized CAP entries. Minor issues entered into the CAP as a result of inspector observations are included in the attached list of documents reviewed.

Enclosure

Findinos No findings were identified.

.2 ldentification and Resolution of Problems - Inservice Inspection Activities Inspection Scope The inspectors reviewed a sample of SSES Unit 2 condition reports, which identified flaws and other nonconforming conditions since the previous 14RlO outage and during the current 1sRlO outage. The inspectors verified that nonconforming conditions were properly identified, characterized, evaluated, corrective actions identified and dispositioned, and appropriately entered into the CAP.

Findinos No findings were identified.

.3 ldentification and Resolution of Problems- Radioloqical Environmental Monitorinq Prooram (REMP)

lnspection Scope The inspectors verified that problems associated with the REMP are being identified by PPL at an appropriate threshold and were properly addressed for resolution in PPL's CAP. The inspectors verified the appropriateness of the corrective actions for a selected sample of problems documented by PPL that involved the REMP.

b. Findinqs No findings were identified.

.4 Semi-Annual Review to ldentifv Trends (1 sample)

a. Inspection Scope The inspectors performed a review of PPL's CAP and associated documents to identify trends that could indicate the existence of a more significant safety issue. The inspectors' review was focused on repetitive equipment and corrective maintenance issues but also considered the results of daily inspector CAP item screenings discussed in Section 4OA2.1. The review also included issues documented outside the normal CAP in corrective maintenance work orders (WOs), station health reports, performance indicators, quarterly trend reports, and maintenance rule assessments. The inspectors'

review concentrated on the six month period of January 201 1 through June 2011, although some examples expanded beyond those dates when the scope of the trend warranted. Corrective actions associated with a sample of the issues identified in PPL's trend reports were reviewed for adequacy. Specific documents reviewed are listed in the Attachment.

Enclosure

Findinqs and Observations No findings were identified.

General Work Environment The inspectors reviewed usage of available programs, namely the Employee Concerns Program (ECP), anonymous ARs, and the anonymous hotline, for raising concerns over the last six months. The ECP had a total of 109 concerns opened from January to May 2011. This represents an increase of opened concerns in any five month time frame since inception of the metrics in November 2009. There were three Level 1 concerns (related to nuclear or industrial safety) opened in the first half ot 2011. The last time that a Level 1 concern was opened was in February 2010. Level 2 concerns (related to GWE or personnel issues) exhibited a steady trend, averaging 9 opened concerns per month, from April2010 to February 2011. Following that, there was a rise in opened Level 2 concerns in March to 16 and a step change to 47 in April. While there is a correlation between the refueling outage schedule and the step change (a similar change was observed during the 2010 refueling outage), this number was 13 higher than last year. With respect to the origin of the concerns, there was a significant increase in the number of concerns from Health Physics staff with 16 in the 2no quarter as compared to one in the first quarter.

Based on this data combined with 2011 CRs regarding departmental resources, the inspectors observed that the Health Physics department has a potentially emerging SCWE trend. Other departments with a relatively elevated number of concerns were Engineering and Operations. lssues generated from Security fell from eight in the first quarter to none at the time of this review. Use of the anonymous AR process remained consistent with historic data. CRs, as a subset of those anonymous ARs, also remained consistent with historic data. Use of the anonymous hotline remained infrequent, consistent with historical data, at one call in March 201 1 with the last call in April 2010.

Overall, the inspectors concluded that alternative means of raising concerns remained generally effective.

Safetv Conscious Work Environment (SCWE) Metrics Review The inspectors reviewed PPL's SCWE metrics through May 2011. The inspectors determined that PPL continues to maintain generally effective SCWE metrics to monitor the work environment at the site. In addition, workers continue to demonstrate a willingness to raise issues through the normal corrective action program, the ECP, and the anonymous AR process. No specific SCWE issues were identified.

PPL also completed a nuclear safety culture assessment (NSCA) in January 2011.

Overall results were communicated to the workforce in June 2011. The results of the NSCA showed that the nuclear safety culture has improved to the approximate level of the industry median. The ECP was rated in the first industry quartile. Compared to 2009, the number of priority organizations decreased, however portions of the maintenance organization and the health physics department continued to exhibit work environment challenges. Notwithstanding, PPL concluded that the nuclear safety culture has improved but remains fragile, with all levels of management engagement required to continue the improving trend.

Enclosure

The inspectors also noted a steady increase in the use of anonymous processes to raise concerns (i.e., anonymous action requests, hotline reports, and the employee concerns program). Other notable trends in SCWE metrics include:

o A continuing challenge with closing condition-adverse{o-quality (CAQ) correct condition and prevent recurrence (CC/PR) action items in the CAP. Specifically, the backlog of CAQ CC/PRs action items during May 2011 was 673, having grown steadily from 361 in May 2010. PPL has developed a recovery plan for this backlog (CR 1328337) which includes creation of a monitoring panel, increased focus at the functional unit manger level, and reviewing the backlog in select departments for the application of supplemental resources.

. Continuing difficulty in closing out those generalwork environment corrective actions that are greater than two years old. While the overall generalwork environment corrective action backlog has decreased steadily over the last year (May 2010 - 215, May 2011 - 135), the older actions have proven difficult to close.

. A rise in the number of lessthan-adequate generalwork environment actions related to the health physics area that involved personnel contamination events and contamination control.

10 CFR 50.65(aX4)

PPL continued to have challenges in the implementation of risk assessments and risk management actions as evidenced by a fifth consecutive calendar quarter with an NCV of 10 CFR 50.65(aXa). The resident inspectors identified a negative trend in risk assessment in the 2010 fourth quarter inspection report (lR 05000387;38812010-005)

based on Green NCVs of the regulation in the second through fourth quarters of 2010.

Since that semi-annual trend review, a licensee-identified Green NCV was noted in the first quarter 20ll inspection report (lR 05000387;38812011-044 and two violations (one NRC-identified and one licensee-identified) are noted in this inspection report documented in sections 1R13 and 4OA7 . Since the second quarter of 2010, there have been six Green NCVs of 10 CFR 50.65(a)(4) in five quarters (3 NRC-identified and 3 licensee-identified.) Based upon these findings, it does not appear corrective actions to address this adverse trend to date have been effective.

The inspectors noted two other examples of near misses with respect to risk assessment:

o On June 8, with both units in Mode 4 and the'C'EDG scheduled to be unavailable, Unit 1 risk was assessed to be Yellow while Unit 2 risk was assessed to be Green. This assessment had been performed the night before by using the EOOS shutdown program for Unit 1. However, the assessor did not use the EOOS shutdown program for Unit 2. Rather, he rationalized that Unit 2 remained unaffected based on the current RHR shutdown cooling configuration as well as the EDG criteria of TS 3.8.2, "AC Sources - Shutdown." When another assessor used the EOOS shutdown programs the following morning, it was correctly identified that both units would be in a Yellow risk configuration.

. On the afternoon of June 15, SGTS hydramotor inspections were scheduled to commence. The work did not require a clearance but the 'B' SGTS fan switch Enclosure

was to be taken to the off position. Risk had been originally assessed as Green but PPL identified the same morning of the work that risk would actually be Yellow.

While these examples were near-miss events since risk was corrected prior to the system unavailability, these events demonstrated that some interim corrective actions are ineffective at preventing challenges in this area. PPL completed a RCA (CR 1347508) and a corrective action plan was approved by the Corrective Action Review Board (CARB) on May 12, 2011.

CAP - Evaluation On March 4,2011, the NRC issued its Annual Assessment Letter to PPL regarding Susquehanna performance during 2010 (ML110620317). In the letter, the NRC identified a cross-cutting theme in the CAP component of the Pl&R cross-cutting area.

Specifically, PPL had four findings with a Pl&R cross-cutting aspect of P.1(c) Corrective Action Program - Evaluation of ldentified Problems. As part of the semi-annual trend review, the inspectors reviewed PPL's scope of efforts and progress in addressing the theme. Major efforts, listed chronologically, included:

. July 30,2010, PPL generated CR 1287298, a Level 3 Evaluation Condition Not Adverse to Quality (NAQ), to conduct a common issue analysis based on sixteen NRC findings with CAP cross-cutting aspects from the third quarter of 2009 to the second quarter of 2010. The CR included corrective actions to develop, schedule, and complete training to improve apparent cause evaluations (ACEs), to require ACEs use at least one analysis tool, and to proceduralize the departmental CARB'

process. This completed common issue analysis was acknowledged by the NRC in the Annual Assessment Letter discussed above.

. August 13,2010, CR 1294155, a Level 2 NAQ, documented a potential trend in NRC findings with an Evaluation cross-cutting aspect. That CR referred to CR 1287298 for its common issue analysis and corrective actions.

o November 15, 2010, CR 1325050, a Level 2 Evaluation condition adverse to quality (CAQ), documented a third NRC finding with an Evaluation cross-cutting aspect.

That CR referred to corrective actions being executed under CR 1287298.

o February 16, 2011, CR 1356368, a Level 1 Evaluation CAQ, documented a fourth NRC finding with a cross-cutting aspect in Evaluation. This CR also referred to CR 1 287 298 corrective actions.

May 12,2011, CR 1406091, a Level 2 Cause CAQ, documented the trend in NRC findings with an Evaluation cross-cutting aspect. The ACE was not completed at the time of the inspectors review on June 13.

May 18, 2011 , PPL issued a site communication that new ACE training was to start on May 24 and that the goal was to have most personnel trained by the end of June.

The Plant Manager also issued a letter the same day stating that ACEs would require at least one formal cause analysis technique and that the ACE training (AD240) would be required by the end of June to conduct an ACE on or after July 1, It also stated that departmental CARBs would now be required for all CAP products Enclosure

in accordance with a new procedure, NDAP-00-0761, that was to be issued May 27.

The procedure requires departmental CARBs be implemented within 30 days of procedure issuance. The Plant Manager also delivered the content of his letter to the management team personally.

May 20, 2011 , a station newsletter discussed the NRC's strong end-of-cycle message about CAP issues.

May 26, 2011, as part of the site's Pl&R Action Plan, the morning leadership meeting agenda was changed to include a review of daily CAP items for the management review committee. Additionally, a site newsletter announced the requirement for CAP coaches at all core business meetings and the site began weekly Senior Leadership Team CAP recovery meetings.

May 31 to June 10,2011, PPL conducted a "CAP & Snack" initiative to engage site staff on CAP issues. PPL reported to the inspectors that the initiative was lightly attended and planned to record sessions so that staff could review them at their convenience.

o June 10- PPL discussed performance at an all-hands meeting during which performance indicator SL52, "Quality of CR Evaluation/Action Plans," was Green and annotated as "Goal Met."

Trend Analvsis The inspectors reviewed the station quarterly trending reports for the first quarter of 2011 and the last two quarters of 2010 and made the following observations.

. The Correct Condition backlog as of Marcn 2011 has shown no improvement since the second quarter of 2009. While the backlog rate flattened in the second quarter of 2011, the backlog has not been restored to initial conditions and the backlog trend prior to this was described as an adverse trend. The inspectors noted that the trend has not appeared as a potential, adverse, or resolved trend in station quarterly trend reports since the first quarter of 2410.

o Performance indicator SL51, "CAQ Correct Condition & Prevent Recurrence Backlog," was evaluated as an adverse emergent trend in December 2010 but does not appear in the list of station adverse trends.

o The April 2011 Performance Metrics identified an adverse trend in Area Contamination and Personal Contamination events. While this data came after the first calendar quarter, the first quarter station trend report was generated on May 30 suggesting that this new trend could have been incorporated.

. The NRC identified a theme in the CAP component of the Pl&R cross-cutting area, specifically Evaluation of ldentified Problems that existed as of the end of 2010. The NRC integrated inspection report for the first quarter ol2011 identified three additional findings with the same cross-cutting theme. Despite this data, the first quarter 2011 station trending report identified this theme as a potential trend.

Enclosure

Based on these observations, the inspectors determined that there were a number of trends identified by other processes or external sources that were not being reflected accurately in the station trending reports. ln other areas:

Door deficiencies were listed as a resolved trend despite a large number of CRs generated in April 2011 concerning plastic signage that was in violation of combustible signage restrictions.

Negative performance in the welding program was listed as a resolved trend despite CRs in April and May where supplementalwelders did not attend weld briefings, a torch blowback gouged a nearby plate, and weld wire was drawn for one work order but used on another three different times.

The inspectors noted that CS chilled water system was a potentialtrend in the second quarter 2010 station trend report, monitored in the third quarter 2010 report, and was not listed in the fourth quarter 2010 report. The inspectors also noted a trend regarding plant chiller Freon leaks that was monitored in the fourth quarter 2010 and resolved in the first quarter 2011 trend reports. ln relation to this, there were two NRC findings in the first quarter of 2011 related to CS chillers, one of which involved Freon leaks.

A trend in torque wrenches found out of calibration was identified as a potential trend in the second quarter 2010, an adverse trend in the third quarter, and monitored in both the fourth quarter 2010 and first quarter 2011. In relation to this, there was an NRC violation in the fourth quarter 2010 regarding measuring and test equipment control and calibration.

. Spurious half scrams during outages was a monitored trend in the second, third, and fourth quarters of 2010, and a resolved trend in the first quarter 2011 station trend report. In relation to this, Unit 1 experienced three spurious half scrams on June 14, 2011 while in Mode 4 and Unit 2 experienced a spurious half scram on April 10,12, and 21, 2011.

r Radiation and HRA posting events was a monitored trend in the second and third quarter 2010 and a resolved trend in the fourth quarter 2010 report. In relation to this, there has been one HRA posting event, a PPL-identified NCV, and three radiation posting events for the first half of 2011 as of June 16, 2011.

PPL procedure NDAP-QA-0710, "Station Trending Program," Revision 5, states that,

"trending is a method for finding and analyzing adverse trends before performance has a consequential decline. In this manner, trending contributes to reducing, but does not eliminate, the probability of consequential events." The inspectors concluded that while trending does not eliminate events, there were a significant number of trends that were either resolved around the same time that similar issues manifested themselves in regulatory findings or that have continued to exist beyond their characterization as being resolved.

EDG Challenqes On February 23,2011, the resident inspectors informed PPL management of observations regarding numerous minor challenges to EDG system health. While none Enclosure

of the issues were more than minor findings or violations, the resident inspectors noted a pattern of minor challenges. The following is a list of CRs and details.

11101110 C EDG tripped on Underfrequency after the five minute cooldown (1319594)

12t16t10 C EDG Fuel Oil Storage Tank (FOST) alarms, indication inaccurate (1 357e01 )

01115111 E EDG'74'relay failed in HVAC alarm circuit (1342832)

01t24t11 E EDG battery charger trouble alarm (1346108)

02108111 D EDG Available for Emergency light did not extinguish (1352728)

02114111 E EDG switching error during swap for A EDG (1355738)

02t14t11 A EDG did not follow cooldown sequence (1355642)

a2116111 A EDG ESW loop B supply valve did not open during EDG transfer (1356877)

02t16t11 C EDG FOST alarms, indication inaccurate (1356784)

02t21t11 D EDG starting air leak (1358908)

02122111 B EDG ESW loop A return valve did not open (1359400)

02122111 B EDG KVAR difference between meter indication and plant computer (1 35e3e6)

02123111 B EDG FOST dropped below the TS level at the end of a surveillance (1 360073)

03/31/11 E EDG supply fan would not remain running (1379413)

06107111 C EDG tripped on underfrequency during cooldown (1419873)

.5 RCA for Steam Leak on Inboard HPCI lsolation Valve (71152A- 1 annual sample)

a. lnspection Scope On February 25, 2011, while investigating the unexplained slow rise in Unit 1 DW unidentified leakage, PPL identified that the primary contributor was a steam leak from HV155F002, the HPCI steam supply inboard isolation valve. An initialengineering evaluation determined that HV155F002, a PCIV, was inoperable. The valve was shut and the HPCI system declared inoperable. This condition, and the forced outage that was required to repair the valve, were discussed in the NRC Integrated Inspection Report, lR 05000387&388/201 1002 issued May 13, 2011 (ML111330523).

The inspectors reviewed PPL's RCA to assess the reasonableness of the identified causes, ensure the corrective actions were appropriate for the identified causes, evaluate the timeliness of the corrective actions, and verify that PPL appropriately addressed both the extent of condition and extent of causes. The documents reviewed are listed in the Attachment.

b. Findinqs lntroduction: A self-revealing Green NCV of 10 CFR 50, Appendix B, Criterion lll,

"Design Control," occurred when a brass gland liner was installed in the gland for HV155F002, the HPCI steam supply inboard isolation valve, without appropriately evaluating the material and design of the liner for its potential impact on the valve packing system. lnappropriate design and fabrication of the gland liner resulted in numerous steam leaks since its installation and ultimately led to a significant steam leak that resulted in the inoperability of the PCIV, necessitating isolation of HPCI and a plant shutdown to conduct repairs.

Enclosure

Description: On February 25, 2011, HV155F002, the HPCI steam supply inboard isolation valve, was shut to isolate a steam leak that was a significant contributor to an increase in unidentified leakage in the Unit 1 drywell. Work orders were implemented to repack HV155F002. When the gland was removed, it was observed that the gland liner had fractured and the lip of the liner was embedded in the washer at the top of the packing. This allowed the liner to move up the gland by about 3/16 inches, which resulted in approximately 20 percent of the loading surface of the gland to be lost and increased the gap around the stem. The packing displaced into the gap and when the packing load on the stem was reduced below system pressure, the steam leak was initiated. Steam then began to disintegrate the packing and the leak worsened with time.

HV155F002 is listed as an automatic Primary Containment lsolation Valve in TS Table 83.6.1.3-1," Primary Containment lsolation Valve,"(Page 3 of 11). This automatic valve is required to automatically shut on indications of a HCPI steam line rupture and fully close in 50 seconds. Engineering evaluation of the as-found condition of the valve concluded that HV155F002 would not able to carry out its PCIV function and was inoperable. TS 3.6.1.3, "Primary Containment lsolation Valves," Action Statement A.1 required the affected flow path to be isolated within 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br />. As a result, the HPCI steam supply was isolated, rendering the HPCI system inoperable. Per TS 3.5,1, Action Statement D HPCI must be restored to operation within 14 days. PPL subsequently conducted a reactor shutdown and cooldown on March 3,2011.

HV155F002 is a 10-inch gate valve that has a horizontal stem orientation. During the early 1990s, PPL experienced numerous MOV failures due to stem scoring. The scoring was the result of the valve gland contacting the stem during operation. To correct this condition, several valves were modified to include a liner inserted in the packing gland.

The purpose of this liner was to prevent damage to the valve stem if it contacted the gland surface. This modification was made to HV155F002 in 1996.

PPL's RCA investigation (CR 1361274) determined that prior to 1998, gland liners were made from high zinc content brass alloy, which is susceptible to stress corrosion cracking. After 1998, the liners were made from low zinc bronze. The RCA investigation determined that the fracture of the gland liner, which was the direct cause of the valve failure, initiated as stress corrosion cracking and eventually failed due to an over-load shear fracture. The RCA determined that the root cause for the packing failure was that the gland design was changed without recognizing implications of gland liner failure on the packing system The first gland liners, including HV155F002, were installed under a work order action plan based on a design that was accepted by the valve manufacturer. When originally proposed in 1995, the installation of a liner in the packing gland was viewed as a normal maintenance activity with no impact. This was based on discussion with the valve manufacturer and engineering personnel under the assumption that the gland liner would not operate under load and would not affect the integrity of the gland and was documented under CR 95-0155. A 10 CFR 50.59 safety evaluation (SE)for this work determined that it was not a change to the facility, or procedures, or constituted a special test. Based on this conclusion, the lining of gland followers were determined to not require any type of modification or approval, and that it was a maintenance function to be handled via maintenance engineering.

During subsequent valve modifications in 1998, RIE 98-0062 was issued for "Anchor Darling Valve Brass Lined Gland Followers." The RIE addressed the impact to the Enclosure

safety of plant operation for a"bronze" liner. The bronze liner was evaluated on the basis of material compatibility and the RIE provided material guidelines for the liner. As part of the evaluation the RIE stated, "ln this application, the liner will be fitted into the existing packing follower (gland). The fit may cause stress corrosion cracking. To minimize the possibility of stress corrosion cracking, an alloy containing less than 15 percent zinc is recommended." This also addressed questions regarding the potential for high zinc content brass resulting in dezincification.

CR 98-2908 was written to address concerns regarding the material acceptability of the brass liners. The CR determined that 8 packing gland liners were made from brass, which was rejected by RIE 98-0062 based on the high zinc content. Despite this, it stated that the rejection of brass was based on a potential FSAR concern with dezincification and so, to eliminate any possible questions, the RIE elected to select a bronze with low zinc content. lt determined that the installation of brass was acceptable, though not preferred, because the gland liner is not a pressure retaining or structural component. Based on this determination, no action to replace the gland liners that were known to be made of brass was taken.

This CR and previous RlEs failed to recognize that the gland liner function also had a structural requirement and transmitted live load to the packing, nor did it recognize that it could be subjected to instant failure or movement resulting in a loss of load to the packing system under pressure. Had this been recognized during the RIE process, brass would have been considered an unacceptable material due to its susceptibility to stress corrosion cracking and action would have been taken to replace the known brass liners with bronze.

Analvsis: Failure to appropriately evaluate the design of a gland liner and its potential impact on the valve packing system for HV155F002, the HPCI steam supply inboard isolation valve, is a performance deficiency which was reasonably within PPL's ability to foresee and correct. The finding is more than minor because it is associated with the design control attribute of the Mitigating Systems cornerstone objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences (i.e., core damage). Specifically, inappropriate design of the gland liner resulted in numerous steam leaks since its installation and ultimately led to a significant steam leak that resulted in the inoperability of the PCIV and isolation of steam to the HPCI system for approximately 5 days.

The finding was determined to be of very low safety significance in accordance with IMC 0609, Appendix A, "Determining the Significance of Reactor Inspection Findings for At Power Situations" (lMC 06094) using SDP Phases 1,2 and 3. Phase 1 screened the finding to Phase 2 because it represented an actual loss of the HPCI system safety function. A Region I SRA conducted a Phase 3 analysis because the Phase 2 analysis, conducted by the inspectors using the Susquehanna Pre-Solved Risk-lnformed Inspection Notebook, indicated that the finding could be of more than very low significance.

Susquehanna Units 1 and 2 were selected for the pilot implementation of the NRC's SAPHIRE 8 risk analysis SDP interface tool using the Susquehanna specific SPAR models for the conduct of Phase 2 SDP evaluations, This tool allows the inspectors to enter specific equipment and human action failures and specify the exposure period and uses the plant specific SPAR model to calculate the increase in core damage frequency (ACDF). During the pilot period the SDP process currently documented in IMC 0609, Enclosure

including use of the Susquehanna Pre-Solved Risk-lnformed Inspection Notebook and any adOitional SRA conducted Phase 3 evaluations, represent the official result. The inspectors' use of the SDP interface was done as a pilot trial. The results of both are discussed below.

The pilot Phase 2 evaluation, conducted using the SDP interface, and the SRA cond'ucted Phase 3 evaluation, assuming that HPCI was inoperable for 5 days, indicated a ACDF in the low E-7 per year range. The dominant core damage sequence was a medium loss of coolant accident followed by a failure of high pressure cooling and failure of the operators to depressurize to allow use of low pressure core cooling systems.

Given the delta CDF, in the low E-7 range, the SRA determined that the increase in large early release frequency (LERF) would not be greater than very low significance beiause of tne 0.3 high pressure core damage sequence factor applied for BWR Mark ll containments in IMC 0609 Appendix H. Further the SRA determined that external events were not of concern given the very short < 5 day, exposure period'

This issue was determined to not have a cross-cutting aspect as this issue was not reflective of current performance. This was based on the age of design modification, which was installed in 1996 and re-evaluated in 1998'

Enforcemen!: 10 CFR 50, Appendix B, Criterion lll, "Design Control" states, in part,

"tr4easures snall also be established for the selection and review for suitability of application of materials, parts, equipment, and processes that are essential to the safety-related functions of the structures, systems and components." Contrary to this, a brass gtand liner was installed in the gland for HV155F002 without appropriately evaluating the iraterial and design of the liner and its potential impact on the valve packing system'

The failure of the valve packing system ultimately resulted in the inoperability of the PCIV, necessitating isolation of the HPCI system and a plant shutdown to conduct repairs. Because tnis tinOing is of very low safety significance and has been entered into ppL's corrective action progiam (CR 1361274), this violation is being trealed as an NCV consistent with section 2.5.2 of tfre NRC Enforcement Policy. (NCV 05000387/2011003-03, Failure to Establish Design Control Measures Associated with Installation of a Gland Liner in the HPCI Steam Supply Inboard lsolation valve.)

c. Observations As part of the scope of this sample, the inspectors reviewed the RCA to assess the reasonableness oi the identified causes, ensure the corrective actions were appropriate for the identified causes, evaluate the timeliness of the corrective actions, and verify that ppL appropriately addressed both extent of condition and extent of causes. The following observations are provided.

O rq an izationa I anLPrQSl ra m matic Co ntri b utor The RCA investigation identified that PPL had numerous opportunities to have identified this condition earlier. HV155F002 has been repacked every two years since 1996 with the exception of 1998 and 2010. In 1998 and 2010 the valve was not repacked, but a re-torque was performed to ensure packing integrity. ln 2000, 2002,2004,2006 and 2008 the valve was repacked as a result of either failing diagnostic testing or packing leakage. The five repacks mentioned were all a result of poor packing performance.

1996 Brass gland liner installed due to deep scoring on valve stem.

Enclosure

1998 Routine packing re-torque performed. Work Order (WO) noted no leakage and gland alignment was "good."

2000 Valve repacked due to low running loads. However, no CR was generated'

2002 Valve repacked due to packing leak during testing. Three CRs were generated as a result of the packing leak:

394758 - "HV155F002 - Requires Repack due to Hydro Leaks" screened the CAQ as a Level3 Conect. Action taken was to repack HV155F002.

395018 - "HV155F002 Packing Gland Follower Bronze Bushing is Loose" screened the CAQ as a Level 3 Closure based on an approved use-as-is disposition.

398043 - "Repeat Maintenance on HV155F002. This U1 HPCI Steam Supply lnboard lsolation Valve Required a Repack after 23 Months" screened the CAQ as a Level 3 Correct. A CRA was generated to evaluate valve stem centering expectations in procedures and training. The CRA was closed saying that sufficient guidance existed, no changes were required'

2004 Repacked due to signs of leakage. One CR and one EWR were generated.

. CR 560822 - "Packing Loads on HV155F002 Found Low"' This CAQ was classified as a Level 3 Evaluate. The CR included a note that stated that the Outage Control Center decided to repack the valve as a correct condition, but also required an evaluation to determine the cause of failing diagnostic testing three consecutive outages. The evaluation included a discussion of the diagnostic test results and a statement that the top ring of packing was found severely degraded. No investigation into why this condition occurred was performed. PCWO 560827 was listed as a completed corrective action.

This PCWO included a packing investigation plan for HV155F002, however, there was no evidence that the action plan was performed and instead a valve repack was performed. No new corrective actions were generated by this evaluation.

. EWR 567821- "HV155F002 cannot achieve its mission time of 4 years."

The EWR description states "the packing on this valve has had a long term poor history and has actually caused station shutdowns. The packing on this valve represents a critical single point vulnerability to station performance."

Additionally, the EWR included a note that the previous Level 3 Evaluation (CR 560822) failed to adequately address and prevent recurrence. This EWR was closed in 2005 with the following actions; changed the packing re-torque PM previously at every 4 years to every 2years and required a minimum of 2 valvestrokes as part of the re{orque. No further analysis of the packing was performed.

2006 Partial repack performed due to signs of past leakage. Additionally, the top ring of packing (braided ring) was identified as being in a degraded condition in the action taken section of the work order. Despite this, no CR was generated to document these conditions.

2008 Valve repacked due to signs of heavy leakage around entire circumference of outer diameter of packing during diagnostic testing.

. CR 996073 - "HV155F002 requires repack." This CAQ was screened as a Level 3 Correct. CR description stated that packing has a history of low life expectancy. The corrective action was to repack the valve.

2O1O Packing re-torque per routine task. lt was observed during the maintenance that the gland was cocked. The gland follower was realigned and retorqued.

. RCA 1361274 determined that it was likely during the re-torque in 2010 that the over-load stress of the gland liner was reached and the liner fractured.

Enclosure

During diagnostic testing of the valve, running loads for the valve were not constant and were indicative of an unhealthy packing set.

Based on the flawed engineering evaluation performed during the valve modification process, the gland liner was never considered as a potential cause for the packing performance problems and other corrective actions were taken. The RCA determined inat tne liner was improperly fabricated such that a sharp edge of the liner was placed in contact with the top ring of packing and this ultimately led to the repeated damage the packing, resulting in loss of load or leaks. Though not the direct cause of the liner iracture, the corrective actions that would have been necessary to improve packing performance would have likely prevented the ultimate failure'

PPL determined that weaknesses in implementation of the CAP were organizational and programmatic contributors to the event. The RCA determined that these weaknesses were being addressed by the Station Excellence Plan. However, there was no discussion or action taken to verify that current initiatives to improve PPL's CAP were sufficient to address the issues identified by this RCA. Specifically, no new corrective actions or analysis were performed to ensure that the organizational and programmatic contributors to this event are specifically covered by the Station Excellence Plan and are not reflective of current performance.

Extent of Cause In review of the charter for the RCA, the inspectors identified that the problem statement that directed the performance of extent of condition and cause potentially narrowed the focus of the reviews. The charter stated "The RCA will focus on the failure of the packing system of the HPCI F002 valve. The team will determine the cause(s) of the packing leak and corrective action(s) for the identified cause(s). Through extent of condition and extent of cause the team will look more broadly at other valve/actuator components if required." The inspectors observed that the last statement potentially influenced the team to limit the review to considering motor operated valves and processes with changes to like components.

Notwithstanding, the PPL RCA team considered numerous cause trend codes that were not assigned to a Cause or Causal Factor and reviewed previous events for trends.

SafetLCulture Review-br HV1 55F002 RCA NDAP-00-0752, Revision 10, "Cause Analysis," requires a review of safety culture for all RCAs. This is completed by reviewing each Cause and Causal Factors against the 37 safety culture aspects identified on PPL's Safety Culture Review Worksheet and entering trend codes for each safety culture aspect identified. This allows trending of the Safety bulture Cause Trend Codes and ensures the site has a healthy nuclear safety culture.

One Causal Factor identified that "less than adequate attention to detail was applied during the fabrication of the gland liner." In the Safety Culture Review Worksheet, this Causil Factor was not assigned a Safety Culture Aspect and no justification was provided as to why no aspect was applicable. ln review of the RCA, the inspectors identified two potential safety culture aspects that appeared to be appropriate for consideration. Aspect 11, "The licensee defines and effectively communicates expectations regarding procedural compliance, and personnelfollow procedures," was Enclosure

potentially appropriate because it was determined, based on interviews with current mechanical maintenance personnel, that the work instructions for fabrication of the gland liner were adequate to ensure that the dimensions were machined correctly and the personnel machining the liner in 1996 had not followed this procedural expectation.

Alternatively, Aspect 15, "The licensee thoroughly evaluates problems such that the resolutions address the causes and extent of conditions, as necessor!," was potentially appropriate, As discussed above, the RCA team identified numerous opportunities to find and correct poor packing system performance.

In subsequent conversations with the RCA team leaders, the inspectors determined that it was reasonable for the causal factor to not be assigned a safety culture aspect.

However, no justification for the deviation was documented in the RCA.

4OA3 Followup of Events (71153 - 4 samples)

.1 (Closed) LER 05000387/2010-001-00. Unit 1 Secondarv Containment Bvpass Leakaoe Exceeded On March 15,2010, during a Unit 1 refueling outage, PPL determined that the as-found minimum pathway secondary containment bypass leakage (SCBL) TS limit had been exceeded during performance of local leak rate testing (LLRT). PPL attributed the cause of the event to the RHR drywell spray penetrations' isolation valve design and the difficulty of meeting the TS limit based on the number of penetrations and valve sizes.

There were no actual consequences and analysis concluded that increases in doses would not have exceeded regulatory limits during a postulated accident.

The as-found value for Unit 1 SCBL in 2008 was 3668 sccm when the TS requirement was less than 4247 sccm. The as-found value for Unit 1 SCBL in 2010 was 7977 sccm when the requirement was 7079 sccm. A TS amendment for both Unit 1 and Unit 2 licenses raised the TS SCBL limit from 9 scfh to 15 scfh between outages. Historic SCBL tests had met the TS requirement and there was no overall trend in SCBL results.

The LER was reviewed for accuracy, the appropriateness of corrective actions, violations of requirements, and generic issues. Additionally, the inspectors reviewed the associated ACE, prior PPL LERs associated with SCBL, historic LLRTS, vendor manuals, the TS amendment to raise the SCBL limit, and the adequacy of corrective actions, Corrective actions included evaluating valve designs and configurations to determine methods to reduce leakage; performing a tra.ining needs analysis; and considering the need to adjust maintenance strategies based on the new as-found data.

A subsequent review of corrective actions determined that the training needs analysis had identified no training gaps, that changing the SCBL TS limit was not feasible, and that eliminating RHR penetrations from SCBL was not feasible. PPL's open corrective action is to implement a design change to the ECCS keepfill system to incorporate it as part of the SCBL boundary.

There was no performance deficiency as there were no prior trends to suggest the limit would be exceeded, there were no deficiencies related to maintenance practices identified by the inspectors, and the cause of exceeding the SCBL limit was not reasonably within PPL's ability to foresee and correct. In addition, PPL's analysis concluded that, during a postulated design basis accident, the increase in dose related to the elevated SCBL leak rate would not have exceeded regulatory limits. The overall failure to meet the SCBL requirement of SR 3.6.1.3.1 1, however, was a violation of TS Enclosure

3.6.1.3. Because no performance deficiency was identified, no enforcement action is warranted for this violation of NRC reguirements in accordance with the NRC's Enforcement Policy. Further, because PPL actions did not contribute to this violation, it will not be considered in the assessment process or the NRC's Action Matrix. PPL entered this issue in their CAP as CR 1243436.

In addition, the inspectors reviewed PPL's evaluation and corrective actions subsequent to identifying the violation and made the following observations:

. A correct-condition action from the ACE to perform a maintenance training needs analysis was closed without being performed; r Through inspectors questioning and a subsequent PPL engineering evaluation, it was determined that the boundary valve HV151F021A(B) actuators were not undersized as claimed in the ACE; and r NDAP-00-0752, "Cause Analysis," Revision 7, Step 8.1 requires an extent of condition for an ACE to consider the total population of items with the same undesired condition as the issue that was identified. The SCBL ACE, however, limited the extent of condition to the RHR drywell spray penetrations, For instance, the as-found 'A'feedwater penetration leaKage, which was not considered in the extent of condition boundary, was 2050 sccm, I times the historical average of 256 sccm. PPL determined that the ACE conclusion would have been unchanged with inclusion of the feedwater penetration leakage.

None of the above observations were determined to be more than minor since there was no actual safety consequences and reasonable assurance remained that physical design barriers would protect the public from radionuclide releases caused by accidents or events. PPL entered the issues into the CAP. This LER is closed.

.2 Cause lsolations On January 9,2011, engineering discovered that a single point vulnerability existed in the RB HVAC system in which a failure of a single nonsafety-related component could result in a spurious steam leak detection (SLD) isolation causing simultaneous isolation of MSlVs, HPCI, and RCIC. PPL attributed the cause of the event to less than adequate single failure analysis. There were no actual consequences and PPL concluded that, baJed on the frequency of sub-10 degree-Fahrenheit temperatures and the low failure rate of the temperature controller, the changes in CDF and LERF were minimal. The LER and its associated ACE were reviewed for accuracy, the appropriateness of corrective actions, violations of requirements, and generic issues. The inspectors documented a licensee-identified violation of 10 CFR 50 Appendix B Criterion lll,

"Design Control," because PPL failed to ensure that the design requirements specified in the Updated Final Safety Analysis Report (UFSAR) were correctly translated into specifications, drawings, procedures and instructions. The enforcement aspects of this violation are discussed further in section 4OA7. This LER is closed.

.3 Extraction Steam Svstem Leak On January 25, at 1:45 am, the field unit supervisor (FUS) and Health Physics personnel responded to the '5C'feedwater heater bay to a report of a potential steam leak. After Enclosure

observation that the steam leak had worsened, reactor power was reduced to 71 percent RTP and extraction steam to the 5C FWH string was isolated. After observation showed that the steam leak was not isolated, plant operators scrammed the reactor from 60 percent RTP. Unit 1 response to the manual scram was per design. There were no actual adverse consequences as a result of this event. PPL attributed the direct cause of the unisolable steam leak to the loss of a bleeder trip valve cover plug via steam-induced thread erosion. This erosion was caused by inadequate thread engagement and improper application of thread sealant. Inspectors had previously documented a self-revealing Green FIN because of the inadequate maintenance procedure to reinstall the bleeder trip valve cover plug (lR 05000387;388/2011002). The inspectors reviewed this LER and the corrective actions associated with this event. No further findings of significance were identified. This LER is closed.

(Closed) LER 05000387i2011-003-00, Unit 1 HPCI Inooerabilitv Due to Valve Packinq Leak On Februa ry 25, 2011, while investigating the unexplained slow rise in Unit 1 drywell unidentified leakage, it was identified that the primary contributor was a steam leak from HV155F002, the HPCI steam Supply inboard isolation valve. An initialengineering evaluation determined that HV155F002, a PCIV, was inoperable and the valve was shut and the HPCI system declared inoperable. There were no actual adverse consequences as a result of this event. PPL attributed the steam leak to a failure to recognize the implications of gland liner failure and the failure modes and mechanisms on the packing system during changes to gland design. lnspectors documented a self-revealing Green NCV because of the inadequate design of the gland liner system in Section 4OA2 of this inspection report. The inspectors reviewed this LER and the corrective actions associated with this event. No additionalfindings of significance were identified. This LER is closed.

40A5 Other Activities

.1 EPU Maior Plant Testg (71004 and 711 1 1 .19)

a. lnspection Scope The inspectors observed portions and reviewed the following major plant test. The details of this inspection sample are described in section 1R19 of this report. The test was considered an inspection sample that meets the requirements of lP 71004 02.03.c:

. Unit 2, RFPT uncoupled runs.

Findinqs and Observations No findings were identified,

,2 EPU PowerAscension (lnteqrated Plant Evolutions) (71004 and 71111.20)

a. Insoection Scope lnspectors witnessed power ascension following the Unit 2 refueling outage. Inspectors witnessed portions of all reactivity changes made to achieve specific EPU test conditions. Inspectors also reviewed operator actions, procedure adherence, and plant Enclosure

response during these integrated plant maneuvers. Power ascension was still in progress at the closure of this inspection period. This was a required inspection sample that meets the requirements of lP 71004 02.03.d.

Findinqs No findings were identified.

Nuclear Station Fuel Damage Event" a. lnspectlgn Scope The inspectors assessed the activities and actions taken by the licensee to assess its readiness to respond to an event similar to the Fukushima Daiichi nuclear plant fuel damage event. This included (1) an assessment of the licensee's capability to mitigate conditions that may result from beyond design basis events, with a particular emphasis on strategies related to the spent fuel pool, as required by NRC Security Order Section 8.5.b issued February 25,2002, as committed to in severe accident management guidelines, and as required by 10 CFR 50.54(hh); (2) an assessment of the licensee's-apability to mitigate station blackout (SBO) conditions, as required by 10 CFR 50.63 and station design bases; (3) an assessment of the licensee's capability to mitigate internal and externalflooding events, as required by station design bases; and (4) an assessment of the thoroughness of the walkdowns and inspections of important equipment needed to mitigate fire and flood events, which were performed by the licensee to identify any potential loss of function of this equipment during seismic events possible for the site.

Inspection Report 05000387; 38812011 00S (ML111310569) documented detailed results of this inspection activitY.

Findinqs No findings of significance were identified.

.4 NRC Temporary lnstru Severe Accident Manaqement Guidelines" (SAMGS)

On May 19,2011, the inspectors completed a review of the licensee's severe accident manag-ement guidelines (SAMGs), implemented as a voluntary industry initiative in the 1gg0'g, to determine (1) whether the SAMGs were available and updated, (2) whether the licensee had procedures and processes in place to control and update its _SAMGs, (3) the nature and extent of the licensee's training of personnel on the use of SAMGS, and (4) licensee personnel's familiarity with SAMG implementation.

The results of this review were provided to the NRC task force chartered by the Executive Director for Operations to conduct a near-term evaluation of the need for agency actions following the Fukushima Daiichifuel damage event in Japan. Plant-specific results for Susquehanna were provided in an Attachment to a memorandum to the Chief, Reactor Inspection Branch, Division of Inspection and RegionalSupport, dated May 27,2011. (M111 1470361)

Enclosure

.5 Followup on Traditional Enforcement AcSrns Includinq Violations.9eviations.

Confirmatorv Action Letters. Confirmatorv Orders. and Alternate Dispute Resolution gqnfirmatorvlQrders (lP 92702 - 1 sample)

Inspection Scope On January 9,2011, the NRC issued a Severity Level lV of 10 CFR 50'9(a)'

"Completeness and Accuracy of Information," when PPL failed to update the Mitigating Systems Performance lndicators (MSPls) to reflect a change in PPL's MSPI basis document. This failure resulted in inaccurate MSPI values reported to the NRC for three consecutive quarters during 2010. After the correct values were updated, no Pls crossed the GreenMhite threshold.

lnspection Procedure (lP) 92702 objective is to determine that adequate corrective actions have been implemented for traditional enforcement actions including violations.

To assess and document the licensee's corrective actions regarding the issued violation, the region elected to conduct lP 92702 and formally informed PPL of the NRC's intent to conduct this inspection via the NRC Annual Assessment letter dated March 4,2011 (ML110620317).

The inspectors reviewed PPL's ACE, related CR's, procedures and relevant references.

The inspectors conducted interviews with Plant Analysis, MOV, Maintenance Rule (MR)

and lSl engineers. All these engineering programs received a new on-line PRA model as a result of PPL's EPU project. The new on-line PRA model was the initiator of a series of events that resujteO- in tne SLIV violation issued to PPL on the 2010 4th quarter inspection report 1R201 0005.

b. Findinqs No findings of significance were identified.

c. Observationg The NRC inspectors determined that overall PPL's corrective actions were appropriate to prevent MSPI data inaccuracies in every quarterly report to the NRC as a result of a new on-line PRA model Or a change to the MSPI basis document. However, the inspectors observed that the ACE extent of condition (EOC) lacked rigor in that, potential implementation and timeliness issues were not evaluated for its existence in other programs that were also affected by the new on-line PRA model. Problems were iOentifieO with MSPI basis document data implementation into the Consolidation Data Entry (CDE) system, which calculates MSPIs reported to the NRC, as a result of the new on-line PftA model. Secondly, a timeliness problem was identified regarding MSPI basis documentation revision approval as a result of a new on-line PRA model. PPL's EOC narrowly focused on programs with a periodic data reporting requirement to an oversight authority with basis documents subject to revision and basis documents not openly conveyed to the authority or validated at the time of data reporting. Specifically, PPL did not evaluate for potential implementation and timeliness issues in the other engineering programs affected by the new on-line PftA model independently of reporting requirements to the NRC or other oversight authority'

The inspectors conducted an EOC evaluation to the most risk significant engineering Enclosure

programs (i.e., lSl, MOV, MR) affected by a new on-line PRA model. The programs were evaluated for their PRA implementation and timeliness requirements to revise the program as a result of the new model and timeliness reporting requirements to an oversight authority. The inspectors concluded that the programs were following their implementation and timeliness requirements as a result of the new PRA model.

4OAO Meetinqs. Includinq Exit On April 14,2011, the inspectors presented inspection results to Mr. and other members of his staff. PPL acknowledged the inspection results and observations presented.

On May 6,2A11, the inspectors presented inspection results to Mr. J. Helsel and other members of his staff. PPL acknowledged the findings.

On May 26, 2011, the inspectors presented Tl-184 inspection results to Mr. T. Rausch, CNO, and other members of his staff. PPL acknowledged the findings'

On June 9, 2011, the inspectors presented inspection results to Mr. J. Helsel and other members of his staff. PPL acknowledged the findings.

On June 22, 2011, the inspectors presented the inspection results to Mr. J. Petrilla, Acting Nuclear Regulatory Affairs Manager, and other members of the PPL staff.

On July 21,2011, the inspectors presented inspection results to Mr. Russ Kearney, Site Vice President, and other members of his staff. PPL acknowledged the findings. No proprietary information is presented in this report.

4C,A7 Licensee-ldentified Violations The following violations of very low safety significance (Green) were identified by PPL and are violations of NRC requirements which meet the criteria of the NRC Enforcement Policy, for being dispositioned as non-cited violations:

. On January 3,2011, PPL identified that a single point vulnerability existed in the RB heating, ventilation and air conditioning (HVAC) system in which the failure of a single nonsafety-related temperature controller coincident with outside ambient air temperatures below 10 degrees-Fahrenheit could result in a spurious SLD isolation causing simultaneous isolation of MSlVs, HPCI, and RCIC. The Updated Final Safety Analysis Report (UFSAR) 3.12.2.2.a states that "failure of any nonsafety-related SSC shall not result in failure of any safety-related SSC." Additionally, UFSAR 3.12.2.1.1 states that "redundant systems are separated from each other so that single failure of a component will not interfere with the proper operation of its redundanVdiverse component. This issue was determined to be a violation of 10 CFR 50 Appendix B, Criterion lll, "Design Control," because PPL failed to ensure that the design requirements specified above were correctly translated into specifications, drawings, procedures and instructions. The performance deficiency was determined to be more than minor because the finding was associated with the Mitigating Systems cornerstone attribute of Design Control, and affected the cornerstone objective to ensure the availability, reliability and capability of systems that respond to initiating events to prevent undesirable consequences. The Enclosure

inspectors evaluated the finding using IMC 0609, Attachment 4, "lnitial Screening and Characterization of Findings," and determined the finding was Green because it was design or qualification deficiency confirmed not to result in a loss of operability or functionality because the two required conditions had not occurred simultaneously. The issue was entered into PPL's CAP as CR 1337940.

On April 8, 2011, PPL identified that the entry to the Unit 2 drywell (RB elevation 719) did not have a proper barrier for being a HRA in accordance with Plant Technical Specification 5.7.1. Specifically, the barrier (rope) at the drywell entrance was found down on one side. This issue was determined to be more than minor based on its similarity to IMC 0612, Appendix E, example 6.9 since an HRA existed and was not barricaded. The finding was evaluated in accordance with IMC 0619 Appendix C, "Occupational Radiation Safety Significance Determination Process,"

and the inspectors determined that the finding was of very low safety significance (Green) because the finding was due to ALARA work control and the 3-year rolling average collective exposure was less than 24Q person-rem (99.7 person-rem for 2008-2010). This issue was documented in PPL's CAP as CR 1383383.

On May 4, a work activity to repair/replace the Open Indication on the 4kV alternate source breaker 2A2Arc9 was conducted from 12:00pm to 5:30pm. The work was originally scheduled to commence on May 6 at 9:00 a.m, The blocking required for the maintenance activity required the associated control power knife switch to be opened. This blocking rendered the alternate breaker unavailable to provide an alternate power source to the 24 bus. On the evening of May 4, the nightshift outage risk manager identified that Unit 2 had been in a Yellow risk period and that the outage control center and station management had been unaware. This issue was determined to be a violation of 10 CFR 50.65 (aX4), for failure to ensure work was properly modeled and evaluated for online plant risk. This finding is more than minor because it is similar to example 7.e. in NRC IMC 0612, Appendix E, "Examples of Minor lssues." This example states, in part, that failure to perform an adequate risk assessment when required by 10 CFR 50.65 (aX4) is not minor if the overall elevated plant risk would put the plant into a higher licensee established risk category. The guidance of IMC 0612 Appendix K, "Maintenance Risk Assessment and Risk Management Significance Determination Process," Flowchart 2 applies.

Since the exposure time of the deficiency was limited to five and a half hours and other backup sources of electrical power remained available (i.e., the other offsite source and the onsite EDG's), incremental core damage probability (ICDP) and incremental large early release probability (ILERP) were determined not to be greater than 1E-6 and 1E-7 respectively. Therefore, this finding is determined to be of very low safety significance (Green). The issue was entered into PPL's CAP as cR 1401749.

ATTACHMENT: SUPPLEMENTAL INFORMATION Enclosure

A-1 SUPPLEMENTAL INFORMATION KEY POINTS OF CONTACT Licensee Personnel R. Bailey, Plant Control Operator J. Boyer, Engineer D. Brophy, Senior Emergency Planning Coordinator E. Capper, Reactor Engineer L. Cassella, Jr, Site Fire Protection Program Engineer C. Coddington, Senior Engineer F. Curry, Senior Technology Specialist L. CraMord, Unit Supervisor R. Day, Senior Engineer D. Dildine, l&C Technician M. Diltz, Operations Training Manager M. Deremer, Plant Control Operator J. Feno, Senior Assessor D. Filchner, Senior Engineer A. Fitch, Manager Nuclear Training l. Francis, Reactor Engineer E. Gerlack, Principal Engineer T. Gorman, Senior Staff Design Engineer/Scientist T. Greer, Unit Supervisor A. Griffith, l&C Supervisor K. Griffith, Nuclear Operations Training Supervisor J. Hartzell, Supervisor Plant Analysis J. Hirt, Reactor Engineering Supervisor R. Klinefelter, Assistant Operations Manager R. Kukorlo, Armorer P. Layden, Contractor - l&C Design Engineer R. Linden, lSl Specialist G. Machlick, Senior Engineer S. Madden, Senior Engineer S. Maguire, Fire Protection System Engineer H. Mozayeni, Shift Technical Advisor J. Petrilla, Supervisor Nuclear Regulatory Affairs D. Przyjenski, Senior Engineer T. Rausch, Chief Nuclear Officer G. Robinson, Shift Manager M. Rochester, Special Projects Coordinator, Nuclear Regulatory Affairs H. Riley, Plant Chemist V. Schuman, Radiation Protection Manager S. Skoras, Senior Engineer J. Waclawski, Senior Engineer M. Yeastedt, Plant Control Operator Attachment

A-2 LIST OF ITEMS OPENED, CLOSED, AND DISCUSSED Opened None.

Opened/Closed 05000387&388t 201 1 003-0 1 NCV lnadequate Surveillance Procedure Results in Failure to Meet Required Action of Technical Specifications for Secondary Containment lsolation Valves (Section 1 R04)

05000387&388/201 1 003-02 NCV Failure to lmplement Risk Management Actions during Dual Unit Elevated Risk (Section 1R13)

05000387/201 1003-03 NCV Failure to Establish Design Control Measures Associated with lnstallation of a Gland Liner in the HPCI Steam Supply lnboard lsolation Valve (Section 4OA2.5)

Closed 05000387/201 0-001-00 LER Unit 1 Secondary Containment Bypass Leakage Exceeded (Section 4OA3.1)

05000387/201 1-001-00 LER Single Point Vulnerability with the Potential to Cause lsolations (Section 4OA3.2)

05000387/201 1-002-00 LER Unit 1 Manual Scram Due to Unisolable Extraction Steam System Leak (Section 4OA3.3)

05000387/201 1-003-00 LER Unit 1 HPCI Inoperability Due to Valve Packing Leak (Section 4OA3.4)

25151183 TI Follow-up to the Fukushima Daiichi Nuclear Station Fuel Damage Event (Section 4OA5.3)

25151184 TI Availability and Readiness lnspection of Severe Accident Management Guidelines (Section 4OA5.4)

Attachment

A-3 LIST OF DOCUMENTS REVIEWED (Not Referenced in the Report)

Section 1R01: Adverse Weather Protection Condition Reoorts:

1 420287*, 1 420299", 1 420340", 1 420904*

Other:

Ol-AD-032, "Station Operation Reporting," Revision 15 Ol-AD-029, "Emergency Load Control," Revision 13 PJM Manual01, "Control Center and Data Exchange Requirements," Revision 19 PJM Manual 39, "Nuclear Plant Interface Coordination," Revision 03 PJM Manual 03, "Transmission Operations,: Revision 38 POG: R. Collier, C. Wood, S. Beard ML060950382 GL 2006-02, lN 93-17 Section 1R04: Equipment Aliqnment Conditiqn Reports (. NRC identified):

1 380661

• , 1 3801 52*, 1384196*, 1 383172*, 1 383755*, 1417471*, 1417468*, 1417467*,

1402442, 1417752", 527099, 1421356*, 1405162*, 1431750*,6941 60, 1423848*,

1420870*, 1 433946*, 1 395880, Procedures:

TP-215-008, "Unit 2 TBCCW Operation During a Refuel Outage," Revision 8 OP-01 1-001, 'SDHR System," Revision 19 OP-149-001, "RHR System," Revision 40 OP-149-002,'RHR Shutdown Cooling," Revision 45 SO-000-010, "Monthly Zone lll Integrity," Revision 24 SO-100-010, "Monthly Zone I Integrity," Revision 24 SO-200-010, "Monthly Zone ll Integrity," Revision 24 TP-235-011, "Refuel Outage Decay Heat Removal and Tie-ln of the SDHR Temporary Cooling Equipment," Revision 1 0 Drawinqs:

M-1536, "SDHR, Sheet 1," Revision 0 E-106256, Sheet 3, "Unit 1 P&lD Residual Heat Removal," Revision 26 E-106256, Sheet 4, "Unit 1 P&lD Residual Heat Removal," Revision 19 E-106256, Sheet 2,"Unit 1 P&lD Residual Heat Removal," Revision 53 E-106256, Sheet 1, "Unit 1 P&lD Residual Heat Removal," Revision 64 E-106215, Sheet 1, "Unit 1 P&lD Service Water," Revision 43 E-162639, Sheet 1, "Unit 2 P&lD Service Water," Revision 42 E-106292, Sheet 1, "Unit 1 P&lD Reactor Building Chilled Water," Revision 44 Attachment

A-4 E-105987, Sheet 1, "Unit 2 P&lD Reactor Building Chilled Water," Revision 37 Work Order:

1151990, 1172586,1376621, 1397961, 1361555, 1380643, 1403301, 1404869, 1352657, 1 3860 1 5, 1 402898, 1 40487 6, 1 407566, 1 366948, 6656 1 9, 1 41 41 47, 1 358008 Other:

TM-OP-049-ST, "Residual Heat Removal," Revision 7 CL-049-0015, "Unit 1 RHR System Division ll Mechanical," Revision 17 CL-049-0014, "Unit 1 RHR System Division ll Electrical," Revision 13 NL-95-001, '50.59 Evaluation - Refueling Outage Decay Heat Removal and Tie-ln of the SDHR Temporary Cooling Equipment," Revision 2 94-3057, "SE for Addition of Supplemental Decay Heat Removal and Reactor (Rx) Bldg. Chiller Water Piping to the Units 1 and 2 Reactor Building," Revision 1 MFP-QA-5250, "Control Structure PLRT and Reactor Building NLRT Boundary Breaches and Penetration Seals", Revision 7 Section 1R05: Fire Protection Condition Reports (.NRC identified):

1392571*, 1 382633 , 1383642, 1382924 Procedures:

FP-213-291, Condenser Gallery (11-113) Fire Zone 2-32D, Elevation 676'

FP-213-271, Condenser Area (1 1-36) Reactor Feed Pump Turbine Exhaust Areas (11-37)

(11 38) (11-309), Fire Zone 2-31D, Elevation 656'

FP-013-189, DG Bay'A', Fire Zone0-41A, Elevations 677',660', and 710', Revision 4 FP-113-119, "Circulation Space (l-500) and Adjacent Rooms (l-511 ,517,514,508), Fire Zones 1-sA-N, S, W, 1-5H, Elevation 749," Revision 5 FP-013-204, "Diesel Fire Pump Room (CW-21), Fire and Service Water Pump Area (CW-20),

Fire Zone 0-728,0-72C, Elevation 676," Revision 4 FP-213-100, "Drywell (ll-400, ll-516, ll-607) Fire Zone 2-4F, Elevation 704'Through 807',"

Revision 3 Drawinqs:

E-106227, Sheet 1, "P&lD Fire Protection Fire Pumphouse, North and South Gatehouse, and Security Control Center Building," Revision 51 E-105012, Sheet ll, "Circulating Water Pumphouse and waterTreatment Building - Fire Protection," Revision 5 E-106318, "Unit 1 Penetration RB Area 28 - Plan of Elevation 670'-0," Revision 33 Q-216O24, "Blackout Penetration RB Unit 1 Area 28 Elevation 670'-0," Revision 0 Other:

EC-EQQL-0695, "Determination of Room Pressure and Temperature Response to a HELB Outside Primary Containment," Revision 7 Attachment

A-5 EC-EQOL-0505, "Design Basis for Environmental Qualification of Equipment for High Energy,"

Revision 4 EC-HELB-1003, "Unit 1 RCIC High Energy Line Break Outside Primary Containment with Doors Open," Revision 0 Section 1R06: Flood Protection Measures Condition Reoorts (* NRC identified):

1 42987 8, 1 4301 07, 1 4301 1 0, 1 4301 1 1, 1 4301 1 3, I 430073, 1 430038, 1 430098

Conditiqn Reports:

1387548,1388055 Work Orders:

1 166427, 1 166422, 490967 Other:

Tube Plugging Form tor 28 RHR HX, dated April21,2011 M-1453, "specification for Heat Exchanger Tube Plugging,' Revision 7 MT-GM-078, "SSES Heat Exchanger Tube Plugging," Revision 7 MT-216-002, MT-GM-031, "lmmersed Component heat Exchanger Internals Epoxy Lining Cladding,"

Revision 13 MT-216-002, "RHR Heat Exchanger Cleaning, Inspection, and Repair," Revision 10 Section lR8: Inservice Inspection Activities:

Condition Reports (*CR issued as a result of this insp.ection):

11 37853. 1146912, 1299707 , 1320282, 1320394, 1 3841 97, 1384492, 1 384837, 1 385233, 1387084", 1 389037, 1 389040 Examination Procedures:

NDE-UT-018, "Manual Ultrasonic Examination of Weld Ovedaid SimilarAnd Dissimilar Metal Welds," Revision 1 NDE-UT-Q13, "Manual Ultrasonic Examination of Dissimilar Metal Piping Welds," Revision 2 NDE-W-1, "Visual Examination W-1," Revision 4 NDE-W-003, "Visual Examinatioh, W-3," Revision 7 NDE-W-005, "Underwater Visual Examination of RPV lnternals," Revision 7 NDE-UT-002, "Manual Ultrasonic Examination of Ferritic Welds," Revision 4 NDE-LP-001,"Color Contrast Liquid Penetrant Examination," Revision 4 NDE Records:

UT-1 1-001, N5A Core Spray DM Safe-end to Safe-end Extension Weld, dated April 14, 2011 Attachment

A-6 UT-11-002, NsB Core Spray DM Safe-end to Safe-end Extension Weld, dated April 14, 2011 BOP-PT-11-097, N5B Core Spray Nozzle, dated April 12,2011 BOP-PT-11-099, N5A Core Spray Nozzle, dated April12,2Q11 yf-11-32, 33, 35, 36, and 37, Drywell Floor/Diaphragm Slab Upper Surface, all dated April 1 1,2411 Drawinos:

SP-DCA-219-1, "Reactor Recirculation Pump 2A Suction Line To Valves 2F041C and 2F042C,"

Revision 14 Work Order:

1 168514 Other:

NDE Technician 0752 certification records WPS N-A-;A-MA-88, "Weld Procedure Specification for gas tungsten arc (GTAW) and shielded metal arc welding (SMAW) of stainless steel, ASME lX and ASME lll," Revision 5 1 152-SRP, "Under Water Construction Corporation, Susquehanna Unit 2 Steam Dryer Skirt Mitigation Procedure," Revision 0 26A6274, "General Electric Hitachi, Steam Dryer Fabrication Specification," Revision 21 Section 1 R12: Maintenance Effectiveness Condition Reports:

1375964, 1140243,1099908,930930, 982706,1031066, 1040810, 1051067, 1073312, 1 100025, 1121475, 1126141, 1 143566, 1 1 78908, 1201730, 1249334, 1270233, 1 301 736, 1 331 21 6, 1 3761 55, 1 385806, 1 361 27 4, 1400869, 1 390976, 1 392357, 1391 034, 1395204, 1392471, 1 386487, 1392351, 1391034, 1384367 Procedures:

SO-116-1303, "Quarterly RHRSW System Flow Verification," Revision 5 NDAP-QA-0O17, "Motor Operated Valve Program," Revision 12 Other:

Maintenance Rule Basis Document - System 16 - RHRSW Generic Letters 95-07 and 96-05 EC-052-0533,'MOV Data Detail Calculation for HV255F001," Revision 13 HPCI System Journal, System 52 EC-VALV-1040, "Pressure Locking Thermal Binding Operability Assessment," Revision 8 Section 1EP6: Drill Evaluation Condition Reoort:

1430396, 1408187 Attachment

A-7 Other:

NEI-99-02, Regulatory Assessment Performance Indicator Guideline RG 1.101, "Emergency Planning and Preparedness for Nuclear Power Reactors," Revision 5 Rrs 2007-02 Green Team HP Drill Controller Binder for Drill on June 28,2011 Emergency Plan Drill Scenario Performance Indicator Evaluation Sheets for June 28,2011 Section 1R13: Maintenance Risk Assessments and Emergent Work Gontrol Condition Reports:

1 399704*, 1399707*, 1399524., 1254144, 1141064, 1 396553, 1400776" 1416827", 1416829*,

1399524, 1411088, 1417454*, 1417358*, 1417135*, 1416634, 1416827, 1416832, 14197 46*, 1 41 9739*, 1 381 739, 1382432" Procedures:

NDAP-QA-0340, "Protected Equipment Program," Revision 10 NDAP-QA-1902, "Maintenance Rule Risk Assessment and Management Program," Revision 2 Work Order:

1417470 Other:

PEPETF for Systems 02, 04,24, dated April28,20'11 PEPETF for Systems 51, 04, dated March 31,2011 Risk Profile for Unit 1 on Sunday, May 1,2011 Risk Profiles for Unit 1 and Unit 2, May 4,2011 Sf CT/E Analysis Dated May 26,2011, "R8 Recirculation Plenum Entry," Station Leadership Package for June 2,2411 EC-RISK-1139, "susquehanna PRA Model Event Tree Notebook and Success Criteria,"

Revision 3 Section 1Rl5: Operabilitv Evaluations Condition Reports (* NR0-identified):

1 390680*, 1 381 739, 1382432*, 511642, 1372643, 1281470, 1274633, 1232956, 1274636 Procedures:

SE-183-006, "Main Steam Safety Relief Valve Inservice Testing," Revision 4 SE-283-006, "Main Steam Safety Relief Valve InserviCe Testing," Revision 4 OP-249-002, "RHR Shutdown Cooling," Revision 48 Other:

ASME OM Code - 1998 Attachment

A-8 Part 9900 Technical Guidance, "Operability Determinations and Functionality Assessments for

' Resolutions of Degraded or Nonconforming Conditions Adverse to Quality or Safety" SE Report for RR-01, RR-02, RR-03, and RR-05 for the First Program Plan for the Third 10-year Inspection Interval, dated March 10,2005, (ML050690239)

EC-RISK-1139, Susquehanna PRA Model Event Tree Notebook and Success Criteria Section 1R18: Permanent Plant Modifications Condition Report (i NRC identified):

1417289 Procedures:

NDAP-QA-1220, "Engineering Change Process," Revision 7 MFP-QA-1220, "Engineering Change Process Handbook," Revision 9 Drawinqs:

Ml-C72-2} "Reactor Protection System," Sheet 6, Revision 20, Sheet 1 1, Revision 10, Sheet 12, Revision 13, and Sheet 3, Revision 8 Work Order:

1 37001 0 Other:

TS 1370028 Log Entries Operations Unit 1 March 12,2011 02:16:05, March 18,2011 14:30:09 Section 1 R19: Post-Mainten?nce Testins Condition Reports (.NRC-ide.ntified ):

1405059,1390057,1408709,1402438,1402235,1406717,1403196,1421772,1421798, 1422390 Action Requests:

1408300, 1 4081 68, 1429049*

Procedures:

SE-204-202,"24 Month 4.16kV Class 1E Bus 2D (2A 204) Offsite Supply Transfer Check,"

dated April 15, 2011, Revision 10 TP-248-010, 'RFPT A(BXC) Uncoupled Run," Revision 3 Work Orders:

1227 598, 777 047, 11 80502, 731334 Attachment

A-9 Other:

PSP-29, "Post-Maintenance Test Matrix," Revision 7 EC 644573 COS-09, 'Design Standard for Dynamic Qualification of Mechanical and Electrical Equipment,'

Revision 1 MT-059-014,"24 Month Vacuum Relief Valve Set Pressure Test and Maintenance," Revision 2 S0-250-005, 'Month RCIC Flow Verification," Revision 17 Section 1R20: Refuelins and Other Outaqe Activities Condition Reoorts (*NRC identified):

1 391 392, 1 392069, 1 391 965*, 1 391 963*, 1 381 823*, 138741 1., 1 387858*, 1 388596*, 1 388593",

1383582*, 1385836*, 1385837*, 1385953*, 1385823., 1385838*, 1385833*, 1387106*,

1387116*, 1387080, 1394675, 1394693, 1394753, 1394535, 1396907*, 139691 1*,

1 39691 5*, 1401341*, 1401342*, 1401345*, 1401346*, 1401348*, 1401349*, 1404752*,

1405259" , 1405253* , 1405254* , 1405251*, 1 405255", 1405247* , 14052&" , 1406147* ,

1 406058*, 1 41 1 638*, 1411639*, 1411642*, 1411646*, 1412003, 1 406493*, 1413337*,

1419280, 1422418*, 1422422*, 1423649, 1423670, 1426781, 1427031, 1427331, 1 427 428, 1 428688, 1 427 537, 1 428065, 1 428688, 1 42817 1, 1 428994, I 4290 49",

1429054, 1429557*

Procedures:

OP-293-002, "Main Turbine Testing," Revision 29 GO-200'004, Plant Shutdown to Minimum Power ME-2RF-100, "Unit 2 Reactor Vessel Disassembly,' Revision 9 NDAP-QA-0507, "Conduct of Refuel Floor," Revision 19 GO-100-004, "Plant Shutdown to Minimum Power," Revision 55 GO-100-005, "Plant Shutdown to HoVCold Shutdown," Revision 50 Other:

Fatigue Assessments on two workers involved in 28 IRM Cable Severing Under Vessel, April 14, 2011 Unit 2, Cycfe 16, Core Verification Video, April27, 2011 Unit 2, Cycle 16, Full Core Loading Pattern, March 4,2011 Unit 2, Cycfe 16, Core Map, dated April25,2011 Fatigue Assessment on Worker, April 15,2011, (CR 1387972),

Fatigue Assessment on Worker May 23,2011, (CR 1411566)

Section 1 R22: Surveillance Testins Qondition Reports (* NRC identified):

g56274, 1142796, 92721, 1 399556, 1 399556, 1 399567, 1 400281 , 1 399655, 1 39971 3, 1 401 331 ,

1401167, 1 1 88951 , 1179371 Attachment

A-10 Procedures:

SE-259-027, LLRT of Feedwater Line B Penetration Number X-9B and Check Valve Operability Tests (SCBL)

NDAP-00-0752, Cause Analysis, Revision 6 SR-178-012, "Unit 1, LPRM Calibration and Validation," Revision 8 Sl-180-203, "Unit 1, Quarterly Functional Test of Reactor VesselWater Level Channels Lls-821-1N031A, B, C, D," Revision 19 SE-224-1O7, "Unit 2 Division I Diesel Generator LOCA/LOOP Test," Revision 14 Sl-180-301, "Quarterly Calibration of Reactor Vessel Pressure Channels PIS-B21-1N021 A,B,C,D and PS-B21-1N021 E,G (Core Spray System and LPCI Permissive) Reactor Pressure Greater Than Setting (420 psig)"

Sl-180-203, "Quarterly Functionaltest of ReactorVesselwater Level Channels, LIS-B21-1N031 A,B,C,D," Revision 19 SE-259-029, "LLRT of Steam HPCI Turbine Penetratlon Number X-11," Revision 16 SE-249-002,"24 Month RHR Logic System Functional Test (Division ll) - Outage (Partial),"

Revision 15 Work Orders:

1 1 80826, 1 314356, 1314256, 1342641, 1342048 Other:

Maintenance Rule Basis Document for Systems 45 and 59 Section 2RS1: Radiolosical Hazard Assessment and Exposure Controls Condition Reports:

1382473;1382568; 1383383; 1384235;1384495;1385488; 1385858; 1385863; 1386120; 1386575; 1386587; 1387239; 1387838; 1388012; 1390644; 1394584 Radiation Work Permits:

201 1 -2001 ; 2O1 1 -2002; 2O1 1 -21 20; 2O1 1 -2320 20 1 1'237 O Section 2R$2: Occupational ALARA Plannins and Controls Condition Reports:

1377 07 5: 1 382827 ; 1 395092 Other:

ALARA Prejob Reviews : 20 1 1 2001 ; 201 1 2002; 201 1 21 20 201 1 -2320, 201 1 237 0 ALARA n-Progress Reviews : 201 I 200 1 ; 20 1 1 2002; 201 I 21 20; 201 1 2320 I

Section 2RS7: Rpdiolosical Environmental Monitorins Prosram Attachment

A-11 Work Orders:

C1564-01, Calibrate Primary Met Tower Rainfall Channel C1565-01, Perform Calibration of Primary Met Tower Dewpoint Channel C2545-01, Perform Calibration of Primary Met Tower Wind Direction Sigma 60 Meter C2546-01, Perform Calibration of Primary Met Tower Wind Direction Sigma 10 Meter C2980-01, Perform Primary Met Tower Temperature Elements Linearity Check Calibrations C1567-01, Perform Calibration of Backup Met Tower Wind Speed Channel C1568-01, Perform Calibration of Backup Met Tower Wind Direction Channel C1569-01, Perform Calibration of Backup Met Tower Wind Direction Sigma Channel C2101-04, Perform Calibration of Nescopeck Met Tower Wind Speed Channel C2101-05, Perform Calibration/Maintenance on Nescopeck Met Tower Wind Direction Channel C2101-06, Perform Calibration of Nescopeck Met Tower Wind Sigma Theta C2101-09, Perform Calibration of Nescopeck Met Tower Temperature Channel Surveillance Procedures:

Sl-099-313, Semi-Annual Calibration - Meteorological Tower Wind Speed Channel (60 Meters)

Sl-099-314, Semi-Annual Calibration - Meteorological Tower Wind Direction Channel (60 Meters)

Sl-099-315, Semi-AnnualCalibration - MeteorologicdlTowerWind Speed Ghannel(10 Meters)

Sl-099-316, Semi-Annual Calibration - Meteorological Tower Wind Direction Channel (10 Meters)

Sl-099-317, Semi-Annual Calibration - MeteorologicalTower Delta Temperature Channel 1 (10-60 Meters)

Sl-099-318, Semi-Annual Calibration - MeteorologicalTower Delta Temperature Channel 2 (10-60 Meters)

Other:

Susquehanna Steam Electric Station Annual Radiological EnvironmentalOperating Report, PLA-6720, dated May 6, 2011 Susquehanna Steam Electric Station 2010 Land Use Census Report, dated November 16,2010 REMP 1't Quarter 2011 Surveillance, dated May 10,2011 Oversite reports of Ecology lll, dated May 25, 2011; May 19, 2011; May 16, 2011; and May 3, 2011 Susquehanna Steam Electric Station PPL Combined Audit of Ecology lll, Inc. REMP and NEMP Programs, Audit No. 22730 Quality Assurance (REMP) Summary Reports tor 2010 (dated May 3, 2011) and 2009 (dated April28, 2011)

Susquehanna Steam Electric Station 1" Quarter 2011 Environmental TLD Report, PLI-95137, dated May 5, 2011 Section 4OA?: ldentification Fnd Resolution of PrPblems Condition Beoorts (* NRC identified):

1 420358, 1287298, 1 325050, 1294155, 1 356838, 1 406091 , 1 1 94033, 1101242, 1221723,

• ,

1 2217 60, 1 41 663 1, 1 347 508, I 293802, 1 33 1 075, 1 323924, 1237 528, 1 443059 1 1361274,394758, 39501 8, 398043, 560822, 996073, 1 361 473 Attachment

A-12 Procedure:

NDAP-QA-0710, "Station Trending Program," Revision 5 MT-GM-01 1, "Valve Packing/Live Loading/lnvestigation," Revision 22 Work Orders:

560827, 1078058 Other:

AD24O, "Apparent Cause Evaluator - lnitial Training," Revision 1

"Station Health Report September - December 2010'

"PPL Susquehanna Performance Metrics, April, 2011"

"Station Quarterly Trend Reports, 1Q1 1, 4Q10, 3Q10, 2Q10"

"Station Excellence Plan, March,2011," Revision 4

"system Journal, System 52, High Pressure Coolant Injection" PLA-4996, "susquehanna Steam Electric Staytion Supplemental Response to Request for Information Regarding Valve and Relay lssues," Letter dated October 21, 1998 Section 4OA3: Event Followup Condition Reports:

1 391 439*, 1412085*, 1412754*, 1412667 Other:

LER 50-38712Afi-001-00 LER 50-387 12011 -002-00 LER 50-387/201 1 -003-00 Unit 1 Outage Schedule for 1C17 Outage - System 46 Section ttOAS: Other Activities Condition Reportp:

1397746,707111,749676,1328561, 1328563, 1334889, 1334892, 1339192, 1339193, 1 3391 94, 1 359306, 1 356823, 1 399661, 1 399663, 1426226, 1426226, 1426961 Procedures:

PL-NF-06-002, "SSES Mitigating System Performance Index Basis Document," Revision 5 NDAP-QA-0737, "Reactor Oversight Process (ROP) Performance lndicators," Revision 7

.On-line PRA Model Rollout Process," Revision 2 PA-Tl-200, PA-Tl-201, "MOV lmportance Measures," Revision 0 NDAP-QA-OO17, "Motor Operated Valve Program," Revision 12 PA-Tl-205, "Plant Analysis Maintenance Rule Input," Revision 0 NDAP-QA-O413, "Maintenance Rule Program," Revisipn 9 PA-T1-206, "Updating the Tables Required in the Mitigating System Performance Index Basis Attachment

A-13 Document," Revision I PA-T!-204, "Risk Inform lSl Data," Revision 0 NEIM-00-1181, "lsl Risk-lnformed Inspection Program," Revision 1 NDAP-QA-1608, "lnseryice Inspection (lsl),' Revision 1 2 Other:

.Regulatory Assessment Performance Indicator Nuclear Energy Institute (NEl) 99-02, Guideline," Revision 6

.Living Program Guidance to Maintain Risk-lnformed Inservice Inspection Programs NEI 04-05, for Nuclear Plant Piping Systems' ,

PLA-5768, "Susquehanna Steam Electric Station Re$ponse to Request for Additional Information from NRC on Proposed Relief Request No.3RR-01 to the Third 10-Year fnservice Inspection Program for Susquehanna SES Units 1 and 2" Susquehanna Steam Electric Station, Units 1 and 2 *Third 10-Year Inservice lnspection (lSl)

Interval Program Plan (TAC NOS. MC1181 aftd MC1182)

PLI- 90201, "Susquehanna Steam Electric Station NRC SE of PPL Response to Generic Letter 96-05" NEDC-32264 BWR Owners Group Report, "Applicatign of Probabilistic Safe$ Assessment to Generic Letter 89-10 lmplementation" NEr 99-02 FAQ rD 468 Section 4OA7: Licensee-ldenti{ied ViolatioTts Condition Reports:

997 122, 1 404505*, 1 405098, 1 405 1 01, 1 405099, 1 405 1 07, 1 40521 5", 1 406734*, 1 4A6627*

Procedures:

NDAP-QA-1220, "Engineering Change Process Handrbook," Revision 9 NDAP-QA-1220, "Engineering Change Process," Revision 7 EP-DS-001, "Containment Combustible Gas Control" Revision 5 EP-DS-002, "RPV and Primary Containment Flooding," Revision 6 EP-DS-003, 'RPV Lever Determination," Revision 4 EP-DS-004, "Primary Containment and RPV Venting," Revision 3 EP-DS-005, "Loss of All Decay Heat Removal," Revision 4 EP-DS-006, "RPV Flooding to the Main Steam Lines," Revision 2 NDAP-QA-0330, "PSTG and Emergency Procedures,r Revision 11 Other:

"Training Search Results for Severe Accident Management Coordinator, May 11,2011"

"BWR Owner's Group Emergency Procedure and Severe Accident Guidelines," Revision 2 8P077, "Severe Accident Progression and Phenomena," Revision 5 EP076, "Severe Accident Overview and Transition," Rbvision 3 Qualification Requirement Report for Severe Accident Management Coordinator

"PL 50.59 Resource Manual," Revision 5

"Emergency Plan Program Positions and Required Training TMX Report" Attachment

N14 LIST OF ACRONYMS AC Alternating Current ACE Apparent Cause Evaluation ADAMS Agencywide Document and Access Management System ALARA As Low As ls Reasonably Achievable ANS Alert and Notification System AR Action Report ASME American Society of Mechanical Engineers BTV Bleeder Trip Valve BWR-VIP Boiling Water Reactor, Vessel Internals Project CAP Corrective Action Program CARB Corrective Action Review Board CFR Code of Federal Regulations CNF Customer Notification Forms i CAQ Condition Adverse to Quality i CDE Consolidation Data Entry ACDF Core Damage Frequency CR Condition Report CRA Condition Report Action ,

CRD Control Rod Drive CREOAS Control Room Emergency Outside Air Supply CS Control Structure CST Condensate Storage Tank CW Circulating Water DEP Drill and Exercise Performance DH Decay Heat DM Dissimilar Metal DW Drywell EAL Emergency Action Level ECCS Emergency Core Cooling System ECOT Employee Concerns Oversite Team ECP Employee Concerns Progrpm EDG Emergency Diesel Generator EHC Electrohydraulic Control EOC Extent of Condition EOOS Equipment Out-of-Service EOP Emergency Operating Procedure EP Emergency Preparedness EPA Electrical Protective Assembly EPD Electronic Personnel Dosimeter EPIP Emergency Plan lmplementing Procedure EPU Extended Power Uprate EQ Environmental Qualifi cation ER Engineering Reguest '

ERO Emergency Response Organization ESS Engineering Safeguard System ESW Emergency Service Water EWR Engineering Work Request FEMA Federal Emergency Management Agency Attachment

A-15 FIN Finding FOST Fuel Oil Storage Tank FSAR ISSES] Final Safety Analysis Report FUS Field Unit Supervisor GE GeneralElectric GEH GE - Hitachi GL Generic Letter GPI Ground Water Protection Initiative GWE General Work Environment HPCI High Pressure Coolant Injection HRA High Radiation Area HV High Voltage HVAC Heating, Ventilation and Air-Conditioning HX Heat Exchanger ICDP Incremental Core Damage Probability rcs Integrated Control System r&c lnstrumentation and Controls IDLH lmmediately Dangerous to Life and Health IEEE Institute of Electrical and Electronics Engineers IN Information Notice IL Instruction Leaflet ILERP Incremental Large Early Release Probability rMc Inspection Manual Chapter IP Inspection Procedure tPl Installed Plant Instrumentation IR NRC Inspection Report tsl Inservice Inspection IST Inservice Testing rwl In-Vessel Visual Inspection IWYIST In Vessel Visual Inspection/lnservice Testing JP Jet Pump KV Kilovolts LCO Limiting Condition for Operation LDE Lens Dose Equivalent LEFM Leading Edge Flow Meter LER Licensee Event Report LERF Large Early Relief Frequency LLD Lower Limits of Detection LOCA Loss of Coolant Accident LOOP Loss of Offsite Power LPRM Low Power Range Monitor (LPRM LSFT Logic System Functional Test LTC Load Tap Changer M&TE Measuring and Test Equipment MG Motor Generator MOV Motor Operated Valve MRFF Maintenance Rule Functional Failures MSPI Mitigating Systems Performance Indicators MT Magnetic Particle Testing i NAQ Not Adverse to Quality NCV Non-Cited Violation Attachment

A-16 NDAP Nuclear Department Administrative Pfocedure NDE Non-Destructive Examination NDT Non-Destructive Test NEI Nuclear Energy Institute NERO Nuclear Emergency Response Organization NRA Nuclea r Regulatory Affairs NRC Nuclear Regulatory Commission NVLAP National Voluntary La boratory Accreditation Prog ram OA Other Activities ODCM Offsite Dose Calculation Manual ODM Operational Decision Making OE Operating Experience OFR Operability Followup Request o&M Operation and Maintenance oos Out-of-Service PARS Publicly Available Records PCE Potential Chilling Effect PCIV Primary Containment lsolation Valve PCP Process Control Program PDI Performance Demonstration Initiative PEMA Pennsylvania Emergency Managemertt Agency PF Power Factor PI [NRC] Performance Indicator PI&R Problem'ldentification and Resolution PIM Plant lssues Matrix PMT Post-Maintenance Test PPL PPL Susquehanna, LLC PRV Pressure Relief Valve PS Planning Standard PT Penetrant Test QA Quality Assurance RB Reactor Building RCA Radiologically Controlled Area RCA Root Cause Analysis RCrC Reactor Core lsolation Cooling RCS Reactor Coolant System REMP Radiological Environmental Monitoring Program RETS Radiological Effluents Technical Specifications RFO RefuelOutage RFPT Reactor Feed Pump Turbine RFU Request for Followup RG INRCI Regulatory Guide RHR Residual Heat Removal RHRSW Residual heat Removal Service Water RIE Replacement ltem Evaluation RMA Risk Management Actions RMS Radiation Monitoring System ROP Reactor Oversig ht Process RPM Radiation Protection Manager RPS Reactor Protection System RPV Reactor Pressure Vessel Attachment

I A-17 RT Radiographic Testing RTP Rated Thermal Power RWMU River Water Make-Up RWP Radiation Work Permit RWST Refueling Water Storage Tank SAMGs Severe Accident Management Guidelines sBo Station Blackout scrv Secondary Containment lsolation Valvc SCWE Safety Conscious Work Environment sDc Shutdown Cooling SDE Skin Dose Equivalent SDHR Supplemental Decay Heat Removal SDP Significance Determination Process SE Safety Evaluation SGTS Standby Gas Treatment System SLD Steam Leak Detection SMAW Shielded Metal Arc Welding SOMS Shifi Operations Management System sow System Outage Window SPAR Standardized Plant Analysis Review SR Surveillance Requirement SRA Senior Reactor Analyst SRM Source Range Neutron Monitoring SRV Safety Relief Valve ssc Structures, Systems and Components SSES Susquehanna Steam Electric Station SW Service Water TASA Tapchanger Activity Signature Analysi$

TBCCW Turbine Building Closed Cooling Watef TEDE TotalEffective Dose Equivalent l TLD Thermoluminescence Dosimeter TRM Technical Requirements Manual TS Technical Specifications 720 T20 Startup Transformer UFSAR Updated Final Safety Analysis Report UT Ultrasonic Test VHRA Very High Radiation Areas VT Visual Examination WBC Whole Body Counter WO Work Order WPS Weld Procedure SPecification l Attachment