IR 05000387/2009003

IR 05000387-09-003, 05000388-09-003; on 04/01/2009 - 06/30/2009; Susquehanna Steam Electric Station, Units 1 and 2; Maintenance Effectiveness, Refueling Activities

ML092230158
Person / Time
Site:	Susquehanna
Issue date:	08/11/2009
From:	Paul Krohn Reactor Projects Region 1 Branch 4
To:	Rausch T Susquehanna
KROHN P, RI/DRP/PB4/610-337-5120
References
IR-09-003
Download: ML092230158 (58)

Text

UNITED STATES NUCLEAR REGULATORY COMMISSION ust 11, 2009

SUBJECT:

SUSQUEHANNA STEAM ELECTRIC STATION - NRC INTEGRATED INSPECTION REPORT 05000387/2009003 AND 05000388/2009003

Dear Mr. Rausch:

On June 30, 2009, 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 16, 2009, 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 Commissions 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 one NRC-identified finding of very low safety significance (Green) and one Severity Level IV violation. Both of these findings were determined to involve a violation of NRC requirements. Additionally, five 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 corrective action program, the NRC is treating these findings as non-cited violations (NCVs), consistent with Section VI.A.1 of the NRC Enforcement Policy. If 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 I; 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 characterization of 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 1 and the NRC Senior Resident Inspector at Susquehanna. The information you provide will be considered in accordance with Inspection Manual Chapter (IMC) 0305. In accordance with 10 CFR 2.390 of the NRCs "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 NRCs document system (ADAMS). ADAMS is accessible from the NRC Web site at http://www.nrc.gov/reading-rm/adams.html (the Public Electronic Reading Room).

Sincerely,

/RA/

Paul G. Krohn, Chief Projects Branch 4 Division of Reactor Projects Docket Nos. 50-387; 50-388 License Nos. NPF-14, NPF-22

Enclosures:

Inspection Report 05000387/2009003 and 05000388/2009003 Attachment: Supplemental Information

REGION I==

Docket No: 50-387, 50-388 License No: NPF-14, NPF-22 Report No: 05000387/2009003 and 05000388/2009003 Licensee: PPL Susquehanna, LLC Facility: Susquehanna Steam Electric Station, Units 1 and 2 Location: Berwick, Pennsylvania Dates: April 1, 2009 through June 30, 2009 Inspectors: F. Jaxheimer, Senior Resident Inspector P. Finney, Resident Inspector S. Barr, Senior Emergency Preparedness Specialist J. Furia, Senior Health Physicist R. Fuhrmeister, Senior Project Engineer T. OHara, Reactor Inspector D. Orr, Senior Reactor Inspector A. Rosebrook, Senior Project Engineer Approved By: Paul G. Krohn, Chief Projects Branch 4 Division of Reactor Projects Enclosure

SUMMARY OF FINDINGS

IR 05000387/2009003, 05000388/2009003, 04/01/2009 - 06/30/2009; Susquehanna Steam

Electric Station, Units 1 and 2; Maintenance Effectiveness, Refueling Activities The report covered a 3-month period of inspection by resident inspectors, and announced inspections by regional reactor inspectors. One Green, non-cited violation (NCV) and one SL IV violation were identified. The significance of most findings is indicated by their color (Green,

White, Yellow, or Red) using Inspection Manual Chapter (IMC) 0609, Significance Determination Process (SDP). Cross-cutting aspects associated with findings are determined using IMC 0305, Operating Reactor Assessment Program, dated January 2009. Findings for which the SDP does not apply may be Green or be assigned a severity level after NRC management review. The NRCs program for overseeing the safe operation of commercial nuclear power reactors is described in NUREG-1649, Reactor Oversight Process, Revision 4, dated December 2006.

Cornerstone: Initiating Events

Green.

The inspectors identified a NCV of Technical Specification 5.5.6, Inservice Testing Program, because PPL did not evaluate the cause, effect and generic concerns of safety relief valve (SRV) failures to meet the +/- 3 percent set pressure test acceptance criteria as required by 1998 ASME Operations & Maintenance (OM) Code paragraph I-1330(c)(3) from 2005 to 2009. Inspectors identified that PPL experienced a SRV set pressure test failure rate of 30 percent over five refuel outages. The causes of these failures were not evaluated for potential effects and generic implications to other SRVs as well as other valve groups. Further, PPL incorrectly interpreted NRC approved relief from certain parts of the ASME operation and maintenance (O&M) code to include evaluation of failures in the lower direction. SRV failures in the lower direction reduce the simmer margin between operating pressures and valve pressure setpoints.

Reduced simmer margin and the lack of failure evaluations can result in more significant operational challenges. As an immediate corrective action, the licensee entered this NCV into their corrective action process (CR 1162307).

This finding is greater than minor because it is associated with the equipment performance attribute of the Initiating Event cornerstone; and it negatively impacted the cornerstone objective of limiting the likelihood of events that upset plant stability and challenge critical safety functions during power operations. This finding is related to the Problem and Identification Resolution cross-cutting area (Corrective Action Program)because PPL did not thoroughly evaluate the SRV failures such that the causes and extent of condition were addressed. (P.1(c)), (Section 1R12)

• SL IV. The inspectors identified a non-cited violation of 10 CFR 50.73(a)(2)(vii),

because PPL did not submit a Licensee Event Report (LER) for the common cause failure and consequent inoperability of two or more SRVs in 2005, 2008, and 2009. The inspectors determined that SRV failures of set pressure testing per the 1998 ASME O&M Code were attributed to setpoint drift resulting in two or more independent channels (two or more SRVs) to become inoperable. As an immediate corrective action, the licensee entered this NCV into their corrective action process (CR 1161398).

This finding was evaluated using the traditional enforcement process because the failure to accurately report events has the potential to impact or impede the regulatory process.

The finding was determined to be a Severity Level IV violation based on Supplement I,

Example D.4 of the NRC Enforcement Policy. However, because this violation was of very low safety significance, was not repetitive or willful, and was entered into PPLs corrective action program, this violation is being treated as an NCV consistent with the NRC Enforcement Policy. This finding is related to the Problem Identification and Resolution cross-cutting area (Operating Experience (OE)) because PPL did not thoroughly incorporate Information Notice (IN) 2006-24 to include SRV set point drift as a reportable common cause failure method. (P.2(b)), (Section 1R20)

Licensee Identified Violations

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

REPORT DETAILS

Summary of Plant Status

Susquehanna Steam Electric Station (SSES) Unit 1 began the inspection period at the authorized licensed power level of 94.4 percent reactor thermal power (RTP). On April 5, 2009, Unit 1 was reduced to 70 percent RTP over a period of 19 hours2.199074e-4 days <br />0.00528 hours <br />3.141534e-5 weeks <br />7.2295e-6 months <br /> for a control rod sequence exchange. On April 9, the unit reduced power to 66 percent power over 18 hours2.083333e-4 days <br />0.005 hours <br />2.97619e-5 weeks <br />6.849e-6 months <br /> in support of a valve replacement on the river water makeup system (refer to section 1R13). On May 15, Unit 1 was reduced to 80 percent RTP over 80 hours9.259259e-4 days <br />0.0222 hours <br />1.322751e-4 weeks <br />3.044e-5 months <br /> in support of main condenser waterbox cleaning.

Finally, the unit reduced power to 72 percent on June 14, to perform another control rod sequence exchange. Unit 1 remained at 94.4 percent RTP for the remainder of the inspection period.

Unit 2 began the inspection period coasting down from 90 percent of its previously licensed RTP of 3489 megawatts thermal. The reactor was shutdown for a scheduled maintenance and refueling outage on April 7, 2009. The reactor was restarted on May 15 and went through numerous power plateaus for extended power uprate (EPU) testing before reaching the authorized power level of 94.4 percent (3733 MWth) on June 3, 2009. On June 12, as part of scheduled EPU testing, operators tripped a condensate pump and reactor power was reduced to approximately 66 percent of licensed power level by the expected automatic runback. The unit was held at 85 percent RTP for approximately 22 hours2.546296e-4 days <br />0.00611 hours <br />3.637566e-5 weeks <br />8.371e-6 months <br /> following the EPU test for planned 2B reactor feedwater pump repairs. On June 26, Unit 2 was reduced to 70 percent power to complete a control rod sequence exchange and was maintained at 65 to 72 percent RTP during isolation and repair of the 4B feedwater heater dump valve transmitter. On June 28, Unit 2 returned to 94.4 percent RTP and remained at this power level for the remainder of the inspection period.

Note: The licensed RTP for Unit 1 is 3952 megawatts thermal. The EPU License Amendment for SSES was approved in January 30, 2008 and was implemented for Unit 1 in accordance with the issued license conditions. For the current operating cycle, the Unit 1 authorized power level is 94.4 percent of the EPU licensed power limit. For the purposes of this report, the licensed RTP for Unit 2 is also 3952 megawatts thermal. The EPU License Amendment was implemented on Unit 2 during this inspection period in accordance with the issued license conditions. For the remainder of the current operating cycle, the Unit 2 authorized power level is 94.4 percent of the EPU licensed power limit.

REACTOR SAFETY

Cornerstones: Initiating Events, Mitigating Systems, and Barrier Integrity

1R01 Adverse Weather Protection (71111.01 - 2 Samples)

.1 Readiness for Seasonal Extreme Weather

a. Inspection Scope

During the week of April 26, 2009, the inspectors reviewed system operations and preparations for elevated ambient conditions. Plant walkdowns for selected structures, systems, and components (SSCs) were performed to determine susceptibility and the adequacy of PPLs operating procedures. Inspectors reviewed operator actions to address failures of equipment due to heating and compensatory actions during the adverse, hot weather conditions. Inspectors included a specific review of the cooling water systems and plant ventilation equipment that was out-of-service or in an unusual alignment status due to the Unit 2 refueling outage. The inspectors also reviewed and evaluated considerations in PPLs Maintenance Rule station risk assessment.

Additional documents that were reviewed are listed in the Attachment. The readiness of the following systems was reviewed.

• Units 1 and 2, high ambient temperatures (92 °F, outside air) causing high turbine building, reactor building (RB), Unit 2 drywell and spent fuel cooling temperatures.

b. Findings

No findings of significance were identified.

.2 Summer Readiness of Offsite and Alternate AC Power Systems

The inspectors reviewed the features and procedures for operation and continued availability of offsite alternating current (AC) power systems and onsite alternate AC power systems to the plant. The inspectors also reviewed communication protocols between the site and the transmission system operator (TSO).

• Common, required sample of offsite and AC power system summer readiness.

b. Findings

No findings of significance were identified.

1R04 Equipment Alignment (71111.04 - 5 Samples)

.1 Partial Walkdown (4 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. The walkdowns included the following systems:

• Unit 1, turbine building ventilation with 1B chiller OOS following motor failure;

• Unit 1, high pressure coolant injection;

• Unit 2, standby liquid control including locked primary containment boundary valves for this system and the residual heat removal system; and

• Common, C emergency diesel generator (EDG) during emergency core cooling system (ECCS) test start, load reject, and 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> run.

b. Findings

No findings of significance were identified.

.2 Complete Walkdown (1 Sample)

a. Inspection Scope

The inspectors performed a detailed review of the alignment and condition of the station supplemental decay heat removal (SDHR) 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 condition reports (CRs)associated with the SDHR system to determine the effect on system health and reliability. The inspectors verified proper system alignment and looked at system operating parameters when there was a significant change to the available decay heat removal systems for Unit 2. The walkdown included the following system:

• Unit 2, supplemental decay heat removal.

b Findings No findings of significance were identified.

1R05 Fire Protection (71111.05Q - 5 Samples)

.1 Fire Protection - Tours

a. Inspection Scope

The inspectors reviewed PPLs 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 those areas to assess PPLs control of transient combustible material and ignition sources, fire detection and suppression capabilities, fire barriers, and any related compensatory measures to assess PPL's fire protection program in those areas. The inspected areas included:

• Unit 1, load center rooms for 1A201 and 1A202, elevation 749;

• Unit 1, lower relay room, elevation 698;

• Unit 2; condenser mezzanine and isophase bus area, FP-213-282;

• Units 1 and 2, access areas and ECCS keepfill areas elevation 779; and

• Common, radwaste heating, ventilation and air-conditioning (HVAC) areas, trash compactor area, charcoal absorber rooms, FP-013-321, FP-013-313 and FP-013-312.

b. Findings

No findings of significance were identified.

1R07 Heat Sink Performance (71111.07A - 1 Sample)

a. Inspection Scope

The inspectors reviewed PPLs program for the as-found and as-left conditions of the 2A residual heat removal (RHR) heat exchanger. Specifically, the review included 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 visually inspected and reviewed tube plugging and repairs to flow and mating surfaces associated with the heat exchanger.

Documents reviewed are listed in the Attachment. The annual heat sink performance sample included:

• Unit 2, 2E205A, 2A RHR heat exchanger clean and inspection.

b. Findings

No findings of significance were identified.

1R08 Inservice Inspection Activities

a. Inspection Scope

(Procedure

==71111.08 - 1 Sample)

The inspector observed selected samples of in-process nondestructive examination

==

(NDE) activities. Also, the inspector reviewed documentation of additional samples of NDE and component replacement activities which involved welding processes. 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 observations and documentation review were performed to verify activities were performed in accordance with the American Society of Mechanical Engineers (ASME) Boiler and Pressure Vessel Code requirements. The inspector reviewed a sample of inspection reports initiated as a result of nonconforming conditions identified during Inservice Inspection (ISI) examinations. Also, the inspector evaluated the effectiveness of the resolution of problems identified during ISI activities.

The inspector reviewed the Boiling Water Reactor - Vessel Internals Project (BWR-VIP)required re-review of prior dissimilar metal (DM) reactor recirculation system nozzle weld ultrasonic inspections. These re-reviews had been completed by a vendor in 2008 and were an electronic review of pre-Supplement 10 weld crown flatness requirements. The vendor noted potential indications exceeding ASME requirements in nozzle N1A and N2B. Subsequently, PPL performed ASME,Section XI, Appendix VIII, Supplement 10 Phased Array Ultrasonic Test (UT) examinations of both nozzles N1A and N2B during the April 2009 outage. These improved inspections did not show any recordable UT indications in the DM welds for nozzles N1A and N2B.

The inspector observed a manual ultrasonic performance demonstration initiative (PDI)ultrasonic examination performed on a dissimilar metal weld in the feedwater system piping inside the drywell. The inspector also reviewed the results of the previous inspection, reviewed the calibration of the testing equipment and reviewed the personnel certifications of the personnel performing the inspection. Additionally, the inspector reviewed the inspection data sheet to ensure PPL had completed the inspection in accordance with the requirements.

The inspector observed a partial phased array, PDI ultrasonic examination scan of the dissimilar metal weld on reactor recirculation system nozzle N1A. The inspector observed the operators recording ultrasonic data and monitoring the quality of the collected data. The inspector also reviewed the qualification certification of the ultrasonic technician performing these examinations.

Additionally, the inspector reviewed the completed inspection reports (data sheets) for several other UT (27), dye penetrant (PT)

(2) and visual testing (VT)

(20) inspections performed during the refueling outage. These reviews verified the effectiveness of the testing procedures, testing performance activities and the effectiveness of the examiner, test equipment and process in identifying degradation of risk significant systems, structures, and components and evaluated those activities for compliance with the requirements of ASME Section XI of the Boiler and Pressure Vessel Code.

The inspector reviewed reported indications from PPL=s In Vessel Visual Inspection (IVVI) programs visual inspections of the reactor internals. Several indications were reported and dispositioned for use Aas-is@ based upon evaluation by the reactor vendor.

Additionally, the inspector reviewed a sample of the vendors customer notification forms (CNFs) which approved the acceptability of these conditions for operation until the next refueling outage.

The inspector also reviewed a sample of corrective action reports, shown in the attachment, which identified nonconforming conditions discovered during this and the previous outage. The inspector verified that flaws and other nonconforming conditions identified during nondestructive testing were reported, characterized, evaluated, appropriately dispositioned, and entered into the corrective action program. The inspector reviewed the corrective actions associated with the steam dryer replacement for Unit 2 as described in Section 4OA5 of this report.

b. Findings

No findings of significance were identified.

1R11 Licensed Operator Requalification Program (71111.11 - 1 Sample)

.1 Resident Inspector Quarterly Review

a. Inspection Scope

On May 14, 2009, the inspectors observed licensed operator simulator training in support of the Unit 2 reactor startup. The inspectors compared their observations to Technical Specifications (TSs), emergency plan implementation, and the use of system operating procedures. Inspectors reviewed startup data specific to the configuration for the current reactor cycle. The inspectors also evaluated PPLs critique of the operators' performance to identify discrepancies and deficiencies in operator training. The following training was observed:

• Unit 2, just-in-time training for Unit 2 reactor startup post-refueling.

b. Findings

No findings of significance were identified.

1R12 Maintenance Effectiveness (71111.12 - 2 Samples)

a. Inspection Scope

The inspectors evaluated PPLs 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 PPLs extent of condition determinations for these issues with potential common cause or generic implications to evaluate the adequacy of PPLs corrective actions. The inspectors reviewed PPL's problem identification and resolution 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. The following issues were reviewed:

• Unit 2, safety relief valve (SRV) as-found pressure setpoint failures; and

• Common, onsite pressure relief valve (PRV) testing of fluid valves and steam service valves, in accordance with ASME O&M code requirements.

b. Findings

Introduction:

The inspectors identified a Green NCV of Technical Specification 5.5.6, Inservice Testing Program, in that PPL did not implement the requirements of the inservice test (IST) program. Specifically, they did not evaluate the cause, effect, and generic concerns of SRVs that failed set pressure testing from 2005 through 2009 in accordance with 1998 ASME O&M Code, paragraph 1330(c)(3).

Discussion: In 2001, Susquehanna issued Licensee Event Report (LER)05000388/2001-005-00 regarding the failure of several SRVs during their as-found set pressure test. At that time, the Technical Specification Surveillance Requirement 3.4.3.1 for both units had an acceptance band of +/-1 percent. As part of the LER cause description, PPL stated that the valves used at Susquehanna have never consistently met the TS requirement of +/-1 percent during as-found testing after in-service operation, but have consistently actuated within 3 percent of setpoint. Part of PPLs corrective action from that LER was to obtain a license amendment to revise the acceptance band for as-found actuation pressure of the SRVs to +/-3 percent. PPL received the license amendment in November 2002.

In 2004, PPL submitted and received NRC approval of their third interval 10-year IST plan. ASME OM Code Subarticles ISTC-1300 and ISTC-5240 identify SRVs as Category C valves and direct that SRVs meet the IST requirements of Appendix I. As part of their IST plan, PPL submitted and received NRC approval for a relief request, RR02, proposing that additional SRVs only be tested in accordance with paragraph 1-1330(c) if valves in the original sample exceeded +3 percent of the nameplate.

Justification for this proposal included SRV historic performance, specifically, an average setpoint drift of -0.705 percent and a standard deviation of 1.43 percent. However, paragraph ISTC-1330(c)(3) also requires in part, The Owner shall evaluate the cause and effect of valves that fail to comply with the set-pressure acceptance criteria established in I-1330(c)(1) or the Owner-established acceptance criteria for other required testsBased upon this evaluation, the Owner shall determine the need for testing in addition to the minimum tests specified in I-1330(c) to address any generic concerns which could apply to valves in the same or other valve groups. The relief request that the NRC approved only relieved PPL of the requirement to test further valves for a failure outside the -3 percent criterion. PPL incorrectly interpreted their relief to include paragraph ISTC-1330(c)(3) and failed to perform the required evaluations for nine SRV failures from 2005 to 2009.

During every refuel outage since 2004, Susquehanna has experienced SRV failures greater than the -3 percent (e.g. -4 percent) TS Surveillance Requirement. In this timeframe, the tested SRVs have experienced an overall failure rate of 30 percent with two of those SRVs deviating by more than -5 percent. In all cases, PPL entered the failures into their corrective action program (CAP). However, in all cases PPL did not evaluate the failures and incorrectly cited the ASME code requirement as being +3 percent instead of +/-3 percent.

The operation of SRVs with reduced set pressure setpoints impacts the plant simmer margin and raises the potential of an operational challenge due to valve leakage, early lift, or failure to reseat. Simmer margin is the difference between the valve safety setting and the valve inlet pressure at rated conditions. Calculation EC-PUPC-1001 discusses the vendors SRV recommended simmer margin to be 150 psi to minimize SRV leakage due to a sealing force factor consideration. For the previous operating cycles, as well as the EPU cycles, both units were operated with a 140 psi simmer margin and credit the steam line to the SRVs with an expected 10 psi drop. Failures of the SRVs low outside the -3 percent band further decrease this simmer margin beyond the vendors recommendation and challenge the onset of SRV leakage as well as valve sticking.

With respect to generic communications, the NRC issued Information Notice (IN)2006-24, Recent OE Associated With Pressurizer And Main Steam Safety/Relief Valve Lift Setpoints. This IN cited that OE shows that new failure mechanisms or root causes can emerge with respect to SRV failures and when several out-of-tolerance valves are routinely identified at a particular plant, this suggests that other causes may also be a factor. The IN continues that since 2005, NRC inspectors identified several findings involving a non-cited violation of 10 CFR Part 50, Appendix B, Criterion XVI, Corrective Actions, for the licensees lack of timely actions to promptly identify and correct out-of-tolerance lift setpoints for the valves specified. The inspectors determined that failure to evaluate and correct SRV failures for generic implications could result in more significant operational challenges at both lower and higher pressures.

None of the SRVs failed their as-found set pressure test in the higher direction.

However, SRVs at Susquehanna have progressively declined in performance in contrast to what PPL reported in their 2001 LER and RR02 and despite an associated increase in the TS surveillance requirement acceptance band. Based on this and the failure to identify and evaluate the cause, effect, and generic implications, the inspectors considered this a performance deficiency.

Analysis:

The inspectors determined that PPLs failure to evaluate the cause, effect, and generic concerns of SRV set pressure test failures was a performance deficiency. This finding was more than minor because there were multiple examples of the failure to maintain and implement the IST program (MC 0612 Appendix E, Example 2h), and it was associated with the equipment performance attribute of the Initiating Event cornerstone and it impacted the cornerstone objective of limiting the likelihood of events that upset plant stability and challenge critical safety functions during power operations.

Specifically, the failure to evaluate SRV test failures resulted in repeated instances where the simmer margin was reduced below vendor recommended values and the failure modes were not evaluated for cause, effect, and generic concerns. Traditional enforcement does not apply since there were no actual safety consequences or potential for impacting the NRCs regulatory function, and the finding was not the result of any willful violation of NRC requirements or PPLs procedures.

The inspectors evaluated this finding using IMC 0609, Attachment 4, Phase 1- Initial Screening and Characterization of Findings worksheet. This finding was determined to be of very low safety significance because it did not contribute to the likelihood of both a reactor trip and that mitigation equipment or functions will not be available.

The inspectors determined that this finding had a cross-cutting aspect in the area of problem identification and resolution because PPL did not thoroughly evaluate the SRV failures such that the causes and extent of condition were addressed. Specifically, no documented analysis was conducted regarding failures over a period of five years to determine cause or evaluate the generic potential for the other SRVs to exhibit the same performance, nor was there consideration for impact on similar components in other systems. (P.1(c))

Enforcement:

Technical Specification 5.5.6 is the Inservice Testing Program which is required to be established, implemented, and maintained. PPLs IST program implements 10 CFR 50.55a(f)(4) for inservice testing requirements set forth in the ASME OM Code. The 1998 ASME OM Code paragraph ISTC-1330(c)(3) requires, in part, that The Owner shall evaluate the cause and effect of valves that fail to comply with the set-pressure acceptance criteria established Based upon this evaluation, the Owner shall determine the need for testing in addition to the minimum tests specifiedto address any generic concerns which could apply to valves in the same or other valve groups.

Contrary to this requirement, PPL did not evaluate SRV set pressure test failures from 2005 to 2009 for cause, effect, and generic concerns. Because of the very low safety significance of this finding and because the finding was entered into PPLs corrective action program as CR 1162307, this violation is being treated as an NCV, consistent with Section VI.A.1 of the NRC Enforcement Policy. (NCV 05000387;5000388/2009003-01, Violation of TS 5.5.6, IST Program)

1R13 Maintenance Risk Assessments and Emergent Work Control (71111.13 - 6 Samples)

a. Inspection Scope

The inspectors reviewed the assessment and management of selected maintenance activities to determine the effectiveness of PPL's risk management for planned and 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 personnel to 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. The selected maintenance activities included:

• Unit 2, shutdown risk Yellow during Unit 1 RHR pump outage window SDHR providing decay heat (DH) removal;

• Unit 2, measuring vent times of RHR piping for known gas volumes, TP-249-087;

• Unit 2, instrument and controls (I & C) investigation of electrohydraulic control (EHC) pressure setpoint 6 psig low during EPU power ascension, PCWO 1149223;

• Common, emergent work and including Unit 1 power reduction to support replacement of river water make-up (RWMU) valve 015011, supply valve to supplemental decay heat removal;

• Common, engineering safeguard system (ESS) transformer OX213 out-of-service for relay calibrations; and

• Common, Yellow calculated equipment out-of-service (EOOS) large early relief frequency (LERF) results for electrical breaker work, HV0122A1 residual heat removal service water ((RHRSW) large spray array on June 15).

b. Findings

No findings of significance were identified.

1R15 Operability Evaluations (71111.15 - 5 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. In 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, Final Safety Analysis Report (FSAR), and associated Design Basis Documents as references during these reviews.

The issues reviewed included:

• Unit 2, low voltage alarm on bus 2A202 4 kV bus during transfer;

• Unit 2, RHR pipe stress/dynamic qualification deficiency - Class I stress analysis, CR 1139592;

• Unit 2, S SRV failed remote position verification (IST), CR 1141005;

• Unit 2, OFR 1152233, work performed for work orders 888339 and 889495 without use of pressure instrumentation measuring and test equipment (M&TE);and

• Unit 2, core thermal heat balance on loss leading edge flow meter (LEFM) during turbine valve testing and EPU power ascension.

b. Findings

No findings of significance were identified.

1R18 Plant Modifications (71111.18 - 1 Sample)

Permanent Plant Modifications

a. Inspection Scope

The inspectors reviewed a permanent plant modification to determine whether the change 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 change by reviewing selected drawings and procedures to verify whether appropriate updates had been made. The inspectors compared the actual installation to the permanent modification documents to determine whether the implemented change was consistent with the approved documents. The inspectors reviewed selected post-installation test results to verify whether the actual impact of the change had been adequately demonstrated by the test. The following modifications and documents were included in the review:

• Unit 2, ADHR EC 881351 installation of manual isolation valve in RHR line HBB-211.

b. Findings

No findings of significance were identified.

1R19 Post-Maintenance Testing (71111.19 - 7 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 was satisfied. The PMT activities reviewed included:

• Unit 1, 1B RHRSW pump re-baseline post IST-failure;

• Unit 2, 2B reactor protection system (RPS) normal power supply electrical protective assembly (EPA) breaker replacements;

• Unit 2, Division I core spray pumps following system maintenance, SO-251-A02;

• Unit 2, control rod drive (CRD) testing following CRD and/or control rod blade replacement;

• Unit 2, RHR 15A injection outboard isolation following local leak rate test (LLRT)and IST failures;

• Unit 2, 1B circulating water pump post-maintenance test run with recirculation runback bypassed, TP-242-003; and

• Unit 2, condensate pump trip test for EPU, TP-244-042.

b. Findings

No findings of significance were identified.

1R20 Refueling and Other Outage Activities (71111.20 - 1 Sample, 71004)

.1 Unit 2 Refueling Outage

a. Inspection Scope

Outage Risk Assessment The inspectors reviewed the outage risk management plan for the Unit 2 refueling outage, planned for April 9 to May 10, 2009, to confirm that PPL had appropriately considered risk, industry experience, and previous site-specific problems in developing and implementing a plan that assured maintenance of defense-in-depth.

Plant Shutdown and Refueling Outage Activities During the refueling outage, the inspectors observed and/or reviewed the outage activities listed below.

• Plant shutdown and cool down activities;

• Establishment of a reactor vessel cool down rate;

• Transition to RHR shutdown cooling method of decay heat removal;

• Outage configuration controls including:

1) availability and accuracy of reactor coolant system instrumentation; 2) electrical power alignments; 3) decay heat removal system operation, including spent fuel pool cooling system supplemental decay heat removal system, and time to boil calculations; 4) availability of reactor inventory makeup water systems; and 5) secondary containment controls and integrity.

• Drywell and suppression chamber walkdowns after shutdown;

• 4 KV emergency buses and supplemental decay heat removal equipment clearances; and

• fuel handling operations including fuel movement, control of reactivity, and fuel assembly tracking.

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 Technical Specification requirements and operating procedures.

Restoration of Systems and Plant Restart Activities The inspectors monitored major system restoration activities, testing and restart activities that were performed at the completion of the Unit 2 refueling outage which was conducted from April 7, 2009 through May 16, 2009. The inspectors observed and reviewed the following:

• Control rod testing;

• Core reload activities and core verification;

• Reactor coolant system hydrostatic testing;

• Primary containment walkdowns prior to closeout;

• Restoration of secondary containment;

• Plant heatup and reactor startup;

• Main steam and turbine valve testing;

• Main turbine startup and loading of generator;

• Plant power ascension; and

• Implementation of EPU testing plan.

During the conduct of the above 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. Inspectors also reviewed all EPU test exceptions and verified that all testing conditions including schedules were in agreement with approved EPU license conditions and PPLs established testing plan.

b. Findings

Introduction:

The inspectors identified an NCV of 10 CFR 50.73(a)(2)(vii), in that PPL did not submit an LER for a common cause failure and consequent inoperability of two or more SRVs in 2005, 2008, and 2009.

Discussion: The inspectors reviewed the as-found set pressure testing of SRVs during the Unit 2 refueling outage in April and May 2009. Three of six SRVs failed that testing as documented in CR 1140321 on April 29, 2009. Under that CR and based on a review of NDAP-QA-0720, Station Report Matrix and Reportability Evaluation Guidance, Revision 15, operations initially determined that the failure conditions were not reportable. The CR was then closed on May 9, 2009, at which point the inspectors questioned whether the Nuclear Regulatory Affairs (NRA) department had evaluated the issue for reportability. Since the original CR had been closed, NRA initiated a new CR 1150432 to provide a reportability follow-up determination. This CR determined the condition was not reportable by citing that setpoint drift was not identified as a common cause applicable to 10 CFR 50.73(a)(2)(vii). It further stated that the vendor who performed the testing indicated no other reason for the failures than setpoint drift.

Contrary to this, NUREG-1022, Event Reporting Guidelines 10 CFR 50.72 and 50.73, Revision 2, states that an LER is required for a common cause inoperability of independent trains or channels. The NUREG does not eliminate setpoint drift as a potential contributor to common cause. Further, IN 2006-24, Recent OE Associated with Pressurizer and Main Steam Safety/Relief Valve Lift Setpoints, identifies in its discussion section that random setpoint drift is a recognized phenomenon that is valid for licensees to include in their LER root cause discussion. IN 2006-24 identifies that setpoint drift is considered a type of common cause. During further investigation, the inspectors discovered that the same condition of not reporting two or more SRV failures due to a common cause also applied during 2005 and 2008.

A review of site procedures and documents to determine why the report was missed revealed four contributors to the error. First, the original CR that captured the SRV failures and determined reportability did not identify the cause of the SRV failures.

Documentation and evaluation of the failures would have supported PPL in its determination of report applicability. Second, a gap was identified in the AR and CR screening team charter as listed in Attachment E of NDAP-QA-0702, Action Request and Condition Report Process, Revision 22. Though the charter requires a member to be qualified to make reportability determinations and expects the team to evaluate or re-affirm immediate and long-term reportability impacts, there was no team guidance to issue a request for follow-up (RFU) to Nuclear Regulatory Affairs (NRA) for further evaluation of reportability. Instead, the corrective action and assessment group had an uncontrolled guidance document on reportability. That guidance directed the screening team to contact licensing with reportabilty questions and to generate a RFU to NRA with a 60 day due date to support timely reporting. This uncontrolled guidance document was not followed on the matter of SRV failures. This issue was captured in PPLs CAP under CR 1157607. Third, a missed opportunity occurred during PPLs review of K, Section 3.1, of NDAP-QA-0720. This section discusses multiple test failures and cites as an example, multiple test failures involving the sequential testing of safety valves. It further states that the existence of similar discrepancies in multiple valves is an indication that the discrepancies arose over a period of time. Therefore, the condition existed during plant operation and the event is reportable. Finally, all three CRs that identified the SRV failures in 2005, 2008 and 2009 incorrectly cited the same section of NUREG-1022 as part of the justification for not reporting the condition. This suggests that an inadequate review of NUREG-1022 for applicability occurred repetitively over the four year span.

Analysis:

The inspectors determined that PPLs repetitive failure to report the common cause inoperability of SRVs in 2005, 2008, and 2009 was a performance deficiency and impacted the NRCs ability to perform its regulatory function. This finding was evaluated using the traditional enforcement process because the failure to accurately report events has the potential to impact or impede the regulatory process. The finding was determined to be a Severity Level IV violation based on Supplement I, Example D.4 of the NRC Enforcement Policy.

The inspectors determined that this finding had a cross-cutting aspect in the area of problem identification and resolution because while PPL collected and evaluated external OE, it did not thoroughly incorporate IN 2006-24 to include SRV set point drift as a reportable common cause failure method. (P.2(b)).

Enforcement:

10 CFR 50.73(a)(2)(vii) requires, in part, that any event where a single cause or condition caused at least one independent train or channel to become inoperable in multiple systems or two independent trains or channels to become inoperable in a single system designed. . .(B) remove residual heat; . . . (D) mitigate the consequence of an accident is reportable. Contrary to this requirement, during 2005, 2008, and 2009 the licensee failed to report instances where two or more SRVs as-found testing failures resulted in inoperability and were attributable to a common cause.

Because this violation was of very low safety significance, was not repetitive or willful, and was entered into PPLs corrective action program (CR 1161398), this violation is being treated as an NCV consistent with the NRC Enforcement Policy. (NCV 05000387; 388/2009003-02, Violation of 10 CFR 50.73(a)(2)(vii), Report Common Cause Failures of Independent Channels)

1R22 Surveillance Testing (71111.22 - 6 Samples)

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 Technical Requirements Manual operability and surveillance requirements to evaluate whether the systems were capable of performing their intended safety functions. The observed or reviewed surveillance tests included:

• Unit 2, RHR Divisions I and II logic system functional tests;

• Unit 2, RHR testable check valve 50B LLRT;

• Unit 2, MSIV C inboard and outboard LLRT and fail safe testing;

• Unit 2, drywell sump configuration control and design bases;

• Unit 2, high pressure coolant injection (HPCI) flow at 150 psig and reactor core isolation cooling (RCIC) flow at 920 psig; and

• Common, monthly control room emergency outside air supply (CREOAS)operability test.

b. Findings

No findings of significance were identified.

Cornerstone: Emergency Preparedness

1EP2 Alert and Notification System Evaluation (71114.02 - 1 Sample)

a. Inspection Scope

An onsite review was conducted to assess the maintenance and testing of the new Susquehanna alert and notification system (ANS), which was placed in service on December 15, 2008. During this inspection, the inspectors interviewed EP staff responsible for implementation of the ANS testing and maintenance and reviewed condition reports pertaining to the ANS for causes, trends, and corrective actions. The inspector reviewed the ANS procedures and the ANS design report to ensure PPLs compliance with design report commitments for system maintenance and testing. The inspection was conducted in accordance with NRC Inspection Procedure 71114,

.02. Planning Standard (PS), 10 CFR 50.47(b) (5), and the related

requirements of 10 CFR 50, Appendix E, were used as reference criteria.

b. Findings

No findings of significance were identified.

1EP3 Emergency Response Organization Staffing and Augmentation System (71114.03 -

1 sample)

a. Inspection Scope

The inspectors conducted a review of Susquehannas emergency response organization (ERO) augmentation staffing requirements and the process for notifying and augmenting the ERO. This was performed to ensure the readiness of key licensee staff to respond to an emergency event and to ensure PPLs ability to activate their emergency facilities in a timely manner. The inspectors reviewed the Susquehanna ERO roster, training records, applicable procedures, drill reports for augmentation, quarterly emergency preparedness (EP) drill reports, and CRs related to the ERO staffing augmentation system. The inspection was conducted in accordance with NRC Inspection Procedure 71114, Attachment

.03. PS, 10 CFR 50.47(b)(2), and related requirements of 10 CFR

50, Appendix E were used as reference criteria.

b. Findings

No findings of significance were identified.

1EP4 Emergency Action Level and Emergency Plan Changes (1114.04 - 1 Sample)

a. Inspection Scope

Since the last NRC inspection of this program area, in October 2008, PPL implemented various revisions of the different sections of the Susquehanna Steam Electric Station Emergency Plan. PPL had determined that, in accordance with 10 CFR 50.54(q), any change made to the plan, and its lower-tier implementing procedures, had not resulted in any decrease in effectiveness of the plan, and that the revised plan continued to meet the requirements of 10 CFR 50.47(b) and Appendix E to 10 CFR 50. The inspectors confirmed no emergency action level (EAL) changes had been made since October 2008, and conducted a sampling review of other EPl changes, including the changes to lower-tier emergency plan implementing procedures, to evaluate for any potential decreases in effectiveness of the emergency plan. However, this review was not documented in an NRC safety evaluation report and does not constitute formal NRC approval of the changes. Therefore, these changes remain subject to future NRC inspection in their entirety. The inspection was performed in accordance with NRC Inspection Procedure 71114, Attachment

.04. The requirements in 10 CFR 50.54(q)

were used as reference criteria.

b. Findings

No findings of significance were identified.

1EP5 Correction of Emergency Preparedness Weaknesses (71114.05 - 1 Sample)

a. Inspection Scope

The inspectors reviewed a sampling of self-assessment procedures and reports to assess PPLs ability to evaluate their EP performance and programs. The inspectors reviewed a sampling of CRs from January 2008 through June 2009, initiated by PPL at Susquehanna from drills, self-assessments, and audits. Additionally, the inspectors reviewed: quality assurance audits, including 10 CFR 50.54(t) audits; the event report for the October 2008 Alert declaration at Susquehanna; and several self-assessment reports. This inspection was performed in accordance with NRC Inspection Procedure 71114, Attachment

===.05. PS, 10 CFR 50.47(b)

(14) and the related requirements of 10===

CFR 50 Appendix E were used as reference criteria.

b. Findings

No findings of significance were identified.

RADIATION SAFETY

Cornerstone: Occupational Radiation Safety (OS)

2OS1 Access Control to Radiologically Significant Areas (71121.01 - 8 Samples)

a. Inspection Scope

The inspector identified exposure significant work areas within radiation areas, high radiation areas (<1 R/hr), or airborne radioactivity areas in the plant and reviewed associated licensee controls and surveys of these areas to determine if controls (e.g.,

surveys, postings, barricades) were acceptable.

With a survey instrument, the inspector walked down these areas or their perimeters to determine whether prescribed radiation work permits, procedure, and engineering controls were in place, whether PPL surveys and postings were complete and accurate, and whether air samplers were properly located.

The inspector reviewed radiation work permits used to access these and other high radiation areas and identify what work control instructions or control barriers had been specified. The inspector used plant-specific Technical Specification high radiation area requirements as the standard for the necessary barriers. The inspector reviewed electronic personal dosimeter alarm set points (both integrated dose and dose rate) for conformity with survey indications and plant policy. The inspector verified that workers knew what actions were required when their electronic personal dosimeter noticeably malfunctions or alarms.

The inspector reviewed radiation work permits for airborne radioactivity areas with the potential for individual worker internal exposures of >50 mrem committed effective dose equivalent (20 DAC-hrs). For these selected airborne radioactive material areas, the inspector verified barrier integrity and engineering controls performance (e.g., HEPA ventilation system operation).

Based on PPLs schedule of work activities, the inspector selected three jobs being performed in radiation areas, airborne radioactivity areas, or high radiation areas (<1 R/hr) for observation (nozzle and vessel ISI, scaffold in drywell, CRD exchange). The inspector observed work that was estimated to result in the highest collective doses, involved diving activities in or around spent fuel or highly activated material, or that involved potentially changing (deteriorating) radiological conditions. The inspector reviewed all radiological job requirements (radiation work permit requirements and work procedure requirements). The inspector observed job performance with respect to these requirements. The inspector determined that radiological conditions in the work area were adequately communicated to workers through briefings and postings.

During job performance observations, the inspector verified the adequacy of radiological controls, such as: required surveys (including system breach radiation, contamination, and airborne surveys), radiation protection job coverage (including audio and visual surveillance for remote job coverage), and contamination controls.

During job performance observations, the inspector observed radiation worker performance with respect to stated radiation protection work requirements. The inspector determined that they were aware of the significant radiological conditions in their workplace, and the radiation work permit controls/limits in place, and that their performance took into consideration the level of radiological hazards present.

During job performance observations, the inspector observed radiation protection technician performance with respect to all radiation protection work requirements. The inspector determined that they were aware of the radiological conditions in their workplace and the radiation work permit controls/limits, and their performance was consistent with their training and qualifications with respect to the radiological hazards and work activities.

The inspector evaluated PPLs performance against the requirements contained in 10 CFR 20 and Plant Technical Specification 5.7.

b. Findings

No findings of significance were identified.

2OS2 ALARA Planning and Controls (71121.02 - 3 Samples)

a. Inspection Scope

Based on scheduled work activities and associated exposure estimates, the inspector selected 3 work activities in radiation areas, airborne radioactivity areas, or high radiation areas for observation (see Section 2OS1 above). The inspector concentrated on work activities that presented the greatest radiological risk to workers. The inspector evaluated the PPLs use of ALARA controls for these work activities by evaluating the PPLs use of engineering controls to achieve dose reductions.

The inspector evaluated PPLs performance against the requirements contained in 10 CFR 20.1101.

The inspector reviewed recent licensee condition reports to determine if identified problems were entered into the corrective action program for resolution.

b. Findings

No findings of significance were identified.

2OS3 Radiation Monitoring Instrumentation (71121.03 - 1 Sample)

a. Inspection Scope

The inspector reviewed PPL self-assessments, audits, and Licensee Event Reports and focused on radiological incidents that involved personnel contamination monitor alarms due to personnel internal exposures. For internal exposures >50 mrem committed effective dose equivalent, the inspector determined if the affected personnel were properly monitored utilizing calibrated equipment and if the data was analyzed and internal exposures properly assessed in accordance with PPL procedures. The inspector determined if identified problems were entered into the corrective action program for resolution.

The inspector evaluated PPLs performance against the requirements contained in 10 CFR 20.1501, 10 CFR 20.1703, and 10 CFR 20.1704.

b. Findings

No findings of significance were identified.

Cornerstone: Public Radiation Safety (PS)

2PS3 Radiological Environmental Monitoring Program and Radioactive Materials Control (7112203 - 10 Samples)

a. Inspection Scope

The inspector reviewed the most current Annual Environmental Monitoring Report and licensee assessment results to verify that the radiological environmental monitoring program (REMP) was implemented as required by TS and the Offsite Dose Calculation Manual (ODCM). The inspector 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 inspector reviewed the ODCM to identify environmental monitoring stations. The inspector reviewed PPL self-assessments, audits, licensee event reports, and interlaboratory comparison program results. The inspector reviewed the FSAR for information regarding the environmental monitoring program and meteorological monitoring instrumentation. The inspector reviewed the scope of PPLs audit program to verify that it met the requirements of 10 CFR 20.1101(c).

The inspector walked-down the air sampling stations and the thermoluminescence dosimeter (TLD) monitoring stations to determine whether they were located as described in the ODCM and to determine the equipment material condition. The inspector visited 25 TLD locations and seven air sampling stations.

The inspector observed the collection and preparation of a variety of environmental samples (e.g., ground and surface water, milk, vegetation, sediment, and soil). The inspector verified that environmental sampling was representative of the release pathways as specified in the ODCM and that sampling techniques were in accordance with procedures. The inspector directly observed the collection of four milk samples, three surface water samples, one drinking water sample, three off-site precipitation samples, and four on-site precipitation samples.

Based on direct observation and review of records, the inspector verified that the meteorological instruments were operable, calibrated, and maintained in accordance with guidance contained in the FSAR, NRC Safety Guide 23, and licensee procedures.

The inspector reviewed each event documented in the Annual Environmental Monitoring Report which involved a missed sample, inoperable sampler, lost TLD, or anomalous measurement for the cause and corrective actions. The inspector conducted a review of PPLs assessment of any positive sample results (i.e., licensed radioactive material detected above the lower limits of detection (LLDs). The inspector reviewed the associated radioactive effluent release data that was the likely source of the released material.

The inspector reviewed any significant changes made by the licensee to the ODCM as the result of changes to the land census or sampler station modifications since the last inspection. The inspector reviewed technical justifications for any changed sampling locations. The inspector verified that the licensee 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 inspector reviewed the calibration and maintenance records for air samplers and composite water samplers. The inspector reviewed calibration records for the environmental sample radiation measurement instrumentation. The inspector verified that the appropriate detection sensitivities with respect to TS/ODCM were utilized for counting samples. The inspector reviewed quality control charts for maintaining radiation measurement instrument status and actions taken for degrading detector performance. The inspector reviewed the results of PPLs interlaboratory comparison program to verify the adequacy of environmental sample analyses performed by PPL.

The inspector reviewed the licensees quality control evaluation of the interlaboratory comparison program and the corrective actions for any deficiencies. The inspector reviewed QA audit results of the program to determine whether PPL met the TS/ODCM requirements.

The inspector observed several locations where the licensee monitors potentially contaminated material leaving the radiologically controlled area (RCA), and inspected the methods used for control, survey, and release from these areas. When possible, the inspector observed the performance of personnel surveying and releasing material for unrestricted use to verify that the work was performed in accordance with plant procedures.

The inspector verified that the radiation monitoring instrumentation was appropriate for the radiation types present and was calibrated with appropriate radiation sources. The inspector reviewed PPLs criteria for the survey and release of potentially contaminated material. The inspector verified that there was guidance on how to respond to an alarm which indicates the presence of licensed radioactive material. The inspector reviewed PPLs equipment to ensure the radiation detection sensitivities were consistent with the NRC guidance contained in IE Circular 81-07 and IE Information Notice 85-92 for surface contamination and HPPOS-221 for volumetrically contaminated material. The inspector reviewed PPLs procedures and records to verify that the radiation detection instrumentation was used at its typical sensitivity level based on appropriate counting.

The inspector verified that PPL had not established a release limit by altering the instruments typical sensitivity through such methods as raising the energy discriminator level or locating the instrument in a high radiation background area.

The inspector reviewed PPLs Licensee Event Reports, Special Reports, audits, and self-assessments related to the radiological environmental monitoring program performed since the last inspection. The inspector determined that identified problems were entered into the corrective action program for resolution.

The inspector reviewed corrective action reports affecting environmental sampling, sample analysis, or meteorological monitoring instrumentation. The inspector interviewed staff and reviewed documents to determine if the following activities were being conducted in an effective and timely manner commensurate with their importance to safety and risk:

• Initial problem identification, characterization, and tracking;

• Disposition of operability/reportability issues;

• Evaluation of safety significance/risk and priority for resolution;

• Identification of repetitive problems;

• Identification of contributing causes;

• Identification and implementation of effective corrective actions;

• Resolution of NCVs tracked in corrective action system(s); and

• Implementation/consideration of risk significant operational experience feedback.

For repetitive deficiencies or significant individual deficiencies in problem identification and resolution identified above, the inspector determined that the licensees self-assessment activities were also identifying and addressing these deficiencies.

The inspectors evaluated the licensees performance against the requirements contained in 10 CFR 50.36, 10 CFR 50, Appendix I, and Plant Technical Specification 6.9.1.7.

b. Findings

No findings of significance were identified.

4OA1 Performance Indicator Verification (71151 - 7 Samples)

.1 Barrier Integrity

a. Inspection Scope

The inspectors reviewed PPLs performance indicator (PI) data for the period of June 2008 through June 2009 to verify whether the PI data was accurate and complete. The inspectors examined selected samples of PI data, PI data summary reports, and plant records. The inspectors compared the PI data against the guidance contained in Nuclear Energy Institute (NEI) 99-02, Regulatory Assessment Performance Indicator Guideline and PL-NF-06-002, SSES Mitigating System Performance Index Basis Document, Revision 4. The following performance indicators were included in this review:

• Units 1 and 2 reactor coolant system (RCS) activity (BI01); and

• Units 1 and 2 RCS identified leak rate (BI02).

b. Findings

No findings of significance were identified.

.2 Emergency Preparedness

a. Inspection Scope

The inspectors reviewed data for the Susquehanna EP PIs, which are:

(1) Drill and Exercise Performance (DEP);

(2) Emergency Response Organization (ERO) Drill Participation; and,

(3) Alert and Notification System (ANS) Reliability. The last NRC EP inspection at Susquehanna was conducted in the fourth quarter of 2008, so the inspectors reviewed supporting documentation from EP drills, training records, and equipment tests from the fourth calendar quarter of 2008 and the first quarter of 2009, to verify the accuracy of the reported PI data. The review of these PIs was performed in accordance with NRC Inspection Procedure 71151, using the acceptance criteria documented in NEI 99-02, Regulatory Assessment Performance Indicator Guidelines, Revision 5.

b. Findings

No findings of significance were identified.

4OA2 Identification and Resolution of Problems (71152 - 3 Samples)

.1 Review of Items Entered into the Corrective Action Program

a. Inspection Scope

As specified by Inspection Procedure (IP) 71152, Identification and Resolution of Problems (PI&R), and in order to help identify repetitive equipment failures or specific human performance issues for followup, the inspectors performed screening of all items entered into PPLs corrective action program. This was accomplished by reviewing the description of each new action request/condition report and attending daily management meetings.

b. Findings

No findings of significance were identified.

.2 Semi-Annual Review to Identify Trends

a. Inspection Scope

As required by Inspection Procedure 71152, Identification and Resolution of Problems, the inspectors performed a review of the licensees 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 screening discussed in Section 4OA2.1. The review also included issues documented outside the normal CAP in corrective maintenance work orders, component status reports, site monthly meeting reports and maintenance rule assessments. The inspectors review concentrated on the six month period of January through June 2009, 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 the licensees trend report were reviewed for adequacy.

As part of this sample and in support of the potential Chilling Effect Letter issued to PPL in January 2009, the inspectors examined issues related to the general work environment (GWE) at Susquehanna. Specific documents reviewed are listed in the attachment

b. Findings

No findings of significance were identified.

c. Assessment and Observations Energy Control Process The inspectors noted a continuation of issues related to the energy control process as discussed in the last semi-annual trend review found in NRC Inspection Report 0500387; 388/2008005. A number of higher significance, Energy Control Process events were noted during the Unit 2 refueling outage. Of particular note, there were three Level 1 events with two of those events occurring within five days of each other. A Level 1 energy control process event is a case where the remaining programmatic barriers, whether administrative or physical, were not effective to protect workers from potential energy sources.

Heating, Ventilation, and Air Conditioning (HVAC)

The inspectors identified a potential adverse trend related to ventilation system health.

refrigerant leaks, elevated fan vibrations, elevated bearing temperatures, and temperature control loop issues that appear to be the lead contributors to equipment degradation. For instance, the A control structure chiller incurred 86 hours9.953704e-4 days <br />0.0239 hours <br />1.421958e-4 weeks <br />3.2723e-5 months <br /> of unavailability due to corrective maintenance and rework on its service water (SW)temperature control system. In addition, Operations received a guidance document from system engineering on 1B turbine building chiller motor current oscillations as well as its own SW temperature control valve issue. Lastly, the site issued a condition report in late June on the numerous failures of cycle timers on station chillers.

The aggregate of these issues has resulted in operational challenges. For example, on January 20, 2009, the A turbine building filtered exhaust fan experienced a short duration, isolated fire due to a failed bearing. On April 15, the A EDG was unloaded and shutdown due to a generator neutral overvoltage alarm that was later attributed to a 1A turbine building chiller motor failure. A day later, Unit 1 average containment temperature momentarily exceeded the limiting condition for operation (LCO) setpoint of 135° F after both RB chillers tripped, one on low refrigerant and the other on high bearing temperature. On April 26, high temperatures were experienced in the turbine building because the 1A turbine building chiller remained out-of-service for maintenance since the failure on April 15 and the 1B turbine building chiller tripped on low refrigerant level.

Station Trending and Analysis Inspection Procedure 71152 recommends the review of licensee trend and system health reports to identify trends that might indicate the existence of a more significant safety issue. The inspectors noted that the most recent site-wide, semi-annual trend review report for July to December 2008 was not completed as of June 26, 2009. The inspectors further noted that the quarterly trend analysis for January to March 2009, specified for each responsibility center, was incomplete for nuclear maintenance, work management, health physics, effluents, and corrective action and assessment. The station system health report for January to April 2009 was also incomplete. This report was changed from a three month to a four month scope in 2004 to ensure that Spring refuel outage results were incorporated. Since the 2009 outage shifted to April and half of May, this report is expected to be complete in July 2009. While this delay is understandable, PPLs overall lack of timely trending and analysis in accordance with self-established periodicities suggests a decreased focus and priority on evaluating performance gaps and precursor trends.

Work Environment The inspectors reviewed the usage of available programs for raising concerns over the last six months. A review of the employee concerns program (ECP) revealed seven entries in the program since the beginning of the year with the latest entry in April. Six of those entries were entered via indirect means; the issues were recommended for capture under the ECP by a third party or teams that became aware of the issue and evaluated them as best served, in whole or in part, by the ECP. Only one of those entries was created as a result of a direct encounter between the concerned individual and an ECP representative. A review of the Ombudsman program, created on June 30, 2008, showed that in the same timeframe, program usage has been on average with the previous six months of data. On May 19, 2009, PPL placed a telephone/web hotline in service. Since the hotlines inception, there have been three entries made. About a dozen anonymous condition reports have been generated using the handwritten method since its inception in February with peaks in April and May, 2009. The web-version of the anonymous condition report was enabled around June 22.

Overall, the effectiveness of the hotline and anonymous condition reporting methods is indiscernible at this time as they remain in their early stages of use. PPLs plans include a return to a permanent onsite ECP representative and that staff position was posted for applicants on May 22, 2009.

The inspectors also reviewed condition reports with work environment codes since August 1, 2008. They reviewed trends by sub-category and monthly interval as well as a comparison of the total number in each code and the total number each month. No trends were identified. However, it was noted that employee issues, plant equipment or tool issue, and GWE enhancement contributed to the majority of the general work environment coded condition reports.

.3 Annual Sample: Review of T20 Startup Transformer Degraded Conditions

a. Inspection Scope

The inspectors selected AR 1082316 and AR 1097273 as PI&R samples for a detailed follow-up review. Both issues involved degraded conditions associated with the T20 startup transformer (T20). T20 has risk importance as it is one of two step-down transformers that provide an offsite power source to all Unit 1 and Unit 2 safety-related, 4kV busses.

AR 1082316 documented on October 13, 2008, a high power factor

(pf) for the H1 high voltage (HV) bushing on T20. Pf is a measure of the power loss through an insulation system and the results are expressed in percent, i.e. the percentage of the resistive current flowing through the insulation to the total current flowing. Higher pfs can be indicative of insulation breakdown or moisture intrusion. Several industry standards and vendor manuals recommend pf testing at bushing installation and regular intervals. The values obtained at each test are compared to the previous tests and nameplate factory tests, and a trend can be established as the bushing ages. Additionally, industry standards and vendor manuals provide trends and absolute pf values when increased pf testing should occur, the vendor should be consulted for guidance, or the bushing removed from service.

AR 1097273 documented on December 4, 2008, an increase in particulates in the T20 automatic load tap changer (LTC) insulating oil. A routine LTC oil sample was taken on October 14, 2008, and the sample sent to a vendor for specialized analysis. Oil analysis is performed to verify that the insulating oil is free from contamination, has maintained its insulating properties, and the particulates and dissolved gases are as expected when compared to the actual LTC operation.

The inspectors assessed PPLs problem identification threshold, cause analyses, extent of condition reviews, operability determinations, and the prioritization and timeliness of corrective actions to determine whether PPL was appropriately identifying, characterizing, and correcting problems associated with the T20 issues and whether the planned or completed corrective actions were appropriate to prevent recurrence.

Additionally, the inspectors interviewed cognizant plant personnel regarding the identified issues. The documents reviewed are listed in the Attachment.

b. Findings and Observations

No findings of significance were identified.

The inspectors determined that PPL properly implemented their corrective action process regarding the initial discovery of the above issues. The AR packages were complete and included cause evaluations, operability determinations, extent of condition reviews, corrective actions, and planned corrective actions.

However, the inspectors identified a departure from industry standards and vendor literature with HV bushing maintenance during 1984 and 2002 maintenance activities.

These 1984 and 2002 departures should have been recognized by PPL during their investigation and evaluation of the increased H1 bushing pf and should have been entered into the corrective action program for evaluation. The departures involved maintaining a permanent record of pf testing, measuring and recording pre-installation and post-installation pfs, more frequent pf testing compared to current and past PPL HV bushing maintenance practices, and thresholds for investigating pf increases compared to nameplate and previously measured values. PPL initiated CR 1138045 to resolve their departure from industry standards and vendor literature. The inspectors identified the following vendor recommendations that were not being consistently applied in the PPL HV bushing maintenance program:

• Westinghouse Instruction Leaflet (IL)44-661, Instructions for Type O Plus Condenser Bushings 115kV through 196kV, dated April, 1983 provided guidance that bushing pf measurements should be taken prior to bushing installation and after installation and compared to nameplate data. IL 44-661 also provided guidance that these results should be a permanent record and used for future comparison during routine testing. PPL did not have any record of pre-installation or post-installation pf results for the T20 HV bushings from the 1984 transformer assembly. (The transformer was assembled on-site at Susquehanna in 1984 and maintained as a spare until 2002 when it was entered into service as a T20 replacement.);

• Westinghouse IL 44-661 provided guidance that when the bushing is placed in service, the pf should not vary more than 10% from nameplate values. ABB IL 44-666G for type O Plus C bushings, the current applicable bushing replacement and associated vendor, provided guidance that ABB Power T&D Company Inc. should be contacted for corrective action procedures if the pf doubles the original installation value. The Doble Reference Book on High Voltage Bushings provided guidance that any significant change from nameplate values should be investigated. And finally, IEEE standard C57.19.100-1995, IEEE Guide for Application of Power Apparatus Bushings, provided guidance that any bushing that exhibits a history of continued pf increase should be scheduled for removal from service and further investigation and the bushing manufacturer consulted for guidance. In 2002, PPL measured a 0.47% pf compared to the 1984 nameplate 0.23% pf and PPL did not thoroughly investigate the 100% increase in pf. (No other pf values were available for trending because pre-installation and post-installation bushing pf values were not measured or a record maintained during transformer assembly in 1984); and

• ABB IL 44-666G recommended an annual pf test frequency for O plus C bushings. IEEE standard C57.19.100-1995 recommended bushing pf testing within one year of installation and at a 3-5 year interval thereafter. In 2006, PPL changed its frequency for pf testing the T20 bushings to 4 years, but PPL decided, on a one time basis, to not test the T20 bushings until 2008, six years after its previous test and after being placed in service.

The inspectors also identified a minor weakness in an operability determination (OFR 1082498) for the H1 bushing increased pf. The operability determination did not include an increased frequency of pf testing for the H1 bushing which would be consistent with the previously mentioned vendor literature and industry standards. PPL intends to replace the T20 at the earliest practical opportunity, but has not determined a date within the operability determination to re-measure the H1 bushing pf and reassess operability if the transformer replacement were delayed. PPL entered this minor issue into its corrective action program as AR 1138049.

.4 Annual Sample: Review of PPLs Root Cause Analysis (RCA) and Corrective Actions to

Address General Work Environment and Potential Chilling Effect Concerns

a. Inspection Scope

The inspectors performed a detailed review of PPLs RCA conducted in response to the NRCs Potential Chilling Effect Letter of January 28, 2009. The inspectors reviewed, the RCA, internal and third party safety culture survey results from the period between 2006 - 2008, ECP and QA documents and selected reference root cause analysis (RCA)documents. The inspectors also conducted interviews with a sample of the RCA team members, and management, site ECP and QA personnel, and several plant workers, managers, and operators not involved in the RCA team. The inspectors reviewed the RCA for completeness, accuracy, methodology, and reasonableness of the conclusions.

The inspectors also reviewed a sample of the corrective actions from the RCA that were indicated as complete or in progress by document reviews, interviews, or material observation. The inspectors also assessed PPLs commitment to longer term action plan items by verifying that these items were entered into the corrective action process for completion and through interviews of responsible personnel.

Background: On January 28, 2009, the NRC issued a PCE letter advising PPL of concerns related to the safety conscious work environment (SCWE) at Susquehanna and requested PPL provide:

(1) a description of PPLs current action plans to address existing SCWE concerns to preclude a chilled work environment at Susquehanna;

(2) PPL plans for further evaluating the health of the SCWE at Susquehanna; and

(3) the metrics PPL intended to monitor to determine the effectiveness of their actions and ensure a SCWE at the Susquehanna site (ML090280115). Also, on January 28, 2009, the NRC issued Susquehanna Steam Electric Station - NRC Integrated Inspection Report 05000387/2008005 and 05000388/2008005 (ML090230434) which described the SCWE concerns at PPL and provided additional background.

This inspection was performed to review the adequacy of PPLs RCA performed in response to the PCE Letter and to review the proposed corrective actions developed in response to the RCA. This sample also provided an opportunity to monitor PPLs progress in addressing SCWE issues to preclude a chilled work environment at Susquehanna through the second quarter of 2009. The PPL Work Environment Improvement Plan was provided to the NRC on February 27, 2009 (ML090710864) and supplements to the plan were provided on March 13, 2009 (ML090760146), and June 23, 2009 (ML091800460). The supplements provided additional details regarding the planned actions, milestones, and the list of the metrics PPL intended to use to monitor the effectiveness of their actions. The June 23, 2009 supplement included a publicly available summary of the results of PPLs RCA and corrective actions developed in response to the findings of the RCA.

b. Findings and Observations

No findings of significance were identified.

Quality of the Root Cause Analysis The inspectors concluded that PPLs RCA of the SCWE issues at Susquehanna was a quality product which accurately identified root causes and contributing causes which led to the safety culture issues at Susquehanna in 2008. The team consisted of a mix of external subject matter experts; the operations, engineering, maintenance, and radiation protection departments; bargaining unit representatives; and management. The inspector felt that the unique mix enabled the team to take a well-rounded and self-critical look at the safety culture issues. The teams conclusions and observations were well-supported and the methodology used was clear and sound. The inspectors determined that the teams four root causes and twenty five causal factors were reasonable and appropriate corrective actions were developed to address each root cause and causal factor.

However, the inspectors determined that an additional causal factor was not specifically identified. Namely, less-than-adequate (LTA) communications on site contributed to SCWE issues. Specifically:

• LTA communication of personnel and policy changes to the site. Plant management did not communicate well the justification behind several key personnel changes and policy changes in 2007 and 2008. Due to the LTA communications, site personnel were left to draw their own conclusions of the reason behind these changes based upon their own observations. As a result, a number of changes were viewed to be retaliatory in nature. This contributed to the perception that management would retaliate against individuals for raising safety concerns.

• LTA communication of managements accountability for their own actions. In a small number of instances, management created the impression that a double standard existed for management compared to the rest of the plant workers. By management not communicating accountability for their errors, yet holding the plant workers directly accountable to similar errors, the functionality of the event review board/accountability review board process was undermined in the eyes of many plant workers and contributed to these processes becoming SCWE issues.

• LTA timeliness of communications. On several occasions, PPL was not timely in responding to indications of SCWE issues and/or communicating the actions taken to address SCWE issues to site personnel. When communications to the site were untimely, completion of corrective actions were delayed and it potentially undermined the effectiveness of these corrective actions as worker questioned why information was not being rolled out. Examples include:

1) the initial action plans developed in August 2008 were not rolled out to the site for over a month; 2) the RCA was approved on May 28, 2009; however, the conclusions were not rolled out to the site until June 23; and 3) the site did not conduct a comprehensive RCA in response to the result of the 2008 safety culture survey which was available in October 2008. A significant effort to address the issues in the safety culture survey was not commenced until after the NRC issued the January 28, 2009, potential Chilling Effect Letter, thus delaying the development of corrective actions despite indications of SCWE concerns.

While this was not directly identified as a causal factor, PPL has taken actions to improve site wide communications via internal newsletters (The Susquehanna Focus and Susquehanna Grapevine). In addition, PPL captured the inspectors observations in the CAP and incorporated them in the site wide rollout meeting the week of June 23, 2009.

Root Cause Analysis Corrective Actions The inspectors determined that the corrective actions developed by the RCA team to address the root cause and causal factors were reasonable, in most cases. While the majority of the corrective actions were not yet completed, they had been appropriately entered into the corrective action program and the actions were scheduled for completion. The time frame for completion of these schedule actions was also determined to be appropriate.

However, the inspector questioned whether a few of the proposed corrective actions would appropriately address the associated causal factor. For example, two of the causal factors were related to the reporting structure of the QA and ECP organizations; however, due to the fact that PPL has a single nuclear site in its fleet, the reporting structure for these organizations results in them reporting to onsite senior management.

As a result, the lack of independence undermines confidence in ECP program effectiveness and the QA program can be challenged to be an independent auditor if senior management is in the review chain for QA products. The corrective actions to address these causal factors did not establish this independence by having them report to an organization independent of the site.

Employee Concerns Program A strong employee concerns program is a pillar of a successful safety culture. However, at Susquehanna, the ECP is not seen by many plant employees as a viable and effective program. There are several reasons for this result. First, the reporting structure of the ECP does not provide independence from site management. When a concern is brought to the ECP, it is then brought to the ECP oversight team (ECOT)which consists of several members of PPL and site management. The concerns are reviewed and the ECOT assigns a manager or ECP coordinator to conduct a review of the issue. After the investigation is completed, the results are presented to the ECOT which accepts or rejects the investigation and determines how the results will be communicated. Because of this structure, many plant workers see the ECP as an extension of management and do not consider it a viable option to raise concerns about management actions, policies, or work environment issues. As a result, workers were more likely to raise these issues through the union grievance process or bring the issue to the NRC. As a result in 2008, there was a significant divergence of the number of ECP cases

(9) and the number of NRC allegations (36).

Another factor which significantly reduced the effectiveness and confidence of the ECP program was the LTA change management and timing of a significant change to the ECP program in mid-2008. Senior management decided to replace the existing ECP program with an ombudsman. The full-time site ECP representative was reassigned and the Allentown ECP representative was to assist the ombudsman during the transition and then move to a new position. The timing of these changes was not well planned. In early 2008, following a number of significant and contentious policy changes, the number of union grievances was at a high level, and with a large number and increasing number of requests of information related to NRC allegations, senior management wanted to change the face of the ECP program and reduce personnel manning. In addition, the site did a LTA job of communicating these changes to the plant and explaining what the function of the ombudsman was and how it differed from the ECP program. As a result, site confidence in the ECP/ombudsman program fell.

PPLs RCA identified many of these issues and a number of corrective actions have been developed to restore confidence in the employee concerns program. While these corrective actions do appear to be reasonable, the task of restructuring the ECP program for the second time in 12 months and then restoring site confidence in this program will be a significant challenge.

Overall Conclusion PPLs RCA was a quality product and the teams make up, organization, and methodologies ensured that the team conducted a self-critical and well-rounded review of SCWE issues at Susquehanna. The root cause and causal factors identified by the team were reasonable and were consistent with the inspectors observations. Corrective actions were developed to address each root and contributing cause. These corrective actions generally appeared to be reasonable and the schedules were viewed to be timely.

PPL has developed a quality plan for addressing their safety culture issues; however, a key factor in addressing the SCWE issues at Susquehanna will be the implementation and execution of both the RCA corrective actions and the long-term action plans to monitor and improve SCWE at the site, adjusting the plan as necessary and as additional information becomes available.

.5 Identification and Resolution of Problems - Inservice Inspection Activities

a. Inspection Scope

The inspector reviewed a sample of corrective action reports, shown in the attachment, which identified nonconforming conditions discovered during this and the previous outage. The inspector verified that flaws and other nonconforming conditions identified during nondestructive testing were reported, characterized, evaluated, appropriately dispositioned and entered into the corrective action program. The inspector reviewed the actions from the steam dryer replacement for Unit 2. PPL had taken actions to ensure successful fabrication of the dryer assemblies at the vendor facility, successful assembly on site and successful installation of the replacement steam dryer in the reactor vessel. The inspector concluded PPL has taken appropriate actions to preclude recurrence of the Unit 1 steam dryer replacement difficulties.

b. Findings

No findings of significance were identified.

4OA5 Other Activities

.1 Unit 2 Extended Power Uprate and Plant Modifications (71004 and 71111.17)

a. Inspection Scope

The inspectors reviewed four permanent plant modifications and associated 10CFR50.59 screenings that were required to support the SSES Unit 2 EPU. The selected permanent plant modifications were EC 674911, EPU Upgrades for Electro-Hydraulic Control System, Units 1 and 2; EC 674914, MSIV High Flow Isolation Setpoint Change, Unit 2; and EC 6902720, Standby Liquid Control Modification for Extended Power Uprate, Unit 2. The details of the inspection scope are documented in IR 05000387/2009006, 05000388/2009006, NRC Evaluation of Changes, Tests, and Experiments and Permanent Modifications Team Inspection Report.

.2 Quarterly Resident Inspector Observations of Security Personnel and Activities

a. Inspection Scope

During the inspection period, the inspectors conducted observations of security force personnel and activities to ensure that the activities were consistent with licensee security procedures and regulatory requirements relating to nuclear plant security.

These observations took place during both normal and off-normal plant working hours.

b. Findings

No findings of significance were identified.

.3 Unit 2 Extended Power Uprate and Inservice Inspection (IP 71004 and 71111.08)

a. Inspection Scope

The inspector reviewed actions associated with the steam dryer replacement for Unit 2.

PPL had taken actions to ensure successful fabrication of the dryer assemblies at the vendor facility, successful assembly on site, and successful installation of the replacement steam dryer in the reactor vessel. During the inspection performed and described in section 1R08 of this report, the inspector concluded PPL took appropriate actions to preclude recurrence of the Unit 1 steam dryer replacement difficulties during the previous refueling outage in 2008.

b. Findings

No findings of significance were identified.

.4 EPU Power Ascension (Integrated Plant Evolutions) (71111.20 and 71004)

a. Inspection Scope

Inspectors witnessed power ascension following the Unit 2 refueling outage. Inspectors witnessed portions of all reactivity changes made to achieve specific EPU test conditions and when operators increased reactor power to 94.4 percent reactor power (3433 MWth). Inspectors also reviewed operator actions, procedure adherence, and plant response during these integrated plant maneuvers. Unit 2 reached a reactor power level of 3433 MWth on June 3, 2009. Inspectors verified the completion of all EPU license commitments and the evaluation and resolution of all test exceptions.

This was a required sample IAW IP 71004 paragraph 02.02 d. The integrated plant startup and power operation procedures reviewed are provided in the Attachment to this report.

a. Findings

No findings of significance were identified.

.5 EPU Major Plant Tests (71111.19 and 71004)

a. Inspection Scope

Inspectors observed portions and reviewed the following major plant tests. Inspectors evaluated these test procedures before the performance of each test to ensure the test could be conducted safely and in accordance with design and licensing bases.

Inspectors directly observed negative and positive reactivity additions and reviewed the results of each power ascension test to ensure the plant response was as expected.

Plant parameters were evaluated for stability and response characteristics. Inspectors validated the EPU Level 1 acceptance criteria were met and that Level 2 acceptance criteria were met or appropriately evaluated. Each of the following tests was considered an inspection sample that meets the requirements of IP 71004, paragraph 02.02 e:

• Steam dryer steady state vibration data and plant walkdown, TP-262-033;

• EPU EHC pressure regulator testing and main turbine valve cycling, TP-293-041, subtest # 24; and

• Condensate pump trip 94.4 percent EPU (special, infrequent or complex test/evolution), TP-244-042, subtest # 103.

b. Findings

No findings of significance were identified.

.6 Additional EPU Inspection Samples (71111.13, 71111.15, and 71004)

a. Inspection Scope

Inspectors observed portions and reviewed the following activities as listed below and described under report sections 1R13 and 1R15. Inspectors performed these inspection samples with an additional focus on the impact on plant stability, EPU test conditions, the appropriateness of operator actions, and procedural adherence.

Inspectors verified the resolution of all associated EPU test exceptions.

• Unit 2, I&C investigation of EHC pressure setpoint 6 psig low during EPU power ascension; and

• Unit 2, Core Thermal heat balance on loss of LEFM during Turbine valve testing and EPU power ascension.

b. Findings

No findings of significance were identified.

4OA6 Meetings, Including Exit

On April 17, 2009, the health physics and ISI inspectors presented inspection results to Mr. C. Gannon and other members of his staff. PPL acknowledged the findings.

On June 19, 2009, the health physics inspector presented results to Mr. C. Gannon and other members of his staff. PPL acknowledged the findings.

On June 25, 2009, the EP inspectors presented the preliminary inspection results to Mr.

C. Gannon and other members of his staff. The inspector confirmed that proprietary information was not provided or examined during the inspection.

On July 16, 2009, the resident inspectors presented their findings to Mr. C. Gannon, and other members of his staff, who acknowledged the findings. With the exception of the general work environment RCA, the inspectors confirmed that proprietary information was not provided or examined during the inspection.

4OA7 Licensee-Identified 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 March 2, 2009, the shipping supervisor discovered that the activity for a shipment of CFS filters to Studsvik was underreported by a factor of over 500, in violation of Title 10, Code of Federal Regulations, Part 71.5. This error occurred due to a flaw in the software package used to prepare the shipping manifest.

The defect had previously been identified by the software vendor; however, effective corrective actions for the defect were not implemented by PPL. This issue was documented in PPLs corrective action program as condition report 1123079.

• On April 6, 2009, a health physics technician observed that a high radiation area posting and rope barricade located on the 699 elevation of the Unit 2 turbine building near the central entrance to the condenser bay had been moved, leaving the area unbarricaded in violation of plant Technical Specification 5.7. This issue was documented in PPLs corrective action program as condition report 1132182.

• On April 8, 2009, a survey of the condenser bay 656 elevation by the liquid radwaste collect condenser area transfer sump to collect tanks was found to have dose rates of 120 millirem per hour at head level, and a hot spot of 4000 millirem on contact, but was not posted and barricaded in accordance with plant Technical Specification 5.7. The area had previously been surveyed on April 7, 2009, and the maximum reading detected was 35 millirem per hour. This issue was documented in the PPLs corrective action program as condition report 1132782.

• On April 19, 2009, two workers entered the Unit 2 condensate filtration system (CFS) room, a posted high radiation area, without having obtained a high radiation area briefing prior to entry, in accordance with Plant Technical Specification 5.7. This issue was documented in PPLs corrective action program as Condition Report 1136333.

• On April 19, 2009, auxiliary decay heat removal (ADHR) piping was moved to the Unit 2 683 elevation equipment space, creating a high radiation area which was unposted for two hours, in violation of Plant Technical Specification 5.7. This issue was documented in PPLs corrective action program as Condition Report 1136335.

ATTACHMENT:

SUPPLEMENTAL INFORMATION

KEY POINTS OF CONTACT

Licensee Personnel

M. Adelizzi, Senior Engineer, Plant Analysis

R. Bogar, Systems Engineer

P. Brady, Design Engineering Supervisor

P. Capotosto, Systems Engineering Supervisor

N. Coddington, Senior Engineer, Regulatory Affairs

D. Coffin, Emergency Planning Manager

R. Collier, Systems Engineer

D. DAngelo, System Engineering Manager

R. Doty, Radiation Protection Manager

J. Folta, Systems Engineer

C. Gannon, VP Nuclear Operations

R. Healey, GEH

T. Iliadis, Outage Manager

M. Jaworsky, Senior Engineer

R. Kessler, Health Physicist - ALARA

R. Linden, Inservice Inspection Specialist

C. Manges, Regulatory Affairs

M. Micca, Health Physicist - Waste Shipping

R. Pagodin, General Manager, Nuclear Engineering

R. Paley, General Manager, Plant Support

B. Payne, IST Program Engineer

H. Riley, Chemist

S. Sienkiewicz, Supervisor NDE Group

J. Welsh, Nuclear Regulatory Affairs

R. Wehry, General Design Engineering

LIST OF ITEMS OPENED, CLOSED, AND DISCUSSED

Opened

None.

Opened/Closed

05000387; 388/200900301 NCV Violation of T.S. 5.5.6, IST Program (1R12)

05000387; 388/200900302 NCV Violation of 10 CFR 50.73(a)(2)(vii), Report Common Cause Failures of Independent Channels (1R20.1)

BASELINE INSPECTION PROCEDURE PERFORMED