IR 05000387/2009006
| ML092110629 | |
| Person / Time | |
|---|---|
| Site: | Susquehanna  |
| Issue date: | 07/30/2009 |
| From: | Doerflein L Division of Nuclear Materials Safety I |
| To: | Rausch T Susquehanna |
| References | |
| IR-09-006 | |
| Download: ML092110629 (20) | |
Text
uly 30, 2009
SUBJECT:
SUSQUEHANNA STEAM ELECTRIC STATION - NRC EVALUATION OF CHANGES, TESTS, AND EXPERIMENTS AND PERMANENT MODIFICATIONS TEAM INSPECTION REPORT 05000387/2009006 AND 05000388/2009006
Dear Mr. Rausch:
On June 19, 2009, the U.S. Nuclear Regulatory Commission (NRC) completed an inspection at the Susquehanna Steam Electric Station, Units 1 and 2. The enclosed inspection report documents the inspection results, which were discussed on June 19, 2009, with Mr. Richard Pagodin and other members of your staff.
The inspection examined activities conducted under your license as they relate to safety and compliance with the Commissions rules and regulations and with the conditions of your license.
In conducting the inspection, the team reviewed selected procedures, calculations and records, observed activities, and interviewed station personnel.
Based on the results of this inspection, no findings of significance were identified.
In accordance with 10 CFR 2.390 of the NRC's "Rules of Practice," a copy of this letter, its enclosure, and your response (if any) will be available electronically for public inspection in the NRC Public Document Room or from the Publicly Available Records (PARS) component of the NRC's document system (ADAMS). ADAMS is accessible from the NRC Web site at http://www.nrc.gov/reading-rm/adams.html (the Public Electronic Reading Room).
Sincerely,
/RA/
Lawrence T. Doerflein, Chief Engineering Branch 2 Division of Reactor Safety Docket No: 50-387; 50-388 License No: NPF-14, NPF-22 Enclosure: Inspection Report 05000387/2009006 and 05000388/2009006 w/Attachment: Supplemental Information
Mr. Timothy
SUMMARY OF FINDINGS
IR 05000387/2009006 and 05000388/2009006; 06/01/2009 - 06/19/2009; Susquehanna Steam
Electric Station, Units 1 and 2; Engineering Specialist Plant Modifications Inspection.
The report covers a two week inspection of the evaluations of changes, tests, or experiments and permanent plant modifications. The inspection was conducted by one resident inspector, two region based engineering inspectors, and one inspector in-training. No findings of significance were identified. The NRCs program for overseeing the safe operation of commercial nuclear power reactors is described in NUREG-1649, Reactor Oversight Process,
Rev. 4, dated December 2006.
NRC-Identified and Self-Revealing Findings
No findings of significance were identified.
Licensee-Identified Violations
None.
ii
REPORT DETAILS
REACTOR SAFETY
Cornerstones: Initiating Events, Mitigating Systems, Barrier Integrity
1R17 Evaluations of Changes, Tests, or Experiments and Permanent Plant Modifications
.1 Evaluations of Changes, Tests, or Experiments (26 samples)
a. Inspection Scope
The team reviewed seven safety evaluations to determine whether the changes to the facility or procedures, as described in the Updated Final Safety Analysis Report (UFSAR), had been reviewed and documented in accordance with 10 CFR 50.59 requirements. In addition, the team evaluated whether Pennsylvania Power and Light (PPL) had been required to obtain NRC approval prior to implementing the change. The team interviewed plant staff and reviewed supporting information including calculations, analyses, design change documentation, procedures, the UFSAR, technical specifications (TS), and plant drawings, to assess the adequacy of the safety evaluations. The team compared the safety evaluations and supporting documents to the guidance and methods provided in Nuclear Energy Institute (NEI) 96-07, Guidelines for 10 CFR 50.59 Evaluations, as endorsed by NRC Regulatory Guide 1.187, "Guidance for Implementation of 10 CFR 50.59, Changes, Tests, and Experiments," to determine the adequacy of the safety evaluations.
The team also reviewed a sample of nineteen 10 CFR 50.59 screenings and applicability determinations for which PPL had concluded that no safety evaluation was required.
These reviews were performed to assess whether PPL's threshold for performing safety evaluations was consistent with 10 CFR 50.59. The sample of issues inspected that had been screened out by PPL included design changes, calculations, procedure changes, and setpoint changes.
The team reviewed all the safety evaluations PPL had performed during the time period covered by this inspection (i.e., since the last modifications inspection). The screenings and applicability determinations were selected based on the risk significance of the associated structures, systems, and components (SSCs).
In addition, the team compared PPL's administrative procedures, used to control the screening, preparation, review, and approval of safety evaluations, to the guidance in NEI 96-07 to determine whether those procedures adequately implemented the requirements of 10 CFR 50.59. The reviewed safety evaluations, screenings, and applicability determinations are listed in the attachment.
b. Findings
No findings of significance were identified.
.2 Permanent Plant Modifications (9 samples)
.2.1 Main Steam Isolation Valve High Flow Isolation Setpoint Change, Unit 2
a. Inspection Scope
The team reviewed a modification associated with the implementation of the extended power uprate (EPU) amendment at Susquehanna Unit 2. Specifically, the team reviewed the engineering change (EC) package that replaced the sixteen main steam line (MSL) flow indicating switches with switches that have a higher upper range capability and an increased high flow isolation setpoint consistent with approved EPU values. The EPU increased MSL flow which resulted in a proportionally higher differential pressure drop across the MSL flow elements. The team performed the review to verify that the design and licensing bases was not degraded by the modification, in particular, the capability to detect a break of the MSL and isolate the steamline consistent with accident analyses assumptions.
The team reviewed the bases for the calculation associated with the high steam flow setpoint and the testing associated with the modification to ensure they were consistent with the design inputs, licensing bases and design requirements. The team also reviewed the 10 CFR 50.59 screen associated with the modification as described in section 1R17.1 of this report. This review specifically focused on the adequacy of PPLs determination that there was no adverse affect on any accident analyses previously evaluated. The team performed a walkdown of the installed components to confirm the installation was in accordance with the design documentation and that the flow indication readings were within the normal expected bands identified in the operational channel check procedures. Additionally, the team performed interviews with PPL staff regarding the design, installation and testing of the new switches. The documents reviewed are listed in the attachment.
b. Findings
No findings of significance were identified.
.2.2 High Pressure Coolant Injection (HPCI) System Acceptance Criteria for Gas Intrusion
a. Inspection Scope
The team reviewed the PPL analysis, EC-052-1056, that established the maximum acceptable volume of gas within the HPCI discharge piping which would not affect system operability. The calculation evaluated the potential for water hammer loads within the system given an assumed air void to ensure any potential waterhammer pressures would be below the maximum design pressure for HPCI system piping.
The team reviewed the design inputs and assumptions to determine whether conservative inputs were used to model the impact of a potential air void on system operation. This review included HPCI pump head versus flowrate for both the booster pump and main pump to ensure appropriate parameters were modeled in PPLs analysis. The team also reviewed the actual HPCI system initiation data from a 2003 injection event which was used to establish pump startup time assumed in the analysis to evaluate the adequacy of the analysis. Additionally, the HPCI pump discharge check valve loss coefficient, calculated moment of inertia and assumed flow area were reviewed to ensure conservative inputs were used consistent with the actual valve characteristics in the field. The team reviewed the output of the analysis with respect to piping loads to ensure that peak loads were found to be within the system pipe loading operability criterion. The team reviewed applicable drawings to confirm assumptions within the analysis. Additionally, the team reviewed the peak water hammer pressures developed for the maximum acceptable gas void to ensure they remained below the maximum pressure for the HPCI system discharge piping during a system initiation. The documents reviewed are listed in the attachment.
b. Findings
No findings of significance were identified.
.2.3 Diesel Generator Fuel Oil Storage Tanks A, B, C, D, and E Level Element Replacements
a. Inspection Scope
The team reviewed a modification that replaced the A, B, C, D and E emergency diesel generator (EDG) fuel oil storage tank level elements. The modification was implemented because the previous level elements were obsolete and needed replacement. The level element is designed to provide fuel oil storage tank level at the EDG local panels. The team performed this review to verify that the design bases, licensing bases and fuel oil storage tank level of the EDGs had not been degraded by the modification. Additionally, the 10 CFR 50.59 screen associated with this modification was reviewed as described in section 1R17.1 of this report.
The team assessed the modification to ensure it was consistent with assumptions in the design and licensing bases. The review included verifying drawings, calculations, calibration instrumentation sheets and calibration procedures were properly updated.
Additionally, post-modification testing data was reviewed to verify the EDG fuel oil storage tank levels. The team performed a walkdown of the EDG panels that indicate fuel oil storage tank levels to assess operation of the level elements. Additionally, the team performed interviews with PPL staff regarding the design, installation and testing of the new level elements. The documents reviewed are listed in the attachment.
b. Findings
No findings of significance were identified.
.2.4 EPU Upgrades for Electro-Hydraulic Control (EHC) System, Units 1 & 2
a. Inspection Scope
The team reviewed the design changes required for the EHC system as a result of the increased reactor power levels associated with the EPU implementation. The EHC system modifications, EC-618888 (Unit 1) and EC-674911 (Unit 2), required the power load unbalance logic and load set meter to be calibrated to the EPU load profile. In addition, the EPU resulted in a revised flow to lift characteristic for the turbine control valves and installation of a second set of steam line resonance compensator (SLRC)boards to attenuate any third harmonic steam line resonance frequency.
The team reviewed the design change package to verify that the modification was consistent with the plant design and licensing bases. The design changes were reviewed to ensure procedures were revised as appropriate to reflect the control system revisions. The completed Unit 1 EPU pressure regulator testing was reviewed to ensure post modification testing verified key design assumptions. The team also reviewed the acceptance criteria within the test procedure to ensure consistency with design requirements for system operation. Additionally, the team reviewed an EHC design analysis report for both Unit 1 and 2 to ensure key testing and control system changes identified had been appropriately evaluated. The team also reviewed the 10 CFR 50.59 screen associated with this modification as described in section 1R17.1 of this report.
The documents reviewed are listed in the attachment.
b. Findings
No findings of significance were identified.
.2.5 Increase of Reactor Feedpump Low Suction Pressure Alarm and Trip Setpoints, Unit 2
a. Inspection Scope
The team reviewed the design changes required for the reactor feedwater pump (RFP)low suction pressure switches as a result of the increased reactor power levels and flowrate associated with the EPU implementation. The modification, EC-674942, increased the setpoint for the switches that trip the pump on low suction pressure. The design change also increased the time delays between sequential RFP trips due to low suction pressure. These changes were required because net positive suction head (NPSH) calculations indicated that the previous setpoint was too low to assure adequate NPSH under all EPU operating conditions.
The team reviewed PPLs analyses associated with modeling the performance of the condensate and feedwater systems during a transient condition such as a trip of condensate pumps or a reactor feedpump. The team reviewed the proposed setpoint changes and time delay settings to verify adequate NPSH protection was provided by the revised settings. This review was performed to verify that the settings provided adequate protection for the pumps from cavitation and prevented tripping all three RFPs simultaneously. The team reviewed the associated 10 CFR 50.59 screen associated with the modification as described in section 1R17.1 of this report, to ensure there was no adverse effect on any accident analysis. The team verified drawings and procedures had been updated with revised design information and that adequate post-modification testing had been performed. Additionally, the team performed a walkdown of the switches in the field to verify consistency with design assumptions. The documents reviewed are listed in the attachment.
b. Findings
No findings of significance were identified.
.2.6 Standby Liquid Control Modification for EPU, Unit 2
a. Inspection Scope
The team reviewed a modification that revised the analysis of the standby liquid control (SLC) boron enrichment associated with EPU on Unit 2. In 2007, PPL performed a modification to the SLC system for single pump operation and the use of enriched sodium pentaborate solution to support EPU. Specifically, the boron in the solution was enriched from 20% to a minimum of 88% to ensure suppression pool temperature was maintained below its design limit during an anticipated transient without scram (ATWS)and that the requirements of 10 CFR 50.62 were met. The modification also included the reduction in SLC flow rate from 82.4 gpm (two pumps operating) to 40.0 gpm (one pump operating) during normal system initiation and operation. The review was performed to verify that the design bases, licensing bases and performance capability of the SLC system had not been degraded by the modification.
The team reviewed the modification to ensure it was consistent with the design and licensing bases. The team reviewed calculations and other technical evaluations to assess whether the modification was consistent with assumptions in the design and licensing bases related to the operation of the SLC system. In particular, the team reviewed SLC tank high and low alarm setpoints, the low temperature alarm setpoints, the net positive suction head calculation for the SLC pumps, and the SLC accumulator settings to ensure design documents were revised to reflect the modification. Also, the team reviewed the post-modification testing to ensure the SLC system was operating correctly. In addition, the team observed performance of the quarterly SLC flow verification surveillance to verify test documentation has been updated and results reflected the design and licensing bases. The team verified that Technical Specifications (TS) and the Updated Final Safety Analysis Report (UFSAR) were properly updated with revised design information. Finally, the team conducted interviews with engineering staff and performed a system walkdown to determine if the SLC system would function in accordance with the design assumptions. The documents reviewed are listed in the attachment.
b. Findings
No findings of significance were identified.
.2.7 Installation of Manual Isolation Valves in Ultimate Heat Sink (UHS) Spray Pond Bypass
Piping
a. Inspection Scope
The team reviewed a modification which installed a manual isolation valve in series with the motor operated isolation valves in each UHS spray pond network bypass piping line.
The modification was implemented to account for the UHS higher heat load due to the EPU conditions that result in a higher maximum temperature for long term cooling requirements. The installed manual isolation valves provide isolation capability of the bypass piping in each spray pond network in the event of the failure of motor operated valves to ensure the design temperature of the spray pond is not exceeded during long term cooling. The team verified that the design bases, licensing bases and performance capability of the UHS had not been degraded by the modification. Additionally, the 10 CFR 50.59 screen associated with this modification was reviewed as described in section 1R17.1 of this report.
The team conducted this review to verify that the design bases, licensing bases and performance capability of the spray network had not been degraded by the modification.
The team verified that drawings, calculations, and procedures were properly updated with revised design information and operating guidance. The team evaluated post-modification testing, which included leak rate testing and valve operation with the remote manual operator, to verify that the valve and spray network would successfully perform their functions. The team performed a walkdown of the readily accessible portions of the modification, including the storage area of the manual operator, to ensure the required time critical operator actions were reasonable and achievable. In addition, the team interviewed the design and system engineering staff to determine if the spray pond network would function in accordance with the design assumptions. The documents reviewed are listed in the attachment.
b. Findings
No findings of significance were identified.
.2.8 Timing Sequence Modification of the HPCI Suction Valves from the Suppression Pool
and Condensate Storage Tank (CST), Unit 1
a. Inspection Scope
The team reviewed a modification that revised the sequence of operation of the HPCI suppression pool and condensate storage tank suction valves when low CST level is reached. Specifically, the modification changed the operation of the HPCI suction valves from series to parallel operation. The modification was implemented as a final corrective action to address a vortexing concern discovered in 2005 by decreasing the stroke time sequence of the HPCI suction valves during transfer to the suppression pool from the CST. The team performed this review to verify that the design bases, licensing bases and performance capability of the HPCI system had not been degraded by the modification.
The team assessed whether the modification was consistent with assumptions in the design and licensing bases. The team reviewed selected drawings, surveillance procedures, training plans, and the UFSAR to determine whether they were properly updated with revised design information. Additionally, post-modification test data was reviewed to verify proper sequencing and operation of the HPCI suction valves. The team confirmed that CST level remained above the vortex limit during the transfer process accounting for degraded voltage stroke time of the suction valves and that there was no impact on the HPCI pump net positive suction head (NPSH). Finally, the team conducted interviews with engineering staff to determine if the HPCI system would function in accordance with the design assumptions. The documents reviewed are listed in the attachment.
b. Findings
No findings of significance were identified.
.2.9 Calculation for CST Water Level for HPCI Suction Transfer, Units 1 and 2
a. Inspection Scope
The team reviewed calculation EC-052-1055 that developed and evaluated the initial CST level required to maintain adequate HPCI and RCIC pump suction conditions in the event of an automatic suction transfer from the CST to the suppression pool due to low CST level. The calculation was performed to support final corrective actions to address a HPCI vortexing concern in the CST that was discovered in 2005. The review was performed to verify that the design bases and performance capability of the HPCI and RCIC system had not been degraded by the conclusion of the calculation. The calculation concluded that a minimum CST transfer level of 40.5 inches would maintain adequate HPCI and RCIC pump suction conditions during suction transfer from the CST to the suppression pool.
The team assessed the validation method of vortex formation and vortex breaker data to ensure vortex formation did not occur in the CST during transfer. The team verified that the CST automatic transfer process setpoint (43.5 inches) was above the calculated level (40.5 inches) required to maintain adequate pump suction conditions. The team also verified that the calibration procedures were revised with the setpoint changes to ensure HPCI system operability. Design assumptions, methodologies, and inputs into the calculation were reviewed to evaluate whether they were technically appropriate, conservative, and consistent with the UFSAR. Specifically, the team ensured the suction valve stroke times were adjusted for degraded voltage conditions. Finally, the team discussed the calculation and design basis with reactor engineers to assess the adequacy and conclusion of the calculation. The documents reviewed are listed in the attachment.
b. Findings
No findings of significance were identified.
OTHER ACTIVITIES
4OA2 Identification and Resolution of Problems (IP 71152)
a. Inspection Scope
The team reviewed a sample of condition reports associated with 10 CFR 50.59 and plant modification issues to determine that PPL was appropriately identifying, characterizing, and correcting problems associated with these areas and whether the planned or completed corrective actions were appropriate. The condition reports reviewed are listed in the attachment.
b. Findings
No findings of significance were identified.
4OA6 Meetings, including Exit
The team presented the inspection results to Mr. Richard Pagodin and other members of PPL's staff at an exit meeting on June 19, 2009. The team verified that this report does not contain proprietary information.
ATTACHMENT
SUPPLEMENTAL INFORMATION
KEY POINTS OF CONTACT
Licensee Personnel
R. Pagodin General Manager - Nuclear Engineering
W. Meltzer Supervising Engineer
C. Hoffman Acting Manger - Nuclear Regulator Affairs
J. Welch Technology Specialist
P. Engel Senior Engineer
M. Adelizzi Senior Engineer
P. Brady Supervising Engineer
R. Centenaro Senior Engineer
M. Chaiko Senior Staff Engineer/Scientist
D. Filchner Senior Engineer
E. Heller Unit Supervisor SSES off shift
T. Wales Senior Engineer
LIST OF ITEMS
OPENED, CLOSED AND DISCUSSED
None