IR 05000254/1998201
| ML20247E545 | |
| Person / Time | |
|---|---|
| Site: | Quad Cities  |
| Issue date: | 05/06/1998 |
| From: | NRC (Affiliation Not Assigned) |
| To: | |
| Shared Package | |
| ML20247E528 | List: |
| References | |
| 50-254-98-201, 50-265-98-201, NUDOCS 9805180380 | |
| Download: ML20247E545 (48) | |
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U.S. NUCLEAR REGULATORY COMMISSION OFFICE OF NUCLEAR REACTOR REGULATION Docket No.:
50-254 and 50-265 License No.:
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Report No.:
50-254(265)/98-201 Licensee:
Commonwealth Edison Company Facility:
Quad Cities Nuclear Power Station, Units 1 & 2 Location:
Quad Cities Site Cordova, IL i
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Dates:
February 16 through March 27,1998 Inspectors:
Morris Branch, Team Leader, Events Assessment, Generic Communications, and
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Special Inspection Branch Robert Hogenmiller, l&C Engineer *
Robert Najuch, Lead Contractor Engineer *
Dennis Vandeputte, Mechanical Engineer *
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Arvind Varma, Electrical Engineer *
Maty Yeminy, Mechanical Engineer *
- Contractors from Stone & Webster Engineering Corporation Approved by:
Donald P. Norkin, Section Chief Special Inspection Section Events Assessment, Generic Communication, and Special Inspections Branch Division of Reactor Program Management Office of Nuclear Reactor Regulation i
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9905100300 990506 PDR ADOCK 05000254 g
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-4 Table of Contents EXECUTIVE SUMMARY.............
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l E1. CONDUCT OF ENGINEERING....
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E1.1 Insoection Scooe and Methodology
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E1.2 Residual Heat Removal and RHR Service Water (RHR. RHRSW).
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E1.2.1.3 Conclusions
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E1.2.2 Electrical...
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E1.2.2.3 Conclusions.
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E1.2.3 instrumentation and Controls (l&C)..
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E1.2.3.3 Conclusions
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E1.2.4 System Interfaces.....
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E1.2.4.3 Conclusions.
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E1.3 Core Sorav (CS) and Automatic Deoressurization (ADS)....
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E1.3.1 Mechanica]
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E1.3.1.3 Conclusions
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E1.3.2 Electrical
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E1.3.3 Instrumentation and Controls (l&C)..
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E1.3.4 System Interfangs....
E14 UFSAR Review..
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E1.5 Design Control
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E.1.5.3 Conclusions..
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X1 Exit Meeting
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Appendix A List of Open items.....
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Appendix B Exit Meeting Attendees.........
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Appendix C List of Acronyms C-1
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EXECUTIVE SUMMARY l
From February 16 through March 27,1998, the staff of the U.S. Nuclear Regulatory l
Commission (NRC), Office of Nuclear Reactor Regulation (NRR), Special Inspection Section, l
conducted a design inspection at Quad Cities Nuclear Power Station. Units 1 & 2 (QC). The l
inspection team consisted of a team leader from NRR and five contractor engineers from Stone
& Webster Engineering Corporation (SWEC).
The purpose of the inspection was to evaluate the capability of the selected systems to perform the safety functions required by their design bases, the adherence of the systems to their design and licensing bases, and the consistency of the as-built configuration and system I
operations with the updated final safety analysis report (UFSAR). For this inspection, the team l
selected the Residual Heat Removal (RHR), RHR Service Water (RHRSW), Core Spray (CS)
I and Automatic Depressurization (ADS) systems, based on their importance in mitigating design-basis accidents (DBAs). In particular, the inspection focused on the safety functions of these systems and their interfaces with other systems.
For guidance in performing the inspection, the team followed the applicable engineering design and configuration control portions of Inspection Pacedure (IP) 93801, Safety System Functional Inspection (SSFI). The team reviewed portions of the station's UFSAR, Technical Specifications (TS), drawings, calculations, modification packages, surveillance procedures, and other documents pertaining to the selected systems.
l The team identified the following issues, some of which challenged the capability of the systems to perform their complete scope of design basis accident mitigation actions. Where
appropriate, the licensee took immediate corrective or compensatory actions to ensure system operability.
The thermal capacity of the ultimate heat sink (UHS), when operating in a recirculation
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mode at extreme low water level, may not be acceptable for the conditions and events stated in the UFSAR, TS, and TS Bases documents.
Evaluation of net positive suction head (NPSH) and vortex considerations for the
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RHRSW and EDG Cooling Water pumps have not addressed extremes of UHS water level and maximum potential flow rates through the systems.
Increased brake horse power (BHP) requirements due to recent modifications to the
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RHRSW pumps had resulted in increased long term manual loading considerations for i
the emergency diesel generator (EDG) units beyond their 2000 hr/yr rating.
The RHRSW pump head exceeds the recommended values specified by General
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Electric, resulting in potential RHR heat exchanger (ASME Section Vill), and RHRSW l
piping system (USAS B31.1), overpressure and code compliance concems.
Evaluatiort f RHR and CS pump performance rely on the use of containment
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overpressure for calculating NPSH in both the short and long term accident mitigation phases. The original design and licensing basis recognized a limited use of i
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overpressure during the long term. The current analysis might indicate an unreviewed safety question (USQ) exists therefore requiring formal submittal to the staff for review.
l Emergency Operating Procedures (EOP)s were not consistent with assumptions made
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i in the current analysis for ECCS NPSH. Specific areas of concem include instructions
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to throttle the emergency core cooling (ECCS) pumps to avoid cavitation, actuation of j
containment sprays, and inability of reflooding the reactor vessel to the top of active fuel resulting in containment flooding as a design basis loss of coolant accident (LOCA)
mitigation action.
During operation in the torus cooling mode, the RHR system does not meet single
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failure criteria for some events. This may be a generic boiling water reactor (BWR)
issue, and is being pursued through_ the BWR Owners Group.
in addition, the team identified the following issues that indicate programmatic deficiencies:
ASME Section XI Pump Testing generally uses installed plant instrumentation for
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j measurement of variables such as flow and pressure. The repeatability and accuracy l
requirements for this code application may be more restrictive than the process equipment capability and may require use of special test instrumentation in the future.
Generic Letter (GL) 89-13 RHR heat exchanger (HX) testing was not done according to l
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EPRI guidelines for instrument accuracy and consequently does not confirm heat removal capacity. The test procedure allows for preconditioning by stroking the RHRSW
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flow reversal valves, and acceptance of degraded HX performance based on reduced river temperatures without adequate administrative controls.
Questions exist regarding RHR heat exchanger thermal capacity, which may be less
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than that assumed in the current analyses. If the heat exchanger capacity is actually i
less than current design basis value, the GL89-13 testing program methods would result i
in nonconservative acceptance cr:teria.
Input errers in the 10 CFR Part 50, Appendix K LOCA analysis resulted in an estimated
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60 'F PCT increase for the General Electric (GE) fuel. This is being further evaluated in accordance with 10 CFR 50.46. Effects on the Siemens fuel analysis were much less.
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instrument uncertainty is currently not applied to the 10 CFR 50.46 Appendix K analysis
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L either in the analysis directly or in the measurement of TS surveillance parameters. The estimated worst case impact of a 10% uncertainty on the ECCS flow rates would be a i
l 78 *F peak clad temperature (PCT) increase for the Siemens fuel and a 170 'F PCT j
increase for the GE fuel. Discussion with the staff continues regarding the' application of
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instrument uncertainty to Technical Specification surveillance parameters.
Other issues regarding design control, calculation control, and UFSAR inconsistencies are l
included within the report. During the inspection the licensee documented many of these
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issues in their corrective action program. The number and nature of the items documented on problem identification forms (PlFs) demonstrated good sensitivity for problem identification.
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111. Engineering E1. CONDUCT OF ENGINEERING E1.1 Inspection Scone and Mathada!aav The prrnary objectives of the design inspection at Quad Cities Nuclear Power Station, Units 1 &
2 (OC), were to evaluate the capability of the systems to perform their safety functions required
i by desigr, bases and to verify whether the licensee, Commonwealth Edison Company (Comed),
has maintained the station in compliance with its design and licensing bases. As the subject of l
this inspecton, the staff of the U.S. Nuclear Regulatory Commission, Office of Nuclear l
Regulatory Regulation (NRR), selected the Residual Heat Removal (RHR), RHR Service Water
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(RHRSW), Core Spray (CS), and Automatic Depressurization (ADS) systems, because of their L
importance in mitigating design-basis accidents (DBAs) at Quad Cities Nuclear Power Station, Units 1 & 2. In particular, this inspection focused on the safety functions of the selected systems and their interfaces with other systems throughout the station. For guidance in performing the inspection, the team followed the applicable engineering design and configuration control portions of Inspection Procedure (IP) 93801, Safety System Functional Inspection (SSFI).
Appendix A identifies the open items and issues resulting from this inspection, while Appendix B lists the individuals who attended the exit meeting on March 27,1998. Appendix C defines the various acronymc used in this report.
E1.2 Residual Heat Removal and RHR Service Water (RHR. RHRSW)
l E1.2.1 Mechanical j
E1.2.1.1 Scooe of Review
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The mechanical design review of the RHR and RHRSW systems included design and licensing i
documentation reviews, system walkdowns, and discussions with cognizant system and design engineers. The team reviewed applicable portions of the Updated Final Safety Analysis Report
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(UFSAR) and Technical Specifications (TS); flow and process diagrams and other system drawings; calculations; design change documentation; system operating, inservice and surveillance test procedures and results; emergency operating procedures (EOP); corrective action program documents (PlF); and operating experience reviews. The scope of the review
' included verification of the appropriateness and correctness of design assumptions, boundary conditions, and system models; confirmation that design bases were consistent with the licensing bases; and verification of the adequacy of testing requirements. Systems interfacing with the RHR system, including the RHRSW system, were reviewed to verify that the interfaces were consistent with the RHR system design and licensing bases and would not have an adverse effect on RHR safety functions. The team also examined installation of the RHR system components during plant walkdowns.
Specific topical areas covered during the mechanical design review included system thermal / hydraulic performance requirements (e.g., system capacity, pump net positive suction i
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head (NPSH), and pump minimum flow); system design pressure and temperature; overpressure protection; component safety and seismic classifications; component and pipina design codes and standards; and single failure vulnerability.
l E1.2.1.2 Findinas a.
RHR Pump NPSH The current OC design credits containment overpressure for determining available NPSH for the RHR and CS pumps immediately following a design basis loss of coolant accident (LOCA).
In response to a 1970 Atornic Energy Commission (AEC) FSAR Ouestion 6.2, information provided by the licensee indicated that a small amount of containment overpressure (approximately 1 to 1.5 psi) was required to provide adequate NPSH for the RHR and CS pumps in the long term (>1,000 seconds) following a LOCA. This information is currently incorporated into UFSAR Section 6.3.3.2.9. The AEC accepted this approach in Section 3.5.2 of the original plant Safety Evaluation Report (SER) dated August 25,1971, stating the following:
"Our review of the residual heat removal system LPCI mode and the core spray emergency cooling mode indicates that a containment overpressure of a few psiis needed for about 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> following a design basis loss-of-coolant accident to assure adequate net positive suction head (NPSH) to the RHR pump in the LPCI mode."
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"We conclude that the reliance placed on a small containment overpressure for the Quad-Cities Units 1 and 2 using the minimum heat removal capacity of the RHR system will not adversely affect the performance of the ECCS."
Late in 1996, the licensee discovered that the head loss across the Emergency Core Cooling System) ECCS suction strainers was greater than originally considered (5.8 ft rather than 1.0 ft at a 10,000 gpm). The licensee initiated PIF # 96-3571, performed an operability determination, and subsequently prepared a 10 CFR 50.59 safety evaluation (SE-97-001) to evaluate UFSAR changes associated with the corrected strainer head loss design basis. The assessment of impact on ECCS pump NPSH resulting from this change took credit for 5.5 psi of containment overpressure in the short term (<10 minutes post-LOCA), and 3.4 psi of overpressure in the lcng term (>10 minutes). CS pump cavitation was predicted in the short term; however, it was determined that CS flow rates would not drop below the minimum required flow assumed in the LOCA analyses. At 10 minutes, credit was taken for operator actions to tum off pumps and/or throttle flow rates to preclude pump cavitation in the long term. The safety evaluation concluded that an unreviewed safety question (USO) did not exist because the original AEC SER dated August 25,1971, aes. Sted the use of containment overpressure, and because an NRC SER dated January 4,1977, accepted licensee's analyses that showed limited RHR pump cavitation for maximum RHR pump runout corditions (General Electric Co. - GE Service information Letter 151), assuming no containment overpressure. The licensee notified the NRC of the strainer head loss discrepancy by telephone on December 23,1996, and later submitted voluntary Licensee Event Report (LER)96-025 on January 22,1997. This same issue was l
identified at the Dresden plant (another Comed plant of similar design); however, because the I
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Dresden licensing basis did not originally include credit for containment overpressure, a license amer.dment was requested and subsequently issued to Dresden in an NRC letter dated April 30,1997.
The team reviewed the recent QC response to NRC Generic Letter (GL) 97-04, Assurance of Sufficient Net Positive Suction Head for Emergency Core Cooling and Containment Heat Removal Pumps, which was submitted to the NRC in a Comed letter dated January 5,1998.
The information presented in this letter indicatM that in the first 240 seconds post-LOCA, containment overpressure in the amount of 6.2 psi for the RHR pumps and 7.3 psi for the CS pumps was required to demonstrate adequate NPSH. The peak cladding temperature (PCT)
occurs during this time interval. The letter also stated that some pump cavitation may occur between 240 and 600 seconds post-LOCA. In the long term (>10 minutes), the letter indicated that 2.3 psi of containment overpressure was required for the RHR pumps, with no overpressure required for the CS pumps.
The apparent increase in reliance on containment overpressure, as indicated in the licensee's GL 97-04 response, was of concern to the team, and a number of discussions with licensee staff took place to better understand the evolution of this issue. The team also reviewed the current design basis NPSH calculations (QDC-1000-M-0454, Short Term RHR/ Core Spray Pump NPSH Analysis - Design Basis LOCA, Rev. 0; and ODC-1000-M-0535, Long Term RHR/ Core Spray Pump NPSH Analysis - Design Basis LOCA, Rev. 0) and EOPs QGA 100, l
RPV Control, Rev. 2; OGA 200, Primary Containment, Rev. 4; and QGA 500-3, Drywell Flooding, Rev. 6. From these discussions and reviews, the team identified the following concerns:
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The original licensing basis did not specifically address credit for containment overpressure in the short term post-LOCA time period (<10 minutes). The AEC acceptance of containment overpressure was based on a review of information provided
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I by the licensee.in response to AEC FSAR questions, which only presented NPSH analysis results for times of 1,000 seconds and greater post-LOCA. The licensee stated that it was their understanding that prior to issuance of Safety Guide 1, NPSH for
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Emergency Core Cooling and Containment Heat Removal System Pumps, containment pressure was considered to be available prior to initiating containment cooling (pool cooling or spray) and was therefore not explicitly discussed in the original FSAR or its amendments.
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The GL 97-04 response and the current NPSH calculations indicated that for the first 240 seconds post-LOCA, containment overpressure in the amount of 7.3 psi for the CS pumps and 6.2 psi for the RHR pumps was required. The team considered these values to be in excess of "a few psi" as accepted in the original AEC SER. The licensee
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stated that these overpressure values were calculated very conservatively, and that if i
the actual suppression pool temperature transient were taken into account, the containment overpressure actually required to ensure the minimum CS flow rate of 5,650 gpm at the time of PCT would be about 3 psi (which the licensee still considered a few psi).
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The amount o' containment overpressure relied on in the long term (>10 minutes) has increased from about 1 to 1.5 psi (as shown on UFSAR Figure 6.3-42) to 2.3 psi (stated
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in the GL 97-04 response). The licensee has concluded that this falls within the original AEC SER acceptance of "a few psi".
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At 10 minutes post-LOCA, UFSAR Sections 6.2.1.3.3 and 6.2.2 allows credit to be taken l
for operator action to throttle CS and Low Pressure Coolant injection (LPCI) pump flow l
rates. EOP QGA 100 initially directs the operator to control CS and LPCI flows below the NPSH limit curves (Detail QGA-D3 for CS and Detail QGA-D4 for RHR); however,
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the team noted that these NPSH limit curves were not consistent with the most recent
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NPSH calculations and could allow the operator to enter pump operating regions where l
cavitation would occur, EOP OGA 100 also docs not contain any specific direction to tum off ECCS pumps or to throttle their flows, as assumed in the NPSH calculations. In
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fact, for a design basis LOCA, reactor water level cannot be maintained above top of I
active fuel (TAF) and the EOP directs the operator to inject water into the reactor vessel at maximum flow rates, ignoring any NPSH limits. If water level cannot be maintained L
above TAF, the EOPs direct the operator to realign the CS system to the CCST and flood the containment to TAF. The licensee stated that within 10 minutes, the operator would diagnose the accident symptorrs, recognize the inability to maintain reactor water level above TAF, and tum off, realign, and/or throttle ECCS pumps as necessary to maintain adequate vessel makeup flow while establishing other safety functions such as
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containment cooling.
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At 10 minutes post-LOCA, the NPSH calculations assume that the operator will initiate containment sprays to reduce containment pressure, thereby reducing the overpressure l
that is available to benefit ECCS pump NPSH. EOP QGA 200 directs the operator to j
initiate torus sprays when torus pressure exceeds 6 psig, with a caution to not ese RHR pumps that are needed for core cooling. The EOP did not contain any cautions with regard to the potential impact of containment spray operation on ECCS pump NPSH.
The team noted that a similar spray concem was addressed in the Dresden. license amendment.
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The current NPSH calculations were performed using a containment overpressure analysis that was performed for the Dresden license amendment. The NPSH l
calculations and the licensee's response to GL 97-04 noted that a QC containment
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pressure and temperature response analysis, for both the short and long terms, was I
currently in progress. Several factors need to be verified in the long term suppression pool temperature analysis to conservatively determine the maximum pool temperature:
The appropriate RHR heat exchanger capacity must be used. Questions regarding the
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design capacity of the RHR heat exchanger are discussed in item E1.2.1.2.d below.
The new containment analysis incorporates the ANS 5.1-1979 decay heat model. For
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the Dresden license amendment, the NRC staff required addition of a 2-sigma uncertainty to the decay heat calculated by ANS 5.1-1979. This same 2-sigma
' uncertainty adder appears applicable to the QC analysis as well.
The existing QC long term containment analyses utilize an RHRSW flow rate of 3,500
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gpm to the RHR heat exchanger. As identified in PlF # Q1998-00383, the RHRSW pump surveillance test procedure does not account for instrument uncertainties; thus,
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the actual RHRSW flow could be less than 3,500 gpm. The issue Screening Form for PlF # Q1998-00383 determined that using a conservative RHRSW flow rate of 3,150 gpm, the peak suppression pool water temperature increased by about 10*F; however, since the corresponding containment pressum also increased, there was no negative impact on RHR or CS pump NPSH. As noted in the issue Screening Form, the evaluations and calculations for reduced RHRSW flow rates need to be re-verified once the new containment analysis has been formally issued. During the course of the inspection the licensee indicated that they currently do not plan to include the effects of instrument uncertainty in the RHRSW surveillance testing in the containment analysis.
7.
The UFSAR changes identified and evaluated in the licensee's 10 CFR 50.59 safety evaluation 97-001 (revised strainer head loss design basis) did not completely describe the impact of the change on ECCS pump NPSH. The UFSAR changes did not address the reliance on containment overpressure in the short term, the potential for or acceptabi!ity of pump cavitation during the short term, or the increased amount of overpressure required in the long term. This concem was partially captured in previous NRC Resident inspection Report 50-254(265)/96020(DRP), IFl 50-254/265-96020-06.
At the conclusion of the AE inspection, the licensee stated their intention to continue i
discussions with the NRC staff regarding the NPSH issue, and also stated that they would
formally submit the QC NPSH analyses to the NRC when completed. This submittalis expected to be similar to the Dresden license amendment submittal. The revised containmerit
response analyses, a necessary input to complete the NPSH analyses, will be expedited to the extent possible. The licensee will document their plans in an upcoming update to their response to NRC Bulletin 96-03.
At the public exit, March 27,1998, the licensee indicated that a schedule to submit and docket the completed NPSH analysis will be included with the update of the Bulletin 96-03 response.
The containment analysis will also be completed with a best estimate goal of September 1, 1998. In the short term, the licensee indicated that the EOPs would be reviewed and revised as i
necessary to reconcile the EOP direction to the assumptions in the NPSH calculation.
i Specifically, issues of pump throttling, use of containment sprays, and riooding containment to
achieve flooding to TAF needed to be evaluated.
The licensee will continue discussion with the NRC staff, as the licensee indicated that unlike -
QC, Dresden was not licensed for overpressure, and for QC a USQ in accordance with 10 CFR 50.59 does not exist. Further the licensee indicated that although the GL 97-04 response i
indicated over 7 psi containment overpressure was required, current best guess analysis indicates only 2.65 psiis required. Resolution of this issue including the licensee's EOP review
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and reconciliation with calculation assumptions, and whether the issue represents a USQ is identified as URI 50-254(265)/98-201-01 (Design Control),
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b.
LOCA Analysis input Errors The licensing basis LOCA analyses for QC are described in UFSAR Section 6.3. Significant analysis input parameters are summarized in UFSAR Table 6.3-3A (for GE fuel) and Table 6.3-38 (for Siemens fuel). The LOCA analysis inputs a're also contained in the following licensee's documents: NFS NDIT 97-00195, LOCA Input Parameters for Quad Cities 1 and 2 (GE Fuel),
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Rev. O, dated October 16,1997; and NDIT 19, Rev. O, Principal LOCA Analysis Parameters for
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Quad Cities Units 1 and 2, Siemens Document EMF-95-165, October 1996. In preparation for l
the team's inspection, the licensee reviewed these input parameters and identified three cases where the LOCA analyses did not properly reflect expected ECCS performance, as follows:
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1.
For the GE LOCA analysis (UFSAR Table 6.3-3A), the LPCI injection valve reactor pressure permissive setpoint is given as 325 psig. This value is not conservative because it is higher than the lowest allowable setpoint specified in TS Table 3.2.B-1 (300 psig). The lower setpoint could delay the delivery of LPCI flow to the reactor vessel. (Reference PlF # Q1998-00606)
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Both the GE and Siemens LOCA analyses assume that LPCI flow to the reactor vessel
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l may commence at a reactor pressure of 325 psig; however, it was determined that LPCI flow would not actually occur until reactor pressure decreases to about 264 psig, due to the RHR pump performance characteristics (shutoff head) and the relative elevation difference between the pumps and the vesselinjection point. This could also delay the delivery of LPCI flow to the reactor vessel. (Reference PIF # Q1998-00688)
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The LPCI and CS pumps have minimum flow bypass lines to protect the pumps when operating against a reactor pressure above the pump shutoff head. The impact of i
reduced LPCI and CS flow to the reactor vessel due to minimum flow bypass was not
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completely accounted for in either the GE or Siemens LOCA analyses. (Reference PlF
- Q1998-00695)
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In an Attachment B Operability Determination Checklist for the above-referenced PIFs, the licensee evaluated the combined effects of the three identified ECCS performance issues. The evaluation deterrnined that: (1) when credit is given for existing LPCI and CS pump
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performance (which exceeds TS minimum performance requirements), the existing limitirig l
licensing basis LOCA analysis results are not adversely impacted (i.e., PCT would not increase); and (2) a different limiting break size, break location, or single failure would not result. It was therefore concluded that the LPCI and CS systems met their functional
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requirements and continued to be operable. The fuel vendors were requested by Comed to
quantify the PCT penalty for the combined effects of the three referenced PlFs on the licensino i
basis LOCA analysis. Preliminary evaluations indicated a PCT penalty of +2*F for the Siemens l
fuel and +60*F for the GE fuel. Since the current licensing basis PCT is 1880 *F and 1765 'F i
for the Siemens and GE fuel, respectively, there would still be adequate margin to the 2200*F l
PCT limit established in 10 CFR 50.46(b)(1). If the finalized fuel vendor analyses determine j
that the PCT penalty exceeds 50 *F, the licensee is committed to make a report to the NRC in j
accordance with 10 CFR 50.46(a)(3). The licensee also stated that the process for developing l
LOCA analysis inputs and providing this information to the fuel vendors would be improved to prevent future errors.
The use of incorrect, non-conservative inputs in the LOCA analyses is identified as URI 50-l j
254(265)/98-201-02 (Design Control).
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LOCA Analysis '- Treatment of ECCS Flow Measurement Uncertainties c.
TS Section 4.5.A.2.b requires a LPCI (RHR) pump flow rate test to demonstrate that two LPCI
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pumps together develop a flow of at least 9,000 gpm against a test line pressure corresponding
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to a reactor vessel pressure of 220 psig. Testing of the RHR pumps is performed in accordance with surveillance procedure OCOS 1000-06, Quarterly RHR Pump / Loop Operability Test, Rev.14. The team reviewed this procedure and determined that test measurements are taken using installed process instrumentation, including control room RHR flow indicators Fl i
1(2)-1001-11 A,B; local pump suction pressure instruments Pl 1(2)-1001-70A-D; and local pump discharge pressure instruments Pl 1(2)-1001-71 A-D. Licensee's calculation NED-I-EIC-0266, Residual Heat Removal (RHR) Drywell Spray Header Flow Indication Error Analysis, Rev. O, dated August 23,1994, determined that at an RHR flow rate of 9,000 gpm, the total flow measurement uncertainty under normal plant conditions was 1586 gpm. The surveillance procedure did not appear to account for this instrument uncertainty; therefore, the actue! RHR pump flow rate could be less than the two-pump 9,000 gpm minimum value required by the TS.
A similar situation existed for the CS pumps. Surveillance procedure OCOS 1400-01, Quarterly Core Spray Pump Flow Rate Test, Rev. 8, called for the use of installed process instrumentation to measure pump performance parameters, and did not account for instrument uncertainty. Uncertainty calculations for this process instrumentation (flow indicators Fi 1(2)-
1450-4A,B; pump suction pressure indicators Pl 1(2)-1402-40A,B; and pump discharge pressure indicators Pl 1(2)-1450-1 A,B) had not been completed by the licensee at the end of the inspection, Therefore, actual CS pump performance could also be less than the minimum required by the TS.
The team reviewed the licensing basis LOCA analyses presented in UFSAR Section 6.3 and l
determined that these analyses, for both GE and Siemens fuel, were performed using the TS minimum required LPCI and CS flow rates as input parameters, with no allowance made for
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surveillance test instrument uncertainties. If actual LPCI and CS flow rates were less than the TS minimum values, then the consequences of the LOCA analyses could be more severe (i.e.,
higher peak clad temperature - PCT). Preliminary worst case assessments by the licensee indicated that a 10 percent reduction in LPCI and CS flow rates would increase the PCT by 78
'F for Siemens fuel and 170*F for GE fuel. A subsequent letter from GE to Comed dated
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March 26,1998, indicated that the impact on the licensing basis PCT was estimated to be
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approximately 40 *F for an assumed 10 percent LPCl/CS flow reduction, based on generic I
sensitivity studies performed for a BWR/4 and using the SAFER /GESTR methodology (the l
current ECCS analysis basis for GE fuel at QC). Since the current licensing basis PCT is 1880
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'F and 1765 *F for the Siemens and GE fuel, respectively, there would still be adequate margin to the 2200 'F PCT limit established in 10 CFR 50.46(b)(1).
The licensee stated that inclusion of ECCS flow measurement uncertainties was not required by i
the QC licensin2 basis because the existing LOCA analyses were perfcrmed using models
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developed in accordance with 10 CFR Part 50, Appendix K ECCS Evaluation Models. Neither Appendix K nor 10 CFR 50.46(a)(1)(ii) specifically address the inclusion of ECCS flow uncertainty in the inputs to these models. The licensee stated that they would pursue further l
discussions with the NRC staff to arrive at an acceptable resolution to this concern. This issue is identified as URI 50-254(265)/98-201-03 (Instrument Uncertainty).
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RHR Heat Exchanger Capacity,105 million vs 97.74 million Stulhr in 1993, GE notified the licensee that based ' n their latest analysis, the RHR " heat exchanger o
duty is not met for cases one and two" that is, the heat exchangers are capable of removing 9~7.74 million Btu /hr, rather than the original design heat removal rate of 105 million Btu /hr with the current design fouling (Letter EBO-93-096, GE's J. M. Oroni to Com Ed's K. R. Sturtecky, RHR Heat Exchangers Analysis, February 26,1993). The licensee had not taken prompt action to evaluate and resolve the vendor's concern. This reduction in capacity was of concem to the team since two RHR heat exchangers passed their. latest acceptance criteria with a slim margin of 1.8 percent (1 A) and 2.6 percent (2A). The removal of 97.74 million in lieu of 105 million 8tu/hr used in the current containment analysis represented a reduction of 6.9 percent.
During the inspection, the licensee confirmed that the two RHR heat exchangers that passed the last test marginally, would have failed when imposing GE's new heat duty. At the March 27, 1998, exit meeting the licensee agreed to the following:
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Questionable capacity rating for the RHR heat exchanger would be resolved by
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establishing communication with the current holder of the original design information.
Confirm that the ongoing revision to the containment analysis would use the correct
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value.
Administrative procedures would be established based on reduced river temperatures,
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to address the slight capacity deficit until final resolution ic achieved. Upon resolution, test procedures will be revised accordingly.
Effective design controls requires that measures shall be established for coordination among participating design organizations, including the revision of documents involving design interfaces. Additionally, effective measures need to be established to assure conditions
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adverse to quality are promptly identified and corrected. Untimely and ineffective resolution of RHR heat exchanger heat removal capacity concems is identified as URI 50-254(265)/98-201-
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RHR Heat Exchanger GL 8913 Testing i
The licensee's commitment to GL 8913, Service Water Problems Affecting Safety-Related
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Equipment, states that the program will assure that the heat exchangers are capable of i
l removing heat in accordance with their required safety function, and added that testing of heat i
exchangers will be performed using station procedures developed from the EPRI Heat Exchanger Performance Monitoring Guidelines for Service Water Systems.
The team's review of procedures QACP 1100-5, RHR Heat Exchanger 1 A Thermal Performance Test, Rev. 4, and QACP 1100-5, RHR Heat Exchanger 2A Thermal Performance
. Test, Rev. 5, and the latest test results for RHR heat exchangers 1 A and 2A identified concerns with test instrumentation, test preconditioning, and administrative control of degraded
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equipment following testing. Specifically, the team had the following concerns:
Test Instrumentation - The test results of the RHR 1 A heat exchanger dated
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September 16,1994 showed an energy mismatch of 28 percent between the tube and shell sides. This mismatch translates to about 40 percent instrument loop uncertainty
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with regard to the overall heat removal capability of the heat exchanger. According to the calculated results, if the more conservative values were used (shell side), the heat exchanger would have fai!ed the acceptance criteria and could not be proven capable of removing the design 105 million Btu /hr heat duty assigned to each of the RHR heat exchangers (UFSAR Section 6.3). Review of the test results for the 2A heat exchanger dated February 27,1995, resulted in similar conclusions (failing the acceptance criteria).
The licensee agreed that the method for testing the RHR heat exchangers should be improved by testing the heat exchangers with a greater differential temperature between:
RHR and RHRSW and that more accurate test instruments should be used. The licensee's test program instrument uncertainties were not in accordance with the EPRI Guidelines; e.g.: the EPRI Guideline requires a delta T uncertainty of i 3 percent while the test of the 1 A heat exchanger had an instrument delta T uncertainty of 121 percent.-
f Heat Exchanger - Possiable Preconditioning - Procedure QCOP 1000-35 Rev.2, RHR
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Heat Exchanger Thermal Performance Test, dated April 8,1997, Section F.2.e note, identifies that RHRSW system flow through the heat exchanger may be required to be
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re-aligned in the reverse flow direction to facilitate data collection. This allowance has
two potential impacts on as found data. First, reversing flow through the heat exchanger flushes out any possible sign of biofouling in the heat exchanger. Secondly, stroking the HX valves as allowed by procedure may reseat the valves thereby reducing as-found
heat exchanger bypass leakage.
The licensee had previously issued PlF Q1998-00382, which indicates that by reversing the flow direction through the heat exchanger, any effects of bypass flow line leakage could be eliminated because the reversed flow valve alignment will use a different valve and bypass line. The licensee concluded that this realignment would not precondition the heat exchanger to a significant degree. However, the team noted that the root cause evaluation associated with an earlier P F (96-0264), postulated that bypass valve leakage was probably the single greatest cause of degraded heat exchanger performance.
Administrative Controls for Degraded Equipment - Procedure QCOP 1000-35 Rev.2,
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RHR Heat Exchanger Thermal Performance Test, dated April 8,1997, Section F.8 t
states that if the heat transfer rate is below the design margin, performance of an operability determination based on calculation NED-M-MSD-47, Quad Cities RHR Heat
' Exchanger Performance as a Function of River Temperature, should be considered.
PlF 96-0264 documented a condition wherein the 1B RHR heat exchanger was found to l_
be at 85.7 percent of the design heat transfer rate, and was accepted as an operable but degraded condition at river temperatures below 84,7 *F based on NED-M-MSD-47.
The team was concemed that this operable but degraded status was based on an uncontrolled environmental parameter and questioned the administrative controls established to restrict plant operation if the river water temperature increased. The
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' licensee indicated that environmental standards restrict plant operation at a river
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temperature of 88.7 *F. However no night orders or equivalent could be located which i
addressed river water temperature dependent operability restrictions for the RHR heat exchanger which may, as in this case, be more restrictive than the environmental limit.
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Instrumentation used for testing, the option to reposition the RHR heat exchanger bypass valves which could alter the as-found heat exchanger test results, and acceptance of a degraded condition without establishing administrative restrictions consistent with the test results are identified as URI 50-254(265)/98-201-05 (Test Control).
At the public exit, March 27,1998, the licensee indicated their intent to improve the GL 89-13 test program, including the procurement of better test equipment to meet the EPRI suggested guidelines.
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f.
RHR Pump Minimum Flow - Bulletin 88-04 NRC Bulletin 88-04, Potential Safety Related Pump Loss, dated May 5,1988, requested that addressees determine whether safety related pump applications have configurations which could result in deadheading one or more of the pumps. If such configurations existed, an
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evaluation was required of (a) as-built system characteristics; (b) installed pump head / capacity data, including actual test data; (c) the effects of test instrument error and reading error; and (d)
the worst case deviation of pump test parameters as allowed by ASME Section XI.
The licensee's response to Bulletin 88-04 (letter dated July 11,1988) stated that based upon calculations, pump to pump interactions resulting in deadheading a weaker degraded pump in a strong pump weak pump arrangement was not a concem. The licensee's response indicated that pump degradation of over 90 percent would be required to cauce a pump sharing a recirculation line to deadhead. The licensee did locate in the Architec Engineert (AE) files, a 1988 analysis which supported the Bulletin response, however this analysis was never formally reviewed and approved as an official calculation and therefora was never transferred to Commonwealth Edison. An official calculation that supporcad the response to Bulletin 88-04 could not be located and the licensee issued PlF Q 1998-00905 to address the documentation requirements necessary to support the positions relative to Bulletin 88-04 response.
Bulletin 88-04 also requested that addressees evaluate the adequacy of minimum flow bypass lines with respect to damage resulting from operation and testing in the minimum flow mode, including cumulative operating hours over the plant lifetime and during the postulated accident scenario invciving the largest time in this scenario. The licensee's response to Bulletin 88-04 dated January 8,1990, indicated that based on site performance test data, the pump manufacturer concluded that vibration levels at minimum flow conditions, if allowed to continue for extended operating periods, (hundreds to thousands of hours) would result in severe damage to the impeller vanes and volute lips. Shorter term operation would cause bearing and seal problems. The vendor's recommended minimum flows were 1000 gpm short-term.1400 gpta long-term. The licensee's design allowed only 400 gpm calculated for the RHR pumps.
This 400 gpm value was based on original design, where the manufacture provided no recommended minimum flow values and where the licensee's analysis determined that 400 gpm could remove all pump generated heat input to the system.
In their response, the licensee agreed to procedurally control pump operation while at minimum flow conditions. These controls included restricting operation and vibration testing if time limits were exceeded during testing conditions. With regard to the response that plant operating procedures allow low pressure pumps to be secured if plant conditions warrant or if they are not immediately needed, the team was concemed with what procedural guidance existed for
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permissible restarts of large RHR/CS pump motors. The licensee indicated current procedures QCOP 1000-05 for RHR Shutdown Coc".g Operation and QCOP 1000-09 for Torus Cooling Startup and Operation give guidance to minimize repeated starts / stops / jogs of RHR pumps due I
to winding life reduction on the induction motors. However, the team determined that procedure QCOP 1000-30 Post-Accident RHR Operation provided no similar operator guidance. PlF Q1998-01090 was written to address potential inadequate procedural controls.
During the inspection, the licensee identified that vendor drawing 992C510AE-1 for the RHR pump motors indicates that successive starts of the motor should be limited to only two starts i
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from ambient temperature or one from rated temperature. Contact with General Electric (GE)
confirmed the need to restrict pump starts and stops under accident conditions as well.
Resolution of PIFs Q1998-00905 conceming pump deadheading evaluation documentation and PlF Q1998-01090 conceming adequacy of procedural controls to ensure minimum flow and proper control of pump starts and stops should resolve these issues.
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Torus Cooling Mode Single Failure Vulnerability During normal station operation with RHR operating in the torus cooling mode, the system cannot automatically be realigned into the LPCI mode in the event of a LOCA, assuming a single failure which results in the return path valves to the torus remaining open. Because of train cross-connect valves, the flow from the operating RHR pumps in either loop would be returned to the torus through the failed open valves in the return line. Little or no LPCI flow will reach the reactor through the parallel discharge path. Assuming an emergency diesel generator failure resulted in this condition, only the opposite train CS pump would be available for core cooling.
While this failure mode may have been bounded and acceptable in the original design and
licensing basis, due to less restrictive criteria prior to the implementation of 10CFR50.46, l
current 10CFR50 Appendix K analysis requires operation and injection of either both CS pumps l
or a combination of CS and LPCI pumps for mitigation of recirculation line breaks. The licensee indicated that the percentage of operating hours in the forus cooling mode, based on RHR pump operating hours, all of which are assumed in torus cooling mode, were 5.66 percent and 5.12 percent for Unit 1 and Unit 2 respectively, for 1995 through 1997. However, the team noted that a TS Limiting Condition for Operation (LCO)is not entered when the RHR is in the torus cooling mode of operation.
In reply to the licensee's solicitation, GE responded via DSB-98013 dated March 4,1998, that a postulated LOCA/ LOOP concurrent with a dies,el generator single failure while in the torus cooling mode was not considered in the original licensing basis of BWR plants, nor in the
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original design basis of the RHR system. GE indicated that operation of the RHR system in the I
torus cooling mode was considered to be an infrequent operating condition, excluded from the ECCS design and analysis because of the low fraction of operating time that RHR was expected to be aligned for non-LPCI mode during normal power operation. Further, GE indicated the design basis for automatic LPCI injection is that it does not require recovery from I
secondary n, odes of operation, however several RHR valves were provided with automatic I
signals from the LPCI initiation logic, thereby increasing reliability and availability of automatic (
LPCl initiation regardless of initial configuration. The reply cites report NEDC-32513,
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Suppression Pool Cooling and Water Hammer, prepared for the BWR Owner's Group as the basis that realignment from the suppression pool cooling mode to the LPCI injection mode was
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not required as part of the design basis, because of the low probability of design basis LOCA l
concurrent with RHR system being in the suppression pool cooling mode.
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The licensee documented this issue in PlF Q1998-00898. At the public exit, March 27,1998, the licensee indicated that this issue is considered generic, to be pursued through the BWR Owners Group. Pending resolution, the 'Unsee will consider administrative controls to limit operation in this mode. The team also considered this item to be a potential generic issue since it was similar to a finding at the Cooper facility. That issue was referred to NRR staff for further review. This issue will remain open pending further evaluation by tha owners group and the
NRC (IFl 50-254(265)/98-201-06).
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Loop Select Logic Operation During Shutdown Conditions Each of the two RHR system loops (A and B) injects into a separate reactor recirculation loop.
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The LPCI loop selection logic is designed to automatically direct LPCI flow to an unbroken l
recirculation loop. The B recirculation loop is preselected. If the loop selection logic determines that a break has occurred in the B recirculation loop, then the LPCI flow is automatically l
directed to the unbroken A recirculation loop. If neither recirculation loop is broken, then LPCI flow is directed to the preselected B recirculation loop.
TS Section 3.5.B specifies operability requirements for the ECCS during shutdown conditions (Modes 4 and 5). For LPCI, one or both LPCI subsystem loops must be operable, with a i
subsystem loop consisting of at least one operable pump and an operable flow path capable of transferring water to the reactor vessel. To satisfy this TS operability requirement, the associated LPCI injection valve (MO 1001-29A or B) must be operable to allow transfer of water to the reactor vessel. If an injection valve is inoperable, then the associated LPCI subsystem loop will also be inoperable. However, if the B LPCI loop injection valve (298)is out of service (e.g., for maintenance or testing), then the entire LPCI subsystem must be considered inoperable because the LPCI loop selection logic will choose loop B for injection (since there can be no differential pressure between the recirculation loop risers when the plant is shutdown). With the inoperable loop B injection valve chosen, neither the A nor B loop injection valves would open, thereby preventing any transfer of water to the reactor vessel by the LPCI l
pumps. The licensee determined that no procedure existed to force the LPCI loop selection logic to choose loop A injection when the B loop injection valve is inoperable, and initiated PlF #
Q1998-00508 to document the concern. The PIF stated that a procedure would be developed to force the loop select logic to choose LPCI loop A when the loop B injection valve is out of service. The licensee stated that a similar procedure already exists at Dresden station.
Resolution of PIF Q1119-00508 should correct this licensee identified concern.
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Minimum Required Torus Water Level During Shutdown Conditions TS Section 3.5.B. Emergency Core Coofing System - Shutdown, specifies operability requirements for the ECCS during shutdown conditions (Modes 4 and 5). One or both CS subsystems, and one or both LPCI subsystem loops, must be operable, to provide a makeup water source for the reactor vessel. To support this operability requirement, TS Section 3.5.C,
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Suppression Chamber, requires a minimum suppression chamber water level of 7 ft. The TS bases for this requirement state that the minimum water volume corresponding to the 7 ft level is based on NPSH, recirculation volume, and vortex prevention, plus a safety margin for l
conservatism.
The team reviewed calculations CWE097.0200.40, Base Suppression Pool Level Required for
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Proper Operation of the RHR/LPCI and Core Spray Pumps during Plant Cold Shutdown and Refueling Conditions, Rev. O, and CWE097.0200.41, Minimum Suppression Pool Water Level Required during Cold Shutdown and Refueling Conditions, Rev. O. These calculations established the basis for the 7 ft value specified in TS Section 3.5.C. The review determined that the NPSH and vortex calculations were based on a flow rate of 4,500 gpm from a single RHR or CS pump. The team considered this to be non-conservative because 4,500 gpm is a throttled flow rate, and it is also possible that two or more RHR/CS pumps could initially start (since the TS requires that at least two low pressure pumps be operable). Higher flow rates are more conservative for NPSH and vortex considerations. The licensee could not identify any procedures that would direct the operator to throttle flow to 4,500 gpm or turn off pumps after they started. The NPSH calculations in CWE097.0200.40 also used the old (incorrect) value for suction strainer head loss (1 ft at 10,000 gpm rather than 5.8 ft at 10,000 gpm). The impact of this error on available NPSH becomes significant at higher flow rates associated with multiple pump operation.
The licensee initiated ? # Q1998-01341 to address this concern. The licensee stated that calculations would be performed to document ECCS pump flow rate limitations (due to NPSH or vortexing considerations) under conditions of low torus water level, and that the calculation results would be used to establish appropriate limitations on allowable pump operation combinations and flow rates. Not using correct and conservative inputs in the calculation of the TS minimum allowable torus water level during shutdown conditions is identified as URI 50-254(265)/98-201-07 (Design Control).
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Surveillance Testing to Confirm RHR Containment Cooling Mode Flow Rate TS Section 4.7.M, Suppression Pool Cooling, specifies surveillance requirements to demonstrate operability of the suppression pool cooling mc de of RHR system operation. This section requires verification that each RHR pump develop the required recirculation flow through the heat exchanger and the suppression pool when tested pursuant to Specification 4.0.E (i.e., in accordance with the IST program). The minimum required suppression pool cooling flow rate is 5,000 gpm ter single RHR pump operation, as assumed in the long term containment response analysis ard as established on the original GE RHR process diagram, drawing number 730E775, Rev.1. iM licensee determined that the RHR pump surveillance
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test procedure (OCOS 1000-06, Rev.11) ed not contain any acceptance criteria directly related to tiiis TS requirement, and initiated PIF # C1998-00510 to document the concem. The issue Screening Form completed for the PIF established that existing RHR pump testing provided reasonable assurance that the RHR system would adequately perform its pool cooling function.
The licensee initiated revisions to QCOS 1000-06 to incorporate the 5,000 gpm pool cooling flow rate acceptance limit. The team noted that this surveillance test deficiency was of the type recently identified in NRC Information Notice 97 90, 'Use of Nonconservative Acceptance Criteria in Safety-Related Pump Surveillance Tests. It also appears to be an additional example of a violation that was cited in NRC Engineering Inspection Report 50-
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254/97013(DRS); 50-265/9701 (DRS) and Notice of Violation dated September 12,1997 (i.e.,
requirements and acceptance limits in design documents not incorporated into the written procedures).
Completion of PIF Q1998-00510 and corrective action for the test control violation in inspection report 50-254(265)/97013 should resolve this issue.
E1.2.1.3 Conclusions The team concluded that the mechanical design of the RHR system was generally acceptable, and that the system was capable of performing its safety functions assuming a loss of offsite power and a single active failure. However, the :eam had a number of concerns regarding the increased reliance on containment overpressure to assure adequate CS and RHR pump NPSH, and the overall timeliness of actions taken by the licensee to resolve this issue since the original discovery of increased suction strainer heado loss in late 1996. Additionally, concerns were identified regarding assumed RHR system performance in the licensing basis LOCA analyses, including use of several nonconservative input parameters and not accounting for flow measurement uncertainties in the assumed CS and LPCI flow rates.
Deficiencies were noted in the licensee's GL 89-13 program for performance monitoring of the RHR heat exchangers, and the licensee had apparently not taken timely actions to address information indicating that the RHR heat exchanger had less heat transfer capability than originally assumed in design and safety analyses. Manufacturer recommendations for RHR and CS pump minimum flow rates and permissible pump motor starts were not completely reflected in plant procedural guidance and instructions for post-accident operation.
Regarding the RHR suppression pool cooling mode of operation, the team was concemed that an RHR subsystem was not declared inoperable when in this operating mode, even though the RHR system has single failure vulnerabilities when aligned for pool cooling. Existing RHR
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pump surveillance tests also did not contain any acceptance criteria relating to the single-pump pool cooling flow rate that is assumed in the long-term containment analyses.
For RHR system operation when the plant is shutdown, the team determined that the TS minimum suppression pool water level was established using nonconservative assumptions for CS/RHR flow rates, and that no procedure existed to force the LPCI loop select logic to choose RHR loop A injection if the loop B injection valve were inoperable.
The licensee identified several of the items above while preparing for the NRC's inspection. In all cases the licensee initiated actions to resolve these items through their condition reporting and corrective action program, or indicated that they would take other actions to resolve the issues through continued discussions with the NRC staff.
E1.2.2 ElecWcal E1.2.2.1 Scoce of Review For the electrical design review, the team focused on the Unit 1 and 2 essential power supplies i
to the RHR, RHRSW, CS and ADS systems. The areas examined, such as emergency diesel
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generators (EDGs),4160-volt AC Switchgear,480-volt AC motor control centers (MCCs),250-voit DC power batteries,125-volt DC control batteries and battery chargers were common to both systems.
The team reviewed UFSAR Section 8.0, Electrical Power, TS 3/4.9, Electrical Power Systems, design criteria documents, electrical calculations and drawings, surveillance procedures and test data, design modification packages, PlFs, and other miscellaneous electrical design documents. Walkdowns were conducted of the system components, Main Control Room, Auxiliary Equipment and Cable Spreading Rooms, RHR and RHRSW Pump Rooms, MCC and Switchgear Areas,125/250 Vdc Battery Rooms and Diesel Generator Rooms. The inspection consisted of reviews of equipment installations, electrical separation, and equipment l
qualification.
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The team assessed portions of the following that are applicable to the RHR, RHRSW, CS, and ADS systems: essential power systems including switchgear, transformers, motors, raceway, panels, cables; regulatory and standard compliance; cable separation; voltage drops and degraded voltages; protective device set points; field installations: modifications; drawings and record changes; and battery and EDG surveillance and test data.
E1.2.2.2 Findinas The team reviewed the emergency diesel generator (EDG) capacity calculations, elementary diagrams, protective relay set points,18 month surveillance test data and electrical equipment.
The calculations showed that EDG loading was properly estimated and the EDG 1 that provides power to one half of the Unit 1 ECCS equipment, ano EDG 2 that provides an equivalent function for Unit 2 ECCS equipment, had adequate capacity margin. The swing diesel, EDG 1/2 thm provides powe- *o the other half of the ECCS equipment for both units had little margin.
The electrical bads including ECCS loads were sequenced onto the EDG within the required time, and the drop in output voltage and frequency and their recovery were generally acceptable; however the team identified several concems as described below.
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EDG Short Term Loading Calculations 9390-02-19-1 Rev.1, dated March 28,1997, 9390-0219-2 Rev.1, dated January 22,1996,' and 9390-02-19-3 Rev.2, dated December 29,1995, Diesel Generators (1-2-%)
Loading Under Design Basis Accident Conditions specifies the acceptable starting times for the RHR, CS and RHRSW pumps. These calculations assume a 5 second nominal value for the interval between load blocks and determined the time for the RHR pumps to start and get to rated speed to be < 4.5 seconds. The allowable values for each load sequence logic interval per TS 4.9.A.8.k. is (4.5 - 5.5 seconds for RHR and 9.5 - 10.5 seconds for CS). If the RHR pump starts at 5.5 seconds and the CS pump starts at 9.5 seconds, it would allow only 4 seconds for the second RHR pump to get to rated speed before CS pump starts. The calculations show that the RHR pump requires <4.5 but > 4 seconds to get to rated speed.
PlF Q1998-0709 documented that QC had previously incorrectly interpreted the TS allowed tolerance for the timing relays and that procedures and calculations may not ensure adequate values. The procedures allowed the RHR timers to be set at 3.3 - 5.5 seconds and allows the CS timers to be set at 9 - 11 seconds. The licensee's response to the PlF indicated that i
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although the procedures were not correct, EDG toad testing demonstrated that the intent of not overloading the EDG by overlapping load blocks was assured.
The team reviewed the test records (strip charts) of the previous 18 month surveillance test for the EDG3. The test results indicated that the EDGs transient response to load sequencing appearted acceptable. However, the test of the % EDG did contain questionable data as to the timing of the CS pump load block addition. The licensee reperformed the test on April 12,1998,
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and again the CS pump load sequencing timer timed out too fast. PIF Q1998-01878 documented this discrepancy. The timer was readjusted and the licensee plans to reperform that test prior to unit startup. PIFs Q1998-0709 requires the licensee to reconcile the EDG loading calculations, testing and calibration procedures, and TS to ensure correct EDG loading.
Misapplication of TS requirements for relay settings and inconsistency between the calculations, procedures, and analysis is identified as URI 50-254(265)/98-201-08 (Design
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Control).
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b.
EDG Long Term Loading I
During the above review of calculations 9390-02-19-1,9390-0219-2 Rev.1, and 9390-02-19-3, the licensee identified that pumped fluid temperature effects on pump brake horse power (BHP)
was not considered in EDG loading analysis. Because of the temperature effect on the specific gravity, lower water temperatures at the start of the event would result in a BHP increase for these pumps. These changes in BHP and EDG loading were relatively small when compared to another problem identified by the team's review.
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As discussed in section E1.2.4.2.c the team identified that the wrong BHP was calculated after
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impeller replacement on the RHRSW modification. The maximum BHP for the RHRSW pumps should have been 1029 hp as compared to a calculated 961 hp.' The licensee initiated PlF Q1998-01078 to evaluate impact of the BHP increase on the Swing EDG Loading Calculation l
9390-02-19-3 (i.e., the most severely loaded EDG). The licensee's initial review determined
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that the new swing EDG kW loading (2908 kW) exceed the 2000 hr/yr limit of 2860 kW.
The licensee performed an evaluation (SO40-OH-0440 dated April 1,1998), using maximum BHP values with the instruroent air compressors tumed off. Based on the schematic drawings 4E-1372B Rev. R and 4E-1372C Rev. B, instrument air loads are not automatically initiated after a LOOP and the switches for the instrument air compressor are placed in pull-to-lock position per EOP procedure QCOA 6100-03. This resulted in a load reduction on the Swing EDG of approximately 150 HP. The analysis confirmed that after removing the air compressor load the kW load required to be supplied by the EDGs to mitigate a design basis event (i.e.
LOCA) after adjustment for correct BHP was now less than the 2860 kW (2000 hr/yr) rating of each respective EDG. Resolution of this item resulted in the identification that manually applied EDG loads are not well understood or effectively procedurally controlled. Various PIFs (Q1998- 01078, Q1998-01107, Q1998-01363, and Q1998-01503) were issued to upgrade procedures and revise EDG calculations.
Revision of the EDG load calculations and EDG manual loading procedures is identified as IFl 50-254(265)/98-201-09.
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c.
U2 Main 4160-V ESS Bus Power
UFSAR Section 8.3.1.6.2, page 8.3-9 states that EDG1 can power the Unit 2 main 4160-V ESS
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bus, if desired, by manually closing two circuit breakers. The plant design did not appear to support this option because of breaker interlocks and there was no procedure to perform this l
evolution. The licensee initiated PIF Q1998-00770 dated February 13,1998, to evaluate either the need for a procedure or to revise the UFSAR.
E1.2.2.3 Conclusions f
The team concluded that the essential electrical power supplies for RHR, RHRSW, CS and ADS systems were capable of performing their safety functions required by their design bases, adhere to the licensing bases, and are consistent with the commitments in the UFSAR.
Calculations for protective relay set points, coordination, voltage drops, EDG loading, battery loading and others were generally conservative in approach, used appropriate methodology, j
produced reasonable results, and were consistent with the design bases. Generally, the functional and performance requirements were consistent with the UFSAR, technical specifications, design criteria documents, and calculations and analysis.
Based on the above findings, the licensee issued various PIFs to revise affected calculations and revice the UFSAR and TS as appropriate to resolve the discrepancies.
E1.2.3 Instrumentation and Controls O&C)
E1.2.3.1 Scoce of Review i
The scope of the instrumentation and control design assessment.:onsisted of a review of RHR and RHRSW Design Criteria Documents, UFSAR, TS, SERs, P&lDs, loop diagrams, schematics / control logic diagrams, setpoint calculations and loop uncertainty analyses, setpoint data sheets, surveillance data sheets, design change packages and surveillance and operating procedures. Walkdowns were done of the system components, instrumentation and controls, Main Control Room, Auviliary Equipment and Cable Spreading Rooms, RHR and RHRSW Pump Rooms, MCC and Switchgear Areas, Battery Rooms and Diesel Generator Rooms. The inspection consisted of reviews of instrument installations, setpoints, electrical separation, and equipment qualification.
E1.2.3.2 Findings a.
Instrument Uncertainty - ASME XI 10 CFR, Part 50.36 (1)(i)(A) and (c)(ii)(A); Regulatory Guide (RG) 1.97, instrumentation For Light-Water-Cooled Nuclear Power Plants to Assess Plant and Environs Conditions During and Following an Accident and; RG-1.105, instrument Setpoints, are referenced in QC Nuclear Engineering Department Technical Information Document TID-E/l&C-20 as the basis for a
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consistent method of analysis for instrument accuracies. TID-E/l&C-10, Analysis of Instrument Channel Setpoint Error and Instrument Loop Accuracy, establishes a method for the preparation, review and approval of instrument channel setpoint error and loop accuracy analysis. TID-Ell &C-20, Basis For Analysis of instrument Channel Setpoint Error and
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Instrument Loop Accuracy, describes a method for the analysis of errors that affect instrument loops. It follows the methodology for the determination of setpoints, allowable values and
instrument loop accuracy described in Nuclear Engineering Standard NES-EIC-20.04 Analysis of instrument Channel Setpoint Error and Instrument Loop Accuracy that is consistent with
ANSI /ISA-S67.04 Parts 1 and 2, dated 1994. UFSAR section 7.1.2.1 notes that setpoints listed in Chapter 7 are understood to be nominal values; the actual setpoints may vary within prescribed limits to account for particular instrument accuracies. NES-EIC-20.04 section 2 indicates that the standard shall be utilized in the development of uncertainty analyses for new setpoints, evaluation or justification of new setpoints, determining instrument indication uncertainties and indication accuracies and performing uncertainty analyses as required for other engineering evaluations. The licensee indicated that the current status of the development of calculations analyzing instrument channel setpoint errors and instrument loop
accuracies includes RPS and ESF setpoints and RG 1.97 Type A instruments. Additionally, the i
licensee provided a document describing the treatment ofinstrument uncertainties at QC. The responsa also reported that in-Service Testing of pumps would be done in accordance with ASME Section XI, OMa Part 6.
10 CFR, Part 50.55a requires 10-year in-service inspections / testing in accordance with Section XI of the ASME Boiler and Pressure Vessel Code. The team reviewed current performance tests for the RHR, RHRSW and CS pumps with attention to the use of installed plant instruments for measuring performance values. The reviewed tests were conducted in accordance with Comed's Third Ten Year Interval Testing Program Plan For Pumps and Valves for QCNPS, issued in accordance with 10 CFR 50.55a. Operability surveillance test procedure OCOS 1000-06 covered the RHR Pumps; QCOS 1000-04 covered the RHRSW Pumps; and QCOS 1400-01 covered the CS Pumps. The team noted in all cases the procedures specified
' the use of insitu pressure and flow instrumentation. The table below lists the instruments and their function and locations.
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RESIDUAL HEAT REMOVAL INSTRUMENT NUMBER FUNCTION LOCATION Fi 1(2)-1040-11 A&B RHR Heat Exchanger Discharge Flow Control Room Pl 1(2)-1001-71 A,B,C&D RHR Pump Discharge Pressure Local Pl 1(2)-1001-70A,B,C&D RHR Pump Inlet Pressure Local RESIDUAL HEAT REMOVAL SERVICE WATER
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Fl 1(2)-1040-1 B RHRSW Pump Discharge Flow Control Room Pl 1(2)-1040-3A&B RHRSW Heat Exchanger Outlet Pressure Control Room PI 1(2)-1001-77A,B,C&D RHRSW Pump Discharge Flow Local Pl 1(2)-1001-160A,B,C&D RHRSW Pump Inlet Flow Local CORE SPRAY _
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Fl 1(2)-1450-4/ &U Core Spray Pump Discharge Flow Control Room PI 1(2)-1402-40 A&B Core Spray Pump Discharge Pressure Control Room Pl 1(2)-1450-1 A&B Core Spray Pump Suction Pressure Control Room No provisions are made in these procedures for adjusting the results to allow for the effects of instrument uncertainties, nor were any directions given to use test instrumentation. PIF Q1998-00383 was issued stating that allowances for the uncertainties of instrumentation used to measure the RHRSW pump performance were not described in calculation QDC-1000-M-0485.
This calculation provided minimum acceptance criteria for determining the capacity of the RHRSW pumps. The reviews of other performance calculations, test procedures and test results in conjunction with this AE inspection similarly revealed the absence of allowances for instrument uncertainties when measuring system performance. These other reviews included the RHR and CS pump performance evaluations, RHR heat exchanger performance testing and ECCS pump room cooler performance testing. The licensee claimed that penalizing the j
test results for instrument uncertainties was not necessary as long as the instrumentation
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utilized met the accuracy requirements described in OM-6.
OMa-1988 Part 6 subsection 4.6 establishes specific requirements for the instrumentation to be used to monitor the test. This inspection focused on the pressure and flow variables monitored to evaluate pump performance. OM-6 limits the acceptable range for pressure and flow indications to three times the reference value at which the pump is to be evaluated, it
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establishes an acceptable instrument accuracy of 12 pm.ent of full scale for pressure and flow individual instruments or total loop accuracy for combinations of instruments. The licensee referred to ASME File 94-1, dated September 22,1994, limiting the meaning of the OM-6
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l l0 requirements to reference accuracy as specified by the instrument manufacturer. The licensee also referred to ASME interpretation 91-3, dated May 14,1991, File OM-90-1, to stipulate that Table 1 of Part 6 applies only to the calibration of the instruments and does not take into account such attributes as orifice plate tolerances, tap locations, and process temperatures.
This would leave reference accuracy to represent those instrument attributes which can not be calibrated out such as reference accuracy itself, linearity, hysteresis, deadband and repeatability. As noted in TID-E/l&C-10 manufacturer specifications define reference accuracy to bound these attributes in a single value. Unless specified separately by the manufacturer it is reasonable to assume they are furnped into the value advertised for the reference accuracy.
NUREG-1482, Guidelines for In-service Testing at Nuclear Power Plants, indicates that licensees must obtain relief from the NRC to use instruments which do not meet the minimum requirements of the ASME code. The NUREG further notes that relief will be granted only if the
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vanance is equivalent to the requirements of the ASME code, or the licensee demonstrates the variance is not sufficient to degrade the results, or that replacement instrumentation is excessively burdensome with minimal improvement in quality.
Using Loop Element Data calculation extracted from NED-I-EIC-0161, Residual Heat Removal i
System Service Water Flow Indication Accuracy Analysis, a preliminary calculation was done to determine the total loop accuracy by the least squares method following the guidelines of OM-6.
The results showed the total loop accuracy to be 12.89 percent full scale, which exceeds the ASME code reo;irement. OC has not requested nor received relief from the NRC. The licensee presented the team with one time calibration records to demonstrate that the instrumentation could perform better than the manufacturer specification. Insufficient historicM data was available to show continued performance of the instrumentation at better than manufacturer specified accuracy levels. Test instrumentation that meets the code requirements can be substituted for the insitu instrumentation if the records reflect the identification of the instruments used to facilitate reuse for future tests.
No calculations were available for the RHR and CS flow indications nor the inlet and discharge pressure indication instruments. Similarly calculations have not been developed to cover the pressure indication loops. As of the exit from this inspection the licensee reported that all of these calculations were in preparation and review for issue. The licensee stated that design basis information necessary to resolve the installed process instrumentation acceptability to meet ASME requirements would be reconstituted. If plant equipment does not meet the ASME requirements, new test equipment would be procured, and procedures would be revised to comply with the code requirements for instrument accuracy. This issue is identified as URI 50-254(265)/98-201-10 (Test Control).
E1.2.3.3 Conclusions The team concluded that the instrumentation and control design for the RHR and RHRSW systems was adequate. Setpoints reviewed were developed using acceptable methodology and adequate margin. UFSAR and Technical Specifications limits were met. The initial extent of application of newer methodology to RPS and ESFAS setpoints and RG 1.97 Type A variables was acceptable. Extended application of the methodology to other variables and
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values such as LCOs, and operating limits is in the planning stage. System performance test and ASME testing for the RHR, RHRSW, and the CS systems did not appear to accurately account for the effects of instrument uncertainties on the measured variable.
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E1.2.4 Svstem Interfaces E1.2.4.1 Scone of Review
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The team selected the following systems that interface with the RHR system to verify that the interfacing system design appropriately supported the function of the RHR system:
RHRSW system, which provides cooling water from the Ultimate Heat Sink (UHS), to
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the RHR heat exchanger.
Clean and contaminated condensate supply system, which provides an altemate suction
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source for the RHR pumps (from the contaminated condensate storage tank - CCST).
Reactor building floor drain system, which collects and processes floor drainage in the l
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l ECCS comer rooms; and the ECCS comer room coolers, which maintain room temperatures within acceptable limits.
In addition to reviewing design information for the interfacing systems identified above, the team examined installation of the interfacing systems during the RHR system walkdown.
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E1.2.4.2 Findinas a.
Ultimate Heat Sink (UHS) TS l
UHS TS 3.8.C states that the UHS shall be operable with a minimum water level at or above -
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elevation 561' Mean Sea Level (MSL) for all operational modes as determined once per 24 l hours by verification of water level. The bases statement indicates that the Mississippi River
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provides an ultimate heat sink with sufficient cooling capacity to either provide normal cooldown l
of the units, or to mitigate the effects of accident conditions within acceptable limits for one unit I
while conducting a normal cooldown on the other unit.'
UFSA7 Section 9.2.5; Ultimate Heat Sink, indicates that on dropping river water level, the water-levelin the condenser water boxes would recede causing both units to be shutdown due to loss of condenser vacuum. Although the water level which would cause the loss of condenser
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vacuum is not indicated, the normal UHS water levelis 572' above MSL as controlled by Lock.
and Dam No.14. UFSAR Figure 2.4-2, Station Site Flow Diagram at the Mississippi River indicates a high point exists between the main river channel and the cribhouse intake at approximately elevation 565'- 0". UFSAR Section 2.4.4 Potential Dam Failures states that the natural river bottom between the river's edge and the main channel varies in elevation from 557'
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to 565' and prevents a direct flow of water from the main channel to the cribhouse during a dam failure with an assumed water level of 561'.
The team identified that the TS and bases appeared to be inconsistent with the UFSAR in that
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. the TS allowed for plant operation in all modes with a river water level down to 561' with capability to support normal and accident condition cooldown and accident mitigation, while the UFSAR implied that the contour of the river bottom at the intake flume would prevent a direct flow of water between the main channel and the cribhouse.
The licensee issued PIF Q1998-01450 to document tnis issue and indicated that the current elevation requirements came into affect through the Technical Specification Upgrade Program
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(TSUP). Prior to T6UP there were no TS's for an ultimate heat sink, however administrative l
controls within procedure QOS 0005-01, Operations Department Weekly Summary of Daily l
Surveillance had required a river level of 570' which was changed to 561' with TSUP
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implementation. The team noted that the expected low water level identified in UFSAR Section 2.4.4 was 570', consistent with the administrative controls previously established in OOS 0005-01, l
At the public exit, March 27,1998, the licensee indicated that the UHS was currently considered operable, and means were in place to add water to the trapped volume. A change to the TS would be processed and administrative limits would be established as an interim measure.
Improved guidance and procedures would be developed including streamlining Dam failure notifications from the Army Corps of Engineers. The above changes would be supported by a 10CFR50.59 safety evaluation.
Resolution of UHS TS 3.8.C River Level Error is identified as URI 50-254(265)/98-201-11
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(Design Control).
b.
UHS - Dam Failure UFSAR Section 2.4.4, Potential Dam Failures, states that if Dam 14 were to fail, the river level at the station is assumed to drop to elevation 561' and that the natural river bottom between the river's edge and the main channel varies in elevation from 557' to 565' and prevents a direct flow of water from the main channel to the cribhouse during a dam failure. UFSAR Section 9.2.5 indicates that the contour of the river bottom would trap a large volume of water at elevation 561' in the intake fiume which in conjunction with the discharge flume, would be used as an evaporative heat sink with portable pumps of approximately 2000 gpm capacity available on site for makeup requirements.
The team determined that in an evaporative mode, the trapped volume UHS would increase in temperature and during summer operation, could be driven well above the 95'F design temperature established for the RHR heat exchanger (UFSAR Table 5.4-6) and could affect the i
performance of other safety related equipment including the EDG Cooling Water System,
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ECCS Room Coolers, RHRSW Vault Coolers, and CR HVAC, all which receive cooling water from the UHS.
The licensee initiated PlF's Q1998-00966 and Q1998-01282 to address these concerns. The
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heatup rate and final temperature for a limited volume UHS operating in an evaporative mode could not be determined from existing documentation. Licensee's preliminary evaluations indicate that for a one hour cooldown time on the main condensers from dam failure to loss of
contact with the river, and a 4000 gpm makeup / dilution flow to the impounded UHS, the UHS j
could reach a maximum temperature of 112' F. This evaluation used a method of makeup i
different than the current UFSAR.
j inability of the UHS, in the recirculation mode with limited makeup capability, to maintain an l
upper limit supply temperature consistent with the design bases, could be indicative of a j
misunderstanding of the original design bases. The administrative controls described in
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E1.2.4.2.a above are in place as a temporary short term resolution. Final resolution of Dam
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failure effects on the UHS is identified as URI 50-254(265)/98-201-12 (Design Control).
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. Plant modifications changed the impellers on the low pressure model 8SF RHRSW pump to a full size impeller Calculation MECH - 13, RHRSW Pump Brake Horsepower Requirements for
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Various Modes of RHRSW Operation, dated November 17,1995, evaluated the effect of the
modification and considered several pump operating cases with and without off-site power.
I Calculation MECH - 13 uses nomenclature of main and booster pump where the description indicates the main pump (LP) feeds the (HP) booster pump. Calculation MECH -13 indicates the BHP required for the main pump decreased from 535 - 540 with the original impeller design to 375 - 380 for the new (larger) impeller design at the same flows. The pump curves used were not included within the calculation, and the basis for the reduction was not evident.
The team compared the results of MECH -13 to pump curves provided with another estculation
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(QDC-1000-M-0353) for the same pumps and concluded that at the same flow rates, an l
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increase in the LP pump BHP to 550 - 590 was required based on head, capacity and efficiency points. When added to the correct values for the HP pump which was modified to a smaller imoeller, a total BHP of over 1000 should be considered for diesel generator loading. MECH.-
13 incorrectly calculated a value of 952-961 BHP for the recently modified impellers.
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The licensee issued PlF Q1998-01363, which concluded that the characteristics of the 8SF i-and 8GT impellers appeared to be swapped, non-conservative flow rates were assumed, and j
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. the pump curves used were outdated. Based on the correct pump curves and a maximum flow
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of 3900 gpm through the low pressure pump, the licensee found the expected BHP increased to l
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1029 including 5 percent margin for uncertainties as in the original analysis. Discussion of the effects of the BHP increase on EDG loading is discussed in Section E1.2.2.2.b.
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Misapplication of the pump curves and use of non-conservative flow rates for the determination of RHRSW pump BHP requirements and EDG loading is identified as URI 50-254(265)/98-201-
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i 13 (Design Control).
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d.
RHRSW Pump Vortex Considerations
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Design of the cribhouse provides non-safety traveling screens and stationary screens to provide l-a filtered suction to the RHRSW and Diesel Generator Cooling Water Pumps.' The stationary screens had been inspected and cleaned once each two years in response to GL 89-13 program. However, PlF 95-915 identified past problems with plugging of the RHRSW screens
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' after only one year in service. Corrective actions included increased inspection and cleaning l
the screens on a yearly basis, consistent with the May Fly larva life cycle. Current normal and y
post-event procedures do not monitor pressure loss across the screens or ensure effectiveness
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of these provisions other than normal shift rounds for traveling screens.
l The team was concemed how the cribhouse intake for the RHRSW pumps addressed the screens for vortex and NPSH considerations. The team noted that PlF Q1997-02871 had addressed vortex formation based on concerns at a sister plant. The analysis, not a formal calculation, concluded QC had a 9" margin for submergence. However, head loss across the screens and maximum expected flow rates through the system were not considered.
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The licensee indicated that no formal calculation for vortex considerations at the cribhouse existed, but one was being prepared. The licensee indicated that the preliminary analysis using i
a 1 ft pressure loss across the screens showed that the 9 " margin previously considered was no longer valid. The licensee's recent information indicated that air ingestion may be experienced. However, based on test data from NUREG-0897, Rev.1 and NUREG CR-2758, any vortex formation in the RHRSW intake bay would be within acceptable limits and not q
damage the RHRSW system.
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The team found that the licensee intemal assessment of IN 87-63, inadequate Net Positive
Suction Head in Low Pressure Safety Systems, indicated that NPSH for RHRSW pumps at 3375 gpm, had over 31 ft margin, and for the diesel generator cooling water pump (DGCWP) at 1700 gpm had over 16 ft margin. The conclusions appeared to be based on single pump operation and did not demonstrate that multiple pump operation through a common suction line-at worst case conditions was bounded. The analysis which developed these conclusions based on IST data was not available. The licensee indicated that this information does not constitute the design basis as documented in recently completed calculations.
Calculation ODC-1000-M-0131 Net Positive Suction Head (NPSH) Availability vs.
Requirements for DGCW and RHRSW Pumps dated March 11,1996, provided the documented design basis. The calculation assumptions include a cribhouse water level of 561' (assumption 5), and a piping roughness value of 0.036 (assumption 6) based on calculation ATD 91-0124, Head Loss in Suction Piping for RHRSW and DGCW Systems. Design inputs included a DGCW pump design flow of 1300 gpm and a RHRSW pump flow of 3500 gpm. The calculation concludes that the RHRSW pumps have in excess of 29' NPSH available compared to 17.5'
required at 3500 gpm and the DGCW pumps have in excess of 29.7' available compared to 28.6' required at 1300 gpm.
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Given the small margin available within the design basis calculation for the DGCW pump, the team was concerned that additional head losses through the separation screens at the cribhouse and potentially non-conservative flow rates may challenge the NPSH conclusions.
The team noted that 3500 gpm corresponds to the single pump RHRSW flow established for the RHR heat exchanger, however procedural guidance to the operators establishes a limit of 3600 gpm or less (uncorrected for instrument uncertainty). Additionally, the calculation does not address flow to the RHRSW Room Cooler, Control Room HVAC, or RHR motor and seal coolers. The DGCW pump flow of 1300 gpm is consistent with UFSAR Section 9.5.5, Diesel Generator Cooling Water System which indicates an approximate flow requirement of 900 gpm for the diesel generator and 404 gpm for the respective ECCS room coolers. However, the team noted that flows through the ECCS room coolers are not controlled and total ECCS room cooler flows of 575 gpm have been measured as documented in PlF Q1997-03613.
The licensee indicated that calculation ODC-1000-M-0131 would be revised to address the separation screen head loss, auxiliary flows through the system, maximum flows through DGCW pumps and maximum flows through the RHR heat exchanger as allowed by operating
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procedures. The licensee indicated that the existing calculation actually used a conservative pipe roughness of 0.432 inches although assumption 6 indicates a piping roughness value of O.036 and thus margins would still exist.
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The nonconservative inputs and modeling for determination of RHRSW and DGCW pump operation is identified as URI 50-254(265)/98-201-14 (Design Control).
f.
RHRSW Design Pressure / Overpressure Protection i
UFSAR Table 9.2-1, Residual Heat Removal Service Water Equipment Design Parameters
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states that the RHR heat exchanger has a secondary (tube side) design pressure of 350 psi, and that ASME Section Vill is the applicable pressure vessel code. GE Design Specification 257HA423 Rev.0, Residual Heat Removal System Design Specification, dated October 4,1968,
requirement 4.2.3.2 states the heat exchanger tube side shall be designed for the shut-off head i
of the RHR service water pumps. GE Specification 257HA423AJ Rev.4, Residual Heat
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Removal System Specification Data Sheets dated September 1,1972, section 4.2 identifies a maximum allowable shutoff head of 810 ft for the RHR service water pumps. Pump curves reviewed indicated that the installed pumps developed a shutoff head of over 1000 ft.
Design Basis Document, RHR (DBD-OC-008) identified numerous functions for the RHR HX relief valve. Functions identified included HX protection when isolated from the system, in case of a tube break from the high pressure RHR side, and operation in the shutdown cooling, torus
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cooling, or fuel pool cooling modes. Potential overpressurization considering the RHRSW pump'as a pressure source was not identified.
l The licensee stated that relief valve capacity (approximately 1300gpm), was based on an
l assumed 10 percent of the shell side flow which would encompass the conditions for thermal l
relief and tube rupture. Based on pump performance curves, the team estimated a relief valve i
capacity in excess of 2500 gpm would be required considering one of two parallel pump operation and a 10 percent code overpressure allowance during relief valve operation.
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The licensee indieved that this situation was first identified by GE during the original plant startup testing, but documentation to resolve the issue has not yet been located. PIF Q1998-
01270 was issued to document this discrepancy between the RHR heat exchanger tube side design pressure and relief valve setting, and the shutoff head of the RHRSW pumps.
The team qudstioned the acceptability of the RHR HX relief to protect the pump discharge piping as well. The licensee provided specification R-4411 Rev. 6, dated April 25,1994, which indicates the RHRSW piping from the discharge of the booster pump to the heat exchanger outlet valves has a design pressure of 350 psig. The licensee issued PIF Q1998-01470 to document the RHRSW discharge piping design pressure discrepancy and to evaluate the impact on the piping stress analysis. PIF Q1998-01470 indicates the resolution of the design pressure discrepancy should be evaluated with respect to the shutoff head of the RHRSW i
pumps (near 450 psig).
At the public exit, March 27,1998, the licensee indicated that the RHR heat exchangers would be evaluated to determine if rerating for an increased design pressure is possible. As an altemative, a code exemption or code relief could be pursued, or system modifications could be required to meet the code. PIF Q1998-01270 verified that operating procedures provide administrative controls to minimize concems with possible system overpressure.
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Design basis needs to be correctly translated into specifications, drawings, piocedures, and instructions. System design with a RHRSW pump shutoff head in excess of the GE specified value, without consideration of overpressure protection requirements for the heat exchanger and piping system is identified as URI 50-254(265)/98-201-15 (Design Control).
g.
RHR/CS Alignment to CCST during Shutdown Conditions TS Section 3.5.B, Emergency Core Cooling System - Shutdown, specifies operability requirements for the ECCS during shutdown conditions (Modes 4 and 5). One or both CS subsystems, and one or both LPCI subsystem loops, must be operable, to provide a makeup water source fcr the reactor vessel. Both this TS section and TS Section 3.5.C Suppression Chamber, allow ths ^S and LPCI subsystams to be considered operable when the suppression chamber water levei is less than 7 ft or when the pool is drained, provided the pump suctions are aligned te the contaminated condensate storage tank (CCST) containing at least 140,000 availabh gallons of water. The CS/LPCI suction from the CCST is uncovered at the 90,000 gallon level. This 90,000 gallon volume in the lower portion of the CCST is reserved for use by the HPCl/RCIC systems and physically not available for CS/LPCI. Thus, at least 230,000 gallons are required in the CCST to satisfy the TS requirements of 140,000 gallons.
Precedure OOS 0005-01, Operations Department Weekly Su.
'ary of Daily Surveillance, Rev.
60, indicates that the CCST water level is verified to be > 10.5 ft m Operating Modes 1 through 5. The licensee determined that this CCST level may not assure the availability of 140,000 gallons of water for reactor vessel makeup via the CS and/or LPCI pumps. The volume of unusable water in the bottom of the CCST was apparently not considered, and there was a lack of clear design documentation to determine the height of the CS/RHR pump suction standpipe inside the CCST. The licensee initiated PlF # Q1998-00775 to address this concem. The licensee indicated that the standpipe location would be measured during the current outage, that vortex calculations would be performed as input in establishing the appropriate minimum water 'evel in the CCST, and that affected station procedures would then be revised. The lack of an exact elevation for the CS/RHR suction standpipe in the CCST was previously identified during the HPCI SOPi conducted in the fall of 1997 (NRC inspection report no. 50-254/07022(DRS); 50-265/97022(DRS).
The bases for TS Section 3.5.C state that a CCST volume of 140,000 gallons provides the required NPSH for the 1S and LPCI pumps, and ensures that at least 50,000 gallons of makeup water can be supplied to the reactor vessel. This statement was apparently in error, since TS LCOs 3.5.B.1.a.2 and 3.5.C 2.c c'early require 140,000 gallons available as a makeup source. The NRC SER dated December 27,1995, that documented the NRC review of a licensee Technical Specification Upgrade Program (TSUP) c lbmittal also clearly identified the 140,000 gallon volume as the required available makeup source (not 50,'J00 gallons). The liccnsee indicated that a correction to +h4 m bases would be processed to resolve this discrepancy.
The failure to establish an r yte e.e CCST water level to assure availability of an adequate makeup water source, as requ a by the TS, is identified as URI 50-254(265)/98-201-16 (Design Control).
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h.
ECCS Leakage Reduction Program TS Section 6.8.D.1 specifies a progiam to provide controls to minimize leakage from those portions of systems outside primary containment that could contain highly radioactive fluids during an accident to as low as practical levels. The LPCI (RHR) and CS systems are included in this program. Implementation of this program was a post-TMIitem (NUREG-0737, item lli.D.1.1). The team reviewed procedures QTP 0500-14, Leak Detection and Reduction Surveillance, Rev. 6, and QCTP 0820-08, Leakage Reduction, Rev. 2, and determined that leakage is maintained as low as practical; however, no specific leakage acceptance criterion I
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was indicated. The licensee stated that the NRC acceptance of the leakage reduction program (NRC letter dated March 5,1980) did not require a commitment to a specific allowable leakage value. The team also reviewed the existing offsite and control room dose calculations described in UFSAR Section 15.6.5.5.3 and determined that no mention is made of a dose contribution from ECCS leakage.
On May 19,1997, the licensee submitted to the NRC a report that re-calculates the post-accident control room doses. This report, which was prepared to address revised control room I
infilt7 tion assumptions, incl 9ded a dose contribution from ECCS leakage of 10 gallons per hour (gph)into the reactor building. The licensee initiated PlF # Q1998-01192 to incorporate the 10
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gph ECCS leakage limit into procedure QCTP 0820-08. The licensee also stated that after
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NRC approval, the revised control room dose assessment results would be incorporated into the UFSAR.
1.
Corner Room Floor Drains Temp Modification UFSAR Section 3.4.1.2.2, Protection of the Emergency Core Cooling System, identifies that check valves are installed in the floor drain lines of the reactor building comer rooms. Qose l
check valves protect the ECCS equipment in the corner rooms by preventing water in the torus j
room area from backing into the corner rooms through the drain lines. During a system i
walkdown, the team noted that plugs were installed in the drain lines.
PIF 96-871 identifies a previous leak within the 1 A RHR room and indicates that the plugs had
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been installed since 1993 under a temporary alteratior, as a corrective action to a 1993 LER (93-022). PIFs 94-2220 and 95-1841 alsc document concems with longstanding issue of plugged comer room floor drains. ER 9600503 identifies that plugs are installed due to valve problems and a design change to add sumps to each comer room has beer, approved.
Hi.; wever, the design change is not expected to be implemented in the near future. The team
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c;.1cluded that the installation vithe drain plugs as a temporary alteration had existed for I
almost 5 years awaiting replacement of the check valves as identified in the corrective actions
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to LER 93-022. The licensee indicated that the check valves had been replaced under the
modification program, however post modification testing had not been completed and therefore l
the plugs were stillinstalled.
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i The team noted that QC Nuclear Power Station Units 1 and 2 Intemal Flooding Analysis Notebook, Rev 0, dated October 1993 indicates that comer room flooding due to wash down from higher sources within the building is considered a probabilistically insignificant event. This conclusion is drawn in part on fact that, should some water find its way into the comer rooms, the drain lines located therein are expected to provide prompt removal.
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Installation of temporary plugs since 1993, pending implementation of corrective actions
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identified in LER 93-022 appears to be a weakness in the licensee's Corrective Action Program.
E1.2.4.3 Conclusions
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i The design of the RHR system interfaces was generally acceptable and supported performance j
of the RHR system safety functions; however, the team identified several concerns. The TS
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minimum required water level of the UHS (Mississippi River), the water source for the RHRSW l
system, appeared to be inconsistent with the original plant design bases. The hoatup rate, final temperature, and makeup water requirements for the UHS when operating in the evaporative i
mode (due to Dam 14 failure) could also not be substantiated by existing licensee
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documentation. Following modifications to the RHRSW pump impellers, the pump BHP was
improperly calculated, which in tum adversely impacted EDG loading. The RHRSW pump l
NPSH calculations did not properly consider maximum system flow rates or intake screen head
loss. The RHRSW pumps were procured with a shutoff head in excess of the GE specified l
value, without consideration of overpressure protection requirements. The water level i
maintained in the CCST may not have assured availability of the TS minimum required volume
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for CS/RHR pump operability during shutdown conditions.
l The licensee initiated actions to resolve these items through their condition reporting and i
corrective action program.
E1.3 Core Soray (CS) and Automatic Deoressurization (ADS 1 E1.3.1 Mechanical i
E1.3.1.1 Scoce of Review The mechanical design review of the CS and ADS included design and licensing documentation review, system walkdown, and discussion with system and design engineers. The team reviewed applicable portions of the UFSAR and TS, flow diagrams, physical drawings, vendor documents, equipment specificationis, numerous calculations, operating and surveillance procedures, PlFs, Operability Determinations, modification packages and safety evaluations. The scope of the review included the appropriateness of the design, bounding design con'litions, validity of design assumptions, verification of design input, verification of heat loade and capability of room coolers, vulnerability of components, adequacy of tests and surveillance and the adequacy of the analysis of their results.
The team placed special emphasis on the possible reduced capacity of the RHR heat exchangers and its impact on the NPSH available for the CS Pumps. The team also reviewed the modes of operation for the ADS valves and whether they are properly utilized in the Alternate Shutdown Cooling mode.
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E1.3.1.2 Findinas
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l a.
The original QC SER states that for the purpose of NPSH calculations, the containment overpressure can be assumed to be "a few psi."
l A review of calculation ODC-1000-M-0454, Rev. O, titled Short Term RHR/ Core Spray Pump NPSH Analysis - Design Basis LOCA, and the licensee's response to GL 97-04, Assurance of Sufficient Net Positive Suction. Head for Emergency Core Cooling and Containment Heat Removal Pumps, revealed the following:
j At time = 0-4 minutes, the analysis assumes available containment pressure of 9.5 psig, which is an assumption not substantiated in any QC design documents. This value is not based on any Quad Cities analysis, rather it is based on a certain value taken from a Dresden analysis. The most limiting case is where both CS pumps and all four RHR pumps operate (flow case 1). CS pump A requires the greatest containment overpressure of 7.2 psig, in order to avoid cavitation.
At time = 4-8 minutes
The analysis assumes available containment pressure of 2.6 psig. Five of the six pumps (4 RHR
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and 2 CS) require a containment pressure > 2.6 psig in order to avoid cavitation (RHR pump D requires 2.5 psig). The greatest deficit of about 10 feet is with CS pump A.
At time = 8-10 minutes The analysis assumes available containment pressure of 1.9 psig. All six pumps require a containment pressure > 1.9 psig in order to avoid cavitation. The greatest deficit of about 12 feet is with CS pump A.
The consequences of such pump cavitation are not certain because the CS pumps were not tested for cavitation. The licensee's response to GL 97-M, states that "Between 240 and 600 seconds post-LOCA, some cavitation may occur." The response also adds that pump cavitation during this time is acceptable and that tests performed on the pumps demonstrate that they can operate for up to 60 minutes in full cavitation without damaging pump intemals. The cavitation test (Bingham Pump Company, Cavitation Test Report 12x14x14-1/2 CVDS Pump) for RHR pump Nos.
270419/26) was done at a 3 ft. deficit in NPSH for the RHR pumps; however, between 4 and 10 minuies, the deficit on the RHR pump will be as high as 8 feet. The CS pumps with a deficit of about 10 feet were not tested.
For long term analysis (> 10 minutes), calculation ODC-1000-M-0535, Rev. O, Long Term
' RHRMore Spray Pump NPSH Analysis - Design Basis LOCA, dated December 8,1997 uses a contair, ment overpressure of 3.4 psig. UFSAR Figure 6.3-42 shows that after actuation of contai,1 ment sprays, the overpressure in the drywell is less than the 3.4 psig value used.
After 10 minutes, the calculation assumes that the operators will notice pump cavitation and throttle l
flow in accordance with the NPSH curves in the EOP flowc'narts. A review of these curves shows that even with a containment overpressure of 3.4 psig, the curves allow operation of the pumps in regions where according to calculation ODC-1000-M-0535, the pumps will cavitate. Further review
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of the EOP flowcharts revealed that no specific directions were given to the operators with respect
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ic limiting drywell sprays, thereby reducing containment overpressure, to times when the Core Spray pumps will not cavitate.
The licensee agrees that at times, the pumps will cavitate, but contends that the cavitation test done by the vendor shows that the pumps can withstand the cavitation.
l This issue is being pursued with the NRC staff as indicated in URI 50-254(265)/98-201-01.
b. Alternate Shutdown Cooling Section 5.2.2.4 of the UFSAR states that the ADS valves and their discharge lines are capable of being used in the altemate shutdown cooling (ASDC) mode. In this mode of core cooling, water would be supplied to the RPV by a CS or LPCI pump which would fill the vessel above the steam line discharge nozzles. The water would then flow through the steam lines and the open relief valves and back to the suppression pool.
The team's review of the current QC design identified that the licensee appeared to have abondoned the ASDC functional requirements for the ADS valves. Additionally, when the ADS valve for Unit 2 were replaced with a different type the ASDC functional requiremer,t did not appear to have been addressed. Additional review of this issue by the team identified the following.
In an April 27,1983, response to the NRC regarding NUREG-0737, item II.D.1, the licensee evaluated the capability of the ERV ADS valves to accommodate the altemate shutdown cooling mode of operation. The licensee stated that the valves at QC were capable of supporting this mode of operation and added that if the normal shutdown cooling is unavailable, the operator would initiate the alternate shutdown cooling mode.
In an October 20,1983, letter to the NRC, NUREG-0737, item II.D.1 - Relief and Safety Valve Test Requirements, the licensee stated that " Based on the analysis of these lines, it is our judgement that the alternate shutdown cooling mode of operation can be readily accommodated for both units at Quad Cities Station."
In order to use the ADS valves in the alternate shutdown cooling mode, the operators need procedural direction for such operation (such as limiting pump flowrate based on the number of open ADS valves, etc.). No procedural records could be found directing the operators to use the ADS valves in the ASDC mode described in the UFSAR and in the letters to the NRC. The
!icensee stated that the reason this cooling path was deleted was that the EPGs (Rev. 3 and 4), do not include this cooling path.
On January 30,1998, the licensee issued a resolution to PIF Q1998-00285 stating that "UFSAR change has been initiated to remove reference to this alternate shutdown cooling method. The tracking number fc-the UFSAR change is: UFSAR-97-R5-026." The team challenged the licensee's decision to drop the ASDC functional requirement from the ADS design. The licensee withdrew the instructions to remove the UFSAR reference and initiated a detailed review to pursue the validity of the need to use the ADS valves for ASDC.
l The licensee stated that If a valid ASDC requirement for the ADS valves was determined, the i
design basis analysis demonstrating acceptable design capabilities will be reconstituted and
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procedure changes will be implemented. At the public exit on March 27,1998, the licensee rewnfirmed their commitment to expedite resolution of this item since there might be a correlation l
with on going fire protection review efforts.
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Reconstitution of the ability to meet UFSAR and other regulatory commitments with regard to the alternate shutdown cooling mode is identified as URI 50-254(265)/98-201-17 (Design Control).
j E1.3.1.3 Conclusions The team concluded that the mechanical design of the CS and ADS systems was generally acceptable, and that the systems were capable of performing their safety functions assuming a loss
of offsite power and a single active failure. The team identified a concern regarding the fact that I
the licensee relied upon considerable containment overpressure in order to justify sufficient NPSH l
for the CS pumps. The team also determined that the ADS system is not procedurally utilized for the Alternate Shutdown cooling mode as required by item II.D.1 of NUREG-0737 and as committed in UFSAR and the licensee's letters to the NRC.
E1.3.2 Electrical The discussion in Section E1.2.2 of this report covers the electrical design review of the CS ano l
ADS systems.
E1.3.3 Instrumentation and Controls (l&C)
The discussion in Section E1.2.3 of this report covers the instrument and control review for the CS and ADS systems as well.
E1.3.4 System Interfaces
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The discussion in Section E1.2.4 of this report covers the system interface review for the CJ and l
ADS system as well.
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E1.4 UF3AR Review The team reviewed the applicable UFSAR sections for the RHR, RHRSW, CS and ADS g stems, other interfacing systems, and the associated electrical and instrumentation and controls sections, to verify consistency between the UFSAR descriptions and design documeritation.
a. The following discrepancies were noted during review of the RHR and RHRSW UFSAR Chapters.
UFSAR Table 6.2-7 lists penetrations of primary containment and associated isolation
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valves (CIV). Containment penetration X-039A/B is the RHR d ywell spra/ ine penetration l
and is isolated by valves MO 1001-23A/B and MO 1001-26A/B. Penetration X-210A/B is the RHR return line to the suppression pool and is isolated by valves MO 1001-34A/B, MO l
1001-36A/B, and MO 1001-37A/B. For all of the above-referenced valves, UFSAR Table 6.2-7 indicates that the "l'est Class" is C; i.e., the valves are Type C leak rate tested in accordance with 10CFR50 Appendix J. The team reviewed procedures QCTS 0600-17,
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RHR Containment Spray Local Leak Rate Test MO-1(2) 1001-23A/B, and MO-1(2) 1001-26A/B, Rev. 6; and QCTS 0600-18, RHR Suppression Chamber Spray MO-1(2)-1001-
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34A/B,36A/B, and 37A/B Local Leak Rate Test, Rev. 5, and determined that leakage through valves MO 1001-23A/B and MO 1001-34A/B was not in fact measured. The valves only served as boundaries for testing of other system valves. The licensee's justification for not leak rate testing these valves was that the valves are sealed with a qualified seal water system (i.e., the RHR system) that is capable of maintaining a water seal at a pressure of greater than 1.1P, for at least 30 days post accident; however, this justification was not reflected in the UFSAR. The licensee initiated PlF # Q1998-01455 to address this discrepancy.
In UFSAR Table 6.2-7, a number of isolation valves are associated with containment
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penetration X-210A/B. This penetration is a oiping header that conveys a number of test re!.um and minimum flow bypass lines back to the suppression pool. For each of these test retum and minimum flow bypass lines, an isolation valve is listed in Table 6.2-7, with the exception of the RHR pump minimum flow bypass lines. Neither the MOVs ( MO 1001-18A/B) or check valves (1001-142A-D) in the RHR pump minimum flow bypass lines are listed as isolation valves. The licensee stated that other potentialinaccuracies in UFSAR Table 6.2-7 have previously been identified (reference PIF # Q1997-032i/ and Q1997-04255), and actions to clearly define what is considered a CIV and revise Table 6.2-7 accordingly are in progress. These actions are being tracked in the licensee's NTS system.
UFSAR Table 6.3-18 shows the variation in RHR heat exchanger duty as a function
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of the number of RHR and RHRSW pumps operating. The definition of the four cases presented in the table (i.e., the number of RHR and RHRSW pumps operating) includes a notation regarding the number of emergency diesel generators (EDG) operating. This notation is potentially misleading because it implies (for Cases 1 and 2) that a single EDG can support the simultaneous operation of more than one RHR and one RHRSW pump. As shown in UFSAR Section 8.3.1.6, each EDG is sized to simultaneously power one CS, one RHR, and one RHRSW pump.
Tae licensee initiated PlF # Q1998-01016 to address this discrepancy.
On UFSAR Figure 5.4-11, a schematic diagram of the RHR system, valve 41 in the
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suction line from the CCST is shown as a normally open valve, even though the notation LC (locked closed)is also shown. This valve should be depicted as normally closed, consistent with the RI R system flow ' diagram, drawing no. M-39, Sheet 2, Rev. AW. This item is captured on FIF # Q1998-00918.
UFSAR Table 6.3-5 indicates RHR pump design parameters of 4,500 gpm flow at
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360 ft of head. Review of the certified vendor pump curves indicated that the total developed head should be about 400 ft at a flow rate of 4,500 gpm. This item is also captured on PIF # Q1998-00918.
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On UFSAR Figure 6.3-12, a schematic arrangement drawing of the LPCI loop
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selection logic, both recirculation loop equalizing valves (designated on the drawing as E, and E.) are shown as normally open. During normal plant operation, one of these valves is actually closed and thus should be cepined as wch on the figure.
This item is also captured on PIF # Q1998-00915.
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b.
The following discrepancies were noted during review of UFSAR Chapter 8 (Electrical Distribution).
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The diesel generator kVA rating on single line drawing 4E-1301, Sheet 3, Rev.AF
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l (3125kVA,2500kW)is not consistent with the value shown in Section 8.3.1.6.1, page
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8.3-8 of the UFSAR (3200kVA,2600kW). The licensee documented this deficiency
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under PlF Q1998-00747.
UFSAR Table 8.3-1 sheet 4 & 5 of 5 (4kV & 480-V Bus Loads) states that: (Unit 1
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shown typical for Units 1 and 2 except Main Transformer or as noted). This note
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does not provide for divergences between Unit 1 and Unit 2. Examples are:
a). 4kV bus 13-1 feeds the pump house transformer,4kV bus 23-1 does not have a i
like load-l
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b). 4kV bus 14-1 feeds the security building (gate house),4kV bus 24-1 does not have a like load; c). 4kV bus 23 feeds the ILRT compressor,4kV bus 13 does not have a like load; d). 480-V SWGR 28 & 29 - The number of MCC loads depicted on the key one line
drawings is 11, as cornpared to 12 loads shown in UFSAR Table 8.3-1, sheet 5 of 5;
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e). 480-V SWGR 16 & 26 - Additional loads, computer UPS, and essential service UPS are not reflected on UFSAR Table 8.3-1.
l The licensee documented these deficiencies under PlFs Q1998 00725 and Q1998-00785.
l Figure 8.3-1 of the UFSAR shows a flow of power from SWGR 14-1 to XFMR 18 to SWGR
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19. Similarly the figure shows SWGR 13-1 powering XFMR 19 and then SWGR 18. This is inconsistent with the design drawing, single line diagram 4E-1301, Sheet 3, Rev. AF. The licensee documented this deficiency under PlF Q1998-00556.
UFSAR Tables 8.3-2 & 8.3-3 (Diesel Generator Loading), labeled as " Original Design
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'3 asis", reflect the original design basis loading values. These values indicate individual load brake horsepower (BHP) and tc,tal diesel generator BHP /kW loading, includi,ng 2000 hour0.0231 days <br />0.556 hours <br />0.00331 weeks <br />7.61e-4 months <br /> kW loading. The listed loads and the total loading do not reflect the current '
configuration and are not diesel generator specific. The licensee documented this deficiency under PIF Q1998-00764.
The tie breaker positions shown on UFSAR Figure 8.3-1 appear to be inconsistent with
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design drawing 4E-1326 Rev. F, and the 4kV breaker identification numbers shown on UFSAR Figure 8.3-1 for buses 61 & 71 are not consistent with breaker numbers shown on key diagrams. The licensee documented this deficiency under PlF Q1998-00789.
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UFSAR Section 8.3.2.:2, page 8.3-32 last paragraph states that 125 Vdc cross-tie exists
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be' wn 4160-V switchgear 13-1 and 23-1 and is controlled by two manually operated circuit breakers that are lead sealed in the open position. Plant walkctwn did not identify lead seals on these breakers. Lead seals cannot be installed on these type of breakers.
The Licensee initiated PlF Q1998-00655 to revise UFSAR.
UFSAR Section 8.3.2.2 states that the period the unit 2125 Vdc attemate battery is relied
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upon is less than 52 days per calendar year (based on the probability of a tomado missile strike) and that there are no limitations on the unit 1 125 Vdc alternate battery. However the TS 3/4.9.c, D.C. sources - Operating states that each unit 125 V6 normal battery may be inoperable for a maximum of 7 days per operating cycle for maintenance and testing provided the 125 Vdc attemate battery is placed in service. If it is determined that a 125 Vdc normal battery needs to be replaced as a result of maintenance or testing, a specific battery may be inoperable for an additional seven days provided the 125 Vdc attemale battery is placed in service. Contrary to the UFSAR statement, it is evident from the TS that both 125 Vdc altemate batteries have limitations on usage. The licensee documented this deficiency under PlF Q1998-01438.
UFSAR Section 6.3.2.1.2 third paragraph says that power required for each pump is
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approximately 850 HP, whereas, the nameplate data indicates that the pumps are rated at j
800 HP. The licensee documented this deficiency under PlF Q1998-00714.
10CFR50.71(e) requires that the FSAR be updated periodically to assure tnat the informatica included in the FSAR contains the latest material developed and the UFSAR shall be revised to include all effects of all changes made in the facility or procedures as described in the FSAR. The above discrepancies are indicative of weaknesses in the licensee's processes for maintaining and l
updating the UFSAR, as required by 10CFR50.71(e) (URI 50-254(265)/98-201-18)
l E1.5 Design Control E.1.5.1 Scoce of Review The team reviewed engineering and design documentation (drawings, calculations, specifications, etc.) for the RHR, RHRSW, ADS, and CS systems as discussed in previous sections of this report.
During these reviews, the team assessed the effectiveness of the licensee's design control processes. The team identified a number of document discrepancies and inconsistencies, as itemized below.
E.1.5.2 Findings a.
Control of Calculations Quad Cities Preparation, Review, and Approval of Calculations procedure NEP-12-02 Rev.5 requires the revision of old calculations when new calculations are performed. Generic concem may exist in that the electronic work control system (EWCS) database for calculations is not complete and that the percentage complete is unknown. The licensee generated NTS 201199CAOD00629.1 to address severst PlFs which have identified problems with the calculation program and EWCS. A few examples are:
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Diesel Generator (EDG) calculations 7318-33-19-1,7318-33-2, and 7318-33-19-3 are all
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essentially inactive EDG loading calculations which are presently shown in EWCS as active.
The controlling calculations for the EDG loading are 9390-02-19-1, -2, and -3. The inactive calculations are not superseded in Quad Cities Calculation Site Appendix NEP 12-020U.
Comed calculation 7923-42-19-1 is for 480V switchgear 18,19,28,29 breaker settings.
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Some breaker settings were changed without revising the calculation. Similar proolem exists in calculations 7923-42-19-2,9149-15-19-1, and ODC-7200-E-0070, that are not revised or superseded to remove obsolete settings. There are various other new calculations generated without revising or superseding the old existing calculations.
Battery Sizing Calculation 7318-32-19-1 reference, Calculation for inputting 125 Vdc Load
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Profiles into ELMS, refers to Cuke calculations 0597-050-E-014 and -016 as input documents. However, these referenced calculations are not in the EWCS data base. These calculation we active documents.
PlF 98-0878 addresses two active calculations documenting the same SRV setpoint for PC
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1(2)-0203-3A thru E. Calculation 64.4200.0405 prepared by Nutech for Comed on November 5,1982 and NED-I-EIC-0043 issued by Corporate I & C Engineering in 1991.
EWCS shows both calculations as being active. However NED-I-EIC-0043 is the applicable design document for the setpoints for PC 1(2)-0203-3A thru E.
Safety E.aiuation SE 95-031 was written for the replacement of thermal overload heaters
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for RHR MOVs 2-1001-4A and 48. Although the motor replacements are "like for like" in the sense that they each are rated at 60 ft-Ib, the new motors are identified as having a higher fullload current. The thermal overload sizing calculation # 004-E-031 and voltage drop calculation # 004-E-005-1001 were not revised to reflect this higher full load current.
i Additionally the electrical load monitoring system (ELMS) data was not updated with correct I
full load and locked rotor currents. Changes in HP and current requires affected j
calculations to be updated to show revised thermal overload heater size. The licensee issued PIF Q1998-00792 to address this issue.
Specification R-4411, General Work Specification - Maintenance / Modification Work, Rev. 6,
specifies design conditions for the 3HR shutdown cooling suction line piping from outboard
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isolation valve MO-1001-47 to the RHR pumps suctions as 150 psig and 200*F. The team i
reviewed UFSAR Section 5.4.7.2.2, which stated that during the shutdown cooling mode, j
the process fluid would approach 338'F (the saturation temperature corresponding to a reactor pressure of 100 psig). TS Table 3.2.A-1 also listed the reactor vessel pressure -
high permissive setpoint (for opening of the shutdown cooiing suction valves) as 135 psig.
Therefore, a design temperature of 200*F appeared to be inconsistent with the actual pressure / temperature conditions at which the shutdown cooling mode of RHR could be
initiated.
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The licensee initiated PIF # Q1998-00909 to evaluate this condition and l
subsequently determined that thermalloading analyses had been performed at a
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l temperature of 340*F, as documented in Calculation File No. 28.0201.0632.10, Rev.
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1, dated September 25,1991; therefore, an unanalyzed condition did not exist. The
!icensee also determined that Specification R-4411 shou!d be revised, and an
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outdated calculation (O2-RHRS-05C, which anlyzed the piping at a temperature of 281*F) should be superseded.
Lack of control of active / superseded calculations, and missing calculations, do not satisfy the requirements of the licensee's Design Control Program and is identified as URI 50-254(265)/98-201-19 (Design Control).
b.
Nonconservative Calculation inputs l
A few examples of nonconservative calculation assumptions identified through the inspection effort include:
.l Vault Cooler Calculations - Calculation VT-16, Rev,0, RHRSW and DGSW Pump Cooler
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Performance Evaluation, dated March 19,1992, uses a fouling factor of 0.002 for the analysis of the RHRSW vault coolers The licensee identified this problem and issued PlF Q1998-00342 dated January 21,1998, stating that as a result of the low velocity in the coolers tubes, a fouling factor of 0.003 should have been used, but a lower value of 0.002 was used. This is unconservative and as a result of this error, the calculation overestimates the capability of the vault cooler to remove heat.
Calculation QDC-5700-M-0442, Rev. O, Core Spray Cooier 2-57488 Capacity with Blocked l
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Tubes, dated August 28,1997, calculates the heat capacity of the CS room cooler after the
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cooler failed D/P testing. The team's review of the test result attached to the calculation I
revealed that the root cause for the fouling and tube blockage was corrosion products from the upstream pipes. According to the inspection report, on March 24,1997, the licensee found that the cooler's tubes exhibited significant fouling with corrosion products. In the first l
pass, of 18 tubes,10 were completely plugged. In each of the second and eighth passes,1 tube was completely plugged and in the seventh pass,2 tubes were completely plugged.
Other tubes were found with corrosion products, some described as 50-90 percent plugged.
The shift engineer was notified that this cooler was inoperable / unable to perform design function in the as-found condition due to corrosion products. The test results were analyzed in calculation QDC-5700-M-0442 which assumed no partial tube plugging for those tubes which were not more than 50 percent blocked. bis is unreasonable because if numerous t'ibes are completely blocked and other tubes are 50-90 percent blocked with corrosion products from the upstream piping, than there will be some more tubes 40 percent blocked and so on.
In addition, this Calculation (ODC-5700-M-0442) mistakenly used a fouling factor of 0.002 while in the section 6.3 of the calculation it is stated that the coil inside fouling factor of 0.003 was used.
Furthermore, the computer program used in the calculation, does not model the heat exchanger correctly and overestimates the coil capacity by more than 6 percent when compared to the vendor's design value.
Design Control requires that the design basis be correctly translated into specifications, drawings, procedures, and instructions. The use of incorrect or nonconservative input data in calculations is identified as URl50-254(265)/98-201-20 (Design Control).
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c.
Reactor Level Setpoints inconsistent with Calculation This inspection included a review of those setpoint calculations important to safety for the RHR, RHRSW, CS, and ADS systems and some parts of the CCST and EDG support systems. Selected setpoints were reviewed against the respective surveillance procedures to verify the inclusion of the calculated instrument errors in the calibration acceptance criteria. Calculation NED-I-EIC-0022 is the reactor vessel low water level and low-low water level isolation setpoint error analysis at normal operating conditions. Rev. 2 was issued to evaluate the bias errors associated with the installation of the Reactor Vessel Level Indication System and the backfill modification. The present setpoints in the field are lower than the setpoints determined in the calculation making them non-conservative. An evaluation of the effect of this condition was conducted in conjunction with the safety evaluation screening. Additionally, this issue was reevaluated by PIF 98-J774 dated 2/13/98. The problem is that instrument errors were not properly transposed from calculation to hardware calibration. When errors were properly considered the margin from setpoint to analytical l
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limit is reduced but the analytical limits are not exceeded. This item is identified as another example of URI 50-254(265)/98-201-19 (Design Control).
i d.
Calibration Frequency Greater Than Assumed The calibration frequency of Recirculation Pump Discharge Differential Pressure Switches DPIS-1-0261-34A/D and DPIS-2-0261-34A/D is stated as 18 month 25 percent (22.5 months)in calculation NED-I-EIC-0163, Rev 1. The last calibration for the Unit 1 switches was March 16, l
1996, and the next due date is scheduled for the refueling outage listed as November 7,1998.
This interval is approximately 32 months which is much larger than what is assumed in the above l
referenced calculation. For the Unit 2 switches the last calibration date was March 21,1997, with the next due date scheduled for the Ursit 2 refueling outage listed as September 25,1999. This interval is approximately 30 months which is also larger than the calibration interval assumed and accounted for in the above referenced calculation. Prelirr,inary calculations based on PIF 98-0910, which documents this concem, identified tnat adequate margin for assumed instrument drift still exist.
Torus Water Temperature in Uncertainty Calculations e.
The instrument uncer'ainty calculations for pump flow rates typically use a lower temperature limit of 68'F for the process fluid. As the torus water temperature of the process fluid in the RHR, HPCI and CS systems may be lower than 68'F a srnall error is introduced when the system is tested at temperatures below 68'F. As the instrument uncertainty calculations already assume a temperature range and a corresponding water density change from 68'F to 300*F, the error irdroduced by temperatures below 68'F would be very small. PIF Q1998-0808 was issued to either re trict testing via procedure change to the temperatures assumed in the analysis or to incorporate a lower temperature limit in the analysis.
f.
DG Fuel Oillank Level instrumentation TS 3.9A.2.b requires a minimum volume of 10,000 gal for the diesels to remain operable.
Emergency Diesel Fuel Oil Storage Tanks leve! is measured as a percent of total vc!ume.
Calet lations QDC-5200-1-0035 and ODC-5200-1-0036 developed schedules for the inventories relatirg percent volume to gallons of fuel oil. Operational testing of the diesels is conducted in f
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accordance with surveillance procedures QCOS 6600-01, QCOS 6600-19 and OCOS 6600-20.
The diesels are declared inoperable during testing because the levels in the fuel oil tank can go below the 10,000 gal minimum. After testing, the tanks must be refilled and the level verified to be i
at least 10,000 gal before the diesel can be declared operable. The acceptance criteria for this minimum volume is an indication of 66 percent on the levelindicators. This equates to 10,269, 10,445 and 10,445 gal respectively for each of the tanks. Calculations NED-I EIC-0142 and ODC-5200-1-0031 determined indication instrument accuracies for the fuel oil tank levels to be between 6 percent and 7.11 percent of full span. The effect of these instrument errors on the indication are
'
such that at 66 percent indication the fuel oil remaining will be less than 10,000 gal of usable volume. Thus the requirement for the diesel to be operable may not be met when the indication says it has. The licensee issued PIF Q1998-1472 with a proposed resolution to revise the acceptance criteria in the above surveillance procedures to account for the effects of instrument error. Followup of this issue is identified as IFl 50-254,265/98-201-21.
g.
RHRSW Pump Mechanical Seals RHRSW pump mechanical seal ecoling lines were inconsistent with the arrangements depicted on the RHRSW P&lD M-37. This drawing was not updated as required by procedure QCAP 0460-05 to reflect revised mechanical seal flushing arrangement after the October 1996 and February 1997 modification for pumps 1-1001-65 C and B. PlF Q1998-00872 was issued to document failure to update drawings in a timely manner.
E.1.5.3 Conclusions
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Although individual items are not significant safety concerns and do not constitute operability concerns, collectively, they are indicative of weakness in the design control program. Calculation quality was mixed and many calculations were not being controlled and revised consistent with plant procedure requirements. There were some instances in which the licensee had no documentation or difficulty in retrieving design basis information.
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X1 Exit Meeting After completing the on-site inspection, the team conducted an exit meeting 'vith the licensee on March 27,1998, that was open to public observation. During the exit meetinj, the team leader presented the results of the inspection. A partiallist of persons who attendet the exit meeting is contained in Appendix B. During the exit the licensee described their short and long term plans to resolve several of the inspection issues. The licensee did not agree with the potential USQ characterization for the use of containment overpressure for ECCS NPSH. Additionally, the licensee expressed concern with the need to consider instrument uncertainties in the conduct of plant testing and analysis. Further discussion for these two issues was encouraged by the team.
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I Appendix A.
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List of Open items This report categorizes the inspection findings as unresolved items (URis) and inspection followup items (IFI) in accordance with Chapter 610 of the NRC Inspection Manual. A URI is a matter about.
which the Commission requires more information to determine whether the issue in question is acceptable or constitutes a deviation, nonconformance, or violation.. The NRC may issue -
- enforcement action resulting from its review of the identified URis. By contrast, an IFl is a matter
' that requires further inspection because of a potential problem, because specific licensee or NRC -
action is pending, or because additional information is needed that was not available at the time of the inspection.-
ltem Number Finding Tidg IX98 50-254(265)/98-20'1-01 URI RHR and CS Pump NPSH (E1.2.1.2.a)-
50-254(265)/98-201-02
- URI LOCA Analysis input Errors - Design Control
- (E1.2.1.2.b)
50-254(265)/98-201-03 URI inclusion of ECCS Flow Measurement Uncertainties in LOCA Analyses (E1.2.1.2.c)
50-254(265)/98-201-04 URI RHR Heat Exchanger Capacity - Test Control (E1.2.1.2.d)
50-254(265)/98-201-05 URI RHR Heat Exchangers, GL 89-13 Testing -
Test Control (E1.2.1.2.e)
50-254(265)/98-201-06 IFl Torus Cooling Mode Single Failure Vulnerability - (E1.2.1.2.g)
50-254(265)/98-201-07 UR!
Minimum Required Torus Water Level During Shutdown Conditions - Design Control (E1.2.1.2.i)
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.50-254(265)/98-201-08 URI EDG Short Term Loading - Design Control I
(E1.2.2.2.a)
l 50-254(265)/98 201-09 IFl EDG Long Term Loading - Design Control
(E1.2.2.2.b)
50-254(265)/98 201-10 URI Pump Inservice Test instrumentation - Test
!
Control (E1.2.3.2.a).
50-254(265)/98-201-11 URI Ultimate Heat Sink (UHS) TS - Design Control (E1.2.4.2.a)
50-254(265)/98-201-12 URI UHS - Dam Failure - Design Control (E1.2.4.2.b)
50-254(265)/C'
H-13 URI RHRSW Pump BHP - L'esign Control (E1.2.4.2.c)
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50-254(265)/98-201-14 URI RHRSW Pump NF 3H - Design Control (E1.2.4.2.e)
50-254(265)/98-201-15 URI RHRSW Design Pressure / Overpressure Protection - Design Control (E1.2.4.2.f)
50-254(265)/98-201-16 URI CCST Water Level to Provide Suction Source for RHR/CS Pumps During Shutdown Conditions - Design Control (E1.2.4.2.g)
l 50-254(265)/98-201-17 U,(.
Alternate Shutdown Cooling Mode - Design Control, (E1.3.1.2.b)
50-254(265)/98-201-18 URI UFSAR discrepancies - 10CFR50.71(e),
(E1.4.a & E1.4.b)
50-254(265)/98-201-19 URI Inadequate Control of Calculations - Design Control (E1.5.2.a & E1.5.2.c)
50-254(265)/98-201-20 URI Nonconservative Calculation inputs - Design Control (E1.5.2.b)
50-254(265)/98-201-21 IFl DG Fuel Oil Tank Level Instruments -
(E 1.5.1.f)
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b Appendix B Exit Meeting Attendees NAME
. ORGANIZATION -
< Comed
,0. Kingsley President, Nuclear Generation Group
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- S.; Perry VP-BWR D. Helwig Senior VP-Nuclear Servbes J. Hosmer VP-Engineering D. Sager Site VP.
L. Pearce Plant Manager R. Holbrook-Engineering Manager.
C. Paterson Regulatory Affairs j
D. Wozniak AE Team Counterpart (Management)
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P. Lawless AE inspection Leader
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S. Boline AE Team Counterpart (Mechanical)
R. Heyn AE Team Counterpart (Mechanical)
J. Taft AE Team Counterpart (l&C)
M. Warpehoski
- AE Team Counterpart (Electrical)
B. Strub AE Team Counterpart (Mechanical)
blRG A. Beach Regional Administrator, Rlll
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S. Richards Project Director, NRR M. Dapas
. Deputy Director, DRS, Rlli J. Jacobson Branch Chief, DRS, Rlll
- M. Ring
- Branch Chief, DRP, Rlli C. Miller Senior Resident inspector R. Walton -
Resident inspector l
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Appendix C
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List of Acronyms AC Alternating Current ADS Automatic Depressurization System AE Architect Engineer AEC U.S. Atomic Energy Commission ANS American Nuclear Society ANSI American National Standards institute ASDC Alternate Shutdown Cooling ASME American Society of Mechanical Engineers ATWS Anticipated Transient Without Scram B&PV Boiler & Pressure Vessel CCST Contaminated Condensate Storage Tank CFR Code of Federal Populations CIV Containment Isolation Valve Comed Commonwealth Edison CR Control Room CS Core Spray DGCW Diesel Generator Cooling Water DP Differential Pressure dT Differential Temperature ECCS Emergency Core Cooling System EDG Emergency Diesel Generator EID Equipment Identification Number ELMS Electrical Load Monitoring System EOP Emergency Operating Procedure EPG Emergency Procedure Guideline EPRI Electric Power Research Institute ER Engineering Request ERV
'Emergercy Relief Valve ESFAS Engineered Safety Feature Actuation Signal EWCS Electronic Work Control System FSAR Final Safety Analysis Report GE General Electric Company GL Generic Letter gpm gallons per minute HPCI High Pressure Coolant Injection HVAC Heating, Ventilating and Cooling I&C Instrumentation & Control IEEE Institute of Electrical and Electronic Engineers IFl Inspection Followup Item IPEEE Individual Plant External Event Examination
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'1 i
o ISA instrument Society of America
IST Inservice Test LCO Limiting Condition for Operation LER Licensee Event Report LLRT Local Leak Rate Test LOCA Loss-of-Coolant Accident -
LOOP Loss of Off-site Power LPCI Low Pressure Coolant injection MEL Master Equipment List MOV Motor Operated Valve NOV Notice of Violation NPDES National Pollutant Discharge Elimination System NPSH Net Positive Suction Head NRC U.S. Nuclear Regulatory Commission NRR Nuclear Reactor Regulation, Office of (NRC)
i P&lD Piping & Instrumentation Diagram I
PCT Peak Cladding Temperature PIF Problem Identification Form L
PlV Pressure Isolation Valve i
PORV Power Operated Relief Valve QC Quad Cities QCNPS Quad Cities Nuclear Power Plant RG.
Regulatory Guide
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RHRSW Residual Heat Removal Service Water RPS Reactor Protection System
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SER Safety Evaluation Report SOPl System Operational Performance inspection SWEC Stone & Webster Engineering Corporation TAF Top of Active Fuel TS Technical Specifications TSUP Technical Specification Upgrade Program UFSAR Updated Final Safety Analysis Report
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