IR 05000254/1991011
| ML20198C225 | |
| Person / Time | |
|---|---|
| Site: | Quad Cities  |
| Issue date: | 06/21/1991 |
| From: | Darrin Butler, Gardner R NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION III) |
| To: | |
| Shared Package | |
| ML20198C177 | List: |
| References | |
| 50-254-91-11, 50-265-91-07, 50-265-91-7, NUDOCS 9106280187 | |
| Download: ML20198C225 (20) | |
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s U.S. NUCLEAR REGULATORY COMMISSION REGION 111 Report No: 50-254/91011(DRS); 50-265/91007(DRS)
Docket No: 50-254; 50-265 License No: DPR-29; DPR-30 Licensee: Commonwealth Edison Company Opus West Ill Downers Grove, IL 60515 Facility Name: Quad Cities Nuclear Power Station - Units 1 & 2 Inspection At: Cordova, IL 61241 i
Inspection Conducted: April 1 through May 10, 1991 l Inspection Team: David S. Butler, Team Leader Zelig Falevits, Assistant Team Leader Jeffery F. Harold, Reactor Inspector !
William H. Scott, Reactor Inspector Tirupataiah Tella, Reactor Inspector Robert A. Winter, Reactor Inspector Frederick H. Burrows, Reactor Inspector, NRR NRC Consultants: Jean L. Areseneault, AECL (Atomic Energy of Canada)
Lloyd Lazic, AECL George B. Skinner, AECL Approved By: 2 [ / //
David S. Butler, Team Leader Date Plant Systems Section Approved By: k- /!T/
Ronald N. Gardner, Chief Date Plant Systems Section Insoection Summary Inspection on April 1 throuah May 10. 1991 (Report No. 254/910ll(DRS):
265/91007(DRS)).
Areas inspected: Special electrical distribution system functional inspection (ED5FI) conducted in accordance with tert.porary instruction (TI) 2515/107 (25107).
Resulta: The team did not identify any electrical distribution system (EDS)
equipment that would be unable to perform its safety function. Five (5) open items were identified regarding safety system protection during DG testing (Paragraph 2.1.6), fuse control program (Paragraph 2.1.15), configuration control (as-built) program (Paragraph Nos. 2.1.16.1 and 2.1.16.2), electrical penetration qualification (Paragraph 2.2.5) and diesel generator (DG) fuel oil system capacity (Paragragh 2.3.1.1). Nine (9) examples of unresolved items 9106280187 910624 PDR ADOCK 05000254 Q PDR
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! 2 were identified regarding system voltage values used in supporting documentation and calculations (Paragraph Nos. 2.1.1.1 and 2.1.1.2), DG loading calculation concerns (Paragraph 2.1.5), lack of detailed information to support cable ampacity determination (Paragraph 2.1.9), miscoordination of breakers (Paragraph Nos. 2.2.1, 2.2.2, and 2.2.4), and seismicity of DG components (Paragraph Nos. 2.3.1.2 and 2.3.3). One deviation was identified regarding the use of breakers that were not sized to prevent overduty conditions (Paragraph Nos. 2.1.4, and 2.2.1). Two violations were identified regarding the lack of timely replacement of CR120A relays (Paragraph 2.1.17),
and an inadequate safety evaluation for ILRT testing of Unit I with Unit 2 at power (Paragraph 3.2). The team observed both strengths and weaknesses which are more fully described in the Executive Summary of this report.
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.TjBLE OF CONTEfin l EXELVIIVE SUMMARY ...... ........................ ...................... i 1.0 INTRODUCTION .................................................... 1 2.0 ELECTRICAL SYSTEMS ............................................... I 2.1 AC SYSTEMS ................................................ 1 2.2 DC SYSTEMS AND ELECTRICAL PENE1 RAT 10NS .................... 11 2.3 MECMANICAL SUPPORT SYST EMS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 13
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3.0' ENGINEERING AND TECHNICAL SUPPORT ............................... 16 4.0 OPEN ITEMS ...................................................... 17
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5.0 UN R E SOL V E D I T E MS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 17 6.0 EXIT MEETING .................................................... 18 APPENDIX A - PERSONNEL CONTACTED
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EXECUTIVE SUMMAR" From April 1 through May 10, 1991, an NRC Region Ill team conducted an electrical distribution system functional inspection (EDSFI) at the Quad Cities Station to review the design and implementation of the plant electrical distribution systen (EDS) and the adequacy of the engineering and technical support (E&TS) organizations. The team reviewed the electrical and mechanical support systems of the EDS, examined installed EDS equipment, reviewed '.DS testing and procedures, and interviewed selected corporate and site personnel.
The team did not identify any ECS equipment that would be unable to perform its intended safety function. Houever, the lack of design basis informatior, made it difficult for the team to draw conclusions as to the functionality of the EDS. Design attributes of the EDS were not readily retrievable and verifiable. Engineering calculations contained unjustified assumptions and incorrect references. In addition, a number of configuration control concerns were identified. The team found the EDS and related support equipment properly installed in the plant and considered the external materiel condition of the EDS and housekeeping in the plant to be strengths. In addition, the team considered the knowledge and expertise of the engineering staff that interfaced with the team to be a strength.
Scveral design weaknesses that were identified will be pursued as unresolved items. Examples included:
o lack of formal documentation to support the seismicity of the DG fuel oil transfer system.
o Lack of formal documentation to support the seismicity of the generator output bus ducts.
o inadequate breaker / fuse coordination.
The team also had severai concerr.s that require additional followup by both the NRC and the licensee. Examples included:
o Weaknesses in the DG loading calculations.
o Engineering calculations contained unjustified assumptions and incorrect references.
o inconsistent voltage values used in degraded voltage documentation.
o Inadequate documentation for system voltage determinations.
o inadequate documentation for cable-ampacity.
o Inadequate documentation for evaluating FSAR/ Technical Specificatica fuel oil requirements.
o Installed circuit breakers ratings differed from design documents.
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o incorrectly sized fuses installed in safety related applications.
o Inadequate documentation to determine that electrical penetrations meet Regulatory Guide 1.63 requirements.
One of the team's concerns resulted in a deviation of FSAR requirements.
Examples included:
o Circuit breakers in the 250Vdc syr. tem were not sized to prevent overduty conditions.
o Circuit breakers in the 4kV system were not sized to prevent overduty conditions.
Several of the team's concerns resulted in violations of llRC requirements.
Examples included:
o CR120A relay coil or relay replacement had not been completed in Unit 1.
(10 CFR 50, Appendix B, Criterion 16)
o inadequate safety evaluation for ILRT testing of Unit I containment.
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1.0 Introduction During electrical inspections at various operating plants in the country, the
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NRC staff had identified several EDS deficiencies. The Special Inspection Branch of the NRC's Office of Nuclear Reactor Regulation (NRR) initiated inspections of the EDS at other operating plants, after they determined that such deficiencies could compromise design safety margins. Examples of these deficiencies included unmonitored and uncontrolled load growth on safety buses and inadequate modifications, design calculations, testing, and qualification
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of commercial-grade equipment used in safety related applications. The NRC i considered inadequate E&TS to be one cause of these deficiencies.
The objectives of this inspectior< were to assess the performance capability of the Quad Cities Station EDS and the capability and performance of the licensee's E&TS in this area. For this inspection, the EDS included all the i emergency sources of power to systems required to remain functional during and following the design basis events. EDS components reviewed included the diesel generators (DGs), 250Vdc and 125Vdc Class lE batteries, offsite circuits and switchyard, 4kV switchgear, 480Vac load centers (LCs), 480Vac and 120Vac Motor Control Centers (MCCs), 250Vdc and 125Vdc MCCs, battery chargers,
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inverters, associated buses, breakers, relays, and other miscellaneous components.
The team reviewed the adequacy of the emergency, offsite and onsite power sources for EDS equipment, the regulation of power to essential loads, protection for postulated fault currents, and coordination of the current interrupting capability of protective devices. The team also reviewed the mechanical systems that interface with the EDS, including air start, lube oil, .'
and cooling systems for the DGs. The team walked-down originally installed and as-modified EDS equipment for configuration and equipment ratings and reviewed qualification, testing, and calibration records. The team assessed the capability of the licensee's E&TS personnel concerning organization and staffing, timely and adequate. root-cause analyses for failures and recurring problems, and engineering involvement in design and operations. The team also reviewed training for Operations and E&TS personnel relative to the EDS.
The team verified conformance.with General Design Criteria (GOC) 17 and 18 and the applicable 10 CFR 50, Appendix B criteria. The team also reviewed plant technical specifications (TSs), the final safety analysis report (FSAR), and appropriate safety evaluation reports (SERs) to verify that TS requirements and licensee commitments were met.
The areas reviewed and the concerns that were identified are described in sections 2_ and 3 of this report. Conclusions are given after each of these sections. A list of the personnel contacted and those who attended the exit-meeting on May 10, 1991, is provided in Appendix A of the report.
2.0 Electrical Systems 2.1 Class lE AC Systems In order to-assess the capability of the electrical system, the team reviewed the regulation of EDS loads, the overcurrent protection, and the coordination of protective devices for compliance with regulations, design engineering i t
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standards, and accepted engineering practices. The review included system descriptions, station FSAR, equipment sizing calculations, system protection, controls and interlocks, equipment specifications, modification packages, licensee event reports (LERs), related test and operating procedures, one line i diagrams, elementary diagrams,-and equipment layout drawings. l l
The characteristics of the power system electrical grid to which the Quad l Cities Station is connected were reviewed to assess the adequacy of important parameters, such as voltage regulation, short circuit contribution, protective i relaying, surge protection and control circuits. The preferred power supply transformers were reviewed in terms of their kVA capability, their connections to the safety buses, field ins allation capability, protection, and voltage regulation. The DGs were re- ad to assess the adequacy of their kW rating, ability to start and accelera . heir assigned safety loads in the required time sequence, the voltage an: 3quency regulation under transient and steady state conditions, compliance wha single failure criteria, and the applicable separation requirements. The 4kV safety buses and their connected loads were reviewed to assess load current and short circuit current capabilities, voltage regulation, protection, adequacy of cable connections between loads and buses, compliance with single failure criteria, adequacy of bus transfer schemes _in terms of any effects on the safety systems, and applicable separation requirements. The 480Vac safety buses and their connected loads were reviewed to assess load current and short circuit current capabilities, voltage regulation, protection, adequacy of cable connections between loads and buses, compliance with single failure criteria, and applicable separation requirements.
The team also evaluated electrical design features, parameters and the configuration management program associated with electrical systems and components. The team performed a field inspection of selected systems to verify whether field installations conformed to design basis requirements and whether modifications had been properly implemented. In addition, the team performed a detailed evaluation of portions o," selected systems to confirm that they would remain functional on demand.
2.1.1 Switchyard Voltaae 2.1. 1 Dearaded Voltaae The team was concerned that the degraded voltage relays were set too low. The planc documentation reviewed was unclear as to the switchyard voltage value that was used to establish the degraded voltage relay setpoints. An April 24, 1981, submittal to the NRC established the switchyard critical voltage as being 328kV, The team calculated that the actual degraded voltage relay settings were based on a critical voltage of 325kV in lieu of the required 328kV. However, the team could not make a clear determination on this matter since the actual calculations to support the voltage studies in the submittal were not available-for review during the inspection. Pending further :nalysis by the licensee and subsequent NRC review, this item is unresolved (254/91011-01a(DRS); 265/91007-01a(DRS)).
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2.1.1,2 Calcul allani lhe team noted, during the system voltage review, that voltage " studies" were being used as supporting documentation instead of formal calculations. The
" studies" were not complete calculations that could be evaluated for technical adequacy. The following elements were not addressed:
(1) The basis for expected / assumed voltage levels.
(2) Acceptance criteria and the basis for this criteria.
(3) References for field data such as transformer tap settings and system loads.
(4) Worst case loading conditions.
(5) Calculation details including input data, methodology, and results.
(6) Minimum allowable voltage at equipment terminals.
Pending further analysis by the licensee and subsequent NRC review, this item is unresolved (254/910ll-Olb(DRb); 265/91007-Olb(DRS)).
2.1.2 Surae Protection for 4kV Busos The team questioned the adequacy of the lightning arrestors connected to the Reserve Auxiliary Transformer (RAT) to protect equipment on the 4kV safety buses fed from that transformer. Of particular concern were modes of operation where safety bus Nos. 13 and 14 are fed from the RAT. In these cases, there is a danger that a lightning surge could damage redundant equipment in both divisions. The licensee provided data which indicates that adequate protection is afforded to the RAT itself, but no analysis was available to demonstrate protection of downstream equipment. The team calculated that a maximum surge voltage of approximately 15kV could be transferred to the secondary terminals of the RAT for a single phase primary surge. This surge voltage could double to 30kV for a two-phase surge. While this voltage is below the basic impulse level (BIL) of the oil-filled safety related substation transformers, it is considerably above the withstand capabilities of the 4kV motors which are typically tested at twice rated voltage plus IkV.
The team considered this matter to be of minimal safety significance since the alignment described is not a normal one and the likelihood of experiencing a damaging surge during these periods is low. However, the team considered this a weakness in the original design of the station.
2.1.3 4kV Short Circuit Calculations The team determined that short circuit calculation Nn. 8445-00-EAD-1, dated January 31, 1990, contained the following weaknesses:
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i o Nonconservative methodologies were employed without justification, such as not including the effects of lowest load motor impedances on bus fault currents.
o Assumptions were not stated or justified, such as the effects of cable temperature on the fault current calculation.
o References for key input data were not provided, suci. as the name plate data for 250MVA breakers, o formulas were used without defining the equation variables.
o The available short circuit current was evaluated at the load equipment terminals instead of at the load breaker's output terminals.
The licensee performed supplementary calculations that demonstrated that the above factors would not have a major effect on the overall results. However, the assumptions underlying these nonconservatisms should have been clearly stated and justified in the original calculation. The team considered this concern a weakness relative to design documentation.
2.1.4 4kV Switchaear The team determined that 350MVA and 250MVA circuit breakers, including safety related breakers on bus Nos.13 and 14, in the 4kV system could experience fault currents up to 109% (overduty) of their maximum interrupting rating.
These conditions are contrary to FSAR Section 8.2.2 which states, "All protective circuit breakers are sized according to standard electrical industry practice where maximum interrupting capabilities of the circuit breakers exceed the available line to line or 3 phase short circuit current taking into account the impedances of the generator, transformers and other electrical system components." The team noted that the overduty conditions described above had been discovered by the licensee on several occasions as early as 1982 yet corrective actions had not been implemented. Failure of a 4kV breaker to function properly in response to a short circuit condition could result in h loss of the preferred power source to a safety bus. The licensee performed a safety evaluation and concluded, based on redundancy and availability of emergency power sources, that operability of ESF loads could be maintained. The team concured with the licensee's determination.
The team considered the overduty condition relative to maximum breaker interrupting ratings to be a deviation (254/910ll-02a(DRS);
265/91007-02a(DRS)) from the commitment made in FSAR Section 8.2.2.
2.1.5 Diesel Generator Loadina Calculation The team identified a number of weaknesses with calculation No. 7318-33-19-3, dated October 5,1990, in regard to the capability of the DG to meet local sequencing and total load capacity requirements. Weaknesses identified in the calculation included:
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o lack of dynamic performance analysis to demonstrate adequate DG performance during the entire range of load sequencing conditions.
The calculation provided a voltage dip analysis based on a dead load pickup curve supplied by the vendor. The curve only defines the voltage performance of the DG for a period of one second following the instant a sequenced load is applied. However, the cumulative and dynamic load effects on the DG output voltage will continue beyond one second as other loads are applied to the DG.
o The calculation did not include a frequency analysis, o The calculation attempted to demonstrate the ability of the DG to start large loads using the dead load pickup curve. This demonstration, however, was not listed as an objective of the calculation and acceptance criteria for this objective were not explicitly defined, o The calculation did not include an analysis for. starting the service water pump (SWP). In response to this concern the licensee provided a draft calculation demonstrating the ability of the DG to start the SWP based on the dead load pickup curve. The draft calculation did not <
include an analysis of the effect of the SWP start on existing loads.
o The calculation indicated that certain loads could drop out due to voltage dips during the loading sequence. However, there was no attempt to quantify the power required to restart lost loads or to assess the effect that this would have on DG performance, o The calculation did not compare the static load profile to the DG's output capacity.
It was unclear how a designated design reviewer could determine calculation acceptability since key acceptance criteria of the calculation and DG loading capability criteria were not stated in the body of the calculation and could not be found in the references stated in the calculation. Pending further analysis by the licensee and subsequent NRC review, this item is unresolved (254/91011-03(DRS);265/91007-03(DRS)).
2.1.6 DG Parallel Operation with the Grid Durina DG Testina The team noted that in order to meet TS requirements for DG testing, the DGs are paralleled with the offsite power system. The team reviewed the generator protection scheme and observed that during DG parallel operation, the DGs could be overloaded. In the event.of a LOCA followed by a loss of offsite ,
power (LOOP), the degraded voltage relays on the associated vitc1 bus would not sense loss of voltage from the offsite power source and load shed (trip)
the necessary circuit breakers. As a result, the DG would be subjected to a sudden overload as the DG attempted to pickup the' loads previously scpplied by offsite power. This condition could damage the DG or trip the DG output breaker. 'The team recognized the low probability of a grid collapse during monthly DG testing. However, the team considered this condition tc be a generic design weakness. Pending further NRC review, this item is con.tidered
.open (254/910ll-04(DRS); 265/91007-04(DRS)).
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2.1.7 Diesel Generator loss of Field Relays The team noted that the DG loss of field relays were installed in a manner that was not consistent with the manufacturer's instructions (General Eler.tric Instruction Manual GEK 27887F). Contrary to the GE instructions, the CEh relays were not fused separately from other potential transformer (PT) loads.
As installed, a blown fuse in one phase of the P1 could result in maloperation of the relay. This could result in damage to the DG and/or connected ESF loads. The licensee demonstrated that the relays are disabled during emergency operation and that maloperation of the relays during testing would result in erratic readings on DG instruments which would be noticed by the operators. Consequently, the likelihood of undetected damage to the DG or ESF l loads was considered to be remote. . The team concurred with the licensee's position. However, the team considered this a weakness relative to the design of the DG protection scheme.
2.1.8 Procedures for Transferrina to Offsite Power The team's review indicated that during a loss of offsite power when the DGs are automatically started and connected to the safety buses, a ground fault on either bus or the associated ESF loads may not be properly annunciated. The annunciation would indicate a DG fault even though the actual fault location could be one of the vital buses or an ESF load. The DG is grounded through a high resistance ground fault circuit. This fault current would be sufficient j to initiate the control room annunciator but would not result in ESF equipment trips. Should offsite power be restored, an operator may attempt a retransfer to the preferred source. However, the transformer supplying offsite power is grounded through a low resistance circuit. The transfer to offsite power would cause a sharp increase in allowable ground fault current; consequently, faulted loads transferred to offsite power could trip on overcurrent. Current procedures do not alert operators to the possible loss of a load, due to a ground fault, when transferring from the DGs to offsite power. The licensee committed to review procedures relative to this condition and make appropriate revisions. The team had no further concerns on this item.
.2.1.9 Cable Amnacity The team was unable to determine whether cables were properly sized to provide sufficient ampacity. The licensee stated that cable sizing was established using various architect engineer (AE) standards. The AE standards were based on industry standards; however, the particular industry standards used to develop the AE standards were not identified. As a result, the team could not effectively evaluate cable sizing and cable fill requirements. Pending further analysis by the licensee and subsequent NRC review, this item is i unresolved (254/910ll-05(DRS); 265/91007-05(DRS)).
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2.1.10 DG Instrument Calibration Proaram The team identified that the DG day tank level instruments were not in the station instrument calibration program, in addition, instrument and setpoint tolerances were not specified for any of the instruments on the DGs, diesel fuel oil storage tanks, diesel fuel oil day tanks, or the air receiver tanks.
The licensee considered these non-TS instruments to be non-safety related. In response to the team's concern, the licensee verified the above level switch settings during the EDSFI. The day tank level switch as-found values were found to be conservative. The licensee indicated that these instruments will be included in the licensee's ongoing program to evaluate and upgrade the classification of DG instrumentation, scheduled to be completed by January 1992. The licensee also indicated that the day tank level switches will be added to the Quad Cities Generating Station Surveillance Program.
The team reviewed the following non-safety related DG instrument calibration data sheets and identified several instruments which were left out of calibration (> 2%). Examples included:
Calibration As left Instrument Tolerance Value PI-2-5241-1 30" i0.9" Hg Vac 28" Hg Vac TI-1/2-3941-68A 244 5'F 250*F TI-1/2-3941-68B 77 5'F 64*F TI-1/2-3941-69B 244 5'F 250*F LS-1-5241-17 66.67 INWC 1.0" - 0" 59.0 INWC The out of tolerance values were not evaluated by instrument maintenance or engineering personnel. The licensee indicated that level switch LS-1-5241-17 was actually left at 66 INWC, but the technician incorrectly entered the value as 59 INWC. -The team concluded that the out of tolerance instruments did not affect DG operability. The team noted~that the instrument data sheets for all the DG instruments did not include calibration tolerances. The licensee issued memorandum No. 13, on April 8, 1991, to all instrument maintenance personnel specifying the instrument tolerances for all non-safety related instruments in the station. The team concluded that the non-safety related calibration program was a weakness.
2.1.11 Station Procedures The team identified the following EDS procedural weaknesses:
o Procedure No. Q0S 6600-SI, " Monthly Diesel Generator and System Operability Test Data Sheet," Revision 14, provided no guidance to the operator regarding actions to be taken when DG cylinder exhaust temperatures exceeded the allowed value. The licensee indicated they would incorporate appropriate procedure steps on who to notify when
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quantitative data was exceeded.
o Station Procedure No. QEPH 500-1-SI, 'ESS UPS Preventive Maintenance Inspection Data Sheets," Revision 2, did not specify capacitance values and applicable tolerances. The licensee indicated that this procedure will be revised to include applicable criteria.
The licensee stated that a procedure upgrade project was underway. The team noted that approximately 8% of a total of 4395 station procedures had been upgraded.
2.1.12 Inspection of Safety Related 250Vdc_ and 480Vitc MCCs The team noted the following deficiencies during the field inspection of safety related 250Vdc MCC No. lA and 480Vac MCC Nos. 14-2 and 19-2:
o Excessive dirt and dust inside the MCC cubicles.
o Excessive copper oxide and pitted contacts on several 250Vdc main contactors contacts.
o Broken terminal blocks in varinus cubicles and as-built discrepancies.
The licensee promptly initiated corrective actions to address the deficiencies noted above. However, further review by the team revealed that the licensee has not established a preventive maintenance program to periodically inspect, clean, snd lubricate Units 1 and 2 250Vdc and some 480Vac safety related MCCs.
The NRC resident inspectors intend to incorporate this issue into their inspection activities. The team considered this item to be a program weakness.
2.1.13 Cable Tray Seoaration The team identified that cable tray Nos. 405B (ESSil) and 439B (ESSI) located in Unit I auxiliary equipment room were connected by a short section of common balance of plant (BOP) cable tray. The licensee stated that a total of 427 cables were routed in six such configurations in both Units 1 and 2. The
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licensee's evaluation indicated all of the cables routed in these trays were installed in accordance with the Quad Cities original routing criteria which did not address B0P cables. It was the licensee's position that B0P cables could be routed in any divisional tray including crossing from one division to another. Review of the cables routed in the B0P sections connecting the ESSI and ESSII trays revealed that some of the cables were erroneously designated as divisional cables but had a non-safety function. The licensee stated that DCRs will be issued to correct the errors in segregation codes of the 80P l
cables. Based on the above criteria, the team did not identify any separation criteria errors that would appear to have deviated from the station's original design. basis. The team considered cable separation practices used at Quad l
Cities to be a weakness.
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2.1.14 Thermal Overload Heaters During field inspections, the team noted several discrepancies between the design drawings and installed thermal overloads (TO). The team determined that many of the T0 discrepancies were due to a lack of design basis documentation and engineering sizing calculation data. The team noted that original sizing calculations for safety related T0s were not available for review for approximately 43 of 174 safety related applications. The team also noted that the Component Failure Analysis Report (CFAR), issued during the last quarter of 1990, identified both Quad Cities units as having significantly high 10 failure rates. The majority of the reported failures have been attributed to under and oversized 10 heaters. The licensee co.wnttted to complete thermal overload sizing calculations for accessible i safety related motors by July 1,1991. For non-accessible safety related !
motors, sizing calculations will be completed within the next fuel cycle. The 1 team considered this as another example of the lack of design basis information. )
j 2.1.15 Fuse Control Problems
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The team observed that fuse Nos. 6 and 10, installed in primary containment 1 isolation (PCI) panel No. 90. 40, were rated 6A and 5A respectively, instead of the 5A and 1A specified in design drawing No. 4E-1764A. Also, fuse Nos. 6, 9, and 13 installed in PCI panel 901-41 were rated 4A, 5A, and 6A respectively, inrtead of the 5A, lA, and 5A specified on design drawing No.
4E-1764B. In addition, the team noted that several fuse types specified on the design documents did not conform with the fuse types installed in PCI panel No. 901-41. The incorrectly installed fuses did not affect equipment operability.
The licensea had previously identified fuse installation discrepancies and has initiate ( t fuse walkdown to identify similar discrepancies. Also, a fuse list and a procedure to control and maintain fuses were being developed.
Pending NRC review of the licensee's actions to replace the incorrect fuses l' and establish an effective fuse control program, this item is considered open (50-254/910ll-06(DRS); 50-265/91007-06(DRS)).
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2.1.16 Confiauration Control (As-Built) Evaluation /Insoection 2.1.16.1 Drawino Review The team identified the following concerns during the as-built drawing review:
o Cable Nos.15153 and 18125 were shown on current electrical drawings even though these cables had been removed from the field during implementation of past modifications.
o Installed circuit breaker ratings differed from design drawings in 480Vac MCC No. 19-1 cubicles B1, B5 and E3; 480Vac MCC No. 18-2 cubicles l F1, F2, F3, F4, G2, G3, and G5; 480Vac MCC No. 19-2 cubicles El, E2, E3, i
E4, F2, F3, F4, and F5; and 120/240 Vac ESS distribution panel and
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instrument bus panel No. 901-49 circuit Nos. 32 and 33.
o 120/240 Vac ESS distribution panel and instrument bus panel No. 901-49 circuit breaker Nos. 27, 29, and 31 were mislabled as Nos. 25, 27, 29, respectively.
o HPCI valve, M0 2301-9, limit switch contact (7-7C) was shown connected on schematic diagram No. 4E-1529, Sheet 3, and wiring diagram No. 4E-1648C even though the limit switch was never installed in the field.
This coatact was also shown on the Control Room Critical Drawing which reflects the as built plant cendition, o Motor power le.ds Al and A2 were shown reversed on the drawings for 250Vdc MCC No. lA cubiclas F02, G01, H02, and 101.
o Critical control room drawing No. 4E-2318B did not show the Unit 2 125Vdc auxiliary battery and the Unit 1 125Vdc auxiliary battery was not labeled.
Pending further analysis by the licensee and subsequent NRC review, this item is considered open (254/910ll-07a(DRS); 265/91007-07a(DRS)).
2.1.16.2 Field insoectioas The team identified the following concerns during the field inspection:
o The licensee had revised the schematic and wiring diagrams to include proposed plant modifications that had not been installed in the field (referred to by the licensee as " chaining" methodology). As a result, the existing electrical drawings did not reflect the field installations (as-built). The licensee informed the team that prior to performing any activity on the EDS, a field wiring verification was required by procedures.
o- The interim document information system (IDIS) data for drawing N0. 4E-1764A contained numerous errors. It was difficult-to determine the as-built condition / status of the documents posted against the drawing using 1015. 1he team was concerned that data errors may exist throughout IDIS.
Pending further analysis by the licensee and subsequent NRC review, this item is considered open (254/910ll-07b(DRS); 265/91007-07b(DRS)). ;
2.1.17 Failure of GE CR120A Relays The team identified that CR120A relays were failing due to a higher than rated voltage applied to the relay coils. Further investigation revealed that the licensee had identified the CR120A relay problem in May 1980, and initiated action item record (AIR) No. 4-80-14 to investigate the high rate of failure of these relays in safety related panel Nos. 901(2)-40 and 901(2)-41, in October 1981, station nuclear engineering department (SNED) completed their review of the subject AIR and recommended replacement of the CR120A relays
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with GE CR1208 relays. In february 1989 BWR engineering recommended replacing all CR120A 115Vac relay coils with 120Vac coils. In March 1990, 50 Unit 2 relay coils were replaced. The team noted that during the last Unit 1 outage (ending April 1991), only five of the fifty Unit 1 CR120A relay coils had been replaced. The licensee intends to replace the remaining 45 coils during the next refueling outage.
Failure to promptly correct identified deficiencies associated with safety related components (CR120A relay) is considered a violation of 10 CfR 50, Appendix B, Criterion XVI (254/910ll 08(DRS)). J 2.1.18 Conclusion l The team did not identify any condition which would indicate that the safety related AC distribution system would be unable to perform its safety function. ,
Significant colculation weaknesses were observed in the AC system voltage and DG supporting documentation, and in the design information for thermal overload and breaker sizes / ratings. Weaknesses were also identified in recent calculations. Programmatic weaknesses were identified in the non-IS calibration program, in-the areas of as-built and configuration control, the installation of under/over sized fuses and the fuse control program, lack of a comprehensive maintenance program for safety related MCCs, lack of concise criteria for cable separation, and the timely resolution of industry identified component failures.
2.2 RC Systems
The team reviewed the station DC systems, 120Vac inverters and electrical containment penetrations for design compliance to applicable standards and codes. The inspection included the review of the 24Vde, 125Vdc and 250Vdc battery design with respect to sizing, duty cycle loading, electrolyte temperature, battery age and capacity. The associated charger designs were reviewed for total loading requirements and the bases of these calculations were checked for their adequacy. The inverters' sizing and design criteria were reviewed for their ability to meet applicable standards and power l input / output requirements. Fault study calculations for the f24Vde, 125Vdc
, and 250Vdc were reviewed relative to system parameters and requirements,
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cptlicable standards, correctness, accuracy and standard engineering practices. Voltage drop studies and cable sizing calculations for the i24Vdt, 125Vde, 250Vde, and 120Vac were reviewed relative to system parameters and requirements, applicable standards, correctness, accuracy and standard engineering practices. A review of breaker / fuse coordiration and sizing was -
performed to determine if protection schemes for the DC systems conformed to standards and practices used for station design. The team also reviewed the electrical penetration design against standards applicable during statinn design and construction.
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2.2.1 250Vdc Coordination Study
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The team identified the following issues:
o Sargent and Lundy (S&L) study SL-4501, vol. 4, "Overcurrent Protective Device Coordination Study," did not include motor and cable damage curves relative to the coordination curves. As a result, breaker / fuse protection for the motors and cables could not be evaluated. The team considered this a design weakness.
o The S&L study identified numerous overduty circuit breakers. The licensee is developing a generic replacement program for the overduty breakers. Ilowever, the team considered the overduty condition (up to 180%) relative to maximum breaker interrupting ratings to be a second example of deviation (254/91011-02b(DRS); 265/91007-02b(DRS)) from the commitment made in FSAR Section 8.2.2 (see Section Nu. 2.1.4 of this report).
o The S&L study identified numerous miscoordinated circuit breakers. The team reviewed the miscoordination examples, which exist in both electrical divisions, and did not identify any common failure modes.
Pending further NRC review, this item is unresolved (254/910ll-09a(DRS);
265/91007-09a(DRS)).
2.2.2 125Vdc Coordination St'tdy The team is concennod with the following issues:
o S&L study SL 4501, vol. 3, "Overcurrent Protective Device Coordination Study " identified that the current contribution from a higher than normal battery electrolyte temperature, and the short circuit contribution from the chargers had the potential to exceed equipment current ratings. Also, the S&L study did not include cable damage curves. The team considered this a design weakness, o The S&L study identified numerous miscoordinated circuit breakers. The licensee planned to perform further breaker / fuse coordination evaluations. Pending further NRC review, this item is unresolved (254/91011-09b(DRS);265/91007-09b(DRS)).
2.2.3 125Vdc Battery Main Fuse
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l The team determined that no fuse or circuit breaker was provided to protect l the 125V battery and the main distribution bus from short circuits. A
! catastrophic failure of the battery may occur if a fault is not rer ad from the battery within 100 msecs. During a walkdown of the main bus panel, an 8"
adjustable wrench was found laying approximately one foot away from the uninsulated bus. The licensee immediately removed the wrench. The team considered this item to be a design weakness.
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2.2.4 120Vac System The team determined that calculations for IE0Vac system voltage drop, short circuit current and coordination studies were not available. The lack of design basis information was considered a weakness. To address this concern t the licensee performed calculation No. 8827-80-79-0. The team's subsequent
, review identified the following weaknesses:
o The calculation did not provide any acceptance criteria for the load voltage drop results, o Miscoordination between the ESS bus main breaker at panel No. 901-49 and feeder breaker Nos. 28 and 33 for faults between 2100 and 3333 amperes.
Pending further NRC review, this item is unresolved (254/910ll-09c(ORS);
265/91007-09c(DRS)).
. 2.2.5 Electrical Penetrations The team determined that no information cy:isted to verify that the Quad Cities Station electrical penetrations met the intent of Regulatory Guide 1.63. NRC letter dated November 30,-1981 to Commonwealth Edison Company, indicated that Dresden 2 (a sister plant) was meeting the intent of these requirements. This is an open item (254/9101-10(DRS); 265/91007-10(DRS)), pending NRC follow up on the licensee's determination that the Quad Cities Station penetrations are similar to the Dresden 2 penetrations.
2.2.6 Conclusions The team did not identify any conditions which would indicate the safety related DC distribution systems and 120Vac system would be unable to perform their safety function. Design attributes of the DC systems were for the most part retrievable and verifiable. However, more attention is needed in the areas of equipment ratings, breaker / fuse coordination, and in the review of engineering analyses.
2.3 Hechanical Systems The team reviewed and evaluated the adequacy of the mechanical system design for the support of the EDS. The support mechanical systems (SMS) include the DGs, and DG support systems. The review included a system walkdown and examination of SMS licensing, engineering, vendor, purchasing, and plant operations documents including the FSAR and TSs; selected modifications and
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safety evaluations; mechanical system calculations; process and instrumentationdiagrams(P&lD);pumpperformancecurvesandmotordata sheets; DG manufacturer technical manuals, selected schematics, and detailed component drawings; procurement specifications for the DG; and operations manuals and procedures'.
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2.3.1 Diesel Generator fuel Q11 Systems 2.3.1.1 DG Fuel Storace Capacity The team found several deficiencies in design documentation associated with the capacity of the fuel oil system:
o No documented fuel consumption tests existed for the Quad Cities DGs.
o The fuel consumption rate calculations did not consider reduced fuel availability to the DGs as a result of fuel consumption by the diesel driven fire pumps.
o Possible impact of transfer pump suction limitations on effective available volume of the storage tanks was not considered, such as vortex considerations and transfer pump suction head requirements.
o The calculation did not address the impact of storage tank orientation (i.e., tanks are installed with a slope along longitudinal axis) on the accuracy of level instrumentation.
o The calculation did not address differences between fuel consumption test conditions and actual operating which could affect fuel storage volume requirements.
The team concluded that_the design documentation deficiencies did not constitute an immediate operability concern since the licensee administratively maintains a much higher level of fuel oil in the fuel oil storage tanks. Pending further analysis by the licensee and subsequent NRC
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review, this item is considered open (254/910ll-ll(DRS); 265/91007-Il(DRS)).
l 2.3.1.2 Seismic Oualification of DG Fuel System Components The team found that portions of the Unit 1, 2, and 1/2 fuel oil system upstream of the day tanks (i.e., storage tanks, piping, and transfer pumps)
were originally classified as non-safety, non-seismic. Consequently, the transfer pumps and'the transfer piping were not seismically qualified, and the
' storage tanks were originally qualified only to a 0.059 requirement specified '
in a general purchase specification. The current Quad Cities station safe shutdown earthquake (SSE) is 0.29s. The team requested that the licensee perform an operability determination for the system. The licensee declared the system operable based on the following:
- o An evaluation of the original equipment and piping by the licensee's seismic specialist. Several equipment items were covered by the Seismic Qualification-Utilities Group (SQUG), Generic implementation Procedure (GIP) data' base; others, particularly the original fuel storage tanks, were not covered by the data base, but, based on the professional opinion of the specialist, were deemed not to constitute an immediate operability concern.
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o implementation of new procedures that provide steps for manual filling of the DG day tank.
The team had no immediate system operability concerns. However, since formal design documentation was not available, pending further review by the NRC, this item is unresolved (254/910ll-12a(DRS); 265/91007-12a(DRS)).
2.3.2 DG Startino Air System The licensee was unable to provide decumentation to support the seismic qualification for the DG air start system supplied with the DGs. This portion of the system includes the air accumulators, accumulator relief valves, and associated piping and valves. The lack of documented qualification raised concerns about the possibility of a common mode failure wherein a seismic event could result in a depressurization of the primary and backup air accumulators for all DGs. The team requested the licensee to perform an operability determination for the system. The licensee subsequently declared the system operable based on the following:
o An evaluation of the equipment design by the licensee's seismic specialist; many equipment items were covered by the Seismic Qualification Utilities Group (SQUG) and Generic Implementation Procedure (GIP) data base, o Information obtained from the DG system supplier, o Information obtained from the manufacturer of the relief valves.
o An acumulator tank design analysis verification.
The team reviewed the above supporting documentation which subsequently demonstrated that seismicity was part of the air start system design criteria.
However, the team concluded that when the plant initiates its seismic upgrade review program for the fuel oil system, that the air start system should be included in this review. The team has no further concerns on this item at this time.
2.3.3 Bus Ducts in Diesel Generator Rooms The team determined that the DG electrical output bus ducts may not be seismically qualified. A seismic event could cause a common mode failure of all three DGs as a result of a bus duct failure. The licensee immediately-initiated actions to determine the seismicity of the bus ducts by performing a SQUG type walkdown. The walkdown indicated that the bus ducts should be able to withstand a seismic event.
The team had no immediate system operability concerns. However, since f ormal design documentation was not available to support the design, pending further review by the' NRC, this item is unresolved (254/910ll-l?h(DRS); 265/91007-12b(DRS)).
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2.3.4 Conclusions
The team concluded that even though seismic documentation was missing, the ,
licensee had provided operability determinations based on SQUG walkdowns that i indicated the mechanical systems should withstand a seismic event and remain operable. The team did not determine if any of the DG mechanical systems would fail to operate during a seismic event.
3.0 Enaineerina and Technical Support
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During the inspection, the team evaluated Commonwealth Edison's E&TS capability at the Quad Cities station. The team reviewed the licensee's temporary modifications (temporary alteration) program, the station's permanent modification program,10 CFR 50.59 evaluation program, root cause analysis for deviations and licensee event reports (LERs), and QA/QC program.
In addition, the team reviewed the technical service orientation (150) and system engineer training program for the entry level engineers.
3.1 Trainina Proaras!1 The team noted that the system engineer training program for the entry level engineers was not as formal and detailed as the TSO program. The TSO program consisted of several training courses such as: steam and mechanical
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fundamentals, electrical fundamentals, BWR system and simulator training.- ,
, Differences were found in the amount of training an entry level engineer received before becoming the responsible system engineer. In one instance, the HVAC system engineer received nine months of training on the system before turnover; however, the individual had not completed the TSO program. Another ,
system engineer had completed the TSO program but received only two and a half weeks of system engineer training before becoming the system engineer responsible-for the RHR/ core spray system.
The team concluded that station supervision should closely monitor any work performed by new individuals who received a limited amount of training. It was also noted that a detailed system engineer training program was in draft form at the end of the inspection.
3.2 10 CFR 50.59 Evaluations The team determined that an inadequate 10 CFR 50.59 evaluation had been performed for temporary modification No. M-4-75-71. The modification connected two 600 HP motor-driven air compressors to Unit 2 4kV safety bus No.
23 during containment integrated leak rate testing (ILRT). The current safety evaluation covered the use of the compressors for testing Unit 2 containment while the unit was in a refueling mode. The licensee did not have a safety evaluation for ILRT testing Unit 1 in this configuration. On February 18,
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1991,- the compressors were connected to bus No. 23 for ILRT testing of the Unit I containment while Unit 2 was at 100% power. Per deviation report No.
'04-02-91-022, a destructive failure of the local 4kV compressor breaker ,
resulted in a voltage drop on the safety related system prior to the trip of l the Bus 23 breaker feeding the compressors. Numerous alarms and a half l reactor scram occurred.
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Failure of the licensee to include in the original safety evaluation an analysis for testing Unit I with Unit 2 at 100% power is a violation of 10 CFR 50.59, (254/910ll-13(DRS).
The licensee committed to not use the ILRT compressors in the future without
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performing an adequate technical Ond safety evaluation.
3.3 Doerational Document Control The team noted that the DCR coversheet for DCR No.91-062, dated March 22, 1991, indicated that all copies of the affected drawing were marked as
" Drawing Change in Progress." However, drawing No. M-325, Revision C, (sheet 9) in the document control center was not marked as such. The licensee initiated a change to Quality Procedure No. QP 6-52, " Document Control for Operations - Distribution and Control of Engineering Documents and Document Change Control," to specify that all holders of DCR affected drawings be notified that drawing changes are in progress. The licensee also indicated that the drawing lists will be revised to properly identify the drawing changes. The team had no further concerns on this item.
3.4 Lonclusions The team concluded that the engineering staff that supported the team was very knowledgeable and competent. In addition, the team found that, in general, the licensee provided adequate technical rupport to the operational staff.
However, the team was concerned with the quality of engineering support documentation that was available to support the corporate engineering and station engineering staff. As described in previous sections, the team identified the absence of calculations that are typically reviewed during an EDSFl. In addition, many of the calculations that were available contained many weaknesses and calculation nonconservatisms. As a result, the team considered the sparsity of design basis information to be an engineering weakness in the E&TS area.
4.0 Open itemg Open items are matters which have been discussed with the licensee, which will be reviewed further by the team, and which involve some action on the part of the NRC or licensee or both. Open items disclosed during this inspection are discussed in Paragraph Nos. 2.1.6, 2.1.15, 2.1.16.1, 2.1.16.2, 2.2.5, and 2.3.1.1.
5.0 Unresolved itemi Unresolved items are matters about which more information is required in order to ascertain whether they are acceptable items, violations, or deviations.
Unresolved items disclosed during this inspection are included in Paragraph Nos. 2.1.1.1, 2.1.1.2, 2.1.5, 2.1.9, 2.2.1, 2.2.2, 2.2.4, 2.3.1.2, and 2.3.3.
The following unresolved items do not require a licensee response at this time: Paragraph Nos. 2.2.1, 2.2.2, 2.2.4, ?.3.1.2, and 2.3.3.
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6.0 Exit Interview i
The team conducted an exit meeting on May 10, 1991, at Quad Cities Station to discuss the major areas reviewed during the inspection, the weaknesses observed, and the inspection findings. NRC personnel and licensee representatives who attended this meeting are documented in Appendix A of this report. The team also acknowledged commitments made during the inspection.
The licensee did not identify any documents or processes as proprietary.
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APPENDIX A Gmmonwealth Edison Qgeny (CECol
- C, Baldwin, Technical Staff
- P. Barnes, Nuclear Licensing, Compliance Supervisor
- R. Bax, Manager, Station
- K. Brohm, Technical Staff
- J. Brunner, Technical Staff Support, Superintendent
- R. Charneski, Technical Staff
- D. Craddick, Maintenance, Assistant Superintendent
- C. Edmondson, Mechanical Maintenance
- D. Elias, Manager, safety Assessment
- B. Fancher, Design Supervision
- T. Fuhs, Regulatory Assurance
- C, Grier, Nuclear Engineer, BWRSD
- R. Hamann, Technical Staff
- J. Hoeller, Training Supervisor
- A. Janikowski, Senior Engineer
- M. Jones, QC Inspector
- N. Kalivianakis, General Manager, BWR Operations
- D. Kanakares, Regulatory Assurance
- J. Kopacz, Operating Engineer
- S. Laughlin, Technical Staff
- J. Leider, Performance Assessment
- D. Luebbe, Technical Staff
- E. Mendenhall, Field Engineer, BWRSD
- T. O'Brien, Principle Engineer
- H. Pacilio, Master Electrician
- C. Richardson, Instrumentation Analysis
- l. Riveria, Technical Staff
- R. Robey, Technical, Superintendent
- T. Rushing, Technical Staff
- C. Sepantak, Technical Staff
- J. Sirovy, Services Director
- C. Smith, Nuclear Quality Programs, Superintendent
- G. Spedl, Production, Superintendent
- B. Strub, System Engineer, Supervisor
- T. Tamlyn, Manager, Site Production
- H. Tucker, Senior Engineer
- K. Uhlir, Senior Engineer
- G. Wagner, Manager, Nuclear Engineering
- J. Werner, Regulatory Assurance
- D. Wengerter, Lead 0AD Engineer
- J. Wethington, Technical Staff, Assistant supervisor
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- 4 APPENDIX A 2 Contractors
- J. Bednarczyk, Sargent and Lundy
- B. Kulieke, Johnson Engineering and Technical Services U.S. Nuclear Reaulatory Commission (NRCl
- H. Miller, Director, Division of Reactor Safety
- M. Ring, Branch Chief, Division of Reactor Safety
- R. Gardner, Chief, Plant Systems Section
- D. Norkin, Chief, Special Inspections Branch
- T. Taylor, Senior Resident
- R. Bocanegra, Resident inspector
- J. Shine, Resident inspector
- Denotes those attending the exit meeting on M3y 10, 1991.
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