IR 05000346/1997201
| ML20216K016 | |
| Person / Time | |
|---|---|
| Site: | Davis Besse  |
| Issue date: | 09/04/1997 |
| From: | NRC (Affiliation Not Assigned) |
| To: | |
| Shared Package | |
| ML20216K011 | List: |
| References | |
| 50-346-97-201, NUDOCS 9709180174 | |
| Download: ML20216K016 (36) | |
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U.S. NUCLEAR REGULATORY COMMISSION
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OFFICE OF NUCLEAR REACTOR REGULATION i
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Docket No.: 50-346 License No! NPF-3 l
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i Report No.: 50-346/97-201 Licensee: Toledo Edison Company facility: Davis-Besse Nuclear Power Station !
Location: Oak Harbor, OH
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Date: May 5-9, May 19-23, and June 9-20, 1997
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inspectors: S.K. Malur, Team Leader, Special Inspection Branch A. Bizzara, Contractor *
R. Jason, Contractor *
L. Rogers, Contractor *
M. Sanwarwalla, Contractor *
, K. Steele, Contractor *
(* Contractors from Sargent and Lundy)
Approved by: Donald P. Norkin, Chief Special Inspection Section Special. Inspection Branch Division of Inspection and Support Programs Office of Nuciear Reactor Regulation
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TABLE OF CONTENTS
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1-E Conduct of Engineering . . . . . . . . . . . . . . . . . . . . . . ,
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E Inspection Scope and Methodology . . . . . . . . . . . . . 1 El.2 High Pressure injection System . . . . . . . . . . . -. . - . . 1 El.2.l' System Description and Safety functions . . . . . . . . 1 El.2.2 Mechanical Design Review . . . . . . . . . . . . - . . . 2 El.2.3 Electrical Design Review . . . . . . . . . . . . . . . 8 El.2.4 Instrumentation and Control Design Review . . . . . . . 11 El.2.5 System Interfaces . . . . . . . . . . . . . . . . . . . 13 El.2.6 HPI System Walkdown . . . . . . . . . . . . . . . . . . 13 El.2.7 Updated Safety Analysis Report . . . . . . . . . . . . 15
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Cl.3 Decay Heat Removal 3ystem . . . . . . . . . . . . . . . , . . 16 El.3.1 System Description-and Safety functions . . . . . . . . 16 El.3.2 Mechanical Design Review . . . . . . . . . . . . . . . 17
- El.3.3 Electrical Design Review . . . . . . . . . . . . . . . 21 El.3.4 Instrumentation and Control Design Review . . . . . . . 21 El.3.5 LPI System Walkdown . . . . . . . . . . . . . . . . . . 24 X1 Exit Meeting ............................ 27
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APPENDIX A Open items . . . . . . . . . . . . . . . . . . . . . . . . . . A-1 APPENDIX B Exit Meeting Attendees . . . . . . . . . . . . . . . . . . . . B-1 APPENDIX C li st o f Ac ronyms . . . . . . . . . . . . . . . . . . . . . . . C- 1
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EXECUTIVE SUMMARY A design inspection at Davis-Besse Nuclear Power Station was performed by the Special Inspection Branch of the Office of Nuclear Reactor Regulation (NRR)
during the period April 14, 1997 through June 20, 1997 including on-site inspections during May 5-9, May 19-23, and June 9-20, 1997. The inspection team consisted of a team leader from NRR and five contractors from Sargent and Lundy Corporatio The team selected for inspection the high pressure injection (HPI) system and the low pressure injection (LPI) functions of the decay heat removal system (OHRS). The purpose of the inspection was to evaluate the capability of the systems to perform safety functions required by their design bases, the adherence to the design and licensing bases, and the consistency of the as-built configuration with the updated safety analysis report (USAR). The engineering design and configuration control section of inspection procedure IP 93801 was followed for this inspectio The team reviewed relevant portions of the USAR, the system descriptions, and selected calculations, drawings, modification packages, surveillance procedures, and other associated plant document The HPI system and the LPI functions of the DHRS have been designed to provide the required injection flow assumed in the analyses for design basis accidents. The system designs provided for sufficient net positive suction head for the HP! and LPI pumps during the injection and recirculation modes of operation. The acceptance criteria for periodic testing of the system pumps and valves and the test results were, in general, acceptable. Except for minor discrepancies, calculations that supported the design used appropriate methodology, produced reasonable results, and were consistent with the design bases. The essential power supplies for both the systems were adequate to support the system functions. The instrumentation and control designs were adequate and the instrument setpoints were conservativ Locally mounted pressure gages Pl 1519 and 1520 were installed in the HPI system with one normally open manual safety class isolation valve in each seismically supported sensing line from the system piping. Because the pressure gage was not seismically qualified, the team questioned the acceptability of a normally open valve as the boundary between safety class 2 piping and the aressure gage although the gage was seismically supporte This issue has acen referred to the NRR staff for further evaluatio The team's review of electrical components in the ECCS rooms that are powered from the Class IE bus indicated that some safety-related electrical components, such as sump pump motors, sump level switches, associated hand switches, and electrical boxes were not environmentally qualified. These components are required to operate under harsh environmental condition The licensee evaluated these components and concluded that there was no operability concern, and issued a potential condition adverse to quality report (PCAQR) to address this issu i
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The team identified weaknesses in battery charger capability testing because !
the testing did not fully comply with the intent of the commitment in the USAR i and questioned the lack of testing of some features of inverters and '
associated component During the inspection, the licensee initiated PCAQR 97-0529, and identified f that reverse flow of check valves DH81 and DH82 on the two LPl pump suction lines from the BWST and leakage rate through stop check valves HP31 and HP32 '
on the HPI pump recirculation lines were not being teste Leakage of post-
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accident containment sump water through check valves DH81 and DH82 in conjunction with either leakage through the BWST isolation valves DH7A or i DH78, or failure of the isolation valves to close could result in increased off-site dose. The licensee initiated actions to test the valves and to revise the inservice testing program documentation to include such testin The team noted that the supports and hardware for borated water sto. age tank (BWST) level transmitters in the valve pit and the shed next to the BWST were i severely rusted. The team was concerned that structural integrity of the transmitter supports could be degraded. Although the licensee had identified the deterioration of the support hardware in 1994, no action was taken to ,
remove, examine, and replace the hardware. The licensee issued work u ders to
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repair the supports for all level transmitters.
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Calculations that support the design basis are not explicitly identified as such, and other calculations that do not su) port the current design bases were not archived, superseded, or identified as listorical information. The team .
- was concerned that data from the calculations that are not part of the design basis could inadvertently be used for future design changes or as input to operational decision Other issues identified by the team included USAR discrepancies, and inconsistencies in instrument setpoint values in different document The licensee initiated appropriate measures to resolve the team's concern Notwithstanding the weaknesses described above, the team concluded that the HPI and LPI systems were capable of performing their safety functions required by their design bases, adhered to the licensing bases, and were consistent
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with the commitments in the USAR.
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E Conduct of Engineering E Insoection Scone and Methodoloav The purpose of this inspection was to evaluate the capability of the selected systems to perform safety functions required by their design basis, adherence to the design and licensing basis, and consistency of the as-built
. The systems configuration with the were selected for inspection updated safety the High anglysisinjection Pressure report (USAR)I)
(HP system and the
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Low Pressure injection (LPI) functions of the Decay Heat Removal COHR) syste These systems were selected on the basis of their importance in m<tigating design basis accidents at Davis-Bess The inspection was performed in accordance with NRC Inspection Procedure 93801, " Safety System functional Inspection." The engineering design and ,
configuration control section of the procedure was the primary focus of the inspectio The open items resulting from this inspection are included in Appendix The acronyms used in this report are listed in Appendix El.2 Hiah Pressure in.iection System
, El. System Description and Safety functions As a part of the emergency core cooling system (ECCS), the HPI system is relied upon to mitigate the effects of small break lots-of-coolant-accidents (SBLOCA) and main steam line break / main feedwater line break (MSLB/MFWLB)
accidents. The HPI system injects borated water into the cold leg piping of the reactor coolant system (RCS). The system is actuated by the safety
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features actuation system (SfAS) on low RCS pressure or high containment pressur The HPI system performs its safety functions by providing: cooling water for emergency core cooling; make-up for reactor coolant contraction due to excessive cooling of the RCS; borated water to decrease reactivity; and containment isolation capability for the lines penetrating containmen The HPI system consists of two sedundant trains and each train has a pump capable of providing 100% of the design HPI flow to the RCS. Each train takes suction from the borated water storage tank (BWST) and injects cooling water to the RCS cold leg piping near two reactor inlet nozzles. Technical specification (TS) 3,5.4.a specifies an available borated water volume of between 482,788 and 550,000 gallons in the BWST. After the BWST is desleted, if HPI injection is still required because of high reactor pressure, tie HPl pumps are supplied with containment sump wahr by remote manually opening the valves in the crosstie line between the discharge of the DHR pumps to the suction of the HPI pumps. This operation is known as the " piggy-back" mod A normally open minimum flow recirculation line from the discharge of each HPI pump to the BWST is provided to prevent damage to the pump due to operation at zero or low-flow condition if RCS pressure exceeds the pump shutoff hea . ._ . . . . _ _ __ _ _ _ _ _ _ _ . __ _ _ __ ._ _ ___
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When operating in the piggy-back mode, the minimum recirculation lines are '
isolated by closing the motor operated stop-check valves HP31 and HP32 to ;
prevent post-accident containment sump water from being pumped into the BWS :
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Each of the two injection lines from the discharge of the HP! pump contain one
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motor operated valve (MOV) for normal isolation from the RCS and to provide the control room operator with the capability to throttle or balance the HP! >
flow rate in-the two branch lines. Flow rate in each branch line is measured and indicated in the control room. Throttling or flow balancing with these *
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valves may be required in the case of a broken or pinched HPI injection lin All electrical components of the HPI system are powered from the emergency power supply. The two HPI trains #re powered from two separate trains of essential power. Train 1 is powered from Class lE Bus "C)" and Train 2 is powered from Class lE Bus "01." Standby power to each Class lE bus is provided by a separate emergency diesel generator (EDG).
El. Mechanical Design Review El.2. Scope of Review for the mechanical design review of the HPl system, the team evaluated the !
plant design transients to establish design requirements, and reviewed the accident analyses and calculations to determine if the HPI system was capable of mitigating the consequences of an accident due to a main steam /feedwater line break, steam generator tube rupture, a SBLOCA, and a large break LOCA (LBLOCA).
The team reviewed plant drawings, modification packages, USAR sections 6.3, 7.4.1, and 15.4, HPl system description 5D-038. Revision 2, technical specifications, operating procedures, one modification package, maintenance and surveillance tests, IE Bulletins, information notices, generic letters, and engineering evaluations associated with the syste The team also reviewed the design of the cooling system for ECCS rooms 105, 113, and 115, and the environmental qualification of the equipment in these room El.2.2.2 findings a. HPI System flow Reauirements The team reviewed the following documents prepared by Babcock & Wilcox (B&W)
to determine the minimum required HPI flow and the maximum time delay for HPI-flow injection considered in the accident analyses: topical reports BAW-10105,
"ECCS Evaluation of B&W's 177-FA Raised-Loop NSS." July 1975, and BAW-10075A,
"Multinode Analysis of Small Breaks for B&W's 177-fuel-Assembly Nuclear Plants with Raised loop Arrangement and Internal Vent Valves," March 1976; B&W documents 51-1170356-00, "ECCS Historical Document for Davis Besse Unit 1 "
November 1987, and 32-1171604-00, '0B-1 LPl/HPI for LBLOCA Calculations,"
March 1988; B&W calculations 32-1159751-01, "ECCS HPl flow Reduction,"
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September 1986, and 32-1664551-00, "TED HPI ATOG Curve Evaluation " October 1986; and B&W engineering information record 51-1164182-01, "HPI flow Acceptance Criteria - ECCS Analysis," September 198 The team verified that the HPI flow required for mitigation of a SBLOCA, main steam line break (MSLB), and LOCA specified in the reviewed documents were consistent with the flow requirements stated in system description 50-03 ;
The minimum HPl flow rates at various RCS pressures at the HP! nozzle presented in Table 1.2-1 of the system description take into consideration a 7% reduction in the HPI flow capability due to pump degradation. The team .
also verified that the time delays used for establishing HPI flow to the RCS !
in the accident analyses were met in the design. Except for MSLB, a time delay of 30 seconds for the injection of HP! flow was used in the analyse For the MSLB, a delay of 35 seconds had been used. B&W analysis 32-1171604 showed that a maximum delay of 35 seconds was acceptabl If an HPI line to the RCS is broken or pinched, throttling of the motor-operated injection valve is necessary to ensure that about half of the
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required flow specified in Table 1.2-1 of 50-038 is supplied to the RCS i through the intact line. The team verified that procedure DB-0P-01200, "RPS, SfAS, SFRCS Trip or SG Tube Rupture," for flow balancing / throttling and the actual time required by an operator to balance the flow after an accident, were in agreement with B&W and the licensee's design basis calculation The team reviewed the HPI flow requirements for a steam generator tube rupture accident that discharges reactor coolant into the secondary side of the steam generator, in this scenario, the reactor coolant leak exceeds the normal capability of the make-up system. Information on the HP1 flow and the tirae at which the flow is required to be initiated to mitigate the consequences of the accident was not available. The licensee has initiated efforts to obtain this information from B&W, (Inspection follow-up Item 50-346/97-201-01)
B&W calculation 32-1171604-00 included the HPI flow as a penalty in the calculation of the core reflood rate because inclusion of the HP! flow increases the pressure in the reactor vessel, and therefore, increases the reflood time. Section 1.2.1 of the HPI system description 50-038 stated that for a large break LOCA, the minimum HPI flow shown in Table 1.2-1 of SD-038 was required, but did not discuss the conservatism in the B&W evaluation due to consideration of HPI flow. The licensee stated that system description a0-038 would be revised to properly characterize the conservatism in considering full HPl flow, b. HPI System In.iection Flow Rate and Pumo Surveillance Testina The team reviewed the licensee's calculations for HPl system hydraulic resistance, piping isometric drawings, and pump surveillance test procedures and acceptance criteria, to evaluate HPI system capability to provide the limiting flow specified in Table 1,2-1 of system description 50-03 Calculations 36.017, "HPI flow vs. Reactor Coolant System Pressure," Revision 03, and C-NSA-52.01-001, "HPl flow Rate As a functior, of RCS Pressure,"
Revision 01, determine the HPI injection flow rates. The pressure drops in
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both the pump suction and discharge lines for standard flows of 100, 200, and j 500 gpm, the sump head for these flows from the original test performance t curves, and tle RCS pressure at the HPl nozzle, were determined in these i calculations. The RCS pressure versus HPI flow rate had also been measured by t test, and the test results were provided in calculation C-NSA-52.01-003, "HPI Pump Acceptance Criteria," Revision 03. The team compared the data in these ,
documents and noted that the calculated values were conservative with respect
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to the actual measured values. The data for developing HPl flow rate versus RCS pressure curve was provide, in Calculation C-NSA-52.01-004, "HPI System Resistance Curves," Revision 0. ;alculation C-NSA-52.01-007, "HPI System Curve with Instrument Error," provided the best-estimate HPI flow curve with a <
7% flow reduction to account for degradation of the pump and a further flow reduction of 1.5% to account for instrument error. This best estimate HPI flow curve enveloped the minimum flow required by the B&W analysis to mitigate an acciden i Calculation C-NSA-52.01-003, "HPI Acceptance Criteria," developed acceptance criteria for the sutveillance test for the HPI pump Because of system limitations for periodic surveillance testing at full HPl flow, the test is conducted at about 400 gp The HP1 pump performance test performed during plant startup showed that the pump delivered a total flow of 820 gpm or 410 gpm per injection leg at an RCS pressure of 400 psig. The results from tests DB-SP-03218, "HPI Pump 1 Quarterly Pump and Valve Test," dated March 17, 1997 and DB-SP-03219, "HPI Pump 2 Quarterly Test," dated April 25, 1997, show that the pump will deliver about 380 gpm at a pump discharge pressure of 1500 psi The original pump test curves showed that the pumps delivered a flow of 380 gpm at a pump pressure of about 3500 ft, or about 1515 psig. The latest pump tests showed minimal degradation of the sump performance since its installation. The team concluded that tie TS 4.5.2 requirement of HPI flow of 375 gpm in each injection leg at 400 asig at the core flood nozzle was ,
satisfied taking into consideration tie system hydraulic resistanc The team concluded that the HPl system had been designed to provide the flow required for accident mitigation, assuming a 7% degradation in pump flow capacity, and that the surveillance tests verify the system capability, HPI Pumo Net Positive Suction Head The team reviewed calculation 36.010. "LPI, HPI, CS NPSHA from BWST "
- Revision 0, and 36.031, "HP! Pump NPSHA at a Possible 1020 gpm flow,"
Revision 0, along with piping isometric drawings M-233A, " Emergency Core Cooling Systems - Borated Water Supply," Revision 15, and M-2338, " Emergency Core Cooling Systems - Pump Suction Piping," Revision 19, to verify the available net sositive suction head (NPSH ) for the HPI pumps when taking suctionfromtieBWSTatpumprunoutcondition. The team's review, however, indicated that on-the basis of the pump performance characteristics and the pressure drop in the discharge line, pump runout will not occu Consideration of the pump runout in the evaluation was conservativ With conservative assumptions regarding low water level and temperature in the BWST, the NPSH at pump runout conditions of 900 gpm and 1020 gpm were calculatedas%9.5feetandabout44feetrespectively. The required net
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positive suction head (NPSH,) at a pump flowrate of 1020 gpm was about 35 feet. Therefore, there was adequate margin in the NPSH As stated above, because of high hydraulic resistance in the discharge pi. ping, the HPl pumps are not expected to reach runout conditions.
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The team reviewed calculation C-NSA-52.01-ll, 'HPl NPSH on CTMT Emergency Sump Recirculation," Revision 0, to determine the NPSH for the HPI pump operating inthepiggy-backmodetakingsuctionfromtheLPIpumpdischarg The calculated total hydraulic losses were based on actual test measurements and calculated values. The calculation estimated the NPSH, at about 200 feet which was wuch greater than the NPSH,.
The team concluded that sufficient NPSH margin was available for the HPl pumps when taking suction from either the BWST or the containment emergency sump in the piggy-back mode, Snigglgundaries and Safety Class Interfaces The team verified that appropriate system boundaries and safety class interfaces were considered and incorporated into the design for the interfaces between the HPI system and RCS, make-up and purification system, and DHR system, locally mounted pressure gages Pt 1519 and 1520 were installed in the high pressure injection (HPI) system with one normally open manual isolation valve in each sensing line from the system piping. Each isolation valve was an ASME Code, Section 111, Class 2 valve and was the boundary between the Class 2 l system piping and the non safety-related sensing line and pressure gage. The !
pressure gage was not seismically qualified and its pressure boundary could fail in a seismic event. Hewever, the sensing line was designed to seismic class I requirements, and the line and the pressure gage were provided with seismic class I supports. Because the pressure gage was not seismically qualified, the team questioned the acceptability of a normally open valve as boundary between ASME Class 2 piping and the pressure gage although the gage was seismically supported. This issue has been referred to NRR staff for further evaluation. (Inspection follow-up Item 50-346/97-201-02) P_ipino Desian Pressure and Temperature The team reviewed the HPI system piping and instrumentation diagram (P&l0)
M-033. Revision 25, system description 5D-038, Revision 02, piping class specification M-200, Revision 05, and piping isometric drawings to verify the piping design pressure and temperature classification for the suction, discharge, minimum recirculation, and test lines. The team determined that the pressure and temperature :lassifications were acceptable except for the following:
- Piping isometric drawing M-233D, "HP Injection System - Auxiliary Building,' Revision 22, provided a table of operating pressure atd temperatures for various lines that were not censistent with the l'ip Design Table, in specification M-200. The licensee stated that the operating temperature and pressure shown on drawing M-233D were not-used
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in the piping design, and initiated DCN M-2330-12 to delete this information from the drawin * Specification M-200 listed the maximum working pressure for lines CCB-19 and CCB-12 as 2500 psig and 1650 psig respectively. These two lines are connected and have no isolation devices between them, and therefore, the pressure in both lines should be identical. However, the team noted that piping stress calculation No.54 for line CCB-12 used the correct value of 2500 psig as the service pressure in the line. The licensee issued a specification change notice (SCN) H-200-05-15 to correct the error in t1e maximum operating pressure for line CCB-12 in specification M-20 * Specification M-200 listed the maximum design pressure for piping CCB-2 between the HPI pump discharge check valves and the motor-operated containment isolation valves as 2600 psig, whereas the pressure for piping downstieam of the containment isolation valves was listed as 2500 psig which is the RCS pressure. Specification M-200 did not provide any explanation for the difference in the design pressure values. The piping stress analysis used a pressure of 2600 psig which is the ASME Code allowable pressure for the pipe. The licensee issued SCN H-200-05-16 to clarify in specification M-200 the basis for the higher pressure rating in the portion of line CCB-2 upstream of the containment isolation valv * The maximum service pressure and temperature rating for line CCB-2 from IIPI pump l-1 discharge to the pump discharge check valve HP22, and from IIP 22 to motor-operated isolation valve HP 2C and 2D was listed in Spe M-200 as 1650 psig at 260*F. The same values are also applicable for the HPI pump 2 discharge line. The maximum service pressure in these lines should be 1850 psig which was the maximum expected pressure when the HPI system was operating in the piggy-back mode. The stress .
analysis for this portion of CCB-2 line was performed at a pressure of 1650 psig and a temperature of 260'F. The stress analysis was, therefore, performed using a lower pressure than the expected valu This discrepancy was identified by the licensee during the inspection and was documented in potential condition adverse quality report (PCAQR)
Co-0825 for reevaluation of this portion of the CCB-2 line to address the increased service pressure in the pump disch rge line. The team determined that the pressure rating for the valves, fittings, and piping-for this portion of the pipe enveloped the pressure of 1850 psig, and the small pressure increase from 1650 to 1850 psig should not significantly impact the pipe hangers and supports, Environmental Qualification of Eautoment in ECCS Rooms 105. 113. and 115 The team reviewed USAR Table 3.6-11, procedure NG-EN-00306, " Environmental Qualification Program," Revision 02, calculation C-NSA-000.02-005, " Main feedwater Line Breaks and Cracks in the Auxiliary Building," Revision 01, and selected electrical schematic drawings for electrical equipment in ECCS rooms 105,113, and 115 to verify the environmental qualification (EQ) of the electrical component _ .. - _ . .. . - _ - _ _ _ -____ __ _ _ _ _ _ _ __
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The environment in the ECCS rooms becomes harsh due to high temperature in the event of a main feedwater linu break (MfWLB), auxiliary steam line break or a l break in the steam generator blowdown line in the auxiliary building. Except i for the MfWLB accident for which the HPI system is required to operate to i bring the reactor to safe shutdown conditions, the ECCS systevs are not required to operate. in the event of a LOCA, the radiation levels in the ECCS rooms increas The team's review of electrical components in the ECCS rooms that are powered from the Class lE bus indicated that some safety-related electrical components, such as sump pump motors, sump level switches LS-4621, LS-4623, LS-4625, associated hand switches, and electrical boxes were not listed in the EQ Master List. These components are required to operate under harsh environmental conditions. Failure of these components could jeopardize Class IE circuit integrity and operation of associated safety-related equipmen )
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The licensee provided a list justifying exemption of some of these components from the EQ program. This list was not an EQ Exempt List that was described in procedure NG-EN-00306, " Environmental Qualification Program," Revision The licensee agreed that sump pumps and associated level instruments and local control stations should have been included in the EQ program in accordance with procedure NG-EN-0030 The licensee issud PCAQR 97-0796 to address the environmental qualification of these components in the ECCS rooms and additional required documentation, and concluded that there was no operability concern because identical local control stations and level instrumentation components have been qualified for harsh environments and the materials commonly used for sump pump motor windings had been demonstrated to be qualified for calculated radiation levels in the ECCS room (Inspection Follow-up Item 50-346/97-201-03) Calculations The licensee provided a total of 19 mechanical system calculations for the HP1 system, which accounted for all the mechanical calculations performed by the original architect-engineer and the licensee. Of these calculations, the team identified only eight that appeared to su) port the current design basis, if the calculations that support the design aasis are not explicitly identified as such and the other calculations are not archived, superseded, or identified as historical information, the team was concerned that data from the calculations that are not part of the design basis could intdvertently be used for future design changes or as input to operational decision The licensee stated that as a part of the design basis validation program, the existing calculations will be reviewed for adequacy and it will be ensured that they reflect the current plant desig System Modification-The team selected modification 96-006, " Installation of High Point Vent in HPI Pump 2A Discharge Line" for review. The design of the system was such that a section of the HP1 pump discharge line could be drained following maintenance or testing of the system and the small trapped air volume in that segment
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could only be flushed out after a pump start. The mcdtfication installed a vent to ensure proper refilling of the discharge piping. The team concluded that the design of the modification, safety analysis, and closecut of the modification was adequately performe El.2. Conclusions The team concluded that the HP! system design was adequate to provide the required flows assumed in the B&W analysis for SBLOCA and MSLB/MFWLB considering a 7% reduction in the pum'p flow capacity. The system provided sufficient NPSH for the HPI pumps when taking suction from either the BWST or the containment emergency sump. Except for the locally mounted pressure gages at the suction of the HPI pumps, the system incorporated appropriate boundaries and class breaks with interfacing systems. This issue has been referred to the NRR staff for evaluation. The team noted several discrepancies in piping specification M-200 rega, ding pioing design pressure and temperature classification. Theteamnotedthatexclusionofsome electrical equipmen!. in the ECCS rooms was a weakness in the EQ arogra The team was concerneo + hat lack of proper identification of design )ases
. calculations could result in the use of information from calculations that have been superseded and do not support the system desig El. Electrical Design Review El.2. Scope of Review for the electrical design review, the team focused on the essential power supplies to the HPI and DHR system The areas examined, such as emergency diesel generators, 4,160-volt AC buses 480-volt unit substations and motor control centers (MCCs), 125-volt DC system, and the 120-volt vital AC system, were common to both systems. Therefore, a separate discussion of the inspection of electrical aspects of the DHR system is not included in the report, The team reviewed USAR Section 8.0 TS 3/4.8 Electrical Power," system descriptions, Design Criteria Manual (DCM) Section 111.0 " Electrical,"
electrical calculations and drawings, specifications and procedures for electrical requirements and construction, one modification work order (MWO)
package, PCAQRs, and other miscellaneous electrital document The team assessed portions of the following that are applicable to the HPl and DHR systems: essential power systems including switchgears, transformers, motors, raceway, panels, cables, terminations; regulatory and standard compliance; channel separation; voltage drops and available voltages; controls and interlocks; alarms and indications; protective device setpoints; field installations; modifications; labeling and identification; fire stops; drawing and record changes; and seismic ard (.nvironmental consideration l
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El.2. Findings The team reviewed the emergency diesel generator (EDG) system description, capacity calculations, elementary diagrams, protective relay setpoints, and electrical equi > ment. The calculations showed that EDG loading was properly estimated and tae EDGs had adequate capacity margin. This was verified by the records from the SFAS integrated time response test performed in May 199 The electrical loads including the ECCS loads were sequenced onto the EDG within the required time, and the drop in output voltage and frequency and their recovery were acceptabl The team reviewed the system description, drawings, protective relay setpoints and coordination calculations, and other aspects of the 4160-volt AC system with emphasis on undervoltage protection sr.hemes. The calculations indicated that the undervoltage setpoints were adequate for proper operation of the electrical loads and for shedding loads in the event of a loss of off-site powe ,
The team reviewed the system descr yt kns for the 4S0-volt unit substations and motor control conters, )rotection settings and coordination, cable 4 ampacities and derating motiods, calculations for voltage drops, and valve operations under reduced voltage. The team reviewed selected HPI and LPI elementary diagrams and SFAS actions and equipment interlock The team had no concerns regarding the 480-volt syste Except for the testing of battery chargers and inverters discussed in the following paragraphs, the team had no other concerns regarding the 125-volt DC and the 220-volt vital AC systems, a- Battery Charaars The electrical distribution system functional inspection (EDSFI) finding .
346/92007-06 stated that the battery charger surveillance requirements were different from the charger design ec7nitment described in USAR Section 8.3.2.1.3. The USAR stated that each " charger is capable of supplying all steady-state DC loads required under any conditions of operation while recharging the battery to a fully charged condition over a period of 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> from a discharged condition of 105 volts per battery." TS 4.8.2.3.2. requires a verification at least once per 18 months that the " battery charger will supply at least 475 amperes at a minimum of 130 volts for at least 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br />."
The licensee revised procedure DB-ME-03002, " Station B.ttery Service and Performance Discharge Test" to include Enclosure 7: " Battery Charger Current Readings During Recharge following Test Discharge." The revised procedure did not require that the load box that was used to discharge the battery be used again to simulate a worst-case steady-state load on the battery and battery charger while the battery was being recharged. The licensee provided Enclosure 7 test result readings for the four batteries for the team's revie The team noted that the initial reading was close to 500 amperes which was the current-limited full rating of the charger. The charging current dropped to less than 475 amperes within 45 to 60 minutes and decreased to near zero
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within 1-1/2 to 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> and remained at near zero for the rest of the 12-hour I charging cycle, it was apparent that without using the load box to simulate a steady-state load, the procedure did not verify the USAR commitmen The team
- also noted that the two backup chargers DBCIPN and DBC2PN were not normally used for recharging and they were not tested. (Inspection follow-up Item 50-346/97-201-04) Testina of Inverters and Associated Components The team reviewed the inspection and testing of the power supplies for the 120 VAC essential instrumentation distribution panels Yl, YlA, Y2, Y2A, Y3, and Y4 Four channels of essential instrumentation are fed by these panels and supply vital 120 VAC to systems, such as reactor protection, safety features actuation, radiation monitoring, auxiliary shutdown, and others as shown on drawing E- The channel 1 essenital instrumentation distribution panels Y1 and YlA are normali, supplied by inverter YVI, which converts 125 VDC to 120 VAC. This inverter is rated at 10 kVA and operates at about 60% of full load, supplying loads that do not significantly c1ange during postulated abnormal events. The inverter YVI is normally energized with 125 VDC from regulated rectifier YRFl which, in turn, is supplied from the 480-volt essential MCC E12A. If the 480-volt feed is de-energized during a transient, such as a loss of off-site power, the inverter is transferred without interruption to a 125-VDC supply from the Channel I batter When the 480-volt feed is restored the inverter will transfer back to the regulated rectifier supply. Should the inverter itself fail, a static transfer switch within the inverter will switch the 120-VAC panels from the inverter to a 480-to-120-VAC constant voltage transformer (CVT) XYl. The CVT powers the buses until the inverter is restored. An additional function of the CVT is to provide fault-clearing power during problems in the 120-VAC circuits. Channels 2, 3, and 4 have a similar configuratio The regulated rectifiers, inverters, and constant voltage transformers are not mentioned in the technical specifications. Therefore, there was no commitment to perform surveillance tests on these Class IE equipment, and no periodic surveillance tests are performed to demonstrate the load carrying capabilities of the regulated rectifier, inverter, static transfer switch, or CVT or to demonstrate the operability of special functions. The existing preventive maintenance procedures for cleaning and visual inspection, the continuous monitoring of CVT availability during normal operation, and the continuous supply of normal loads by the regulated rectifier and inverter, do not demonstrate the specified capabilities or the available margins under abnormal conditions of the 120 volt AC system. (Inspection follow-up Item 50-346/97-201-05) Electrical Installation Procedurn
The team reviewed maintenance procedure DB-ME-09512. " Installation Procedure for Raceways Carrying Electrical Cables," to evaluate implementation of raceway criteri All safety-related cables at Davis-Besse are routed in Class IE conduits. Procedure DB-ME-09512 provided few specific requirements
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and guidance for the installation of conduits. The team had numerous comments .
on-this procedure relating to safety-related aspects, such as material requirements, seals and fittings, codes and standards, conduit supports, i installation practices, and acceptance criteria. The team also reviewed i electrical specification 7749-E-14, " Electrical Construction and Installation," several sheets of drawings E-302A and E-1037P dealing with electrical standards and details and grounding details, and maintenance procedure DB-MM-01001 " Installation Procedure for Essential Electrical Hangers and Supports The team did not find specific installation requirements or guidance in these documents. The lic'ensee issued PCR 97-1596 to revise procedure DB-ME-09512 to resolve the team's comment .
The team reviewed maintenance procedure DB-ME-09500, " Installation and Termination of Electrical Cables," because the licensee stated that the instructions for wiring within panels were covered by this procedure. This procedure did not include installation requirements, such as physical
- separation and color coding stated in USAR subsection 8.3.1.2.25, and separation if low level signal wiring from power or control wiring stated in panel-specifications. It appeared that no other criteria document or procedure addressed such requirement El.2.3.3 Conclusions
. The team concluded that the essential power supplies for the HPI and LPl 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 USA Calculations for protective relay setpoints, coordination, voltage drops. EDG loading, battery loading, and others were conservative in approach, used appropriate methodology, produced reasenable results, and were consistent with the design bases. Design bases documents cover the performance requirements, design requirements, developmental and r code references, component descriptions, technical specifications, and limit Some weaknesses in raceway installation and panel wiring procedures were identifie The functional and performance requirements appeared to be consistent with the USAR, technical specifications, system descriptions, and calculations and analyses. The battery charger capability testing did not fully comply with the intent of the commitment in 11e USAR as identified in an EDSF1 findin The team also questioned the lack of testing of some features of inverters and associated component El. Instrumentation and Control Design R(iiew El.2.4.1 Scope of Review The scope of the instrumentation and control design assessment consisted of a review of HPI system documents, such as sections 6 and 7 of the USAR, technical specifications, system description, P&lDs, loop diagrams, operational schematics / control logic diagrams, four setpoint calculations and loop uncertainty analysis, six instrument data packages, maintenance, surveillance, and operating procedures, and one modification packag .
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El.2.4.2 -Findings The system design documents reviewed by the team adequately supported the-design bases, except for the items discussed in the following paragraphs,
- Reactor Coolant low Pressure (SFAS level 2) Actuation Setooint The retctor coolant pressure instrument loop provides low reactor coolant pressure input for the SFAS Actuation Level 2 permissive for HPI operatio The team noted inconsistencies in the reactor coolant low pressure setpoint on
- he variour documents that were reviewed. Technical Specification Table 3.3-4 specifies a trip setpoint of 1620.75 psig and an allowable value of 1615.25 psig. This was based on the low pressure trip value of 1585 psia considered in the B&W SBLOCA analysis (calculation 32-1159744-0, dated June 16,1986)
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with an addition of 2.03% for instrument error. A subsequent reanalysis (B&W cal _culation 32-11178648-00, Revision 1) justified a value of 1515 psia, but this value was not considered in the technical specifications. Instrument data package 648-ISNC02A3, Revision 4, showed a calibrated setpoint of 1661 psig which was considered by the team to be conservative. The team also
- reviewed calculation C-ICE-48.01-002, Revision 2, which established a loop '
uncertainty of 12 psig and a setpoint of 1660 psig. Although conservative, this value did not match the results of the B&W analysis and the instrument data prckage. The licensee, however, stated that this calculation, now in its 6th revision, was intended to support a future amendment to the technical specifications that will establish new allowable values, a new trip setpoint, and iratrument icop uncertainty. The licensee acknowledged the above inconsistencies and indicated that this issue will be addressed as part of a future technical specification update and design basis validation progra , HPI Pumo Flow Test Calculation Calculation C-NSA-52.01-003, "HPI Pump Acceptance Criteria," Revision 3, established the acceptance criterth for the HPI pump quarterly flow test. The team reviewed this calculation and noted that the assumed 1.5 accuracy for the flow indicator for obtaining test data was not consistrat with the 2%
calibration tolerance specified in the instrument data package. The licensee initiated PCAQR 97-0677 to revise the instrument calibration tolerance to 1.5% 4 to be consistent with the calculation. This error did not invalidate previous test result because the calibration record for the flow indicator that was used in the test was verified to have an as-left instrument tolerance of 0.75%, which enveloped the required instrument accurac El.2.4.3 Conclusions The team concluded that the instrumente ion and control design for the HPI system was adequate. All instrumentation setpoints- that were reviewed had adequate margin and the technical specification limits were met and the errors that were noted by the team were minor. The team noted an inconsistency in the RCS low pressure setpoint value in the technical specification, loop uncertainty calculation, and instrument data sheet. However, the actual setpoint was conservative and acceptabl _ _ _ _ ___ _ __ _ __ __
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El.2.5 System Interfaces El.2. ECCS Room Cooler *
-The team reviewed 50-0280, " System Description for Auxiliary Building Radioactive Area HVAC System," Revision 2,50-018, " System Description for Service Water System," Revision 2, and calculations for the ECCS room cooler capacity to determine whether ECCS room coolers had the capability to maintain the maximum design room temperatur The HPl system <iescription 50-038 stated that the normal tcaperature in the ECCS rooms was s5'F and the maximum allowable temperature was 125'F. Thit maximum temperature limitation was imposed by the ECCS pump motor bearin ~11 lubrican Calculation-C-NSA-032.02-003, " Maximum Allowable Service Water Temperature with inoperable ECCS Room Coolers," Revision 3, supported the post-LOCA design room temperature of 125'F for the ECCS rooms. The team also reviawed calculation 25.13. "ECCS Pump Room Heat Load / Fan-Coil Unit Capacity v Service Water Temperature," Revision 1, and calculation 25.14 "ECCS Pump Room Heat Load / Fan-Coil Unit Capacity vs. Service Water Temperature for Rm Ma Design Temp. = 122*F (50*C)," Revision 0, and estimated equivalent heat loads for an ECCS room temperature of 125'F. The heat loads used in calculation C-NSA-032.02-003 were consistent with the team's estimates. The team concluded that with the technical specification limit of 85'F for the maximum allowable service water bay temperature, the combined capacity of both room coolers in each ECCS room was adequate to limit the maximum room temperature in the ECCS room to 125'F under post-LOCA condition SD-028C stated that the normally closed (NC) motor-operated valve SW 5425 at the outlet of the room coolers opened automatically on increasing room temperature. Modification 95-006 implemented a design change that left the valve permanently open and power to the motor operator was removed. The system P&lD showed that the power to the valve had been removed. The team noted that, in accordance with plant modification procedure NG-EN-00301, Section 6.4, Action Item 8, a change notice should have been issued to update the system description as part of the closeout of modification 95-006. The team noted that Table 2.4-1 in 90-028C showed the rating of cooler E42-1 Btuh, whereas the correct rating was 180,000 Btuh. The licensee issued SDCN-028C-02-005 to correct these error El.2.6 HPI System Walkdown El.2.6.1 Scope The team inspected the installed mechanical, electrical, and instrumentation and control equipment for the HPI system to evaluate their consistency with drawings, design specifications, and regulatory requirements. During the -
walkdown the team interviewed plant system engineers, and operation and maintenance personnel. The team walkdown covered the HPI pump rooms, control room, auxiliary shutdown-panel, BWST area, cable spreading room, switchgear rooms, battery rooms, and electrical distribution panel . .- . . - - - . .-- - .
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For the electrical walkdown, the team chose three HPI and three LPI cable These included two instrument cables, two control cables, one 480-volt power-supply cable to a valve motor operator, and one 4,160-volt pump motor )ower supply cable. Some of the aspects examined included cable sizing and aend radii, control board and enclosure wiring, separation, raceway, seismic supports, identifications, fire stops and wraps, drawings and records, environmental considerations, material control, and installation procedure El.2.6.2 Findings Motor Operator Installation for Valve DH61 The team observed that the motor operator installation for isolation valve DH 63 was nonstandar This valve was originally designed for manual operation during the piggy-back mode of HPI operation. A modification was performed to add a motor operator to permit remote operation of the valve. Because of space limitations, the motor was mounted away from the valve with a connecting shaft to the valve stem. The licensee did not perform an analysis to verify acceptability of the loading on the piping due to the nonstandard mounting of the motor. During the inspection, the licensee performed a preliminary piping and pipe support analysis that showed that the stresses were much below the allowable value. The licensee will update the appropriate piping stress analysis to incorporate the preliminary analysis, Groundwater Leakaae in pump room 115, the team noted that a tygon tube was attached to a vertical structural support, and was discharging water to a floor drain. The licensee explained that groundwatsr was getting into conduit runs and drains through holes in the conduits into an area above the non-essential electrical
, distribution switchboard MCC F-2 The tygon tubing drain observed by the team was a portion of the leak collection system installed to preclude water intrusion into switchgear and other important plant equipment. The licensee explained that the stution was maintaining a leak collection log for tracking leakages and the drainage arrangement was temporar Groundwater leakage into buildings was a larger concern that the licensee was evaluating for potential corrective actions, Electrical Construction The team's comments on electrical installation procedures are discussed in E1.2.3.2.c of this repor The licensee resolved the team's questions during the walkdown on the use of threadless conduit couplings and conduit unions, the criteria for spacing of conduit supports, and the radiation resistance and fire loading of PVC covering on flexible conduits, HPI Pumo tube Oil Pressure Switch During the walkdown of ECCS pump room 115, the team noted that the HPI pump P58-2 lube oil pressure switch PDS-4961 had a material deficiency tag (MTD
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C469, dated May 2, 1995) attached to it, with a caution statement not to bump the pressure switch. The function of the pressure switch was to initiate operation of the backup DC lube oil pump in case of failure of the safety-related AC lube oil pump. Plant personnel were cautioned not to bump the switch to preclude its failure or inadvertent actuation. The team noted that PCAQR 95-0237 was issued on March 20, 1995, identifying a calibration stability problem with the pressure switch, but the PCAQR stated that I&C maintenance was unable to determine the exact cause. The licensee concluded that there were no operability concerns because the pressure switch failure would tause the DC lube oil pump to start, and would not affect operation of the AC lube oil pump. The licensee stated that the pressure switch would be replaced in July 1997, with a suitable narrow-range type that was inherently more accurate and stable. Recommended changes to the post-calibration intta11ation techniques would be incorporated in the PM procedur The team was concerned that the corrective actions to replace the pressure switch had not been timely. The pressure switch for the redundant train (PDS-4957) had experienced a similar failure in 1994, and was replaced with the original model with the same range and setpoint. The team discussed the
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inappropriateness of the use of a pressure switch with a range of 0-70 psid for an application that required a setpoint of 8 psid with a deadband of psi The licensee indicated that the feasibility of making the pressure switches in both trains identical would be evaluated, Taaaina of Instruments and Associated Valvet The team noted that several instruments, isolation valves, and manifold valves in the HPI and t.PI systems did not have identification tags. The team also noted that some devices had more than one tag with different identification numbers and some tags were attached at the incorrect locations. Tagging procedure DB-DP-00023, Revision 02, applies only to new tags, and existing tags not conforming to the requirements of the procedure are considered acceptable until replacement is necessary. Based on discussions with plant personnel, it appeared that the existing instrument and valve tagging condition had not hindered plant operations or maintenance. Without a consistent tagging system, the plant has to rely on operators' familiarity with the plant's physical configuration. The licensee acknowledged that this
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problem was previously identified, and a program was being initiated to address the tagging issue on a generic basis. This program will cover definition of requirements, standardization, procedure update, and implementation schedul El. Updated Safety Analysis Report The licensee had initiated an USAR program in August 1996 to review and update the USAR, Concerns resolution request (CRR) forms were prepared for the identified questions or open concerns in the USAR related to the HPI and DHR systems. The team reviewed the CRR forms that had been resolved and approved by the station review group, and concluded that the USAR issues had been appropriately resolve .
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The team identified the following additional discrepancies in the USAR:
- USAR Section 6.3.1.4 stated that " permissive signal is provided to allow the manual opening of the sump valves" whereas Section 6.3.5 stated that
"No actions are required by the operator in large pipe LOCA..." These two statements are contradictor * The SFAS set point of 1600 psig for low RCS pressure and the high pressure injection setpoint in USAR Table 15.4.2-1 did not correspond to either the analyzed design bases set point of 1570 psig or the technical specification set point of 21620.75 psig. The licensee had submitted license amendment request (LAR) 96-0014 dated April 18, 1997, to the NRC to revise the technical specification The USAR will be revised after the approval of the LA *
USAR Table 7.5-1 indicated that HPI and LPI flow readouts in the main control room are types A(analog), D(digital), and F(computer). The actual instal:ed readouts are types A and F only. The licensee issued UCN 97-066 to revise the USA * USAR Section 15.4.4.2.3.2 provided a sequence of events and elapsed time to justify an assumption of a 35-second delay in injection of water to the RC The team considered the assumption to be conservative, however, the timing of sequence of events listed in the USAR did not correspond to the SFAS integrated time response test, the time delay analysis provided in B&W analysis 32-1171604, or the licensee's calculation C-EE-004.01-04 The USAR also considered the time delay for starting the HPl pumps, although the opening of the motor-operated injection valves was a more critical contributor to the time dela The above discrepancies had not been corrected and the USAR updated to assure th.t the information included in the USAR contained the latest material as required by 10 CFR 50.71(e). (Unresolved Item 50-346/97-201-06)
El.3 Decay Heat Removal System El. System Description and Safety functions The decay heat removal (DHR) system performs both normal operation and accident mitigation functions. In its normal operation mode, the system removes decay heat from the reactor core and sensible heat from the RC The system also provides auxiliary spray to the pressurizer, maintains the reactor coolant temperature during refueling, and provides a means for filling and draining the refueling canal. In its accident mitigation or LPI mode, the system injects borated water into the reactor vessel and provides long-term reactor core cooling after a LOC The decay heat removal system includes the BWST, the containment emergency sump, the BWST recirculation pump and heat exchanger, the refueling canal drain pump, the decay heat dropline valve pit, the decay heat removal pumps, the decay heat removal coolers, and the piping and valves associated with these components. Two redundant DHR pumps are arranged in parallel and are
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designed for continuous operation during the period required for removal of decay heat. Each DHR train has one decay heat removal cooler to remove decay heat from the RCS during a cooldown. Operating both coolers provides the design capability to reduce the reactor coolant temperature from 280*F to 140*f in approximately 22 hour2.546296e-4 days <br />0.00611 hours <br />3.637566e-5 weeks <br />8.371e-6 months <br /> The BWST contains an available borated water volume between 482,778 and 550,000 gallons with a minimum of 2600 ppm boron in solution and is used for emergency core cooling and filling the refueling canal during refueling. The BWST supplies borated water for emergency cooling to the containment spray system, the LPI function of the DHR system, and the HPI system, it also supplies makeup water to the spent fuel pool cooling system and can serve as a source for the makeup pump The LPI functions of the DHR system are initiated automatically by ar SFAS signal, and the LPI pumps take suction from the BWST and inject borated water into the reactor vessel. The DHR pumps are referred to in this report as LPI pumps where the emergency core cooling functions of the pumps :re discusse After a low-low level of 95 inches in the BWST is reached, the lh pump suction is manually transferred to the containment emergency sump to provide long-term cooling of the reactor. In this mode the DHR system removes heat from the containment by cooling the containment sump water in the DHR coolers before pumping the water back to the reactor vesse During the piggy-back operation of the HPI system, the LPI pumps provide containment water to the suction of the HPI pumps after the cross-connect valves between the two systems are manually opened by the operato The spent fuel pool cooling system is not designed to meet seismic Class I criteri When manually interconnected with the spent fuel pool, the DHR system provides safety-grade cooling and a larger capacity for heat removal from the spent fuel poo El. Mechanical Design Review El.3. Scope of Review for the mechanical design review of the LPI functions of the DHR system, the team evaluated the capability or the system to provida emergency core cooling during the injection and recirculatinn phases of post-accident ECCS operatio The team reviewed system description S0-042, Revision 2 for the DHR system, USAR sections 6.3 and 15.4, drawings, calculations, and operating and surveillance testing procedures, The team also performed system walkdowns and discussed the system design and installation with licensee engineering and operating personne El.3.2.2 Findings LPI In.iection Flow Rate and LPI Pumo Surveillance Testina The design basis for LPI injection flow rates as a function of the pressure at the reactor vessel core flood nozzle is given in Table 1,2-1 of the decay heat
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removal system description SD-042, Revision 2. The team verified that the system was designed so that each of the two trains provide the minimum LP flow rate and the flow rate was consistent with data in B&W document- 51-1158934-01, " Functional Requirements for the DH/LPI System," dated August 27, 198 Technical specification 4.5.2 has a requirement for verifying the LPI pump flow rate in each injection leg of 2650 gom at 100 psig pressure at the core flood nozzle on the reactor vessel. This requirement was presented in a B&W letter dated January 11, 1978. Interpolation of the data in Table 1,2-1 of SD-042, showed that the LPI flow rate at 100 psig was about 2486 gp Surveillance test procedures DB-SP-03136 and DB-SP-03137 specified an acceptance criteria for the LPI pump total developed head >etween 337.3 feet and 369.8 feet for flow rates between 2940 and 3060 gpm. The surveillance requirement was, therefore, higher than the design basis injection flow rate at 100 psig in the reactor vessel and was acceptabl Calculation C-NSA-049.02-010, " Review of Test Data from DB-SP-10065 for Valve
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DH14A," Revision 0, showed that the LPI train with the lowest flow could deliver considerably more than 2650 gpm at 100 psig in the reactor vesse This calculation also showed that the surveillance requirement could still be met with a 10% degradation in the performance characteristics of the pump with the appropriate reduction in system resistance. Therefore, the team concluded that the quarterly inservice testing of the LPI pumps in accordance with ASME Code Section XI with an acceptance criteria accounting for a 10% degradation in the pump performance characteristics was acceptabl The licensee issued system description change notice (SDrN) SDCN-042-02-005 to clarify the discussion of the LPI system flow requirement Net Positive Suction "aad (NPSH) Calculation USAR Section 6.3.2.14, " Net Positive Suction Head Requirement," included a table listing the NPSH either the BWST or from, theandemergency NPSH, forsumpthe LPI pumps in the drawing suction containmen The NPSHfrom for the LPI pumps when taking suction from the BWST was more than four times,the NPSH,, and the team reviewed the NPSH calculation 36.010, "LPI,HPI,CS NPSHA from SL">T," Revision 0, to verify the adequacy of the NPSH for the LPI pump Calculation C-Ne.-049.01-004, " Vortex Formation with ECCS Pump Suction from the BWST," Revision 0, assumed conservatively high flowrate from the BWST and minimum BWST level accounting for instrument errors, and concluded that at the
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minimum switchover level in the BWST, potential air ingestion into LPI pump suction of 2% by volume was the maximum to be expected. In accordance with Appendix A of Regulatory Guide 1.82, a 2% air ingestion into the suction flow will cause the pump NPSH to increase by a factor of two. Because there was adequatemarginintheNESH concerns during the operati on,of thetheteam concluded LPI pumps whilethat there taking werefrom suction no NPSH the BWS The licensee had performed calculations C-NSA-049.02-004, " Maximum Pump Flow for DH Pump 1-1 Under Accident Conditions," Revision 1, C-NSA-049.02 -005,
" Maximum Pump Flow for DH Pump 1-2 Under Accident Conditions," Revision 1, and
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C-NSA-049.02-009, " Mechanical Stop Position for Valve DH14B," Revision 0, to determine the position of the mechanical stops for the replacement valves DH14A and DH148 located at-the outlet of DHR coolers to limit the system flow rate and prevent pump run out. In addition, flow testing was done with pump suction from the BWST to confirm the required system flows with the new valve stops. This testing revealed that the actual system flow resistance was about 25% less than the calculated value. A new system flow calculation C-NSA-049.02-010 " Review of Test Data from DB-SP-10065 for Valve DH14A," Revision 0, was performed using the reduced system flow resistance. However, no new NPSH, calculation was performed with suction from the containment emergency sump and utilizing the revised system flow resistance. The licensee issued PCAQR 97-0478 to document and resolve this issu Calculation C-NSA-49.02-19, " Modification to Bechtel Calculation 36.35,"
Revision 0, was issued on May 17, 1997, to correct discrepancies in calculation 36.35, such as use of original pump curves instead of pump curves consistent with the modified pump impellers, and incorrect pressure drop through the flow measuring orifice. The new calculation concluded that adequate NPSH margin (2.59 feet for train 1 and 5.01 feet for train 2)
existed for e,ach LPI pump at flow rates limited by the new stop positions in valves DH14A and DH14B. However, the team noted that the calculation used the pump inlet flange elevatice which was about 2 feet higher than the pump centerline elevation and a water temperature of 120"F instead of the higher estimated post-accident temperature of the containment emergency sump wate As a result, the team determined that the calculated NPSH, was underestimated by about 3.5 feet and was conservative. The licensee issued RFA 97-0203 to revise calculation C-NSA-49.02-19 to account for the pump centerline elevatio .
In addition, the team noted that the calculation did not address the scenario in which one LPI pump supplied both injection lines with the crosstie valves open. In this configuration, emergency procedure DB-0P-02000 required the operator to limit the total injection flow in both lines to 4000 gpm, which results in a total pump flow of 4100 gpm including pump recirculation flow of 100 gpm. The actual flow would be higher if the flow instrument errors were considered, and NPSH under this condition would be higher. In view of the conservatisminthebPSHcalculationdescribedaboveandtheexistingmargins, the team did not have additional concerns regarding LPI pump NPS [.CCS leakaoe Testino During the inspection, the licensee initiated PCAQR 97-0529, and identified that reverse flow testing of check valves DH81 and DH82 on the two LPI pump suction lines from the BWST, and the leakage rate through stop check valves HP31 and HP32 on the HPI pump recirculation lines, were not being teste Leakage of post-accident containment sump water through check valves DH81 and DH82 in conjunction with either leakage through the BWST isolation valves DH7A or DH7B or failure of the isolation valves to close could result in increased off-site dos _ _ _ _ . _ . __ _ _
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No analyses had been performed to demonstrate that a conservatively high containment pressure under post-accident conditions was not sufficient to 1 overcome the static head of water in the BWST, thus eliminating the need to reverse flow test these valves. The inservice testing (IST) program documentation for DHRS-valves stated that the reverse flow testing of check valves DH81 and DH82 was not required because isolation valves DH7A and DH7B :
l would be closed. The potential leakage through isolation valves DH7A and DH7B or their failure to close was not considered. The licensee successfully l l
tested valve DH82 during the inspection and scheduled the testing of DH81 at a later date. The IST program documentation for DHRS valves was revised to include reverse flow testing of these check valve Leakage of containment sump water through stop check valves HP31 and HP32 on the HPI pump recirculation lines during the piggy-back mode of operation could result in increased off-site dose because the recirculation lines discharge into the BWST. The licensee was evaluating the testing requirements for these two valves as part of the resolution of PCAQR 97-0529. The design basis for valves DH81, DH82, rip 31, and HP32 was apparently not correctly translated into 1 procedures and instructions as required by 10 CFR 50, Appendix B, Criterion III, " Design Control," and Toledo Edison Nuclear Quality Assurance Manual,
Section 3.4.6.1. (Unresolved item 50-346/97-201-07)
TS 6.8.4 required that a program be established to reduce leakage from the ECCS and that integrated leakage from each system be tested at refueling intervals or less. USAR Table 15.4.6.5-2 shows the offsite dose due to an assumed total post-accident ECCS leakage of 5890 ml/hr. Procedures DB-SP-03136, DB-SP-03137, DB-SP-0 3218, and DB-SP-03219 verify external leakage from components, such as pumps and valves. Results of the recent tests showed negligible external leakage from the ECCS. Because the leakage tests were performed at a temperature lower than the expected temperatures under post-accident conditions, the team considered that this test could not verify that the post-accident leakage from the system would be less than the assumed value. The licensee is currently evaluating the issue of testing of internal and external leakage from the ECCS. (Inspection Follow-up Item 50-346/97-201-08) Pressure Interlock Setooint for Valves DHil and DH12 Valves DH11 and DH12 are nonnally closed motor operated valves in the DH drop line that isolate the RCS from the DHR system. These valves form the pressure boundary between the two systems (the design pressure rating of the RCS is 2500 psig whereas the design pressure rating of the DHR system is 300 psig).
The pressure interlock in the valve. control is designed to prevent these valves from being opened when the RCS pressure is above the design pressure of the DHR system. The interlock would also cause automatic closure of DH11 and DH12 as the RCS pressure increases past the pressure setpoint. In addition, other procedural controls are in place to ensure that these valves are not moved to their incorrect positions during various plant operating mode In TS 4.5.2.d and TS Table 3.3-4, the setpoint for the DH11 and DH12 pressure interlock is stated as <438 psig. The licensee stated that the setpoint was in error and that PCAQR 97-0238 was initiated on February 25, 1997, to
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disposition this issu Nuclear engineering memo DBE-97-00164 and calculation C-ICE-048.01-002, "SFAS Reactor Coolant Pressure Actuation Setpoints,"
determined a new TS allowable value of <328 psi Licensing Amendment Request (LAR) 96-0014 will implement the change to the appropriate technical specification by replacing the original setpoint of <438 psig with-the new allowable value of <328 psig. The team verified that the actual set)oints for these valves were 306 psig for DHil and 265 psig for DH12, whici were both below the new allowable value. In response to the team's question, the licensee stated that the actual valve setpoints had remained approximately the same since 1977, and therefore, the team concluded that there was no conc 4rn of potential overpressurization of the DHR system, Procedure RA-EP-02RQ Procedure RA-EP-02820, " Earthquake," governs the operation of the station after a seismic event. The teat noted that this procedure did not mention the availability of or refer to other procedures for back-up cooling of.the spent fuel pool. The DHR system is designed as a seismic class I syste.m and provides a back-up cooling capability. The licensee initiated procedure change request (PCR) 97-1404 to revise the procedure to direct the operators to consider aligning a DHR system train to cool spent fuel in the event the normal spent fuel pool cooling system was not operable, in addition, the licensee initiated PCR 97-1435 to revise procedure DB-OP-06012 to provide additional guidance to operators regarding the degradation of the LPI function of the DHR system if the DHR system ie aligned to perform spent fuel cooling functions during Modes 1, 2, and El.3.2.12 Conclusions The team concluded that the LPI system was designed and tested to provida the required flow rates assumed in the accident analyses. The system provided sufficient NPSH for the LPI pumps when taking suction from either the BWST or the containment emergency sump. The team noted that reverse flow testing of check valves DH81 and DH82 and leak testing of valves HP31 and HP32 had net been performed and this was a weakness in the IST program. At the time of the inspection, the licensee had taken actions to test these valve El.3.3 Electrical Design Review The discussion in Section El.2.3 uf this report covers the electrical design review of the LPI functions of the DHR syste El. Instrumentation and Control Design Review El.3. Scope of Review The scope of the instrumentation and control design assessment consisted of a review of LPI system design and associated documents. The team reviewed the instrumentation and control portions of sections 6 and 7 of the USAR, technical specifications, system descriptions, P&lDs, loop diagrams,
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operational schematics / control logic diagrams, four setpoint calculations and loop uncertainty analyses, and ten instrument data packages. The team also reviewed the associated surveillance, normal and emergency operating procedures, and two modification package El.3.4.2 Findings The system design documents reviewed by the team adequately supported the design bases, except for the items discussed in the following paragraphs,
, BWST tow-Low level Setooint The BWST level instrument loop provides input for the low-low BWST level (SFAS Actuation Level 5) permissive to initiate recirculation flow from the containment vessel emergency sum The team noted several inconsistencies in the BWST Low-Low level trip setpoint value shown in the various documents. TS Table 3.3-4 specified a low-Low level trip setpoint of 89.5 to 100.5 inches,
"with an allowable value of 88.3 to 101.7 inches," measured from the bnttom of the tank. USAR Section 6.3.1.4 states that at a BWST level of approximately 8 feet a permissive signal is provided to allow manual opening of sump valve Operational Schematic OS-004, Sheet 1, Revision 20, and Instrument Data Package 49A-ISL1525A, Revision 1, specify a calibrated setpoint of 95" from the suction pipe or 99" from the tank bottom. Calculation C-ICE-48.01-004,
"SFAS BWST Low level Setpoint," Revision 2, established a loop accuracy value of 19.5" with a setpoint of 96".
Document RFA 94-0509 dated January 17, 1995, calculated the minimum acceptable BWST level at which the SFAS Level 5 permissive bistable will trip. The team noted the following discrepancies in this document: the zero level reference point was at the bottom of the tank, while the setpoint calculation assumed a reference point 4" higher resulting in a conservative calculated setpoint; the licensee could not retrieve the basis for the instrument string inaccuracy and bistable tolerance values of 113.5" and 15.5" respectively that were used to establish consistency with the technical specification trip setpoint; and although the document performed the function of a calculation or analysis, it did not comply with the format and review requirements for calculation To verMy consistency of the setpoint calculation methodology, the team reviewed a subsequent revision to the instrument string data package arid Revision 3 of the setpoint calculation. On the basis of review of these tiocuments, the team determined that the BWST low-low level setpoint of 95" had adequate margin to-account for instrument error, valve stroke time, and operator delay, and to ensure that enough water from the BWST had been transferred to the containment to provide the minimum NPSH for the LPI_and containmentspraypumpstakingsuctionfromthecontainmenlemergencysum The team verified that the permissives and interlocks for the valves on the suction lines from the BWST and containment emergency sump were acceptabl i
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To resolve the team's concerns, the licensee indicated that document RfA 94-0509 would be reissued as a calculation and would include verification of assumptions and references. Also an evaluation of interfacing documents and other affected calculations would be performed. (Inspection follow-up Item 50-346/97-201-09)
The team also reviewed the BWST level instrument setpoints for high and low level alarms and determined that they were acceptable, Hioh Containment Pressure (SFAS Level 3) Actuation Setooint The containment pressure instrument loop provides input for the high containment pressure (SFAS Actuation level 3) permissive to initiate LPI operation. in the reviewed documents the team noted inconsistencies in the containment high pressure trip setpoint. TS Table 3.3-4 provided a trip setpoint of 18.4 psia, with an allowable value of 18.52 psia. Justification for these technical specification values were provided in Bechtel letter BT-11388, "TM1 Action Plan, Section ll.E.4.2, Containment Isolation Dependability," dated January 7, 1981. Instrument Data Package 59A-ISP2000, Revision 5, showed the actual calibrated setpoint as 17.4 psia, providing a margin of 1 psia. The licensee was unable to provide supporting documentation for this margin but considered 1 psia as a reasonable value to account for instrument loop inaccuracies, in addition to a built-in margin of 1 psia in the technical specifications as evaluated in the Bechtel letter. The team was concerned that no loop uncertainty calculation had been performed to document that the combined instrument inaccuracies would not exceed the setpoint margi The team noted that calculation C-ICE-48.01-001, " STAS Containment Pressure Actuation," Revision 0, established a loop accuracy value of 1.5 psia (which exceeded the 1 psia margin discussed above) and a setpoint of 18.625 psi However, the licensee stated that this calculation was intended to support a future licensing amendment that would implement a new setpoint and revised technical specification value The licensee acknowledged the weakness in the I&C calculation and indicated that this issue will be addressed as part of a planned DBD reconstitution program at D (Inspection Follow-up Item 50-346/97-201-10). RG 1.97 Indication for BWST level Emergency procedure DB-0P-02000 required monitoring of BWST level indicators L1-1525A, B C, and D, on the main control room vertical panel C5716 to permit manual switchover of the DH pump suction from the BWST to the containment emergency sump. The team noted that these indicators were powered from a Class lE bus and seismically mounted, but they were classified as non safety-related. The indicators are classified as a Type A, Category 1 variable requiring full Class IE qualification in accordance with RG 1.97 because they provide primary information to permit control room operators to take manual control action ____ _ _ _ _ _ _ _ _ _ _
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The team also noted that there were four other BWST level indicators (LI-1525A1, 81, Cl, and DI) located on the safety-related SFAS cabinets in the i main control room. The team considered it appropriate for the operators to l monitor the safety-related BWST level instruments during post-accident l conditions. The licensee initiated PCR 97-1397 to revise the procedure DB-0P-02000 to include monitoring of the safety-related level indicators in the SFAS cabinets when performing the DH pump suction switchover operation , Document Discrepancies The team identified the following document discrepancies:
- Drawing 05-004, Sheet 1, did not show the correct color coding and instrument symbols for FYIDH2A and FYIDH2 The licensee issued DCN OS-004-0054 to correct the drawin * Drawing E-30-23 showed an incorrect model number for containment pressure transmitter PT-2001. DCN E-30-23-35 was issued to delete this information from the drawing, because it was provided in H-720 * Section 1.2.1.3 of system description SD-042 stated that a safety-related alarm shall be provided if the dropline valves were open and power was not removed. The annunciator system is non-safety relate The licensee issued SDCN 42-02-004 to correct the system descriptio * Section 1.1.1.1 of system description S0-042, stated that valves DHil and DH12 were associated with pressure switch PSH-RC2B However, only valve DHil was interlocked with the pressure switch. The licensee issued SDCN 42-02-005 to correct this discrepanc El.3.4.3 Conclusions The team concluded that the instrumentation and control design for the LPI system was adequate. All setpoints that were reviewed had adequate margins and technical specification limits were met. However, some inconsistencies wre observed between the technical specifications, loop uncertainty calt.ulations, and data sheets. The basis for the current setpoint for BWST low-low level documented in RFA 94-0509 was not appropriately verified and approved, although the current setpoint was acceptable. The licensee initiated corrective actions for the discrepancies identified by the tea El.3.5 LPI System Walkdown El.3. Scope The team inspected the installed mechanical, electrical, and instrumentation and control equipment for the LPI system to evaluate their consistency with drawings, design specifications, and regulatory requirements. During the walkdown the team interviewed plant system engineers, and operations and maintenance personnel. The team walkdown covered the HPI pump rooms, DH
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cooler room, control room, auxiliary shutdown panel, BWST area, cable spreading room, switchgear rooms, battery rooms, and electrical distribution panel The results of the electrical walkdown are discussed in Section El.2.6 of this repor El.3.5.2 Findings
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1 Control of Temocrary Shieldina During the plant walkdown, the team noted a temporary shielding installation on a pipe near valve DH134 in decay heat cooler room 113. The line was currently not in use and had apparently become a potential crud trap. This .
shielding had temporary shielding request tag No. 94-0003, dated February 3, 1994, attached to it. This installation had been in place for over three year Request for assistance (RFA) 94-0042 that was issued to evaluate this temporary shielding installation was approved for temporary use on.y by Design Engineering / Civil on January 26, 1994. The team inquired whether this installation had been periodically reviewed and approved by engineering and whether the attachment of shielding to the piping was analyzed from the point of view of seismic II/I concerns. The licensee stated that the shielding had not been reviewed since its initial installation and that its attachment to the piping had not been seismically analyze The licensee reviewed the original calculation done in response to RFA 94-0042, and concluded that the RFA was still applicable for use on a temporary basis, and the attachment of the shielding to the piping considering the seismic loads was acceptabl Installation of temporary shielding was controlled by procedure DB-HP-01802,
" Control of Temporary Shielding." This procedure was currently in the process of being enhanced and will address the concerns raised by the inspection team regarding periodic review of installed temporary shielding packages to ensure installation requirements continue to be met, and inclusion of complete descriptions of the installation and fastening methods in the shielding request documents to ensure seismic considerations were fully understood by all_ parties involved in the preparation, review, and approval of these requests, BWST Level Transmitters The team reviewed the instrument installation details and instrument data packages and performed verification walkdowns of the BWST level transmitter The transmitters were properly spanned, compensated, and were calibrated to account for boron concentration and differences in elevation During the walkdown of the four BWST level transmitters in the valve pit and the shed next to the BWST, the inspection team noted that the transmitter mounting brackets, nuts, and bolts for transmitters LT-1525B and LT-1525C were severely rusted while the mounting hardware for LT-1525A and LT-15250 showed
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signs of_ corrosion to some_ degre The team was concerned that structural integrity of two of four transmitter supports could be degrade The licensee initiated work requests WR-97-1286 and WR-97-1247 to repair
- transmitters LT-1525B and LT-15250. . The team noted that PCAQR 94-0840 dated September 28, 1994, had previously identified corrosion of LT-15258 and Lil525-0 based on a seismic qualification walkdown of the components in the BWST pit,- and the licensee had concluded that the condition of the transmitter supports was acceptable. The licensee conducted another inspection on January 13, 1997, and _ concluded that the supports were still capable of meeting operability requirements. However, the team noted that the PCAQR and corresponding evaluations only addressed the transmitters in the BWST pit and did not include the two transmitters in the shed, one of which (LT-15250) had been severely corrode The licensee also issued work requests WR-97-1546 and WR-97-1550 to repair supports for transmitters LT-1525A and LT-15250. The team expressed its concern about the delays in initiation of corrective actions and the licensee stated that the focus was on rectifying water leakage in the pit which took a long time to accomplish and had delayed implementation of any corrective action-and closeout of the PCAQR. During the implementation of the work request, the licensee will examine the removed hardware to verify that the corrosion was not severe enough to have had the potential for failure of the support In this instance, the licensee's measures to assure that conditions adverse to quality are promptly corrected as required in 10 CFR 50, Appendix B, Criterion XVI, " Corrective Action," were not adequate. (Unresolved Item 50-346/97-201-11).
The team noted that some piping insulation and protective metal covers had been removed from the HPI pump recirculation and test return lines to the BWST and were left on the catwalk near DH-7A & B valve operators. The licensee stated that this material was wet at the time of inspection of the BWST valve pi The piping insulation should have been reinstalled in accordance with the maintenance work package in response to corrective actions for PCAQR 94-0840, but did not get included in the process. The licensee reinstalled the required piping insulation after the team questioned the acceptability of the uninsulated sections of the piping. The licensee stated that during the period without insulation, the piping heat tracing and use of space heaters in
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the area prevented potentitl freezing problems, Modification of Valves DH13A/B and DH14A/B Modification 87-1168 was implemented to replace the single-acting type actuators on DH cooler discharge valves DH13A/B and bypass valves DH14A/B with-double-acting type actuators. P&lD M-033A and drawing 0S-004 Sh.1 show the double-acting type actuators that agree with the as-installed condition, but instrument installation detail drawing Q-084 and the vendor drawing series M-329 still showed the old configuration with single-acting valve actuator The team noted that these drawings were not listed as affected documents in the modification package. It was noted that marked-up P&lD, isometric drawings and bills of materials were used to install the modificatio _ -. - _ .
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However, no installation detail drawing or a revision to drawing Q-084 was-included in the modification package. The installation was consistent with the information prcvided in the modification package and was acceptabl Section 6.6.2.f of plant modification procedure NG-EN-00301, states that the Planner shall verify that applicable documents, such as change notices, reflect the as-built cor. figuration and had been correctly updated as part of the post implementation / closeout process. The licensee acknowledged that in the modification closeout process drawing Q-084 was omitted in error, and initiated DCN Q-084-1 tt update the drawin The licensee stated that vendor drawings for the actuators and associated control tubing are classified as " fabrication" status, and are not required to be update XI Exit Meeting After completing the on-site inspection, the team conducteu an exit meeting with the licensee on June 20, 199 During the meeting the team presented the results of the inspectio A list of persons who attended the exit meeting is contained in Appendix B.
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APPENDIX A OPEN ITEMS This report categorizes the inspection findings as unresolved items and inspection follow-up items in accordance with the NRC Inspection Manual, Manual l Chapter 0610. An unresolved item (URI) is a matter about which more information is required to determine whether the issue in question is an acceptable item, a deviation, a nonconformance, or a violation. The NRC Region 111 office will-issue any enforcement action resulting from their review of the identified unresolved items. An inspection follow-up item (IFI)
is a matter that requires further inspection because of a potential problem, because sprific licensee or NRC action is pending, or because additional information is needed that was not available at the time of the inspection, item Number f.inding Title Iyat 50 346/97-201-01 If I HPI Flow Requirements for SG Tube Rupture Accident (Section El.2.2.2.a.)
50-346/97-201-02 IFI Safety Class Interface at Pressure Gage Isolation Valves (Section El.2.2.2.d.)
50-346/97-201-03 IFl Environmental Qualification of Equipment in ECCS Rooms (Section El.2.2.2.f.)
50-346/97-201-04 IFl Battery Charger Surveillance Testing (Section El.2.3.2.a.)
50-346/97-201-05 IFl Testing of Inverter and Associated Components (Section El.2.3.2.b.)
50-346/97-201-06 URI USAR Discrepancies (El.2.7)
50-346/97-201-07 URI Reverse flow Testing of LPI Pump Check Valves and HPl Pump Recirculation Stop-Check Valves (Section El.3.2.2.c.)
50-346/97-201-08 IFI ECC5 teakage Testing (El.3.2.2.c.)
50-346/97-201-09 IFl BWST Low-Low Level Setpoint Calculations (El.3.4.2.a.)
50-346/97-201-10 IFl High Containment Pressure Actuation Setpoint (El.3.4.2.b.)
50-346/97-201-11 URI Corrective Action for BWST Level Transmitter Support Corrosion (El.3.5.2.b.)
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APPENDIX B EXIT MEETING ATTENDEES ORGANI7ATION ME Toledo Edison J. Stetz Senior V.P., Nuclear-J. Wood V. P., Davis-Besse J. Lash Plant Manager T. Myers Director, Nuc. Support Services R. Donnellon Director, Engineering and Services .,
F. Swanger Manager, D-B Engineering J, Freels Manager, Reg. Affairs J. Rogers Manager, Plant Engineering H. Stevens Manager, Nuclear Safety & Inspections D. Lockwood Supervisor, Compliance C. Kraemer Engineer, Compliance A. Stallard Sr. Ops. Advisor J. Harsigan Sr. Staff Engineer, DBE K. Prasad Sr. Staff Engineer, DBE J. Marley Sr. Engineer, Plant Engineering A. Wise Sr. Engineer, Plant Engineering R. Hovland Sr. Engineer, Plant Engineering G. LeBlanc Sr. Engineer, DBE P. Jacobsen Sr. Engineer, DBE NfLC M. Ring Chief, Engineering Brech, Region III D. Norkin Chief,' Special Inspection Section, NRR M. Miller Reactor Engineer, Region III S. Stasek Sr. Resident Inspector Team Leader, NRR S. Malur A. Bizzara Contractor, S&L M. Sanwarwalla Contractor, S&L R. Jason Contractor, S&L K. Steele Contractor, S&L L. Rogers Contractor, S&L
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_ APPENDIX C LIST OF ACRONYMS AB Auxiliary Building AC Alternating Current A0V Air-Operated Valve ASME American Society of Mechanical Engineers AT0G Abnormal Transient Operating Guidelines AUX S/D Auxiliary Shutdown AUX Auxiliary AUX S/D PN Auxiliary Shutdown Panel B& Babcock & Wilcox BS -Building Spray BTU British Thermal Unit BWST Borated Water Storage Tank CF Core Flood CFR Code of Federal Regulations CFT Core Flood Tank CTMT Containment CV Control Valve CVT Constant Voltage Transformer DB Davis-Besse DBA Design Base Accident DBD Design Basis Documentation DBMMS Davis-Besse Maintenance Management System DBNPS Davis-Besse Nuclear Power Station DC Direct Current DCN Drawing Change Notice DCR Document Change Request DH Decay Heat DHR Decay Heat Removal DHRS Decay Heat Removal System DP Differential Pressure .
EcCS Emergency Core Cooling System EDG Emergency Diesel Generator EDSFI Electrical Distribution System Functional Inspection E0P Emergency Operating Procedure
EQ Environmental Qualification ESF- - Engineered Safety Features ESFAS Engineered Safety Features Actuation System f Fahrenheit FCN Field Change Notice FCR Facility Change Request FCV Flow Control Valve ft., FT Feet or Foot FW Feed Water gal . , GAL Gallons gpm., GPM Gallons Per Minute C-1
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t HELB High Energy line Break FP High Pressure FPI High Pressure Injection FS Hand Switch !
kVAC Heating, Ventilating, and Air Conditioning HZ, Hz Hertz I&C Instruments and Control IFI Inspection follow-up It+.m ILRT Integrated Leak Rate Test IN Information Notice 151 In Service Inspection .
IST in Service Testing kVA Kilovolt-Ampere LAR License Amendment Request LC0 Limiting Condition for Operation
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LER Licensee Event Report LOCA Loss-of-Coolant Accident LOOP Loss-of-Offsite Power LP Low Pressure LPI Low Pressure injection M/HELB Moderate /High Energy Line Break M&TE Measuring and Test Equipment MCB Main Control Board MCC Motor Control Center MF Main feedwater MOV Motor Operated Valve MS Main Steam MU1P Make-Up and Purification MWO Maintenance Work Order NC Normally Closed NG Nuclear Group Procedure NNI Non-Nuclear Instrumentation NNS Non-Nuclear Safety NO Normally Open NPSH Net Positive Suction Head NRC Nuclear Regulatory Commission NSR Nuclear Safety Related NSSS Nuclear Steam Supply System OTSG Once Through Steam Generator P&lD Piping & Instrumentation Diagram
'PAM Post Accident Monitoring PB Piggy-Back PCAQ Potential Condition Adverse to Quality PCAQR Potential Condition Adverse to Quality Report PI Pressure Indicator PIC Pressure Indicator Controller PM Preventive Maintenance PMT Post Maintenance lesting PMWO Preventive Maintenance Work Order PORV Power Operated Relief Valve PRA Probabilistic Risk Assessment psi, PSI Pounds per Square inch C-2
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psia, PSIA Pounds per Square Inch Absolute psid. PSID .
Pounds per Square-Inch Differential psig -PSIG- Pounds per Square Inch Gauge PT Pressure Transmitter PVC Polyvinyl Chloride QA Quality Assurance R Reactor Building RC Reactor Coolant RCP Reactor Coolant Pump RCS Reactor Coolant System REV Revision RFA Request for Assistance R Regulatory Guide .
RPS Reactor Protection System RV Reactor Vessel S&L Sargent & Lundy S\D Shutdown SA Safety Actuation SCFM Standard Cubic feet per Hour-SCN Specification Change Notice SDCN System Description Change Notice SE Safety Evaluation SEC Seconds SER Safety Evaluation Report SF Spent fuel SFAS Safety Features Actuation System SFPP Spent Fuel Pool Pump SG Steam Generator SOV, SV Solenoid Operated Valve SPDS Safety Features Display System SPEC Specification SSFI Safety System functional Inspection SW Service Water TCV Temperature Control Valve TDH Total Developed Head
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TM Temporary Modification TMH Temporary Mechanical Modification TR Temperature Recorder TS, Tech, Spe Technical Specifications TT Temperature Transmitter UPS Uninterruptible Power Supply URI Unresolved Item USAR Updated Safety Analysis Report V DC, VDC Volts DC V AC, VAC Volts AC W Watts
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