IR 05000373/1997023

Insp Repts 50-373/97-23 & 50-374/97-23 on 971222-980306. Violations Noted.Major Areas Inspected:Engineering

ML20217D067
Person / Time
Site:	LaSalle
Issue date:	03/23/1998
From:	Jeffrey Jacobson NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION III)
To:
Shared Package
ML20217D010	List: ML20217D008 ML20217D061 ML20217D067
References
50-373-97-23, 50-374-97-23, NUDOCS 9803270293
Download: ML20217D067 (11)

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U.S. NUCLEAR REGULATORY COMMISSION REGIONlli Docket Nos: 50-373;50-374 License Nos: NPF-11; NPF-18 Report Nos: 50-373/97023(DRS); 50-374/97023(DRS)

Licensee: Commonwealth Edison Company Facility: LaSalle County Station, Units 1 and 2 Location: 2601 N. 21st Road Marseilles,IL 61341 Dates: December 22,1997, through March 6,1998 Inspector: Eric Duncan, Reactor Engineer Approved by: John M. Jacobson, Chief Lead Engineers Branch Division of Recctor Safety I l

9803270293 980323 PDR ADOCK 05000373 O PDR

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- EXECUTIVE SUMMARY LaSalle County Station, Units 1 and 2 NRC inspection Report 50-373/97023(DRS); 50-374/97023',DRS)

Engineering

• The inspector reviewed the licensee's response to information Notice 87-10 related to the potent;al for waterhammer in the residual heat removal (RHR) system if a Loss-Of-Coolant-Accident (LOCA) concurrent with a Loss-Of-Offsite-Power (LOOP) were to occur while the system was aligned for suppression pool cooling. (Section E8.1)

e- Allowable tolerances in the construction of the drywell may cause a delay in leakage entering the floor drain sump for detection. However, technical specification leakage requirements would be still be met assuming the worst case drywell floor holdup volum (Section E8.2)

e The shell side of the Unit 1 and Unit 2 RHR pump seal coolers did not meet design pressure requirements and were not procured as required by 10 CFR 50, Appendix B, Criterion IV," Procurement Document Control." _ (Section E8.3)

e A design modification to add screens to the Unit 2 floor and equipment drain sumps to prevent foreign material intrusion into the sump piping and containment isolation valves was not controlled as required by 10 CFR 50, Appendix B, Criterion ill, " Design Control."

(Section E8.4)-

k Report Details Exercise of Enforcement Discretion

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A violation described in Section E8.3 of this report is based upon licensee activities which were

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identified after, but occurred prior to the licensee announcing, in December 1996, an extended I shutdown of the LaSalle County Station. This violation satisfies the appropriate criteria in l Section Vll.B.2," Violations identified During Extended Shutdowns or Work Stoppages," of the J

" General Statement of Policy and Procedures for NRC Enforcement Actions,"(Enforcement l

Policy), NUREG-1600, and a Notice of Violation is not being issued for this violation because the criteria specified in Section Vll.B.2 were met, which allows enforcement discretion to be applied. Specifically, the violation was licensee-identified as a result of a comprehensive j program for problem identification and correction that was developed in response to the shutdown, the violation would not be categorized at a severity level higher than Severity Level ll, and the violation was not willful. In addition, actions specified in Confirmatory Action Le#er ,

Rlll-96-0088 effectively prevent the licensee from starting up LaSalle County Station witl at implicit NRC approva Ill. Engineering E8 Miscellaneous Engineering issues E (Ocen) Insoection Follow uo item 50-373/97013-01: 50-374/97013-01: Review of Information Notice 87-1 As discussed in inspection report 50-373/97013; 50-374/97013, the inspector reviewed the licensee's response to Information Notice 87-10 related to the potential for waterhammer in the RHR system if a Loss-Of-Coolant-Accident (LOCA) concurrent with a Loss-Of-Offsite-Power (LOOP) were to occur while the system was aligned for suppression pool coolin j As part of that effort, the inspector reviewed the RHR waterhammer analysis prepared by Sargent & Lundy (S&L) which concluded that although a waterhammer would occur, I the RHR system would maintain its pressure boundary integrity, structural stability, and functional capability during the waterhammer event. The inspector questioned the methodology which the licensee employed in the calculation including the basis for the 1 assumptions made and the basis for the analysis acceptance criteria. Inspection follow )'

up item 50-373/97013-01; 50-374/97013-01 was opened pending further NRC revie During this inspection, the inspector obtained the Office of Nuclear Reactor Regulation's i (NRR) respon.se to Task Interface Agreement (TIA) 96-0389, " Quad Cities, Unit 1 and 2, I Regarding NEDC-32523 Applicability to RHR Water Hammer Potential," dated October 12,1997. In that response, NRR stated the following:

. In accordance with General Design Criteria 35," Emergency Core Cooling,"

licensees are required to address unavailability of either onsite or offsite power (whichever is more limiting) concurrent with a LOCA and the consequences of

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the event. If the loss of offsite power is more limiting, the licensee is required to consider the LOOP concurrent with a LOC .

Since the probability of a waterhammer event increases as the amount of time the system is operated in the suppression pool cooling (SPC) mode increases, and the likelihood of damage to the system increases with the frequency of waterhammer events, operating in the SPC mode more often that assumed in the Updated Final Safety Analysis Report (UFSAR) may be an unreviewed safety questio .

If licensee's determine that the frequency of use of the SPC mode of RHR is greater than that assumed in the UFSAR, then LOCA occurrence during SPC mode should be postulated and the corresponding draindown and waterhammer should be addresse Therefore, based on the discussion in TIA 96-0389, a waterhammer analysis was not ,

required if operation in the SPC mode of RHR was less than that assumed in the i UFSAR. The inspector discussed this information with licensee personne Subsequently, the inspector determined that although no specific amount of time spent f in shutdown cooling was addressed or prescribed in the UFSAR, historically the time j spent in this configuration was low which indicated that a valid waterhammer analysis i may not be required. At the end of the inspection, the licensee was in the process of establishing a maximum SPC operation limit, above which an acceptable waterhammer analysis would be require This item will remain open pending NRC review of this established operation limi E8.2 (Closed) Licensee Event Reoort (LER) 50-373/97021-00: Undrainable Low Areas in the Drywell Floor Resulting in a Degradation of the Leak Detection System (LDS) Due to increased Delays in Detection of Unidentified Leakag As discussed in inspection report 50-373/97013; 50-374/97013, and LER 50-373/97021-00, the licensee determined that the ability of the drywell floor to  !

accumulate water was inconsistent with the UFSAR description. Specifically, the licensee's response to UFSAR question 212.17 stated that there were no undrainable low points in the primary or secondary containment which would result in a delay in the detection of leakage. Contrary to this description, there were undrainable areas which would result in the delay of the detection of leakag During the licensee's investigation of this problem, an additional problem related to the reliability of instrumentation associated with portions of the LDS was identifie Regulatory Guide 1.45 required that the sensitivity and response time for the LDS should be adequate to identify a leakage rate of 1 gallon per minute (gpm) in less than 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br />. To meet this requirement, a capacitance probe was used to measure instantaneous sump level which is electronically converted to a flow rate. However,

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operating experience had demonstrated that the capacitance probe frequently drifted and was unreliable. As a result, the recurrent failure of the electronic level indication resulted in the LDS not meeting design basis requirement As part of the licensee's immediate corrective actions, the LDS was declared inoperabl In addition, the licensee planned the following long-term actions:

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Resolution of the discrepancy between the as-built configuration of the plant and the description contained in response to UFSAR question 212.1 Improving the reliability of the sump level monitoring instrumentatio Confirming that there were no other hold up volumes in the containment which could result in unacceptable delays in the detection of unidentified leakag During this inspection period, the licensee reviewed documents associated with the as-built configuration of the plant and identified that the floor of the Unit 1 and Unit 2 drywells were poured to conform to American Concrete Standard (ACl) 301-72,

" Specifications for Structural Concrete for Buildings," as required by S&L Standard Specification for Concrete Work (Form 1715-Q) and were certified by quality control )

inspectors on the " pour checkout cards." Table 4.3.1 of ACI 301-72 allowed up to a 3/4- !

inch variation from the level or from the grades specified in the contract document Therefore, although the UFSAR stated that there were no undrainable low points in the primary or secondary containment which would result in a delay in the detection of leakage, in fact, there was a potential that holdup volumes in the drywell floor may exist, which would delay the detection of RCS leaksg The licensee reviewed this information and subsequently determined that assuming a worst case with the floor drain 3/4 inch above all the rest of the floor and that 15 percent of the floor was taken up with equipment mounting, then the calculated holdup volume was about 1800 gallon '

Technical Specification (TS) 3/4.4.3.2, " Reactor Coolant System Operational Leakage,"

required that RCS leakage shall be limited to a 2 gpm increase in unidentified leakage over any 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> period. The inspector verified that given a 2 gpm leakage rate, and assuming a worst case holdup volume, that the leakage would be conducted to the floor drain sump well within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />, and therefore the ability for detection to meet the requirements of TS 3/4.4.3.2 would still be presen The inspector concluded that allowable tolerances in the construction of the drywell may cause a delay in leakage entering the floor drain sump for detection, although the licensee indicated in the UFSAR that there were no undrainable low points in the primary or secondary containment which would result in a delay in the detection of leakage. However, the inspector also concluded that technical specification leakage requirements would be still be met assuming the worst case drywell floor holdup volum However, it also appeared that the as-built construction of the drywell may be outside the plant's licensing basis since undrainable low points may exist in the drywell although

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the UFSAR stated that there were no undrainable low points in the primary containmen Resolution of the discrepancy between the as-built configuration of the plant and the description in the UFSAR as well as improvements to sump level monitoring i

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instrumentation is an unresolved item (URI 50-315/97023-01(DRS);

50-316/97023-01(DRS)) pending NRC review of the licensee's corrective action E8.3 (Closed) LER 50-373/98018-00: RHR Pump Seal Coolers Do Not Meet Design Pressure Requirements Because Requirements Were Not included in Original Purchase Specification to Pump Manufacture As discussed in the subject LER, the licensee identified that the shell side of the Unit 1 and Unit 2 RHR pump sea! coolers did not meet design pressure requirement Specifically, the licensee determined that the shell side of the coolers had a design

' pressure of 75 pounds per square inch gauge (psig) although the design pressure of the RHR Service Water (RHRSW) system that supplied the cooling water had a design pressure of 150 psi The licensee performed a root cause investigation and determined that the coolers were purchased during initial plant construction without regard to pressure requirements and that, as a result, the coolers were procured with a shell side design pressure of 75 psig (which was about normal system operating pressure) vice the 150 psig design pressure requirement To determine the significance of this event, the licensee obtained the hydrostatic testing results for the cooler casings and determined that although the coolers were rated at 75 psig, they were able to withstand significantly higher pressures. Specifically, in addition to successfully hydrostatically testing each cooler's casing to twice the design pressure, the manufacturer had also performed a hydrostatic test to destruction of an identical cooler casing. The destruction test pressure where the casing was first noted to be leaking was found to be 450 psig. The licensee concluded that the seal coolers would not fall catastrophically when exposed to a pressure of 150 psig and would remain intact and operationa As part of the licensee's corrective actions, the affected seal coolers were replaced with coolers rated at a design pressure of 150 psig. In addition, the licensee verified that similar procurement problems did not exist for other cooler The inspector reviewed this event and verified that modifications were installed to replace the cast iron RHR seal coolers with cast steel seal coolers which met system design pressure requirements. In addition, the inspector reviewed the hydrostatic test results for the coolers removed as well as the replacement coolers and had no additional concem CFR 50, Appendix B, Criterion IV," Procurement Document Control," required that measures shall be established to assure that the applicable regulatory requirements, design bases, and other requirements which are necessary to assure adequate quality are suitably included or referenced in documents for procurement. The failure to include

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l in procurement documents for the Unit 1 and Unit 2 RHR seal coolers specifications regarding shell side design pressure was an example where the requirements oi10 CFR 50, Appendix B, Criterion IV, were not met and was a violation. However, because this violation was based upon activities prior to the events leading to the ,

current extended plant shutdown and satisfy the criteria in Section Vll.B.2," Violations l

Identified During Extended Shutdowns or Work Stoppages," of the " General Statement '

of Policy and Procedures for NRC Enforcement Actions"(Enforcement Policy), NUREG-1600, a Notice of Violation is not being issued (50-373/97023-02; 50-374/97023-02). l Specifically, the violation was licensee-identified as a result of a comprehensive program I for problem identification and correction that was developed in response to the shutdown, the violation would not be categorized at a severity level higher than Severity Level ll, and the violation was not willful. In addition, actions specified in Confirmatory Action Letter Rlll-96-0088 effectively prevent the licensee from starting up LaSalle I County Station without implicit NRC approval.

E8.4 (Closed) LER 50-374/95006-00: 50-374/95006-01: Primary Containment Maximum Allowable Leakage Exceeded Due to Local Leak Rate Test (LLRT) Failur As discussed in the subject LER, the licensee identified on March 20,1995, that the Unit 2 maximum allowable primary containment leakage rate was exceeded during th3 performance of a Local Leak Rate Test (LLRT). Specifically, the 2RE024 and 2RE025 Drywell Equipment Drain (RE) Sump containment isolation valves had been leak rate tested and the leak rate was determined to be excessive (test volume could not be pressurized). The cause of the leakage was determined to be seat leakage through both valves. Upon inspection, the seat was found damaged due to foreign materia As part of the licensee's corrective actions, both valves were repaired and successfully leak rate tested. In addition, a plant modification was performed which installed permanent screens in the floor drain and equipment drain sumps to prevent foreign materialintrusion into the RE piping and isolation valve The licensee concluded that since the drywell RE sump would normally be filled with l water which would tend to seal any air leakage, the safety significance of the event was I minimal. In addition, the licensee concluded that in the event that air leakage eventually l occurred through the containment isolation valves, the downstream piping was normally filled with water and provided additional isolation with normally closed automatic valves that are designed to open with pump flo l The inspector reviewed this event including design change packages (DCPs) 9500086 l (Unit 1) and 9500087 (Unit 2) which controlled the installation of the foreign material exclusion (FME) screens in the floor drain and equipment drain sumps. The inspector reviewed the modification package for Unit 1. No deficiencies were identified. However, the inspector noted the following weaknesses regarding the licensee's implementation of the modification on Unit 2:

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Unit 2 Drawings Were Not Upoated as Appropriate The inspector identified that although Piping and Instrumentation Drawings (P&lDs) associated with the floor and equipment drain system had been updated to reflect the addition of the screens on Unit 1, similar drawings for Unit 2 had not been updated to reflect the chang .

The Unit 2 Design Change Package Was inappropriately Canceled Although the Unit 1 DCP (9500086) was statused as complete, the Unit 2 DCP (9500087) was statused as canceled. Upon further review, the inspector identified that although the work was documented in the Electronic Work Control System (EWCS) as accomplished and had been accomplished according to the cognizant system engineer, the DCP was canceled on March 20,1997, because the DCP could not be located following completion of the work. As a result, documentation associated with the work was not available for revie I The inspector discussed this information with licensee personnel. As a result, Problem Identification Form (PlF) L1997-07512 was initiated to document the issue. At the end I of the inspection, the licensee planned to re-construct a new DCP to identify any required post-modification inspections, revise drawings as appropriate, and perform a walkdown of the syste The inspector concluded that the design of the modification to add screens to the Unit 1 and Unit 2 floor and equipment drain sumps was good. In addition, no deficiencies were identified in the implementation of the modification on Unit 1. However, the inspector also concluded that the implementation of the modification on Unit 2 was poor since the DCP was canceled when the DCP paperwork could not be located and design drawings were not updated to reflect the installation of the modificatio The inspectors determined that the design modification to add screens to the Unit 2 floor and equipment drain sumps was not controlled as required by 10 CFR 50, Appendix B, Criterion 111, " Design Control," and was a violation (50-374/97023-03(DRS)).

This LER is close E8.5 [Clqged) LER 50-373/96021-00: Inadequate Review of Modification of Main Control Room Atmospheric Control System Radiation Monitoring Logic Results in an Unreviewed Safety Questio This event was discussed in inspection report 50-373/97003; 50-374/97003. No new issues were revealed by the LE This LER is close VI. Management Meeting X1 Exit Meeting Summary

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The inspector presented the results of these inspections to licensee management at an exit meeting on March 6,1998. The licensee acknowledged the findings presente The inspector asked the licensee if any materials examined during the inspection should be considered proprietary. No proprietary information was identifie I

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PARTIAL LIST OF PERSONS CONTACTED l Comed l F. Dacimo Site Vice President  !

G. Poletto Site Engineering Manager E. Connell Design Engineering Supervisor  :

R. Palmieri System Engineering Supervisor l P. Bames Regulatory Assurance Manager i J. Damron System Engineering G. Kats System Engineering '

INSPECTION PROCEDURES USED IP 37550 Engineering  !

IP 37551 Onsite Engineering IP 90712 In-Office Review of Written Reports of Nonroutine Events at Power Reactor Facilities i IP 92700 Onsite Follow-Up of Written Reports of Nonroutine Events at Power Reactor l Facilities l

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ITEMS OPENED, CLOSED, AND DISCUSSED Opened 50-373/97023-01; 50-374/97023-01 URI Floor and Equipment Drain System Sump Level Monitoring Problems 50-373/97023-02; 50-374/97023-02 NCV RHR Pump Seal Coolers Do Not Meet Design Pressure Requirements 50-373/97023-03; 50-374/97023-03 VIO Inadequate Drywell Sump Screen Modification Closed 50-373/97021-00 LER Undrainable Low Areas in the Drywell Floor Resulting in a Degradation of the LDS 50-373/96018-00 LER RHR Pump Seal Coolers Do Not Meet Design Pressure Requirements 50-374/95006-00; 50-374/95006-01 LER Primary Containment Maximum Allowable Leakage Exceeded Due to LLRT Failur /96021-00 LER Inadequate Review of Modification of MCR Atmospheric Control System Radiation Monitoring Logic Discussed 50-373/97013-01; 50-374/97013-01 IFl Review of Information Notice 87-10

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LIST OF ACRONYMS USED ACI American Concrete Institute ASME American Society of Mechanical Engineers CFR Code of Federal Regulations DCP Design Change Package DRS Division of Reactor Safety EWCS Electronic Work Control System FME Foreign Material Exclusion gpm gallons per minute IFl Inspection Follow up item LDS Leak Detection System LER Licensee Event Report LLRT Local Leak Rate Test LOCA Loss Of Coolant Accident LOOP Loss Of Offsite Power NCV Non-Cited Violation NRR Office of Nuclear Reactor Regulation PDR Public Document Room -

P&lD Piping and Instrumentation Drawing PIF Problem Identification Form psig pounds per square inch gauge RCS Reactor Coolant System RE Drywell Equipment Drain System RHR Residual Heat Removal RHRSW Residual Heat Removal Service Water S&L Sargent & Lundy SPC Suppression Pool Cooling TIA Task Interface Agreement TS Technical Specification UFSAR Updated Final Safsty Analysis Report URI Unresolved item

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