IR 05000373/1989018

SSFI Repts 50-373/89-18 & 50-374/89-18 on 890724-1010. Violations Noted.Major Areas Inspected:Hpcs Sys & Licensee self-initiated Audit of HPCS Sys

ML19332D604
Person / Time
Site:	LaSalle
Issue date:	11/15/1989
From:	Hasse R, Huber M, Mendez R, Phillips M, Weiss E, Yin I NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION III)
To:
Shared Package
ML19332D600	List: IR 05000373/1989018 ML19332D599 ML19332D602
References
50-373-89-18, 50-374-89-18, IEIN-83-08, IEIN-88-024, IEIN-89-007, NUDOCS 8912050011
Download: ML19332D604 (37)

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U. S. NUCLEAR REGULATORY COMMISSION

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. Report Nos.!50-373/89018(DRS);.50-374/89018(DRS)

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. Docket: Nos. ! 50-373; 50-374 License Nos. NPF-11;.NPF-18-D

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Licensee:-

Commonwealth Edison Company.

i Post Office Box-767-s Chicago,-IL;60690

Facility Name:? LaSalle-County Station, Units 1 and 2 InspectionAtilCommonwealthEdisonOffices, Chicago, Illinois

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LaSalle Site, Marseilles,' Illinois im,

Inspection Cond ted

. J rough October 10, 1989

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l Inspectors:i P. Phil '

.s,! Team Leader

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Date M.P,$H5ber-

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R. Mendez:

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Date R. AL Hasse Y/Y/87

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I l Consultants:

R. :Spil ker H. Stramberg

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Lundgren

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Reviewed By:

ss, ting Chief h/fgfy

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Operations Branch Date i

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. Inspection' Summary

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Inspection 'on July 24 t'hrough October 10, 1989 (Report No. 50-373/89018(DRS);

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and No. 50-374/89018(DRS))

Areas Inspected:

Announced Safety System Functional Inspection (SSFI) of ithe high pressure-core spray (HPCS) system and evaluation of the licensee's self-initiated Safety System Audit of the same system.

The inspection was conducted using inspection procedure 93801.

-Results:

Based on the inspection, the team made the following conclusions:

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The HPCS was operable; however, the unresolved item rehted to component

operability at battery minimum voltage could affect HPCS operability _

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(Section~ 4.1.2.3)'.

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There were several examples where the actual design margins were less

than stated-in the Updated Final Safety Analysis Report (UFSAR) or in

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conflict with the Technical Specification requirements. Sections 4.1.1'.1, 4.1~.1.2, 4.1.1.3, and 4.1.2.1).

The performance of safety evaluations for the most part was acceptable;

however, the evaluation performed for nodification M-1-1-84-019 was

. inadequate and may have resulted in the performance of the modification despite the presence of an unreviewed safety' question.

Plant procedures

also did not properly reflect this modification.

(Sections 4.1.4.2 and i

4.4.1).

l The licensee's program for check valve maintenance was considered a

strengtn.

In addition, the implementation of the IST program and

logical functional testing programs were acceptable.

(Sections 4.3.6 and 4.3.7).

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The-SSFI. conducted by Commonwealth Edison in 1987 on this same system did an

excellent job of finding and correcting labeling problems and most drawing

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concerns. The effort was conducted by a multi-disciplinary team composed of 1-individuals experienced in electrical and mechanical design.

However, this SSFI was heavily criented toward walkdowns of the system and review of. completed modifications and-maintenance performed on the system. The evaluation contained two major limitations that contributed to not identifying the items found by the NRC inspection. These limitations were (1) the assumption that the existing surveillance procedures covered all applicable Technical Specification surveillance requirements and (2) the assumption that all l

activities associated with the original design and installation were i

acceptable. The Task Force formed by Commonwealth Edison to evaluate the i

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cffectiveness_of licensee SSFIs had also recognized this latter limitation j

l1 and had recommended that future efforts SSFIs be expanded to incorporate some amount of original design validation.(Section 4.7.1).

'The. team identified seven open items, four unresolved items, and nine

-violations of NRC Rules and Regulations. Of these violations, five

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. met the criteria of 10-CFR Part 2 Appendix C, for non-issuance of a

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Notice of Violation. The remaining four violations dealt with an inadequate 10 CFR 50.59 evaluation (Section 4.1.4.2); inadequate l

post-calibration test (Section 4.2.1.3); inadequate procedure for l

diesel generator fuel pressure surveillance (Section 4.3.5); and i

inadequate corrective actions for the 2B diesel-generator air start solenoid valve (Section 4.6.2).

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'The'four: unresolved' items dealt with whetherfthe batteries, battery

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. racks, and chargers meet:the requirements of-10 CFR Part 50, Appendix B

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(Section~4.1.2.0); whether!the installed ~ equipment will operate at.the

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minimum voltage they will experience during an event-(Section 4.1.2.3);

whet er the~ iese -generator skid wiring conforms with'the standards of

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i IEEE 383-1974 (Section 4.1.2.5); and whether-the implementation of D'

modification M-1-1-84-019 created an unreviewed safety question

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I (Section 4.1.4.2).

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= SUMMARY.OF SIGNIFICANT INSPECTION FINDINGS The Safety' System Functional Inspection at the LaSalle County Nuclear

Station; reviewed the design basis, operating history, maintenance history, surveillance history, and self-SSFI of the High Pressure Core' Spray System and concluded that the system was functional.

During the course of the inspection, as detailed in Section 4 of this report,.theLteam identified seven open items, four unresolved items,

and nine. violations of NRC Rules.and Regulations.

Of these violations,

.five met the criteria of'10 CFR Part 2, Appendix C, for non-issuance of La Notice of Violation.

In addition, the team evaluated the effectiveness

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of the licensee's self-SSFI on the same system for Unit 2.

-The design evaluation determined that the basic design was satisfactory and no common mode failures were detected; however, there were several examples where the actual! design margins were less than stated in the Updated Final Safety Analysis Renort (UFSAR) or in conflict with the Technical Specification (TS) requirements.

For example, the station batteries were designed to operate at temperatures above 65 F; however, the TS allowable minimum temperatures were as low as 50 F for the battery room and 60 F for the battery cells.

At these lower temperatures, some of the station batteries would not have been capable of performing their

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The team verified that the batteries had not reached

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sufficiently low temperatures to render them inoperable since initial licensing.

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The team was unable to determire if all equipment would be operable at

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minimum dc voltages that could oe experienced during an event.

This unresolved issue has the potential to render the system inoperable.

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~ The performance ofLsafety evaluations for the most part was acceptable;-

however,:the evaluation. performed for modification M-1-1-84-019 was

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-inadequate:and may have resulted in the performance of the modification j

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despite the presence of an unreviewed safety question.

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.For th'e'most part, relays that were examined were set in accordance with station requirements;-however, two exceptions were identified.

In one case, the different_ setting did not compromise the effectiveness of the

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associated relay;.however, the overcurrent relay for phase B of bus 243-1

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was sufficiently out of. tolerance that a failure of the phase A relay

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would have resulted in no overcurrent protection'for this bus.

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'Theclicensee's program for check valve maintenance was considered a-i strength.

In addition,.the implementation of the IST program and logic-functional testing programs were acceptable.

Weaknesses-were found relating _to the review of design calculations, I

establishment of electrical QC hold points, incorporation of vendor recommendations in diesel generator maintenance, and technical review of

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work requests.to ensure proper post-maintenance testing is performed.

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The. licensee's self-SSFI was conducted by a multi-disciplinary team

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The self-SSFI was heavily oriented toward walkdowns of the system and review of completed modifications and maintenar.ce performed on the system.

i-Findings from the self-SSFI primarily involved labeling / drawing deficiencies.

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These appeared to have been cerrected prior to the NRC effort, since such

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discrepancies were not identified by the NRC team.

The self-SSFI contained i

= two major limitations that were attributed to be the cause for i-non-identification of the items.found by the NRC. These limitations were i-(1)-the methodology for evaluating surveillance requirements and (2).the

assumption that all activities associated with original design / installation

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The licensee had recognized this latter limitation, and

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- had recommended-that future self-SSFIs not be so limited.

However, based j1

on the NRC team's findings, these self-SSFIs conducted prior to the i

implementation of.the Task Force recommendation should not be exclusively l

relied upon-to assure system operability.

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24.0 DETAILED INSPECTION FINDINGS The-team conducted in-depth reviews in a number of areas, which are described below.

The team identified a number of concerns, along

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with several positive items.

Each is discussed below:

l 4.1. System Design and Modificatio_n_s J

4.l.1 Mechanical Systems Design l

This portion of the inspection consisted of a detailed review of the HPCS system, pump room and diesel generator cooling, cycled condensate storage, fuel oil for the HPCS diesel generator, fire protection, stacion heating, and associated ventilation systems.

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The inspection focused on whether there was a potential for common c

b mode-. failures _of the ECCS. The mechanical systems design evaluation determined that the basic design was satisfactory and no common mode

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failures were detected; however, the following six issues were identified,

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!which' include examples where the actual design margins were less than Df stated in the Updated Final Safety Analysis Report (UFSAR):

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-4.1.1.1 HPCS Diesel Generator Fuel pi_1_ Consumption C'

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b Changes in the HFCS Diesel Generator electrical loading were not J

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$j factored into the fuel oil consumption rate that formed the basis for the fuel oil storage requirements.

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UFSAR'Section 9.5.4.1.1 specified the safety design bases for the F

HPCS fuel oil storage. Table 8.3.1 in the UFSAR listed the loads on the HPCS diesel generator, and identified the maximum diesel

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loading as 3280 bhp. However, the associated storage capacity

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calculation, D0-7, dated 3/11/76, calculated the seven day fuel F

oil storage requirement based on a maximum diesel loading of j

s 3087 bhp. Based on the larger diesel generator loading, the fuel

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oil consumption rate increased, which in turn increased the fuel j

oil storage requirements..There was no evidence that the increase

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was ever factored into the design.

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The licensee acknowledged the increased consumption (500 gallons for: the seven day storage requirement) but stated that it was included

_incthe 1000 gallon margin identified in the UFSAR Section 9.5.4.1.1.d.3.

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.The licensee agreed to revise the UFSAR to indicate that the margin i

'had been reduced-to 500 gallons. This will be tracked as an Open l

Item.(373/89018-01;374/89018-01).

j The-team determined that sufficient capacity was available in the HPCS fuel oil storage tank to meet the increased fuel consumption st.ch that minimum storage requirements need not be modified.

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the failure of the licensee to adequat.ely address-the interface

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between the diesel loadings and fuel requirements points to weakness

in the interdisciplinary engineering review of original design

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assumptions.

E 4.1.1.2 HPCS Diesel Generator Day Tank Level l

During tne review of the licensee's self-initiated SSFI report, the Team noted that the low level alarm on the HPCS Diesel Generator

- day tank was not set to provide 50 minutes of fuel cemafning in the day tank, as specified in Section 9.5.4.1.1.e of the UFSAR, although this had been a finding (6B) from the CECO self-initiated SSFI. The corrective action implemented to address the original finding was to perform a revised calculation which indicated that 50 minutes of fuel

was remaining after alarm initiation.

However, the assumptions used

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in the calculation were contrary to the actual operation of the fuel oil pumping equipment. The calculation used an incorrect use rate l

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from the day tank which led to an incorrect conclusion that'the required'cmount of fuel was present.

In fact, the amount of fuel availablelwould be insufficient.to meet the UFSAR commitment with e

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The ' licensee was made aware of this situation and had' initiated corrective action while the tea.m was still on site to revise the alarm setpoint, However, the occurrence of this error points to

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a fault.in the licensee's program for performance and review of design calculations.

The-failure'to detect errors in the calculation to support the current alarm.setpoint indicated a weakness in the performance off calculational reviews-and verifications that are prescribed.

.irJANSI/ASME NQA-1-1983.

This weakness is further discussed in Paragraph 4.1.1'.4 below.

4.1.1;3 -HPCS Diesel Generator Load Rejection Tests

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.t The team ~ determined that the TS Sections 4.8.1.1.2.d.2 & 3 identified values' for perfcrming the full load rejection test and single largest

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load rejection test that were less than the values given in UFSAR

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Table _8.3,1.

Table 8.3.1 of the UFSAR identified the single largest load on the.HPCS diesel as 3050 bhp which equates to 2528.kw and Lgave the~ total load as 3280 bhp which equates to 2719 kw. These loads were at variance with the TS which identified 2381 kw for the large

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. load rejection test and 2600 kw for the full load rejection test.

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1The intent of these TS-surveillances was to ensure.that the diesel i

generator would not trip off if the bus it was powering was lost-and to ensure that the diesel generator would continue to supply power-

y to'the bus with.no more than a 75% drop in voltage if the largest

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load on the bus were to trip off.

This position is consistent with that presented in Regulatory Guide 1.9, " Selection, Design, and Qualification of Diesel-Generator Units Used as Standby (Onsite)

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Electric' Power Systems at Nuclear Power. Plants," Revision 2.

The~ team agreed that the single largest load contained in Table 8.3.1

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used a conservative pump efficiency of 90% in arriving at the 2528 kw;

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however, the manufacturer's certified pump curve gave a load of 2408 kw at.3030 bhp. The 2381 kw load specified in TS appeared to come from data obtained-during a prototype test performed at LaSalle by General Electric.

The team considered that the conditions ur. der which that prototype test was performed did not represent the design or normal operational conditions of the plant, for example, the strainer was not 50% plugged per.the design requirement and water temperature of the suppression pool was lower than seen during normal operations.

It appeared that a non-conservative value was used for the TS

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surveillance.

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F 1Th'e licensee stated that the requirement for the full load ~ reject

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test was the: continuous rating of the diesel generator, which is

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2600 kw.

However, the licensee had utilized the 2000 hour-rating-

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~1n the actual = sizing of-the diesel.

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The-licensee committed to revise the TS to incorporate the appropriate

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values for " full load" and " single largest load" that met the intent

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'of-the surveillance requirement.

This will be tracked as an Open Item L.

(373/89018-02; 374/89018-02).

4.1~1.4 Design Calculations-

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c During the. review of the design bases for HPCS, the team found many examples where calculations were inconsistent, utilized

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different: assumptions for the same variable,.were incomplete, or were missing. With few exceptions, these calculations had been

. performed as part of-the original station design in 1973. Some examples included the following:

Calculation. entitled "HPCS Pump Discharge Pressure - Design" used a maximum suction pressure of 30 psig from the cycled condensate storege tank and 56 psig from the suppression pool, while calculation-entitled "HPCS Design Pressure & Temperature" identifiea the suction line pressure as 100 psig.

-Calculation "HPCS Design Pressure & Temperature" was missing

'the design temperature and pressure for the discharge of the

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water leg pump, even though the.need for this information was noted:in the calculation.

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Calculation entitled "HPCS Safety / Relief Valve Sizing" identified the set point for valve E22-F035 as 1100 psig-and operating pressure as 1225 psig. The 1100 psig should nave been 1100 psid,-and the operating pressure did not agree with calculation "HPCS Operating Conditions." Further, the portion of the calculation dealing with valve E22-F035 had been superseded by calculation HP-11, " Resetting Valve E22-F035",

which was not noted in either calculation. The new calculation used a maximum shutoff head and suction head which differed

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from those in the "HPCS pump Discharge Pressure Design"

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calculation.

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Calculaticn D0-7, " Diesel Oil Storage Capacity," concluded that the HPCS diesel generator fuel oil storage tank capacity

"7 was insufficient to meet the seven day fuel storage requirement.

Although, the tank was subsequently modified, there was no calculation confirming the adequacy of the modified tank. A preliminary. unreviewed and unapproved calculation, D0-11,

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" Diesel Oil Storage and Day Tank Usable Capacity - HPCS Diesel,"

dated 8/7/89 was prepared during this inspection which indicated

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'Although Section 9.2.7.2'of the UFSAR specified that a minimum l'

of 135,000 gallons of the condensate-storage tank capacity was m

reserved for HPCS/RCIC,.there was no calculation available

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which confirmed that_this requirement was met. A preliminary,.

unreviewed'and unapproved calculation, CY-01, Cycled Condensate

,b, Storage Tank Usable Capacity for HPCS/RCIC, was prepared during c

the-inspection which indicated that sufficient capacity ns F

dedicated in the condensate storage, tank for HPCS/RCIC.

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f (These examples of deficient calculations, as well as those noted

in paragraphs 4.1.1'.1.end 4.1.1.2 above, point to a weakness in the-

' licensee's program to ensure that calculations performed as part of s"

. design activities be performed in a controlled manner which includes

. review and approval. Although the team found numerous examples of

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conflicting information between calculations and-incomplete D

calculations, either the design conditions enveloped the differences or the differences were not significant.

In the case of missing calculations, the licensee was able to provide preliminary calculations sufficient-to assure the team.that the design was adequate.

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the licensee's new modification program had provisions to ensure that calculations were adequately reviewed, most of the problems with

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calculations dated back to original desion,

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4.1.1.5 Locction of Diesel Cooling Water Relief Valves

The team found that the relief valve on the diesel generator coolers discharge directly into tha ;,ersonnel access areas a

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around the diesels at heights ranging from approximately three j

e to six feet from the floor, At this level, a relief discharge

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could impinge directly on personnel working in the area. The i

e licensee should consider modifying the discharge of these valves j

to avoid potential impingement on personnel.

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-4.1.1.6

,Vnit 2 HPCS Relief Valve ALARA-Concerns

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The Unit 2 HPCS relie'f valve, E-22-F035, discharges directly into I

the HPCS equipment room, while the Unit I relief valve has its f

discharge routed to the reactor building equip. tent drain. The team

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could not identify any reason why there should be a difference between the two units.

In the event that the Unit 2 relief valve

.should actuate, the potential exists to needlessly contaminate personnel who may be present or enter the room after such an actuation.

The licensee should consider modifying the discharge of the Unit 2

relief valve to match that currently installed in Unit 1.

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4;1.2 Electrical Systems Desian

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This portion of the inspection consisted of a detailed review of the HPCS diesel generator, 4160 volt distribution; 4.16 kV to 480 volt transformer; 480 V Motor Control Center; and 125 V dc ba ttery.

In addition, deficiencies identified in the HPCS

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y system wet e-evaluatid in~ similar systems, including the 125 V de

batteries for electrical divisions I and II, and the 250 V de batteries.

The following: significant issues were identified:

i 4.1.2.1

~ DC Battery Sizing Calculation c:

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Each HPCS diesel generator set is supplied with its own respective

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125V DC battery and DC power panel from which various electrical components are powered. The HPCS system is designated as Division III. The team-reviewed the battery sizing salculation

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for the Unit 1 Division III battery and noted the following:

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. Battery temperature correction factor of 65F versus 60F was used, f

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No. aging factor was used in the calculation, a

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The dc' loading profile tha't was used was the UFSAR Load 1 Table 8.3-14 whMh was originally developed by General Electri::.for t% initial purchase of the battery.

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In response to the team's specific investigation with respect to-determination of the de current value that was associated with diesel generator flashing field circuit, Sargent & -Lundy determined that'a value of 1.9 amperes should be utilized instead of the UFSAR

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value of 1.0 amperes that had been used in the above calculation,

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'f The. licensee was_ requested to determine what the actual loads would be and determine.if.the battery size was appropriate for those loads.

Ceco's analysis determined that there was conservatism between the load profile that was_used to size:the battery and the actual

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approximate loads.

They.noted that the battery sizing calculations

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indicated a Unit 1 battery remaining margin of 9.5% and for Unit 2

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8.1%.

Their analysis utilized the value of 1.9 amperes noted above and was based on load information obtained from tabulations that

were recently supplied by the diesel generator vendor and walkdowns utilized to obtain individual equipment nameplate information.

The team determihed that design calculations were based on a temperature correction i' actor of 65F, but TS 4.8.2.3.2.6 allowed

'the electrolyte temperature to decrease to 60F, The capacity of a lead acid battery decreases below 100% when temperature is lest than 77F. When battery ro:ms are not maintained at 77F, compensation

'for the lower temperatures must be included when sizing the battery.

This had not been done at the TS temperature value. Therefore, the team reviewed the adequacy of the battery sizing for the other batteries based on temperature concerns.

Further investigation indicated tnat all of the other plant batteries, i.e. the 125V Division I, Division II, and the 250V Division I batteries were sized on the basis of 65F. Also our

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review of plant' documentation determined _that..the licensee's

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i engineer advised CECu in-February 1985 that the 125 V Division I,

' Unit:1, and 250 V Division I, Units 1 & 2, had little or no margin'

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above what would be required for maintaining minimum de system

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design voltage.

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' Talks with cognizant CECO and Sargent & Lundy engineering staff indicated that the Division I, Unit 1 battery would be inadequate in 'ai 60F temperature environment. The operability of the Divisional batteries is further discussed in paragraph 4.3.2 below.

The team. reviewed the history of the establishment of the TS temperature requirement,.and determined that the licensee's original

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submittal to NRR indicated that the minimum battery temperature should

'g be:65F; however, the TS issued to the licensee stated 60F. The licensee had failed to identify the significance of this change made

'during the TS' review process, and had not determined that their batteries could meet the revised specification as' issued.

4.1.2.2-Battery Specification The' team was unable to obtain a copy of the Division III ~125V battery and battery charger equipment specifications.

Ceco's purchase order-documentation that was usea when the battery was replaced provided a reference to the battery vendor's werk order number.

' Without a-specification, the. team was unable to determine if the batteries conform-with the requirements specified in 10 CFR Part 50, Appendix B, in that there is no indication that quality requirements were imposed.on the vendor for the battery replacement.

In addition there is a concern as to whether this equipment conforms with the requirements for class IE components.

The UFSAR states that the batteries, battery racks, and chargers are Class 1E equipment and

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design documentation requirements are contained in ANSI N45.2.11.

This is an-Unresolved Item (373/89018-03; 374/89018-03) pending a

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determination _as to whether the batteries conferm with 10 CFR Part 50, Appendix B, requirements and the standards for class 1E components.

E 4 '.1. 2. 3 DC Components - Maximum and Minimum Voltam During normal or float operation the-battery and respective bus is at a value.of 130.5 volts. When an e:ualizing charge is applied the voltage is increased to a maximum value of 135.6 volts.

Similarly when the battery is called upon to operate when AC power is unavailable, its initial voltage decreases during the period of

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During this time frame the minimum voltage may decrease to 105 volts.

The team was cencerned as to whether the devices connected to the dc busses could susta:n the overvaltages that were present during either the float or equalizing condition or perform their intended functions during periods of low voltage.

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.NRC Information Notice 83-08, " Component Failures Caused by

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Elevated.DC Control Voltage," was issued in March 1983. Based

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-on the. licensee's inability to initially determine that the end

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l devices connected to-the DC busses could sustain the overvoltages,

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t it'was not clear what type of effort had been expended by the

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licensee in the evaluation of this informhtion notice.

The results of the licensee's analysis determinid that for maximum

,<a voltage conditions, a majority of the components specified maximum g

voltage; operating ranges greater than 135.6. volts.

For.the remaining

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. components the licensee l determined that they were not exposed to the

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' maximum voltage condition on a continuous basis due to their 11ntermittent periods of operation.

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The. licensee also provided a detailed 11 sting of the' minimum DC voltage associated with-each device and compared that to the minimum battery terminal voltage.

This was obtained from actual service tests performed on the batteries, indicating that these voltages were 109,4 V for Unit 1 and 106.3 V for Unit 2'.

While this voltage occurs at the main DC battery and distribution bus,

'

'the licensee had not included the voltage drops associated with line losses through the cabling connecting the component to the bus. However,-due to low current values, it was expected that the voltage drop through the cable would be minimal.

(The licensee needs'to determine the capability of the equipment to operate properly based on the lowest expected de voltage that would be present at the end device. The assessment that the equipment will remain operable at minimum voltage conditions is

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an' unresolved item (373/89018-04; 374/89018-04).

"

,

. 4.1.2.4--

DG Cabling

~ Page B.1' 95-'of Appendix B to the UFSAR described how the station

. complied with the position specified in Regulatory Guide 1.75.

It. stated that all class 1E circuits should comply with the requirements of.IEEE Standard 383-1974.

Based on the team's review of the diesel generator equipment specification, it was not clear that the vendor supplied cabling that-interconnects between skid meunted equipment was in conformance with IEEE 383-1974.

The licensee's en'gineer, Sargent & Lundy had previously completed an evaluation of the wiring that was utilized on the emergency diesel generator sets at LaSalle on May 8, 1985.

They determined that while the majority of the cabling was qualified, several unmarked wires were found that lacked sufficient identification to allow qualification' by either testing or analyses.

As the diesel generator is a Class 1E equipment item, it is necessary to provide equipment, including associated components, that meets all technical and quality requirements that are

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commensurate with Class 1E requirements.

The design documentation l

.that is provided must provide assurance that the equipment

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performance will be in accordance with design requirements.

The licensee had taken the position that wiring which was installed

.

by a vendor;onLthe vendor's own equipment, which was supplied as a i

single component (i.e., diesel generator skid), was beyond' the scope j

of that which was addressed in the UFSAR commitments. Therefore, they felt that the qualification ~of the wiring was beyond the scope

..

of.the VFSAR. However, there must still be' assurance that the

equipment.will perform in accordance with design requirements,

regardless of whether supplied by the vendor, or installed by the-

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-licensee.

The determination ~of how the associated class 1E wiring for the diesel generator supplied by the vendor complies with IEEE 383-1974, is an: unresolved item (373/89018-05; 374/89018-05).

-4.1.3 Instrumentation and' Control Systems Design l

The portion of the inspection consisted of a detailed review of

'

_ instrumentation and control systems associated with the HPCS

'

system valves..and pump, HPCS diesel generator, diesel fuel oil J

s pumps,.and associated electrical distribution networks, ihe following issues were identified:

~

4.1.3.1

. Div1sion 3 Electrical Power System Annunciation & Status Disalay-Modification No. M-1-84-019 changed the function of the HPCS

4.16kV normal power supply overcurrent lockout relay without adequately addressing the control room alarms or system inoperable status displays.

i The original design provided for a dedicated lockout relay to trip and lockout the HPCS 4.16kV normal supply breaker on overcurrent and to actuate the control room annunciator window

'

"4kV Bus.143-(243) MAIN FD. BKR LK0 TRIP." The modification

changed the function of lockout relay 86-N/1432 by using spare

!

contacts to add tripping and locking out of the diesel generator breaker. However, the modification failed to make any changes to the-annunciator window to inform the operator that this was a

.

... MAIN FD. BKR/DG BKR LK0 TRIP."

In addition, no changes were made to the associate annunciator procedure to alert the operator that the 4kV bus was dead and would remain so.

The procedural revision portion of this modification is discussed in

'

Paragraph 4.4.1 below.

Status indication for diesel generator lockout relay K1 was

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reviewed and found to be acceptable.

The impact of providing inconsistent status indication for lockout relay 86-N/1432 and

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pm

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!:g f-lockout relay K1 may be confusing to the control room operator fy

= and has the potential iVran: incorrect or slow response in-restor.ing power-to the HPCS'4.16kV bus following a trip and lockout of its power source breakers. The licensee should consider modifying the annunciator window for this lockout trip Jg of.the_ bus to provide correct status indication.

,

L4.1.3.2 Protective Relaying / Circuit Breakers

,

The team reviewed the relay and circuit breaker networks to determine if they were adequhtely coordinated and provided sufficient protection to the components,-motor control centers, or electrical buses in the

'

event of faults.

In addition, the review verified that installation'

was in accordance with. the design as specified in the UFSAR, and that

,

=TS surveillance requirements could be performed.

In all cases,_the-relays and circuit breakers were found-to,be acceptably coordinated.

However, a review of the diesel generator lockout features revealed that the generator trip on overcurrent was bypassed on an.ECCS actuation signal. This appeared to be contrary to the surveillance requirement specified in the TS.

s i

Section 4.8.1.1.2,7.b of the TS required verification that the

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following automatic trips were not bypassed on an ECCS actuation

'

signal: engine overspeed, generator differential or overcurrent, j

and emergency manual stop.

The TS commitments for Division 3'

Section._4,8.1.1.2.7b and 4.8.1.1.2.13e were inconsistent, since.

the test requirement of section 4.8.1.1.2.13e indicated that the genersto'r overcurrent trip is bypassed on an ECCS actuation signal. A review of the corresponding TS requirements for the

diesel generctors Division 1 and 2 revealed that the generator j

overcurrent trip is also bypassed on an ECCS actuation signal.

Based on discussions with NRR and the licensee, no reason could be given why the HPCS diesel generator TS surveillance requirement should be different from the division 1 or division 2 requirement.

The licensee had interpreted the "or" within the specifi ation to

'

mean that as long as either generator differential or overcurrent

,

was not bypassed, the TS was satisfied; and the generator

'

differential trip was not bypassed.

The licensee agreed to request a TS change for the Division 3 requirements to make thea consistent with the Division 1 and 2 i

requirements.

This will be tracked as an Open Item (373/89018-06; 374/89018-06).

4.1.4 10 CFR 50.59 Evaluations For most of the modifications reviewed, the safety evaluation determinations conducted by the licensee were adequate; however, there were two exceptions as follows:

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hl Isolation of Condensate Storage Tank as Source to HPCS System

- 4.1. 4' 1

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bl-A safety evaluation was performed for what theJ11censee termed an-

'

" ongoing maintenance activity."

Due to a pipe failure of the p

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return lline from.HPCS to the condensate storage tank (CST) during a surveil. lance test in-1985, the valves connecting HPCS to the CST were closed and. power removed.

In addition, part of the return-

'

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piping;was dug up and permanently. capped. Maintenance hold tags k

were used as the administrative control to ensure that the valves remained closed and.deenergized.. Although safety evaluations are

,

p not.normally performed for. maintenance activities, the NRC considers N

this particular. activity to be a temporary modification to the

facility as described in the UFSAR, and as such, a safety evaluation would be requirec prior to the performance of the temporary r

p

- modification. 'At the time of the pipe failure, the NRC reviewed I

the interim corrective actions for this event and concluded that at t

- plant operations were acceptable with the CST valved out as a L-source of water, c

Thetteam considered the conclusion of the safety evaluation to be valid; however, the documentation of the bases supporting this conclusion was not in compliance with the requirements of 10.'CFR 50.59(b)(1). Weaknesses in the documentation of safety-evaluations had also been identified by the licensce's self-initiated SSFI, and changes had been made to the 50.59 safety evaluation performance process which should correct the problem.

Since the

- criteria'of 10 CFR Part 2, Appendix C, Section V.G.1 were met, no

- notice of violation is being issued for this example, j

4.1'. 4. 2-Modification M-1-1-84-019 l

- This modification added a function to relay 86-N/1432 which

. would lockout the diesel generator from providing power to its associated 4.16-kV bus.

Prior to this modification, the relay

}

isolated the HPCS 4.16 kV bus from its normal supply on bus

'

overcurrent. After the modification, the diesel generator output breaker would also trip and lockout.

In this case, the

'

diesel would be unable to provide power to the bus. The intent I

of the modification was to prevent connecting the diesel generator onto a faulted bus.

!

As a result of this modification, the consequences of relay 86-N/1432 failing closed were changed.

Before the modification, failure of this relay would cause isolation of the HPCS 4.16 kV bus from its normal offsite power source followed by a diesel generator l

auto-start and restoration of power to the bus.

In this case, the availability of the HPCS system is not changed.

However, after the

,

modification, the failure of this relay would isolate the 4.16 kV bus from all pcwer, thus rendering the entire HPCS system inoperable.

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.The 10 CFR 50.59 evaluation for this modification concluded that b

an-unreviewed safety question did not exist; however, the bases m'

Efor.this conclusion did not address the issues discussed above.

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'Spe'cifically:

a)-

Why the modification did not increase the consequences of

failure of-equipment important to safety (e.g., relay

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_86-N/1432).

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b).

Why-the modification did not. increase the probability of

'

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failure of equipment important to. safety (i.e., the failure

'

of thc HPCS to perform its safety function due to loss of normal'and emergency power sources due to the failure of relay N-SE/1432 [ bus is normal, with no overcurrent

,

conditions]).

,

,&s The failure'to document adequate bases for the conclusion that this modification did not generate an unreviewed safety question is a

,

violation-of 10 CFR 50.59(b)(1). As noted above, the licensee's self-initiated-SSFI, conducted _in 1987, had also identified inadequate

' documentation'of-50.59 evaluations as a finding. This modification was. installed in.1988; therefore, corrective actions implemented as

,

a result of the self-SSFI failed to ensure that subsequent-modifications had adequate 50.59 documentation.

Therefore, since criteria V.G.1,d and e of 10 CFR.Part.2, Appendix C were not' satisfied, a notice of violation will-be issued (373/89018-07;- 374/89018-07).

-As noted above, the licensee has not addressed whether an i

~

un_ reviewed safety question exists.

Installation of a-change to

the' facility when an unreviewed safety question existed would also beLa violation of 10 CFR 50.59(a)(1). An unreviewed safety question is defined in the regulations as a condition where:

,

(a) the probability of occurrence of an accident may be increased; (b) the consequences of an accident may be increased; (c) the

,

possibility for an accident or malfunction of a different type

!

than any evaluated previously may be created; or (d) the margin

,

of safety as defined in the basis for any technical specification is reduced.

Until the above issue is satisfactorily addressed, the existence of an unreviewed safety question is an unresolved item (373/89018-08; 374/89018-08).

4.2 Maintenance This portion of the inspection was conducted to evaluate the licensee's maintenance of the HPCS system and its selected support systems.

Representative procedures, vendor manuals, completed work packages,

/

general housekeeping, and material condition were reviewed. A detailed NRC evaluation of the licensee's maintenance programs was conducted earlier this year and is documented in inspection report Nos. 50-373/89010(DRS) and 50-374/89010(DRS). Maintenance activities were reviewed in two general arecs, electrical (relays, motors, motor control centers, generator, transformer, breakers, etc.) and mechanical (pumps, valves, and the diesel).

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' Electrical Maintenance

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4.2.1.1

' Circuit Breakers Lf Inspection of circuit breaker preventive and corrective maintenance

'

L practices consisted of visual inspections during plant walkdowns,

. review ~of maintenance procedures, and review of work requests for

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breakers associated with the HPCS. -A-. review of preventive

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maintenance documentation and work requests indicated that the

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licensee was maintaining the circuit breakers in accordance with f

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= vendor' recommendations; was meeting the required maintenance

,

p schedules; and was; performing the required-post-maintenance testing.

(-

D LAlthough'the' licensee appears to be properly maintaining their D

circuit breakers,'a weakness was observed in the area of QC j

inspectio_ns after corrective maintenance was performed. The i

,,

V

'teamireview of work ~ requests L8334 and L75521 that were performed

'

L for the replacement of a breaker and a temperature switch, respectively, found that no QC inspections of the electrical

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circuitry were performed. Similarly, a review of modification

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W package M-1-1-84-090 associated with the replacement of motors

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-on motor-operated valves also found that no electrical QC

inspections were performed..

Licensee representatives indicated j

7" that the procedure governing QC hold points (lap'1700-3, " Guidelines

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for, Quality Control Hold / Witness Points") only applied to major l

modifications.

For minor modifications or' repairs, where parts installed were "like-for-like" QC hold points were optional.

• A1though the team _found no examples where electrical circuitry was incorrect or the wrong component was installed, the licensee's j

establishment of electrical-QC hold points was considered a weakness j

in-that its implementation was discretionary.

!

l 4.2.1.2~

Diesel Generator and Associated Wiring j

The team reviewed maintenance records for the HPCS diesel generator.

!

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Examination ~of completed maintenance records indicated that the l

licensee met the required maintenance schedules and frequency, and

"

performed the_ work in accordance with procedure LES-DG-102. However, a review of the vendor instruction manual for the generator against j

the procedure indicated that several vendor recommendations had not a

been incorporated into the procedure. The maintenance activities j

specified in the vendor manual, SM-100, " Synchronous Motors, Generators,-

"

D.C. Exciters and Brushless Equipment," were either not performed by the licensee or performed at less frequent intervals than specified in the manual.

For example, the licensee changed the bearing grease every 18 months, but the manual indicated this should be done every 6 months. Additionally, the vendor manual specified that an insulation resistance test of the windings be performed on a yearly basis; but the licensee was not performing such tests.

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h;Qf The_ licensee ackno'wledged that they had not incorporated the a

maintenance activities outlined in the vendor manual in their-procedures because the manual-applied to several different types g

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of generators. The = licensee was in-the process of contacting

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the vendor in order.to formulate a maintenance program for the

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. generator.

During the inspection of the Unit No, I diesel generator DG-1A the team noted1that the wiring.(3 leads) between the Weodward-

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governor-casing and the governor motor was installed without being routed-through flexible tubing to protect against damage.

'

The. installation;of the governor wiring on the other Unit 1 and 2 diesel _ generators had.similar installation' deficiencies. However,-

the Woodward Governor company bulletin 03032, Fig 7-8 indicated that lthe governor motor wiring connection was to'be routed through a flexible tubing.

This was the case for all the diesel generators where the vendor installation had been unchanged.

-Because the engine speed control governor is located in the

.midst of heavy; components which require regular checking and

.

,

maintenance and the wire sizes are small, the installation of

i'

the-flexible tubing for routing of the wiring between governor l

motor and -the governor casing is necessary to oreyent-degradation of the ' wiring, which-could increase the probability of faults-in j

,

the engine speed control system.

When notified of the. term's concerns, the licensee stated that-l they intended to issue-work orders to restore the flexible

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tubing installation to the condition as originally furnished by

,

the manufacturer.

I The discrepancies between vendor recommendations and the licensee's

. activities:were considered a weakness.

j 4.2.1.3 Protective' Relays l

The' team reviewed procedures used by the licensee to maintain j

. protective relays and_ walked down-the relays to verify that set i

points were in accordance with the Relay Setting Orders (RS0)

required by the licensee's corporate office For the most part, relay settings were acceptable.

However, this was not the case for two relays identified by the inspection team.

These two cases involved the magnetic trip setting for the HPCS injection valve, E22-F004; and the phase B overcurrent protection relay for bus 243-1,

'

2451-AP074B.

For the HPCS injection valve, E22-F004, the magnetic trip setting a

was 6.5, although the RSO set point sheet specified a setting of

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i-4.0.

An evaluation of relay performance determined that this llN i

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L discrepancy 1_n setting had no'effect on the timing of the trip, which occurred within.the required band.

Therefore, the setting

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was acceptable.

.

.

For the Type:IAC 51 relay 2451-AP074B, the phase B overceirrmt

,

protection, relay for safety related bus 243-1, the time levu was, improperly set at 3.0L..The RSO set point sheet specified a time' lever setting of 1.0L to' correspond to a pick up. time of

-

0.5 seconds. This relay was' calibrated on November 22, 1988,

.and the' associated documentation indicated that the relay had been'left at a. setting of 1.0L, but due to other complications,

,

the as left results were not acceptable and a new relay had been ordered. This-as found trip lever setting would result in a' relay

,

pick up time:far in excess of 0.5 seconds.

Calibration procedure

.LES-GM-229, Revision 0, " Unit Two Southern Division OAD Periodic Protective Relay Calibration Procedure at LaSalle County Stati~on for Relays Not Mentioned in Tech Spacs," establishes the tolerance for'this type of relay _be no more than 5%.

I

' Bus 243-1 is protected by two relays, phase A and phase B, for

,

all three phases.

A current imbalance in one phase would be

,

sensed in the other two phases and as a consequence, two relays

'

provide protection for a three phase circuit. Although the phase A relay was properly calibrated, a single failure of the phase A F

relay would have resulted in no overcurrent protection, since b

the. phase B relay:was out of tolerance by a substantial margin.

'

The licensee subsequently initiated actions to recalibrate the l

relay.

The process of calibrating these relays involved the removal of t

the relay from its case, placing it on a cart, and transporting

.

'

it to the I&C shop.

The relay is then calibrated, placed back on r

the cart, transported back to the switchgear room, and reinstalled

-

into its case. A simple functional test is then performed to verify

[

,

that the relay works. This test does not evaluate whether the relay is properly timed; but only tests to see that the relay trips.

The

,

failure to verify appropriate relay settings upon completion of the calibration activity is a violation of Criterion XI of 10 CFR Part 50 Appendix B (374/89018-09).

- 4.2.2 Mechanical Maintenance

,

- 4.2.2.1 Maintenance Work Request Review Overall, detailed procedures were in place for the conduct of maintenance. The work requests were written to incorporate the existing procedures, where applicable, in the work request packages.

Maintenance personnel used the procedures during maintenance

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.c p'erformed, both in the shop and at the job site.

In most cases, the; team found that vendor manuals'and recommendations were

,

incorporated into the procedures and work request packages.

Appropriate manual references and copies of the manual pages were

,

,

used directly by the maintenance and technical: staff personnel.

'

The technical staf f reviewed the vendor manuals-to ensure that.

the procedures would be workable with the specific work request i

package;for the component to be maintained.

,

~4. 2. 2.2 _

Post-Maintenance-Testing Operations specified the required testing'for determining operability.

For_ example, when a valve-was serviced as part of the licensee's routine maintenance program, the work requests were not reviewed by the engineering _ staff to_ ensure adequate l

testing was specified.

This was also true for non-routine

maintenance.

The team was concerned that insufficient technical

review was given.to work requests to ensure that proper

_

post-maintenance testing was specified. This is considered a weakness.

However, the team found no examples where testing had been

~

inadequately performed.

In-addition, the CECO corporate office had issued a Nuclear Operations Directive requiring the station to revise the_ governing procedures to ensure that engineering would be involved in the establishment of post-maintenance testing requirements.

These revisions should alleviate the team's concerns in this area.

a 4.2.2.3 Preventive Maintenance i

Preventive maintenance (PM) at LaSalle included general inspection of component physical condition, wiring inspections, and periodic lubrications. This work was accomplished by regularly scheduled surveillances through the general surveillance program (GSRV) and the' lubrication surveillance program (LUBQ).

j i

The team reviewed preventive maintenance procedures, completed i

surveillances, and the preventive maintenance histories of selected

components.

No problems were noted.

A system walkdown was conducted which found the majority of components to be in good physical condition.

Valve 1E22-F023, the HPCS full flow test valve, had both gear grease and stem grease on the stem,-indicating that a gearcase seal could have been leaking.

The licensee wrote a work request to evaluate this condition.

,

'

The licensee's check valve PM program was considered a strength by the. team.

This included all plant check valves.

The valves were prioritized and plans were made to inspect and in some cases test the check valves using diagnostic equipment, based on priority, i

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'The.1'icensee indicated that the program would commence-during the

W upcoming outage. The current inspection frequency for these valves

varie's from four to six years. The program did provide continual

'

review of-.the inspection results for verification of inspection f

- frequency.

If the program was implemented as planned, check valve

-

b reliability should improve and failures should be precluded due to the evaluation and continued monitoring of valve characteristics.

~

.31 Surveillance and Testing

,

The team reviewed the surveillance and routine testing program for the i

HPCS and supporting systems described in Paragraph 4.0 of this report.

When potential concerns were identified, this review was extended to

other similar plant systems.

The review was conducted by identifying

,

i the TS surveillance requirements and comparing these to the surveillance procedures.- -The procedures were reviewed for technical adequacy and-T e

r selected surveillance results were reviewed for compliance with the i

b acceptance criteria. The acceptance criteria were reviewed against

F the TS UFSAR system design parameters and assumptions, and as-installed

conditions, to verify that-the intent of the surveillance was met.

The inservice testing -(IST)~ program implementation was reviewed utilizing

" Ceco IST Program for LaSalle County Station," dated September 18, 1988.

J

.

The tests performed were reviewed to determine if all required components

'

- were tested in accordance with both the licensee's IST program and

'

I Section XI of the ASME Code, except where relief had been requested and

'

granted.

"

4.3.1 Division 3 Switchgear Room Temperature Surveillance TS 4.7;7.A.4 required that the temperature in the switchgear rooms be. monitored every 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> and that these temperatures be within the band of 54F to 104F.

This temperature surveillance for the Division 3 switi;hgear rooms had consisted of monitoring the return air temperature on a ventilation system which served part of the switchgear room. The licensee had not included a direct temperature measurement of the switchgear room in their surveillance program and therefore had not actually monitored room temperature as required by Technical Specifications. The Division 3 switchgear room temperature is significant because the temperature of the Division 3 batteries, located in this room, is critical in determining whether or not they can perform their design function.

During the inspection a revision to the daily surveillance procedure was issued to require that the switchgear room temperature be taken using a thermometer in accordance with the Technical Specification required schedule. This revision was reviewed by the team and found to address the NRC concerns.

The failure to monitor the Division 3 switchgear room temperature is a violation of Technical Specification 4.7.7. A.4; however, since this was an isolated example where no procedure addressed the surveillance requirement, the violation was of Severity Level V, and corrective l-i,

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actions were' instituted prior to the end of the inspection, no

. notice of violation is being issued per the~ criteria of '10 CFR

'

Part-2,. Appendix C,Section V.A.

[

-4,3.2-Acceptance ~ Criteria for' Battery Electrolyte Temperatures i

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-TS 4.8.2.3.2.b.3 requires that the. electrolyte temperatures for

'

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the station batteries be determined every seven days and that this

,

temperature be at least 60F, A review of battery sizing calculations t

(see^ Paragraph 4.1.2.1 above) determined that a minimum electrolyte

[~'

temperatureJof 65F had been assumed in.the. design ~ calculations for all. of the batteries, and as a result of' battery loading, there.was t

insufficient-margin for the batteries in some of the divisions to ensure that they would operate if-'the temperature dropped below 65F,

,

l The surveillance procedures implementing the TS requirement used 60F l

as the acceptance criteria.

Thus, the electrolyte temperature could L

~

be'within the acceptance criteria, with'the batteries unable to perform their design function.

Sargent & Lundy had advised CECO

.in February 1985 that the 125 V Division-I batteries for Unit 1 and the 250.V batteries for Unit E had little or no margin above that which would be required for maintaining minimum.DC system design

-

a voltages based on the-design temperature of 65F.

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During the inspection the licensee revised Procedures LOS-AA-01, Unit Daily Surveillance, Revision 22, dated August 15, 1989 and LOS-DC-W1, Weekly Surveillance for the Safety Related 250V DC, 125V DC and Diesel Fuel Pump Batteries, Revision 14, dated

'

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e August 18, 1989,- to require' daily monitoring of the ambient j

temperatures associated with battery rooms to assure that the

'

Ltemperature is greater than or equal to 65.6F.

This will ensure that-the electrolyte-temperature is above 65F.

The licensee also i

agreed.to initiate a change to the TS to reflect the correct design i

O

. assumptions.

Implementation of this revision will be tracked as

.!

Open Item No. 373/89018-09; 374/89018-10.

i

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The team reviewed the surveillances which had been conducted on the 125 V division 1 batteries for Unit I and the 250 V batteries for Unit 2 since initial operation.

During that time period, the

,

team found four weekly surveillance results where the division 1

{

battery pilot cell temperatures were below 65F.

On all of these j

occasions, the unit was shutdown either for a maintenance or l

,

refueling outage, and the TS requirements for operable batteries

'

under shutdown conditions (TS 3.8.2.4 - only one division required

to be operable) would have been met.

!

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With regard to the 250 V batteries, the team found all surveillances

during the period December 5, 1985, through December 26, 1985, to have results where the pilet cell temperatures were below 65F.

In this case, the unit had been shutdown for a maintenance outage until approximately December 22, and at the time of the last weekly o

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j-surveillance with a temperature below less than 65F, the unit was

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operating.at 45% power. The lowest surveillance temperature recorded

,

was 64F during this period. _ The February 1989 capacity test

,

' performed on these batteries resulted in 112.5% capacity measured.

Similarly, the service test conducted on January 27, 1987, resulted

in a minimum voltage of.222.94 with the acceptance criteria being

greater than 21') volts. Based on'these test results, and.the fact

• m that the battery temperature was only one degree below design allowable

'

'(temperature correction factor less than 1%), the team concluded that'

!

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, the batteries cauld be considered operable at 64F.

~*

'4~3.3 Division 2 Battery Load Profi]e l

.

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'TS 4.8.2.3.2.2.b and d provide a loading. profile to be used for.

determining the Division 2 battery capacity. This loading profile

'was less than that given in the UFSAR, whicn represented the actual emergency'loods-A review of the procedures implementing these TS

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required surveillances indicated that the correct loading profiles

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(from the.UFSAR) were being used in performing these tests. The licensee agreed to initiate a change to the TS.to accurately reflect

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the actual emergency loads.

Completion of this action will be tracked

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as Open Item No. 373/89018-10; 374/89018-11.

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4.3.4 HPCS Testable Check Valve

,

The team reviewed testing requirements'for HPCS components and l

V determined that the HPCS testable check valve 1(2)E22-F005 was not tested as required in 10 CFR Part 50, Appendix J.

This was an acceptable practice for LaSalle, because TS 3.6.3 and the UFSAR i

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allowed this valve to be considered as a containment isolation valve

.without requiring a Type C test.

Upon further review, the team found that the testable check valves in low pressure core spray

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[1(2)E21-F006), reactor core isolation cooling [1(2)E51-F066), and low pressure coolant injection (1(2)-F041A,B, and C] were also not

'

tested for the same-reason.

The NRC had previously approved this

~. testing methodology in the Safety Evaluation Report; however, based on a re-evaluation performed by the NRC at Clinton, these valves had

.been'put back in the required Type C testing program.

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b'

Based on the above, the NRC will re-evaluate the licensee's program to not Type C test these valves.

This item will be tracked as open

,L.

item No. 373/89018-11; 374/89018-12, 4,3.5 Monitoring Diesel Generator Fuel Pressure

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laSalle surveillance procedure LOS-DG-M3, Revision 19. "1B(28)

Diesel Generator Operability Test," required that fuel pressure be

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monitored for the engine driven fuel pump while the DG was loaded

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V 7e to ensure proper functioning of the fuel pump, suction strainer, f'

.and fuel filter. However, for the HPCS diesels (Division.1B and 2B)

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there it a separate motor driven fuel supply train having its own.,

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Strainer, ~ filter, and pump running continuously to provide fuel that

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is.'used to' cool the fuel injectors. The motor-driven fuel supply train was notLbeing monitored to ensure proper functioning of this V1 train. :The licensee. agreed to revise procedure LOS-DG-M3 to provide L

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for monitoring of the motor-driven pump fuel line pressure during monthly DG tests, b

The failure of the licensee to provide an adequate surveillance m

. procedure appropriate to th6 circumstances for monitoring the T

motor'deiven fuel oil system pressure is consi_dered an example of'a violation of Criterion V of Appendix B to 10 CFR Part 50

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(373/89018-12;'374/89018-13).

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4.3.6 Inservice Testing Program

'

,The licensee's IST program'had received approval for implementation from the NRC, provided certain items' identified during that review

'

were corrected. The team reviewed selected surveillance procedures, test results; and documentation to-verify adequate program implementation.

In addition, Piping and Instrumentation Diagrams

'

l(P& ids) were reviewed to ensure.that all components that were

required to be in the IST program were tested appropriately, t

L Results reviewed indicated that the testing was conducted in

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accordance with the procedure and met the requirements of the licensee's IST program.

Test data from completed testing was

' reviewed and was within appropriately established acceptance f-criteria.

The check valve ii. m ility program established by the

'

licensee _was viewed as a strength.

The program is comprehensive

incorporating Industry reports and guidelines, and NRC information E

notices.. Failures should be precluded due to the evaluation of

adverse trends through continued monitoring of valve characteristics.

I The review of. the program scopo determined that the diesel generator air start compressor discharge check valves [1(2)E22-F362A and B)

-were not listed in the licensee's IST program.

Based on the licensee's review of Generic Letter 89-04, " Guidance on Developing

'

Acceptable Inservice Testing Programs," the licensee had determined

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that these check valves required additional testing, and they were being'added to the IST program to address the generic letter.

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4.3.7 Logic Functional Testing The review of the licensee's procedures for performing logic functional tests for the HPCS autostart and other logical functions revealed a good program that covered a check of the operation of til

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relay contacts.

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i The operations area was reviewed primarily from the standpoint of

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, operator training and procedure adequacy.

Interviews with operations

personnel were also conducted.

Procedures reviewed included HPCS

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operating procedures and Emergency Operating Procedures (EOPs).

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In-general.-procedures and' operator training were adequate; however, two. concerns were identified, which are discussed in the following-

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paragraphs:-

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i 4.4.1 M_odification M-1-1-84-019 This modification added a lockout preventing the Division 3 diesel l

generator from closing onto a faulted bus (see Paragraph 4.1.4.2

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above). The initiation of this lockout was alarmed in the Control

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Room using: an existing alarm (2HP12A). The annunciator response -

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procedure (IH13-P601 A302) for this alara had not been revised to I

reflect the modification although the operators had been trained

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.on the modification prior to the completion.

The procedure

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erroneously. directed the operator to ensure that the diesel

'

generator had loaded onto the bus, which was what the modification prevented from occurring.

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Upon identification by the team, the lirensee immediately issued

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x a night order and processed a revision to the procedure.

The

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> procedure revision was issued prior to the conclusion of the i

'in vection, was reviewed by the team, and was determined to be

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acceptable. The failure to provide a procedure appropriate to the

{

situation is a violation of 10 CFR Part 50, Appendix B, Criterion V.

!

Ilowever, since this violation was isolated, would normally be classified as a Severity Level V violation, and corrective actions were completed prior to the conclusion of the inspection, no notice i

of violation will be' issued per the criteria of 10 CFR Part 2, Appendix C, Section V.A.

4.4.2 HPCS Operating Procedures

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The HPCS operating procedures had not been revised to reflect the

'

isolation of the system from the CST.

Since the isolation had been handled as an ongoing maintenance activity utilizing "out of service" (005) tags rather than a modification, procedure revisions were not

'

triggered by the program.

.

Review of the HPCS operating procedures indicated that except for LOP-HP-05, " Raising Suppression Pool Level," these procedures addressed both the CST and the suppression pool as suction sources.

"

The team concluded that these operating procedures did not present

an immediate problem since training on the current HPCS configuration mitigated the inaccurate procedures, and all operations personnel interviewed were aware of what actions were required to operate the system without the CST as a water source.

However, allowi-ng procedures to exist for over four years that did not reflect actt.a1 plant

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configuration is considered a wed.r.est. ' During this inspection the I

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licensee had in place a modification package to permanently isolate

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the CST.from the HPCS system that should trigger the revision of.

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t the above prccedures.

4.5 Modification Process v

The team reviewed.the following licensee procedures for performing

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. plant modifications that were current as' of. July 31, 1989:

. LAP.-240-6, Revision 19. Temporary System Changes; (

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LAP-900-4, Revision 35, Equipment Out-Of-Service Procedure;

LAP-1300-2, Revision 24,' Modification Program;

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LAP-1300-2AiRevision1,ModificationRequest;

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LAP-1300-2B,. Revision 1, Plant Modifications Designed By Engineer; I

LAP-1300-20, Revision 1, Plant Modifications Designed By Technical

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Staff; i

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LAP-1300-2D, Revision 1 Processing of Modifications; l

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. LAP-1300-2E, Revision 0. Station Modification Review Committee;

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LAP-1300 5,1 Revision 10, Field Change Requests; LAP-1500-4, Revision 13 Action Item Records; l

NSED. Procedure Q,6, Revision 0, Design Modifications; and

NSED Procedure Q.8, Revision 12, Field. Change Requests (FCRs) Written

Against An Engineering Change Notice (ECN).

I These procedures were considered adequate with the procedure for temocrary system changes. found to be considerably improved.

There were no major

!

modifications of HPCS and its supporting-systems which had been completed based on these upgraded procedures; therefore, the effectiveness of l

implementation was not assessed.

4.6 Handling of Industry / Equipment Experience l

The team reviewed the licensee's activities related to the evaluation

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and. resolution of equipment problems that had either been forwarded-to the licensee by the NRC in the form of information notices or had been_ identified through the licensee's deficiency reporting system.

l The team conducted walkdowns of the HPCS and associated support systems to determine if the issues described in the information notices had been acceptably addressed. Two deficiencies were fcund associated with emergency diesel generators that could be associated with the material contained in information notices 88-24, " Failures of Air-Operated Valves

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Affecting. Safety-Related Systems"; and 89-07, " Failures of Small Diameter Tubing in Control Air, Fuel Oil, and Lube Oil Systems Which Render

. Emergency Diesel Generators Inoperable." These deficiencies were

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' associated with the HPCS diesel generator's air start system and the

,

small bore tubing installed on the diesel.

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4.6.1 Deficiencies Associated with Air Stact System The' air start system for the diesel consisted of two compressors that maintain a pressure of 210 to 240 psig in four large air receivers'. -This air then passes through a regulator to a pilot solenoid valve.

The regulator-is required to maintain maximum air pressure between 195 and 200 psig. When the valve is operated, the air drives four air start motors on each diesel to start the engines.

During the walkdown of the Division 3 Diesels, 240 psig air pressure was found in the receivers for the IB diesel and 230 psig was found for the 2B. diesel.

The air pressures measured downstream of the regulators for the 2B diesel were 225 psig and 210 psig, which is the pressure impinging on the pilot solenoid valve.

However, the maximum rated operating pressure for the pilot valve was 200 psig.

The IB diesel was not instrumented with a pressure gauge downstream of the regulator; therefore, the team.was unable to determine whetSer the maximum operating pressure had been exceeded.

During the inspection, the licensee prepared work requests to install temporary pressure' gauges on the IB diesel to check and adjust the system pressure to 195 to 200 psig, and to adjust the 28 diesel regulators to this same pressure band.

'NRC Information Nott,:e 88-24 dealt with a condition where certain air-operated valves failed to operate because they were exposed to pressures in_ excess of rated pressure.

A review of past maintenance work requests showed that air leaks through the pilot solenoid vahe had been a recurring problem, requiring

. valve repair on both of the valves on the 28 diesel in 1987.

Sargent & Lundy (S&L) had been asked to determine the cause of these recurring valve leaks.

In January 1989 S&L informed the licensee that the cause of these leaks was excessive line

_ pressure at the valve.

The licensee reviewed the S&L evaluation and in July 1984 established a requirement to check all DG air start system pressures downstream of the pressure regulator once per week to determine if the regulators were allowing pressure to build up beyond 200 psig.

These checks were performed for diesel generators 0, IA, and 2A; however, when performing the check at diesel 18, which did not have a pressure gauge, the check was not performed.

The Unit 2 installation was assumed to mat S Unit 1.

Therefore, these two diesels were not checked. The failsre of the licensee staff to implement corrective action for the IB and 2B diesel generators is a violation of Criterion XVI in i

Appendix B to 10 CFR Part 50 (374/89018-13; 374-89018-14).

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LaSalle procedure LEP-DG-102,. Revision 3, " Diesel Generator Air Start Pilot Solenoid Valve Repair / Replacement and Testing,"

required two leak checks to be performed on the DG air start

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solenoid valves _every.18 months.

The first leak check was to be done~on the benen after valve refurbishment and the second p~

after installation on the diesel. The pressure specified in the procedure for both of these checks was 90 psig, even though the operating _ pressure was maintained at approaimately 200 psig.

. Although not so stated in the procedure, the tem determined that the second test had been performed at.the system pressure

of 200_psig. This is an example of-the procedure not being appropriate to the circumstances in violation of Criterion V in Appendix B to 10 CFR_Part 50..The licensee agreed with this

' observation and revised the procedure during the inspection.

Since,the criteria of 10 CFR Part 2, Appendix C, Section V.A were met, no. notice _of violation is being issued.

4.6.2-Deficiencies Associated with Small Bore Tubing

During a walkdown of the 2B diesel, several small diameter I1 ping and tubing deficiencies relating to routing and restraining were identified, As a' result the team performed a detailed walkdown of the 2A diesel. :The following specific-deficiencies were identified:

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a..

Lube oil drops were found below the pressure switches at L

some tubing branch connections..

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Some piping restraints were inadequate.

Some were completely g'

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off of the line; some consisted of only half of the clamp;

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- and some were made with thin sheet metal electrical conduit

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with large gaps between restraints.

c.

Minor tubing cuts and wall thinning were observed due to rubbing.

In some of the wall thinning cases, the associated tubing showed signs of leakage, d.

Wire harnesses on DG speed control motors above the

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governors were either not installed, or improperly installed (see Paragraph 4.2.1.2),

L-p.

Based on the team's walkdown, licensee personnel conducted detailed walkdowns of the 0, IA, and IB diesels, found similar problems, and l initiated sen ral work requests to restore line configuration back to F

the original conditions, su:o as replacing pipe clamps and tightening

!

fasteners.

The apparent cause of these deficiencies was vibration, j.

and improper installation.

"

NRC Information Notice 89-07 was issued on January 25, 1989, to alert licensees that failure of tubing in control air, fuel oil, and lube oil systems could be caused by (1) wall thinning by material rubbing, (2) inadequate design, and (3) inadequate support; and that b

these failures could render the diesel generator inoperable. These

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-conditions were present on the diesels which the team walked down.

• In.. addition, the licensee experienced a fuel oil system leak when

the bourdon tube of one of the two fuel oil pressure gauges on DG 2B ruptured,'apparently due to excessive vibration, on March 4, 1989,

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the second day of continuous operation. This resulted in DG shutdown

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to prevent possible fire. The licensee's corrective action as a i

i result of this event had been to replace the failed gauge, inspect l

the other gauges on this diesel for damage, and replace the one other f

gauge found to be damaged. However, this corrective action was not

extended-to other diesel generator fuel oil-gauges that had been

subjected,to similar vibration. The licensee has since issued a j

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2:

i work request in replace all susceptible. gauges.

The--team conductvd a detailed review of actions that had been impi mented by the licensee as a result of the issuance of infonation notice 89-07 and the DG 2B tube failure.

Licensee

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fo.lowup'to the information notice did not result in a detailed W snail diameter piping and tubing inspection which could have i

identified some.of the deficiencies observed by the team prior to'the'NRC, inspection.. iiowever, the licensee did propose, in

'May In89, that the lube oil, fuel oil, and engine cooling tubing l

and piping be re-routed to provide. adequate separation, and that additional. supports be provided to handle the vibration.

The licensee's actions to correct the conditions which could

result in small diameter piping and tubing failure, as described in Information Notice 89-07, will be tracked as an Open Item (373/89018-14; 374/89018-15).

4.7 Evaluation of Licensee-Initiated S$FI on HPCS The licensee began a program for conducting the equivalent of SSFIs at their sites in early 1987.

This was a voluntary initiative conducted in an effort to utilize this inspection technique to evaluate system

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functionality.

Through this process, the licensee could obtain a

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considerable amount of information about plant performance. The first t

sites ~ chosen were Dresden, Quad Cities, and Zion.

Consultations were

then held with WESTEC, who had been iqvolved in the conduct of several NRC SSFIs. WESTEC reviewed what had been dene at Dresden, Quad Cities,

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and Zion,-and made some recommendations on how to improve the licensee

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efforts. These recommendations were implemented furing the licensee's

'

conduct of an SSFI at LaSalie conducted between July 27 and November 24,

'

1987.

'

The LaSalle self-SSFI was conducted under the auspices of the corporate

'QA Department. The inspection group consisted of 16 inspectors, including

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8 members of the QA Department and 8 mechanical and electrical design i

engineers from Sargent & Lundy. The inclusion of design engineers was a positive effort to utilize personnel with appropriate engineering W

disciplines.

The licensee's inspection methodology involved the collection of a sample of work requests and all modifications that had been completed on the

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Unit 2 HPCS. Of these, the inspection included a review of six temporary

. change. packages, eight' completed modification packages, and 36 work

1. _

requests._ -In addition, over 3000 hours0.0347 days <br />0.833 hours <br />0.00496 weeks <br />0.00114 months <br /> were spent in walkdowns of tha HPCS and associated systems to determine that components were designated

.

per P&ID and installation drawings, position and location of components allowed operation and ease of maintenance, pipe she was per dasign

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documents,. material' condition was good, and electrical wiring was routed

_

per drawings.

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The findings included 20 cases where there was an apparent discrepancy s-between.an identified condition and a requirement, and 37 instances where t

pt there was a substantiated discrepancy between an identified condition and

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a requirement.

In^ addition, four generic issues were identified:

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(1) voluntary entrance into LCOs without a teport to NRC; (2) poor documentation of basis utilized from the TS ed FSAR in 50.59 safety o[

evaluations; (3) procedures, drawings, and labeling of equipment were

[

not in agreement; and (4) changes.to the UFSAR were not timely nor i

accurate. -The specific findings mostly related to drawing and installation r

discrepancies.

'.

On November 20, 1987, the licensee established'an SSFI Task Force to review the results of the first four licensee-conducted hiFIs to

.

determine whether changes in methodology should be made 4,id to evaluate the results for potential generic findings. The SSFI Task Force issued their final report on June 30, 1988, which contained c

several recommendations regarding the conduct of future SSFIs and the L

resolution of apparent generic deficiencies at all stations.

These k

recommendations were reviesed anci considered to represent positive-improvements to the licens;e's program.

L In addition, the Task Force con,1uded that:

(1) that ell systems

'

evaluated would function as designed when needed; (2) no immediate

. safety. concerns were identified; (3) the self-SSFIs were effective, useful initiatives that reached credible'_ conclusions; (4) the self-SSFI y

l process should continue on a planned schedule; and (5) the self-SSFIs

should be conducted in such a way that the impact on plant activities L

were minimized.

~

Upon completion of the NRC team's HPCS inspection activitiec, the team

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reviewed the' licensee's SSFI Task Force Final Report, self-SSFI report, C.

SSI 01-87-01, and held discussions with the licensee's SSFI team leader

'

and. lead inspectors in the areas of mechanical and electrical.

Findings made by the NRC team were evaluated to determine if they had also been identified by the licensee's efforts, and if not, the root cause for non-identification. The corrective actions implemented as a result of the licensee's findings were also reviewed.

The NRC Team agreed that no immediate safety concerns existed;

-however, the team did not agree that the system would always function as required due to the potential electrical design concerns noted above.

The team also agreed that the self-SSFI did an excellent job of finding and correcting labeling problems and most drawing Oncerns, based on the fact that the NRC team did not find situations where labeling or drawings for the evaluated unit were inappropriate.

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C.

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k As noted above,'the NRC team identified several deficiencies involving

,"

the HPCS;and associated support systems during this inspection which were not identified during the licensee's efforts.

These differences r

'in findings could be attributed to limitations in-the licensee's SSFI (

methodology. The team identified only three cases where findings from the licensee's SSFI had n(t been corrected and were also identified by the NRC team. These are discussed below.

4.7 I

' imitations in SSFI Methodology

.

nN Two' major limiW, ions wert identified related to the methodology for-conductinr SSFIs.

The first limitation related to the limited review of design documents.. The licensee's efforts were limited to changes made as a result of the completed muJification proces>.

A basic assumption was made that the original design of the system, as licensed, was correct unless nidence to the cont.ary was identified in the subsequent review of materisl. S.milarly, components were not checked to verify that they conformed with design requirements if they were the original ec.nponents. The primary emphasis of the licensee's efforts were wa'ikdowns and review of changes made to the systems through modifications.

As noted during the NRC effort, several deficiencies were identified.

relating to o-iginal installation, some of which related to

'

calculations, battery purchase specifications, battery load profiles,

.and discrepancies between the UFSAR, TS, and design assumptions.

In the> case of UFSAR discrepancies, the self-SSFI had identified a generic concern; however, all of the specific examples had not been identified that related to the HPCS system.

By limiting their efforts to installed modifications, the licensee did not determine

_

whether the system "as installed" was capable of performing its

design functions but rather that the system as originally designed had not been changed to invalidate the condition it was in at the time of initial licensing. This was apparent by the considerable amount of time required for the licensee to determine what were the

.

actual-loads on electrical buses, the original purchase specifications

of the battery, and the maximum and minimum voltage that components

,

' installed in the system were capable of withstanding.

The licensee also recognized this shortcoming in their Task Force report that recommended that future SSFIs incorporate efforts for design validation although it indicated that this should not be done until the design reconstitution effert is completed.

Since all functionality concerns related to initial installation or design may not be identified by a self-SSFI conducted before implementation of the Task Force recommendations, those prior efforts should not be exclusively relied upon to justify that the associated systems are operable.

The second limitation related to the methodology used by the licensee to verify appropriate surveillances were conducted at

required times for the electrical portion of the self-SSFI. The

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licensee began _ by reviewi 2g all of the surveillance procedures l

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to ensure that acceptance criteria in the procedure conformed

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y with the_TS requirements and that the procedures were implemented

.,

as required.

However, by not comparing TS, the UFSAR, and de 'an

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values for consistency and then utilizing the apptopriate val j

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b to verify that the requirements were covered within an approp- _

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surveillance procedure, a vulnerability existed where surveillances

required by TS but not specified in a procedure would be missed, as

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p was;the case-for the switchgear room temperature surveillance identified in section 4.3.1 above. To ensure future self-SSFIs

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do not miss these findings, the licensee needs to revise their.

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methodology related to the review of surveillan;e procedures.

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4.7.2 Implementation of SSFI Corrective Actions

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i The NRC team noted three cases _where deficiencies identified by

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the self-SSFI were also'found by the NRC team, indicating.that I

corrective actions may not have been sufficiently complete. These L'

related to the~ alarm setpoint for the diesel generator day tank, the

!

!

performance of 50.59 safety evaluations, and the incorporation of

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as-built conditions for the diesel generator air-start system into appropriate drawings.

The team noted that there was a distinct

'

different cause for each of these items not.being corrected.

I

The first case dealt with the inappropriate alarm setpoint for the diesel generator day tank, where the licensee's finding had

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been closed out. The closeout was based on the fact that an S&L

-calculation had been QA certified, and had shown that required

.

run time would be met. As noted in section 4.1.1.2 above; the

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fuel drawdown assumption made in the calculat. ion was erroneous, and reflected a' lack of knowledge cbout the system. This would

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indicate that not only were the irdividuals involved in the performance of the calculation and its QA review unfamiliar with

'

system oparation but that the acceptance of the calculation to

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close the SSFI concern was based strictly on the fact that s

paperwork was provided without independent assessment of its validity by the individual knowledgeable of the system who had

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made the original finding.

In this case the corrective action had been inader nte tc address the-finding.

The appropriate

corrective act wn would hevt been to revise the alarm setpoint.

'

L The secono case dealt with the performance of 50.59 safety

evaluations.

In this case, the corrective actions were incomplete in that they had focused on future performance of 50.59 activities without consideration of those activities in process. The specific modification identified by the NRC team had not been completed as of the time when the self-SSFI was performed, and although deficiencies were identified by the self-SSFI in the performance of 50.59 reviews, the corrective actions were focused on providing adequate requirements in the new modification program. However, it was not apparent that any actions had been taken to address modifications that were "in the piprH ne" to ensure that the safety evaluations associated with them

were acceptable. These would include modifications that were yet to be completed utilizing the old modification program or that had been

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installed after completion of the self-SSFI. 'In'this case, the H

corrective actions were incomplete regarding the finding and

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have resulted in an additional. violation.

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The third case dealt with the updating of drawings to reflect i

'

_ as-built conditions for the Unit I diesel generator air start system.

r

._

The'self-SSFI on Unit 2 HPCS had identified several cases where

"

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drawings did not match the u-built conditions.

However.in one e

case, the corrective action 'or the air start drawing had been Unit 2 specific.

In this case, P&lDs for the HPCS diesel generator air

,

,

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start systems _for units 1 and 2 were compared. Although the drawings

A for' Unit 2 had been revised to incorporate the air pressure gauges

- that were. installed, the P& ids for diesel generator air start systems IB,-1A, 2A, and 0 did not show the installed pressure gauge at the end of the air manifold.

In this case, the corrective actions were -

incomplete regarding the finding in that the drawing errors were not corrected for the otbe: _ diesel generator air start systs P& ids. The l

_

licensee iritiated corrective actions to correct these drawings. The failure to extend corrective actions to all affected nonconformances

.is-_an example of a violation of Criterion XVI of Appendix B to 10 CFR l

Part 50;. however, since this example would be considered to be a t

Severity Level V based on minor saf ety significance; and the licensee initiated corrective actions prior to completion of the inspection; no notice of; violation-is being issued because the criteria of

5ection V.A ofL10 CFR Part 2, Appendix C, have been met, j

'5.0- OPEN ITEMS d

Open items are matters which have been discursed with the licensee-t which will be reviewed further by the inspector, and which inv:1ved i

some action on the part of the NRC or the licensee or both.

Open

iteas determined during this inspection are discussed in Paragraphs i

4.1.1.1, 4.1.1.3, 4.1.3.2, 4.3.2, 4.3.3, 4.3.4, and 4.6.2 of this report.

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6.0 UNRESOLVE0' ITEMS Unresolved items are matters about which more information is required in order to ascertain whether they are acceptable items, violations, or deviations.

Unresolved items disclosed during this inspection are c'iscussed in Paragraphs 4.1.2.2, 4.1.2.3, 4.1.2.5, and 4.1.4.2 of

.this report.

7.0 PERSONNEL CONTACTED

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Commonwealth Edison

• G. J. Dieoerich, Station Manager, LaSalle County Station (LSCS)

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• J. C. Renwick, Production Superintendent, LSCS

+* W. R. Huntington, Technical Superintendent, LSCS

+* T. A. Hammerich, Regulatory Assurance Supervisor, LSCS

• 4. L. Massin, Engineering Pr. ject Manager, LaSalle, CECO

'

• G. L. Swihart, Safety Systems Groi.p Leader, Techn W.1 Staff, LSCS

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Commonwealth' Edison (

.* D. A.; Spencer, Technical Staff, LSCS

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. +*: B.: M,' K.: Wong, BWR Systems-Engineering, Ceco

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+* W. Morgan, LaSalle Licensing Administrator, CECO j

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G. P. Wagner, Nuclear Engineering Manager, CEro

't MJ L.' Reed, BWR-Systems Engineering,' Ceco m

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• D. R. Szumski, Technical Staff, LSCS.

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J. S. Abel, BWR Systems. Engineering Manager

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'+ L 0..De1 George,. Assistant Vice President, Quality Programs and

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Assessment

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P. F. Manning, Team Leader, CECO Self-Initiated SSFI

+

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J. D. Brunner,' Assessment Administrator,. Performance Assessment i

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'D. A. Brown, Superintendent of Quality Assurance / Nuclear Safety.

.

R.-J. Cozzi, Senior Particirant, Of fsite Review and. Investigative

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Function

• T. Benoit, Quality Assurance f

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• M. A. Harper, Quality Asturance

-' L. A._Lauterbach, Onsite Nuclear. Safety.

• R. D..Crawfo-d,LMaster Electrician, Electrical Maintenance J. Miller,- Assistant Technical Staff Supervisor

.P. Sampson, Technical-Staff, Systems Engineer J. Foster, Principal Engineer, Mechanical Maintenance

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F..J. Lentine,. Superintendent, PWR Design Engineering

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Sargent and-Lundy' Engineers

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• M. A. Navarro, Licensing.

• G. I Zwarich,. Project Manager

• D. A. ' Kolczak,. Electrical Project Engineer

.

+- H. A. Furlager, Project Engineer R. H, Pullock, Project Manager

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Illinois Department of Nuclesr Safety

• J. Roman, Resident Engineer U.S. Nuclear Regulatory Commission

- C. J. Paperiello, Deputy Regional Administrator

+

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H. J. Miller, Dire tor, Div1sion of Reactor Safety

+

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+* T. O. Martin, Deputy Director, Division of Reactor Safety

,

• G. C. Wright,-Chief, Operations Branch, Division of Reactor Safety g

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• R. M. Lerch, Acting Chief, Sectior, IB, Division of Reactor Projet

• R. D. Lanksbury, Senior Resident Inspector

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• Attendeo the preliminary exit 'neeting on August 25, 1989.

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+ Attended the management exit meeting on October 10, 1989.

Other persons were contacted during the course of the inspection, l,

. including members of the licensee's system and design engineering staff, training department, operations department, and maintenance department.

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- 8.0- MANAGLMi.l!T-EXIT IK_TE_RV.IEWS

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The term lmetisith-t'dilicensee representatives denoted in Paragraph 7.0 i

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above'attihe. conclusion o' the inspection. The team summarized the scope r

land-findings.of the, inspection at a preliminary exit meeting on August 25,-

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1989;_~'A m:nagement exit meeting was held on October.10, 1989, to

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characterize

those findings which had been determined to be apparent '

violations. of NRC requirements and to present the'_overall conclusions l

reached by the inspection. team. The team also. discussed the likely

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informational: content'of this inspection report during the August 25, j

1989 meeting. The licensee acknowledged the information presented, and

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-k did not indicate'that any of the.information disclosed during the

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. inspection could be considered pr jetaryinnature.

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