IR 05000458/1998016

Insp Rept 50-458/98-16 on 980730-0807.Violations Noted. Major Areas Inspected:Engineering & Fire Protection.Also Reviewed,Status of Various Programs Which Were Planned or in Progress

ML20198N931
Person / Time
Site:	River Bend
Issue date:	12/29/1998
From:	NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION IV)
To:
Shared Package
ML20198N889	List: IR 05000458/1998016 ML20198N884 ML20198N915 ML20198N931
References
50-458-98-16, NUDOCS 9901060254
Preceding documents:	ML20211Q772 (9 September 1999)
Download: ML20198N931 (55)

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ENCLOSURE 2 U.S. NUCLEAR REGULATORY COMMISSION

REGION IV

Docket No.: 50-458 License No.: NPF-47 Report No.: 50-458/98-16 Licensee: Entergy Operations, In Facility: River Bend Station Location: St. Francisville, LA Dates: July 20 through August 7,1998 l Inspectors: M. Runyan, Reactor Inspector, Engineering Branch P. Goldberg, Reactor inspector, Engineering Branch R. Bywater, Reactor inspector, Engineering Branch P. Qualls, Fire Piotection Engineer D. Wigginton, Project Manager R. Fretz, Project Manager Accompanying T. Tinkel, Consultant i Personnel: R. Cooney, Consultant l l

Acproved By: T. Stetka, Acting Chief, Engineering Branch Division of Reactor Safety

ATTACHMENT: Supplemental Information I

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9901060254 981229

PDR ADOCK 05000458

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TABLE OF CONTENTS I

EX ECUTIVE SU M MARY . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . iv l

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Report Details . . . . . . . . . . . . . . . . . . . . . . . . ....................... .. ........ 1 '

111. Engin e e rin g . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1 E1 Conduct of Engineering . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1 l E Standby Gas Treatment System . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1 l E1.2 4.16 kV Electrical Distribution System . . ......... ..... ..... 5 E1.3 High Pressure Core Spray System . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7 E1.4 Condition Reports . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10 l E1.5 Temporary Alterations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 12 E2 Engineering Support of Facilities and Equipment . . . . ................ 14 E Evalcation of 10 CFR 50.59 Safety Evaluation Program . . . . . . . . . . 14 E4 Engineering Staff Knowledge and Performance . . . . . . . . . . . . . . . . . . . . . . 16 E General Engineering Experience and Competence . . . . . . . . . . . . . 16 I E8 Miscellaneous Engineering Issues . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 17 I E (Closed) Inspection Followup Item 50-458/9621-01: Entergy Operations, l

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Inc., Resolution of Quality Assurance Program Required for Resource S ha rin g . . . . . . . . . . . . . . . . . . . . . . . . . . ....... ... ....... 17 E8.2 (Closed) Inspection Followup item 50-458/9622-01: Adequacy of Molded i Case Circuit Breaker Trip Setpoints . . . . . . . . . . . . . . . . . . . . . . . . 17 I

E8.3 (Closed) Inspection Followup Item 50-458/9627-02: NRR to Review Near-Buoyant Objects . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ..... 18 E8.5 (Closed) Licensee Event Reoort 97-007: Cracked Screw Assembly Swivel Pads on Emergencj Diesel Generators Could Have Prevented Fulfillment of Safety Function . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 19 E8.6 Engineering Backlog . ...................................20 E8.7 System Engineering . . ...................................20 l E8.8 USAR Review Program . . . . . . . . . . . . . . . . . . . . . . . . .. ....... 21 1 E8.9 Year 2000 Computer issue . . . . . . . . . . . . . . . . . . ....... .... 22 IV. Plant Support . . . . . . . . . . . . . . . . . . . . . . . ............................. .... 23 F8 Miscellaneous Fire Protection Issues . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 23

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F (Closed) Unresolved Item 50-4J8/97201-01: Smoke detector application, placement, and installation in fire area C-24 does not meet requirements  ;

of License Condition 2.C.10 . .. ............. ..... . .... 23 l F8.2 (Closed) Unresolved item 50-458/97201-02: Failure to include fire l protection check valves in a functional testing program . . . . . . . . . . . 23 I F8.3 (Closed) Unresolved item 50-458/97201-03: Lack of engineering evaluations to establish the fire-rating or fire-resistant capabilities of fire-rated boundaries. . . . . . . . . . . . . . . . . . . ............... . .25 l

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F (Closed) Unresolved item 50-458/97201-04: Outdated equipment and failure to assign personnel to the fire brigade who have normal plant duties that do not conflict with their response to a plant fire. . . . . . 26 F (Closed) Unresolved Item 50-458/9720105: Failure to perform an adequate operability assessment and provide appropriate compensatory measures for conditions affecting the functionality of post-fire safe-shutdown capability. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 27 F (Closed) Unresolved item 50-458/97201-06: Failure to perform an adequate post-fire safe. shutdown analysis that meets the licensee commitment to Sections Ill.L.1, Ill.L.2, and Ill.L.7 of Appendix R to 10 CFR Fad 50 . . . .. ............................. .... 27 F (Closad) Unresolved nam 50-458/97201-07: Deficiency in the design of the reactor overpressure protection system, under certain postulated conditions, could lead to inadvertent actuation of 16 SRVs resulting in an un-analyzed plant transient . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 31 F8.8 Othe r FPFi lssues . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 32 F8.8.2 Control of Combustible Materials . . . . . . . . . . . . . . . . . . . . . . . . . . . .33 V. Manag e m ent M e e ting s . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . A XI Exit Me etin g Sum mary . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 34 iii

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i EXECUTIVE SUMMARY  !

River Bend Station NRC Inspection Report 50-458/98-16  ;

i t uring the period of July 20 through August 7,1998, an engineering and fire protection inspection was conducted onsite. The safety system engineering inspection was performed on the standby gas treatment system, the 4.16 kV electrical distribution system and the high prestare core spray system. in addition, a followup inspection of previous inspection findings l was conducted in engineering arc. ; ire protection. The team also reviewed the status of various programs which were planned or in progres Overall, the team determined that engineering activities were generally effectively implemente This determination was based on calculations, modifications, and condition reports that l exhibited sound engineering practice Enaineerina

• The quality of recent design calculations showed improvement over earlier design calculations, in that they contained more detail and were sufficient to facilitate an independent review of the design. The older calculations were found to be adequate after consultations with licensee engineers (Section E1.1.2).

• The team concluded that the 4.16 kV electrical distribution system was well designed and its design basis was well documented. The methodology used in updating older calculations was a strength (Section E1.2.2).

• No discrepancies were identified for the surveillance testing of the 4.16 kV electrical distribution system. The time delay relay settings for loss of power instrumentation surveillances were ir. correctly listed in the Updated Safety Analysis Report; however, these settings were correctly stated in the Technical Specifications and in the associated surveillance procedures (Section E1.2.3).

• A problem was observed in the relief valve setpoint program, in that data sheets, with values often differing from the design cold set pressure, had been used in one case to set a relief valve, resulting in an improper setting. The licensee quickly recognized the error, which did not introduce a safety concern, and corrected it (Section E1.4).

• The team observed that two failures of the high pressure core spray system discharge relief valve had occurred within the past four years. The licensee was still in the process of determining the root cause (Section E1.4).

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= The temporary alteration program was effectively implemented. However, in response '

to NRC questions, the licensee determined that containment temperature had, on one occasion. dropped to 60 degrees Fahrenheit compared to an assumed design minimum temperature of 70 degrees Fahrenheit. The licensee initiated a condition report to resolve the implications of this discrepancy (Section E1.5).

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• Overall, the 10 CFR 50.59 program was found to be satisfactory. However, the failure to identify as an unreviewed safety question an increase in the calculated doses for a loss of coolant accident as reported in the updated safety analysis report was identified as a violation of 10 CFR 50.59. Specifically, the exclusion area thyroid dose increased from 32.8 to 37.8 rem, and the low population zone thyroid dose increased from 50.3 to 115.1 rem (Section E2.1).

• The team concept developed in system engineering was effective because the assignment of several individuals to each system increased the overall level of expertise and provided more flexibility in supporting operations (Section E8.7).

Plant Support

• The failure to provide a procedure for using standby service water for fire protection was identified as a noncited violation (Section F8.2).

• The condition where a postulated fire could have potentially caused all 16 safety relief valves to open due to a fire-induced circuit failure was identified as a violation for failure to implement the provisions of the fire protection program as required by Operating License Condition 2.C.10. However, the licensee identified the violation and committed

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to perforrn a modification to correct the condition during the April 1999 refueling outag in accordance with Section Vll.B.6 of the NRC's Enforcement Policy, the NRC exercised discretion and did not propose a civil penalty nor issue a violation in this case (Section F8.6).

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Report Details Summary of Plant Status

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The unit operated at full power during the onsite portion of the inspection.

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! l E1 Conduct of Engineering E1,1 Standby Gas Treatment System

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'E1.1.1 System Descriotion L Mechanical

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in the post-accident mode following a design basis accident (DBA), standby gas treatment system (SGTS) fans draw down and maintain a negative pressure in the containment annulus and auxiliary building. The technical specifications (TS) require the SGTS to draw down the annulus to a negative pressure of at least 0.5 inches water glass (wg) within 18.5 seconds of system initiation and to draw down the auxiliary building to a negative pressure of at least 0.25 inches wg in 13.5 seconds. Air removed

! from these areas is processed through the SGTS filter train before it is discharged to the atmosphere. The filter train processes potentially contaminated air from the annulus and auxiliary building following a DBA to limit thyroid and whole body dose to within the limit 1 of 10 CFR Part 100 at the site boundary (exclusion area boundary) and low! population zone outer boundary. Following initial draw down, the SGTS is designed i

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to maintain a negative pressure of less than 0.5 inches wg in the annulus and less than O.25 inches wg in the auxiliary building continuously for 100 days.

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The major components of this system receive electric power from 480 volt standby buses 1EJS*LDC 1 A&2A (Red Train) and 1EJS*LDC 1B&2B (Blue Train). These 480

voit buses are in turn fed from 4.16 kV standby buses ENS-SWG 1 A&1B respectively, j which are provided off site power via 230 kV-4.16 kV Reserve Station Service

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Transformers RTX-XSR 1C&1D. The 4.16 kV buses may also be provided with power l by emergency diesel generators (EDGs) 1EGS-EG1 A & 18 when power is not available from the gri The air-operated fan and filter inlet and outlet dampers are operated by 125 volt de solenoid valves. On a loss of de power, the dampers fail open. Red train solenoids are supplied power by de bus EMB-SWG01 A and blue train solenoids are supplied power by de Bus EMB-SWG01B.

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The 480 volt fans and the filter heater circuit breakers have solid state tripping devices, which operate on overcurrent. The breakers are also tripped by load shed signal ,

The fans are started automatically by load sequencer signals, by Radiation '

Monitor RMR-RE103, and by loss of air flow from the opposite-train fa J E1.1.2 Desian Review Insoection Scoce (93809)

Mechanical The team exam'ned portions of various documents that discussed the safety and design basis of the SGTS. These documents included the Updated Safety Analysis Report (USAR), TS, the system requirements documents, calculations, drawings, and condition reports (CRs). Additionally, discussions of various related topics were conducted with licensee engineer Electrical The team reviewed one-line diagrams to assure that redundant components were fed from separate buses and reviewed one calculation involving the fan flowswitche Observations and Findinas - Mechanical i USAR Fidelity The team's review of the USAR identified a few examples of incorrect information in the SGTS sections. USAR Section 6.2.3.2.1, stated that the SGTS fan receives power from the EDG within 38 seconds after the design basis accident (DBA) (i.e.,

30 seconds plus 8 seconds for the fan to attain rated speed). A review of other documentation (e.g., Calculations ES-194-3," Auxiliary building pressure following a loss-of-coolant accident (LOCA)," Revision 3, and G13.10.2.7*23, " Shield building 1 J annulus following a LOCA," Revision 1) and discussions with engineering personnel )

confirmed that the 38-second value was incorrect. The correct value was 48 seconds, i The incorrect 38-second value also appeared in Table 6.2-34 and Figure 6.2-61 USAR Section 6.2.3.3, discussed the positive pressure period (PPP) for the annulus and auxiliary building. The PPP is the time following a DBA that the pressure is more positive than -0.25 inches wg. The USAR stated that the PPP for the auxiliary building was 111 seconds. A review of other documentation and discussions with engineering personnel confirmed that the 111-second value was incorrect. The team noted that the i

associated procedures were not affected by this USAR discrepancy.

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The licensee had already identified these errors during their ongoing USAR programmatic review, but the USAR had not yet been updated at the time of this l inspection. The team determined that the errors did not result in a safety concern. The l licensee was also aware of some additional SGTS USAR errors, and License Change I

Notice (LCN) 15.06-006 was in process to correct them. The failure to update the USAR was considered to be a violation of 10 CFR Part 50.71(e). This failure constitutes a violation of minor significance and is not subject te formal enforcement actio Calculations I

The team found that certain older River Rend Station (RBS) calculations for SGTS lacked sufficient explanation and detail in some areas to permit an independent review without obtaining additional information.

l The team reviewed Calculation BV45.22-1," Fan External Total Pressure Fans 1GTS*FN1 A & FN1B Annulus and Auxiliary Building Exhaust, Accident Mode,"

Revision O. This calculation was designated safety-related. The pressure drop calculation for node 4 to 5 used an input value of 2.269 inches wg based on l

Calculation BV45.20-1, " Fan External Total Pressure 1GTS*FN1 A & FN1B Containment /Drywell Purge Exhaust, Normal Operation Mode lil," Revision 1. A cross check of Calculation BV45.20-1 did not reveal how the 2.269 inch water value was determined. When presented with this observation, the licensee informed the team that after performing their own review, they determined that the result of this portion of the calculation was correct as stated. The team verified that the calculation was correc However, the licensee agreed that the calculation lacked sufficient detail to readily understand how the 2.269 inches wg value was derived in this portion of the calculatio .

The licensee stated that this information would be added to Calculation BV45.22- The team reviewed Calculation PB-251,"To Determine the In-Leakage and Amount of Exhaust Air Required To Maintain A Negative Pressure of 1/4 in. W.G. in the Aux. Bldg,"

Revision 0. This was a safety-related calculation. The team noted that the calculation was overly conservative in determining the time to achieve negative pressure in the auxiliary building. This resulted in an oversized fan being specified. The licensee agreed with the team's observation that the oversized SGTS fan would create a larger negative pressure condition in the auxiliary building than otherwise required by the design. While l the team noted that plant operation and testing confirmed this observation and that this condition did not represent a safety concern, the team also noted that the higher negative pressure caused door passage problems. The team considered this problem to be a burden for site personnel The effect of this condition on plant operations is j further discussed in Section E8.2 of NRC Inspection Report 50-498/980 The team reviewed Calculation G13.18.2.1*079-00," Evaluation of Standby Gas l Treatment System Drawdown Data," Revision 0. This was a recently prepared

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safety-related calculation that was representative of the quality of calculations currently being prepared by the licensee. This calculation was considered to be well written and

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exemplified the team's general impression that the technical quality of calculations was improvin t

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Observations and Findinas - Electrical The team reviewed Calculation IA-GTS*1,"Setpoint Calculation 1GTS*FS 24A & B,"

i'ievision 4, which was the safety-related setpoint calculation for the flowswitches that monitor airflow from Fans 1GTS*FN 1 A&18. No discrepancies were identified in this revie Conclusions Some portions of the USAR contained incorrect information in the sections affecting the SGTS. The licensee had previously identified these errors and was in the process of correcting them. Some older SGTS calculations lacked sufficient detail to permit a meaningful independent review, without obtaining clarification from licensee personne The quality of more recent calculations showed improvement over earlier calculation l E1.1.3 Surveillance Testina Inspection Scope (93809)

The team examined portions of selected documents that discussed surveillance test requirements for the SGTS. Primarily, these documents were the TS and condition reports (CRs) that addressed issues related to SGTS surveillance test results. Selected requirements found in the evaluation of the CRs were compared to corresponding TS requirements for consistenc l Observations and Findinas j

No areas of concern were identified during this revie l I

' Conclusions The team concluded that the surveillance testing program with respect to the SGTS was j satisfactor )

E1.1.4 Desian Modifications Insoection Scope (93809)

The team reviewed four engineering requests (ERs) that documented plant modifications affecting the SGTS. In add un to the documentation for the particular modification, other documentation contained or referenced in the ER documentation

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packages were selectively reviewed. These documents included 10 CFR 50.59 screenings and evaluations, calculations, and LCNs.

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No areas of concern were identified during this review.

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. Conclusions The team determined that the plant modification program with respect to the SGTS was satisfactor E1.2 4.16 kV Electrical Distribution System E1.2.1 System Descriotion The standby power system, which supplied Class 1E safety-related motors and 4.16 kV/480 volt load centers, was arranged in three divisions. These divisions were designated Train A (Red), Train B (Blue), and Train C (Orange).

Train A was supplied power from the 230 kV grid by preferred Station Service Transformer 1RTX-XSR1C, whereas Train B was supplied from the 230 kV grid via preferred Station Service Transformer 1RTX-XSR1D. Train C was supplied power from 1NNS-SWG1C, which in turn was supplied by either 1NNS-SWG1 A or 1NNS-SWG1 Those switchgear sections were supplied from the 230 kV grid by either Station Service Transformer 1RTX-XSR IC or 1D. Each of the divisions was also provided with an emergency diesel generator (EDG).

E1.2.2 Desian Review Inspection ScoDe (93809)

The team reviewed System Design Criteria Document SDC-302 ENS," Safety Related 4.16 kV Electrical Distribution System Design Criteria," Revision 0, seven design basis calculations, seven CRs, two ERs, four one-line diagrams, the USAR, and seven surveillance test procedures (STPs). The team assessed technical adequacy, consistency, and completeness of the system. The team also conducted a walkdown of the 4.16 kV switchgea Observations and Findinas The team determined that the system design criteria document was satisfactory in scope and accuracy. The criteria clearly described the safety function of the Class 1E standby buses. The criteria also addressed the supply of nonsafety-related plant auxiliaries that require a reliable power supply and were therefore fed from the safety-related buse Most of the calculations reviewed by the team were performed originally by an architect / engineer. The licensee was in the process of updating most of these calculations. The newly revised calculations were observed to be of considerably better quality than the originals. The team considered the licensee's ongoing efforts to update the existing electrical calculations to be a strengt No discrepancies were identified during the system walkdow i l

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. Conclusions The team concluded that the 4.16 kV electrical distribution system was well designed and documented. The methodology used in updating older calculations was a strengt E1.2.3 Surveillance Testing Inspection Scope (93809)

The team reviewed Procedure STP-302-1601, " ENS-SWG1 A/B Loss of Voltage Channel Calibration and Logic System Functional Test," and the resultant data from procedure performanc Observations and Findinas The tearn observed that the surveillance test results for STP-302-1601 were satisfactory for the last three times it was performe The team identified discrepancies associated with time delay relay settings in the loss-of-power instrumentation surveillance tests listed in TS Table 3.3.8.1-1. There were inconsistencies among the values in this table and those reported in the USAR and the STPs. USAR Section 8.3.1.1.3.9 lated the second time delay associated with degraded voltage for Divisions 1 and E as 50 seconds, whereas TS Table 3.3.8.1-1 listed this time as 60 seconds. The same 'ISAR Section listed the time delay associated with Loss of Voltage for Division 3 es 2 seconds while item 2.b of the TS Table 3.3.8.1-1 listed this time as 3 seconds. The USAR Section listed the first time delay associated with Division 3 degraded voltage as 10 seconds whereas item 2.e of the same TS table listed it as 3 second The licensee responded to the team's observation with documentation that indicated that the values in the USAR were in error and that the TS and surveillance procedures were correct. The team agreed with the licensee's response and noted that since the TS and the surveillance test procedures were correct, the error had not affected the validity of past surveillance tests. In response to the team's finding, the licensee initiated CR 98-1004, which identified the discrepant condition and recommended that the USAR be revised to agree with the TS. This failure to correct the USAR error was a violation of 10 CFR 50.71(e). This failure constitutes a violation of minor significance and is not subject to formal enforcement action. In addition, since the licensee's review of the USAR was in progress and, because additional reviews by the licensee in this USAR section were pending, the team considered it likely that this inconsistency would have been discovered and corrected independently by the license Conclusions in a limited sample, the team did not identify any discrepancies in surveillance testing of the 4.16 kV electrical distribution system. Some USAR discrepancies, which were not safety significant, were identified during this revie .. - - _ _ _ _ - _ - _ _ _ _ _ - _ _ _ _ _ - _ - _ _ _ _

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E1.2.4 Desian Modifications Insoection Scoce (93809)

The team reviewed Modification Requests 86-0595 and 86-111 Observations and Findinas Modification Requests 86-0595 and 86-1119 involved changing time delay relay settings used in EDG starting circuits. The modification requests were complete and included satisfactory safety evaluation Conclusions Based on review of the selected modification requests, the team concluded that these modifications of the 4.16 kV electrical distribution system were satisfactor E1.3 Hiah Pressure Core Sorav System E1.3.1 System Description Mechanical The high pressure core spray (HPCS) system is one of the four subsystems that comprise the emergency core cooling system (ECCS) that cools the reactor following a loss of coolant accident (LOCA). If the break is small, the HPCS system is designed to

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maintain coolant inventory as well as vessel level while the reactor coolant system is still pressurized. If the water levelis not maintained by the HPCS system, the automatic depressurization system (ADS), low pressure coolant injection (LPCI) system, and/or the low pressure core spray (LPCS) systems are automatically initiate The HPCS system consists of a pump, discharge piping fill pump, injection valve, spray sparger head, other system piping and valves, suppression pool suction strainer, system instrumentation and controls, and electrical switchgear and power supplies. The system is designed to operate from normal offsite auxiliary power or from an emergency diesel generator (EDG) if offsite power is not availabl The HPCS system cerves as a backup to the reactor core isolation cooling (RCIC)

system to maintain the reactor water level in the event the reactor becomes isolated from the main condenser during operation and feedwater flow is los Electrical The HPCS pump motor receives electric power from Division 3,4.16 kV standby bus E22*S004. The motor-operated valves that are part of the HPCS system are supplied power from standby MCC 1E22*S002, which is fed from the Division 3,4.16 kV bus via 4.16 kV /480 volt transformer 1E22*S003. Although not part of the HPCS system, the standby service water (SSW) pump motor (SWP-P2C) is also supplied power from bus E22*S004. The normal supply to E22*S004 is from 1NNS-SWG10, which in turn is

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supplied by either 1NNS-SWG1 A or SWG18. Both of these buses are supplied from the 230 kV grid via preferred station service transformers 1RTS-XSR1C or XSR1D.

l When the normal supply to E22*S004 is lost, the EDG supplies power to the syste volt dc power is provided to the diesel generator and to E22*S004 from battery 1 E22*S0018AT via 125 volt de bus 1 E22*PNLS00 E1.3.2 Deslan Review Insoection Scoce (93809)

i The team examined portions of various documents that discussed the safety and design basis of HPCS. These documents included the USAR, TS, system requirements documents, calculations, drawings, and test reports. Additionally, discussions on various ietated topics were conducted with engineering personne Observations and Findinas USAR Fidelity The review of the USAR identified one example of incorrect information in the HPCS sections. Table 6.3-1 stated that at 30 seconds following the start of a DBA LOCA, the HPCS injection valve is open and the pump is delivering design flow, completing HPCS startup. Based on a review of other portions of the USAR and discussions with the licensee, the 30 second value was determined to be incorrect. The correct value was 27 seconds. Upon additional review, the licensee determined that this was an i

administrative error and that the 30 second value should have been removed with other changes addressed by LCN 06.03-030 dated December 12,1997. This failure to correct the USAR was a violation of 10 CFR 50.71(e). This failure constitutes a violation of minor significance and is not subject to formal enforcement action. The licensee initiated CR-98-1001 to document the incorrect 30 second value in Table 6.3-1 and indicated that an LCN to change the USAR would follow. The EDG loading calculations were not affected by this erro Calculations The team reviewed Calculation G13.18.2.2*031-0," Net Positive Suction Head (NPSH)

Available for ECCS Pumps for Suction from the Suppression Pool Under Accident Conditions,* Revision 0. This calculation supported analysis of a recent major design modification that installed new design ECCS suction strainers in the suppression poo The team determined that this calculatic? was satisfactor System Desian Criteria The team reviewed the HPCS system design criteria. One example was found where the information was inconsistent with the USAR. Section 3.3.1 of the system design criteria addressed the HPCS pump and stated that the minimum required net positive j suction head (NPSH) for the pump was 2 feet at a reference location 36 inches above

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the pump mounting base plate. A review of the manufacturer's test report T-36631-1, i "HPCS 15 Stage Pump Performance Curve (Byron Jackson)," June 29,1977, indicated i

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- I that the NPSH required was 1 foot, referenced to 3 feet c.bove the mounting flang USAR Table 6.3-13 likewise stated that the HPCS NPSH required was 1 ft at 3 ft above the mounting flange. The licensee stated that this portion of the system design criterion was covered by an open item listed in the back of the system design criteria that indicated that an update was required because of the ECCS suction strainer modification (i.e., the error was scheduled to be corrected). Because this error did not affect the analytical design of the plant, the team noted that the discrepancy did not constitute a safety concern.

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Setooint Calculations The team reviewed Calculations 1 A-E22*04, "Setpoint Calculation HPCS Condensate Storage Tank Low Level," Revision 2, and 1 A-E22'05, "Setpoint Calculation 1E22*ESN655C & G," Revision 4. The methodology used in both setpoint calculations was in accordance with applicable standards. The team did not observe any assumptions that were not acceptable and considered these calculations to be satisfactory, Conclusions One portion of the USAR contained incorrect information in the sections affecting HPCS. One example was found in the HPCS system design criteria where information was inconsistent with respect to the USAR. Three calculations supporting the HPCS design were observed to be satisfactor E1.3.3 Surveillance Testina Inspection Scope (93809)

The team examined portions of selected documents that discussed surveillance test requirements for the HPCS system. These documents included the TS, surveillance test procedures (STPs), and related CR Observations and Findinas The team examined selected requirements in the STPs were compared to corresponding requirements to assure consistency. In addition, selected test results were reviewed to compare for consistency with the corresponding procedure and to confirm that the results were within acceptance limits. No areas of concern were identified during this revie Conclusions The team determined that the surveillance testing program with respect to the HPCS system was satisfactor . .. .

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E1.3.4 Desian Modifications Insoection Scope (93809) .

The team reviewed three engineering requests (ERs) describing plant modifications that -

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' Observations and Findinas No areas of concern were identified during this review. The team determined that the plant modification program with respect to the HPCS system was satisfactor Conclusions The team determined that the plant modification program with respect to the HPCS system was satisfactor E1.4 Condition Reports I Insoection Scoce (37550)

The team reviewed Procedure RBNT-030, " Initiation and Processing of Condition Reports," Revision 12. In addition, the team reviewed 46 CRs associated with the )

' SGTS, the HPCS system, and the 4.16 kV electrical distribution system. The team 1

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discussed the CR process and some of the CRs with licensee personne Observations and Findinas )

The team determined that the CR process provided a single process for documenting the evaluation and resolution of problems, concerns, activities, and conditions that could adversely affect or have the potential to adversely affect the safe operation of the plan As an overall observation, the team found that the licensee was using the CR program successfully, in most cases, corrective actions were complete and well documente The team reviewed CR 97-1881, dated October 20,1997, and CR 97-2131, dated December 18,1997. The first CR, CR 97-1881, stated that the set pressure of the HPCS diesel generator starting air relief valves was set too low and reset them from 250 to 270 psig by means of Maintenance Action item Number 313888. The licensee concluded that the setpoint was incorrect because the valve data sheet listed the j setpoint as 270 psig. The inservice test procedure correctly listed the spring set 1 pressure as 250 psig. At the time, the licensee erroneously assumed that the setpoint value in the inservice test procedure was not correct. The second CR, CR 97-2131, .

documented that the relief valves were incorrectly set at 270 psig. The licensee initially l concluded that the maintenance personnel incorrectly read the setpoint data shee However, subsequent to this finding, the licensee realized that the new set pressure was incorrect and promptly installed valves with a setpoint of 250 psig. The team reviewed a number of safety and relief valve data sheets for setpoints and compared these values with the spring set pressure listed in Procedure STP-000-6606,"Section XI

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Safety and Relief Valve Testing," Revision 6. The procedure defined the cold differential l l test pressure as the inlet static pressure used for bench testing the valve. This set l pressure was adjusted for back pressure and temperature. The team noted that the valve data sheets contained only the process setpoint, not the cold differential test i

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pressure. Out of 31 data sheets reviewed, the team found 13 examples where the setpoint on the data sheet was different from the cold differential test pressure listed in

! the test procedure. These disparities ware not unexpected because of the differences in l how the values are derived, but the team noted that, based on the differences noted, the invalid use of data sheets could result in an incorrect pressure being set in the fiel The team determined that the pressure relief valve set pressure program had a weakness since, at least in this one case, the valve data sheets were improperly used for determining spring setpoints. For valves within the ASME Section XI inservice Testing Program, the surveillance test procedure was required to be used for setting pressures in the field and the data sheets were for information only. Therefore, this l problem did not appear to involve a safety concern, and the improper use of the data sheets appeared to be isolated. However, the licensee agreed that further actions were needed to correct the noted inconsistencies. The licensee's resolution of relief valve setpoints was identified as an inspection followup item. (50-458/9816-01)

The team reviewed CR 96-1585, dated August 31,1997, which documented an electrical spike on the reactor building annulus ventilation radiation monitor, which caused a ventilation system isolation and autostart of SGTS Train A. The licensee concluded that the spike was probably due to an electrical noise spike in the detector circuitry. There were two radiation monitors and the SGTS would start if one of them alarmed. Since 1995, there had been shc inadvertent starts of the SGTS caused by

false alarms of a radiation monitor. The underlying cause of the problem was an l

actuation logic (one out of two) that did not preclude system actuation from a single faulty detector. The team identified this situation as an observation but noted that the inadvertent actuations did not present a safety concer The team reviewed CR 97-0804, dated May 29,1997, which documented the failure of the HPCS pump discharge relief valve. The licensee discovered that the bellows in the relief valve was broken, which allowed water to exit the weep hole in the valve bonne The licensee performed a root cause inspection and came to a preliminary conclusion that the bellows failed due to chloride stress corrosion cracking. The licensee consulted the valve manufacturer who stated that the only bellows failures they had seen were cause:I by valve cycling, which fatigued the bellows. The vendor stated that they had not seen a beliows failure due to chloride stress corrosion cracking. During reviews prompted by NRC questions during the inspection, the licensee determined that the bellows in the same valve had failed in 1994. The 1994 failure was only documented as a work request, not as a CR. As a result, the licensee had been unaware that the bellows failure in 1997 was a repeat failure. The team was concerned that the use of work requests could preclude the identification of repeat occurrences. Since CR 97-0804 was not yet closed, the licensee initiated another action to discuss the bellows failure with the system engineer to determine if, during quarterly surveillance testing of the HPCS pump, the relief valve cycled or chattered. The team noted that the failure of the bellows would cause the opening pressure of the relief valve to be higher than intended and, therefore, result in a higher pump discharge pressure. The team

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concluded that even with this postulated pressure increase, the increase would not damage the system and that the system would still be operable. Review of the licensee's determination of the root cause of the relief valve failure and the licensee's review to investigate the possible misuse of the work request system in 1994 was identified as an inspection followup item (50-458/9816-02). Conclusions in most cases, engineering actions in response to CRs were satisfactory. Several problems involving the relief valve setpoint program and a relief valve failure were noted and brought to the licensee's attentio E1.5 Temocrary Alterations Inspection Scope (93809)

The team reviewed the licensee's temporary alteration program and discussed some of the safety-related temporary alterations with appropriate licensee personnel, in addition, the team reviewed Procedure ADM-0031," Temporary Alterations," Revision 8 Observations and Findinas The team noted that the procedure defined a temporary alteration as any temporary change that did not conform to approved drawings or other design documentation or changed the design function of the equipment. The procedure specified that a temporary alteration could not remain open beyond the operating cycle in which it was installed unless an extension was obtained in accordance with the procedur Of the 11 existing temporary alterations,2 were installed in 1995,2 in 1996,3 in 1997, and 4 in 1998. Two of the eleven temporary alterations were designated as safety-relate Temporary Alteration Number 96-025," Removal of Standby Liquid Control System Heat Trace Capability and Annunciator Function," dated September 12,1996, removed an annunciator in the control room that was intermittently clarming and considered a nuisance and also removed power to all standby liquid control system heat trace circuit The licensee stated that a pending modification to the plant would eliminate the standby liquid control system suction line heat trace controls and annunciation in the futur The team reviewed the safety evaluation for the temporary alteration. When the system was required to be operable in Modes 1 and 2, the sodium pentaborate se Jtion temperature was required to be greater than 45 degrees Fahrenheit. The team noted that with the improved Technical Specifications, the standby liquid control system was no longer required to be operable in Mode 4 with a control rod withdrawn. The safety evaluation stated that the ambient containment temperature was adequate to maintain the solution above the precipitation temperature. In addition,if the ambient containment

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! temperature decreased such that the solution temperature approached the 45 degrees Fahrenheit limit, the tank heaters were available to provide solution heating. The licensee concluded that because the heat tracing had no function in maintaining the i l system operable or supporting the system response to an accident, there was no effect on operation of the system with the heat tracing disabled.

l The team questioned if consideration was given to a reactor stanup during winter with a cold containment temperature and asked to see the minimum recorded containmcat

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, temperature. During review of this question, the licensee initiated CR 98-0991 after they I determined that the environmental design criterion's minimum containment ambient temperature was 70 degrees Fahrenheit, whereas the minimum recorded containment l temperature was 60 degrees Fahrenheit. The 60 degrees Fahrenheit temperature was recorded during an unplanned outage in January and February 1996. The licensee performed a preliminary review of the qualified equipment in containment. The licensee found that the equipment reviewed were generally unaffected by temperature values l

below 70 degrees Fahrenheit. Most equipment could be shown to be operable at l temperatures of approximately 40 degrees Fahrenheit. As noted above, the sodium l

pentaborate solution in the standby liquid control system required a minimum l temperature of 45 degrees Fahrenheit. The team was satisfied that the standby liquid i control system had not been adversely affected by this low temperature condition.

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In the CR, the licensee recommended that the basis for the minimum containment temperature of 70 degrees Fahrenheit be evaluated and revised as necessary. The licensee also recommended that procedures should be strengthened to provide guidance to monitor containment temperature and to take actions to maintain temperatures during cold weather shutdowns. This issue was identified as an inspection followup item (50-458/9816-03) pending review of the licensee's actions to determine I

whether the 60-degree temperature excursion caused a safety concern, and whether the 70-degree temperature limit should be reduced to accommodate future anticipated low temperatures in containmen Based on the low number of existing temporary alterations and quality of the documentation, the team determined that the licensee was managing the temporary l alteration program in a satisfactory manne ! Conclusions The licensee was managing the temporary alteration program in a satisfactory manne l A question concerning the minimum containment temperature was identified for future followup.

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E2 Engineering Support of Facilities and Equipment E2.1 Evaluation of 10 CFR 50.59 Safety Evaluation Prooram Inspection Scope (37001)

The team reviewed the licensee's 10 CFR 50.59 Safety Evaluation Program in accordance with Inspection Procedure 37001. This included a review of procedures and controls, training and qualifications of personnel performing evaluations, and completed safety evaluation Observations and Findinas Procedures and Controls l

The procedure governing the process for conducting 10 CFR 50.59 safety evaluations l was RBNP-057,"10 CFR 50.59 License Basis Reviews and Environmental Evaluations," j Revision 7. It implementeo the guidelines recommended in NSAC-125, " Guidelines for 10 CFR 50.59 Safety Evaluations," June 1989, as revised by Nuclear Energy Institute (NEI) document NEl 96-07, "10 CFR 59 License Basis Reviews and Environmental Evaluations," dated June 30,1998, Revision 7, to determine whether a proposed change, test or experiment involved a change to technical specifications or an unreviewed safety question (USO). Procedure RBNP-057 assigned responsibilities for l individuals allowed to prepare, review, and approve formal safety evaluations as well as l performing 10 CFR 50.59 applicability screening I The team reviewed the classifications of procedures identified by the licensee in Procedure RBNP-057, as requiring screening and/or a 10 CFR 50.59 evaluation prior to implementing procedure changes. A review of applicable procedures determined that the licensee's classifications were appropriat j The team identified a potential concern with program procer.'ures during review of a 10 CFR 50.59 safety evaluation screening performed for Teroporary Alteration 97-01 This temporary alteration modified the internals of the control rod drive system flow control valves, C11-FCVD012A/B. These valves supply seal injection / purge water to the reactor recirculation pump seals. The temporary alteration was implemented during a recent outage without a 50.59 evaluatio The team was concerned that the 10 CFR 50.59 screening did not properly determine whether a safety evaluation was required. A review of the USAR description by the team for the recirculation pump seals did not reveal any description of the seal injection / purge water system. Therefore, since this information was not described in the USAR, the temporary alteration package screening determination that a 10 CFR 50.59 safety evaluation was not required, was appropriat .

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Trainino and Qualifications The team reviewed training outlines and materials for the initial and requalification programs for personnel responsible to prepare and approve 10 CFR 50.59 safety evaluations. The training materials noted the disagreements between the NRC and the licensee regarding the definition of " increases in the consequences," as discussed later in this section of the repor Imolementation The team reviewed 18 safety evaluations identified on the most recent Summary Report of 10 CFR 50.59 changes. For each item, the team reviewed documentation of the proposed change, the USAR review (including scope of USAR documents reviewed),

technical specification (TS) screening, and appropriateness of the safety evaluation's conclusions. The team determined that each of these safety evaluations was l catisfactor l As discussed above, the fusee recently adopted procedure changes, which implemented NEl 96-07 guidance. All safety evaluations approved by the Facility

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Review Committee after this procedure change went into effect (seven evaluations)

were reviewed in order to determine whether an inappropriate use of an " increase in consequences" was mad Safety Evaluation (SEN) 98-0033, " Revise LOCA Calculations," evaluated an LON, which changed LOCA dose calculation results in USAR Table 15.6-7. The LCN was !

prompted from (1) a revision of the positive pressure period (PPP) in response to NRC Information Notice (IN) 88-76, (2) correction to inaccuracies in the suppression pool j water volume, (3) addition of a liquid leakage term in response to IN 91-56, and (4) l enhancement of engineered safety features liquid leakage. As a result, exclusion area thyroid dose increased from 32.8 to 37.8 rem, and low population zone thyroid dose increased from 50.3 to 115.1 rem. In the 10 CFR 50.59 safety evaluation documentation, the licensee stated that, " . . . the dose consequences remain below the regulatory limits of 10 CFR Part 100 and 10 CFR Part 50, Appendix A, General Design Criterion (GDC) 19 as approved per NUREG-0989 and License Amendment 98." The licensee's position was that, in the safety evaluation report (SER) for License Amendment 98, " . . . the NRC's acceptance criteria for the removal of PVLCS are 10 CFR Part 100 and GDC 19, not the specific values calculated by either the NRC or RBS." This statement conflicted with the NRC's publicly-stated position on increases in consequences. The team determined that the licensee did not appropriately follow the current 10 CFR 50.59 rule and should have declared the dose increase to be a unreviewed safety question (USQ).

The team identified that the licensee's use of NEl guidance for " increases in consequences"; specifically, the guidance on implied approval of 10 CFR Part 100 l

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limits, was contrary to NRC requirement because increases in consequences involve a USO when established licensee analysis values as reviewed by the NRC are exceede )

10 CFR 50.59(a)(1) states, in part, that a holder of a license authorizing operation of a production or utilization facility may make changes in the facility as described in the safety analysis report without prior Commission approval unless the proposed change involves an unreviewed safety questio CFR 50.59(a)(2) states, in part, that a change shall be deemed to involve an unreviewed safety question if the probably of occurrence or the consequences of an accident previously analyzed in the safety analysis report may be increase The implementation of the USAR change as addressed by SEN 98-0033 increased the consequences of a loss of coolant accident because the calculated doses were increased. This was considered to be an unreviewed safety question. The failure to obtain Commission approval prior to creating an unreviewed safety question by changing the facility as described in the USAR was identified as a violation (50-458/9816-04).

However, the team also noted that the low population zone thyroid dose increase was a

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result of overly conservative assumptions and calculations in response to IN 91-56. The IN directly applied to a potential flow path from the safety injection system to the refueling water storage tanks and the licensee made a number of conservative assumptions in order to create an analogous flow path from the residual heat removal (RHR) system to the condensate storage tank. In addition, the licensee did not credit the standby gas treatment system in their dose calculations. The team also noted that no regulatory dose limits were exceeded as the result of this USAR change. As noted in Section XI of this report, the licensee disagreed that this issue constitued a violation of NRC requirement Conclusions Overall, the 10 CFR 50.59 program was found to be satisfactory. Safety evaluation documentation was thorough and provided appropriate justification for the conclusion '

in one case, the licensee inappropriately concluded that a USAR change did not involve an unreviewed safety question. This was identified as a violation of 10 CFR 50.5 E4 Engineering Staff Knowledge and Performance E4.1 General Enaineerina Experience and Competence Inspection Scoce (37550)

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. Observations and Findinas Based on this inspection effort, the team determined that engineering personnel were experienced and possessed good technical and plant knowledge. Personnel knowledge included a good understanding of the engineering processes and organizational j interfaces involved in controlling, maintaining, and supporting the operating plan Conclusions l

Based on the results of this inspection, the team concluded that engineers possessed l good experience levels and competence in completing their assigned task E8 Miscellaneous Engineering issues (92903) l

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E (Closed) Inspection Followuo item 50-458/9621-01: Entergy Operations, Inc.,

Resolution of Quality Assurance Program Required for Resource Sharing i

Backaround This item was opened to track licensee action on a licensee-identified issue involving the <

I lack of clear quality guidelines controlling the procurement of services from one Entergy site by another Entergy site. The licensee generally used standard procurement proceaures for this process but often bypassed these controls. This was a concern because the quality assurance programs varied from site to sit Inspection Followup

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To address this concern, Entergy developed Corporate Policy PL-126," Site Providing Services to Other Sites," Revision 0, dated January 25,1997. Each Entergy site was to revise their site procedures to be consistent with the corporate ,

policy. Procedure RBNP-093," Control of Shared Services," Revision 0, was developed )

to implement the corporate policy and was placed into effect on June 22,199 I

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Based on a review of Corporate Policy PL-126 and Procedure RBNP-093, which l appeared appropriate for the situation and internally consistent, the team concluded that the licensee had adequately addressed this issu E8.2 (Closed) Inspection Followuo item 50-458/9622-01: Adequacy of Molded Case Circuit Breaker Trip Setpoints Backaround Valve E51-MOVF064, RCIC turbine outboard isolation valve, failed to close because its supply breaker tripped in response to an instantaneous reversal from an open to a close demand signal. The licensee's original investigation did not include a review for generic implications, in response to the NRC concern, the licensee reopened their review to identify any generic concern !

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As a separate concern, the NRC noted that the licensee's molded case circuit breakers were set to trip at a maximum of 11 times the fullload current rather than the value of 1.73 times the locked-rotor current, as recommended by the Electric Power Research Institute (EPRI). This was a concern because some high speed motors can have locked-rotor currents approximately 10 times the full load current. Consequently, a current of 11 times the full load current could be as low as 1.1 times locked-rotor current for these motor The safety concern for both issues discussed above was that inadvertent breaker trips could preclude the capability to remotely operate essential motor-operated valve Inspection Followup The licensee issued CR 96-1110A to investigate the NRC concerns. The outcome of a study of the locked-rotor and full load current for all safety-related high speed (>3400 rpm) motors was that 14 molded case circuit breakers were either adjusted or the trip coils were replace As a secondary corrective action, the licensee identified an additional 48 molded case circuit breakers that had instantaneous trip coil settings that were less than 150 percent of the measured inrush current. Of these,14 breakers had been adjusted with the remainder to be completed by the end of 199 The licensee was confident that once the scheduled breaker adjustments are complete, all of the breakers would have settings greater than the EPRI recommended 1.73 times the locked-rotor curren The licensee identified 19 motor-operated valves that could be susceptible to circuit breaker trips during reversals in direction of travel. In each case, the ramifications of this phenomenon were shown to be minimal because of administrative controls, such as limiting conditions for operation being in effect, operators stationed locally, or other administrative controls. The trip of Valve E51-MOVF064 occurred during a refueling

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outage under a limiting condition for operatio The team determined that the licensee had acceptably addressed the concerns regarding molded case circuit breaker settings, pending additional operating experience that may, potentially, necessitate additional actions. The team determined that the ;

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licensee had not violated any plant procedures within this scenario of event E8.3 (Closed) inspection Followuo item 50-458/9627-02: NRR to Review Near-Buoyant Objects Backaround The NRC identified a concern that objects of specific gravity slightly greater than water (near-buoyant) could be carried by a tornado into the SSW cooling tower and be carried into the suction of the SSW pumps. This matter was referred to the NRC program office for further revie i

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Inspection Followuo l The NRC program office determined that licensees do not have to specifically address the effect of near-buoyant debris to meet design mquirements of cooling water supplies unless a significant source of such material exists in the vicinity and is capable of l becoming airborne due to a tornado. The team determined that a source of near-buoyant materials, r,uch as paper, grasses, hardhats, etc., were not present in i sufficient quantities near the plant site. Even if these materials were carrieo into the l cooling tower, the team noted that the licensee would have some tims (a matter of days) .

to clear the debris to ensure adequate long-term coolin l l

E8,5 (Closed) Licensee Event Report 97-007: Cracked Screw Assembly Swivel Pads on Emergency Diesel Generators Could Have Prevented Fulfillment of Safety Function Backaround l The licensee issued CR 97-1647, " Swivel Pads on Cylinders 1 and 2 of the Div 11 Diesel Generator have Cracks," on September 28,1997. The licensee discovered that six valve adjusting screw assembly swivel pads (VASASPs) on the Division i emergency diesel generator (EDG) and four VASASPs on the Division 11 EDG were cracked. The i VASASPs work in conjunction with the valve adjusting screw assemblies, which are threaded screws that allow a fine adjustment of the valve clearances on the EDG. A l failure in this system could cause a loss of EDG function. Although the VASASPs were l cracked, they were functional and could have supported continued EDG operatio However, as a conservative measure, the licensee declared both EDGs inoperable. The plant was in Mode 5 at this time and the licensee entered the appropriate limiting condition for operation. Within 4 days, all VASASPs, whether cracked or not, on both EDGs had been replaced, and both EDGs were declared operabl Inspection Followuo The team reviewed the licensee event report and CR 97-1647. In the root cause determination, the licensee, in consultation with the manufacturer, determined that the cracks resulted from three conditions: (1) the material lot used to manufacture the VASASPs was incorrect and had lower toughness than desired for the application, (2)

the swaging of the VASASPs socket over the ball of the valve adjusting screw assemblies was performed to an excessive degree during the manufacturing process, and (3) the ball on the valve adjusting screw assembly of at least one of the cracked assemblies had an edge that helped to precipitate the crack. The licensee inspected the replacement units before they were installed and determined that none of them were affected by any of the above three conditions. This determination was supported by discussions with the manufacturer, who shted that the swaging process had been revised to prevent excessive swaging and that the materials used in the manufacturing process were of sufficient toughnes The licensee addressed the generic aspects of this event by considering two possibilities: (1) that other components procured from the same manufacturer had similar material and processing deficiencies, and (2) that the manufacturer had supplied other nuclear utilities with defective VASASPs. With regard the first issue, the licensee

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reviewed the vendor's quality assurance program and reviewed the material history of components supplied the manufacturer. Based on this information, the licensee concluded that, absent information to the contrary, it was reasonable to consider the EDGs operable pending discovery of any additional defects. With regard to the second issue, the licensee determined that only one other nuclear plant used VASASPs of this type, and that plant had not installed any VASASPs processed from the defective material lot. The manufacturer processed a report in accordance with 10 CFR Part 21 to notify the industry of the proble The team determined that the licensee had adequately addressed the defects discovered in the VASASPs. Corrective actions were comprehensive and appeared sufficient to preclude rer-rence of the even E8.6 Enaineerina Backloa Insoection Scope (37550)

The team reviewed the licensee's engineering backlog and the manner in which it was being trended and tracked. In addition, the team discussed the backlog with appropriate licensee personne Observations and Findinas The engineering backlog had a downward trend since January 1997. For design engineering, the total engineering workload decreased from approximately 1900 items in January 1997 to approximate!y 1000 in June 1998. The design engineering backlog consisted of ERs, open modifications, open CR actions, and other miscellaneous item The system engineering backlog also had a slightly downward trend since January 1997, with a reduction from 170 to 149 item The number of open temporary modifications had a downward trend since 1992, at which time there were 73 open temporary modifications. At the time of this inspection, only 11 remained open. The licensee's goal of maintaining the number of temporary alterations less than or equal to 15 had been met since 199 Conclusions The team concluded that the engineering backlog was declining and was being managed effectively by the license E8.7 System Enaineerina l Insoection Scope (37550)

The tearn discussed the status of the system engineering department with applicable department managers. In addition, the team interviewed some of the system engineer I

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The system engineering department consisted of approximately 22 to 24 engineers, with each system engineer responsible for three to five systems. The system engineering manager stated that the number of system engineers had remained steady for the past l few years, in October 1997, the licensee initiated a team concept for the system l engineers where three or four engineers shared a number of primary systems.

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Eventually, each member of the system engineering team would become an erjert on all of the systems within the team's responsibility. The system engineers who were interviewed believed that the team concept was good since it allowed for peer review of each other's work. The team considered the team concept to be a strength, c.' Conclusions

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System engineering appeared to have adequate staffing and was stable. The team concluded that the system engineering team concept was a strength.

l E USAR Review Procram l

i inspection Scope (37550)

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The team reviewed the licensee's program for reviewing the USAR. The review was focused on portions of the effort that affected the SGTS and the HPCS syste Observations and Findings The USAR review effort was described in "USAR Review Procedure," Revision 3, dated

, May 7,1998. Section 1.2 of this procedure stated that the objective of this review was ,

l to improve USAR accuracy through a reasonableness review and to identify the areas of the USAR that require a more detailed evaluation. The review process relied on the personal experience and knowledge of the designated reviewer and on the review of pertinent documents. The designated reviewers were assumed knowledgeable in the aubject matter and could exercise their judgment in using the procedure. A line-by-line compliance to the guideline was therefore not necessary as long as the review objective was met and the review was appropriately documented. The review therefore was not intended to verify and validate full accuracy of the USAR text. However, during the review, areas of the USAR requiring a detailed examination were to be identified for j future actio For the purpose of the review, the USAR was divided into 151 parts. At the time of the inspection,18 of the 151 parts had been reviewed and approved as part of the Phasa 1 i " reasonableness" review. The remaining parts were in various stages of completion.

I Nonc of the USAR sections for the plant systems selected for the team's review had been completed (i.e., SGTS and HPCS). However, portions of these sections were in various states of completion. At the request of the team, the licensee provided the partially completed packages for review.

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To obtain some insight into the nature and quality of the review process, the team selected the package for the mechanical review of USAR Section 6.3," Emergency Core Cooling Systems," for an in-depth evaluation. The licensee reviewer found that the information in the section was appropriate for the subject matter and that the section reasonably reflected the plant design and operating conditions. Some references to other USAR sections, figures, tables, and external documents were found to be incorrect and some editorial errors were identified. There were no obvious technical inaccuracies or areas of technical concern to the reviewer. The team concurred with the reviewer's assessment of this sectio Conclusions The ongoing USAR review effort appeared to be satisfactory; although, the team noted that the review was not a line-by-line verificatio E8.9 Year 2000 Computer issue Inspection Scoce (37550) l l

The team reviewed the licensee's plans for ensuring the continued operability of digital I equipment in the year 200 I Observations and Findinas The team reviewed " Year 2000 Desktop Guide," Revision 0, dated July 28,1998, which established the licensee's plan to ensure that plant systems and components influenced by digital circuitry will continue to operate safely and efficiently following January 1, 2000. The guide also identified additional dates that could result in computer difficultie The licensee employed 11 full-time contractors along with in-house participation to address this issue. All work on critical systems was scheduled to be completed by January 1,1999, with continued work on important systems to be completed in July 1999. At the time of the inspection, this activity was approximately two weeks behind schedule, but, based on the resources available, the licensee did not believe that meeting the deadlines would be a problem or that excessive use of overtime work would be neede The team observed that the licensee's program was comprehensive and that strong management support was eviden c, Conclusions The licensee's program to address the Year 2000 computer problem appeared to be satisfactor ;

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IV. Plant Support F8 Miscellaneous Fire Protection issues (92904)

The team reviewed the following items that were identified during the NRC's Fire Protection Functional Inspection (FPFI) and documented in NRC Inspection Report 50-458/97-201. The team also reviewed the licensee's June 30,1998, response to the FPFI repor F8.1 (Closed) Unresolved item 50-458/97201-01: Smoke detector application, placement, and installation in fire area C-24 does not meet requirements of License Condition 2.C.1 Backaround The FPFI team reviewed the placement of smoke detectors in Fire Area C-24. The FPFI team observed that the smoke detectors were not installed in the pockets between the ceiling beams. The licensee performed Calculation G13.18.12.2-127," Evaluation of Smoke Detector Installation in Fire Area C-24 As Compared to NFPA-72E-1978,"

Revision 0, to address the FPFI concern. The calculation concluded that the fire detectors were installed in accordance with the Code of Record and the licensing basi Inspection Followuo The licensee's evaluation stated that the detectors were installed in accordance with the National Fire Protection Association (NFPA) Code of Record, NFPA-72E-1978, for the plant fire detection system. The team reviewed Calculation G13.18.12.2-127, Revision 0, the Code of Record, and the installed configuration of the detection system in Fire Area C-24. The team verified that the licensee's conclusion was correct and that the system was installed in accordance with requirement F (Closed) Unresolv9.0 item 50-458/97201-02: Failure to include fire protection check valves in a functional testing progra Backaround As described in Section 9.5.1.2.2.0," Seismic Design Requirements," of the USAR, a Seismic Category I water supply is provided from the standby service water (SSW)

system to the seismically designed fire protection standpipe system to provide water for hose stations serving equipment required for safe plant shutdown following a safe shutdown earthquake. A seismically-qualified check valve is located in the normal fire protection water supply piping upstream of each of the three SSW system cross connections. These hose station supply header check valves are designed to prevent diversion of SSW system flow through a break in the nonseismically qualified fire protection water supply piping when the SSW system is being used as the fiie protection

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l l water supply. The NRC identified that the licensee did not have procedures for testing these check valves. The subject valves were: Valve FPW-319," auxiliary and reactor building fire protection header to hose racks inlet check valve"; Valve FPW-V395, " fuel I building fire protection header hose racks header check valve"; and FPW-V820, " control building fire protection header hose racks inlet check valve."

inspection Followup The licensee's FPFI report response stated that the subject valves were tested in accordance with the requirements of the Technical Requirements Manual (TRM) and that the setject valves were verified to open in accordance with the TRM-required Procedure, STP-251-3702, every 3 years. The team reviewed Procedure STP-251-3702, " Fire Hose Station Water Flow Test and Hose Hydro inspection,"

Revision 7. The team noted that this procedure implemented the requirements of surveillance requirement TSR 3.7.9.4.4 by partially opening each hose station valve to verify that the valves were operable and that there was no flow blockage. This test involved cracking open the hose rack angle valve to allow 2 to 3 gallons of water to flo The team concluded that performing this test at each hose station resulted in only a partial stroke of the hose station supply header check valves. There was no test to j verify that the check valves had close The licensee's FPFI report response identified that the subject check valves were reviewed in an engineering analysis, which recommended that they could be screened from additional testing. The team reviewed Engineering Document No.1961C," River Bend Station Check Valve Program Development," Revision 0. The check valve analysis and prioritization that were performed as part of this evaluation concluded that the subject valves were * Priority 5/ low usage," and recommended that the valves be inspected every five plant operating cycles. The licensee used the recommendation of this study, combined with the good historical performance and maintenance history of these and similar valves, to conclude that no additional testing or inspections were necessary. The team did not have a concern with the technical adequacy of this conclusio The team reviewed Procedure STP-251-3502," Fire Protection Water Valve Cycle Test," Revision 9, and verified that the manual isolation valves immediately upstream of the hose station supply header check valves were included in the test. These seismically-qualified, normally open, manual isolation valves were required to be cycled through at least one complete cycle of full travel every 12 month Procedure STP-251-3502 accomplished this requirement. These valves provided additional assurance that if the SSW system was required for fire protection water system supply following a safe shutdown earthquake, a break in the nonseismically qualified portion of the fire protection system could be isolate The team asked the licensee for a copy of the procedure that would be used to place the SSW system in service as a source of fire protection water if necessary following a l

safe shutdown earthquake. The team was informed that there was no procedure for i accomplishing this task and were provided with a copy of CR 98-0214, dated

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February 26,1998, that also identified that there were no procedures to implement this I function. The CR identified a corrective action for Plant Engineering to develop a scope

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l and outline of operating instructions to place the SSW system in service to supply water to the fire protection system in the event of a loss of the fire protection water suppl This corrective action had a due date for completion of August 26,1998. The CR identified another corrective action for Operations to develop a procedure using the outline developed by Plant Engineering. This corrective action had a due date for completion of June 30,199 The team was concerned that this due date may not be appropriate and that operators may not be knowledgeable of the capability or have the necessary training for placing .

the SSW system in service in the event of a loss of fire protection water supply before l the procedure is written. The licensee provided the team with a copy of System Training Manual Lesson Plan RBS-1-STM-GPST-A0118.00," Service Water Systems." This lesson plan identified that operators were taught that the SSW system was capable of providing a backup source of water to the fire protection system by means of opening the manually-operated cross-connect valves. The licr;nsee also provided the team wi'h l a copy of Emergency Operating Procedure EOP-0005," Injection lato RPV with Fire System," Revision 11, which identified procedural steps for using the fire protection water supply system to inject into the reactor via the SSW system cross-connect valve ,

Based on the existence of this procedure and operator training regarding capability of j the SSW system as a backup supply of water for the fire protection system, the team j concluded that there was no safety issue, which would require immediate action to implement the corrective actions identified in the CR. The team did note, however, that J l

the SSW system lesson plan provided operators with incorrect training. The training stated that check valves in the SSW system piping prevented fire protection system water from entering the SSW system. These check valves had been previously removed to allow a means of injecting water into the reactor per EOP-0005. The licensee acknowledged the team's observation and initiated actions to correct the trainin Technical Specification 5.4.1.d required that written procedures shall be established, implemented, and maintained covering fire protection program implementation. The failure to have written procedures for using the SSW system as a source of water to the fire protection system, as described in the fire protection program, was a violation of i Technical Specification 5.4.1.d. This nonrepetitive, licensee-identified failure, which is !

scheduled for correction by the licensee, is being treated as a noncited violation, l consistent with Section Vll.B.1 of the NRC Enforcement Policy (50-458/9816-05).

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F8.3 (Closed) Unresolved item 50-458/97201-03: Lack of engineering evaluations to establish the fire-rating or fire-resistant capabilities of fire-rated boundarie Backaround The FPFI team identified that the licensee did not have acceptance criteria for the clearance around a fire door that was in accordance with the requirements of National Fire Protection Association (NFPA) 80. The team reviewed the licensce's evaluation of fire door clearance acceptance criteri ,

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Inspection Fo.suo The licensee provided copies of a fire door test conducted October 22,1986, by the door manufacturer for the type of doors used at the station. The test demonstrated that the door successfully passed a 3-hour fire endurance test. Therefore, the team concluded that the licensee adequately demonstrated that the installed fire door configuration would pass a 3-hour fire tes F8.4 (Closed) Unresolved Item 50-458/97201-04: Outdated equipment and failure to assign personnel to the fire brigade who have normal plant duties that do not conflict with their response to a plant fir Backaround The FPFI team identnied that the licensee's fire brigade personnel protection equipment was outdated by current technology. The FPFI team also identified that the licensee was not implementing the fire brigade staffing in accordance with a document, which was referenced by the SER. The team reviewed the licensee's response to these two fire brigade issue Insoection Followup ,

The licensee reviewed the FPFI team observation concerning the quality of the personnel protection equipment for the fire brigade. At the time of this inspection, the licensee had on order or had received state-of-the art fire protection equipment for fire brigade member The facility operating license requires that the licensee implement the approved fire protection program as approved in the USAR, the safety evaluation report (SER) dated May 1984, and Supplement 3 to the SER dated August 1985. Section 9.5.1.3 of the SER stated that the licensee committed to implement the NRC supplemental guidance provided in " Nuclear Plant Fire Protection Functional Responsibilities, Administrative Controls and Quality Assurance," dated August 29,1977. This letter stated that the responsibilities of the fire brigade members, under normal plant conditions, should not conflict with their responsibilities during a fire emergency. The licensee determined that the statement in the SER (concerning the subject commitment) was in error because they had never made the referenced commitment in any licensing submittals. The licensee stated that they would send a letter to the NRC to document and correct the error. The team reviewed the licensee's current fire brigade staffing requirements in the approved fire protection program and noted that the licensee complied with the requirements identified in 10 CFR Part 50, Appendix R. The team reviewed licensee fire brigade drill response time records for the 18 months preceding this inspection and noted that the fire brigade responded in a timely manner during these drill The team concluded that the licensee was taking actions to ensure that fire brigade personnel had state-of-the art personnel protection equipment. The team also concluded that the fire brigade members could respond to a fire in a prompt manne _ - - - - . . =

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F8.5 (Closed) Unresolved item 50-458/97201-05: Failure to perform an adequate operability assessment and provide appropriate compensatory measures for conditions affecting the functionality of post-fire safe-shutdown capabilit Backaround The FPFI team identified that the licensee had removed an installed Thermo-Lag fire barrier, rendering the barrier inoperable, while maintaining only an hourly fire watch patrol. The FPFI team was concerned that since the barrier had been completely removed, the compensatory measures that the licensee implemented were less than adequat Inspection Followuo The team observed that the licerdee's fire protection program required that an hourly fire watch patrol be implemented when a missing or degraded fire barrier was identifie The team found that the licensee implemented the requirements of the fire protection program. However, during interviews with licensee personnel, they indicated that they understood the concern expressed by the FPFI team that additional fire protection enhancements may be warranted for planned impairments of significant portions of a fire protection system. The licensee's position was that additional fire protection enhancements could have been considered for this impairment but that the requirements of the fire protection program were not violated in this case. The team agreed with the licensee's conclusion that the use of an hourly fire watch patrol was consistent with regulatory requirements. The team concluded that although the licensee should have considered the implementation of additional fire protection features t".

compensate for the removed Thermo-Lag barrier, no violation occurre F8.6 LClosed) Unresolved item 50-458/97201-06: Failure to perform an adequate post-fire safe-shutdown analysis that meets the licensee commitment to Sections lil.L.1, Ill.L.2, and Ill.L.7 of Appendix R to 10 CFR Part 5 Backaround The FPFI team questioned whether the licensee performed an adequate post-fire safe shutdown analysis. Specifically, a postulated fire in certain areas of the plant could potentially cause all 16 safety relief valves (SRVs) to simultaneously open. The licensee had identified this issue in 1996 but had determined that it was not credible and that further consideration of the issue was not within the scope of its fire protection program requirement Inspection Followun Operating License NPF- 47, Condition 2.C.10, required that the licensee shall comply with the requirements of the fire protection program as specified in Attachment 4 to the license. Attachment 4 required that the licensee implement and maintain in effect all provisions of the approved fire protection program as described in the Final Safety Analysis Report for the facility through Amendment 22 and as approved in the SER, dated May 1984, and SER Supplement 3, dated August 198 . , - -- _ .

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The SER Supplement 3, page 9-13, stated that the fire protection program was in conformance with the guidelines of Branch Technical Position CMEB 9.5-1and 10 CFR Part 50, Appendix R, Section Ill.G. The United States Courts have held that for fire areas where alternative or dedicated shutdown is chosen, then 10 CFR Part 50, Appendix R, Section Ill.L must apply. Therefore, the team concluded that the requirements of 10 CFR Part 50, Appendix R, Section s Ill.G and Ill.L were applicable as referenced to License Condition 2.C.1 Each of the 16 SRVs was provided with a Division I and a Division 11 solenoi Energization of either solenoid caused its associated SRV to open. Four Rosemount pressure transmitters were located in the reactor building and converted a reactor pressure input signal into a de output signal. Two of the transmitters were used for the Division l SRV solenoids and the other two were used for the Division ll SRV solenoid A high pressure condition detected by both pressure transmitters for either division j satisfied the controllooic to energize their associated set of solenoids and open all i 16 SRV l The two twisted pairs of pressure transmitter signal conductors for each division were contained in a common multi-conductor cable from the containment penetration to the l trip unit in the main control room. If one of the wires in a pair were too short to the other l wire of the same pair, a high RCS pressure signal would be received by the SRV pressure logic trip unit. If the other pair in the same cable were to short together, a second high-RCS pressure signal would be received by the SRV pressure logic trip unit, which would satisfy the trip logic to open the SRVs. The fault current caused by these circuits was too low to cause the circuit protective fuses to open. Therefore, fire damage to either of two multi-conductor cables (Division I or Division 11) could cause the trip logic to be satisfied and result in the spurious opening of all 16 SRVs. Opening all SRVs when the reactor is at full power would result in a blowdown to the suppression pool and a rapid reactor pressure vessel depressurizatio in 1996, the licensee identified the potential that fire-induced circuit failures within a single multi-conductor cable could result in spurious high-pressure signals that would cause all of the SRVs to open. In Engineering Report (ER) 96-0672, dated November 18,1996, the licensee stated its position that only one fire-induced spurious operation need be assumed during the fire event requiring alternate shutdown except in the case of hi/lo pressure interfaces. Specifically, the licensee took the position that since it would take two shorts to occur in either single multi-conductor cable of concern, and that these conditions need not be assumed to occur concurrently, the single multi-conductor cable was an acceptable condition. The licensee based its position on its interpretation of the response to Question 5.3.10 in Generic Letter (GL) 86-10. " Implementation of Fire Protection Requirements," April 24,1986. No modifications were performed or planned to correct the conditio Question 5.3.10 of GL 86-10, " Design Basis Piant Transients," states, "What plant transients should be considered in the design of the alternative or dedicated shutdown systems?" The response states,"Per the criteria of Section Ill.L of Appendix R, a loss of offsite power shall be assumed for a fire in any fire area concurrent with the following assumptions: (a) the safe shutdown capability should not be adversely affected by any one spurious actuation or signal resulting from a fire in any plant area; (b) the safe

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shutdown capability should not be adversely affected by a fire in any plant area, which results in the loss of all automatic functions (signals, logic) from the circuits located in the area in conjunction with one worst case spurious actuation or signal resulting from the fire; and (c) the safe shutdown capability should not be adversely affected by a fire in any plant area, which results in spurious actuation of the redundant valves in any one high-low pressure interface lin The team considered that the licensee's conclusions regarding this issue were in erro The licensee's interpretation that only one circuit failure (one twisted pair of wires shorting together) needed to be considered did not meet the NRC's implementation guidance in the GL 86-10 response to Question 5.3.1. This question," Circuit Failure Modes," states, "What circuit failure modes must be considered in identifying circuits associated by spurious actuation?" The response states,"Section s !ll.G.2 end Ill.L.7 of Appendix R define the circuit failure modes as hot shorts, open circuits, and shorts to ground. For consideration of spurious actuations, all possible functional failure states must be evaluated, that is, the component could be energized or de-energized by one or more of the above failure modes. Therefore, valves could fail open or closed; pumps could fail running or not running; electrical distribution breakers could fail open or closed. For three-phase AC circuits, the probability of getting a hot short on all three phases in the proper sequence to cause spurious operation of a motor is considered sufficiently low as to not require evaluation except for any cases involving Hi/Lo pressure interfaces. For ungrounded de circuits, it it can be shown that only two hot shorts of the proper polarity without grounding could cause spurious operation, no further evaluation is necessag except for any cases involving Hi/Lo pressure interfaces." Since the SRVs were not Hi/Lo pressure interfaces and the SRV circuitry did not meet either of the exceptions discussed in the answer to Question 5.3.1, evaluation of the SRV circuitry was require Section Ill.G.2 of Appendix R specified that where cables or equipment including associated nonsafety circuits that could prevent the operation or cause the maloperation due to hot shorts, open circuits, or shorts to ground of redundant trains of systems necessary to achieve and maintain hot shutdown conditions were located within the same fire area outside primary containment, that they be provided with fire protection features necessary to ensure that they remain free of fire damage in accordance with Appendix R, Section s Ill.G.2.a b, or Appendix R, Section Ill.G.3, specified that alternative or dedicated shutdown capability is required where the protection of systems whose function is required for hot shutdown does not satisfy the requirement of Appendix R, Section Ill. For a fire in the main control room, the system credited in the fire hazards analysis for alternative shutdown reactor pressure vessel level control was the steam-driven reactor core isolation cooling (RCIC) system. However, if all of the SRVs were to spuriously open due to shorts of the SRV pressure transmitter conductors, the rapid depressurization would eliminate the steam pressure required to drive the RCIC system i

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turbine. Therefore, because fire-induced short circuits of the SRV pressure transmitter conductors (located in the same fire area) could prevent the operation of the RCIC system, which was required to achieve and maintain hot shutdown conditions, the licensee was not in conformance with Appendix R, Section Ill.G.2. If a licensee does not comply with Appendix R, Section Ill.G.2, then the licensee is required to provide alternative or dedicated shutdown capability per the requirement of Appendix R, Section Ill. The normal emergency core cooling system (ECCS) and reactor feedwater systems were not electrically isolated from the effects of a main control room fire. Therefore, their availability to perform an RCS makeup function cannot be assured (e.g., there is potential for a main control room fire to damage ECCS initiation logic, cause spurious closing of ECCS flowpath valves, or cause spurious ECCS pump shutdowns).

I i' Using the GL 86-10 guidance, should a postulated control room fire occur that required l evacuation, a reactor trip must be initiated as the operators leave to go to the remote .

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shutdown panel. If th,e SRVs were to spuriously open, a rapid RCS depressurization would occur. As a result of this depressurization, the RCIC system would be unavailable. The "A" train of the RHR system was protected from the effects of a fire, but it would be in a suppression pool cooling mode lineup for decay heat removal rather than low pressure coolant injection (LPCI). An operator at the remote shutdown panel

would have to manually realign the system from the suppression pool cooling mode of

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operation to the LPCI mode of operatio CFR Part 50, Appendix R, Section Ill.L, required, in part, that the alternative shutdown capability shall be able to maintain reactor coolant inventory and that it be capable of maintaining the reactor coolant level above the top of the core. The licensee performed an analysis of this event, which concluded that if the operator initiated injection using the RHR system within 10 minutes after event initiation, the ECCS

! acceptance criteria of 10 CFR 50.46 were not exceeded but reactor coolant level would

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not be maintained above the top of the core. Therefore, an alternative or dedicated shutdown capability was not provided in accordance with Appendix R, Section Ill. that met the performance goals of Appendix R, Section Ill.L. This was a violation of License Condition 2.C.1 The NRC had a meeting with the licensee to discuss this issue at on August 19,199 At this meeting, the licensee reaffirmed the position that considering multiple circuit failures was outside the scope of Appendix R and the Generic Letter 86-10 implemenMon guidance. The licensee also presented information at the meeting that concluded that this event was of very low probability and was not risk significant in its response to the FPFI report, dated June 30,1998, the licensee committed to implement a modification to mitigate the effects of any hypothetical SRV cable short j during the April 1999 refueling outage. However, the licensee reiterated its position that i its present configuration was in compliance with the fire protection program licensing l basi i l

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! The NRC had a meeting with the licensee on July 29,1998. At that meeting, the licensee described conceptually a modification that would bypass the short circuit signal l and eliminate the spurious SRV actuation concern. The licensee reiterated its commitment to install the modification during the April 1999 refueling outag The team noted that the licensee had proceduralized operator actions and had conducted operator training to mitigate the post-fire SRV actuation event as described above. Also, the team noted that although a refueling outage had already occurred since the time of the FPFI inspection when a modification could have been performed, '

the licensee had committed to perform a modification within a reasonable time after the i issuance of the FPFI repor )

In accordance with Section Vll.B.6 of the NRC Enforcement Policy, the NRC exercised l its enforcement discretion to not propose a civil penalty and to not issue a violation in I this case. Discretion was warranted because: (1) the apparent widespread i misunderstanding of the requirements, (2) the fact it was licensee identified, (3) the low l risk significance, (4) the fact that the licensee took compensatory actions, and (5) the l licensee commitment to implement a modification during the next refueling outage that ];

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F8.7 (Closed) Unresolved item 50-458/97201-07: Deficiency in the design of the reactor overpressure protection system, under certain postulated conditions, could lead to

inadvertent actuation of 16 SRVs resulting in an un-analyzed plant transien Backarourt_d

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The FPFI team questioned whether the design of the safety relief valve (SRV) actuation I

circuitry complied with the requirements of general design criteria (GDC) 23 of l 10 CFR Part 50, Appendix A. GDC 23 requires, in part, that the protection system be designed to fail in a safe condition if a postulated adverse environment (such as a fire) is experienced. The FPFI team was concerned that the protection system was not designed to fail in a safe condition as exemplified by a postulated fire causing two l conductor-to-conductor shorts in a reactor pressure vessel pressure transmitter cable '

and simultaneous opening of all 16 SRVs. The postulated transient had not been j reviewed in the safety analysis repor ;

Inspection Followup

The team reviewed the design of the SRV overpressure logic, the reactor protection l system, and the engineered safety features to determine whether the SRV overpressure logic circuitry was within the scope of GDC 2 The team reviewed USAR Section 3.1,"Conformance with NRC General Design Criteria," Section 7.2, " Reactor Protection (Trip) System," and Section 7.3, " Engineered Safety Features." USAR Figure 7.2-1, Sheet 3, identified that the four reactor vessel

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pressure transmitters that provided input to the reactor protection system were B21-PTN078A, B21 PTN078B, B21-PTN078C, and B21-PTN078D. The pressure transmitters that provided input to the SRV overpressure logic were B21-PTN068A, B21-PTN0688, B21-PTN068E, and B21-PTN068F. Therefore, the SRV overpressure

. logic circuitry was not part of the reactor protection system addressed by GDC 2 The GDC discussion in USAR Section 3.1 also referenced USAR Section 7.3. The

applicable discussion therein concerned the automatic depressurization system (ADS).

The team reviewed Section 7.3, and noted that although Section 7.3 included a i description of the SRV overpressure logic circuitry in Figure 7.3-2, Sheets 6 and 6A, l which used the affected pressure transmitters, ADS actuation did not require reactor

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pressure as an input. Therefore, the SRV ov9rpressure logic circuitry was not l

necessary for ADS actuation and not part of the protection system addressed by

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GDC 2 Based on the above review, the team concluded that the SRV overpressure logic circuitry was not part of the protection system as identified in GDC 2 F Other FPFI issues The team reviewed the following additional FPFI issues that were identified as " Program Weaknesses" in the FPFI inspection Repor F8.8.1 Fire Suporession System in Fire Area C-4 Insoection Scope The FPFI team observed that the licensee had installed six side wall sprinkler heads to provide automatic suppression in Fire Area C-4. The FPFI report noted that the heads were not installed in accordance with the applicable NFPA Code and that no Code deviation evaluation had been performed. The team reviewed licensee Calculation G13.18.12.2-126," Justification for Deviations From NFPA 13-1983 For Suppression System AS 6C in Fire Area C-4," Revision 0. The team also conducted a visual inspection of Fire Area C- Observations and Findinas The licensee completed Calculation G13.18.12.2-126 after the FPFI and the calculation confirmed that the side wall sprinkler installation deviated from the requirements of NFPA Code 13-1983. However, the calculation concluded that the deviation was not safety significant. The team visually inspected Fire Area C-4 and noted that combustible materialloading in the fire area was extremely low. The team also noted that there were additional upright sprinkler heads instalied, in accordance with NFPA Codes, throughout the fire area. Therefore, the team concluded that the as-built fire suppression system was acceptable.

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With regard to the generic aspects of this issue, the licensee informed the team that it performed walkdowns of each fire area and did not identify any areas where the fire suppression or detection system was inadequate. Additionally, the licensee planned to perform a rigorous fire protection system design basis reconstitution effort, including Code reconciliation. Deviations identified would be appropriately evaluate Operating License NPF-47, Condition 2.C.10, specified that the licensee shall comply with the requirements of the approved fire protection program. The fire protection program stated that the sprinkler systems were designed using the guidance of NFPA 13; however, no deviation from the NFPA Code was described in the progra Generic Letter 86-10 informed licensees' that deviations from the Code should be identified and justified. This failure constituted a violation of minor significance and was not subject to formal enforcement actio Conclusions The team concluded that the licensee's evaluation was adequate to demonstrate that full NFPA Code compliance was not needed for the side wall sprinkler heads in Fire Area C-4 after this deviation was identified by the FPFI team. The failure to have identified and justified this deviation from the NFPA Code was determined to be a violation of minor significanc F8.8.2 Control of Combustible Materials Inspection Scope The FPFI team identified that Procedure FPP-0040, " Control of Transient Combustibles," Revision 7, may not provide adequate control of transient combustible materials in the plant. The team reviewed Procedure FPP-0040, visually inspected housekeeping in various plant areas, and interviewed licensee personnel responsible for the progra Observations and Findinas The team observed that Procedure FPP-0040 did not explicitly contain each statement contained in the NRC guidance concerning control of transient combustible material The team observed that personnel were allowed to leave some small amount of materials at the job site that had work in progress without formal review by the fire protection staff. Tir team observed, however, that there was no excessive amount of transient materials in the plant. The team noted that each small amount of materials left in the plant had a " Work in Progress" sign in the area, which was dated and had a responsible organization listed. The team did not observe any " Work in Progress" signs, which had been left in place for an excessive amount of time. Interviews with responsible plant personnel demonstrated that the staff had a high awareness of the issue and could quickly identify and remove any excessive combustible materials that might accumulate in the plan .. .

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1. Conclusions l The team concluded that the licensee was effectively controlling the use of transient l combustible materials.

V. Manaaement Meetinas XI Exit Meeting Summary l The team presented the preliminary inspection results in a debriefing to members of l licensee management on August 7,1998. The licensee acknowledged the findings presented, but disagreed with two of the proposed violations discussed during the meeting. The licensee did not agree that the issue stated in Section E2.1 of this report constituted a violation of 10 CFR 50.59. In this matter, the licensee stated that they l were implementing the guidance of the Nuclear Energy Institute that was disseminated j l

industry-wide. The team explained that, since the NRC does not fully endorse this guidance, utilities that use it are vulnerable to enforcement action. The licensee also did not agree with a violation of failure to protect against the effects of a control room fire as described in Section F8.6 of this report. In this case, the licensee believed that it was in compliance with the regulations, and that guidance in Generic Letter 86-10 specifically exempted the subject wiring configuration. As stated in the report, this violation was not j issued on the basis of an exercise of enforcement discretio Following additionalin-office review, the team presented the inspection results to members of licensee management via telephone on October 15,1998.

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The licensee was asked whether any materials examined during the inspection should l

be considered proprietary. The licensee stated that some information reviewed by the team was proprietary. This information was returned and was not discussed in the repor i

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i ATTACHMENT SUPPLEMENTAL INFORMATION  ;

PARTIAL LIST OF PERSONS CONTACTED Licensee  ;

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R. Azzerello, Manager, Electrical and instrumentation and Control Engineering .

_V. Bacanskas, Lead Engineer, Fire Protection ,

R. Brian, Manager, Mechanical Design Engineering .

R. Buell, Manager, Project Management 3 P. Campbell, Technical Assistant D. Dormady, Manager, Plant Engineering

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B. Ellis, Fire Protection Engineer J. Fowler, Quality Programs Manager

. T. Hoffman, Supervisor, Engineering R. Kerar, Fire Protection Engineer R. King, Director,' Nuclear Safety and Regulatory Affairs D.' Lorfing, Licensing Supervisor S. Martin, Supervisor, Design Engineering J. McGaha, Executive Vice President D. Mims, General Manager-1 W. O'Malley, Manager, Operations D. Pace, Director, Engineering B. Thumm, Licensing Engineer -

NRC N. Garrett, Resident inspector -

INSPECDON PROCEDURES USED

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92903' Followup-Engineering 93809 Safety System Engineering Inspection 92904 Followup Plant Support 37550 Engineering 4

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37001 10 CFR 50.59 Evaluations

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! REMS OPENED. CLOSED. AND DISCUSSED i

, Opened 50-458/9816-01 IFl Problems with Pressure Relief Valve Set Pressure Program (Section E1.4).

50-458/9816-02 IFl Root Cause of Relief Valve Failure (Section E1.4).

50-458/9816-03 IFl Containment Temperature issues (Section E1.5).

50-458/9816-04 VIO Failure to Consider an increase in Dose Consequences to be an Unreviewed Safety Question (Section E2.1).

j 50-458/9816-05 NCV Lack of Procedure to Use Service Water for Fire Protection (Section F8.2).

Closed

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50-458/97-007 LER Cracked screw assembly swivel pads on emergency diesel generators could have prevented fulfillment of safety function (Section E8 5).

, 50-458/9621-01 IFl Entergy Operations, Inc., resolution of quality assurance ,

program required for resource sharing (Section E8.1). l 50-458/9622-01 IFl Adequacy of molded case circuit breaker trip setpoints (Section E8.2).

l 50-458/9627-02 IFl NRR to review near-buoyant objects (Section E8.3). j

50-458/97201-01 URI Smoke detector application, placement, and installation in fire area C-24 (Section F8.1).

! 50-458/97201-02 URI Failure to include fire protection check valves in a functional test program (Section F8.2).

50-458/97201-03 URI Lack of engineering evaluation to establish fire rating / fire resistance capabilities of fire-rated boundaries (Section F8.3).

50-458/97201-04 URI Failure to assign other people to fire brigade (Section F8.4).

50-458/97201-05 URI Failure to perform adequate operability assessment (Section F8.5).

50-458/97201-06 URI Failure to perform adequate post fire safe shutdown analysis (Section F8.6).

50-458/97201-07 URI Deficiency in design of reactor overpressure protection system (Section F8.7).

50-458/9816-05 NCV Lack of procedure to use service water for fire protection (Section F8.2).

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LIST OF ACRONYMS USED )

ADS' automatic depressurization system cfm cubic feet per minute CR condition report CST condensate storage tank DBA design basis accident ECCS emergency core cooling system EDG emergency diesel generator i EPRI Electric Power Research Institute ER engineering request FPFI fire protection fu'nctionalinspection )

GDC general design criterion GL generic letter j HEPA high-efficiency particulate air HPCS high pressure core spray 4 IN NRC Information Notice  ;

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LCN license change notice  ;

l LER licensee event report LOCA loss-of-coolant accident [

LPCI low pressure coolant injection LPCS low pressure core spray NEl Nuclear Energy Institute NFPA National Fire Protection Association NPSH net positive suction head NRC Nuclear Regulatory Commission PPP positive pressure period RBS River Bend Station

- RCIC reactor core isolation cooling

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l i ~RHR residual heat removal t

L SEN- safety evaluation (10 CFR 50.59)

SER safety evaluation report .

SGT standby gas treatment system SSW standby service water l

STP surveillance test procedure T temporary test procedure

.TRM - Technical Requirements Manual  ;

TS-- . Tec'inical Specifications

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USAR Updated Safety Analysis Report US unreviewed safety question VASASP valve adjusting screw assembly swivel pad wg water glass

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l LIST OF DOCUMENTS REVIEWED l

l Procedures I l

I NUMBER DESCRIPTION REVISION i

ENG-3-037 Engineering Request Revision 2 Process l

l RBNP-030 Initiation and Processing of Revision 12 l l Condition Reports  !

! J EDP-AA-20 Engineering Calculations Revision 12 RBNP-088 USAR Maintenance Revision 0 '

l No Number USAR Review Revision 3 l

l STP 203-6305 HPCS Quarterly Pump and Revision 7

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l Valve Operability Test STP-203-6805 HPCS Cold Shutdown Valve Revision 4 Operability Test l

STP-302-1601 ENS-SWG1 A/B Loss of Revision 0 Voltage Channel Calibration and Logic System Functional Test PL-126 Site Providing Services to Revision 0 Other Sites RBNP-093 Control of Shared Services Revision 0 ENG 3-006 Modification Design Revision 16 Guidance I

, ENG 3-033 Modification Design Control Revision 4

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Plan ADM-0031 Temporary Alterations Revision 8A RBNP-030 Initiation and Processing of Revision 12 Condition Reports

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RBNP-057 10 CFR 50.59 License Basis Revision 7

! Reviews and Envirc.unental l Evaluations i

l STP-000-6606 Section XI Safety and Relief Revision 6 Valve Testing

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STP-251-3702 Fire Hose Station Water Revision 7 l Flow Test and Hose Hydro inspection STP-251-3502 Fire Protection Water Valve Revision 9 Cycle Test EOP-0005, Enclosure 7 Injection into RPV with Fire Revision 11 System SOP-0042 Standby Service Water Revision 16B System Operating Procedure SOP-0037 Fire Protection Water Revision 16 System Operating Procedure Enaineerina Reauests and Temporary Alterations NUMBER- DESCRIPTION REVISION /DATE ER 97-0147 ECCS Suction Strainer -

Modification ER 97-0277 Correct ESK-6GTS02 6/3/97 ER 97 0324 HPCS Design Basis 6/5/97 Information ER 98-0166 SGTS Modification 4/19/98 ER 98-0230 SGTS Modification -

ER 98-0233 SGTS Evaluation 6/17/98 ER 96-0017 Status of Normal / Preferred 1/16/96 Transfer ER 96-0602 CSH PS235 & 249 Setpoint 8/22/96 Change ER 97-0293 Modify Control Circuit of 6/10/97 E22*S004-ACB01 ER 98-0430 SRV Control Circuit 7/28/98 Modification ER 96-0072 Spurious High RPV Signal 11/18/96 Initiation of SRVs TA 96-13 Install enhanced option 1 A 10/10/97 flow control trip reference card in APRM B

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TA 96-025 Disable SLC suction piping 9/01/96 heat trace and alarm Condition Reports (CRs)

l L NUMBER DESCRIPTION REVISION /DATE

!- CR 96-1137 CST Level for Vortex - -

L Prevention Allowance

} CR 96-1511 ~ SGTS Fan GTS*FN1 A 6/7/96 Rotating Backwards l CR 97-0526A(CR-97-2154) SGTS Surveillance Test - -

l Validity l o  !

l CR 97-0800 ' SGTS USAR Changes - l CR 97-0808 Low Vacuum in Annulus -

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( -.CR 98-0430 SGTS High Air Flow .

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.. CR 98-0437 SGTS High Air Flow 4/17/98 CR 98-0795 Div i and ll D/G Control Air -

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I CR 98-0913 USAR Review Updates for -

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CR 98-0924 High Vacuum Reading in 7/21/98 Auxiliary Building

- CR 98-1001 USAR Table 6.3-1 Error -

CR 97-1494 STP-302-1602 Timer 62-6 9/17/97 j CR 97- 0122 Circulating Water Pump 2/4/97 l

Motor Heater Removal CR 97-1322 ENS SWG 18 ACB 29 Gnd 9/4/97 J Overcurrent Relay

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CR 94-1032 .52S contacts on 4.16 kV 8/18/94 1

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Switchgear

. CR 97-0793 Spring Charging Motor 5/28/97 Control Cicuit CR 96-151 E22*S001 Battery Service 8/19/96 Test

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a CR 96-0562 HPCS Pump Motor Breaker 6/27/95 i

CR 97-1067 HPCS Breaker trip when 7/22/97 started

l CR 97-0795 incorrect Calcula:!on used 5/26/97 SPDS EGF ESX15 l~ CR 97-1079 . Allowable Values in TR 7/24/97

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3.8.4.7~

!~ :CR 97-0942 E22-LTN 054 C&G incorrect 5/17/96

!- head correction

! CR 96-1380 HPCS Diesel Alarm 7/21/96

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l CR 96-1459 HPCS 125V dc Distribution 8/7/96 System

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CR 96-1516 Div 3 Volt Profile inrush I not 8/19/96

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included CR 97-2010 E22 MOV FO12 failed to 11/11/97 open ,

J CR 96-1283 GTS-FNI A appeared to have 7/28/96

secured on its own i

- CR 98-0632 GTS-FLT1 A heater failed to 5/21/98 energize as required by i procedures L

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CR 97-1157 Grease sjung from motor 8/6/97 bearings on both standby gas treatment fan motors 97-1988 Auxiliary building supply fan 11/6/97 l did not trip on low flow as expected CR 98-0230 High negative prassure in the 3/3/98 auxiiiary building and annulus with standby gas treatment - ,

, running 1 l

CR 98-0296 Difficulty opening aux building 3/19/98

, doors with standby gas running

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O CR 98-0415 Questions asked about the 4/15/98 impact of auxiliary building access with both trains of standby gas running -

CR 98-0430 Lineup of standby gas to limit 4/6/98 the off site dose limits CR 96-1320 STP does not test the 7/16/96 pressure drop across the profilters as required by TS CR 98-0591 Incorrect acceptance criteria 5/17/98 was adopted for the high pressure core spray pump room cooler CR 97-1690 10CFR21 notification for 9/30/97 defects and noncompliance concerns for the EMD air start motors i

CR 98-0708 The current plant 6/8/98 l configuration does not -

correspond to that described in the SAR with respect to the reserve volume of water in the CST CR 96-1593 Discrepancy in the minimum 10/3/96 temperature in the HPCS diesel generator room CR 97-1420 Piece of plastic gasket found 9/15/97 in service water side of heat exchanger CR 95-0581 Failure to grease the core 7/13/95 spray DSL turbo lube oil pump during performance of PM CR 96-1581 Discrepancy between FSAR 9/12/96 and calculated maximum temperature for HPCS pump room CR 96-1313 Battery performance 7/15/96 L-

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discharge test was terminated prior to meeting the procedure conditions

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CR 98-0109 Heater cable was spared 2/1/98 without a 50.59 evaluation CR 96-1137 Condensate storage tank 6/20/96 technical specification minimum level requirement may not ensure that 1254k gallons of makeup water is available CR 95-0717 Discrepancies between 7/17/95 USAR figures and other drawings CR 98-0846 Two pieces of grey colored 8/23/95

/ cement were discovered on top of the breaker when it was removed from the cubicle CR 97-0606 While running HPCS purnp it 4/30/97 was observed that the minimum flow valve functioned sluggishly CR 97-2010A HPCS minimum flow valve 1/22/98 demonstrated erratic operation CR 97-2100 HPCS minimum flow valve 11/11/97 failed to auto open CR 97-0804 HPCS discharge relief valve 5/29/97 found with ruptured bellows CR 98-0991 Actual containment 8/5/98 temperature was lower than the minimum containment temperature specified in the Environmental Design Criteria CR 96-1585 Standby gas system initiated 8/31/96 due to spike to radiation monitor

.CR 97-0792 Radiation monitor went into 5/28/97 alarm and started standby 1 gas fan

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CR 961584 Radiation monitor spiked and 8/31/96 ,

started standby gas fan j

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I l CR 98-0216 Annulus high pressure alarms 2/27/98

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were received CR 97-1881 The relief valves for the diesel 10/20/97 ;

l starting air system were reset to a higher set pressure CR 97-2131 The relief valves for the diesel 12/18/97 l starting air system were set back to the original set  ;

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pressure l

l CR 961379 Relief valve for the 10/30/96 l condensate pump motor air l .l l cooler is set higher than j i

required CR 96-1994 Relief valve on the 11/21/96 ,

i condensate emergency i makeup hotwelllevel control l

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valve bypass line is set higher than required CR 96-1571 Setpoints for the main steam 8/29/96 moisture separator reheater pressure relief valves are not l In accordance with those i required by plant design documentation

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CR 97-2008 Relief valve was replaced 11/11/97 tiecause the valve set pressure was 30 psi too high CR 96-1082 46 discrepancies were 6/13/96 discovered between the setpoints required by the plant safety and relief valve data sheets and the setpoints etched on the valve data i

plates CR 92-0603 There is a question as to 8/21/02 what the actual pressure setting is for the HPCS air start system air dryer discharge lines l'

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I CR 98-0998 - Open cable tray floor 8/6/98 i

penetrations without  !

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guardrails in cable chase

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room on 116' elevation CR 98-0803 Fire detection, suppression, 6/25/98 and barrier issues l i

CR 97-0991 Po?'v demultiple shorts in 7/2/97 "

reactor > .ssure vessel l pressure transmitters causing j all 16 SRVs to open -

l CR 98-0214 No procedure to provide SSW 2/26/98 to fire protection hose  ;

stations  !

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l Calculations

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NUMBER DESCRIPTION REVISION l

BV45,191 Fan External Total Pressure Revision 1 l i

Fans 1HVR-FN7A & FN78 l Auxiliary Building Exhaust System Normal Operation 1 Modes I,11, & Ill BV45.20-1 Fan External Total Pressure Revision 1 1GTS*FN1 A & FN1B Containment /Drywell Purge Exhaust, Normal Operation Mode 111 BV45.22-1 Fan External Total Pressure Revision 1 Fans 1GTS*FN1 A& FN1B Annulus and Auxiliary Building Exhaust, Accident Mode ES-151 Net Free Air Volume of the Revision 0 Auxi!!ary Bldg ES-193-4 Shield Bldg Annuius Revision 4 Following a LOCA l

ES-193-5 Shield Bldg Annulus Revision 5 ;

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Following a LOCA i i ES-194-3 Auxiliary Building Pressure Revision 3 i Following LOCA l I

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G13.18.14.1 *027-0 . Evaluation of Post-LOCA Revision 0 Auxiliary Building Positive

>. . Pressure Period in Support l of CR-98-0437

G13.18.2.1*079 00 Evaluation of SGTS - Revision 0 I Drawdown Data G13.18.2.2'031-0 NPSH Available for ECCS Revision 0 Pumps for Suction from the Suppression Pool Under

' Accident Conditions-G13.18.2.7*23 Shield Building Annulus Revision 1 Folicwing a LOCA (Note:

This calculation supersedes ES-193-5)

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PB-251 _ To Determine the in-Leakage Revision 0 and Amount of Exhaust Air Required to Maintain a Negative Pressure of 0.25 in wg in Auxiliary Building E129 Load Study 13.8 & 4.16 kV Revision 4c System s

E130 Sizing Ground Resistors Revision 3 4.16 kV System E131 Station Service Short Circuit Revision 1 & 8 addendum Analysis E132 Voltage Profile Revision 3 & 9 addendum 1 l

E167 5 kV Cable Sizing Revision 2 addendum B EOS-64 5 kV Cable Lie Extension 4/8/85 lA-GTS*1 Setpoint Calculation Revision 4 i 1GTS*FS 24A & B IA-E22*04 Setpoint Calculation HPCS Revision 2 addendum 4 !

Condensate Storage Tank i Low Level j

l lA-E22*05 Setpoint Calculation Revision 4 !

1E22*ESN 655C & G lA DFR#2 Setpoint Calculation HPCS Revision 5 Floor Water Level l

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O G13.18.12.0*03 Common Cause Failure 4 kV 6/28/90 Circuit Breakers G13.18.3.1 *01 Sustained & Degraded Revision 1 Voltage Setpoints Div 1&2 G13.18.12.2-126 Jastification for Deviations Revision 0 From NFPA 13-1983 For Suppression System AS-6C in Fire Area C-4 G13.18.3.1 *02 Sustained & Degraded Revision 2 Voltage Setpoints Div 3 Drawinas NUMBER DESCRIPTION REVISION PID-27-15A Engineering P&l Diagram Revision 1 System 257 5sandby Gas Treatment PID-27-04A Engineering P&l Diagram Revision 2 System 203 HPCS System PID-9-10E Engineering P&l Diagram Revision 18 System 256 Service Water-Standby PID-15-1C Engineering P&l Diagram Revision 9 System 251 Fire Protection Water & Engine Pump EB-45C-11 Ventilation and Cooling Plan Revision 11 EL 95'-9" Auxiliary Bldg EE1A Main One Line Diagram Key Revision 19 Drawing EE1K 4.16 kV One Line Diagram Revision 17 1 ENS *SWG 1 A EE1L 4.16 kV One Line Diagram Revision 14 :

1 ENS *SWG 1B I EE1M 4.16 kV One Line Diagram Revision 7 E22*S004 i

1EJS* LOC 1 A&2A 480 V One Line Diagram Revision 10 Standby Bus i

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' Standby Bus

Miscellaneous Documents l

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NUMBER DESCRIPTION REVISION

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River Bend Station Updated Revision 10 l Safety Analysis Report

, Operating License NPF-47 River Bend Station Operating Revision 101 and Appendix A License and Technical Specifications l

l SDC-203 HPCS System Design Revision 0 l Critena j l

SDC-302 ENS Safety Related 4.16 kV Revision 0 :

Electrical Distribution System Design Criteria

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l SURD-P50 SGTS Evstem Description Revision 0 and ReqJirements Document Test Report HPCS 15 Stage Pump 6/29/77 T-36631-1 Performance Curve (Byron Jackson)

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Year 2000 Desktop Guide Revision 0

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Entergy Operations, Inc., 7/29/98 !

Fire Protection PEER Group l Position Paper Regarding -

Fire Brigades and OSHA 29 CFR 1910.134 1961C River Bend Station Check Revision 0 Valve Program Develooment STM-GPST-A0118.00 Service Water Systems -

Training Manual i

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i Safety Evaluations Document Evaluated Safety Evaluation (SEN)

, LCN 04.06-032 97-0063 l LCN 06.03-029 97-0071

! LCN 07.03-151 96-0086 l _ LCN 08.03.062 96-0026

LCN 08.03-069 97-0023

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MR 95-0010 & LCN 09.03-219 REVS 96-0098 MR 96-0068 & FCN 1, LCN 09.03-231 97-0073

CR 95-0839 & LCN 09.05-108 96-0052 MR 96-0048 & LCN 10.04-160 97-0016 LAR 97-27 97-0072 LAR 97-03 97-0005 LAR 97-03 REV 1 97-0009 ER 97-0155 97-0038 l

ER 97-0294 97-0081 ER 97-0607 97-0087 CR 96-1644 97-0008 ,

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! SOP-0018 97-0007 TP-97-0004 97-0084 Safety Evaluations i

! SEN Document Title l l I

98-0027 ER 98-0380 Repair / Replacement of HVC System Damper Blade Seals I 98-0028 ER 98-0321 Uprate Motor Data to Reflect Actual LRA Test Data 98-0029 ER 98-0136 Evaluation of Alternate HVK Chiller 1C Motor 98-0030 ER 98-0068 Replace Trend Recorders with Digital Recorders 08-0031 ER 98-0397 Repair /Rertacement of HVC System Damper Blade Seals l 98-0032 ER 97-0040 BWR Stab' ity Enhanced Option 1 A 98-0033 LCN 15.06-006 Revise LOCA Calculations 1 l

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