ML20210R015

Design Insp Rept 50-271/97-201 on 970505-0613.No Violations Noted.Major Areas Inspected:Lpci & RHRSW Sys

ML20210R015
Person / Time
Site:	Vermont Yankee
Issue date:	08/27/1997
From:	NRC (Affiliation Not Assigned)
To:
Shared Package
ML20210Q998	List: ML20210Q991 ML20210R015
References
50-271-97-201, NUDOCS 9709020247
Download: ML20210R015 (37)

See also: IR 05000271/1997201

Text

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OFFICE OF NUCLEAR REACTOR REGULATION

Docket No.: 50 271

License No.: DPR-28

Report No.: 50-271/97-201

Licensee: Vermont Yankee Nuclear Power Corporation

Facility: Vermont Yankee Nuclear Power Station (VY)

Location: RD 5, Box 169

Brattleboro, VT 05301

Dates: May 5 through June 13,1997

Inspectors: James Isom, Team Leader, Special Inspection Branch

Robert Hogenmiller,I&C Engineer *

Robert Najuch, Lead Engineer *

Dennis Vandeputte, Mechanical Engineer *

Arvind Varma, Electrical Engineer *

Maty Yeminy, Mechanical Engineer *

• Contractors from Stone & Webster Engineering Corporation

Approved by: Donald P. Norkin, Section Chief

SpecialInspection Branch

Division ofInspection and Support Programs

Office of Nuclear Reactor Regulation

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Table ofContents

EXECUTIVE S UMMARY . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ' l

El .0 - Inspection Scope and Methodology . . . . . . . . . . . . . , . . , , . . . . . . . . . . . . . . . . . 1

El.1 Low-Pressure Coolant Injection . . . . . . . . . . . . . . . . . . . . . . . . . , . . . . . . . . , . . . 1

El.l.1 System Description and Safety Function . . . . . . . . . . . . . . . . . . . . . . . . . . 1

E 1.1.2 Mechanical . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2

El.2 Residual Heat Removal Service Water . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . , , . . I1

El.2,1 System Description and Safety Function . . . , . . . . . . . . . . . . . . . . . . . . . . I1 l

E l .2.2 Mechanical . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 11 j

El.3 Electrical / Instrumentation and Controls . . . , . . . . . . . . . . . . . . . . . . . . . . . . . , , . . 18 I

l El.3.1 System Description and Safety Function . . . . . . . . . . . . . . . . . . . . . . . . . . 18 1

E l .3.2 Electrical . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 18

El.3.3 Instrumentation and Controls . . . . . . . . . . . .................. 21

E l .4 FS AR Review , . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 23

E l .4.1 Scope of Review . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2 3

E l .4.2 Findings . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 24

E l .4.3 Conclu sions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 24

E l .5 Design Control . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 24

E l .$.1 Scope of Review . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 24

E l . 5.2 Findings . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2 5

E l . 5.3 Conclusions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 26

APPENDIX A LIST OF OPEN ITEMS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . A 1

APPENDIX B EXIT MEETING ATTENDEES . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . B 1

APPENDIX C LIST OF ACRONYMS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . C- 1

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. EXECUTIVE SUMMARY

From May 5 through June 13l1997, the staff of the U.S. Nuclear Regulatory Commission (NRC),

Office ofNuclear Reactor Regulation (NRR), Special Inspection Branch, conducted a design

inspection at Vermont Yankee Nuclear Power Station (VY) The inspection team consisted of a team

leader from NRR ~and five contractor engineers from Stone & Webster Engineering Corporation

(SWEC).

The purpose of the inspection was to evaluate the capability of selected systems to perform the safety

- functions required by their design bases, as well as adherence of the systems to their respective design i

. and licensing bases, and the consistency of the as-built configuration and system operations with the

final safety analysis report (FSAR). As the focus of this inspection, the team selected the low

pressure coolant injection (LPCI) mode of the residual heat removal (RHR) system and residual heat

removal service water (RHRSW) system, on the basis of their importance in mitigating design-basis

- accidents (DBAs) at VY.

For guidance in performing the inspection, the team followed the engineering design and

configuration control portion efInspection Procedure (IP) 93801, " Safety System Functional

Inspection (SSFI)." The team also reviewed portions of the plant's FSAR, design-basis documents, -

drawings, calculations, modification packages, surveillance procedures, and other documents

pertaining to the selected systems.

In preparation for the inspection and in performing previously scheduled engineering reviews, the

licensee identified various issues affecting the of stems under review. The team identified the

following 6dditional issues, some of which raised questions concerning the capability of the selected

systems to perform their DBA functions. Where appropriate, the licensee took corrective or

compensatory actions to ensure system operability. .

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In 1982, the licensee requested a license amendment to modify the plant's technical

specifications (TS) by increasing the normal suppression pool (torus) water temperature limit

from 90 to 100*F. However, the licensee failed to adequately evaluate the impact of a higher

pool temperature following a loss-of-coolant accident (LOCA). Affected analyses included the

net positive suction head (NPSH) for pumps, LOCA containment analyses, piping stress and

support loads, and equipment qualification. Plant operation with a pool tempe:eture exceeding

90*F for greater than 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> had_ occurred between the time the amendment was granted

(1985) and the time the licensee discovered the deficiency (1994). Administrative controls

currently preclude plant operation with torus water temperature exceeding 90*F The team

concluded that the plant had operated outside ofits design bases during the periods when the

torus temperature exceeded 90 F.

• Post-LOCA effects of a change in the initial torus water temperature limit from 90 to 100'F

were further complicated by other factors. The licensee reduced the design heat removal

capacity of the RHR heat exchanger on the basis of findings identified during the licensee's

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internal service water system operational performance inspection (SWOPI) conducted in 1994.

The containment analyses performed by General Electric Company (GE) assumed that -;

feedwater flow ceased at time zero; however, in 1996, the licensee determined that the inclusion

of feedwater mass and energy would lead to an increase of about 10*F in the peak calculated

post LOCA torus water temperature. The licensee has evaluated the separate effects from each

of these changes, and maintained safe operation through administrative controls on torus

L ~ temperature; however, the licensee has not completed its analysis of the integrated effects of

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these changes.

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The available RHR pump minimum flow (350 gpm) was considerably less than the (2700 gpm)

pump vendor recommended minimum flow required for satisfactory pump operation.

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Funhermore, the licensee lacked the technical basis for operating the RHR pump with the

existing minimum flow rate and had not adequately addressed concerns regarding the safety- ,

related pump minimum flow issue identified in Inspection and Enforcemerit (IE) Bulletin 88-04.

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As a result of this inspection, the licensee obtained additional vendor guidance regarding RHR

pump minimum flow operation and instituted interim corrective actions to have the operators

secure the pump when it operated below the required minimu n flow for more than 30 seconds.

• On the basis of the team's concerns regarding heat exchanger test results and instrument

inaccuracies, the licensee placed an administrative limit to restrict plant operation to river water

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temperature below 80'F,

Ponions of the service water system piping and emergency diesel generator auxiliary systems

were installed without protection against extemal missiles. Moreover, the licensee was using a

probabilistic risk assessment (PRA) approach as a design basis for lack of protection from

tornado-generated missiles, which did not appear consistent with the original licensing

documentation.

The team identified the following issues which indicated potential programmatic deficiencies:

The licensee addressed inconsistencies with the FS AR or TS limits by imposing conservative

administrative limits on plant operation, However, the team identified several examples which

indicated that the licensee's correction of the licensing documentation was not timely.

Examples included the torus pool temperature, RHR heat exchanger capacity, feedwater

addition to the containment analysis, and permissiole service water out-of-service limitations. In

some cases, the licensee incorporated its resolution of an issue into larger programs, such as

Improved Technical Specifications; however, this approach appeared to unduly protract the

final resolut ion of these issues.

When equipment was rendered inoperable for surveillance as required by the plant's TS, the

licensee's practice concerning entry into the limiting condition for operation (LCO) was not

consistent with the guidance provide in Generic Letter (GL) 91-18. Moreover, no

documentation existed with regard to NRC approval of the licensee's position.

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The team identified deviations from GL 89-13 licensing commitments regarding the inclusion of

all emergency core cooling system (ECCS) corner room coolers, and determination of the

. testing frequency necessary to ensure that the design heat removal capability of the RHR heat

exchangers would be maintained._

The team identified weaknesses in the development and control of calculations, and the review.

and approval processes. The licensee did not sdequately maintain electrical design calculations .

in accordance with Engineering Instruction WE 103, " Engineering Calculations and Analyses."

The licensee did not adequately consider the effects of the motor overcurrent relay in its analysis ,

l- of the Vernon 69 KV switchyard low voltage and RHR pump starts. The team noted a lack of

documentation and traceability to previous analyses for exceptions to the electrical separation i

criteria. Although the licensee was developing an instrument Apoint program, the

methodology only recently addressed instrument drift in the analysis.

There was a weakness concerning the licensee's translation of design criteria and design bases

into detailed operating instmetions. As a result, operating procedures were inconsistent with .

design requirements regaroing RHR pump minimum flow requirements, permissible RHR pump

motor starts, and service water pump operation upon loss of ventilation.

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El.0 Insnection Scone and Methodolony

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The primary objectives of the design inspection at the Vermont Yankee Nuclear Power Station (VY),

were to evaluate the capability of the systems to perform their safety functions as required by design

bases and to verify whether the lica.nsee, Vermont Yankee Nuclear Power Corporation (VYNPC),

has maintained the plant in compliance with its design and licensing bases The team selected for

inspection the Iew Pressure Coolant Irjection (LPCI) mode of the Resideal Heat Removal (RHR)-

System and the Residual Heat Removal Service Water (RHRSW) system because of their importance

in mitigating design-basis accidents (DBAs) at VY. For guidance in perform *ng the inspection, the

team followed the applicable engineering design and confi F uration control portions ofInspection

Procedure (IP) 93801, Safety System Functional Inspection (SSFI).

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l Appendix A identifies the unresolved items (URIs) and inspection followup items (IFIs) resulting

[ from this inspection. Appendix B lists the individuals who attended the exit meetings on June 13 and

l July 1,1997. ' Appendix C defines the various acronyms used in this report.  !

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El.1 Low-Pressuie Coolant Inlection

El.1,1 System Descrintion and Safety Function

The RHR system was designed as a multi-function system having both normal and accident mitigation

functions. The safety function of the LPCI operating mode of the RHR system is to restore and

maintain coolant inventory in the reactor vessel aAer a loss-of-coolant accident (LOCA), such that

adequate core cooling is maintained. LPCI operates in conjunction with the other core standby  ;

cooling systems (CSCS); including tha high pressure molant injection (HPCI), automatic - '

depressurization system (ADS), and core spray (CS) system . Together, these systems provide

adequate core cooling over the complete spectrum of possible break sizes in the reactor coolant

. system, up to and including a double-er.ied break of the recirculation pump suction line.

The RHR system consists of two identical closed loops. Each loop contains two parallel pumps; one

heat exchanger; and the necessary piping, valves, and instrumentation. The RHR heat exchanger in .

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u.ch loop is cooled by the RHRFW system. In the LPCI operating mode, each RHR loop draws

suction from the suppression peol and injects into the core region of the reactor vessel through a

reactor recirculation loop. The RHR heat exchanger! are initially bypassed (when core cooling is of

primary concern), but can be used after a time delay to cool the injection flow. A minimum flow line

discharges to the torus s ppression pool to provide pump protection when pumping against a closed

- discharge line. A LOCA r.ignal automatically starts all four RHR pumps and positions valves to direct

the coolant injection flow to the reactor vessel. When reactor pressure decreases to a set value, the

LPCl injection valves automatically open and, as LPCI discharge pressure exceeds reactor pressure,

LPCI flow enters the reactor vessel through the intact recirculation loop (s).

The LDCI system was designed to perform its safety-related function following a LOCA assuming a

loss of normal power and a single active failure. In addition, the LPCI equipment, piping, and

supports were designed in accordance with Class I seismic criteria.

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El.l.2 Mechanical

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El.l.2.1 Scope of Review

The mechanical design review of the LPCI system included system walkdowns and discussions with

cognizant system and ded;n eng:noers as well as reviews of the plant's design and licensing

documentation.- The team reviewe d applicable portions of the plant's fmal safety analyds report

(FSAR); technical specifications (TS); as well as the relevant design basis documents (DBDs), flow

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and process diagrams; other system drawings; calculations;' design change requests (PDCR and EDC-

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R); system operating, inervice and surveillance test procedures and results; event reports (ER); and

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operstmg expenence reviews (OER).

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The team verified the appropriateness and correctnen of the licensee's design assumptions, boundary --

conditions, and system models. The team also assessed whether the design bases were consistent

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with the licensing bases and verified the adequacy of the licensee's testing requirements. In addition,

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the team reviewed systems interfacing with the LPCI system to verify that the interfaces were

i consistent with the LPCI system design and licensing bases and would not have an adverse effect on

l the LPCI function. The mechanical design review included system thermal / hydraulic performance

. requirements (such as system capacity, pump net positive suction head, and pump minimum flow) as

]- -well as system design pressure and temperature, overpressure protection, component safety and

seismic classifications, component and piping design codes and standards, and single failure

vulnerability.

El.l.2.2 EndinEl

a. Sunnression Pool Temnerature Desian Basis

. - In 1982, the licensee requested a' license amendment to modify the plant's TS by increasing ti,c .

j- normal suppression pool (torus) water temperature limit from 90 to 100'F (Amendment No. 88

, received in 1985). This increase in the initial pool water temperature resulted in a peak post-LOCA

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pool temperature (approximately 1767) that was about 10*F higher than the maximum value of

[ 166T presented in FSAR Section 14.6.3,- Although the resulting peak post-LOCA pool temperature

(176*F) was highe than the pool temperature stated in the FSAR (166'F), the licensee's analysis

bounded this temptrature increase in that their analysis assumed a peak post-LOCA pool temperature

j- of 176*F. Therefore, the increase in the peak post LOCA pool temperature resulting from raising the

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initial pool temperature to 100*F had already been analyzed. The basis for the change solely

addressed hydrodynamic load considerations, and did not consider the impact of this amendment on

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other analyses such as the core standby cooling system (CSCS) pump net positive suction head

{ (NPSH), LOCA containment analyses, CSCS piping stress and support loads, and equipment-

[ qualification.

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Unrelated to amendment No. 88, the licensee determined that the use of more conservative

assumptions with respect to addition offeedwater mass and energy and consideration ofintermediate

and small break LOCA scenarios - such as the analytical models promulgated by General Electric

- Company (GE) (as described in NUREG-0783)- would also result in higher post LOCA pool

temperatures. The licensee documented this condition in Potential Adverse Condition (PAC) 96-0"t,

dated March 25,1996 and determined that in the worst case, the peak post-LOCA pool temperature

would not exceed 176'F given an initial pool ter,perature of 90'F,

The licensee prepared a Basis for Maintaining Operation (BMO) 96-05, dated April 8,1996 and

performed a 10 CFR 50.59 Safety Evaluation as documented in SE 96 008, dated April 8,1996, to

assess the acceptability of an increase in the maximum post-accident pool temperature from 166'F

(the value shown in the FSAR) to 176*F. The licensee concluded that the plant could continue to

safely operate and that an u:u eviewed safety question did not exist, as long as the initial pool water -

temperature did not exceed 90'F.

Before completing the BMO, the licensee established administrative controls to limit the suppression

pool temperature to 90'F through a standing order (SO #19) on December 1,1995. This standing

order limit was subsequently revised to limit the pool temperature to 87'F on May 19,1997 to

account for inaccuracy in the instrumentation used to measure pool water temperature. The licensee

was still performing the final detailed containment analyses at the end of this inspection.

The inspection team had the following concerns related to this suppression pool temperature issue:

(1) Plant Oneration Outside the Design Basis-

The licensee had not evaluated the effects ofincreased pool temperature from both the increase

in the initial pool temperature and from the effects of feedwater energy addition to the

operability of the LPCI and core spray pumps. Since license amendment No. 88 was granted on

June 6,1985, the plant has operated with suppression pool water temperature of up to 100'F,

even though the safety analyses presented in the FSAR were based on 90'F.- A review of plant

operating records from 1985 to 1995 identified three separate instances (two 2-day periods in

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August 1988 and an 8-day period in Auli,ust 1993) when the measered pool water temperature

exceeded 90'F for greater than 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />. The plant was outside ofits design and licensing

bases during those periods. The licensee initiated ER No. 97-%35 to evaluate this concern.

This item is designated as URI 50-271/97-201-01.

(2) Timeliness of Corrective and Compensatory Actions:

The following licensee actions did not appear to be timely:

• Approximately 9 years elysed before the licensee identified the deficiencies associated with the

1985 TS change in the pool temperature limit (i.e., from June 6,1985 when License

Amendment No. 88 was issued until May 27,1994, when licensee memo OPVY 298-94 was

issued which addressed the deficiency regarding the licensee's failure to evaluats de impacts of

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the higher post LOCA pool temperature on other analyses such as CSCS ~ pump NPSH, LOCA

- containment analyses, CSCS piping stress and support loads and equipment qualification),

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k * The licensee took approximately 18 months (from May 27,1994 to November 2,1995) to enter

the pool temperature discrepancy into their corrective action system (ER 95-0644). Further,

j some 19 months elapsed _between the time the licensee identified the problem and the time that

c the licensee imposed an administrative limit on the pool temperature (SO #19 issued December

1,1995. Additionally,23 mont s hhad elapsed between the time that the licensee had identified t

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the problem and the time that the licensee completed a safety evaluation and operability

, determination (SE 96 008 and BMO 96-05, both approved on April 8,1996).

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i- '* The RHR system operating procedure OP 2124 was not revised until April 1997 to reflect the

, pool temperature limit dictated by SO #19 (originally issued December 1,1995).

• The licensee did not request a TS change after SE 96-008 was approved on April 8,1996,

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L The inspection team concluded that the licensee was not timely in its identification and

! correction of the torus temperature problem. The failure to promptly identify and correct the

!- toms temperature problem represented a weakness with respect to the requirements of 10 CFR

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Part 50 Appendix B, Criterion XVI," Corrective Action." This item is designated as

- URI 50-271/97-201-02.

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f (3) Licensee Event Report

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On March 26,1996, the licensee made a one-hour telephone notification to NRC in accordance

with 10 CFR 50.72 (b)(1)(ii)(B). VY reported that the worst-case LOCA containmera analysis '

F should consider feedwater flow as indicated in NUREG-0783 and that small and intermediate

[ breaks may result in a higher peak temperature than a large break. This new analysis potentially

[ . placed the plant in a condition outside ofits design bases. Although the licensee made a one-

!' hour telephone notification, the team found that VY failed to issue a licensee event report

(LER) to report this condition. . The licensee's failure to issue an LER is considered URI 50-

L 271/97 201-03.

b.- RHR Pump NPSH Calculations

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The licensee identified that there were several cases (A2, B2 and C2) in which calculation VYC 808,

! Rev. 2 yielded a negative NPSH margin for the RHR pumps. The analyses assumed that the RHR _

- pumps were operating under design flow rate condition (7000 gpm), and considered the effects of

j suction strainer clogging caused by fibrous insulation debris as well as the impact of a 10*F increase .

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in peak calculated post accident suppression pool water temperature (from 166 to 176'F). To

, demonstrate acceptable NPSH margins, the licensee used reduced head pump performance conditions

that were provided by the RHR pump vendor, Bingham-Willamette (BW),' as part of the original

j pump test data.- The team found that the licensee's use of the reduced head pump performance curve

was acceptable for this application;

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e - The team identified several errors in the licensee's calculations which reduced the NPSH margin for

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the RHR pumps. The most significant error was the use of an equation (developed in Calculation

{ _ VYC-1389, Rev. 0) to calculate the required NPSH as a function of pump flow rate.~ This equation

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was a curve fit of the vendor's test data. However, the required NPSH values calculated using the

i equation were less than the actual test data (by about 0.5 ft.) in the rated flow range and, thu s, were _  :

not conservative. However, there was conservatism in calculation VYC-808 (e.g. over-estimation of

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the clean strainer head loss prior to adding allowances for strainer clogging) which would yield

additional NPSH margin. The licensee issued ER No. 97-0664 and memo VYs 60/97 dated June 6,

1997 to address the non-conservative NPSH values calculated by the equation. The licensee's

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resolution of the nonconservative differences between the equation and the test data is designated as

IFI 56 271/97-201-04.

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- c. Non-Conservative LPCI How Rates Used in LOCA Analyses

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l TS Section 4.5.A.1.c required the performsnce of a flow rate test drhg each refueling outage to

!- demonstrate that each LPCI pump delivers 7450 gpm plus or minus 150 gpm (veuel to vessel).

j Section E of surveillance procedure OP 4124, Rev. 46, specified the flow rate test acceptance criteria

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as 7300 to 7600 gpm using recorder FR-143. In preparing for the design inspection, the licensee had

identificd that Calculation VYC-937, Rev. O and Rey,1, used the nominal flow value of_7450 gpm,

i- rather than the udnimum acceptance value of 7300 gpm, as the starting point for developing the LPCI

l flow rate inputs to the LOCA analyses (ER 97-0502). This resulted in higher LPCI flow rate values

than may actually exist following a LOCA.

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The licensee concluded that the resulting reduction in LPCI flow (approximately 90 gpm) would have

! a minimal impact on the LOCA analysis results. The use ofincorrect and non-conservative LPCI .

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flow inputs in the LOCA analyses represents a weakness with respect to Criterion III of Appendix B

to 10 CFR Part 50. This item is designated as URI 50-271/97-201-05.

d. RHR Pump Minimum Mow (IE Bulletin 88-04)

The team had concerns with the design of the RHR system to provide adequate minimum flow for

continuous RHR pump operation. The plant's original design required that each minimum flow line

have a nominal design capacity of 350 gpm for each pump, In 1986, Bingham Willamette (RHR

pump vendor) notified Vermont Yankee Nuclear Pcwer Corporation (VYNPC) that the ndnimum

flow for the RHR pumps should be increased to 2700 gpm for continuous operation. BW defined

continuous operation n more than 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> of pump operation in any 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />. BW also indicate!

that the minimum flow can be reduced to 2075 gpm for intermittent operation. However, the rdih

system currently accommodates only 350 gpm through the minimum flow piping.

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As a result of the team's inspection activi ties, VY reviewe<l the precautions regarding minimum flow

within the operating and surveillance procedures.- The licensee then added a precautionary statement

in OP 2124, " Residual Heat Removal System," Rev. 41, to restrict operation of the RHR pump in the

minimum tiow mode to less than 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> of continuous operation in a 24-hour period and indicated

that a flow of 2700 gpm is required for periods of 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> or more. The licensee also issued

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Department Instructions (dis)97-102 and 97 100 to clarify ops 4124 and 2124 by indicating that a

system flow rate of 2700 gom should be promptly established aAer planned pump starts,

The licensee also obtained additional clarification from the pump vendor, Sulzer Bingham Pumps Inc.

(SBPI) formerly known as Bingham Willamette (BW), In their letter to W dated May 21,1997,

SPBI stated that the RHR pumps could be operated at 350 gpm for 30 minutes as a one-time event in-

l

'

the life of the plant. Additionally, SBPI recommended that RHR pump operation should not be

sustained at a flow rate of 350 gpm for any longer than 30 seconds for monthly startup surveillance

tests. Further, SBPI believed that the RHR pumps could survive operation at 350 gpm for 30

minutes and continue to function once the flow is increased to 2700 gpm or greater, provided that the

pumps were in good mechanical condition. W informed the team that operator action will limit

post accident minimum flow operation to 30 minutes or less.

The licensee had previously reviewed the RHR pump minimum flow issue in 1986 when BW notified

W of the change in the minimum flow requirement, Having compared the estimated time for pump

operation at minimum flow to the total hours which the pump can operate over its life, W concluded

in 1987 that a substantial safety hazard did not exist for the plant, In their analyses, the licensee

concluded that intermittent operatior, of less than 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> per 24-hour period over the 40-year design

life was equivalent to 29,200 hours0.00231 days <br />0.0556 hours <br />3.306878e-4 weeks <br />7.61e-5 months <br />. In contrast, the licensee indicated that monthly surveillance

testing used the minimum flow path for 15 to 30 seconds, which W considered negligible.

In the worst case, a small break LOCA may require RHR operation in the minimum flow mode for a

maximum of 4 to 5 hours5.787037e-5 days <br />0.00139 hours <br />8.267196e-6 weeks <br />1.9025e-6 months <br />; however, the licensee concluded that a total of 5 hours5.787037e-5 days <br />0.00139 hours <br />8.267196e-6 weeks <br />1.9025e-6 months <br /> of operation in the

minimum flow mode was considerably less than the 29,200 hours0.00231 days <br />0.0556 hours <br />3.306878e-4 weeks <br />7.61e-5 months <br />. W therefore concluded that the

pumps would not experience sufficient operating time under the reduced flow conditions for ,

recirculation cavitation failures to develop. However, as a precaution, W added a statement to

procedures OP 2124, " Residual Heat Removal System," Rev. 21, and to OP 4124, " Residual Heat

Removal and RHR Service Water System Surveillance," Rev. 22, that pump operation in the >

minimum flow rhode should be minimized,

r

At approximately the same time period, NRC issued IE Bulletin No. 88-04, " Potential Safety Related

Pump Loss," and requested that all licensees investigate and correct two minimum flow design

concerns. One of these concerns was to determine whether the installed minimum flow capacity was

- adequate for a single pump in operation. Specifically, action item 3 oflE Bulletin 88-04 requested

that licensees conduct an evaluation with respect to damage resulting from operation in the minimum

flow mode, considering cumulative operating hours in the minimum flow mode over the lifetime of

the plant and during the postulated accident scenarios involving the largest time spent in this mode.

The evaluation was to consider best current estimates of potential pump damage derived from

pertinent test data and field experience, including verification from the pump suppliers that current

minimum flow rates were sufficient to ensure that there will be no pump damage from low flow

operation. If the test data did notjustify the existing capacity of the bypass lines, or if the pump

supplier did not verify the adequacy of the current minimum flow capacity, the licensee was to submit

a plan to obtain additional test data or modify the minimum flow capacity as needed.

6

.- .. .

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. . . . . . . . .

. . . . . . . .

... .. .... .

- _ .._ . _ . _ _ _. _ _ __ . _ __ _ _ . _ _ . _ _ _ _ _ _

.. . .-

,

,

] --

.. - - -

.. W responded to IE Bulletin 88-04 through a series ofletters. The last of these letters to the NRC

(BW 89 42, dated May 8,1989) indicated that W had previously revised plant procedures to

reAect the most recent information on minimum flow and no further procedural changes were

i necessary at that time. Additionally the letter stated that the licensee did not consider it necessary to

increase the minimum flow capacity based on the experience of the Boiling Water Reactor Owners

Group (BWROG), and based on W's own experience and their engineering judgment that

'

mbdmizing time in the minimum flow mode, coupled with the preventative maintenance history would

i ensure that the pumps remain reliable. With regard to the vendor's experience, W's response

e indicated that the minimum pump flow rates were acceptable for surveillance testing; however no

4

data were available to assess operation in the minimum Sow range for all time durations,

i

The team identified the following issues regarding the licensee's response to IE Bulletin 88-04:

i e The team concluded that W's response to IE Bulletin 88-04 'acked the technical basis to

_

' conclude that the existing RHR pump minimum flow would be adequate during the postulated

accident scenarios during which the RHR pump would operate for several hours under

i

minimum flow conditions. VY's response to Bulletin 88-04 did not provide either the

[' verification from the vendor or test results to demonstrate that RHR pump minimum flow rates

were adequate during the postulated accident scenarios. Although the vendor acknowledged

i that the monthly surveillance tests - limited to 30 seconds at 350 gpm - would probably not

result in pump damage, the vendor could not support the assertion that a cumulative arithmetic

[ series of minimum flow 9 vents over the life of the plant (29, 200 hours0.00231 days <br />0.0556 hours <br />3.306878e-4 weeks <br />7.61e-5 months <br />) had the same

'

relationship to pump degradation as the length of a specific event (4 to 5 hours5.787037e-5 days <br />0.00139 hours <br />8.267196e-6 weeks <br />1.9025e-6 months <br /> of RHR pump

operation during an accident scenario). SBPI also could not predict the mechanical condition or

performance of the pumps after a 5 hour5.787037e-5 days <br />0.00139 hours <br />8.267196e-6 weeks <br />1.9025e-6 months <br /> run at 350 gpm and did not recommend such a run.

The team identified the lack of test data and inconsistency with the vendor's recommendations

regarding RHR pump minimum flow as URI 50-271/97-201-06.

• The licensee's modification ofits operating instructions in response to IE Bulletin 88-04 did not

adequately reflect the vendor's instructions rege.rding RHR pump minimum flow operation.

Although the 350-gpm bypass capacity did not support RHR pump operation beyond the 30

seconds, the operating procedures contained no such restrict ions. Instead, the licensee revised

the operating and surveillance procedures to caution the operators to minimize pump operation

in the minimum flow mode. During the inspection, the licensee revised operating procedures to

reflect vendor recommendations on the RHR minimum flow requirements.-

• Finally, the team was concerned with the fact that operator action was necessary within the first

30 minutes under certain accident scenarios to prevent possible damage to the RHR pumps.

The team considered the operator intervention to overcome a design deficiency as a change to

the RHR system design and a change to the LPCI mode of RHR operation as described in the

FSAR (URI 50-27U97-201-07).

7

.

Wm- -

s,v -- ,ee. s ~~- e- -- -mF--

_ _ . _ _ _ _ _ _ . . . _ _ _ _ _ _ _ _ _ _ _ _ _ . - _ - _

, .

)

i.' l

8

e. RHR fume Motor Starts - Procedure Precautions

"

_ The team requested that the licensee provide the basis for the precaution in OP 2124, " Residual Heat

Removal System," Rev 41, which allowed three RHR pump starts.in 5 minutes, followed by a

L 20-minute run or a 45-minute shutdown for cooling. _VY noted that the National Electrical

- Manufacturers Association (NEMA) MG-1 required that motors be capable of two starts in -

.*

succession, with the motor initially at ambient temperature. GE Nuclear Energy services also

provided a response (by letter dated June 5,1997) which indicated that each RHR motor was capable

of three starts firom ambient, without adversely affecting the integrity of the motor, provided that the

acceleration time was less than 5 seconds and the ambient temperature was less than 30*C (86'F).

• However, the licensee indicated that the maximum normal operating temperature for the RHR corner -

rooms was 109 F and the room temperature may reach 155'F during accidents. The team therefore

, considered the 86*F limitation on ruccessive pump stnts to be inconsistent with the normal and

design temperatures for the RHR corner rooms.

'

'

'

.

Criterion III to 10 CFR Part 50, Appendix B," Design Control," requires that licensees must correctly

translate the design bases into specifications, drawings, procedures, and instructions. The team -

! concluded, however, that the licensee's direction in the operating instructions (compared to the

i

manufacturer's recommendations and limitations for RHR' pump motor starts) failed to meet this

requirement. This is identified as URI 50-271/97-201-08.

! f. Failure to Update FSAR

i

During their internal service water operational performance inspection (SWOPI) in 1994, the licensee

j found that RHR heat exchanger performance was over-estimated because (1) tube plugging was not

considered, (2) the fouling allowance was too low, and (3) the tube wall thickness was larger than

, assumed (0,049 in. versus 0.035 in.). The re-calculated capacity was 52.5 x 10' Btu /hr, as

f determined in Calculation VYC-1290, Rev. O, dated August 1,1994 However, the licensee failed to

update FSAR Table 4.8.1, Figure 4.8-1, Figure 6.4-3 and Section 14.6.3.3.2, which still stated that

[ the design heat transfer capability of the RHR heat exchaager is 57.5 x 10' Btufar.

!

The licensee failed to update the suppression pool post-LOCA temperature analyses presented in

FSAR Section 14.6.3, which included an assumption that feedwater flow ceases at the beginning of a

LOCA event. This assumption was considered conservative at the time that the analyses were

performed (late 1960s to early 1970s). However, the licensee recently determined that it is more -

conservative to assume that the feedwater mass and energy addition would continue following the

l LOCA event. This new scenario would lead to an increase of about 10'F in the peak calculated post.

LOCA suppression pool water temperature (from 166 to 176*F), assuming an initial pool temperature

of 90*F, The licensee documented these results in Calculation VYC-1290, Rev,2, dated August 8,

1996.

8

_ . . . . _ - _ _ . _ - _- __ _ _ _ _ _ _ _ _

_ _ _ _ _ _ _ _ _ _ _ . _ _ _ _ _ .

_

On March 26,1996, the licensee notified the NRC that the plant was operating under a condition

outside ofits design bases. Specifically, the higher peak pool water temperature impacted the CSCS 3

pump NPSH and equipment qualification. The licensee then prepared SE 96-008 and concluded that  !

. the increase in peak post LOCA pool water temperature from 166 to 176'F did not constitute an

unreviewed safety question.

The licensee predicated this conclusion on administratively limiting the maximum normal pool

temperature to 90'F (revised to 87'F in May 1997) or less, even though the TS allowed 100*F In

addition, the licensee included a summary of SE 96-008 in the W Cycle 18 Operating Report (dated

May 2,1997), which was submitted in accordance wi:h 10 CFR 50.59(b)(2). However, contrary to

,

the requirements of 10 CFR 50.71(e), the licensee had not updated the FSAR to reflect the results of '

this safety evaluation in their W Cycle 18 Operating Report.

The licensee's failure to update the FSAR to reflect changes in RHR heat exchanger performance and -

l suppression pool post LOCA temperature analyses is contrary to the requirements of 10 CFR -

L 50.7)(c). This item is designated as URI 50-271/97-201-09,

g. Torus Cooline /LCO Mananement

The licensee identified a single failure vulnerability when the RHR system was aligned in the torus

cooling mode and wrote EF 97-473 to document this concern. For certain LOCA events and

single-failure considerations, realignment of valves for torus cooling would not be possible (because

of a failure of the power supply) and would result in one LPCI pump flowing out the break area, and

the second LPCI pump in torus cooling alignment. This condition would result in less flow than the

minimum licensing basis of one CS pump, and one LPCI pump injecting into the intact recirculation

loop to mitigate the consequences of an accident as described in the FSAR The licensee stated that -

the LPCI system need not be declared inoperable because W's licensing basis regarding surveillance

, testing did not require entering a limiting condition for operation (LCO) to perform testing. In

addition,- W considered operation of the RHR system in the torus cooling mode to be an extension

ofHPCI and reactor core isolation cooling (RCIC) surveillance testing.

The team concluded that the W practices of not entering TS LCO conditions when equipment was

rendered inoperable for TS surveillance was not consistent with the NRC's operability guidance, as

stated in Generic Letter (GL) 91-18. Specifically, Enclosure 2 to GL 91-18 provided technical

guidance for operability determinations. Paragraph 6.4 of Enclosure 2 stated that if a TS surveillance

required that safety equipment be removed from service and rendered incapable of performing its

safety function, the equipment was inoperable. The GL further stated that the LCO action statement

shall be entered unless the TS explicitly directed otherwise. The team considered the inability of the

LPCI system to withstand a single failure while in the torus cooling mode to render the system

incapable of performing its design safety function and, therefore, the licensee should limit the time the

' LPCI system is in the torus cooling mode.

9

__ _ . _ _ _ _ _ _ _ .

l

-l

The licensee did not have any licensing documentation to support the NRC's acceptance of the VY- ~

_ position that LCO entry to perform testing was not required. The licensee indicated that this was a '

matter of practice since initial operation, and no formal documentation of NRC approval was -

- available. During the exit meeting on July 1,1997, the licensee informed the team thct they intended

to enter an LCO whenever the RHR system was aligned in the torus cooling mode. The team

identified this issue as URI 50-271/97-201-10.

This issue was previously identified in the NRC's Region I Team Inspection Report No. 50-271/93-

g0, dated September 7,1993. VY's response, datad November 12,1993, indicated that it had

incorporated formal self-assessment of TS surveillance requirements to improve management controls

into the Improved Technical Specifications (ITS) program, which is currently scheduled for submittal

in the fourth quarter of 1998. The team identified the issue regarding the timeliness of followup

commitments as URI 50-271/97-201-11.

El.1.2.3 Conclusions

The mechanical design of the LPCI system was generally acceptable, and the system was capable of

performing its safety function.- The LPCI operating mode of the RHR system was capable of

performing its safety-related coolant injection function in the event of a LOCA assuming a loss of-

._ normal power and a single active failure. LOCA analyses performed to evaluate CSCS performance

incorporated adequate margins for LPCI surveillance test flow measuring inaccurr.:ies, addressed

flow diversion through the RHR pump minimum flow lines, and considered limiGng single active

failure cases. The licensee's component safety and seismic classificatic.is, an$ specified codes and

standards were appropriate, and that the design pressures and temperatues specified for piping and

components, and the overpressure protection features provided, were adequate. The two RHR loops

were physically separated such that no s:ngle physical event would make both loops inoperable.-

Nonetheless, the team identified several concerns as follows:

a

past operation outside of the plant's design bases when suppression pool water temperature

exceeded 90*F (50-271/97-20101)

e

inadequate technical basis with regard to the RHR pump minimum flow requirements

(50-271/97-201-06)

e

change to the LPCI mode of RHR operation as described in FSAR (50-271/97-201-07)

e

failure to enter TS LCO conditions when equipment was rendered inoperable (not consistent

with GL 91-18 guidance)(50-271/97-201-10)

.-

failure to take timely and/or complete corrective actions to resolve the suppression pool water

temperature issue (50-271/97-201-02)

• -- failure to issue an LER to report a condition outside of the plant's design basis

(50-271/97-201-03)

• errors in the calculation of RHR pump NPSH margin (50-271/97-201-04)

e use of non-conservative LPCI flow rates in the LOCA analyses (50-271/97-201-05)

_

..

failure to update the FSAR to reflect reduced RHR heat exchanger capacity and to incorporate

revised c(ntainment analyses (50-271/97-201-09)

.)

_ _ _ . _ _ . _ _ _ . - _ _ . - . _ _ _ _ . _ . . _ _ . _ _ _ _ _ _ _ _ .

p* -*

4=

y

' e

inappropriate operating instructions regarding permissible RHR pump motor starts

'

.(50-271/97-201-08)

. * - lack of timeliness in the licensee's actions with regard to commitments for self assessment of TS

P l requirements (50-271/97 201-11)

,

b El.2 Residual Heat Removal Service Water

i

, - El.2.1. System Descrintion and Safety Function

'

The safety fbnction of the RHRSW system is to provide sufficient cooling capacity for the RHR

'

system during a DBA and to minimize the probability of a release of radioactive contaminants to the

environment. The RHRSW system consists of four RHRSW pumps; two RHR heat exchangers; and

-

the necessary piping, valves, and instruments. The system is Safety Class 3, with a Class I seismic -

design. . Components and equipment are powered from the emergency buses, such that power is

. available during a loss of offsite power. The two RHRSW loops are redundant and physically

j separated, and each loop is capable of providing 100% of the cooling capacity required for safe

_

l -

shutdown. Isolation valves automatically close on loss of service water header pressure to isolate all

non-essential equipment. In r,ddition, the pump spaces are provided with safety-related room coolers

_ (RRUs 7 & 8), which remove heat to avoid excessive temperatures in the RHR rooms,

i

i El.2.2 Mechanical

,

El.2.2.1 Scone of Review

The mechanical design review of the RHRSW system included system walkdowns and discussions

with system and design engineers as well as reviews of the plant's design and licensing

L documentation. The team reviewed applicable portions of the FSAR and TSs, as well as flow

diagrams, physical drawings, vendor drawings, equipment specifications, a draft DBD, calculations,

l operating and surveillance procedures, and ERs. The team reviewed the appropriateness of the >

design, bounding conditions, validity of assumptions, design inputs, vulnerability of system

' components, overpressure protection, and adequacy of tests and surveillances.

! El.2.2.2 Findings

i

- a. RRUs 7&8 Test Measurement Inaccuracies

i

The licensee had used the differential pressure (delta-P) method in Calculation VYC-1329, "RRU 7 &

8 Performance Assessment (Clean & Plugged)," Rw.1, to determine the thermal performance of the

~ two safety related unit coolers. This analysis used the relationship between the pressure drop across

~ the heat exchanger and its heat removal capacity to determine the e offouling for the heat

. exchangers.1 Calculation VYC-1329 assumed that the increase in pressure drop was the result of

fouled heat exchanger tubes.

i

!

i

- 11

i

i

!

. . . . _ . , _

, . . ~ . _

-

- - -

-- -- -

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- The team found several problems with the test results. First, the team could not ' draw a coherent

regression line through the test data points. Additionally, the test results 6dicated that the pressure

drop across RRU 7 had decreased some 17 months aAer the heat exchanger was cleaned. This l

'

-indicated improved thermal performance. Further, the measured pressure drop across the heat :

exchanger (10 psid) aAer it had been cleaned was much higher than what was calculated (2.5 psid) for

a fouled cooler. The licensae attributed 3.5 psid of this 7.5 psid to instrument location and the

remaining 4 psid to instrument inaccuracies. The team also determined that the results from

Calculation WC-1329 were not used as inputs to other safety-related calculations. The licensee -

informed the team that more accurate instruments were installed in February 1995, and future test -

measurements should be more consistent and more accurate. I

Criterion XI in Appendix B to 10 CFR Part 50 requires that "... provisions for assuring that all

.

'

prerequisites for the given test have been met, that adequate test instrumentation is available and

used, ..." The team concluded that the test data obtained was indicative of a failure to meet this

-

requirement,- URI 50-271/97 201-12.

b. Incorrect Assumntion in the Calculation Methode!ery for RRU 7 and 8

The licensee failed to update the heat exchanger fouling assumption used in Calculation WC-1329,-

even though their inspection of the heat exchanger indicated that the assumption was incorrect.

Calculation WC-1329 assumed that gross silting would be the cause of increased differential

_

_ pressure across RRUs 7 and 8. Hov>ever, the licensee's inspection of the heat exchanger tubes (April

1995) found no evidence of silt fouling. The team concluded that the fouling of the heat exchangers

resulted from other fouling mechanisms such as slime. AAer discussions with the licensee, it appeared

that this discrepancy had a negligible effect, but the licensee issued ER 97-0634 to address this issue.

Criterion III in Appendix B to 10_ CFR Part 50 states that the design control measures shall provide

for verifying or checking the adequacy of design by the perfcimance of a suitable testing program.

Calculation WC-1329 used an assumption wh:ch seemed reasonable when made; however, it was

found that the initial assumption was incorrect during subsequent inspection of the heat exchangers.

Nonetheless, the licensee did not revise their assumptions when the calculation was revised

(URI $6 271/97-201 13).

c. Downerade of RRUs 5 and 6 -

The licensee had changed the safety classification of RRUs 5 and 6 from safety-grade to non safety- -

grade without performing a safety evaluation. Paragraph 10.7.6 of the FSAR stated that "the pump

spaces are provided with space coolers (RRUs 5,6,7, and 8) fed from the Station service water

- system (SWS) to prevent overheating of the motors ..." Discussion with the licensee indicated that -

the safety evaluation was not performed because the engineer who had reviewed this change

incorrectly determined that no safety evaluation was needed. AAer reviewing the licensee's

procedure AP 6002," Preparing 50.59 Evaluations and FSAR Changes," Rev. 5, the team determined

that questions 2, 8, and 20 associated with the screening evaluation should have required the

performance of a safety evaluation.

12

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_ _ _ _ __ _ . _ _ _ _ _ _ _ _ _ _ _ _ . _ _ . _ _ _ _._.. _

g

i

_

The licensee performed the screening evaluation during the inspection and agreed with the team that a -

safety evaluation should have been performed. The team concluded that the downgrading of RRUs 5

- and 6 without a safety evaluation constituted a weakness in the safety evaluation screening process

j and identified this issue as URI 50 271/97 201 14.~  !

d,_ Overslebt of the Safetv Evaluation Process by the Mant Oneratle=al Review Committee

,

(PORO

i

j- The team noted that ne PORC had inappropriately approved the downgrading of RRUs 5 and 6 from

! safety to non safety grade without a safety evaluation. The licensee informed the team that

performance weakt-,es associated with the PORC had already been identified and addressed by

j Region I inspectors. In the licensee's letter NW 94-89, dated September 2,1994, W notified the

i

NRC that it was upgrading the process used for PORC evaluation of plant changes, and the upgrade j

i process would be ccmpleted as of December 1994, The NRC responded in letter NW 94-164,  !

'

l dated Sep. ember 26,1994, stating that the proposed corrective actions and preventive measures were

! adequate. Me team noted that PORC's approval regarding the downgrade of RRU 5 and 6 took

[ place before the licensee made improvements to the PORC review process.

i

i

e. Deletion of RRUs 5 and 6 from the GL 89-13 nronram

In a response to the NRC regarding GL 89-13, the licensee corrmitted that safety-related RRUs 5 and

6 would be monitored and analyzed in accordance with the delta-P method specified in Section 8 of

EPRI NP-7552 (paragraph d.1 in Attachment A to BW 90-007, dated January 22,1990). However,

_

when the licensee removed RRUs 5 and 6 from the GL 89-13 program, they did not notify the NRC

that these coolers were no longer covered by their monitoring program.

The team considered the removal of RRU 5 and 6 from the GL 89-13 program constituted a change

from W's licensing commitments and the licensee should have notified the NRC.- The team

identified this issue as IFI 50-271/97 201-15.

f. Performance Testina of RHR Heat Exchanners

'

The team found that calibration and other problems existed with regud to the instruments used to

measure RHR heat exchanger performance. As part of the licensee's GL 8913 program, the licensee

performed a series of tests and some test results indicated as much as 46 percent discrepancy between

the' measured energy removed from the RHR system and the energy added to the service water

system. L Accuracy of more recent tests improved because of the licensee used more accurate

instrumentation.

'As a result of the inspection, the licensee reviewed calibration records of the instruments used,

analyzed the data, and issued three ERs as follows:

(1) ER-97-0667, dated June 5,1997, documented the fact that flow measuring instruments

recorded more than actual flow,

13

o .--

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(2): - ER-97 0630, dated May 29,1997, documented a condition in which the flow instmments

exhibited inaccuracies as high as 12.35%, contrary to the value of 10% assumed in the analysis.

(3) -- ER 97 0602, dated May 23,1997, documented the team's fmding that the instrument computer

input points used in the tests were uncalibrated. Specifically, these were the Emergency

Response Facility Instrumentation System (ERFIS) points, which were used to record the -

service water supply temperature (F060), RHR inlet temperature (M062, M064), RHR outlet

temperature (WO98, WO99), RHR flow (P001, P002), RHRSW flow (P05, P006), und RHRSW

outlet temperature (TE 10 94A,B).

On the basis of the team's concerns regarding the heat exchanger test results, the licensee analyzed

the impact of the instrument inaccuracies and documented their result in B'MO No, 97-27. The BMO

made a few recommendations, one of which was to " impose and maintain an administrative limit to - '

restrict plant operawn to river temperatures of 80 F or below." The river design temperature is 85"F.

- Criterion XII in Appendix B to 10 CFR Part 50 requires that " Measures shall be established to assure

that tool gages, instruments . . . are properly controlled, calibrated, and adjusted at specified periods

to maintain accuracy within necessary limits." The team concluded that the test data obtained was -

mdicative of a failure to meet this requirement. URI 50-271/97-201-16.

g. Failure to Insnect RHR Hent Exchanner IB (GL 39-13 Commitment)

The licensee failed to test RHR heat exchanger IB during the refueling outage in September 1996. In

Attachment A to BVY 90-007 (from VY to NRC), the licensee stated that the RHR heat exchangers

"will be tested by measuring their heat transfer capability . . . " and that both heat exchangers were

tested once and will be tested during the next two refuel outages, in addition, the licensee stated that

"a testing frequency will be determined to provide assurance that the design heat removal capaWG of

these heat exchangers is maintained."

The team considered this a deviation from the licensing commitment to determine a testing frequency

to provide assurance that the design heat removal capability of these heat exchangers was maintained.

URI 50-271/97-201-17.

h. Common-Mode Failure of Non Safety Renulators Affectine Safety-Related Diesel

Generators

The team found that the service water flow control valve for the plant emergency diesel generator

(EDG) was susceptible to common-mode failure from its asso:iated non safety-related pressure

regulator. - The failure of the flow control valve could cause a loss of all service water to the EDGs.

This failure mechanism affected both trains of EDGs

Service water to the EDGs was supplied through flow control valve FCV-104-28A. FCV-104-28A

was a normally closed valve with a fail'open setting, and the solenoid valve FSO-104-2SA supplied air

- to operate FCV-104-28A. Because the air supplied to the solenoid valve was from a

14

_

, ,-

nonsafety-related pressure regulator, a failure of the pressure regulator could result in the mt! function

of the solenoid valve, which could prevent FCV-104-28A from opening. Additionally, since the non

safety-related pressure control valve supplied air to the solenoid valves for both trains of EDGs, the

failure of a single non safety related pressure regulator could potentially disable both trains of EDGs.

Furthermore, the team noted a similar situation with the flow control valve in that a non safety-related

regulator also supplied air to the valve positioner and flow controller FC 104 28A. Therefore, a

failure of this non safety pressure regulator could also cause closing of flow control valve

FCW104-28A. The team concluded that failure of either the flow control valve FC%104-28A or

- flow controller FC-104-28A would cause the EDGs to become inoperable because ofloss of service i

water,

The licensee initiated ER-97-0512, dated May 9,1997, and a preliminary BMO evaluation. In

addition, the licensee revised BMO-96-03 to analyze the condition. As a result, the licensee i

performed a commercial dedication on new air pressure replators and installed them during the

inspection.

Criterion Ill in Apoendix B to 10 CFR Part 50 states that " Measures shall also be established for the

selection and review for suitability of application of materials, parts, equipment, and processes that .

are essential to the safety-related functions of the structures, systems and components " Contrary to

that requirement, failure of non safety-related pressure regulators may have prevented the operation

of safety-related EDGs. URI 50-271/97 201-18

i. Service Water Intake Bay Ambient Temnerature Unon Loss of Ventilation

c The team identified a concern regarding the operability of the service water pumps resulting from loss

j of service water room fans (non safety-related). Such a loss would cause the room temperature to

!- exceed the NEMA rating for the motor insulation during the summer months. The service water

'

rooms were cooled by natural convection when fans were lost. This natural draft was created by

opening a ceiling damper during the summer months.

I

'

Based on the team's concerns, the licensee issued a BMO to address this service water operability i

issue. The licensee concluded that, although the NEMA rating for the Class B insulation of the

motors will be exceeded, service water pump motors were tested to significantly higher temperatures =

_

and that higher ambient room temperature would shorten the life of the motor, but would not cause

immediate failure. The team had no further nuestions on this BMO.

The team was also concerned that there were no alarms available to warn the operators of high

ambient temperature conditions in the service water pump rooms. However, the team's review of :

design and licensing documents revealed that VY wu not required to have these alarms for the

service water pump rooms. The only indication of high room temperature was from the pump motor

winding temperature instrumentation which would be affected by the room temperature, The motor

15

._. - - - - - -

,7_____-__----

...

i

!

a

j

winding temperature instmmentation was not safety.related instrumentation. VY's calculation VYC. l ;

1387, "Swvice Water Pump Room Analysis," Rev.1, auumed that only two service water pumps

would be :unning when non safety related fans were unevallable.

ll

,

i

l j. Onerability of SWE/LCO Management  ;

)

i  % team was concemed by the licensee's lack of timeliness in revising their Technical Speci6 cations

.

(TS) aner identifying a TS requirement that appeared to be non-conservative. Speci6cally, TS

j 3.5.D.3 allowed all four service water pumps to be inoperable for up to 7 days. The team expressed a

j concern that the plant operation could be al%wed for 7 days without any service water pumps being ,

i

operable. The licensee informed the team that they had identi6ed this issue on February 24,1997,  !

3 and wrote an event report. The resolution to that ER initiated a revision to OP 2181, which read I

- *When it is determined that both SW subsystems are inoperable, the :eactor shall be in a cold ,

, shutdown condition within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />, unless a subsystem is sooner made operable or a BMO is written  ;

I

and approved." Although the procedure effbetively imposes an administrative LCO, the team was  !

!. concemed with the licensee's schWe for revising their TS. N licensee's original intention was to  ;

} .nclude this change to their TC N ITS submittal, which appeared to be several years away. At the

end of the inspection, the licenti . aformed the team that changes to TS 3.5.D.3 would be inde in '

! September 1997.-

t

,

t

l Additionally, the team found that the basis for TS 3.5.D.3 conAicted with FSAR Section 10.8.2.  ;

i

Specifically, the FSAR stated that the alternate cooling system (backup service water system) was not

i.

'

classi6ed as an engineering safeguard system and was not designed to accept the consequences of a

j design basis LOCA. Also, it was not immune to a single failure. However, the basis for TS 3.5.D.3 l

l stated that the altemate cooling water system provided an altemate heat sink to dissipate residual heat

i

aAer a shutdown or accident. The team verified that the FS AR statement was correct and the basis -

for the TS was incorrect,

[

<

j - Not revising their TS was considered a licensee's failure to take prompt corrective action to address .

i conditions adverse to quality (URI 50 271/97 201 19),  !

'

L'

k. Tornado Missile Protection

,

i The team identified a concern regarding the acceptability of the licensee's use of the probabilistic risk $

i assessment (PRA) methods to address tomado missile protection for some safety related equipment, t

Specifically, the licensee'r pse of PRA appeared to be inconsistent with the licensing basis for the .

! Pl ant.

4 .

.

! Although VY's FSAR did not specifically state that components which affect safe shutdown of the  ;

[F

'

plant wue designed to be protected firom tornado induced missiles,Section XII.2,1.3 of the . .

'

Preliminary Design Assessment Report (PDAR) indicated that components which directly affect the _;

ultimate safe shutdown of the plant are located either under the protection of reinforced concrete or '

i. underground. - These components included the SWS and the standby diesel generator system. If

s

- protective barriers were not installed, the structures and components were suppose to be designed to a

'

'

16 -

3

'

T

J J,. .,,,,m_a_.m.. -- ..--._>.-,,_,,. _.. - .. - m ,me.. .- - ,.,,# ,,_...m _ _,,--m,_ ,_,,-+.,-.-,.,w

-

. .

withstand the effects of the tornado, including tornado missile strikes. However, the team found that

several components did not appear to have adequate protection from the effect6 of tornadoes.

Specifically, these systems included the service water supply line to the circulating water and service

water traveling screens, service water piping to the diesel generators outside the diesel generator

rooms in the turbine building, fbel oil transfer lines routed on the exterior of the pump house and the

diesel exhausts.

When similar issue with respect to tornado protection was raised in the past the team identified

similar issues regarding adequate equipment protection from tornadoes in VY's Service Water

Operational Performance Inspection (SWOPI), conducted in 1994 and during the NRC Electrical

Distribution System Functional Inspection (EDSFI) (Report No. 50 271/92 81)- VY stated that

probability of tornado missile damage to systems such as the fbel oil transfer lines was staall and that

no further action was warranted at this time. VY committed to address their long term resolution of

this issue in the Individual Plant External Event Examination (IPEEE).

The use of PRA methods to address tornado missiles hazards was identified as

URI 50-271/97 20120.

El.2.2.3 Conclusions

The mechanical design of the RHRSW system was generally acceptable, and that the system was

capable of performing its safety fbnctions when administrative limits are imposed. The system

appeared to have adequate flow, with no identified problems regarding NPSH, and the design 1

pressures and temperatures specified for piping and components were adequate, in addition, the

licensee's calculations and analyses were generally comprehensive and accurate.

Nonetheless, the team identified several concems as follows:

• --

operation of safety related equipment which was dependent on the functionality of non safety-

related equipment (50-271/97 201 18)

• heat removal capability of the RHR heat exchangers and the RRUs (50-271/97 201 12 and 50-

.271/97 201-16)

e

instrument calibration and accuracy, as well as documentation of test frequencies and equipment

requiring testing (50 271/97-201-12 and 50-271/97 201 16)

• - timely revisions to TS (50 271/97-201 19)

e

design process (50 271/97 201 13and 50-271/97-201-14)

e

the acceptability of tlw use of *RA methods to satisfy licensing commitments with regard to

tornado missile protection (50 271/97 20120).

17

. . 1

El.3 Electrical / Instrumentation and Controls

El.3.1 System Descrintion and Safety Function

The alectrical systems required to operate equipment in the RHR system include the 4160 volt AC

safety related buses which receive power from either offsite sources, onsite scneration, the Vernon

hydro-electric plant, or the two onsite EDO sets. These 4160 volt AC buses provide power to the

480 volt AC safety related buses which,in tum, provide power to 480 volt AC motor control centers

(MCCs) which distribute power to 480 volt AC loads,125 volt DC battery chargers, and 120 volt

AC instrumentation power supplies. The large redundant RIIR pumps and motors are powered from

the redundant 4160 volt AC safety related buses, and the redundant 125 volt DC buses provide

power to operate circuit breakers, solenoids, some of the motor-operated valves (MOVs) and the

control power for the EDGs.

The Class IE 125 volt DC system consists of two separate and redundant safety related buses (DC-1

and DC 2). A 60-cell, lead acid,2175 ampere-hour (AH) battery and a battery charger serve each

bus. A spare battery charger could be connected to either bus and could charge either station battery

(A 1 and B 1). An additional safety related battery, AS 2, supplies power to emergency loads in the

same separation group as battery B 1.

El.3.2 Electrical

El.3.2.1 Scone of Review

The electrical design review of the LPCI system included system walkdowns and discussions with

cognizant system and plant design engineers as well as reviews of design and licensing

documentation. The team reviewed applicable portions of the FSAR and TS; design documents

including drawings for the 4160-volt AC safety related buses, emergency diesel generator (EDG)

units, circuit breakers, MCCs, electrical cables and 125 volt DC; electrical calculations; ERs and

OERs.

The review included verifying the functional capability of the plant's electrical systems to proside

adequate power to operate the RHR system (and the associated equipment) in the LPCI mode under

the plant conditions that were most demanding on the electrical system. Specific areas covered

included load studies, sizing criteria, separation criteria, electrical coordination, short circuit and fault

current analysis, and 125 volt DC surveillance test data.

El.3.2,2 Findines

a. Vernon 69 KV Switchyard Low Voltare

Calculation VYC-1512," Station Blackout Voltage Drop and Short Circuit Study," Rev. O, dated

March 5,1997, documented a condition in which with the RHR pump terminal voltage could degrade

'

18

- - - ._. . . - . _ - - - . - -. - . - - - - - . ,

. .

to as low as 3100 volts AC (77.5% of the rated nameplate voltage) during pump starts. This

condition would exist when the Vernon 69.KV switchyard was at its minimum voltage (64.5 KV) and

there was maximum load on the 69 KV/13.2 KV transfonner that feeds the town of Wrnon By

contrast, the calculation assumed that 3200 volts AC (80% of the rated nameplate voltage) was

required for pump start. W licensee therefore issued ER 97-0409 to document the potential that the

RHR pump might fail to start at a voltage lower than what was assumed in the calculations.

Additionally, the licensee completed BMO 9717 to assess pump operability.

h operability assessment determined that the specific RHR pump motor and pump sped torque

curves provided reasonable assurance that the RHR pump can start with a voltage as low as

1

2800 volts AC (70% of the nominal, rather than the 80% assumed). However, at the team's request,

the licensee performed an evaluation concerning the time required to accelerate the pump to rated

speed at the reduced voltage of 2800 volts AC. The team found that the motor overcunent relay

would trip the motor before the pump reaches full speed at the reduced voltage of 2800 volts AC.

Given the evaluation and relay trip time, the licensee determined that a minimum tenninal voltage of

. 75% was determined as necessary in order to ensure a successful pump start. VY imposed

administrative operating limits for inonitoring and maintaining greater than 3900 volts AC on the

L %rnon tie line to ensure that sufficient voltage margin 1.nnaintained.

W licensee agreed to revise calculation VYC 1512 to resolve the potential for low Vemon tie line

voltages. The team identified this issue as IFl 50 271/97 21,

b. Main Station Batterv Service Test

.

h team reviewed surveillance test data for the main station battery service test performed on

September 14,1996, in accordance with OP-4215, " Main Station Battery Performance / Service Test,"

Rev. 6. This review sevealed that the licensee failed to follow OP-4215 which required that the

licensee attach the printout of the test records, wWh showed individual cell voltage (ICV) and

battery terminal voltage readings, to the procedure. Record retention requirements have existed

since Rev. O of the procedure, which was originally issued on September 3,1989.

This is a failure to maintain quality assurance (QA) records in accordance with Criterion XVII of

Appendix B to 10 CFR Part 50. The team identified this issue as URI $0 271/97 22.

c. Standhv Battery Charmer CAB Sinele Failure

In preparation for the inspection, the licensee identified a condition in which the connection of a

standby battery charger to the DC-2 bus could potentially result in lou of both DC divisions, h

standby charger " CAB" could be manually connected to either DC-1 or DC 2 busses and is available

to substitute for battery charger CA 1 or CB 1 in the event of a normal charger failure or a

maintenance outage. Battery charger " CAB" was not normally connected and was fed from MCC 8B

(a Division I power supply). If battery charger " CAB" was connected to the 125 volt DC-2 Bus,

19

-. - - - - . - - . - - - . -

--

i

!

l (a Division 11 power source) a failure of the Division 1 AC power system (with charger " CAB"

,

providing power to DC 2) would lead to a loss of both DC divisions and eventually to the loss of

i- control of the Division 11 AC system if charger power could not be restored before the batteries were

j depleted.

!

W TS 3.10 allowed coritinued operation, without restriction, if the standby charger " CAB" was

j connected to either DC 1 or DC 2. Moreover, FSAR 8.6.2 stated that no single failure shall cause

'

the loss ofDC supply from batteries of both systems. However, a single failure could cause both

125 Vdc buses to become degraded if charger " CAB" was connected to DC 2 since both DC 1 and

DC 2 would be supplied by chargers that were fed from Division I MCCs. A single failure (loss of

Bus 3) and consequential loss of both chargers would cause both main station batteries Al and B1 to

discharge, eventually leading to a loss of both DC 1 and DC 2.

W team considered this a deficiency in the plant's TS requirement. W licensee has issued ER97-

0177 to evaluate this deficiency. The team considers this as IFI $0 71/97 23.

d. Batterv Sizing Calculations

N team reviewed Calculation No. WC 298," Battery Sizing Calculation for Vermont Yankee

125-V Station Batteries A-1 and B 1; Capacity Verification for Battery Chargers BC 1 1 A and BC.

1 1B," Rev.10, dated April 22,1997. This review revealed that batteries A 1 and B 1 were made up

of 60 cells, C & D type LC 31. For the worst-case condition, batteries A 1 and B 1 had a design

capacity margin of approximately 28.6% and 21.1% respectively with 60 cells, and 18.6% and 16.7%

with 59 cells. The chargers used with batteries A 1 and B 1 were rated at 150 amperes and the team

verified these ratings and found them to be adequate to meet the loading requirements.

The team also reviewed Calculation No. WC 730, " Sizing Calculation for 125 V de Station Battery

AS 2," Rev.1, dated March 4,1997. This review revealed that the AS 2 battery comprised 59 cells,

of C & D Type KC 9. For the worst-case condition, the AS 2 battery had a design capacity margin

of 54% with 59 cells, and 27% with 58 cells, h charger used with ba!M AS 2 was rated at 100

amperes and the team verified that this rating was adequate to meet the loading requirements.

El.3.2.3 Conclusions

The team concluded that electrical design was adequate and operating within the design limits for

components that perform the engineering safeguards functions of the RHR LPCI mode, h team

had concems with calculation WC-1512 which did not accurately indicate the voltage limitation for

starting the RHR pump (IFl 50-271/97 21); the licensee failure to retain required battery records

(URI 50 271/97 22); and the possibility ofloss of both DC divisions with the use of the standby

battery charger (IFI 50-271/97 23).

20

-( 7 .. ~ m., _ - . - - . . - - - - - - - -

_

i

I

s- l

f El.3.3 -lastrumentation and Centrols (laCl i

i

El.3.3.1 Scope of Review

i The team reviewed applicable sections of FSAR Chapters 1, 3, 5, 6, 7, 8, and 9; TS; DBDs; vendor

i documents; piping and Instmment diagrams (P&lDs); logic diagrams; electrical wiring diagrams;

i control wiring diagrams; instrument installation drawings; calculations; ERs and EDCRs. In addition,

the team conducted interviews, and performed walkdowns of features associated with the RHR

system to ensure the ability of the system to meet FSAR commitments and TS limits. The review

included inspecting instrument installations, setpoints, and AC and DC control power provisions, as

l well as altemative shutdcwn and station blackout (SBO) provisions. The team paid particular

i attention to modifications performed by he licensee to verify continued adherence to design bases

j and licensing requirements. l

El.3.3.2 Eindings

l a Use of she Vernon Tle as an Alternate AC (AAC) Source for Station Blackeet

i .

! As a result oflessons learned from the Maine Yankee Independent Safety Assessment, the NRC

I

reviewed VY's use of a backfeed through the main transformer as a delayed access source of AC

i

power and inquired about the use of the Yemon tie as a second delsyed access source of AC power.

! As a result of this review, the NRC took exception to the use of the Vernon tie as an off' site source in

! response to loss-of power events and as an altemate AC (AAC) wurce of power for the purpose of

meeting SBO requirements. VY reviewed this matter (and documented its finding in BMO 97-03)

l and concluded that since the Vemon Tie was used to meet the requirements of a delayed access AC

source of power it could not be used as an AAC source of power. Additionally, the licensee found ,

that no analysis existed to demonstrate that the backfeed through the transformer could meet the

i_  : timing requirements of a delayed access AC source of power,  !

!

'

!

'

At the end of the inspection, VY committed to modify the backfeed to be an acceptable delayed

{ access source of AC power and intended to use the Vemon tie only as an AAC source of power. The  ;

! '

licensee also intended to submit FSAR changes by September 30,1997. Resolution of the use of the

'

Vemon tie for SBO considerations is identified as IFl 50 271/97 20124.

b. ECCS Initiation Sinnal Cabline and Wiring Senaration

]

Based on the team's walkdown of the ECCS initiation signal circuits, the team questioned the

.

adequacy of VY's electrical wiring separation criteria. The team was concerned with the cables from

. reactor pressure vessel (RPV) level transmitters LT 2 3 72A, B, C, and D in conduits laboled as Si

and SIIX, which were terminated in the same terminal box with no provisions for separating the t

) . wires. Likewise, cables from conduits labeled as Sil and SIX were terminated in another termhal

box.- According to the separation criteria, cables labeled SI, Sli, SIX and SIIX, were to be mutually

separated from each other. Additionally, the team observed that cables entering control room

1-

!

. _ , - . _ - -._ _ _ u.._ ., . _ _ _ _ - . _ _ _ ._- _ _ . - , . . . _ . . _ . _ _ _ _ . _ _ _

. .

cabinets 9 32 and 9 33 (ECCS auxiliary relaying cabinets) were bundled together inside the cabinet

up to the terminal blocks regardless of their division assignment,

h licensee consulted with GE, the original provider of the auxiliary relay cabinets, to detwmine if

GE had conducted an analysis of the observed condition. GE was able to direct the licensee's

attention to the NEDO document 10139. This document presented the results of a GE single failure

_ analysis, and concluded that no single failure associated with the commingling of the subject cables

and wires could result in the loss of safety Ibnction for both divisions.

The team also found that the control wiring associated with the breakers (3V4, 3V, and 4V) used to

power the safety related electrical buses from the Vernon tie breakws were not separated. Although-

the wiring to the 52a/b auxiliary contacts associated with the Vernon tie breakers could not be

inspected directly, the licensee informed the team that the wiring was not separated,

h licensee performed an analysis and concluded that no possible fault could interfere with the safety

functions of the breakers in question nor could the fault be transmitted to other safety systems. W

licensee also indicated that the condition had been previously analyzed with identical results; however

no record existed for the earlier analysis.

Although the licensee was eventually able to verify that the observed wiring configuration in the plant

was acceptable, the team noted that the VY separation criteria did not clearly define the acceptability

of wiring installations in common enclosures. In addition, no prograra requirement existed which

required the licensee to document the analyses of deviations from the separation criteria. Also, the

separation criteria did not denne all of the classification labels for cable and wiring, and the

application of the criteria to panel wiring was vague. The licensee concurred that VY needed to

upgrade the separation criteria to address exemptions from separation requirements. The licensee's

actions to improve their program requirements was identified as IFI 50 07137-201 25.

c. Instrument Uncertainty Calculation Meth:t':n

h team reviewed instrument uncertainty calculations for selected instrument loops for the RHR

system, including initiation and permissive signal loops and indication and recording loops. N team

noted that the calculations did not include any specific provisions to account for the instrument driA

effects on the performance of the instrumentationc In 1997, the licensee began issuing drin analysis

calculations for selected hardware lacking vendor driA data to address the lack of provisions for driA

in the instrument loop uncertainty analyses, The licensee agreed that VY should revise the

uncertainty calculations to reflect the allowance for drin factors. The licensee also indicated that the

development of procedures and schedules for this effort was underway. The licensee's schedule and

new program to address this effort are identified as IFI 50 27tM7-201 26.

22

. .

d. LPC1/RHR Systeam Mow Leon Uncertahtv  !

The team's review of Calculations VYC-453 and 479 revealed a significant uncertainty tolerance l

associated with the RHR/LPCI flow instrument. The large uncertainty tolerance stemmed from the

4.1 % and -5.6% of full instrument loop uncertainty associated with the flow loop. As a result, a

Sow rate of 3920 gpm was required (2700 gpm plus .061 *(20000 gpm)) to ensure that the LPCI

pumpe would have an adequate continuous minimum flow rate of 2700 spm. The licensee issued ER

97 0694 to address this concem. ER 97 0694 imposed a procedural limitation of 4000 gpm to ensure

RHR pump operation above the vendor recommended minimum flow value,

in addition, the team determined that the large uncertainty associated with the flow indication also

afects the upper end of LPCI operation. The RHR heat exchanger placed a constraint on the

. maximum continuous flow allowable through the heat exchanger at 7000 spm to avoid detrimental

efects of vibration on the heat exchanger. Therefore, flow through the LPCI should not exceed 5880

gpm (7000 gpm ,056*(20000 gpm) to avoid the flow range in which there would be concerns for

' heat exchanger vibration.

l

t

'

The licensee's resolution regarding the operation of the LPCI pumps to meet its minimum flow

requirement and to avoid passing excessive flow through the RHR heat exchanger is identified as

IFI 50 271/97 20127.

'

El.3.3.3 Conclusions

The team concluded that the design and installation of the 1&C aspects of the system were generally

acceptable. The team noted that VY needed to resolve the acceptability of the use of the backfeed

and the Vernon tie as delayed access and AAC sources of power (IFl 50 271/97 201 24). The team

also found that exceptions to the separation criteria were not well documented or recorded, and the

application of the separation criteria within panels was not well defined for both NSSS and BOP

installations (IFI 50 271/97 20125). Additionally, the team identified the licensee's resolution

regarding operation of the LPCI pumps to meet its minimum flow requirement and to avoid passing

excessive flow through the RHR heat exchanger as IFl 50 271/97 201 27. The team also concluded

that the instrument uncertainty calculation methodology used at VY needs to address the efects of

instrument drift (IFI 50 271/97 20126).

El.4 FSAR Review

El.4.1 Scone of Review ,

The team reviewed the appropriate FSAR sections for the LPCI and RHRSW systems, as well as

associated electrical and IAC sections of the FSAR to verify consistency between the FSAR

- descriptions and design documentation, ,

23

.- - _ - - - - - .- -. - ~ , ,-.

.,=o

El.4.2 Eindings

The team identined the following FSAR discrepancies:

FSAR Figures 4.81 and 6.4 3 (Rev.13) did not agree with drawing 5920 725 (Rev. 9). For

example, LPCI flows and RHR heat exchanger duty differ. The licensee initiated ER No.

97 0626 to address this discrepancy,

i

The text of FSAR Section 6.4 cited references (e.g., References 6.4.a,6.4.b, and 6.4.c) which

l were neither identified nor described in the FSAR. The licensee initiated ER No. 97 0580 to

correct this discrepancy.

FSAR section G.3, " Summary Description Core Standby Cooling Systems," indicated that the

low. pressure CSCS staned automatically following a reactor vessel low low water level signal J

and time delay or low pressure signal. This conflicted with the LPCI system operation and the

description ofinitiation signals as identified in FSAR Sections 6.5.2.5,7.4.3.5.2, and 7.4.3.5.4,

which stated that the LPCI system did not start on a low. pressure signal. These sections

' Indicated that LPCI initiated on three initiation signals, (1) RV low. low water level concurrent

with low reactor pressure, (2) primary containment (drywell) high pressure, (3) sustained RV

low. low water level. The licensee issued an event report to document this discrepancy.  !

The electrical power to the service water strainers and instrummiation was non safety.related.

FS AR Section 8.5 indicated that these strainers were safety related. The licensee issued an

event repon to document this issue and initiate an FSAR revision.

Et,4.3 Conclusions

The team identified several instances in which the licensee failed to update the FSAR to ensure that it

contained the latest information, as required by 10 CFR 50.71(c). Although individualitems were not

significant, collectively, they appeared to indicate a licensee weakness in updating the FS AR (URI 50

271/97 201 28),

El.5 Deslan Control

El.5,1 Scone of Review

The team reviewed engineering and design documents (drawings, calculations, specifications, etc.) for

both the LPCI and RHRSW systems as discussed in previous sections of this repon. During these

reviews, the team assessed the effectiveness of the licensee's design control process.

24

.

. e a

El.5.2 liadingt

N team identi6ed several design document discrepancies and inconsistencies, as follows:

The RHR system Ametional control diagram (Drawing No. 5920 27, Rev.15) incorrectly stated

in Note 6 that the motive power for the RHR system injection valves in both loops shall

originate kom a common bus, which was automatically connectable to two alternate emergency

bus sources. LPCI system component power supplies were modined in EDCR 73 31, but the

licensee had not modified note 6 to reflect these modifications. W licensee initiated ER No.

97 0601 to correct this discrepancy.

• Relief valves RV 10-210A, and B were provided to relieve pressure kom the bonnets of the

normally open RHR injection valves V10 25A, and B to prevent valve pressure locking. b

setpoint of the relief valves was changed firom 1050 psig to 1150 psig by Work Order 76-0920,

dated July 7,1976; however, the licensee never updated the related design documentation,

including the RHR system P&lD (Drawing No. G 191172), the valve drawings (Drawing Nos.

5920 2615 and $920-11934), and FSAR Figures 4.8 2 and 7.4 6 (RHR system P&lD) to

incorporate the setpoint change. The inservice test (IST) database was also in error since it

extracted reliefvalve information Rom the P&ID. W licensee identified this discrepancy in

preparation for this design inspection, as documented in ER No. 97 0569.

• Drawing No. 5920 FS 1495 depicts flood protection modifications made to the RHR corner

rooms. This drawing indicated that a check valve was to be installed in the comer room sump

pump discharge piping; however, the radwaste system flow diagram (Drawing No. G 191177,

Sheet 1) did not show this check valve, and Operations verified that the check valve was not  :

installed. The licensee initiated ER No. 97-0661 to address this discrepancy.

• In response to a condition identified by the licensee (and reported to the NRC in March 1997),

' the licensee revised the RHR system operating procedure, OP 2124, to disallow the use of the

condensate transfer system as an alternate RHR system keep fill method; however, the

procedure revision was incomplete. Item 15 in the Precautions section of OP 2124, Rev. 42,

still refers to the use of the condensate transfer system for RHR system keep-All. The licensee .

initiated a procedure change form (in accordance with AP0037) to correct this discrepancy. t

• Engineering Instruction WE-103," Engineering Calculations and Analyses," Rey,15, dated ,

October 14,1994, section 4.1.4.2, stated that, when information fkom QA design records was

required, the licensee must ensure that the appropriate (governing) documents were used and .

'

that such documents were the latest approved revision obtained from the appropriate source.

Calculation VYC 1349, Rev. I, issued on April 30,1997, referenced drawing G 191372, sh.1,

Rev. 41. However, engineering had approved Rev. 42 of the drawing G 191372 on December

20,1996. The author of the calculation used a drawing from the aperture card file not knowing '

that the aperture cards were uncontrolled documents (for information only) and were not

25

- . _ _ _ . _ _ _ . . _ . _ . _ _ _.._.___

. ,, .

frequently updated. Also, there was no sign posted on the aperture card file to that eft'ect.

These practices appear to conflict with Engineering Instruction WE.103. The licensee has

issued an ER 97 0588 to address this concern.

• Calculation VYC.298, Rev.10, issued on April 22,1997, referenced various drawings as listed

in Section 3.0.5 (a) through (1), which were superseded by a later revision before the licensee

issued Calculation VYC.298, Rev.10. Review of the latest revisions of the drawings indicated

- some de load changes. The licensee has verified that there were no operability concems and

that the battery has adequate margin to support the load change. Again, these practices appear

to conflict with Engineering Instruction WE.103. The licensee has issued ER 97 0665 to

identify this concem.

• Calculation VYC 811,"125 Vdc System Short Circuit Current Study," Rev. 2, evaluated

equipment capability during short circuit conditions. It provided review of 125.Vdc circuit

breakers to detemnine if they were sized properly, to interrupt the maximum calculated short

circuit current. It failed to include short circuit contributions from the MOV loads listed in

calculation VYC 1296. The licensee's preliminary review of expected short circuit current

contributions attributable to MOVs showed that total system short circuit current will increase,

but will remain within the short circuit rating of the de buses and breakers.

El.5.3 Conclusions

The team identified several design document discrepancies and inconsistencies. Individually, they

were not significant to safety and did not constitute operabilhy concems; however, collectively, they

indicated a weaknesses in the design control process. The licensee will address these deficiencies in

their Configuration Management Improvement Project (CMIP) and improve the calculation and

- drawing processes. The team identified this issue as URI 50 271/97 29,

26

. .. .

APPENDIX A

LIST OF OPEN ITEMS

This report categorizes inspection findings :s unresolved items (URIs) and inspection followup items

(IFis) in accordance with Chapter 610 of the "NRC Inspection Manual." A URI is a matter about

which the Commission requires more information to detwmine whether the issue in question is

acceptable or constitutes a deviation, nonconformance, or violation. The NRC may issue

enforcement action result!ng firom its review of the identified URIs. By contrast, an IFI is a matter

that requires fbrther inspection because of a potential problem, because specific licensee or NRC

action is pending, or becaase additional information is needed that was not available at the time of the

inspection.

hem Number Finding Title /R= lated Relation

hPt

50-271M7 201-01 URI Suppression Pool Water Temperature - Past Operation

Outside Design Bases (El.l.2.2.a)

50 271M7 20102 URI Untimely Actions to Resolve Suppression Pool Water

Temperature Issue 10 CFR Part 50, Appendix B,

Criterion XVI, Conective Action (El.1.2.2.a)

50 271/97 201-03 URI Failure to Issue an LER - 10 CFR 50.73(a)(2)(ii)(B)

(El . l .2.2.a)

50 271/97 201-04 IFI Clarification of RHR Pump NPSH Margins and Correction -

of Calculation Errors (El.l.2.2.b)

50-271M7 201-05 URI Non-Conservative LPCI Flow Values Used in LOCA

Analyses 10 CFR Part 50, Appendix B, Criterion III,

" Design Control" (El.l.2.2.c)

50 271M7-201-06 URI Insufficient Technical Basis as Requested by IEB 88-04 for

Existing Minimum Flow,(El 1.2.2.d)

50 271M7 201-07 URI Change to LPCI Mode of RHR Operation As Described in

FSAR (El,1.2.2.d)

50 2716 7 201-08 URI Inappropriate Operating Instructions Regarding RHR Pump

Motor Starts,10 CFR Part 50, Appendix B, Criterion III,

"D; sign Control" (E1.1.2.2.e)

Al

. ., ..

)

50 271/97 201-09 URI FSAR Not Updated to Incorporate Reduced RHR Heat

Exchanger Capacity 10 CFR 50.7)(e)(El.l.2.2.f)

50 271/97 201 10 URI Entry into TS LCO Conditions when Equipment is  !

Rendered Inoperable TS 3.5.A.2 and TS 3.5.A.3 i

(El.l.2.2 3)  ;

50 271/97 201 11 URI Timeliness to Followup Self assessment of TS Surveillance l

Requirements (E1.1.2.2 3)

50 271/97 201 12 URI Measurement Inacaracies Regarding Room Coolers

(RRU) 7 and 8 10 CFR 50, Appendix B, Criterion XI,

" Test Control"(El.2.2.2.a)

50 271/97 201-13 URI Incorrect Auumption in the Calculation Methodology for

RRU 7 and 8,10 CFR Part 50 Appendix B, Criterion III,

" Design Control" (E1.2.2.2.b)

50-271/97 201 14 URI Downgrading RRUs 5 and 6 Without a Safety Evaluation,

10 CFR 50.59," Changes, Tests, and Experiments"

(El.2.2.2.c)

50 271/97 201 15 IFI Deleting RRUs 5 and 6 from the GL 8913 Program GL

8913 Commitment (El.2.2.2.e)

50-271/97 201-16 URI Analysis of RHR Heat Exchanger using Tests

Measurements Collected and Recorded with Inaccurate or

Uncalibrated Instruments,10 CFR Part 50, Appendix 3,

Criterion XII, " Control ofMeasuring and Test Equipment"

_ (El.2.2.2.f)

50-271/97 201 17 URI Failure to Inspect RHR Heat Exchanger IB - GL 89-13

Commitment (El.2.2.2 3)

50 271/97-201-18 URI Common-Mode FailurestNon Safety Regulators Affecting

Safety Related Diesel Generators,10 CFR Part 50.

Appendix B, Criterion III, " Design Control" (El .2.2.2.h)

50-271/97 201-19 URI Failure to Take Prompt Corrective Action to Revise TS

Discrepancy (El.2.2.2j)

50-271/97-201-20 URI Use of PRA to Address Tornado Missiles (El.2.2.2.k)

50-271/97 201-21 IFI Vernon 69.KV Switchyard Low Voltage (El.3.3.2.a)

A2

- - " -

O eg n

50 271/97 201 22 URI Main Station Battery Service Test .10 CFR Part 50,

Appendix B, Criterion XVII, "QA Records" (El.3.3.2.b)

50 271/97 201 23 IFI Standby Battery Charger CAB Single Failure (El.3.3.2.c)

50-271/97 201 24 IFI Use of Offsite Vernon Tie as Station Blackot.t AAC Power

Source and as Offsite Delayed Access Source of Power

(El .3.3.2.a)

50-271/97 201 25 IFI Upgrade of Cable Separation Criteria (El.).3.2.b)

50-271/97 201 26 IFI Lack of Provisions for Instrument DriA in Instrurnent

Uncertainty Calculation Methodology (El.3.3.3.d)

50 271/97 201 27 URI Excessively liigh Uncertainty for RIIR Flow Indication and

Recording Loop (El.3.3.3.e)

50-271/97 201 28 URI FSAR Deficiencies and Errors (El.4.3)

50-271/97-201 29 URI Design Control Weakness (El.5.3)

A3

o .. .

APPENDIX B

EXIT MEETING ATTENDEES

NAME ORGANIZATION

Ross Barkhurst President,CEO VY

Jim Callaghan Manager,MechanicalEngineering YAEC

Jim Chapman D* rector, Nuclear Engineering YAEC

Russell Clark Acting VP YAEC

William Cook Sr.ResidentInspector NRC

Don Davis CEO YAEC

Robert Gallo Branch Chief, NRR/ DISP NRC

'

Frank IIelin Superintendent, Technical Services VY

Kahtan Jabbour Project Manager, NRR NRC

-Richard January Manager,1&C Engineering YAEC

Andrew Kadak President YAEC

Edward Knutson ResidentInspector NRC

Edgar Lindamood Manager, Division of Engineering - VY

David McElwee Licensing Engineer, Safety and Regulatory Affairs - VY

David Mannal Manager, Reactor Engineering VY

Greg Maret Plant Manager - VY

Stan Miller DesignEngineering VY/YAEC

Mark Mills Manager, Fluids Systems, YAEC

Don Norkin Section Chief, NRR/ DISP NRC

Don Reed Sr. Vice President VY

William H. Ruland Branch Chief, DRS/ Region I NRC

Bill Sherman Nuclear Engineer Dept, of Public Service (Ve:mont)

Tom Schimelpfenig Manager,FinancialPlanning VY

Stephen Schultz Vice President YAEC

Robert Sojka Manger, Licensing - VY

Robert Wanczyk Director, Safety and Regulatory Affairs - VY

Jim Wiggins Director,DRS/RegionI NRC

Don Yasi Manager, Nuclear Services YAEC

Note: Individuals listed above attended the team exit at Bolton, Ma, on June 13,1997 and/or

attended the public exit on July 1,1997 at Brattleboro, Vt,

B-1

- - . - - . -

__ _ - _ _. _ . _ _ . _ _ _ . _ . . _ - ._ _ . . . ._ _ _ _ - _ __._ _. _ _ . __ _

g ,,

APPENDIX C

LIST OF ACRONYMS

Abbreviation Mcamne

AAC Alternate AC

AC Ahernatmg Cwrent

ACS Altemate Coolmg System

ADS Automatic Depressuruation System

All Ampere Iker

Bl!P Hest IEciency Pomt

BMO Basis for Mamtamms Operation

Htu Bntinh Thermal Umt

HWROO Hoihng Water Reactcv Owners (koup

CFR Code of Federal Regulatums

CMIP Configuratuvi Management improvement Program

CRD Control Rod Dnve

CS C(ve Spray

CSCS Core Standby Coohng Systems

CWD Control Winns Diagram

D13A Design lianis Accident

Dl3D Design 13 amis Document

D1 Department Instruction

TiCCS limergency C(se Coolms System

TDCR lingmeenns Design Change Request

EDO limergency Diemel Generator

liDSFl Electncal Distnbution System Functional inspection

lik livent Report

ERFis Emergency Responne F acility Instrumentation System

FSAR Fmal Safety Analysis Report

Oli General Electnc Co

~

GL Genene letter

gpm gallons per mmute

IIPCI thsh Pressure Coolant injection

hr hour

^

1&C Instrumentation and Control

ICV Indmdual Cell Voltage

IFl inspecuon Followup liem

IP inspection Plan (or inspection Pncedure)

MiEE Indmdual Plant Extemal Event Exammation

ik inspection Report

IST innervice Test

ITS Improved Techmcal Specifications

LV kilovolts

LCO Limitmg Condition for Operaticu

LNP las of Normal Power

LOCA lone-of-Coolant Accident

LOOP lens of offsite Power

LPCI low Pressure Coolant injection

MCC Motor Control Center

MOPD Maximum Operating Pressure Diflerential

MOV Motor Opert:?od Va ve

, C1

'

--,y-gy e-----r r+ - ' + - -t+ -- - - -

a <a o

NEMA National 1:lectnesl Manufacturers Anuciation

NNS Non Nuclear Safety

NPhli Net Pontive Suction llend

NRC US Nuclear Regulat<wy Commission

Nkk Nuclear Regulatcrv Regulation, Office of(NRC)

NsSS Nuclear Steam Supply System

Ol :R Operating 1.xpeneme Renew

OS11 Operational Safety leam inspection

l' AID Pipmg and instrumentation ihagram

PAC Potential Advme Condition

!'DCR Plant I)esign Change Request i

l PORC Plant Operational Review Ctwnmittee l

psid Pounds per aqure toch differential

psig Pounds per aqure inch gage

QA Quality Aavurance

RCIC Reactor Core laolation Cooling

NO Regulat<wy Guide

RilR Residualllest Hernoval

RilRSW Residuct llent Removal Smace Water

RPV React <r Pressure Veasel

RRU Roorn Coolers

SitO Station lilacLout

SitPl Sulier 13tngham Pumps Inc.

SO Standing Order

SRV Safety Relief Valve

SSC System Structure or C(nnponent

SSF) Salety System Functional inspection

SSFP Standby Spent Fuel Pool

SWiiC Stone & Webster lingincenng Corpoiation

SWOPl Semce Water Operational Performance inspection

SWS Semce Water system

1S lechmcal Specfication(s)

UPS Umnterruptable Power Supply

URI Unresolved item

VY Vermoni Yankee Nuclear Pouer Station

VYNPC Vennont Yankee Noelear Power Ocwinration

YAliC

_ _ _

Yankee Atomic Energy Corportation

C2