Text

Insp Rept 50-397/98-15 on 980713-31.Violations Noted.Major Areas Inspected:Review of Design & Licensing Basis for High Pressure Core Spray Sys & Associated Support Sys & Review of Fire Protection Program
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Site:	Columbia
Issue date:	11/06/1998
From:	; NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION IV)
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ENCLOSURE 2

U.S. NUCLEAR REGULATORY COMMISSION

REGION IV

Docket No.:

License No.:

Report No.:

Licensee:

Facility:

Location:

Dates:

Team Leader:

Inspectors:

50-397

NPF-21

50-397/98-15

Washington Public Power Supply System

Washington Nuclear Project-2

Richland, Washington

.July 13-31, 1998

Linda Joy Smith

Reactor Inspector, Engineering Branch

Division of Reactor Safety

David Pereira

Reactor Inspector, Engineering Branch

Division of Reactor Safety

Edmund Kleeh

Operations Engineer, Inspections Program Branch

Office of Nuclear Reactor Regulation

Bob Quirk

Consultant

Approved By:

Craig Baron

Consultant

Thomas F. Stetka, Acting Chief

Engineering Branch

Division of Reactor Safety

Attachment:

Supplemental Information

9'Siii603i8 98ii06

PDR

ADOCK 05000397

6

PDR

i

EXECUTIVE SUMMARY

Washington Nuclear Project-2

NRC Inspection Report 50-397/98-15

During the weeks of July 13 and July 27, 1998, the NRC conducted the onsite portion of an

engineering team inspection.

The team inspection included a review of the design and

licensing basis for the high pressure core spray system and associated

support systems and a

review of the fire protection program.

The team found that the design and testing of the high pressure core spray system was

generally consistent with applicable licensing, design, and operations documents

(Section E1).

The high pressure core spray pump had adequate available net positive suction head.

The team found that the high pressure core spray system valves were capable of

performing their functions under accident conditions (Sections E1.1.1 and E2.2).

Design control errors were identified that did not affect equipment operability. The

Mode 4 and 5 technical specification surveillance requirement acceptance

criterion for

condensate

storage tank level did not assure the Technical Specification Bases

commitment to maintain 135,000 gallons reserve in the condensate

storage tank. The

technical specification allowable value for reactor vessel water Level 1 ir. the emergency

core cooling system instrumentation table was not correctly derived from the analytic

limitfor Level 1 in that it did not include sufficient margin for post-accident environmental

effects. These errors were determined to be examples of a violation of 10 CFR Part 50,

Appendix B, Criterion III, "Design Control," (Sections E1.1.1 and E1.2).

The licensee had developed a data base that captured the relationship between

calculations, so that they could identify needed calculation revisions. When a

calculation was revised, the data base was used to identify all of the other calculations

that were potentially impacted by the revision. This data base relied on calculation cross

references;

however, these cross references were not always accurate or complete for

older calculations (Sections E1.1.1, E1.3.1 and E8.5).

Based on a sample of six modification packages,

recent design modification packages

were correctly prepared in accordance with the current procedures.

The plant

modification requests addressed

all relevant design and safety issues and effectively

verified the design changes by post-modification testing.

Thc, current format for a

'odification package was clear and easy to understand (Sections E1.1.2, E1.3.2, and

F2).

~

In violation of 10 CFR Part 50, Appendix B, Criterion V, "Instructions, Procedures,

and

Drawings," procedures were not always adequately followed or prescribed.

Category

1 post-accident monitoririg instruments; all other demarcation lines were to be

black. The team noted that HFES-10 did not'include a requirement for marking

Category 2 post-accident monitoring instruments.

The licensee initiated Problem Evaluation Report 298-0898 to address this discrepancy.

Based on a review of photo logs of the control room, the licensee determined that they

were in compliance with the license condition for both Category

1 and 2 post-accident

monitoring instruments, as required, prior to startup following the first refueling outage.

The licensee stated that identification of the neutron flux recorder as a post-accident

monitor, Category 1, parameter was probably lost when the recorders were replaced,

but th'e indications were still qualified Class 1E devices.

The licensee stated that the

primary containment isolation valve status panel was removed either during construction

or early after licensing because

of design deficiencies and was replaced with position

lights above each of the associated switches in various locations around the control

room. While these indicators were not 'marked as post-accident monitors, the

indications were still qualified Class 1E. They speculated that the remaining markings

were likely removed and not reinstalled, when the control room was painted.

10 CFR Part 50, Appendix B, Criterion V, "Instructions, Procedures,

and Drawings,"

states, in part, "Activities affecting quality shall be prescribed by documented

instructions, procedures, or drawings of a type appropriate to the circumstances

and

shall be accomplished

in accordance with these instructions." The failure to accomplish

control panel marking for Category

1 instruments in accordance with HFES-10 and the

failure to prep-.rly prescribe marking requirements for Category 2 post-accident

monitoring instruments in instructions, procedures, and drawings is an example of a

violation of 10 CFR Part 50, Appendix B, Criterion V (50-397/9815-02).

Interviews with licensed control room operators, several design engineers, and system

engineers resulted in the observation that, in general, personnel were not aware of the .

Regulatory Guide 1.97 license condition and related commitment to identify

post-accident monitor Category

1 and 2 devices.

However, the licensee noted that

operators received extensive training on the more general topic of which instruments

could be relied upon post accident.

Setpoint Program

At original licensing, the licensee committed to determine instrument errors based on

test and experience.

During the early 1990s, the licensee stated they had subsequently

conducted a large setpoint uncertainty calculation program.

This program was

-7-

described in Procedure EES-4 "Setpoint Methodology" and was based on ISA-67.04,

"Methodology for the Determination of Setpoints for Nuclear Safety Related

Instrumentation."

The results of this program were used as a basis for the improved

technical specification submittal.

The licensee submitted their improved technical specifications in 1995. Technical Specification Bases, Sections B 3.3.1.1, "Reactor Protection System (RPS)

Instrumentation," and B 3.3.5.1, "Emergency Core Cooling System (ECCS)

Instrumentation," in the improved technical specifications both state that the technical

specification allowable values were derived from the analytic limits, corrected for

process and all instrument uncertainties, except drift and calibration. The trip setpoints

included in the licensee controlled specification manual are derived from the analytic

limits, corrected for process and all instrument uncertainties, including drift and

calibration.

Elevation Uncertainty

The team questioned the licensee regarding the need for inclusion of an uncertainty

term in the reactor vessel level setpoint calculations to provide an allowance for

construction elevation uncertainty.

The licensee reviewed vendor supplied

documentation related to reactor vessel fabrication and found that the dimensions for

the as-built configuration of the vessel level taps had been measured (post-fabrication)

to within + 1/32 of the designed vessel level tap locations.

The licensee also reviewed

vendor documentation related to the development of analytical limits and found that the

analytical limits included the measured as-built elevation uncertainties.

Therefore, it was

not necessary to include an additional allowance for construction elevation uncertainty in

the reactor vessel level setpoint calculations.

Environmental Effects

The team found that Calculation E/l-02-91-1051, "Setting Range Determination for

MS-LIS-31A, -31B, -31C, -31D, -37A, -37B, -37C, and -37D," Revision 0, contained the

assumption that, although the instruments were 'ocated inside a harsh e;.,:'ronment, the

uncertainties associated

with the harsh environment were not required to be included in

the analysis.

The team questioned the validity of this assumption because

reactor

vessel Level 2 signals generated by Level Indicating Switches MS-LIS-31A, -B, -C & -D

were used for long-term HPCS level control.

The licensee initiated Problem Evaluation Report 298-0900 to address this issue and

determined that MS-LIS-31 A, -31 B, -31C, and -31D remained operable.

The licensee

found that there was enough existing margin between the technical specification

allowable value for HPCS actuation at Level 2 and the analytical limitfor Level 2 to

.

accommodate the larger harsh environment uncertainties.

Because the technical

specification allowable value remained correct and the more limiting setpoints in the

plant calibration procedure continued to ensure that the allowable value of the technical

specifications would not be exceeded,

the team concluded that the calculation e'rror had

not adversely impacted the HPCS control system design.

-8-

The team requested that the licensee verify that this problem did not affect the other

reactor vessel instruments.

The licensee identified that Switch

1 on Switches

MS-LIS-37A, -37B, -37C, and -37D could potentially be affected by the same error. This

switch was used for initiation of the automatic depressurization

system (ADS), LPCS,

and low pressure coolant injection (LPCI) at reactor vessel water Level 1 (consistent

with Technical Specification Table 3.3.5.1-1, "Emergency Core Cooling System

Instrumentation," Items 1.a, 2.a, 4.a, and 5.a).

For the purposes of promptly evaluating operability, the licensee assumed that all of

these switches were required to operate post-accident.

The licensee noted that for the

Level 1 switches, the additional uncertainty introduced because

of harsh environmental

effects could not be accommodated

between the existing technical specification

allowable value and the analytic limit. The licensee determined that a revision to the

technical specification allowable value for Level 1 from -148-inches reactor vessel water

level to -142.3-inches reactor vessel water level would be required, if these switches

were required to operate post-accident.

The most recent calibration settings were

sufficiently conservative to assure the Level 1 trip would occur at a reactor water vessel

level above -142.3-inches reactor vessel water level; therefore, the level switches were

operable.

The team determined that the licensee did an effective extent of condition

review.

The licensee planned additional research to determine if all the Level 1

switches were required to operate post-accident.

Subsequent

to the conclusion of the onsite inspection, the team requested a copy of the

environmental qualification report for Switches

MS-LIS-37A, -37B, -37C, and -37D,

used for initiation of ADS, LPCS, and LPCI at reactor vessel water Level 1. The

licensee provided documentation that stated these switches were required to be able to

change state for 4,320 hours0.0037 days 0.0889 hours 5.291005e-4 weeks 1.2176e-4 months , while subjected to harsh environment conditions.

On this

basis, the team concluded the switches were required to operate post-accident and that

the current technical specification allowable values were incorrect in that a more

conservative value was needed to adequately include post-accident harsh environment

uncertainties and assure that the associated

analytical limitwas met.

10 CFR Part 50, Appendix B, Criterion III, "Design Control," states, in part, "Measures

shall be established to assure that applicable regulatory requirements and the design

basis, as defined in g 50.2 and as specified in the license application...

are correctly

translated into specifications, drawings, procedures, and instructions." The failure to

correctly translate the Technical Specification Bases commitment to derive the allowable

values from the analytic limitcorrected for process and all instrument uncertainties

except drift and calibration into the technical specification for Reactor Vessel Water Low

I ow Low - Level 1 is a an example of a violation of 10 CFR Part 50, Appendix B,

Criterion III (50-397/9815-01).

Conclusions

The installed instrumentation and controls met HPCS system logic requirements.

The

majority of the HPCS controls and instrumentation were installed in conformance with

good human factors practices, and the licensee routinely trained the operators regarding

the availability and use of particular instruments during accidents.

However, the licensee

did not meet Regulatory Guide 1.97, "Instrumentation for Light-Water-Cooled Nuclear

-9-

Power Plants To'Assess

Plant Environs Conditions During and Following an Accident,"

guidance to specifically identify to operators instruments intended for use under accident

conditions.

Control panel marking was not always accomplished

in accordance

with

Human Factors Engineering Standard (HFES) -10, "Demarcation Standard,"

Revision 0,

Section 3.1, which required the use of 0.25-inch wide red demarcation lines to identify

and enhance the visibilityof Category

1 post-accident monitoring instruments.

In

addition, marking requirements were not prescribed in documented instructions for

Category 2 post-accident monitoring instruments.

The failure to follow procedures and

the failure to prescribe adequate procedures were determined to be examples of a

violation of 10 CFR Part 50, Appendix B, Criterion V, "Instructions, Procedures,

and

Drawings."

In general, HPCS setpoint analyses were acceptably developed based on ISA-67.04,

"Methodology for the Determination of Setpoints for Nuclear Safety Related

Instrumentation."

However, the team identified a failure to include harsh environment

effects on the reactor vessel Level 2 switch. In this case, there was adequate margin

between the analytical limitand the existing technical specification allowable values to

accommodate

the error. The licensee identified a similar issue with the reactor

vessel'evel

1 switches that willlikely require a technical specification revision. The failure to

adequately include post-accident harsh environment uncertainties in the technical

specification allowable value for reactor vessel water Level 1 was an example of a

violation of 10 CFR Part 50, Appendix B, Criterion III, "Design Control."

E1.3

HPCS Electrical S stem Desi

n

E1.3.1

HPCS Electrical Design Capability

The team reviewed calculations to evaluate the basis for the derated ampacity assigned

to both alternating current (ac) and direct current (dc) HPCS power cables and the

selection and coordination of various protective devices.

The team reviewed calculations

to evaluate the capability of HPCS system components to withstand the maximum

available short-circuit currents in the ac and dc distribution-systems.

The team reviewed

procedures and calculations to confirm that the Division 3 Diesel Generator trips were

functional, especially those not bypassed,

and to check that the generator would not

exceed its nameplate power ratings during the initiation and operation of the HPCS

system.

The team reviewed calculations to confirm adequate minimum expected ac and

dc voltages.

The team also reviewed the cable routing and heat trace design for the

HPCS.system.

Observations and Findin s

Ampacity of AC and DC Power Cables

The team found that all power cables were conservatively derated, assuming worst case

loading in trays and conduits, for environmental conditions that can cause higher

operating cable temperatures.

Calculation 02.06.20 determined a cable's ampacity by

-10-

the calculated-cable-depth

method used in National Electric Manufacturers Association

Publication WC51-1975, "Ampacities Cables in Open-top Cable Trays" This method

assumed

uniform heat production per cable tray area and then determined a given

cable's ampacity based on the calculated depth of all cables in the tray. The licensee

conservatively applied the above formula and then applied derating factors for

temperature

in a specific area; covers on trays; fire barriers; trays covered with Thermo-

Lag; etc.

For conduits, the free air ampacity was derated for the number of cables in a

conduit and the number of conduits in proximity to one another in an array during routing

with the largest array in a given route being most limiting. The derating factors used

were the latest conservative values proposed by industry. After taking this approach, the

allowable ampacities of some cables were less than their required full load currents. The

above formula for calculated cable depth in tray was then adjusted to take into account

the intermittently loaded cables and spare cables in a given tray. This meant heat

production in a given tray dropped, but the allowable heat tolerance of a given cable

would rise permitting higher ampacities for the problem cables.

4 kV Over Current Protection

The team found that the over current protection for the 4 kV supply to the HPCS system

equipment was properly coordinated.

When the respective time overcorrect curves for

the normal feed to 4 kV Switchgear SM-4, the HPCS pump, and the 4 kV feeder to

Motor Control Center MC-4A, respectively, were plotted on the same log-log paper, it

was evident that coordination was achieved for all fault current values including the

starting current of the HPCS pump and the inrush current of the transformer supplying

Motor Control Center MC-4A.

480 Volt Over Current Protection

The team initiallynoted that the over current relay on the feeder from 4 kV Bus SM-4 to

480 volt Motor Control Center MC-4Adid not appear to coordinate with the 100 ampere

breaker on Motor Control Center MC-4A that supplied the Division 3 Diesel Generator

auxiliary ac panel.

In 1985, the licensee issued Field Change Request 85-9528-0-01 to

revise the setting of the over current relay, but at the time of the inspection had not

implemented these changes

in the field. The team was initiallyconcerned that a 1985

field change had not been implemented.

However, the team performed a further

evaluation and independently calculated the actual currents for the ac loads.

Even

though there was some slight overlapping of the time-current curves for the respective

protective devices involved, the overlap occurred at fault current values that were not

expected to occur. The team noted that only three phase fault currents were relevant,

because the 480-volt system was high resistance grounded.

The team determined that

the licensee had acceptably prioritized implementation of this field change based on

available fault currents.

AC & DC System Fault Analysis

The team found that electrical buses and components associated

with the HPCS system

had been properly sized to withstand the calculated fault currents.

Calculations

E/1-02-92-13, "Short Circuit Current Calculation for 480 V Systems, " Revision 0, dated

-11-

December 22, 1994, and Calculations E/1-02-92-09, "Short Circuit Current Calculation for

4.16 and 6.9 kV Buses," Revision 0, dated June 8, 1992, demonstrated

that the electrical

buses and components were capable of withstanding the maximum available short-circuit

current.

The team reviewed Calculation E/l-02-91-06, "Short Circuit Calculation for the

250 V, 125 V, and 24 V dc Systems," Revision 0, dated March 26, 1993, and determined

that all HPCS dc distribution system components had sufficient short-circuit withstand

capability to endure the low magnitude fault that was calculated to be available in the dc

system.

However, the team noted that all three calculations included incorrect design

assumptions for conductor temperature.

The licensee assumed

a conductor temperature

of 50'entigrade to calculate the cable resistances

in the dc system and 75'- Centigrade

to calculate the cable resistances

in the ac system.

These assumptions were not

conservative, because actual room temperatures

can go as low as 40'entigrade.

A

lower temperature decreases

resistance,

resulting in increased fault current. As

discussed

in the previous subsection,

in some cases breaker coordination and circuit

protection were acceptable based in part on the expected fault currents.

These cases

willneed to be reverified after the fault currents are recalculated.

The licensee agreed and included this concern in Problem Evaluation Report 298-0963.

10 CFR Part 50, Appendix B, Criterion V, "Instructions, Procedures,

and Drawings,"

states, in part, "Activities affecting quality shall be prescribed by documented instructions,

procedures, or drawings, of a type appropriate to the circumstances and shall be

accomplished

in accordance with these instructions." Step 3.1.14 of Engineering

Instruction El 2.15, "Preparation, Verification and Approval of Calculations," effective

July 1 through August 9, 1991, and Step 4.1.15 of Engineering Department

Procedure EDP 2.15, "Preparation, Verification and Approval of Calculations,"

Revision 0, effective August 10, 1991, through March 1996 required that calculations be

verified by ensuring that all aspects are technically correct, complete, and accurate.

The

failure to adequately verify the conductor temperature input assumptions for Calculations

E/l-02-91-06, E/l-02-92-13, and E/1-02-92-09 resulted in an indeterminate conclusion

regarding the adequacy of the selected electrical protective equipment.

This failure is an

example of a violation of 10 CFR Part 50, Appendix B, Criterion V (50-397/9815-02).

'I

Coordination of Protective Devices in the DC System

The team determined that there was lack of coordination between the Division 3, battery

125-ampere output breaker, and the 20- and 70-ampere molded-case breakers located

at Distribution Panel E-DP-S1/HPCS.

The calculated fault current at the load-side

terminals of any breaker in Distribution Panel E-DP-S1/HPCS was 2020 amperes, which

would cause the battery output breaker and the respective molded-case breaker to open

simultaneously.

The team found that the licensee had previously identified the lack of coordination

between the Division 3 battery main breaker and the feeder breakers in Distribution

Panel E-DP-S1/HPCS in September 1992 and had documented the design deficiency on

Problem Evaluation Report 292-0409.

The responsibility for rectifying this design

-I2-

.

deficiency has been transferred among a variety of documents, but the latest one was

Technical Evaluation Request 97-0130-0 initiated in June 1998, which had not been

resolved.

The team found that the licensee had not promptly corrected this design

deficiency, in part, based on the fact that the HPCS system was not designed to be

single failure proof. The licensee had reasoned that for many loads on the distribution

panel, the loss of the load itself would cause loss of the HPCS system and; therefore, the

breaker coordination issue was moot.

However, the team identified that the lack of coordination was a design deficiency that

should be addressed,

because proper application of the single failure criterion required

that failures resulting from design deficiencies be pre-assumed.

Some loads on the

distribution panel were not required to operate the HPCS system, but a fault at the

load-side terminals of the supply breakers for these loads would still prevent operation of

the HPCS system.

For example, the Division 3 Diesel Generator lube oil Pump

DLO-P-10 was supplied from Distribution Panel E-DP-S1/HPCS and was not essential to

operation of the HPCS system.

The lube oil pump was only required for long-range

maintenance and reliabilityof the Division 3 Diesel Generator.

With the current design, a

fault at the load-side terminals of the supply breaker for lube oil pump DLO-P-10 could

cause the battery output breaker to trip, which would unnecessarily prevent the operation

of the HPCS system.

The team reviewed the licensee's commitments to provide proper breaker coordination.

The team found that in FSAR, Section 8.3.2.1.2.2, the licensee had committed to design

the 125-volt dc system in accordance with applicable clauses of IEEE Standard

308-1974.

IEEE Standard 308-1974, Section 5.3.1 (6), "[Direct-Current Systems,

General] Protective Devices states that, "Protective devices shall be provided to limit the

degradation of the Class 1E power systems."

The team determined that the current

protective device design for 125-V dc Distribution Panel E-DP-S1/HPCS did not

adequately limitdegradation of the HPCS Class 1E Power system when a fault occurred

at the load side breakers that supply non-critical loads.

10 CFR Part 50, Appendix B, Criterion XVI,"Corrective Action," states that measures

shall be established to assure that conditions adverse to quality such as deficiencies are

promptly corrected.

The failure to promptly correct the dc breaker coordination

deficiency is a violation of 10 CFR Part 50, Appendix B, Criterion XVI (50-397/9815-03).

The licensee agreed and issued Problem Evaluation Report 298-0961

~ This problem

evaluation report included plans to correct the design deficiency during Refueling

Outage R-14 and to evaluate methods of prioritizing and resolving documented design

deficiencies to ensure timely resolution of open issues.

The team determined that this inspection report adequately describes the reasons for the

violation, and the actions taken to correct and prevent recurrence of the violation.

Therefore, the licensee is not required to respond to this violation.

-13-

Protection of Penetration Feedthroughs

The team found that the HPCS system penetration feedthroughs were adequately

protected from damage caused by over current. There are only two circuits that

penetrate containment for the HPCS system, and they are for position indication for

testable check Valve V-5 and for manually operated Valve V-51. Both valve indication

circuits have two over current devices to protect their feedthroughs from high fault

currents.

The indication circuit for Valve V-5 was disconnected,

but the calculation

showed that both valve indication circuits had their penetration feedthroughs adequately

protected by two protective devices in series.

If one device fails to open,

then the other

one will respond to open the circuit path to the feedthroughs.

HPCS Diesel Generator Capability

The team reviewed Calculation E/I-02-91-03, "Div.1, Div.2, and Div.3 Diesel Generator

Loading Calculation," Revision 6, and determined that peak accident loading of the

Division 3 Diesel Generator at 2610.2 kilowatts was just slightly above its continuous

rating of 2600 kilowatts and was well within its 2000 hour0.0231 days 0.556 hours 0.00331 weeks 7.61e-4 months rating of 2850 kilowatts. The

only major load on the Division 3 Diesel Generator was the HPCS pump. Based on a

review of the simulated loss of coolant accident tests for HPCS initiation, the team

determined that the Division 3 Diesel Generator could safely start all required HPCS

loads.

The team found that the Division 3 Diesel Generator trips were functional and that

appropriate trips were bypassed to maximize HPCS availability to perform it's safety

function. The team reviewed documentation of the most recent performance of

Procedure MMP-DG3-B103, "Diesel Generator DG-3 Mechanical Inspection," Revision 1,

and found that the over speed trip at 1037 RPM was adequately tested.

Using

Procedure TSP-DG3/LOCA-B501, " HPCS Diesel Generator DG3 LOCA Test,"

Revision 0, the licensee verified that the appropriate trips would be bypassed during a

loss of coolant accident.

The licensee also had performed periodic maintenance to

confirm the readiness of the only Division 3 Diesel Generator trip that was not bypassed,

the differential current relay.

During implementation of Procedure TSP-DG3/LOCA-B501, the licensee also verified

that the fuel oil storage tank level was at 44622 gallons (the technical specification limit

was 33,000 gallons) and that the emergency core cooling system activation signal

initiated the HPCS system.

4 kV Available Voltage During a LOCA and Starting of Large Motors

The team found that during a LOCA, Division 3 was supplied by Transformer TRS from

the 230 kV system.

The off-load tap setting for Transformer TRS was .975. This tap

setting effectively raised the source voltage to 1.025 per unit. The worst case voltage

drops willbe experienced when the HPCS system was supplied from the offsite source

and not the Division 3 Diesel Generator.

-14-

Calculation E/l-02-87-07, "WNP-2 Plant Main Bus Voltage Calculation," Revision 3,

showed that for the degraded grid voltage relay allowable minimum setting of 3684.45

volts ac, the available voltage at Motor Control Center MC-4A would be about 415 volts

ac. Calculation E/I-02-90-01, "Low Voltage Systems Loading and Voltage Calculations,"

Revision

4, indicated that with 415 volts at Motor Control Center MC-4A all of the Motor

Control Center MC-4A loads would be supplied a minimum of 408 volts ac at their

terminals.

This was less than the preferred value of 90 percent of nominal voltage or

414 volts ac and would cause the loads (especially the motor loads) to operate at

increased temperatures

because

of the reduced voltage.

The majority of the loads were

motor operated valves that operate only intermittently during a HPCS initiation and would

not be significantly affected by this concern.

Continuous HPCS loads would experience

an indefinable loss of thermal life because

of the expected increase in current du'ring low

voltage conditions.

However, since HPCS only operates infrequently, the team

determined that this minor design discrepancy would have negligible impact on the

overall reliabilityof the HPCS system.

All HPCS ac loads had sufficient voltage to operate even when starting motors on the

4 kV buses.

For worst case starting voltages at Bus SM-4, the team determined that the

HPCS system could be initiafed without causing the degraded grid voltage relay to

dropout.

Minimum AC Voltages at Low Voltage Buses

The team found that the licensee satisfactorily demonstrated

that all ac loads supplied

from Motor Control Center MC-4A had sufficient voltage to operate properly for all

operating conditions. The mechanical calculations for the HPCS motor operated valves

assumed the terminal voltage at each valve's motor to be 80 percent of 460-volts ac,

unless a higher voltage was required for a motor operated valve to develop its required

torque and thrust.

Some motor operated valves required more than 80 percent voltage

to open or close.

For example, Valves V-23 and V-12 required 85 percent and

88 percent voltage, respectively, to develop their required torque.

In Calculation

E/I-02-90-01, the licensee determined that the available voltage at each motor operated

valve's mc!.---lerminals was higher than that needed to assure proper operations of the

valve during the starting of motors at Motor Control Center MC-4A and upstream buses.

Minimum DC Voltages at Low Voltage Buses

The team's review confirmed that sufficient voltage was available at the terminals of most

dc power loads except for lube oil pump DLO-P-10.

When the starter for the Division 3

Diesel Generator lube oil pump DLO-P-10 was relocated from dc Distribution Panel E-

DP-S1/HPCS to near the pump itself, the voltage drop calculation was not revised to

incorporate this circuit change.

While this was a another indicator of the failure to

update calculations as changes occur, the team noted that lube oil pump was riot

required to support the HPCS system safety function. The licensee agreed that the

voltage drop calculation had not been appropriately revised and documented

it on

Problem Evaluation Report 298-0985.

This failure to update the voltage drop calculation

constitutes a violation of minor significance and is not subject to formal enforcement

action.

-15-

The team also noted that Calculation 2.07.04, "D.C. Cable Voltage Drop," Revision 5, did

not analyze voltage drops for instrumentation, relays, etc., in downstream panels from

the dc Distribution Panel E-DP-S1/HPCS.

The licensee planned to determine how they

assured that loads of this type had the requisite pickup voltage at their terminals under

minimum voltage conditions.

Cable Routing

The licensee, at the team's request, provided a copy of Cable and Raceway Report

CARPS 2.1 for power and control cables to HPCS motor operated valves and the HPCS

pump. This document showed that these cables were routed exclusively with Division 3

cables and in Division 3 raceways, which supported the separation policy.

Heat Tracing

The team asked the licensee about the heat tracing of the HPCS standby service water

piping. Only the return line was heat traced at the point where it rose out of the ground

and then drops down to facilitate discharging HPCS standby service water into standby

service water Pond A. The licensee stated that this heat tracing was supplied by a

Class 1E power supply, was alarmed for power failure, had indication that power was

available, and that the heat tracing alarms and indications were routinely monitored by a

roving operator.

Conclusions

In general,

the electrical equipment for the HPCS system was well designed.

Both ac

and dc power cables for the HPCS system were appropriately sized.

With some

exceptions, the electric protective devices were appropriately selected and coordinated.

The team concluded that the licensee had not appropriately assessed

the significance of

some breaker coordination errors in the dc system and did not promptly correct these

design deficiencies.

This was an example of a violation of 10 CFR 50, Appendix B,

Criterion XVI, "Corrective Action." While some selections were marginal, the team found

that, in general, breakers were properly selected to withstand the maxir..

rn calculated

available short-circuit currents in the ac and dc distribution systems.

However, in conflict

with the licensee's procedures, the calculations to determine available short-circuit

currents contained nonconservative temperature assumptions.

This was an example of a

violation of 10 CFR Part 50, Appendix B, Criterion V, "Instructions, Procedures,

and

Drawings." Breaker coordination and protective device selection will need to be

reassessed

after the licensee correctly calculates the available short-circuit currents.

The team found that the Division 3 Diesel Generator had acequate capacity.

The

protective trips were functional and appropriate trips were bypassed on a safety actuation

signal. The team determined that the minimum expected ac and dc voltages were

adequate to meet HPCS system operating requirements.

The team also determined that

the cable routing and heat trace design for the HPCS system were satisfactory.

-16-

E1.3.2

Electrical Design Changes

The team reviewed Plant Modification Record 93-0049-0, "HPCS-V-10 R 11 Time Delay,"

and 93-0052-0, "HPCS-MO-4 Close on Torque," to determine whether the intent of the

original design basis was maintained and to confirm that safety functions were not

compromised by the design change.

b.

Observations and Findin s

Test'Return Valve AuxiliaryRelay Replacement

Plant Modification Record

93-0049-0, replaced an instantaneous

pickup auxiliary relay in

the opening control circuits of HPCS test return Valves V-10 and V-11 with an

instantaneous

pickup and delayed drop-out relay.

This relay was modified to delay the

close signal until the valve's opening motion had ceased,

thus preventing high actuator

currents and protective device actuations, which are caused by sudden motor reversals.

The plant modification record appeared

to the team to resolve the longstanding design

concern.

This design change did not impact the original safety purpose of each valve,

which was containment isolation during an accident, since it only delayed valve closing if

the valve was still trying to open.

The plant modification record properly addressed

the

seismic mounting of relays, ensured that the relays had sufficient rating for the available

current and voltage in each valve's control circuit, and all other relevant design concerns.

Use of Torque Switch to Control Closure for HPCS Injection Valve V-4

Plant Modification Record 93-0052-0, changed the closing control circuit of HPCS

Injection Valve V-4 to prevent damage to the valve by allowing a torque switch to control

closure in lieu of a limitswitch. The primary design safety function of this valve was to

open to inject water into the vessel during an accident, which was not altered by this

design change.

The close safety function was to prevent vessel overfill and containment

isolation. The post-modification test for this modification verified the new settings of the

torque switches along with verifying that back leakage was not altered from what it was

prior to this modification.

~ c.

Conclusions

The plant modification records addressed

all relevant design and safety issues and

effectively verified the design changes by post-modification testing.

-17-

E2

E21

Engineering Support of Facilities and Equipment (93809)

HPCS S stem Walk Down

Ins ection Sco

e

The team performed a walk down of the accessible portions of the HPCS and HPCS

standby service water systems to verify that the system configuration was consistent with

the design basis.

The walk down included the CST area, supply piping from the CST to

the HPCS pump, the HPCS pump room, various reactor building areas that contained

HPCS piping and valves, the HPCS standby service water pump area, and the Division 3

Diesel Generator room.

Observations and Findin s

The team found the system configuration to be consistent with the HPCS, condensate

supply, and standby service water system flowdiagrams in the areas observed.

In

addition, the team observed that housekeeping was very good. The team did not

observe any improperly stored material or unsecured temporary equipment in these

areas.

C.

Conclusions

Based on the area walk downs, the HPCS and HPCS standby service water system

configurations were consistent with the design basis.

The plant reflects the licensee's

attention to housekeeping.

The team did not observe any improperly stored material or

unsecured temporary equipment.

E2.2

HPCS Valve 0 eration

a.

Ins ection Sco

e

The team reviewed the available licensing, design, and operations documents related to

the capability of HPCS system valves to perform their required functions under accident

conditions.

Observations and Findin s

Calculation C106-92-03.02, 'WNP-2 HPCS System MOV Design Basis Review,"

Revision 2, documented the system level design basis review of the motor operated

valves in the HPCS system that were included in the motor operated valve program

developed to meet Generic Letter 89-10, "Safety-Related Motor-Operated Valve Testing

and Surveillance." This calculation documented the maximum expected differential

pressure, maximum line pressure, maximum flow rate, maximum fluid temperature, and

stroke time for each valve. The team reviewed this calculation and found it to be

complete and correct.

-18-

'onclusions

The team found that the HPCS system'valve design was consistent with the applicable

licensing, design, and operations documents and that the valves were capable of

performing their functions under accident conditions.

E2.3

HPCS Mechanical S stem Surveillance Testin

Acce tance Criteria

Ins ection Sco

e

The team reviewed the available licensing, design, and operations documents related to

surveillance testing of HPCS system mechanical components.

This review included the

applicable technical specifications and surveillance procedures.

b.

Observations and Findin s

HPCS Pump Testing

Technical Specification Surveillance Requirement 3.5.1.4 required the HPCS pump flow

to be greater than or equal to 6350 gpm and the pump head to be greater than or equal

to 200 psid. These variables were verified by the inservice testing program.

Surveillance

Procedure OSP-HPCS/IST-Q701,

"HPCS System Operability Test," Revision 3, included

the inservice testing of the HPCS pump. The low action limitfor pump flow was 6500

gpm, and the low action limitfor pump discharge pressure was 380 psig. Procedure

PPM 7.4.5.1.11, "Record of Reference Values and Acceptance Criteria Changes for

ASME Pumps and Valves," dated April20, 1992, provided the correction between an

indicated flowof 6500 gpm and an actual flowof 6350 gpm under test conditions.

Calculation ME-02-90-017, "Pressure Drop Verification for the HPCS System,"

Revision 0, determined that a pump discharge pressure of 380 psig would correspond to

a pump head of 200 psid. The team reviewed these documents and found them to be

correct and complete.

HPCS Valve Testing

The Inservice Testing (IST) Program Plan, Second 10-Year Interval, Revision 1,

identified the required testing for the HPCS system valves.

Surveillance Procedures

OSP-HPCS/IST-Q701and

OSP-HPCS/IST-R701,

"HPCS Check Valve Operability-

Refueling Shutdown," Revision 1, included the inservice testing of HPCS system valves.

The team reviewed these documents and found that the procedures correctly

implemented the program plan requirements.

Section 2 of the Program Plan stated that it complied with the requirements of

10 CFR 50.55a(b)(2) and 50.55a(f). The 1989 edition of ASME Section XI was

incorporated into Paragraph 50.55a(b) by rulemaking on September 8, 1992. The 1989

edition specified that the rules for the inservice testing of valves were stated in the

ASME/ANSI Operations and Maintenance (OM) Standards,

Part 10, "Inservice Testing of

-19-

0

Valves in Light-Water Power Plants." The applicable revision was the OMa-1988

Addenda to the OM-1987 Edition. OM-10 stipulated that Category A valves are those

valves with functions in which the closed valve seat leakage was limited to a specific

amount.

The team noted that the valves required to provide isolation between the HPCS system

and the CSTs under accident conditions were not classified as Category A and were not

required to be leak rate tested by the IST Program Plan.

Motor Operated Valve V-1

(14-inch) and Check Valve V-2 (20-inch) were in the CST suction line. Motor Operated

Valves V-10 and V-11 (10-inch) were in the HPCS test line to the CST. Allthese valves

would be closed to isolate the HPCS system from the CST, if the HPCS system was

taking suction from the suppression

pool after an accident.

It appeared that any leakage

through these valves could be released to the environment through the vented CSTs.

The IST valve classification of Valves HPCS-V-1, 2, 10, and 11 did not appear consistent

with FSAR, Section 6.2.3, "Secondary Containment Functional Design." Section 6.2.3.2,

"System Design," stated,'"The control rod drive, HPCS, RHR, LPCS, fuel pool cooling,

and RCIC systems connect to systems that terminate outside containment.

Each of the

water leak paths has been evaluated and the isolation valves have been 'assigned

leakage values based upon allowable ASME leak rates.

The summation of the water

leakage for all the water leak paths was equated to 0.03 standard cubic feet per hour

(scfh) of air."

Engineering Technical Memorandum TM-2099, Revision 0, which formed the basis for

part of FSAR, Section 6.2.3.2, established analytical leakage limits for liquid leakage

paths that originated in primary containment and would byp'ass secondary containment

on a "per valve basis," based upon allowable ASME leak rates.

The team determined

that, since these valves were not leak tested, the leakage limits assumed

in Technical

Memorandum TM-2099 were unrealistically low values for valves in service.

The team asked if the IST classification of these valve was consistent with the licensing

basis.

In response to this question, the licensee investigated the history of this issue

and concluded that, while the IST classification was not consistent with the current

licensing basis, it was the licensing basis that was in error. The licensee issued Problem

Evaluation Report 298-0928, "FSAR Value for Secondary Containment Bypass Leakage

Limitwas'nappropriately Being Applied to Liquid Leakage Bypass Paths," dated July 28,

1998.

The licensee planned to correct their licensing basis to make it clear that their

current testing practices were adequate for these secondary containment bypass valves.

The team reviewed the licensee's basis for their position. The licensee determined that

the initial plant licensing basis assigned a secondary containment bypass limitof

0.74 scfh to four gaseous leakage paths and did not include explicit consideration of

liquid bypass leakage paths.

After initial licensing, the licensee identified additional

gaseous bypass leakage paths.

The associated

valves were included in FSAR

Table6.2-16, "Primary Containment Isolation Valves," and were added to the local leak

rate test program.

The overall 0.74 scfh limitwas not changed to accommodate

the

additional gaseous leak paths.

-20-

In 1989, the licensee identified several liquid bypass leakage paths that had not been

explicitly addressed

during plant licensing. To ensure that the original 10 CFR Part 100

calculations remained valid, the licensee developed an equivalence between the gaseous

and liquid bypass leakage paths, utilizing Standard Review Plan 15.6.5, Appendix B, and

assuming that 10 percent of the liquid becomes airborne on a volumetric basis.

They

included the gaseous equivalent of the anticipated liquid bypass leakage in their estimate

of total gaseous

leakage.

The licensee determined that the total predicted liquid

leakage rate was equivalent to a gaseous leakage of .03 scfh. This value was subtracted

from the 0.74 scfh limitto establish the remaining gaseous

leakage limitof 0.71 scfh.

This evaluation was documented

in Interoffice Memorandum SS2-PE-89-0646,

"Potential

Bypass Leakage and Unmonitored Effluent Paths," dated June 22, 1989.

The application of a portion of the secondary containment bypass limitof 0.74 scfh to

liquid bypass leakage paths was added to the licensing basis in 1996.

FSAR/Technical

Specification Bases Change Notice 95-072, Revision 0, was approved on May 8, 1996,

revising FSAR, Section 6.2.3.2, to include a discussion of the liquid bypass leakage

being equated to 0.03 scfh of gaseous leakage.

Engineering Technical Memorandum

TM-2099, "Secondary Containment Bypass Leakage," Revision 0, formed the basis for

part of this FSAR change.

TM-2099 stated that the approach used to correlate liquid

leakage rates to equivalent gaseous

leakage rates was similar to Standard Review

Plan 15.6.5, Appendix B, with 10 percent of the leakage assumed to become airborne.

Based on questioning from the team, the licensee concluded that the calculation method

used to determine the equivalence between airborne and liquid secondary containment

bypass leakage in both Interoffice Memorandum SS2-PE-89-0646 and Engineering

Technical Memorandum TM-2099 was technically inaccurate and did not implement

Standard Review Plan 15.6.5.

During this inspection, the licensee performed an additional informal analysis of the

impact of the liquid leakage bypass paths using a new method and determined that the

offsite and control room doses would remain within the limits of 10 CFR Part 100

guidelines and the 10 CFR Part 50, Appendix A, General Design Criteria 19 limits.

Based on this new method, the analyst determined that the low population zone thyroid

dose consequences

would be 2.21 rem/gpm of liquid leakage.

Therefore, a total liquid

bypass leakage rate of greater than approximately 100 gpm would be required to exceed

the limits of 10 CFR Part 100 guidelines and the 10 CFR Part 50, Appendix A, General

Design Criteria 19 limits. The licensee stated that the impact of any potential liquid

bypass paths must be individually evaluated to determine the actual anticipated

conditions at the point of release, the timing and holdup capacity, any additional dilution

factors, applicability to the accident scenario being evaluated, and that Engineering

Technical Memorandum TM-2099 and the FSAR would be updated to reflect these

factors.

The licensee concluded that an assumption of a total system leakage limit rather than

individual valve leakage limits was appropriate for these secondary containment liquid

bypass paths.

Therefore an IST classification of Category A was not applicable to the

valves required to isolate liquid bypass leakage paths.

The licensee stated that leak

tightness of all liquid bypass paths would continue to be demonstrated

by Type A

Containment Leak Rate Testing. The liquid leakage necessary

to exceed the analyzed

-21-

limitwas of such a magnitude (approximately 100 gpm) that during the course of normal

plant operation, these potential liquid leakage paths could be demonstrated

to be

adequately leak tight by virtue of relatively stable CST level, reactor water sump and tank

levels, and standby service water system radiation levels. The team agreed that an IST

classification of Category A was not applicable to the valves required to isolate the liquid

bypass leakage paths, if leakage rates of approximately 100 gpm were found to be

acceptable and the FSAR was appropriately revised.

The team reviewed the licensee's informal analysis and questioned the new calculation

method used to determine the equivalence between airborne and liquid secondary

containment bypass leakage.

For the configurations being considered, the Standard

Review Plan 15.6.5, Appendix B, Revision 1, stated that if the calculated flash fraction

was less than 10 percent or if the water was less than 212

F, then 10 percent of the

Iodine in the leakage should be assumed to become airborne unless a smaller amount

was justified based on actual sump pH history and ventilation rates.

The licensee's

informal analysis did not assume that 10 percent of the Iodine in the liquid leakage

becomes airborne.

Instead the informal analysis was based on a General Electric study

that determined that the release fraction would be less than 10'0.1 percent) with 185'- F

suppression

pool water. The team did not verify the applicability of the reduced release

fraction based on the General Electric study to this application during the inspection.

This release fraction had a significant effect on the analysis results.

This item is

unresolved pending completion of an NRC review of the application of the General

Electric study to the release fraction determination (50-397/9815-04).

In 1996, the licensee submitted Letter GO2-96-199, "Request for Amendment to

Secondary Containment and Standby Gas Treatment System Technical Specifications,"

dated October 15, 1996. This amendment had not been approved by the NRC at the

time of the inspection.

The proposed change would increase the allowable secondary

containment bypass leakage from 0.74 scfh to 18 scfh. This change was based on

analyses that have shown that the offsite and control room doses would remain within the

limits of 10 CFR Part 100 guidelines and the 10 CFR Part 50,.Appendix A, General

Design Criteria 19 limits. The licensee stated that the analyses did not specifically

address liquid leakage.

Conclusions

With the exception of valve leakage testing, testing of the HPCS system mechanical

components was consistent with the applicable licensing, design, and operations

documents.

This testing was sufficient to verify the capability of the mechanical

equipment to perform its required functions under accident conditions.

With regard to valve leakage testing, the licensee identified several liquid secondary

containment bypass leakage paths in 1989 and was proactive in addressing the effect of

these paths on the design basis by establishing a reduced total gaseous bypass leakage

limit. However, the licensee did not effectively implement the design controls required to

recognize the valve leakage testing requirements associated

with assigning valve

specific leakage limits. In addition, the calculation method used to determine the

equivalence between airborne and liquid bypass leakage was not well documented and

was in error.

-22-

Based on the results of an informal analysis performed by the licensee during this

inspection and the licensee's statement that the FSAR willbe revised to eliminate valve

specific leakage limits for these liquid bypass leakage paths from the design basis, the

licensee's position that an IST classification of Category A was not applicable to the

valves required to isolate the liquid bypass leakage paths was found to be appropriate.

However, the team did not verify the applicability of the calculation method for

determining the Iodine release fraction used in this informal analysis during the

inspection.

This release fraction had a significant effect on the analysis results.

This

item is unresolved pending completion of NRC review of the applicability of this

calculation method.

HPCS Standb

Service Water Thermal Performance Testin

Acce tance Criteria

Ins ection Sco

e

The team reviewed the capability of the HPCS standby service water system to provide

an adequate cooling water supply to the Division 3 Diesel Generator Heat Exchanger

DCW-HX-1C, the Division 3 Diesel Generator room Cooling Coils DMA-CC-31 and 32,

and the HPCS pump room cooling Coils RRA-CC-4. The historical thermal performance

monitoring data for the Division 3 Diesel Generator Heat Exchanger DCW-HX-1C was

reviewed in detail.

Observations and Findin s

A summary of the historical thermal performance monitoring data for the Division 3

Diesel Generator Heat Exchanger DCW-HX-1C from 1990 through 1998 indicated that

the heat exchanger performance had been maintained at or above 40 percent of the

design heat transfer coefficient value for this heat exchanger.

This thermal performance

monitoring data had been obtained and evaluated in accordance

with Test Procedure

8.4.63, "Thermal Performance Monitoring of DCW-HX-1C," Revision 5.

Calculation ME-02-92-242, "DCW-HX-1C Performance Evaluation," Revision 0, specified

that an o:"..-"-IIheat transfer coefficient of at least 208 BTU/(hrft'), which was

40 percent of the design value of 520 BTU/(hrft'), was required to ensure acceptable

thermal performance under accident conditions. The team's review of this calculation

indicated that this 40 percent acceptance

criterion was developed in Calculation

ME-02-92-0243, "DCW-HX-1C Design Performance Requirements," Revision 0, and was

based on a design HPCS standby service water flow of 910 gpm to Heat Exchanger

DCW-HX-1C. The team noted that heat transfer was affected by fouling and flow.

Flow balance test Surveillance Procedure OSP-SW-M103, "HPCS Service Water

Valve Position Verification," Revision 2, allowed an acceptable flow range of 780 gpm

to 960 gpm to Heat Exchanger DCW-HX-1C. The purpose of Surveillance

Procedure OSP-SW-M103 was to demonstrate the operability of the HPCS standby

service water system per Technical Specification Surveillance Requirement 3.7.2.1. The

licensee stated that the minimum acceptable flowvalue of 780 gpm was consistent with

FSAR Table 9.2-5, "Standby Service Water Flow Rates and Associated Heat Loads Used

in the Ultimate Heat Sink Analysis."

-23-

The team asked the licensee to determine if the minimum acceptable flow of 780 gpm

allowed by Surveillance Procedure OSP-SW-M103 was less conservative than the flow

value of 910 gpm assumed

in Calculation ME-02-92-243 to develop the 40 percent heat

transfer acceptance

criterion.

In response

to this question, the licensee determined that

the criterion was nonconservative and issued Problem Evaluation Report 298-0959,

"DCW-HX-1CThermal Performance Monitoring Acceptance Criteria was

Non-conservative," dated July 30, 1998. This problem evaluation request determined

that Heat Exchanger DCW-HX-1C, Diesel Generator DG-3, and the HPCS service water

system were all operable because

Heat Exchanger DCW-HX-1C had been cleaned in

April 1996 and subsequent

performance monitoring data had shown sufficient margin to

ensure operability.

In addition, the licensee reviewed the calculations and procedures. for

the remaining diesel generator heat exchangers

and the RHR heat exchanger and found

the acceptance

criterion was correctly developed for these heat exchangers.

On August 10, 1998, the licensee provided the latest version of Problem Evaluation

Report 298-0959, which documented their reportability evaluation.

Based on a reanalysis

of past thermal performance and operating data for Heat Exchanger DCW-HX-1C, the

licensee determined that the heat exchanger had been capable of performing its design

function at all times since performance monitoring began in 1990 and; therefore, the

condition was not reportable.

The problem evaluation report also included the licensee's

plans for correcting the test acceptance

criterion in Procedure PPM 8.4.63 prior to the

next performance of the thermal performance test for Heat Exchanger DCW-HX-1C.

10 CFR Part 50, Appendix B, Criterion XI, "Test Control" states that a test program shall

be established to assure that all testing required to demonstrate that structures, systems,

and components willperform satisfactorily in service was identified and performed in

accordance with written test procedures, which incorporate the requirements and

acceptance

limits contained in applicable design documents.

The 40 percent acceptance

criterion specified in Calculation MWE-02-92-242 and developed in Calculation

MWE-02-92-243 was not correctly determined from applicable design documents and as

a result the thermal performance test did not assure that Heat Exchanger DCW-HX-1C

would perform satisfactorily in service for all allowed HPCS standby service water flows.

The failure to correctly develop the acceptar.": criterion from design c

umentation is a

violation of 10 CFR Part 50, Appendix B, Criterion XI (50-397/9815-05).

The team determined that this inspection report adequately described the reasons for the

violation, and the actions taken to correct and prevent recurrence of the violation.

Therefore, no response to this violation is required.

Conclusions

The team concluded that, with the exception of the required flowfor Heat Exchanger

DCW-HX-1C, testing of the HPCS standby service water system demonstrated

that the

system was capable of providing an adequate cooling water supply to support operation

of the HPCS system.

With regard to thermal performance testing of Division 3 Diesel Generator Heat

Exchanger DCW-HX-1C, the licensee failed to effectively implement the test program

control required to assure that the acceptance

criteria of a surveillance test was valid for

-24-

all expected HPCS standby service water flows. This was determined to be a violation of

10 CFR Part 50, Appendix 8, Criterion. XI, "Test Control." The licensee determined that

the HPCS standby service water system and associated

equipment were operable at all

times since performance monitoring began in 1990.

E2.5

HPCS Instrument Calibration and Channel Check Procedures

The team evaluated the instrumentation and control configuration by walking down

instrument racks for the HPCS related transmitters and process, and by reviewing related

technical specification required channel calibration arid channel functional test

procedures.

b.

Observations and Findin s

The team reviewed instrument channel calibration and channel functional test procedures

associated with HPCS setpoint calculations.

Actual test results from the last 3 years for

selected channels were also reviewed.

The procedures were well written and had an

adequate

level of detail. 'The results were well documented.

The team noted a few

instances where the procedures were modified to clarify minor detail errors; this

demonstrated

an adequate

level of a questioning attitude'by instrument technicians and

control room personnel as well as sensitivity to procedure adherence.

c.

Conclusions

HPCS instrument setpoint channel check and calibration procedures were adequate to

'nsure

safe and reliable operation.

The procedures were well written and had an

adequate

level of detail.

E2.6

Division 3 Batte

Testin

a.

Ins ection Sco

e

The team evaluated the testing of the Division 3 battery to verify that the capacity and

surveillance testing of the Division 3 battery was adequate to assure that the battery was

functional.

Observations and Findin s

Division 3 Battery and Battery Charger Load Calculation

i

The team reviewed Calculation E/l-02-85-02,"High Pressure Core Spray Battery and

Battery Charger," Revision 1, to evaluate the ability of the Division 3 battery to perform in

accordance with its design accident load profile. The licensee had clearly established the

size of all loads supplied by the battery, except two: the inrush current for spring

charging motors of 4 kV breakers and the field flash current for Division 3 Diesel

Generator.

The licensee was not able to directly determine the size of these loads, so

-25-

they estimated their size, based on a combination of information from the nuclear steam

supply system vendor, alternative, calculations, and a review of data for comparable

equipment.

Considering the overall margin in the battery, this level of confirmation was

acceptable.

Division 3 Battery Testing

The team reviewed the Performance Test Procedure ESP-B1DG3-F101

and the Service

Test Procedure 7.4.8.2.1.19 for the Division 3 battery and determined that the licensee

had elected to perform the performance test in lieu of the service test.

However, the

team noted that the performance test was not modified to envelope the service test

during the initial minute of the battery's accident load profile as required by Technical

Specification Surveillance Requirement 3.8.4.7.

In response to that concern, the licensee determined that the current performance tests

for not only the Division 3 battery, but for the Division 1 and 2 Batteries E-B1-1 and

E-B2-1 were also conducted in lieu of their respective service tests on April30, 1998,

May 12, 1998, and April30, 1997 respectively.

Since the performance tests were not

modified to envelope the service test, the licensee now had to rely exclusively on the last

service test for each of the three Class 1E batteries in order to determine their readiness

for performance during an accident.

The licensee determined that the last service tests for Division 1, 2, and 3 batteries were

performed on April 19. 1996, April28, 1995, and May 9, 1996. Technical Specification 3.0.2 requires the next surveillance test to be performed at 1.25 times the

interval stated in the technical specifications.

Applying that criteria, the last service tests

for each of the Division 1,2, and 3 batteries would expire on October 22, 1998,

October 28, 1997, and November 19, 1998. The licensed determined that only the

service test for Division 2 Battery E-B1-2 had expired prior to the perforrriance of a

qualified service test or its equivalent.

The failure to perform a surveillance test that met

the requirements of Technical Specification Surveillance Requirement 3.8.4.7 for

Division 2 Battery E-B1-2 within 1.25 times the specified frequency of 24 months (prior to

October 28, 1997) is a violation of Technical Specification 3.0.2 (50-397/9815-06).

. The licensee informed the NRC of the expired tests on July 14, 1998, and asked for and

was verbally granted a Notice of Enforcement Discretion on July 15, 1998, that permitted

the licensee to delay taking any required actions until a technical specification

amendment was approved.

This allowed the licensee to wait until the R-14 refueling

outage or an earlier outage of sufficient duration in order to perform a qualified service

test for that battery.

Problem Evaluation Report 298-0887 was initiated to document this concern and identify

all related corrective actions to be undertaken.

On August 17, 1998, the licensee

submitted Licensee Event Report (LER) 50-397/98-01 2-00, which discussed reportable

corrective action taken, and action taken to preclude recurrence.

The team determined that the LER, in combination with this inspection report, adequately

describes the reasons for the violation, and the actions taken to correct and prevent

-26-

I

recurrence of the violation. Therefore, the licensee was not required to respond to this

violation.

Conclusions

The team confirmed the capacity of the Division 3 battery to perform its intended safety

function and identified that the licensee had inappropriately credited a battery

performance test for a service test.

However, the previous service test had been

conducted within the allowed frequency.

During their review to identify other similar

problems, the licensee identified that they had exceeded the allowed surveillance test

frequency specified in Technical Specification 3.0.2 for the Division 2 Battery E-B1-2, a

violation of NRC requirements. The team concluded that the licensee's extent of

condition review was effective.

E2.7

Year 2000 Pro'ect

at

The team reviewed the status of the licensee's plan to assure safe plant operation at the

turn of the century when computer chips and programs may malfunction due to an

incorrect representation

of the date.

Observations and Findin s

The team found that the licensee did have a plan in place to address the year 2000

issue.

Susceptible plant embedded systems had been identified and a detailed review of,

these systems was in progress.

The licensee had already identified that some systems

would require remediation.

The licensee planned to benchmark their effort with other

boiling water reactor utilities and develop contingency plans, where needed.

Conclusions

The licensee had a plan in place to address the year 2000 issue.

E7

Quality Assurance in Engineering Activities (37550)

E7.1

ECCS Pum

10 CFR 21 Evaluation

Ins ection Sco

e 37550

The team reviewed the licensee's response to a recent 10 CFR Part 21 report submitted

by Ingersoll-Dresser Pump Company concerning breakage of cast iron pump suction

heads.

The NRC was notified of this potential safety hazard by the Ingersoll-Dresser

'ump

Company on July 9, 1998, in accordance

with 10 CFR Part 21 (reference Event

Notification 34499). The HPCS, LPCS, and RHR pumps were similar Ingersoll-Rand

pumps with cast iron heads.

-27-

Observations and Findin s

The team found that the licensee had addressed

this issue prior to the 10 CFR Part 21

report in response

to an industry event notice dated April 15, 1998. The industry report

concerned the failure of a cast iron bearing support bracket in a RHR pump at Limerick

Unit 1, discovered on April 11, 1998.

The licensee initiated Problem Evaluation Report 298-0407 on April 21, 1998. The

problem evaluation report concluded that no inspections of the pumps were required at

the time and that inspection of pump Nos. RHR-P-2A or 2B would be placed on the

5-year plan.

In addition, a corrective action plan to inspect and/or replace the suction

head on one of the RHR pumps was issued.

These actions were based on the service

history of the pumps and the recommendations

provided by the pump vendor.

The team found the actions taken by the licensee to be appropriate and found that this

issue had been addressed

in a timely manner prior to the 10 CFR Part 21 report being

issued.

Conclusions

es

E8.1

The licensee effectively addressed

this recent industry issue by evaluating the

applicability of the condition in a timely manner and initiating an appropriate corrective

action plan. The team found the licensee's response to this potential safety hazard to be

both thorough and proactive.

Miscellaneous Engineering Issues (92903)

Closed

Violation 50-397/9713-01:

Inadequate Corrective Actions

Backcaround

The NRC identified three examples of a 10 CFR Part 50, Appendix B, Criterion XVI

violation. The licensee characterized the examples as either failure to promptly identify a

condition adverse to quality or failure to fullyimplement corrective actions in a timely

manner.

The licensee attributed the violation to management

not properly enforcing their

expectations regarding timely identification and completion of corrective actions.

In

addition, the licensee stated that inadequate work management

methods contributed to

the untimely implementation of corrective actions.

Ins ection Followu

The licensee corrected the specific examples, issued Problem Evaluation Report 298-

0034 on January 12, 1998, and planned improved procedural guidance for management

oversight of the corrective action process.

The team confirmed that the specific conditions had been corrected and reviewed the

licensee's planned corrective actions for preventing recurrence and concluded that they

were reasonable.

The revision to Procedure

PPM 1.3.12A was in progress at the time of

-28-

this inspection and was on schedule for completion on August 1, 1998.

Based upon the

licensee's corrective actions that were completed and scheduled to be completed, the

team concluded that this violation was being properly addressed.

E8.2

Closed

Violation 50-397/9713-02:

Failure to Maintain Acceptance Criteria and Inservice

Testing of RCIC System Valves

a.

Back<around

The NRC identified the failure to maintain the acceptance

criteria for the opening stroke-

time testing of six RCIC system valves and the failure to maintain inservice testing of

Valve RCIC-V-45 as required by 10 CFR 50.55a(f). The violation occurred as a result of

an inappropriate RCIC system classification downgrade.

b.

Ins ection Followu

E8.3

The NRC verified that the appropriate motor operated valves were included the

licensee's IST program as the result of the RCIC System safety classification upgrade.

The licensee determined this violation was caused by an inadequate safety evaluation.

The preventive corrective action steps for this violation are identical to those for Apparent

Violation 50-382/9713-03.

The team's review of these actions is documented below in

Section E8.3. The licensee achieved full compliance on December 18, 1997, when the

licensee approved and incorporated changes to the IST program to properly reflect the

safety classification of the RCIC components.

The team concluded that this violation

was properly addressed.

Closed

Violation 50-397/9713-03:

Inadequate Safety Evaluation for RCIC Downgrade

Back<around

The NRC identified the failure to perform an adequate safety evaluation in accordance

with 10 CFR 50.59. The licensee downgraded the RCIC system from a safety-related

system to a nonsafety-related system without NRC approval. The NRC had previously

verified that all pertinent RCIC components. were upgraded by the licensee with the

exception of two rupture discs on the RCIC turbine exhaust line.

Ins ection Followu

The licensee agreed that it misapplied generic technical guidance in downgrading the

- RCIC system and had failed to identify an unreviewed safety question.

During this

inspection, the team confirmed that Work Order KKB9, Task 01, completed the

replacement of RCIC turbine exhaust rupture discs, the last pertinent components

requiring upgrade.

The licensee also reviewed past safety evaluations to identify similar violations. This

review was documented

in "Review of Approved 50.59 Safety Evaluations For the Use of

Generic Guidance" dated 3/16/98. The licensee reviewed 911 safety evaluation

summaries and 101 safety evaluations in order to determine if generic guidance

appropriately applied. -The licensee also revised Procedure PPM 1.3.43, "Licensing

-29-

Basis Impact Determinations," Revision 13, to clarify guidance for use and interpretation

of generic documents and included this event in the licensing basis impact training

outline for safety evaluation preparers and reviewers.

This program upgrade was

reviewed in NRC Inspection Report 50-397/98-13 and found to be satisfactory.

Based on

a review of the completed corrective actions, the team concluded that this violation was

being properly addressed.

r. ~'rLER

~

I

ir

ri

r

a.

~Back round

On April 23, 1998,

a licensee engineering-review showed that discharge-to-radwaste

Valve RHR-V-40 would not close upon receiving a manual close or isolation signal when

throttled less then 13 percent open.

This configuration was in conflict with the RHR

system description as stated in the FSAR.

This four-inch motor-operated valve was used to throttle flow rate to radwaste from the

suppression

pool during normal operation and to initiate RHR, Loop B, shutdown cooling

during shutdown.

The valve provided a close safety function for secondary containment

isolation and emergency cooling system lineup.

The LER documented several planned actions to correct the design deficiency and to

prevent a recurrence of this type of problem for another valve.

b.

Ins ection Followu

The team verified that the licensee completed the corrective action identified in the LER.

The LER stated that the safety consequences

of the design deficiency were minimal

because

the safety function is to close, the valve is normally closed, and the valve was in

series with Valve RHR-V-49 that was unaffected by the design flaw. The probability of

occurrence of Valve RHR-V-40 being open less than 13 percent coincident with a failure

of Valve RHR-V-49 was very low. The team;;.-

ed with the licensee's conclusion that

the safety consequences

of the design deficiency were minimal.

10 CFR Part 50, Appendix B, Criterion III, "Design Control," states,

in part, that measures

shall be established to assure that applicable regulatory requirements and the design

basis, as defined in g 50.2 and as specified in the license application, are correctly

translated into specifications, drawings, procedures,

and instructions.

FSAR Figure 7.3-14C included a wiring drawing for Valve RHR-V-40 that indicated that

the valve would close as required upon initiation of an isolation signal. This design was

not correctly translated into GE Functional Control Diagram CVI- 02E12-04.3.3,

-30-

Revision 8.

As a result, Valve RHR-V-40 would not have closed or auto-closed if it was

throttled open to between 9 to 13,percent.

The failure to correctly translate the design

specified in a license application into drawings is a violation of 10 CFR Part 50,

Appendix B, Criterion III, "Design Control." The licensee properly identified and corrected

this violation. This non-repetitive, licensee-identified, and corrected violation is being

treated as a non-cited violation consistent with Section VII.B.1 of the NRC Enforcement

~Polic

(50-397/9815-07).

Closed

Ins ection Followu

Item 50-397/9713-04:

Potentialfor NumerousCalculation

Modification Records to Affect Technical Content of Calculations.

Back<around

Calculation modification records were developed to postpone a calculation's revision until

several design changes could be processed at one time. In NRC Inspection Report 50-

397/96-201, the NRC reviewed Engineering Directorate Manual 2.15, "Preparation,

Verification and Approval of Calculations," Revision 2, and noted that the procedure

recommended that calculations be revised if five or more calculation modification records

were outstanding against a calculation. The NRC found evidence that three sampled

calculations had more than five calculation modification records outstanding and opened

Unresolved Item 50-397/96201-16.

The NRC conducted a followup of the unresolved item and determined that the licensee's

activities were in accordance with Procedure 2.15, in effect at the time, in that

management approval was obtained when more than five calculation modification

records were applied to a specific calculation. The inspectors also found that, as the

result of this NRC finding, the licensee had strengthened

informal management

expectations for calculation modification record control and had established an

engineering team to self-assess

their calculation process and controls. The inspectors

reviewed this self-assessment,

which was completed on October 16, 1997. The

inspectors noted that while the assessment

identified numerous problems with the

retrieving and handling of calculations and with Procedure 2.15, it did not determine, if it

was necc".""p to verify the technical impact of the numerous calculation modification

records on the content of the existing calculations.

The NRC reviewed a listing of calculations dated July 3, 1997, and found that 45

calculations had more than 5 calculation modification records.

The NRC planned further

inspection to evaluate the technical impact of an excessive number of calculation

modification records.

Ins ection Followu

The team found that in April 1998, the licensee implemented a prioritized plan to reduce

the number of calculations with more than 5 calculation modification records from 45 to

13 by July 1999. The licensee stated that the remaining 13 calculations with more than

five calculation modification records would be further reduced once the initial goal was

attained.

-31-

e

HPCS Setpoint Calculation Modification Records

To assess

the technical impact of multiple calculation modification records, the team

reviewed the twelve unincorporated (plant implemented status) calculation modification

records against various HPCS setpoint calculations.

The team identified administrative

and document control problems with four of them (Calculation Modification Records

92-0260, 92-0503, 92-0506, and 92-0546).

In the worst case, these document control

problems resulted in having two calculations of record with different setpoints for the

Level 1 reactor vessel emergency core cooling system level switches and for the starting

control for diesel driven air Compressor DSA-C-2C. However, the team did not find any

evidence that these errors resulted in a plant procedure or hardware error. The licensee

agreed to correct the administrative errors. These failures constitutes a violation of minor

significance and are not subject to formal enforcement action.

Electrical Load Tally Calculation Modification Records

The team also reviewed calculation modification records associated with six calculations

that analyze the loading on medium voltage and low voltage ac buses and one

calculation for each of the three dc divisions that documented a similar analysis for the

loads on the dc buses.

The team found that the licensee used the calculation

modification record process to track the addition of electrical loads to the busses.

Procedure EDP 2.15, "Preparation, Verification and Approval of Calculations,"

Revision 3, Step 4.5.5 stated that, "The CMR [calculation modification record] shall be

prepared against the latest revision of the calculation and all outstanding CMRs against

the calculation shall be considered.

The pertinent outstanding CMRs, which could affect

the results/conclusions,

shall be identified and accounted for in the CMR."

The team found that, in general, the licensee was not specifically identifying the pertinent

outstanding calculation modification records as required by Procedure EDP 2.15. The

licensee was only recording that all CMRs for the particular CMR have been reviewed.

To ensure that the intent of Procedure EDP 2.15 was implemented, the licensee

established an informal computer-based

sy".em to track electrical loa 'dditions to the

various electrical busses evaluated in Calculation E/l-02-90-01, "LowVoltage Systems

Loading and Voltage Calculations, " Revision 4.

The team requested that the licensee review a selection of calculation modification

records for Calculation E/l-02-90-01 to determine if the calculation's working file

adequately addressed

the bus loading. The licensee sampled 63 calculation modification

records and determined that the calculation working file was not properly updated for the

load additions described in the following three calculation modification records:

CMR 92-0453, which increased the load amps on Panel PP-7A-A, circuit 18 by

.04 amps;

CMR 92-0489, which added a new load of 7.38 amps on Panel PP-8A-C-A; and

-32-

CMR 97-0173, which increased the load amps on motor control center MC-8A for

SW-V-12B from 5.75 amps to 5.9 amps.

The team concluded that use of the working file to track loads, did not meet the intent of

EDP 2.15, Step 4.5.5, because

all outstanding calculation modification records were not

identified.

10 CFR Part 50, Appendix B, Criterion V, "Instructions, Procedures,

and Drawings,"

states, in part, "Activities affecting quality shall be prescribed by documented instructions,

procedures, or drawings, of a type appropriate to the circumstances and shall be

accomplished

in accordance with these instructions." The team concluded that the

licensee did not adhere to the requirements of Procedure EDP 2.15 in that the loads in all

outstanding CMRs related to Calculation E/I-02-90-01 were not identified and accounted

for. This failure is considered to be another example of a violation of 10 CFR Part 50,

Appendix B, Criterion V, "Instructions, Procedures,

and Drawings," (50-397/9815-02).

Subsequently, the licensee added the loads described in these calculation modification

records to the working file load tally and concluded that the affected motor control

centers still met the acceptance

criteria of the load calculation. The licensee also

informed the team that, as a conservative practice, load deletions were not included in

the working file, making the'working file estimate conservative.

The licensee stated that they plan to develop written guidance for administering the

~

working files.

The team concluded that use of numerous calculation records in lieu of making a formal

revision to Calculation E/I-02-90-01 did affect the technical content of the calculation.

However, the team also concluded that the licensee's working file process would

adequately control load additions, if rigorously followed.

F2

Status of Fire Protection Facilities and Equipment (64704)

Ins ection Sco

e

The team conducted a fire protection equipment walk down with licensee personnel,

interviewed fire brigade personnel, and conducted an independent walk down of selected

areas to verify proper installation, operability, and maintenance of fire protection system

and equipment.

In addition, the team witnessed a fire drill conducted on the evening of

July 29, 1998.

The team also reviewed 27 fire protection system surveillance procedures to determine if

the fire protection equipment was being properly tested.

The team reviewed the content

-33-

of these procedures and the frequency at which they were perfoimed to ensure that the

fire detection and suppression systems were tested in accordance with technical

specification requirements.

In addition, the team reviewed fire protection modifications to

ensure that the fire protection equipment was being properly maintained and upgraded

as needed.

b.

Observations and Findin s

The team's review of the fire protection system surveillances indicated that the licensee

conducted the surveillances in accordance with their procedures and initiated appropriate

work order tasks for any problems or discrepancies

noted.

The team noted that the

surveillance procedures were consistent with technical specification requirements and

performance frequencies. The team noted no discrepancies

in the review of these

surveillance procedures.

The team reviewed four fire protection modifications to assess

the licensee's ability to

maintain and upgrade the fire protection equipment over time. The following four

modifications were reviewed:

~

Technical Evaluation Report 94-0348, Revision 0, which installed a hanger to

steady fire protection line at FP-V-642.

~

Installation of muffler on Diesel Fire Pump

1, via Work Order Task ZP7401.

~

Plant Modification Record 91-0379, Revision 0, Delete the Reactor Water

Cleanup Room Fire Detection Sensors.

Plant Modification Record 89-0427, Revision 0, Addition of Manual Pull Station in

Service Building, Machine Shop.

Based on this review and a review of post modification test activities, the team concluded

that the licensee was properly maintaining and upgrading the fire protection equipment.

The team interviewed several members of the licensee's fire brigade and found them to

be knowledgeable in fire protection, fire fighting, and safe shutdown activities. The

licensee's fire brigade consisted of a qualified fire brigade leader and at least four

additional qualified fire brigade members on-site at all times. The team noted that the

fire brigade was not included in the minimum shift crew complement required for unit

shutdown.

During the interviews, the fire brigade members informed the team that they

maintained their medical certification by attending a yearly .nedical examination.

The

team considered the scheduling of these physical examinations was proactive in that fire

brigade members were notified 45 days to 60 days prior to the examination date.

Any

fire brigade member who missed this examination was removed from the fire brigade

until the medical examination was conducted.

Fire brigade members were required to participate in at least two fire drills each year.

The team noted, during the records review, that the members participated in more than

two fire drills each year. The team observed one fire drill conducted on the evening of

July 29, 1998. The fire drill was conducted and monitored by fire protection personnel,

-34-

including the fire marshall.

The team observed that the fire brigade was fullycapable of

mitigating the fire. The team observed a critique after the fire drill, conducted by the fire

marshall.

Based on these observations,

the team determined that the fire drill was

satisfactory and provided confidence that the fire brigade was properly trained.

The team reviewed the fire brigade training records on seven individuals who were

currently qualified on the fire brigade.

The team noted that these training records were

complete and accurate.

The team conducted a walk down with the licensee of the essential fire fighting systems

consisting of the fire pumps, piping systems, fire hose stations, fire detection systems,

and fire barriers.

During this walk down, the team noted that all fire pumps were

.

operable, piping systems were painted and maintained in good condition, and that the fire

hose stations were fullyoperable with tools attached for opening valves and attaching

hoses.

In addition, the team determined that the fire detection systems and fire barriers

were operable.

The team also conducted an independent walk down of selected areas

in the plant, including the Division 2 Diesel Generator room. The team determined that

fire extinguishers were inspected, charged, and pressurized for use and that transient

combustibles were adequately controlled. The team noted that the fire detectors were

operable and being properly maintained via surveillance procedures.

Qs

The NRC issued a Confirmatory Order modifying the WNP-2 License on March 25, 1998.

This Confirmatory Order requires'that Thermo-Lag barrier modifications be completed

during the R14 refueling outage (Spring 1999) and that all modification package closeout

be completed by December 1999. The licensee stated that the Thermo-Lag Reduction

effort was not currently on schedule and were considering means to assure that the order

requirements were met.

Conclusions

The team concluded that fire equipment was being properly tested at the required

frequencies.

No discrepancies were noted during a walk down of the fire protection

system.

Fire pumps, piping systems, and fire hose stations were being properly

maintained.

Fire detection systems were in service and fire extinguishers were being

inspected and maintained ready for operation.

Fire hose stations were also properly

equipped and ready for use.

The team also concluded that the fire protection equipment

was being upgraded as necessary.

The fire brigade was properly trained and qualified to perform fire fighting, and the annual

medical examination requirement was being met.

F3

Fire Protection Procedures and Documentation (64704)

Ins ection Sco

e

The team reviewed procedures and documentation related to the fire protection program

to evaluate the overall adequacy and implementation of the licensee's

Fire Protection

-35-

Program.

This review included seven procedures related to the licensee's approved Fire

Protection Program.

Observations and Findin s

The team reviewed procedures concerning the fire protection program implementation

including control of transient combustibles, control of ignition sources, plant fire

protection program implementation, and fire barrier impairment.

The introduction of transient combustibles into plant areas during routine operation and

maintenance

activities and the storage of combustibles in plant areas were governed by

Procedure 1.3.10C, "Control of Transient Combustibles," Revision 0. This procedure

delineated the responsibilities and procedural guidance for general combustible material

control criteria, initiating transient combustible (TC) permits, extending TC permits, and

clearing the TC permits. The team determined that this procedure was comprehensive

for controlling transient combustibles.

The installation of permanent combustible

materials was controlled by the design control process.

The team determined that the control of ignition sources was governed by

Procedure 1.3.10A, "Control of Ignition Sources," Revision 3. This proc'edure delineated

the responsibilities and guidelines for the use of ignition sources.

The team noted that

the requirements for the uses of ignition sources were comprehensive.

For example, the

procedure identified what situations required a fire watch assignment,

ensured that fire

protection system impairments would be closed upon work completion, and ensured that

a final inspection of the work area was performed upon termination of the fire watch and

ignition source permit.

Conclusions

The team concluded that the fire protection program procedures were comprehensive

in

detailing the requirements for transient combustibles, barrier impairments, and control of

ignition sources.

Quality Assurance in Fire Protection Activities (64704)

Ins ection Sco

e 64704

The team reviewed the licensee's Quality Assurance activities in the fire protection

program.

These activities included the performance of periodic fire prevention/protection

audits, the identification and resolution of fire protection discrepancies,

the review of fire

system/equipment

changes and alterations, and the review of periodic surveillance

activities to ensure that they were being conducted as required by the fire protection

program.

The team reviewed two periodic audits conducted by the Quality Assurance Department.

These were the 1998 Annual Fire Protection Audit and the 1997 Annual-Biennial-

Triennial Audit.

-36-

'bservations

and Findin s

The team reviewed the 1998 Annual Fire Protection Audit conducted during March 16

through March 31, 1998. This audit concluded that the fire protection program was being

adequately implemented to meet the requirements and assure safety of the plant and

personnel.

The audit determined that the corrective actions taken with respect to fire

protection related problems were evaluated and noted to be effective in preventing

significant adverse trends.

The fire fighting and protection training were judged to be

adequate.

The team agreed with the 1998 Annual Audit findings. The team determined that the

corrective action program with respect to fire protection was notable in that it prevented

the recurrence of events.

The audit determined that 65 problem evaluation requests

were identified since January 1997 for fire protection issues.

The audit then categorized

the problem evaluation reports into groups of common problem types and reviewed them

for increasing trends in the number and severity. The audit determined that there were

no adverse trends.

During the audit review of problem evaluation reports, the licensee identified that several

open corrective action items were over 1-year old. A detailed review of these older

actions determined that the safety of the plant was not being compromised because of

the age of these items. The licensee determined that the these items were in two

categories:

(1) equipment replacements

being done on a planned schedule and

(2) enhancements

and clarifications to documentation.

The audit determined that an

average of three extensions had been, granted with the oldest action item nearly 3 years

old. The Quality Assurance Department initiated a Quality Recommendation 298-013-A

to review the timeliness of open corrective actions.

The fire protection manager reviewed

the current list of fire protection corrective actions and provided a justification for each

item. This review indicated that the scheduled dates were appropriate and that the risk

of problem recurrence was negligible.

The team reviewed Quality Recommendation 298-013-A and the fire protection

manager's response and determined that this action was appropriate.

The audit also included an assessment

of the fire fighting and fire brigade training

program and concluded that the training was adequate with no programmatic

deficiencies.

The most significant issue identified was that the fire brigade had not been

recently trained on rope signals, hand signals, or shoulder tapping. The Quality

Assurance Department issued Quality Recommendation 298-013-B, which

recommended

the addition of communications in fire brigade training.

In response to this issue, the fire department training manager revised the training lesson

plans, classroom, and practical exercise training to include communications.

The team

verified that the revised training had included the use of communication skills.

The team reviewed the 1997 Annual-Biennial-Triennial Fire Protection Audit conducted

May 22 through June 12, 1997, and determined that it was comprehensive

and that it

satisfied the requirements for assessing

fire protection equipment and program

-37-

implementation requirements.

The team agreed with the 1997 audit's findings.

The

1997 audit identified strengths in the following areas:

The training and commitment of fire protection personnel,

The fire penetration seal program,

Implementation and control of fire watch tours,

Material condition of the fire fighting equipment, and

Use of an independent consultant to conduct the fire program self assessment.

c.

Conclusions

The team concluded that both Quality Assurance audits were comprehensive and

satisfied the requirements for assessing

fire protection equipment and program

implementation requirements.

The team agreed with the findings and recommendations

of both audits.

Several strengths identified in the 1997 audit by the licensee were

confirmed by the team during this inspection, especially fire personnel knowledge and

skill, and excellent material condition of the fire fighting equipment.

V. Management Meetings

X1

Exit Meeting Summary

The team met with licensee representatives

on July 31, 1998, to conduct an exit

interview. During this meeting, the team leader noted that team personnel had reviewed

proprietary documentation during the course of the inspection.

Proprietary

documentation was not divulged in this report.

The licensee acknowledged the team's findings.

-38-

ATTACHMENT1

SUPPLEMENTAL INFORMATION

PARTIALLIST OF PERSONS CONTACTED

Licensee

G. Barstas, l&C Design Engineer

R. Brownlee, Licensing Engineer

D. Beach, l8C Design Supervisor

D. Coleman, Regulatory Affairs Manager

R. Ehr, Lead Mechanical & Civil Engineer

M. Ferry, NSSS System Engineer

S. Ghbein, Project Engineer

R. Green, I8C Design Engineer

D. Mand, Manager, Design & Projects Engineering

L. Pong, Supervisor Performance Engineering

G. Richmond, l8C System Engineer

R. Seidl, l8C System Engineer

M. Schmidtz, NSS System Engineer

NRC

S. Boynton, Senior Resident Inspector

64704

37550

92903

93809

INSPECTION PROCEDURES USED

Fire Protection

Engineering

Followup - Engineering

Safety System Engineering Inspection (SSEI)

ITEMS OPENED CLOSED AND DISCUSSED

~Oened

50-397/9815-01

VIO

The design basis for CST capacity and reactor vessel water

Level 1 was not correctly translated into the plant design and

the Technical Specifications respectively (Sections E1.1.1

and E1.2).

50-397/9815-02

VIO

Procedures were not adequately followed or established for

marking Category

1 and 2 PAM instruments, verifying short

circuit calculation assumptions and controlling calculation

modification records (Sections E1.2, E1.3 and E8.5).

50-397/9815-03

VIO

A dc breaker coordination design deficiency was not promptly

corrected (Section E1.3).

50-397/9815-04

URI

The establishment of appropriate leak testing for liquid

secondary containment bypass valves requires NRC review

of the method for calculating release fraction (Section E2.3)

50-397/9815-05

VIO

The thermal performance test acceptance

criterion for the

Division 3 Diesel Generator Heat Exchanger DCW-HX-1C

was not valid for all expected HPCS standby service water

flows (Section E2.4).

50-397/9815-06

50-397/9815-07

'IO

Surveillance Requirement 3.8.4.7, the Division 2 Battery

service test, was not completed within the specified frequency

as required by Technical Specification 3.0.2 (Section E2.6).

NCV

.

The requirement for Valve RHR-V-'40 to close for secondary

containment isolation and to establish the emergency cooling

system lineup specified in the FSAR,was not correctly

translated into drawings (Section E8.4).

Closed

50-397/9713-01

VIO

Inadequate Corrective Actions (Section E8.1) ~

50-397/9713-02

50-397/9713-03

VIO

Failure to Maintain Acceptance Criteria and lnservice Testing

of RCIC System Valves (Section E1.2).

VIO

Inadequate Safety Evaluation for RCIC Downgrade (Section

E1.3).

50-397/9713-04

IFI

Potential for Numerous Calculation Modification Records to

AffectTechnical Content of Calculations (Section E8.5).

50-397/98-005

50-397/9815-03

LER

Voluntary LER on RHR Valve Design Deficiency (Section

E8.4).

VIO,Adc breaker coordination design deficiency was not promptly

corrected (Section E1.3).

'2-

50-397/9815-05

VIO

The thermal performance test acceptance

criterion for the

Division 3 Diesel Generator Heat Exchanger DCW-HX-1C

was not valid for all expected HPCS standby service water

flows (Section E2.4).

50-397/9815-06

50-397/9815-07

VIO

Surveillance Requirement 3.8.4.7, the Division 2 battery

service test, was not completed within the specified frequency

as required by Technical Specification 3.0.2 (Section E2.6).

NCV

The requirement for Valve RHR-V-40 to close for secondary

containment isolation and to establish the emergency cooling

system lineup specified in the FSAR was not correctly

translated into drawings (Section E8.4).

LIST OF ACRONYMS USED

ac

CFR

gpm

HFES

HPCS

IFI

LER

LO~A

alternating current

Code of Federal Regulations

calculation modification record

condensate

storage tank

direct current

diesel generator

emergency core cooling system

Final Safety Analysis Report

gallons per minute

human factors engineering standard

high pressure core spray

inspection followup item

licensee event report

loss-of-coolant accident

low pressure coolant injection

low pressure core spray

motor operated valve

net positive suction head

problem evaluation request

-3-

psl

psia

psld

pslg

plant modification request

pounds per square inch

pounds per square inch absolute

pounds per square inch differential

pounds per square inch gage

RCIC

reactor core isolation cooling

RHR

residual heat removal system

SBLOCA

small break loss-of-coolant accident

scfh

SSEI

standard cubic feet per hour

safety system engineering inspection

TS

Technical Specification

URI

USQ

unresolved item

unreviewed safety question

VIO

violation

DOCUMENTS REVIEWED

SAFETY EVALUATIONS

NUMBER

DESCRIPTION

95-101

FSAR Section 6.2, Containment Systems

97-087-0

Basic Design Change BDC-96-0139-OA

REVISION

December 13, 1995

March 19, 1998

PROBLEM EVALUATIONREPORTS

NUMBER

DESCRIPTION

298-0928

FSAR Value for Secondary Containment Bypass

Leakage Limitis Inappropriately being Applied to

Liquid Leakage Bypass Paths

REVISION

July 28, 1998 (Draft)

298-0407

OER per INPO Network Operating Event OE8933,

April21, 1998

RHR Pump Bearing Support Bracket Failure

298-0899

Results of Calculation E/l-02-91-1011

(HPCS-LS-1 A, -1B) Not Incorporated into

Calculation 5.52.070 (CST Setpoints)

July 17, 1998

-4-

0

PROBLEM EVALUATIONREPORTS

NUMBER

DESCRIPTION

298-0959

DCW-HX-1C Thermal Performance Monitoring

Acceptance Criteria is Non-Conservative

REVISION

July 30, 1998

292-0409

Inadequate Coordination Identified in Calculation

E/I-02-91-07

Revision 0

298-0034

Permanent Corrective action

298-0421

298-0887

Potential for RHR-V-40 To Not close if Throttled

Partially Open

125 Volt Division 2 Battery E-B1-2 Surveillance SR 3.8.4.7 Was Not Adequately Performed

Revision

1

Revision 0

298-0961

298-0985

Timely Completion of Corrective Action Associated

with PER 292-0409

Plant Modification Record (PMR) 86-0362-0

Implementation Omitted Revising Voltage Drop

Calculation 2.07.04 for DLO-M-P/10

Revision 0

PROCEDURES

NUMBER

5.5.13

4.4.4.2

2.4.4

2.4.5

7.4.7.1.1.3

OSP-SW-M103

8.4.63

SAG-1

DESCRIPTION

Overriding HPCS High RPV Level Isolation

Interlock

Inadvertent HPCS Startup

High Pressure Core Spray System

Standby Service Water System

HPCS Service Water Valve Position Verification

(Data from May 17, 1996)

HPCS Service Water Valve Position Verification

(Data from June 16, 1997)

HPCS Service Water Valve Position Verification

(Data from May 12, 1998)

Thermal Performance Monitoring of

DCW-HX-1C (Data from February 23, 1998;

March 14, 1997; and February 12, 1998)

Severe Accident Guidelines

REVISION

Revision 4

Revision 9

Revision 20

Revision 38

Revision 12

Revision 0

Revision 2

Revision 5

Revision 0

-5-

0

PROCEDURES

NUMBER

., SAG-2

5.1.1

5.1.2

5.1.3

5.1.4

5.1.5

5.1.6

5.2.1

5.3.1

5.4.1

5.6.1

DESCRIPTION

Severe Accident Guidelines

RPV Control

RPV Control - ATWS

Emergency RPV Depressurization

RPV Flooding

Emergency RPV Depressurization

- ATWS

RPV Flooding - ATWS

Primary Containment Control

Secondary Containment Control

Radioactivity Release Control

Station Blackout (SBO)

OSP-SW/IST-Q703

OSP-HPCS/IST-R701

HPCS Service Water Operability

HPCS Check Valve Operability - Refueling

Shutdown

OSP-HPCS/IST-Q701

HPCS System Operability Test

REVISION

Revision 0

Revision 13

Revision 14

Revision 15

Revision 5

Revision 3

Revision 12

Revision 13

Revision 11

Revision 5

Revision 3

Revision

1

Revision

1

TSP-RV/IST-R701

2.8.6

2.7.3

4.601.A1

7.4.7.1.28

OSP-SW-M103

OSP-SW-M102

SWP-FPP-01

PPM 1.3.10

Testing of IST Program Safety/Relief Valves

Condensate

Storage and Transfer System

High Pressure Core Spray 2', sel Generator

601.A1 Annunciator Panel Alarms

HPCS Service Water Flow Balance (Data from

June 13, 1993; December 27, 1993; March 24,

1994; June 14, 1994; March 22, 1995; April1,

1995; and May 23, 1995)

Standby Service Water Loop A Valve Position

Verification

Standby Service Water Loop B Valve Position

Verification

Nuclear Fire Protection

Program

Plant Fire Protection Program Implementation

Revision

1

Revision 12

Revision 31

Revision 11

Revision 0

Revision 4

Revision 2

Revision 0

Revision 21

-6-

0

PROCEDURES

NUMBER

PPM 1.3.10A

PPM 1.3.10B

P

PM 1.3.10C

PPM 1.3.19

PPM 1.3.57

PPM 15.1.1

PPM 15.1.2

PPM 15.1.3

PPM 15.1.4

PPM 15.1.5

PPM 15.1.6

PPM 15.1.14

PPM 15.1.15

PPM 15.1.16

PPM 15.1.18

PPM 15.1.19

PPM 15.1.20

PPM 15.1.23

PPM 15.2.1

PPM 15.2.2

PPM 15.2.6

PPM 15.2.7

PPM 15.2.14

PPM 15.2.16

DESCRIPTION

Control of Ignition Sources

REVISION

Revision 3

Active Fire System Op. and Impairment Control

Revision

1

Control of Transient Combustibles

Plant Material Condition Inspection

Program

Barrier Impairment

Fire Suppression

Systems Inspection

Fire Door Operability

FP-P-1 Monthly Operability Test

FP-P-110 Monthly Operability Test

FP-P-2A Monthly Operability Test

FP-P-2B Monthly Operability Test

Pre-action and Deluge Systems Flow Switch

Revision 0

Revision 23

Revision 11

Revision 8

'evision 10

Revision 9

Revision 4

Revision 6

Pre-action Systems Trip Test

Protected Area & Warehouse Sprinkler Sys.

Test

Monthly Fire Pump Battery Testing

Function and Sensitivity Check of Ionization

Detect.

Revision 8

Revision 4

Revision 5

Revision 7

HVAC Duct Detectors-Channel

Functional Test

Revision 7

Zone 22, 23, 25, and 26 HVAC Duct Smoke

Detect.

Function Check, Sensitivity Check and Cleaning

of Photoelectric Detectors

Thermal Detectors-Channel

Functional Check

Revision 4

Wet Pipe Sprinkler Flow Switch Functional Test

Revision 9

Protected Area Suppression Systems Inspection

Revision 3

Quarterly Fire Suppression

Systems Valve Align.

Revision 9

Fire Protection System Annual Flowpath Valve

Revision 8

Exer.

-7-

0

I

PROCEDURES

NUMBER

DESCRIPTION

REVISION

PPM 15.2.25

PPM 15.3.5

PPM 15.3.7

PPM 15.3.9

PPM 15.3.10

PPM 15.3.13

Fire Damper Operational Inspection

Fire Systems Inspection

Fire Pump Drive Inspection FP-ENG-1

Fire Pump Drive Inspection FP-ENG-110

Interior Deluge Systems Trip Test and Air Flow

Test

Revision 7

Revision 5

Revision 6

Revision 3

Revision 5

Manual Pull Stations-Channel

Functional Check

Revision 5

PPM 15.3.14

PPM 15.4.6

Exterior Deluge Systems Trip Test and Strainer

Flush

Fire Rated Pene.

Seal & Structural Fire Barrier

Operability Inspection

Revision 7

Revision 4

PPM 1.3.43

MMP-DG3-B103

Licensing Basis Impact Determinations

Diesel Generator DG-3 Mechanical Inspection

TSP-DG3/LOCA-B501

HPCS Diesel Generator DG3 LOCA Test

Revision 13

Revision

1

Revision 0

CALCULATIONS

NUMBER

DESCRIPTION

5.19.13

Sizing of HPCS Emergency Water Volume

CMR-94-1160

Calculation Modification Record for

Calculation 5.19.13, Revision 5

REVISION

Revision 5

December 19, 1994

C MR-97-0003

NE-02-90-50

E/I-02-91-1018

CMR-94-1162

E/I-02-91-1011

CMR-96-0007

Calculation Modification Record for

Calculation 5.19.13, Revision 5

HPCS System Analysis

Setting Range Determination for Instrument

Loops: HPCS-LS-3A and HPCS-LS-3B

Calculation Modification Record for

Calculation E/1-02-91-1018, Revision 0

Setting Range Determination for Instrument

Loops: HPCS-LS-1A and HPCS-LS-1B

Calculation Modification Record for

Calculation E/1-02-91-1011, Revision 0

April 17, 1997

Revision

1

Revision 0

November 16, 1994

Revision 0

January 15, 1996

-8-

'i

CALCULATIONS

NUMBER

5.52.070

ME-02-82-03-0

CMR-91-0110

DESCRIPTION

Setpoints - CST System

Strainer Plugging Due to Containment

Coating in Suppression

Pool Post-LOCA

Calculation Modification Record for

Calculation ME-02-82-03-0, Revision 0

REVISION

Revision 0

May 2, 1991

ME-02-90-17

CMR-98-0179

Calculation Modification Record for

Calculation ME-02-90-17, Revision 0

July 23, 1998

Pressure

Drop Verification for HPCS System

Revision 0

5.19.11

CMR-94-0142

CMR-96-0225

CMR-97-'0115

NE-02-82-44

ME-02-96-21

C106-92-03.02

5.19.08

10.04.72

5.19.14

5.19.10

High Pressure Core Spray System - Pressure

Drop Calculations

Calculation Modification Record for

Calculation 5.19.11, Revision 4

Calculation Modification Record for

Calculation 5.19.11, Revision 4

Calculation Modification Record for

Calculation 5.19.11, Revision 4

Suppression

Pool Temperature Versus Pump

Flows of HPCS, LPCS, RCIC and RHR-

Systems

MOV Pressure

Locking Calculation

WNP-2 HPCS System MOV Design Basis

Review

High Pressure Core Spray System-

Restrictors

WPPSS NP ¹2 Analysis Vortex Formation at

the HPCS/RCIL Suction Inlets in the

Condensate

Storage Tanks

NPSH of HPCS Pump - Maximum Allowable

Suppression

Pool Temperature.

High Pressure Core Spray System - ECCS

Minimum NPSH Calculations - Reg.

Guide

1.1, Rev. 0

Revision 4

May 4, 1994

July 23, 1996

July 18, 1997

Revision 0

Revision 2

Revision 0

9

CALCULATIONS

NUMBER

CMR-94-0229

CMR-95-0692

C MR-96-0227

CMR-97-0207

NE-02-83-09

ME-02-92-243

DESCRIPTION

Calculation Modification Record for

Calculation 5.19.10, Revision 0

Calculation Modification Record for

Calculation 5.19.10, Revision 0

Calculation Modification Record for

Calculation 5.19.10, Revision 0

Calculation Modification Record for

Calculation 5.19.10, Revision 0

LI QSS - HPCS System Flow Recirculation

DCW-HX-1C Design Performance

Requirements

REVISION

April 27 1994

November 14, 1995

July 23, 1996

July 18, 1997

Revision 0

ME-02-92-242

DCW-HX-1C Performance Evaluation

Revision 0

ME-02-92-243

NE-02-89-25

ME-02-91-26

CMR-91-0162

CMR-92-0469

8.14.64B

ME-02-92-244

CMR-94-1104

DCW-HX-1C Design Performance

Requirements

Vortex Limitat Intake Strainer of Pump for

HPCS, LPCS, RCIC, and RHR Systems

HPCS Test Line Orifice Installation

Calculation Modification Record for

Calculation ME-02-91-26, Revision 0

Calculation Modification Record for

Calculation ME-02-91-26, Revision 0

HPCS System M200 Sht 100 & 132 AG 68

Piping Analysis

Minimum Heat Transfer Required for DCW,

Heat Exchangers A & B

Calculation Modification Record for

Calculation ME-02-92-244, Revision 0

Revision 0

Revision

1

Revision 0

June 19, 1991

November 2, 1992

Revision 10

Revision 0

November 9, 1998

ME-02-92-245

RHR Heat Exchanger Tube Side Flowrate and

Revision 0

Inlet Temperature Evaluation

CMR-97-0010

Calculation Modification Record for

Calculation ME-02-92-245, Revision 0

January 14,1998

Ell-02-85-02

High Pressure Core Spray Battery and Battery

Revision

1

Charger

-10-

CALCULATIONS

NUMBER

DESCRIPTION

E/I-02-91-06

E/I-02-92-01

Short Circuit Calculation for the 250V, 125V,

and 24 V D.C. Systems

F

Fuse Coordination Study for DC Power

Distribution Systems

REVISION

Rewsion 0

Revision 0

E/I-02-87-07

E/I-02-90-01

E/I-02-95-01

2.07.04

2.12.58

ME-02-92-74

ME-02-92-75

ME-02-92-78

ME-02-92-79

ME-02-92-80

ME-0292-234

E/I-02-93-04

E/I-02-91-03

WNP-2 Plant Main Bus Voltage Calculation

Low Voltage Systems Loading and Voltage

Calculations

Overcurrent Protective Device Settings and

Coordination Calculations for 480 Volt

Distribution Systems

D.C. Cable Voltage Drop

2nd Level Undervoltage Relay Settings for

Buses SM-7, SM-8, and SM-4

Calculation for Thrust & Setpoint for HPCS

Motor Operator Valve 1

Calculation for Thrust & Setpoint for HPCS

Motor Operator Valve 4

Calculation for Thrust & Setpoint for HPCS

Motor Operator Valve 12

Calculation for Thrust & Setpoint for HPCS

'otor

Operator Valve 15

Calculation for Thrust & Setpoint for HPCS

Motor Operator Valve 23

On Site Diesel Fuel Storage for the

Emergency Diesel Generators DG-1, DG-2,

and DG-3.

Overcurrent Protection of Primary

containment Electrical Penetrations

Div.1, Div. 2, and Div. 3 Diesel Generator

Loading Calculations

Revision 3

Revision 4

Revision 0

Revision 5

Revision 4

Revision 0

Revision

1

Revision 2

Revision 0

Revision 2

Revision 6

-11-

CALCULATIONS

NUMBER

DESCRIPTION

02.06.20

'able Ampacity Verification Calculations for

Conduit &Tray

REVISION

Revision 3

E/1-02-87-02

480V MCC Load Data for LOCA Operation

Revision 6

E/I-02-86-05

E/I-02-85-07

E/I-02-87-03

E/l-02-92-13

E/I-02-92-09

E/I-02-85-08

6.9KV, 4.16KV, and 480V Motor Load Data

for Normal Full Load Operation

480V MCC Load Data for Normal Full Load

Operation

4.16KV and 480V Motor Load Data for LOCA

Operation

Short Circuit Current Calculation for 480V

Systems

Short Circuit Current Calculation for 4.16 and

6.9 KV Buses

Generators, Transformers, and Branch Data

for WNP-2 Distribution Systems

Revision 4

Revision 10

Revision 2

Revision 0

Revision 7

DESIGN CHANGES

NUMBER

" DESCRIPTION

BDC No.

ECCS Suction Strainer Replacement

96-0139-OA

REVISION

Revision 0

LICENSING DOCUMENT CHANGE REQUESTS

NUMBER

DESCRIPTION

95-072

SAR/Technical Specification Basis Change Notice

Form - FSAR 6.2.3.2, 6.2.3.3.2, Table 6.2-1 6,

15.6.5.5.1.2, and 312.017

REVISION

Revision 0

DRAWINGS

NUMBER

DESCRIPTION

REVISION

Drawing M520

Flow Diagram HPCS and LPCS Systems - Reactor

Revision 83

Building

-12-

Drawing M527

Drawing M524,

Sheet

1

Flow Diagram Condensate

Supply System - All

Buildings

Flow Diagram Standby Service Water System-

Reactor, Radwaste,

D.G. Buildings and Yard

Revision 90

Revision 96

Drawing

Local Instrument Installation Storage Tank Area El

D-220-3500-070.

441'-0" COND-LT40

0 COND-LT40,

Sheet 3

Revision

1

MISCELLANEOUS DOCUMENTS

NUMBER

DESCRIPTION

REVISION

Audit 298-013

Audit 297-040

WNP-2 Annual Fire Protection Audit- 1998

Revision 0

WNP-2 Annual-Biennial-Triennial Audit-

Revision 0

1997

Technical

Evaluation Report

94-0348

Hanger installation Fire Protection Line

FP-V-642

Revision 0

Surveillance Report

Diesel Fire Pump ¹1 MufflerReplacement

Revision 0

297-054

I

Plant Modification

Record 91-0379

Delete RWCU Room Fire Detection

Sensors

Revision 0

Plant Modification

Record 89-0429

PTL No. 135936

Letter G02-98-002

Letter GO2-96-199

Addition of Manual Pull Station in Service

Revision 0

Building, Machine Shop

Operating Experience Report Disposition

Form - IEN96055 - Inadequate Net

Positive Suction Head of Emergency Core

Cooling and Containment Heat Removal

Pumps under Design Basis Accident

Conditions

January 13, 1997

90-Day Response

to Generic Letter 97-04

January 5, 1998

- WNP2 to NRC

Request for Amendment to Secondary

October 15, 1996

Containment and Standby Gas Treatment

System Technical Specifications - WNP2

to NRC

-13-

MISCELLANEOUS

NUMBER

DOCUMENTS

DESCRIPTION

REVISION

OER Action

Tracking No.

81032H

Operating Experience Review Summary -

October 24, 1991

IEN91056- Potential Radioactive Leakage

to Tank Vented to Atmosphere

23A1619AA

General Electric Design Specification Data

Sheet - High Pressure Core Spray System

Revision 12

RP03

IST Program Plan Relief Request

TM-2099

Technical Memorandum - Secondary

Containment Bypass Leakage

FSAR Section 6.2

Containment Systems

Revision

1

Amendment 52

Revision 0

Technical Specification 3.5

Technical

Specification Basis

3.5

PER No. 294-0074

Section 308

82-RSY-0900-T3

Letter GO2-97-218

Letter GI2-90-009

SS2-P E-89-0646

Emergency Core Cooling Systems

(ECCS) and Reactor Core Isolation

Cooling (RCIC) System

Emergency Core Cooling Systems

(ECCS) and Reactor Core Isolation

Cooling (RCIC) System

Follow-up Assessment

of Operability - The

Presence of High Pressure Trapped

between the Valve Seats Could Lock the

Valves in the Closed Position and Prevent

the Valves from Performing their Opening

Safety Functions.

Design Specification for High Pressure

Core Spray System

License Training System Description for

High Pressure Core Spray System

Request for Amendment to Secondary

Containment and Standby Gas Treatment

System Technical Specifications

(Additional Information) - WNP2 to NRC

EValuation of JCO Regarding Standby

Gas Treatment System Attainment of

Secondary Containment Pressure

(TAC

No. 75048) - NRC to WNP2

Interoffice Memorandum - Potential

Bypass Leakage and Unmonitored

Effluent Paths

-14-

Amendment 150

Revision 7

June 17, 1997

Revision 4

Revision 8

December 4, 1997

January 3, 1990

June 22, 1989

MISCELLANEOUS DOCUMENTS

NUMBER

DESCRIPTION

82-RSY-1400-T3

7.4.5.1.11

License Training System Description for

Standby Service Water System

Record of Reference Values and

Acceptance Criteria Changes for ASME

Pumps and Valves

REVISION

Revision 9

April20, 1992

IST Program Plan

Division 60

FSAR Figure 6.3-1

FSAR Section

15.6.5.5.1.2

Technical Specification 3.7.1

Section 309

FSAR Section

~

6.3.2.2.1

FSAR Table 9.2-5

LER 98-005

IST Program Plan - 2nd 10-Year Interval

Design Specification for Reactor Core and

System Analysis for WNP-2

Head Versus High Pressure Core Spray

Flow Used in LOCA Analysis

Fission Product Transport to the

Environment

Standby Service Water (SW) System and

Ultimate Heat Sink (UHS)

Design Specification for Standby Service

Water System

High Pressure Core Spray (HPCS)

System

Standby Service Water Flow Rates and

Associated Heat Loads Used in the

Ultimate Heat Sink Analysis

Potential for Failure of Residual Heat

Removal System Valve to Close on an

Isolation Signal

Revision

1

Revision 9

Amendment 51

Amendment 30

Amendment 149

Revision 2

Amendment 51

Amendment 52

Revision 0

WOT KKB9, Task

01

WNP-2 Document

Review of Approved 50.59 Safety

Evaluations for the Use of Generic

Guidance Final Report

3/1 6/98

MMP-RCIC/IST-F701 RCIC-RD-1 and RCI

May 1, 1998

WOT LFF6, Task

01

WNP-2 Document

RHR-MO-40 Install Modification

IST Program Plan - 2nd 10-Year Interval

'Pages

94,95,96, and 96a)

5/22/98

Revision

1

-15-

MISCELLANEOUS DOCUMENTS

NUMBER

DESCRIPTION

WNP-2 Document

Licensing Basis Impact Determination

ESOOOOOS

Update Training - Presentation

Guide

REVISION

Revision 4

-16-

ML17284A806

Text

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