ML17059A244

Insp Rept 50-410/93-81 on 931129-940128.Violation Noted. Major Areas Inspected:Functionality of Plant,Unit 2 Electrical Sys

ML17059A244
Person / Time
Site:	Nine Mile Point
Issue date:	03/20/1994
From:	Cheung L, Ruland W NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I)
To:
Shared Package
ML17059A243	List: ML17059A242 ML17059A244
References
50-410-93-81, NUDOCS 9403290028
Download: ML17059A244 (58)

See also: IR 05000410/1993081

Text

U.S. NUCLEAR REGULATORY COMMISSION

REGION I

REPORT/DOCKET NO.

LICENSE NO.

LICENSEE:

FACILITYNAME:

INSPECTION DATES:

50-410/93-81

NPF-69

Niagara Mohawk Power Corporation

Nine Mile Point Unit 2

November 29, 1993 through December

17, 1993,

and January 24-28, 1994

'RC

CONSULTANTS:

J. Hailer, Electrical Engineer

M. Shlyamberg, Mechanical Engineer

TEAMLEADER'eonard

S. Cheung, Sr.

eactor Engineer

Electrical Section, EB, DRS

Date

APPROVED BY:

William H. Ruland, Chief, ES, EB, DRS

ggo F

Date

9403290028

940322

PDR

ADOCK 050004i0

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the functionality of Nine Mile Point Unit 2 electrical distribution system.

R~e~ul:

As described in the Executive Summary.

TABLE OF CONTENTS

~Pa

e No.

EXECUTIVE SUMMARY

1V

1.0

INTRODUCTION

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2.0

2.3

2.4

2.5

2.6

2.7

2.8

2.9

2.10

ELECTRICAL SYSTEMS

2.1

Offsite Power and Grid Configuration..............

2.2

Bus Alignment During Startup, Normal Power and Shutdown

Ope rations

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Bus Transfer Schemes

Class 1E AC Power Systems

Emergency Diesel Generator

Degraded Voltage Protection Schemes for Class 1E Buses

2.6.1

First Level Voltage Protection ..............

2.6.2

Second Level Voltage Protection

Class 1E 120 VAC System

Class 1E 125 VDCSystems....................

Class 1E AC Power System Equipment.............

COnClUSlon

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3.0

MECHANICALSYSTEMS

3.1

Power Demands for Major Loads

3.2

Diesel Generator and Auxiliary Systems

3.3

Heating, Ventilation, and Air Conditioning (HVAC) Systems

3

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COnCluS10nS

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4.0

ELECTRICALDISTRIBUTIONSYSTEM EQUIPMENT

4.1

Equipment Walkdowns .................

4.2

Electrical Equipment Maintenance and Testing

4.2.1

Emergency Diesel Generator Testing ....

4.2.2

Station Batteries.................

4.2.3

Relay Testing

4.3

Conclusions........................

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5.0

REVIEW OF NMPC's SELF-ASSESSMENT OF ELECTRICAL

DISTRIBUTIONSYSTEM.......................

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6.0

UNRESOLVED ITEMS

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7.0

XITMEETING

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ATTACHMENT 1 - Persons

Contacted

ATTACHMENT2 - Abbreviations

ATTACHMENT3 - Nine Mile 2 Electrical Distribution System

111

EXECUTIVE SUMMARY

During the period between November 29, 1993, and January 28, 1994, a Nuclear Regulatory

Commission (NRC) inspection team conducted

an electrical distribution system functional

inspection (EDSFI) at the Nine Mile Point Unit 2 (NMP2). The inspection was performed to

determine the adequacy of the Niagara Mohawk Power Corporation (NMPC) self-assessment,

and whether the electrical distribution system (EDS) at NMP2 was capable of performing its

intended safety functions as designed,

installed,"and configured.

This inspection also

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included a review of NMPC response

to the deficient condition that the high pressure core

spray (HPCS) system injection valve failed to open during testing as reported in licensee

event report (LER) 93-10.

The team reviewed the NMPC self-assessment

reports and selected questions and responses,

including an independent review conducted by a contractor.

NMPC's self-assessment

covered a scope similar to an NRC EDSFI, and identified 57 open items and 43 observations

during the course, of the inspection.

Based on these open items, NMPC initiated 52

deviation/event reports (DERs).

Based on these findings, the team determined that NMPC's

self-assessment

was comprehensive

and of high quality.

Three NRC findings were not

identified by the NMPC inspection team.

These findings are:

1) there was insufficient

evidence that the capacity of the day tanks and storage fuel oil tanks met the final safety

analysis report (FSAR) commitment; 2) the emergency diesel generators

were tested above

their two-hour ratings; and 3) lack of an analysis of the impact of the uninterruptible power

supplies output voltage total harmonic distortion (THD) in excess of 5% of the fundamental.

In addition, there were two significant deficiencies that were also missed by the NMPC self-

assessment

EDSFI, but were later identified and corrected by NMPC:

1) incorrect tap

setting on the 4160-600V transformer which served the HPCS system auxiliaries, and 2)

inadequate pickup voltage characteristics of motor starter contactors for the HPCS system

motor-operated valves (MOVs). However, the NRC findings and the deficiencies that were

identified later by NMPC were, in the team's opinion, a rare exception, rather than a lack of

indepth, comprehensive review by the NMPC self-assessment

team.

The team selected samples from the EDS in the electrical and mechanical design, and

maintenance and test areas for independent review.

The scope included a plant walkdown,

technical reviews of studies, calculations, design drawings, and station procedures pertaining

.to the EDS.

Interviews were conducted of corporate and plant personnel.

Based on the sample documents reviewed and equipment inspected,

the team concluded that

the electrical distribution system at Nine Mile Point Unit 2 is capable of performing its

intended functions, and that NMPC's actions in response to the deficient condition that the

HPCS system injection valve failed to open during testing, were appropriate.

However, the

team determined that this deficient condition constitutes an apparent violation of Technical Specifications, Section 3.5.1, Item C, as discussed

in paragraph 2.9 of this inspection report.

The team identified three unresolved items; one in the electrical design area, one in the

mechanical design area, and one in the electrical equipment test area.

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Discussed

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HPCS System Inoperable

2.9

Three

nres Ived Item

Item Number

EEI93-81-04

UPS output voltage THD

2.7

greater than 5% of the

fundamental

50-410/93-81-01

EDG fuel oil reserve

not meeting FSAR

commitment

3.2

50-410/93-81-02

EDGs were tested above

4.2.1

their two-hour rating

50-410/93-81-03

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1.0

INTRODUCTION

DETAILS

During inspections in the past years, the Nuclear Regulatory Commission (NRC) staff

observed that, at several operating plants, the functionality of related systems had been

compromised by design modifications affecting the electrical distribution system (EDS).

The

observed design deficiencies were attributed, in part, to improper engineering and technical

support.

Examples of these deficiencies included:

unmonitored and uncontrolled load

growth on safety-related

buses; inadequate review of design modifications; inadequate design

calculations; improper testing of electrical equipment; and use of unqualified commercial

grade equipment in safety-related applications.

In view of the above, the NRC developed an electrical distribution system functional

inspection (EDSFI) program for operating plants.

In response

to this, Niagara Mohawk

Power Corporation (NMPC) conducted two electrical self-assessments

at NMP2 from

mid-1991 to October 10, 1993.

Their review covered areas similar to an NRC EDSFI,

Fifty-seven open items were identified by NMPC.

Some of these issues were not yet

resolved when this inspection started.

This inspection was conducted to supplement and follow up on NMPC's self-assessment.

During this inspection, the NRC team reviewed the NMPC self-assessment

report and

selected questions and answers from those reviews.

In addition, the NRC team also selected

areas that they considered important to safety for detailed review, using techniques and past

experience developed during previous EDSFIs.

The NRC team's review covered portions of onsite and offsite electrical power sources

and

included the 115 kV buses,

reserve service station transformers, 4.16 kV power system,

emergency diesel generators,

600V Class 1E buses and motor control centers,

station

batteries, battery chargers,

125 Vdc Class 1E buses, uninterruptible power supplies (UPS)

and the 120 Vac Class 1E vital distribution system.

The NRC team verified the adequacy of the emergency onsite and offsite sources for the

EDS equipment by reviewing regulation of power to essential loads and circuit independence.

The team also assessed

the adequacy of those mechanical systems that interface with and

support the EDS.

These included the air start, lube oil, and cooling systems for the

emergency diesel generator and the cooling and heating systems for the electrical distribution

equipment.

A physical examination of the EDS equipment verified its configuration and ratings and

included original installations as well as equipment installed through modifications.

In

addition, the team reviewed maintenance

and surveillance activities for selected EDS

components.

In addition to the above, the team verified general conformance with General Design Criteria (GDC) 17 and 18, and appropriate criteria of Appendix B to 10 CFR Part 50.

The team also

reviewed the plant technical specifications,

the Updated Final Safety Analysis Report, and

appropriate safety evaluation reports to ensure that technical requirements

and licensee's

commitments were being met.

This inspection also included a review of NMPC response

to the deficient condition that the

high pressure core spray system injection valve failed to open during testing as reported in

LER 93-10.

The details of specific areas reviewed, the NRC team's findings, and the applicable

conclusions are described in Sections 2.0 through 5.0 of this report.

2.0

ELECTRICALSYSTEMS

The team reviewed the Nine Mile Point Unit 2 (NMP2) electrical distribution system (EDS)

self-assessment

performed by Niagara Mohawk Power Corporation (NMPC). The scope of

this self-assessment

was similar to an NRC-performed EDSFI and included the efforts by

NMPC and an independent consulting firm, Ogden Environmental and Energy Services.

The

team noted that several significant issues were identified in the EDS design area:

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Incorrect operational mode for the reserve station service transformer automatic load

tap changers;

inconsistencies,

non-conservative considerations

and the lack of transient voltage and

transient frequency analyses in the emergency diesel generator (EDG) loading studies;

lack of sizing calculation for the EDG neutral grounding resistors;

potential for the short circuit current to exceed the 4.16 kV switchgear interrupting

, capability and the lack of short circuit analysis for the Division III600V system; and

incomplete analysis in the degraded grid protection setpoint study regarding the

impact of relay tolerances and the operation of low voltage equipment with degraded

terminal voltage.

Additional details of this review are discussed,

in part, by the following subsections

and

Section 5.0 of this report,

The team also reviewed a sample of the key features and components of the Class 1E portion

of the EDS design and equipment ratings.

The review addressed

both ac and dc systems and

included:

a) normal and emergency power sources;

b) load analysis and load flow; c)

equipment ratings versus worst-case loading; d) voltage regulation; and e) degraded voltage

protection.

2.1

Offsite Power and Grid Configuration

The electrical power output of the NMP2 main generator was rated 1348.4 MVA, 0.9 power

factor at 25 kV. The generator output voltage was stepped up to 345 kV by a 408 MVA

transformer bank located at the station.

Connection of this transfer bank to the NMPC grid

was made at the Scriba 345/115 kV switchyard which is located approximately 3000 feet

from NMP2. In addition to this connection from NMP2, the 345 kV section of the Scriba

switchyard also had connections to (a) the NMP1 output, (b) the Fitzpatrick nuclear station

output, and (c) the NMPC network via two transmission lines.

The 345 kV section of the

Scriba switchyard utilized a breaker and a half scheme with two 345-115 kV

autotransformers.

These two autotransformers

were equipped with automatic load tap

changers (ALTC) and each served a separate

bus in the 115 kV section.

These ALTCs were

in the auto-mode and the output voltage of each auto transformer was set at 118 kV. The

NMP2 electrical distribution system is shown in Attachment 3.

The offsite power supply to the NhlP2 was the 115 kV section of the Scriba switchyard.

Two separate lines, one from each Scriba 115 kV bus, were routed on separate

structures to

a three section

115 kV bus located a the NMP2.

One line, source A (switchyard line 5)

served reserve station service transformer 1A (2RTX-XSRIA)via one bus end section, and

the other, source B (switchyard line 6), served reserve station service transformer 1B (2RTX-

XSRIB) via the other bus end section.

The center bus section served the auxiliary boiler

service transformer (2ABS-Xl). The 115 kV bus sections were equipped with disconnect

switches which were normally positioned to align the center section with source A gine 5);

the disconnect between the center section and the section served by source B (line 6) was

normally open.

Thus, source A normally supplied transformers 2RTX-XRIAand 2ABS-XI

while source B normally supplied transformer 2RTX-XRIB. An ALTC was provided for

each of the two reserve station service transformers

(RSST).

The NMPC self-assessment

inspection had observed that the ALTCs for the two RSSTs were

being operated in the manual mode.

Whereas, it was indicated in Section 8.2.1.4 of NMP2

final safety evaluation report (FSAR) that the ALTCs would be operated in the auto-mode to

maintain secondary winding voltage.

NMPC documented the concern with deviation/event

report (DER) 2-91-Q-0573, dated July 23, 1991.

The RSST ALTCs had been in the manual

mode since the initial plant startup.

NMPC stated that during the preoperation

stage,

these

ALTCs were placed in the manual mode because the upstream 345-115 kV auto transformer

ALTC in the Scriba switchyard was being operated in the auto-mode.

NMPC performed an

operability determination for the ALTC being in the manual mode instead of being in the

auto-mode.

They determined that there was no operability problem because:

a)

The safety equipment was designed for loss-of-offsite-power (LOOP) and degraded

voltage conditions;

'b)

During the LOOP and degraded voltage condition, power would be transferred to the

emergency diesel generators;

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c)

The ALTC being in the manual mode did not affect the undervoltage and degraded

voltage settings;

d)

NMPC evaluated the over-voltage and determined that the over-voltage would not

affect equipment operation.

The offsite power voltage was regulated by the Scriba

345-115 kV auto transformers.

The voltage level was analyzed by Stone & Webster

in their 1985 voltage profile study for different motor loading conditions, with the

ALTC being in the manual mode.

NMPC also performed a reportability evaluation and determined that this issue was not

reportable because the operability of the safety equipment was not affected.

During the 1992 refueling outage, NMPC changed the ALTC to auto-mode.

The timing of

the Scriba 345-115 kV transformers was changed from 60 seconds to 30 seconds,

and the

RSST ALTC timing was set at 60 seconds.

These settings were selected to avoid voltage

oscillation during large motor starting.

NMP2 Operation Procedure NZ-OP-72 was revised

to incorporate these changes.

NMPC also completed a 50.59 evaluation and determined that

there were no unreviewed safety questions for the above changes.

The RSST ALTCs have

been in the auto-mode since the startup from the 1992 refueling outage.

The team concluded that the actions taken by NMPC in response

to the DER were

appropriate.

The team observed that during the recent refueling outage NMP2 experienced

a partial loss

of offsite power.

Specifically, the source A, which supplies Division I equipment, was lost

while the plant was in the refueling mode.

Source B was unaffected,

This event was

reported to the NRC by licensee event reports (LER) 93-08, dated December

1, 1993, titled

"Engineered Safety Feature Actuations Due to a Partial Loss of Offsite Power Caused by a

Personnel Error," and LER 93-09, dated December 2, 1993, titled "Engineered Safety

Feature Actuations Resulting From a Loss of Power to RPS and RCIS Caused by Personnel

Error." The team found no design concerns associated

with these two LERs and that further

analysis of these LERs was outside of the scope of the EDSFI.

The team observed that the 115 kV offsite power source had been the subject of an earlier

NRC inspection on July 19-23, 1993. At that time the inspector concluded that the 115 kV

offsite power source was reasonably reliable.

The inspection findings were discussed in the

combined inspection report 50-220/93-15 and 50-410/93-15.

The EDSFI team's review of

the 115 kV power source did not identify any concerns that would change the previous

assessment.

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2.2

Bus Alignment During Startup, Normal Power and Shutdown Operations

The medium voltage portion of the EDS consisted of the following:

two nonsafety-related

13.8 kV buses for normal unit auxiliaries (2NPS-SWG001

and

2NPS-SWG003);

one nonsafety-related

13.8 kV bus for the auxiliary boiler auxiliaries (2NPS-

SWG002);

five nonsafety-related

4.16 kV buses for the normal unit auxiliaries (2NPS-SWG011

through SWG015) and

three safety-related 4.16 kV buses,

one each associated

with engineering safeguards

Division I (2ENS*SWG101), Division II (2ENS~SWG103) and Division III

(2ENS*SWG102).

During unit startup and shutdown, half of the unit normal auxiliary buses were served by

reserve transformer 2RTX-XRIA; the other half of the auxiliary buses were served by

reserve transformer 2RTX-XRIB. The auxiliary boiler bus was served by transformer 2ABS-

XI. The Division I and Division IIIbuses were served exclusively by a tertiary winding of

reserve transformer 2RTX-XRIAand the Division II bus was served exclusively by a tertiary

winding on reserve transformer 2RTX-XRIB. However, in the event either reserve station

service transformer was temporarily out of service, the associated Division I or Division II

bus could be served by a 4.16 kV tertiary winding of the auxiliary boiler service

transformer.

Following startup, the units normal auxiliary buses were manually transferred to the normal

station service transformer 2STX-XNS1 which was connected to the unit main generator

leads.

2.3

Bus Transfer Schemes

The team observed that following a unit trip, the normal auxiliary buses were transferred

from the normal station service transformer to the reserve station service transformers by an

automatically initiated fast dead-bus transfer scheme.

Since the Division I, IIand IIIbuses

remained connected to the reserve transformers during normal operation, no transfer was

required for these buses following a unit trip.

The team observed in the NMPC self-assessment

that the impact of the above fast dead-bus

transfer on the safety-related Division I, II and IIIbuses had been addressed.

NMPC had

analyzed the transfer and concluded that the scheme was acceptable.

The team did not

review the analysis.

f

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2.4

Class 1E AC Power Systems

The team observed that the Class 1E ac power systems included a 4.16 kV system and a

600V system.. The 4.16 kV Class 1E systems consisted of three separate

and independent

buses for Division I, II and III. Division I and Division IIIwere served by offsite source A

while Division II was served by offsite source B.

Each division had a standby emergency

supply from its own dedicated emergency diesel generator.

Division I and Division II

systems were essentially redundant and served load center transformers and pump drive

motors associated with the low pressure core spray system, service water system, residual

heat removal system and the spent fuel pool cooling system.

Division IIIserved the high

pressure core spray system pump drive motor and a motor control center.

The 600V Class 1E systems included three separate

and independent

sets of load center

switchgear and motor control centers.

Division I and Division II load centers were each

double-ended, i.e., had the capability of being served by one of two 4.16 kV-600V

transformers.

These load centers served the larger low voltage motors (150 HP and larger),

larger low voltage non-motor loads (60 kW and larger) and motor control centers.

The

Division III600V system had a single 4.16 kV-600V transformer which served the division's

motor control center.

Division IIIhad no load center switchgear.

The team noted that the NMPC self-assessment

had implied that all 4.16 kV-600V

transformers were provided with appropriately rated surge arresters.

However, in response

to the team's query, NMPC advised that, in fact, the Division III4.16 kV-600V transformer

was not provided with surge arresters.

Further, in response

to the team's concern NMPC

performed an evaluation which concluded that the basic impulse level (BIL) provided for the

transformer insulation would withstand the potential surges on the 4.16 kV system to which

it could be exposed.

The team reviewed the electrical distribution equipment loadings for the Class 1E ac

electrical distribution system equipment based on the NMPC calculation EC-151, Revision 0,

dated November 13, 1992, titled "AuxiliarySystem Performance Using ELMS-AC,"

including the calculation dispositions 00A, 00B and 00C, dated January 7, 1993,

May 4, 1993, and May 6, 1993, respectively.

This documentation indicated that, under

worst-case loss of reactor coolant (LOCA) conditions, the reserve station service

transformers, 4.16 kV switchgear, 4.16 kV-600V transformers,

600V switchgear and 600V

motor control centers would be operated within their designed ratings.

In their self-assessment,

NMPC had identified a concern with the potential fault duty to

which the 4.16 kV switchgear could be exposed while testing either the Division I or

Division II EDG in parallel with the 115 kV system through the auxiliary boiler service

transformer.

NMPC addressed

this concern in DER 2-92-3960, dated November 3, 1992.

Resolution involved a rerun of the ELMS-AC program for calculation EC-151 using a more

realistic short circuit time constant for the emergency diesel generator.

The self-assessment

also identified a lack of a short circuit analysis for the Division III600V system.

This

concern was addressed

by NMPC in their DER 2-92-Q-1788, dated April21, 1992.

Resolution involved the generation of calculation EC-151, Revision 0, which indicated

acceptable fault levels on Division III600V system.

Based on the team's review of the referenced deviation/event reports and calculation EC-151,

the team concluded that the loading and potential fault duties were within the Class 1E ac

power system equipment capabilities.

2.5

Emergency Diesel Generator

The team observed that a dedicated emergency diesel generator (EDG) is provided for each

Class 1E ac power system.

The ratings of the EDGs are as follows:

8760 hour0.101 days <br />2.433 hours <br />0.0145 weeks <br />0.00333 months <br /> (continuous) rating

2000 hour0.0231 days <br />0.556 hours <br />0.00331 weeks <br />7.61e-4 months <br /> (short time) rating

2 hour2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> rating

Division I &II

4400 kW

4750 kw

4840 kw

Division III

2600 kw

2850 kw

2860 kw

NMPC identified, during their self-assessment,

that their calculation EC-032, Revision 7,

titled "Diesel Generator Loading," which was used to document the worst-case loading,

contained inconsistencies.

Namely, the calculation did not consider cable losses nor actual

motor power factors.

Further, the calculation did not address

the transient voltage and

frequency conditions encountered

during the EDG loading sequences.

To address

these

concerns, NMPC issued DER 2-92-Q-1782, dated April2, 1992, and DER 2-92-3628, dated

October 6, 1992.

In addition, NMPC determined that a scenario of a loss-of-offsite power

(LOOP) followed by a LOCA had not been analyzed.

To address

these concerns, NMPC

issued DER 2-92-Q-1461, dated April7, 1992.

Resolution of the steady-state

loading

concerns involved revising calculation EC-32 as Revision 8, dated January 4, 1993, which

did consider transformer and cable losses and, where known, actual motor brake horsepower

and power factor (otherwise nameplate horsepower and power factor).

This revision of the

calculation, based on the "ELMS-AC" program used in calculation EC-151, Revision 0,

determined the worst-case loading on Divisions I, II and IIIEDGs to be 4292 kW, 3875 kW

and 2540 kW, respectively, which is within the EDG continuous rating.

The resolution of the transient voltage and frequency concern involved the issuance of a new

calculation, EC-156, Revision 0, dated June 29, 1993, entitled "Diesel Generator Transient

Analysis," which was based on the electrical transient analyzer program "ETAP." The team

noted from the results of this calculation that, for Division I and Division II, generator output

frequency did not recover to 98 percent as implied by the calculation objective, and the

regulatory position given in USNRC Regulatory Guide 1.9, Revision 3, dated July 1993.

In

response to the team's concern, NMPC made a preliminary rerun of the "ETAP" program

using the known brake horsepower for motor loads when known rather than the rated

0

horsepower.

In addition, the EDG governor and exciter transfer function constants were

changed to better represent

the NMP2 EDG units.

The rerun of the program yielded an

acceptable frequency recovery.

NMPC advised that the next revision of calculation EC-156

willbe issued using this more realistic data.

In their self-assessment

inspection, NMPC also identified the lack of a EDG generator

neutral grounding resistor calculation.

This.was addressed

by DER 2-92-Q-1256, dated

March 31, 1992.

The concern was resolved by the issuance of calculation EC-153, which

addressed

the EDG generator neutral ground resistor, Revision 0, dated September 30, 1992.

Based on review of the referenced DERs and calculations EC-032 and EC-156, the team

concluded that the loadings on the EDGs were within their designed capabilities.

2.6

Degraded Voltage Protection Schemes for Class 1E Buses

2.6.1

First Level Voltage Protection

The team observed that the setting of the first level, or loss of voltage, protection scheme for

the Class 1E 4.16 kV buses was 3212 volts or about 77 percent of nominal.

Three relays

were provided for this function on each bus; i.e., one per phase,

and acted in two-out-of-

three logic to detect loss of the offsite power supply to the associated

bus.

Following a time

delay of about 3 seconds,

load shedding and EDG starting for that bus would have been

initiated.

The team did not identify any concerns in the review of this protection scheme,

2.6.2

Second Level Voltage Protection

The team observed that the setting of the second level, or degraded voltage protection

scheme for the Class 1E 4.16 kV buses was 3847 volts, or about 92.5 percent of nominal.

NMPC determined that with this setting, when considering relay tolerances,

the protection

scheme actuation could occur at 3770 volts or 90.6 percent of nominal.

NMPC had

determined, using their preliminary revision 4 to calculation EC-136, titled "Degraded

Voltage Relay Set Point," that the lower limitof the setting, i.e., 3770 volts, would still

provide sufficient voltages for the 600 volt safety-related motors (at least 90 percent of

nameplate rating for running conditions and at least 80 percent of nameplate rating for motor

starting).

The preliminary revision of calculation EC-136 was based on the "ELMS-AC"

program used in calculation EC-151, Revision 0.

The team noted that, as was the case for the first level protection, three relays were provided

on each bus, i.e., one per phase,

and acted in two-out-of-three logic to detect unacceptable

degraded voltage conditions on the associated

bus.

This scheme had two time delays.

The

first time delay was set at 8 seconds and acted in the event of a LOCA; the second time

delay was set at 30 seconds without a LOCA. Following either time delay actuation, bus

stripping and EDG starting is to be initiated for the associated

bus.

9

The team did not identify any concerns with the design of this second level voltage protection

scheme.

2.7

Class 1E 120 VAC System

The team noted that the Class 1E 120 Vac system consisted of two uninterruptible power

supplies (UPS) which served the plants instrumentation and controls associated

with the

emergency core cooling system.

These UPS systems each had a rated output of 25 kVA at

120 volts, plus or minus 2 percent and 60 hertz, plus or minus 0.5 hertz.

The team noted

that for the kVAloading, these UPS systems were well within their capabilities.

Both the NMP2 FSAR and the UPS procurement specification identified the total harmonic

distortion (THD) of the output voltage to be not more than 5% of the fundamental,

It was

not clear to the team nor NMPC engineers whether the 5% applied to the loaded or unloaded

conditions.

Tests conducted by NMP2 plant personnel indicated that during the unloaded

condition, the THD was 3.9%, while during the loaded condition, the maximum THD was

9%.

In response

to the team's concern, NMPC performed a thorough analysis, which

indicated that all loads connected to the UPS were determined to be operable because

many

of these loads were immune to a higher THD. Subsequently,

NMPC issued DER 2-93-2905,

entitled, "UPS,with a THD Greater Than 5%," on December

15, 1993, to address

this issue.

This DER requires further analysis to determine the acceptance

criteria for the THD and to

establish control of future load addition.

This item is unresolved pending NRC review of the

resolution of DER 2-93-2905 (50-410/93-81-01).

2.8

Class 1E 125 VDC Systems

The team observed that the Class 1E 125 vdc systems consisted of three separate

systems;

one each for Division I, II and III. The Division I and Division II systems each consisted of

a 2550 AH (8 hour9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> rate), 60 cell, calcium grid, lead acid battery bank, two 300 A chargers

and associated

panelboards.

The Division IIIsystem consisted of a 100 AH (8 hour9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> rate), 60

cell, calcium grid, lead acid battery bank, two 50 A chargers

and associated

panelboards.

The second charger of each system was an installed spare which could be manually placed in

service when required.

The NMPC self-assessment

inspection identified two technical specifications concerns

involving these systems.

The first related to electrolyte temperature.

Both the FSAR,

Section 8.3.2.1.2, and design calculations considered 65'

to be the minimum electrolyte

temperature

whereas Technical Specification 4.8.2 specifies a surveillance requirement for a

minimum temperature of60'.

NMPC has requested,

by a letter to the NRC, dated

December

14, 1993, that the Technical Specification be changed to 65'.

10

The second NMPC-identifiied concern involved Division I and Division II systems.

Technical Specification Section 3.8.2.2 requires that both the primary and backup chargers

be in operation when the associated

UPS system is powered by its backup dc supply.

NMPC

determined that, ifthe battery had been discharged prior to the connection of the second

charger, there was a potential for the bus supply breaker to trip when both chargers went to

their current limit. NMPC verified the adequacy of one charger to supply the normal dc

loads, including the dc requirements of the UPS, and recharge the battery within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.

As a result, NMPC has requested,

by the same letter as above, that the Technical

Specification be changed to delete the requirement for the operation of the second charger.

NMPC identified a few minor concerns involving assumptions

used in the 125 Vdc system

calculations including battery design margin, battery temperature correction factor and

loading assumptions.

These concerns where addressed

and resolved by the deviation/event

report process.

The team did not identify any additional concerns with the Class 1E 125 Vdc

system design.

C

2.9

Class 1E AC Power System Equipment

The team reviewed NMPC licensee event report (LER) 93-10, dated December 8, 1993,

regarding the inoperability of the High Pressure

Core Spray (HPCS, Division IIIemergency

core cooling) system due to equipment deficiencies.

The LER reported a failure to operate

the HPCS system injection valve motor starter opening contactor during a test that was

performed on November 8, 1993, during the 1993 refueling outage.

The opening contactor,

located in motor control center 2EHS*MCC201, provides electrical power to the valve motor

to open the valve when that contactor picked up.

NMPC determined that the control voltage

applied to the contactor was insufficient for the starter coil to pickup, thus preventing the

HPCS system injection valve (2CSH*MOV107) from opening.

NMPC stated that the design

specifications had required the contactor to operate with 96 volts '(80 percent of 120 volts) or

less across the contactor coil.

NMPC determined that the inadequate coil voltage was due to two separate conditions,

One

of these conditions was that the tap setting on the 4160-600V transformer (2EJS*X2) was set

at +2.5% rather than -2.5% as specified in the design.

This resulted in a 5% voltage

reduction on the 600V motor control center bus.

The second condition was the inability of

the valve motor starter coil (GE size 2 contactor) to pickup at 96 volts (80% of the coil

rating) as determined by testing.

Both conditions existed in the plant since initial startup

more than five years ago.

Further, NMPC determined that either condition alone would

have prevented valve actuation during degraded voltage conditions.

This problem was not

detected and corrected earlier because it was obscured by the ALTCs for the RSSTs being

operated in the manual mode as discussed in Section 2.1.

When the ALTCs were in the

manual mode, the 4.16 kV bus voltage was increased

about 2.6%, resulting higher control

voltage across the valve motor starter coil. NMPC made these ALTC features operational

'and set at auto-mode before startup from the 1992 refueling outage.

The 4160V bus voltage

was maintained at nominal voltage since then.

NMPC stated that the HPCS system injection valve passed all tests conducted prior to the

1993 refueling outage.

During the 1993 refueling outage, several tests were conducted for this'valve.

The first test

was a static test (stroking the valve with the HPCS pump stopped) that was conducted on

October 4, 1993, and passed.

The second test was a dynamic test (with the HPCS pump

running) and was conducted on October 5, 1993.

The valve opened successfully.

The third

test was also a dynamic test conducted on November 8, 1993.

The valve failed to open.

Subsequently,

DER 2-93-2622 was generated

and the valve was declared inoperable (LER

93-10 was issued later).

On November 10, 1993, after cleaning various contacts in the

control circuit, NMPC stroked the valve twice (HPCS pump not running), and the valve

opened successfully.

On November 15, 1993, NMPC attempted to stroke the valve, and the

motor contractor failed to pick up. Allof the above tests were conducted before the

deficiencies were corrected, which took place between November 17, 1993, and

November 21, 1993.

The offsite power supply was at normal voltage during the above tests.

However, specific voltages were not measured in each case.

After the motor contactor was

replaced and the transformer tap setting corrected,

a dynamic test was conducted on

November 21, 1993, and passed.

During this inspection, NMPC performed a preliminary calculation, which indicated that,

before the deficiencies were corrected,

and with the 4160V bus being at nominal voltage, the

valve motor control circuit had barely enough voltage for the contactor coil to pick up, with

no margin.

The corrective actions taken and completed by NMPC included:

a)

Replaced four GE size 2 contactors in the HPCS 600V motor control center with

Gould contactors, which have a pull-in voltage of'86V or less, and corrected the

transformer tap setting from +2.5% to -2,5%.

b)

Verified, by measuring the secondary voltage, that the Divisions I and II switchgear

transformer taps were set correctly.

c)

Reviewed the preoperation

test data for Divisions I k, IIcontactors and determined

that the contactors could pull in under degraded voltage conditions. It was found that

Divisions I and IIswitchgear use Gould contactors.

This type of contactor has a pull-

in voltage of 86V or less.

The above corrective actions were verified by the team during the inspection.

" For the contactors in the HPCS 600V motor control center that were not replaced, NMPC

provided the followingjustifications:

Pl

12

a)

Two GE size 2 contactors were not replaced because

they were used for equipment

which is required to function only when the HPCS pump was in the standby mode and

was not required to function during an accident.

In addition, the test data indicated

that these two contactors required pull-in voltage of 89V or less.

b)

GE size

1 and size 3 contactors were not replaced because the test data indicated that

these contacts would pull-in with less than 96 V.

The team considered this justification to be appropriate.

NMPC determined the root cause for the valve motor contactor deficiency to be an

equipment deficiency that was not identified during plant startup testing due to inadequate

methods used to evaluate startup test data.

NMPC also determined the root cause of the

incorrect transformer tap setting to be poor work practices during plant construction and

preoperational

testing.

The team reviewed NMPC's program for plant modification to

ascertain whether their current practices would preclude the above deficiencies.

For a typical

plant modification, the project engineer interfaces directly with the design engineers

and

procurement engineers

to assure that the design requirements are properly incorporated into

the purchasing requirements.

Upon receipt of the procured items, receipt inspection and

document reviews are performed by the procurement engineers

to ensure conformance with

the design requirements.

Post-modification tests are required to demonstrate proper

operation of the equipment.

Any nonconformances

identified are documented in a DER and

resolved through the DER program.

During this inspection, the team interviewed project

engineers,

procurement engineers,

design engineers,

QA engineers,

and testing personnel.

The team found them knowledgeable and familiar with the program procedures.

Within the

scope of this review, the team did not find a current problem with the programs that led to

the motor contactor deficiency.

The team determined that the HPCS system injection valve would not open during degraded

voltage conditions, which rendered the HPCS system inoperable from initial startup of the

plant until the deficiencies were corrected in November 1993.

This deficient condition

constitutes an apparent violation of NhIP2 Technical Specifications, Section 3.5.1, item C,

which requires that the HPCS system be operable during conditions 1, 2, and 3 (EEI 50-

410/93-81-04).

2.10

Conclusion

The team concluded that the ac and dc systems were generally well designed and conformed

to the Technical Specifications and NMP2 FSAR with the exception of the two items (battery

minimum electrolyte temperature

and the battery backup charger) for which NMPC has

requested Technical Specification revisions (discussed in Section 2.8).

The team also

concluded that the EDS components were adequately

sized and configured, and that the

actions taken by NMPC in response

to the HPCS system injection valve issue were

13

appropriate.

One apparent violation (identified by NMPC) and one unresolved item were

identified in this area.

The apparent violation pertains to the inoperability of the HPCS

system, while the unresolved item pertains to the total harmonic distortion of the UPS output

voltage.

3.0

MECHANICALSYSTEMS

To verify the loading on the emergency diesel generators,

the team reviewed the power

demands of major loads for selected pumps and the translation of mechanical into electrical

loads as input into the design basis calculations.

The team also conducted a walkdown of the

supporting mechanical systems, including the diesel generator cooling water system, the

starting air system, the lube oil system, and the heating, ventilation and air conditioning

(HVAC) systems for the emergency diesel generators

(EDG) rooms, the ac and dc

switchgear areas and battery rooms.

3.1

Power Demands for Major Loads

The team reviewed the power demands for the major pump motors on the EDGs following a

loss of coolant accident (LOCA) plus a loss of offsite power (LOOP) condition.

Other

combination of LOCA and LOOP conditions discussed in the Nine Mile Point 2 (NMP 2)

Updated Safety Analysis Report (USAR) were also reviewed.

This review was based on the

information provided in the NMPC self-assessment

report and review of the design

calculations, procedures

and memoranda.

The majority of the break horse power (BHP)

curves, for the large pumps, exhibited peak values.

For these pumps, maximum BHP values

were conservatively assumed

to be in excess of the peak values indicated on the BHP vendor

certified curves.

For the pumps which had an increasing BHP characteristic (e.g., service

water pump) NMPC used very conservative assumptions

to maximize the flow rates.

These

flow rates were utilized to determine the corresponding BHP values for input into the EDG

loading calculation.

Based on this review, the team has determined that the power demands

for the major pump motors on the EDG were conservatively established in the Diesel

Generator Loading Calculation No. EC-32, Rev. 8.

'he team also reviewed a resolution of a concern related to a potential for EDG overloading

due to a lack of the administrative controls in the operating procedures,

which was identified

during the NMPC's self-assessment.

The existing procedures did not restrict the restart of

the tripped low pressure core spray or residual heat removal pump motor during a

LOCA/LOOP condition with a nearly fully loaded diesel.

The team found the NMPC's

corrective actions (a revision of the appropriate procedures)

undertaken to resolve this

concern, to be appropriate.

, ~

14

3.2

Diesel Generator and Auxiliary Systems

The team reviewed the NMPC's calculations, procedures,

and drawings to determine the

design adequacy of the diesel generators

and auxiliary systems.

A summary of the team's

findings is given below.

NMP 2 has three EDGs.

Two EDGs are rated at 4,400 kW each and supply power to

Divisions I and II emergency loads.

The third EDG is rated at 2,600 kW and is supplying

power to high pressure core spray (HPCS - Division III) system.

Each EDG has its own day

tank and (7 day) storage tank.

Two fuel oil transfer pumps per EDG are used to transfer

fuel oil to day tank from its respective storage tank.

The FSAR, Section 9.5.4.2.1, stated that each storage tank (approximately 52,664 gal. for

each of the standby diesel generator fuel oil storage tanks, and 36,173 gal. for the HPCS

diesel generator fuel oil storage tank) is sized to store sufficient oil for continuous operation

of its respective diesel engine at rated capacity for 7 days.

The FSAR, Section 9.5.4.2.3,

stated that based on a fuel consumption of 5.472 gpm at a rated 4,480 kW for the Division I

and II diesels, and 3.361 gpm at a rated 2,850 kW for the Division IIIdiesel, the 1-hr

running time volumes, including the dead volume in the tanks are 409 gal and 282 gal,

respectively.

To verify these commitments the team reviewed nine related mechanical and

~

~

~

~

~

electrical calculations.

The team's review of these documents generated

some concerns related to the NMPC's

ability to meet its FSAR commitments.

The discussion presented below provides basis for

the team's concerns and the NMPC's response.

a)

The fuel oil consumption rate changes

and the variation in the fuel oil properties were

not considered in the above calculations.

The committed fuel oil tank (both day and

storage) capacities were established

based on the results of the EDG tests for the

Division I &II diesels and on a vendor manual data for the HPCS diesel.

The team

expressed

concern with using the data as a basis for the tank volume calculation

without addition of any margin to allow for changes in the diesel conditions and/or

acceptable, variation of the fuel properties,

This is especially true for the HPCS

diesel,'since the calculation was based on a typical consumption

rate.

NMPC

concurred with the team's concerns and performed a preliminary engineering

evaluation of the impact of these assumptions.

This evaluation indicated a potential

for a small shortfall (within a couple of percentage

points) from the committed

volumes.

However, at this time, the team could not make a final determination

regarding the NMPC's compliance with the FSAR commitments, since NMPC did not

have vendor's input required to complete the evaluation.

b)

15

The effects of the temperature

changes were not considered in the above calculations.

The fuel oil tank capacities were established

based on constant fuel oil temperature.

Although this assumption is true for the underground storage tanks, it is not always

true for the day tanks.

The day tanks are located in their respective EDG rooms and

see wide temperature variations.

This is further compounded by the use of volume-

based instruments for tank level monitoring.

(Unlike a differential pressure type, this

type indicates level based on a constant volume and not constant mass.

The vendor

consumption rates are mass-based.)

NMPC concurred with the team's concerns and

evaluated its impact as part of the preliminary engineering evaluation discussed in

item a) above.

Pending completion of this evaluation, the team deferred its

assessment of the impact of the temperature

changes on the FSAR commitments.

This is an unresolved item pending NRC's review of the completed evaluations discussed

in

items a) and b) above (50-410/93-81-02).

The team reviewed issues related to the EDG cooling identified in the self-assessment.

The

team agreed with NMPC's conclusion that the safety-related

service water (SW) system

provides adequate cooling to the EDGs.

The team noted that the process

safety limits, established in mechanical set point calculations,

were incorrectly incorporated into electrical calculations.

The error in the incorporation of

the process safety limits was originally discovered by NMPC during the self-assessment.

The team agrees with NMPC's assessment

that this error did not affect Technical

Specification limits. NMPC reconciled all of the affected calculations prior to completion of

this inspection.

However, this error appears

to be a part of the wider set point programmatic

issue, which has been recognized by NMPC. The set point issue is tracked (internally) by

NMPC. The NMPC's resolution of this issue encompasses

a variety of far reaching and

broad corrective actions which are scheduled for completion by December 31, 1995.

In the

interim, NMPC assessed

the accuracy of the NhP2 set point calculations for NSSS (nuclear

steam supply system) and BOP (balance of plant) positions of the Technical Specifications for

reactor protection.

The preliminary results of this review indicate that these calculations will

not require any changes.

3.3

Heating, Ventilation, and AirConditioning (HVAC) Systems

The team reviewed the design of the HVAC systems which provide services to the electrical

equipment within the scope of the EDSFI review, namely:

Division I, II&IIIbattery

rooms, switchgear rooms, diesel generator rooms, and diesel generator control rooms.

The

documents

used for this review were the NMPC's calculations, procedures,

drawings, and

the findings of the self-assessment.

16

The team reviewed related issues identified in the self-assessment.

These issues were:

1) the EDS equipment cooling;

2) hydrogen concentration;

and 3) EDG room exhaust fan

protection.

The team concurred with the NMPC's resolutions of these issues, which were as

follows:

1) the safety-related SW system provides adequate cooling of the EDS equipment;

2) the design of the HVAC system provides adequate hydrogen removal and complies with

the FSAR, Section 9.4.1.2.4, commitment that each battery room is maintained at a negative

pressure with regard to the surrounding areas;

and 3) the set point for the EDG room exhaust

fan low flow condition willprovide an adequate protection to the exhaust fan operation.

Additionally, NMPC had verified operation of tornado dampers during this inspection.

The team also reviewed issues related to tornado and missile protection of the HVAC

'ystems

and found that the afforded means of protection were adequate.

3.4

Conclusions

The team, based on the review of the design attributes within the scope of this inspection,

concluded that the mechanical systems supporting the EDG and other electrical equipment are

capable of performing their design functions.

The team also observed that the

mechanical'ystems,

within the scope of this inspection, had ample margin based on generally

conservative design.

One unresolved item was identified:

there was no evidence that the

capacity of the day tank and the fuel storage tank meets the FSAR commitments.

4.0

ELECTRICALDISTRIBUTIONSYSTEM EQUIPMENT

The scope of this inspection element was to assess

effectiveness of the controls established

to

ensure that the design bases for the electrical system was properly tested and maintained.

This effort was accomplished

through the review of the results of the NMPC's self-

assessment,

field walkdown and verification of the as-built configuration of electrical

equipment as specified in the electrical single-line diagrams, modification packages,

and site

procedures.

In addition, the maintenance

and test programs developed for electrical system

components were also reviewed to determine their technical adequacy.

l

4..1

Equipment Walkdowns

The team inspected various areas of the plant to verify the as-built configuration of the

installed equipment.

Areas inspected included the EDGs, EDG control rooms, 4 kV

switchgears,

batteries, inverters, and 480V load centers.

Class 1E transformers were also

examined.

The walkdown indicated that adequate

measures

were in place to control system

configuration. Allelectrical equipment was found to be generally well maintained with

surrounding areas clear of the safety hazards.

In general, the electrical equipment installed

adhered to the design requirements.

17

The team reviewed issues identified in the self-assessment

related to housekeeping

and

potential safety hazards.'uring

the walkdown, the team observed that all housekeeping

potential safety hazard issues were satisfactory resolved.

The general plant condition gave

the impression of good housekeeping

practices, especially considering that the unit was being

returned to service after an outage at the time of the walkdown.

4.2

Electrical Equipment Maintenance and Testing

The team reviewed the results of the NMPC's self-assessment,

various maintenance

and

testing procedures for equipment such as the emergency diesel generator,

batteries, battery

chargers,

4 kV switchgear, molded case circuit breakers,

and protective relays.

NMPC

personnel were interviewed to assess

their understanding of the testing and maintenance

programs.

The team observations

are described below.

4.2.1

Emergency Diesel Generator Testing

Periodic surveillance testing of the EDGs was conducted to assure their operational

availability and capacity to perform their shutdown functions.

The Technical Specifications

(TS) for NMP2, Section 4.8.1.1.2, provided monthly and 18-month test requirements for

each EDG to demonstrate operational readiness.

These requirements

were implemented by

the monthly surveillance tests and by the 18-month endurance

tests.

The team reviewed monthly surveillance test procedures

and 18-month test procedures

and

several completed monthly and 18-month records test.

The team concluded that the test

procedures included adequate

acceptance

criteria that were consistent with the TS

requirements.

Review of completed test records indicated that the tests were conducted in

accordance with the test procedures.

The 18-month test procedure specified an EDG load equal to or greater than its 2 hour2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> rating

of 4840 kW (Division I &II EDGs) and 2860 kW (Division IIIEDG) for the first 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br />

without specifying the upper limit. During the remaining 22 hours2.546296e-4 days <br />0.00611 hours <br />3.637566e-5 weeks <br />8.371e-6 months <br />, this test procedure

specified an EDG load equal to or greater than its continues rating (also without the upper

limitvalue) of 4400 kW (Division I &IIEDGs) and 2600 kW (Division IIIEDG). The

team reviewed the test data of past two 18-month tests for all three EDGs.

The test data indicated the following:

1) Division I &IIEDGs were loaded consistently

between 4850 and 4910 kW for first 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> and between 4400 and 4500 kW for the

remaining 22 hours2.546296e-4 days <br />0.00611 hours <br />3.637566e-5 weeks <br />8.371e-6 months <br /> in each test; and 2) Division IIIEDG was loaded consistently between

2900 and 2910 kW for first 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> and between 2600 and 2700 kW for the remaining 22

hours in each test.

18

NMPC's position on this issue was as follows:

1) the temperature

and other variables

observed during these tests were well within the normal operating range; and 2) the

maintenance inspections, which took place 18 months after each endurance

test, did not

reveal any unexpected wear to the diesel engine parts that would be expected to indicate

wear.

Additionally, NMPC contacted both EDG vendors concerning the consequences

of

these tests.

The vendors'esponses

indicated that testing with slightly above rated load

would not damage the EDGs.

Also, NMPC revised appropriate procedures by addition of

caution statements which identified maximum load not to be exceeded.

The team agreed with NMPC that the current condition does not present an immediate

operability concern.

The long term concern, associated with the continuing operation of the

diesels above their rating, requires further resolution.

Pending NRC's review of the

provided information and/or corrective actions by NMPC, this item is unresolved (50-

410/93-81-03).

The team also reviewed issues related to a potential for fuel exposure below the cloud point

(formation of paraffin due to a low temperature exposure) before the fuel was transferred to

the storage tank from the delivery truck, identified in the self-assessment.

NMPC has an

operation procedure in place which requires the delivery truck to be stored in a heated

enclosure during the winter. The team agreed with the NMPC's conclusion, that this

operation procedure provided an adequate protection against fuel exposure below cloud point.

4.2.2

Station Batteries

The team reviewed the testing program'of the station batteries to assure that adequate dc

power was available to operate the dc equipment.

There were three 125 Vdc batteries - one

for each division. The team reviewed 18-month and 60-month test procedures

and their test

results to assure that they, meet the surveillance requirements

stated in the TS, Section 4.8.2.1.

The team noted that the test procedures included adequate acceptance

criteria that were consistent with the TS requirements.

Review of completed test records

indicated that these tests were conducted in accordance with the test procedures.

The team

concluded that the 18-month and 60-month tests for 125 Vdc batteries at NMP 2 were

properly implemented.

The team reviewed related issues identified in the self-assessment.

These issues were as

follows:

1) the battery charger output voltage regulation commitment; and 2) electrolyte

minimum temperature requirements of 60'F vs. 65 F. NMPC's resolutions of these issues

were as follows:

1) NMPC contacted the battery charger vendor and obtained the results of

the original charger test, which confirmed the voltage regulation commitment; and 2) NMPC

had submitted a TS change request, requesting changing the minimum temperature in TS 4.8.2.1.b.3 from 60'F to a more conservative value of 65'F (this issue was also discussed in

paragraph" 2.8 of this report).

19

4.2.3

Relay Testing

~

~

The team reviewed the NMPC calibration and testing program for protective relays used in

the safety-related portions of the EDS.

The team noted in the procedures

that safety-related

relays, such as loss of voltage and degraded voltage relays, reactor coolant pump drive motor

overcurrent relays and safety-related pump drive motor auto start time delay relays are

calibrated and tested every 18 months to conform with the technical specifications.

Other

safety-related protective relays are calibrated and tested on a less frequent schedule of either

every 30 months or 42 months depending on relay model and style number.

Auxiliary relays

are tested every 6 years.

The team did not identify any concerns with the program.

4.3

Conclusions

Based on the review of the documents,

the team concluded that NMPC had an acceptable

maintenance

and testing program for the electrical distribution system equipment at NMP 2.

One unresolved items was identified in these areas:

the EDGs were tested at a power output

greater than the 2 hour2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> rating of 4840 kW (Division I &IIEDGs) and 2860 kW (Division III

EDG).

5.0

REVIEW OF NMPC's SELF-ASSESSMFAT OF THE ELECTRICAL

DISTRIBUTIONSYSTEM

The team reviewed the NMPC's self-assessment

report and selected questions to determine

the adequacy of their review.

The self-assessment

was performed by NMPC from mid 1991,

'o

October 10, 1993.

In addition, NMPC contracted with Ogden Environmental and Energy

Services (Ogden) to perform an independent review.

The Ogden team consisted of six team

members:

one team leader, two electrical design reviewers, two mechanical design

reviewers, and one operations and testing reviewer.

The NMPC's self-assessment

covered electrical system design, mechanical system design,

electrical equipment testing and maintenance,

and engineering and technical support (E&TS)

areas.

The electrical system design covered offsite and onsite systems, including offsite grid

stability, bus alignments, voltage studies, emergency diesel generator (EDG) load

calculations, and station batteries and battery chargers.

The mechanical system design

covered EDG auxiliary systems (fuel oil, cooling water, lubrication oil, and starting air

systems), HVAC for switchgear room, EDG rooms, and battery rooms. It also covered

service water system performance in support of the EDS equipment, tornado and missile

protection, and hydrogen accumulation in the battery rooms.

The electrical equipment

testing and maintenance included maintenance

and testing of EDGs, protective relays, circuit

breakers and fuses, batteries and battery chargers.

20

The NMPC's self-assessment

team identified 57 open items and 43 observations.

Based on

these findings, 52 deviation event reports (DERs) were generated.

Out of these 52 DERs, 44

were closed and the required corrective actions implemented by NMPC prior to completion

of the NRC inspection.

The team was impressed not just by the number of questions, but

also by their quality and depth.

The team concluded that the self-assessment

findings had

been appropriately reviewed and prioritized by the NMPC.

Based on this review, the team concluded that the NMPC's self-assessment

was

comprehensive.

It covered sufficient areas for a normal EDSFI.

The number and

significance of their findings indicated an excellent level of detailed review.

Examples of

significant findings are:

1) incorrect operational mode for the reserve station service

transformers'utomatic

load tap changers

as discussed in Section 2.1, and 2) non-

conservative considerations

and the lack of transient voltage and transient frequency analyses

in the emergency diesel generator loading studies as discussed in Section 2.5.

Certain issues

were not identified.

These included:

1) there was insufficient evidence that the capacity of

the day tanks and storage fuel oil tanks met the final safety analysis report commitment; 2)

the emergency diesel generators were tested with power output greater than their two-hour

rating; and 3) lack of an analysis of the impact of the uninterruptible power supplies output

voltage total harmonic distortion (THD) in excess of 5% of the fundamental.

In addition,

there were two significant deficiencies that were also missed by the NMPC self-assessment,

but were later identified and corrected by NMPC:

1) incorrect tap setting on the 4160-600V

transformer which served the HPCS system auxiliaries; and 2) inadequate pickup voltage

characteristics of motor starter contactors for the HPCS system motor-operated valves

(MOVs). However, these additional findings and the deficiencies that were identified later

were, in the team's opinion, a rare exception, rather than the lack of indepth and

comprehensive review by the NMPC self-assessment

team.

6.0

UNRI<SOI VED ITEMS

Unresolved items are matters about which more information is required in order to ascertain

whether they are acceptable items, deviations, or violations.

Unresolved items are identified

in the Executive Summary of this report.

7.0

EXITMEETING

The licensee's

management

was informed of the scope and purpose of this inspection at the

entrance meeting on November 29, 1993.

The findings of this inspection were discussed

with the licensee's

representatives

during the course of the inspection and presented

to

licensee management during the exit meetings on December 17, 1993, and January 28, 1994.

The licensee did not dispute the inspection findings during the exit meeting.

A list of

attendees

is presented in Attachment 1.

ATTACHMENT1

Persons Contacted

Nia ara M hawk Power

o

oration

T. Aiken

A. Anderson

W. Baker

M. Bullis

U. Buiva

J. Bunyan

J. Conway

R. Dean

C, Deban

R. Deuvall

S. Doty

G. Eldridge

P. Flint

D. Greene

J. Guariglia

J. Halusic

A. Issa

J. Jirusek

A. Julka

N. Kabarwal

K. Korcz

H. Lockwood

R. Main

L. Mott

J. Mueller

R. Orcutt

A. Pinter

A. Raju

L. Schiavone

C. Terry

K. Ward

A. Zallnick Jr.

Electrical Engineer, Unit 2 Design

Operations Department Specialist

Licensing Program Dir'ector

Supervisor, Administrative Service

Lead Engineer, Electrical Design

Senior Project Engineer

Acting Plant Manager, Unit 2

Manager, Technical Support, Unit 2

Manager, Information Management

Supervisor, Mechanical Design

General Supervisor, Electrical Maintenance

EQ Program Manager

Steno., Administrative Service

Manager, Licensing

Specialist, Mechanical Maintenance

Lead Engineer, Mechanical Design

SQ Program Manager

Lead Engineer, Special Programs

Supervisor, Unit 2 Electrical Engineering

Lead Electrical Design Engineer

Licensing, Unit 2

Supervisor, Relay and Control

Maintenance Engineer

Project Designer, Unit 2

Plant Manager, Unit 2

Superintendent,

Power Dept.

Site Licensing Engineer

Electrical Engineer, NMPC EDSPI Team Leader

Mechanical Design Engineer

Vice President, Nuclear Engineering

Manager, Engineering, Unit 2

Supervisor, Unit 2 Licensing

Attachment

1

~Con rect r

R. Das

G. Morris

ASTA Engineering

Ogden Engineering

Nucl

r Re

lat

ommission

W. Mattingly

J. Menning

B. Norris

W. Ruland

NRC Resident Inspector

Project Manager, NRR

Senior Resident Inspector

Chief, Electrical Section, DRS

ATTACEQCENT 2

Abbreviations

A or Amp

ac

BHP or bhp

BIL

BOP

CB

CFR

dc

ECCS

EDG

FSAR

GDC

GE

, gpm

HPCS

HVAC

IEEE

kA

kv

kVA

kW

LC

LOCA

, LOOP

MCC

MOV

NSSS

PSI or psi

RG

rms

RSST

THD

TS

UPS

USNRC

UST

UV

V

Vac

Vdc

Amperes

Alternating Current

Brake Horsepower

Basic Insulation Level

Balance of Plant

Circuit Breaker

Code of Federal Regulations

Direct Current

Emergency Core Cooling System

Emergency Diesel Generator

Final Safety Analysis Report

General Design Criteria

General Electric

Gallons Per Minute

High Pressure

Core Spray

Heating Ventilation and Air Conditioning

Institute of Electrical and Electronics Engineers

Kiloamperes

Kilovolts

Kilovolt-amperes

Kilowatts

Load Center

Loss of Coolant Accident

Loss of Offsite Power

Motor Control Center

Motor-Operated Valve

Nuclear Steam Supply System

Pounds per Square Inch

USNRC Regulatory Guide

Root Mean Square

Reserve Station Service Transformer

Total Harmonic Distortion

Technical Specifications

Uninterruptible Power Supply

United States Nuclear Regulatory Commission

Unit Service Transformer(s)

Undervoltage

Volt(s)

Volts Alternating Current

Volts Direct Current

0*

345KV TO

ATION (LIME 23)

42/56/78HYA

RESERYE

BANK

'A'5/+5k

'45/25KV

Scu~g

4./PI&+

RBSHVA EACH

~ gag

xQ(R

ttskv/i3 gk.v/~J6kv

J

L

UNIT

25KY~

~NORHAL ST4

TRANSF,

24. Y6V/IXSKV

I88-58/58HYA

I154

13,tgvqi

a+ils~I/

8'puA6~ B

LMI8 ~

42/56/78HVA

RESERVE

BAN( 8

2gTX-Q4

115KV SOURCE '8'OR '4

AVX BOILER

NO

CVL ONLY .

2%'S-SVGNI

13.8KV

NORHAL

AVX. TRANSF.

CUB. 0%.Y

20%-SMG883

AUX. TR4NSF.

NC

I3JRV

AUX.BOILER

BUS

2M%-SMG882

NORHAL 4.168KY

205-S'MGBH

NC

AS-SkeIS

ZNNS-SVGSII

2WS-SNGBI2

~-SNGB13

4.16KV

4.16KV

NO

STUB BVS

STUB BUS

CUB.

ONLY

i.16~V OIV.I -I

EHERGENCT

BUS

ZENS~SWGIBI

NO

2ENS SVGI82

NO

~ 4.168KV OIV.3

El+RGENCY

BVS

ZENS'SNGI83

4.168KV GIVE

Ek%RGENCY

- BVS

EGI OIV.I

44NKN

ATTACHMENT 3

Nine Mile 2 Electrical Distribution S stem

EG2 OIV.3

~6%~ Y

m&4/z

zsHS4<cc zo I

EG3 GIVE

4INKN

SKASZ.nrM

0