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Insp Repts 50-338/87-38 & 50-339/87-38 on 871120-1218.Three Violations Noted.Major Areas Inspected:Plant Status,Ler Followup,Monthly Maint & Surveillance Observation,Esf Walkdown,Operator Safety Verification & Health Physics
	ML20149E621
Person / Time
Site:	North Anna
Issue date:	01/15/1988
From:	Caldwell J, Cantrell F, King L; NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II)
To:	;
Shared Package
ML20149E589	List: ML20149E587; ML20149E596; ML20149E621;
References
	50-338-87-38, 50-339-87-38, IEB-87-002, IEB-87-2, NUDOCS 8802110183
	Download: ML20149E621 (12)
	v • d • e

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UNITED STATES

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NUCLEAR REGULATORY COMMISSION

I ~d REGION H

h 101 MARIETTA STREET,N.W.

" * ATLANTA, G EORGI A 30323

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Report Nos.: 50-338/87-38 and 50-339/87-38

Licensee: Virginia Electric & Power Company

Richmond, VA 23261

Docket Nos.: 50-338~and 50-339

Facility Name: North Anna 1 and 2

Inspection Conducted: November 20 - December 18, 1987

Inspectors: 4 /w

J.~ L. Caldwell, Seri)(f Resident Inspector

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Date Signed

MG

L.' P. King, Resident'4nspe'ctor

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Approved by: 4[M2

F. 5. Cantrell, Secti5 ief

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Division of Reactor Pr cts

SUMMARY

Scope: This routine inspection by the re:fdent inspectors involved the

following areas: plant status,. licensee event report (LER followup), monthly

maintenance observation, monthly surveillance observation, ESF walkdown,

operator safety verification, operating reactor events, Temporary Instruction

(TI) 2500/26, cold weather preparation, health physics, and instrumentation

problems related to startup of Unit 2. During the performance of this inspec-

tion, the resident inspectors conducted reviews of the licensee's backshift

operations on the following days - November 17, 18, 23, 24 and December 1, 2,

3, 4, 5, 7, 8, 14, 15, 16, 17 and 18, 1987.

Results: Three violations were identified: (1) Failure to follow the require-

ments of RWP-87-3156 (see paragraph 13); (2) Failure to perform adequate post

maintenance testing on Unit 2 "A" Steam Generator Flow Channel III (see

paragraph 14); (3) Violation of Technical Specifications (TS) 3.3.1.1 and

3.3.2.1 for failure to declare two steam flow channels inoperable (see

paragraph 14).

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REPORT DETAILS

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1. Licensee Employees Contacted

ti. W. Harrell, Station Manager

R. C. Driscoll, Quality Control (QC) Manager

G. E. Kane, Assistant Station Manager

H. L. Bowling, Assistant Station Manager

R. O. Enfinger, Superintendent, Operations

H. R. Kansler, Superintendent, Maintenance

A. H. Stafford, Superintendent, Health Physics

J. A. Stall, Superintendent, Technical Services

J. L. Downs, Superintendent, Administrative Services

J. R. Hayes, Operations Coordinator

D. A. Heacock, Engineering Supervisor

D. E. Thomas, Mechanical Maintenance Supervisor

G. D. Gordon, Electrical Supervisor

L. N. Hartz, Instrument Supervisor

F. T. Termine11a, QA Supervisor

J. P. Smith, Superintendent, Engineering

D. B. Roth, Nuclear Specialist

J. H. Leberstein, Engineer

G. G. Harkness, Licensing Coordinator

L. L. Edmonds, Superintendent, Nuclear Training

N. K. Martin, Security

Other licensee employees contacted include technicians, operators,

mechanics, security force members, and office personnel.

The following members of the regional staff met with the North Anna staff

on December 16, 1987, for a presentation of current plant initiatives and

a plant tour:

M. L. Ernst, Deputy Regional Administrator

A. F. Gibson, Director, Division of Reactor Safety

C. W. Hehl, Deputy Director, Division of Reactor Projects (DRP)

F. S. Cantrell, Chief, Proejet Section 2A, DRP

Attended exit interview

2. Exit Interview (30703)

The ins)ection scope and findings were summarized on December 18,

1987, w< th those persons indicated in paragraph 1 above. The licensee

acknowledged the inspectors findings. The licensee did not identify as

proprietary any of the material provided to or reviewed by the inspectors

during this inspection.

(0 pen) Violation 338/87-38-01: Failure to follow the requirements of RWP

87-3156 (see paragraph 13).

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(0 pen) Violation 339/87-38-01: Failure to perform adequate post

maintenance testing on Unit 2 "A" Steam Generator Steam Flow Channel III

(FI-2474) (see paragraph 14).

(0 pen) Violation 339/87-38-02: Violation of T.S. 3.3.1.1 and 3.3.2.1 for

failure to declare "A" Steam Generator Steam Flow Channel III and "B"

Steam Generator Steam Flow Channel IV inoperable. This is being

considered for escalated enforcement (see paragraph 14).

(0 pen) Unresolved Item 339/87-38-03. Lack of overpressure protection for

the B accumulator (see paragraph 9).

3. Plant Status

Unit 1

Unit 1 began the inspection period operating at 100% power. On November 23,

the unit tripped due to a failed high level switch on the SA feedwater

heater (See paragraph 10 for details). The unit was back on line by

November 24. On November 28, the "B" Reactor Coolant Pump (RCP) number

one seal leak off went off scale high. This resulted in a forced reactor

shutdown to replace the "B" RCP seal package. On December 8, the licensee

restarted Unit 1, and the unit is presently operating at 100% power.

Unit 2

Unit 2 began and ended the inspection period operating at 100% power.

However, on December 3, the Unit 2 "B" accumulator relief valve began

lifting, making it difficult for the operators to maintain the required

pressure in "B' accumulator. The licensee gagged the failed relief and

installed one from Unit 1 in the vent line next to the original relief

valve (See paragraph 9 for details).

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4. Unresolved Items

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i An unresolved item is a matter about which more information is required to

determine whether it is acceptable or may involve a violation or

deviation.

One unresolved item was identified in this report and is discussed in

paragraph 9. q

5. Licensee Event Report (LER) Follow-up (90712 and 92700) i

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The following LERs were reviewed and closed. The inspector verified that

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reporting requirements had been met, that causes had been identified, that

corrective actions appeared appropriate, that generic applicability had

been considered, and that the LER forms were complete. Additionally, the

inspectors confirmed that no unreviewed safety questions were involved and

that violations of regulations or TS conditions had been identified. !

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(Closed)~LER 339/86-01 (Rev.1): High Lift Setpoints on Main Steam Safety- 4

Valves. The valves have been tested at Wyle Laboratories and reset.

(Closed) LER 338/87-06: RCP Busses Undervoltage Relays Out of Tolerance:

1/2 PT-33.2A,B,C were revised to include the new dropout voltages.

(Closed) LER 338/87-16: Inoperable Turbine Overspeed Protection System

Due to Incorrectly Reassembled Intercept and Reheat Stop Valves. A

procedure has been developed to control maintenance on both Units 1 and 2

intercept and reheat stop valves. The procedure includes steps for proper

identification of components. Each valve and actuator will be uniquely

identified to preclude incorrect assembly.

(Closed) LER 338/87-19: Excessive Skin Exposure Due to Contamination From

Hot Particle Transferred to Individual from Laundered Protective Clothing.

The following actions have been taken by the licensee:

a. An automatic laundry monitor has been installed.

b. Four additional personnel contamination monitors have been purchased

and placed into operation.

c. A one hour session was developed and conducted for radiation workers

at station. Hot particle information has been included with General

Employee Training.

d. A four hour session was developed and conducted 17 times to give

special training to all Health Physics technicians.

e. Radiological work practice #22C was developed to provide guidelines

for establishing controls for hot particles.

(Closed) LER 338/87-09 (Rev. O and 1): Main Steam Safety Valves Setpoints

Below TS Minimum. All 15 safety valves were sent to Wyle Labs for

testings. Eleven safety valves had low setpoints and were readjusted to

within specifiestion. The safety analysis contained in Chapter 15 of the

UFSAR was still bounding and there was no unreviewed safety question.

(Closed) LER 338/87-13: Loss of Normal Power Supply to Emergency Bus

During Testing. The licensee determined the root cause was failure to

follow procedure. The electrical maintenance procedure has been revised to

emphasize the requirement that all wires need to be lifted prior to

testing relays.

(Closed) LER 338/87-18 (Rev. 0 & 1): Non-Environmentally Qualified Motor

As Required Had No Documentation. The licensee determined the root cause

of the event. Present level of training should prevent reoccurrence.

(Closed) LER 338/87-03: Single Component Failure in Access Control

Cardreaders/ Failure Could Have Permitted Unauthorized / Undetected Access

into Vital Areas. The licensee has taken corrective action.

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(Closed) LER 339/87-03: Improper Determination of Quadrant Power Tilt

Ratio. QPTR was determined by one set of four symmetric incore thimbles

instead of two sets. The P-250 program was revised so that a tilt is only

printed when eight of the symmetric thimbles are obtained and calibrated.

The program has been implemented on both Units 1 and 2 P-250 computers.

(Closed) LER 339/87-06: Reactor Trip Caused by a Failing Intermediate

Range Detector. Detector replaced and calibrated. Also, replaced H.V.

power supply, P-6 bistable board and spare bistable board.

(Closed) LER 339/87-08: Pressurizer Safety Valves Set Pressures Not

Within TS Limits. The safety valves were repaired and readjusted at Wyle

Labs to within the correct set pressure allowed by TS 3.4.3.

6. Monthly Maintenance (62703)

Station maintenance activities affecting safety related systems and

components were observed / reviewed, to ascertain that the activities were

conducted in accordance with approved procedures, regulatory guides and

industry codes or standards, and in conformance with TS.

The inspector attended several daily maintenance meetings during the

outage to replace the radial motor bearings and the seal package on the

Unit 1 "B" reactor coolant pump. The inspector made several tours of the

containment and observed the work on the radial bearings for the "B"

reactor coolant pump motor. 1he Westinghouse procedure for the repair was

reviewed. Readings taken before the bearings were replaced indicated the

tolerances were out of specification. It was not clear at this time if

the seal failure was due to the problem with the radial bearing.

The inspector observed work on the replacement of a drain valve FW-69 on

the 1-RC-E-1A main steam generator feed line.

Several valves were repacked on the "C" accumulator during this outage.

The inspector noted during a walkdown of containment that the following

additional accumulator valves appeared to need repacking based on boric

acid buildup on valve stems. The licensee was informed of the inspectors'

observations:

a. Motor operated valve 1850 C

b. "B" accumulator outlet

c. All three accumulators makeup valves

d. "A" accumulator lower level transmitter shutoff valve 1-51-117

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The inspector reviewed the work order and inspected che work on main

r feedwater valve FW-110. This is a pressure seal valve that was leaking

badly before the outage. The manufacturer was contacted and a spacer ring

was machined. The valve was reassembled.

No violations or deviations were identified.

7. Monthly Surveillance (61726)

The inspectors observed / reviewed technical specification required testing

and verified that testing was performed in accordance with adequate

procedures, that test instrumentation was calibrated, that limiting

conditions for operation (LCO) were met and that any deficiencies

identified were properly reviewed and resolved.

On November 25, 1987, the inspectors observed 2-PT-14.1 "Test of the

Unit 2 "A" Charging Pump". No problems were identified.

On December 3,1987, the inspectors observed containment air lock leak

rate test 1-PT-62.4. The seal failed the test and needed to be replaced.

The next test was performed satisfactorily on December 12, 1987.

On December 2,1987, the inspectors observed the start of the security

aiesel using test 1-MISC-20. No problems were identified.

No violations or deviations were identified.

8. ESF System Walkdown (71710)

The following selected ESF system was verified operable by performing a

walkdown of the accessible and essential portions of the system on

December 15, 1987:

A check was made of the Unit 1 casing cooling system using operations

checklist 1-0P-7.10A.

No violations or deviations were identified.

9. Operational Safety Verification (71707)

By observations during the inspection period, the inspectors verified that

the control room manning requirements were being met. In addition, the

inspectors observed shift turnover to verify that continuity of system

status was maintained. The inspectors periodically questioned shift

personnel relative to their awareness of plant conditions.

Through log review and plant tours, the inspectors verified compliance

with selected TS and Limiting Conditions for Operations.

In the course of the monthly activities, the resident inspectors included

a review of the licensee's physical security program. The performance

of various shifts of the security force was observed in the conduct of

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' daily activities to include: protected and vital areas access controls,

searching of personnel, packages and vehicles, badge issuance and retrieval,

escorting of visitors, patrols and compensatory posts. In addition, the

resident inspectors observed protected area lighting, protected and vital

areas barrier integrity and verified an interface between the security

organization and operations or maintenance.

On a regular basis, radiation work permits (RWP) were reviewed and the

specific work activity was monitored to assure the activities were being

conducted per the RWPs. Selected radiation protection instruments were

periodically checked and equipment operability and calibration frequency

was verified.

The inspectors kept informed, on a daily basis, of overall status of both

units and of any significant safety matter related to plant operations.

Discussions were held with plant management and various members of the

operations staff on a regular basis. Selected portions of operating logs

and data sheets were reviewed daily.

The inspectors conducted various plant tours and made frequent visits to

the control room. Observations included: witnessing work activities in

progress; verifying the status of operating and standby safety systems and

equipment; confirming valve positions, instrument and recorder readings,

annunciator alarms, and housekeeping.

On December 2, at 11:45 a.m. , the Unit 2 operators commenced nitrogen

makeup to the "B" accumulator in order to maintain the pressure within the

TS limits. At 1:45 p.m., the licensee discovered that the relief valve

was lifting on the "B" accumulator and at 3:38 p.m. , the licensee gagged

the relief valve. The following day at 3:51 a.m. , the licensee

successfully blocked open the nitrogen fill isolation valve to the "B"

accumulator ensuring that the relief valve on the nitrogen fill header

would not be isolated from the "B" accumulator. This nitrogen relief

valve was exactly like the accumulator relief with the exception that the

nitrogen relief has a carbon steel body and the accumulator relief had a

stainless steel body.

On December 3, the inspectors questioned the licensee whether the relief

setpoints and capacities for the nitrogen relief and the accumulator

relief were the same and whether or not the nitrogen relief was in the

Inservice Inspection (ISI) program (i.e., periodically setpoints tested).

On December 4, the licensee informed the inspectors that at approximately

2:00 a.m., a Unit I relief valve was installed on a vent line next to the

gagged Unit 2 "B" accumulator relief valve because with different piaing

configuration, they could not demonstrate equivalent relieving capability

with the nitrogen relief valve. This vent line is the same size as the

relief line and the vent line isolation valve was locked open. The reason

for this installation was because the licensee could not demonstrate that

the relief capabilities were the same between the nitrogen relief and the

accumulator relief even though they were confident that the accumulator

could not exceed pressures beyond which it had already been tested. Also,

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even though theLnitrogen relief valve' had a listed 'setpoint of 700 isig,

.the 'same.as 'the. accumulator relief, this valve was not in the ISI program

and had not been tested since it was installed.- The valve had lifted in

the recent past due to' high pressures in the nitrogen system, but the

licensee .could. not be sure what the setpoint was. . Consequently, ' the

licensee decided to install a qualified and tested relief valve obtained -

from Unit I which was in Mode.5, cold shutdown, at the time. This item is ~

identified as Unresolved Item 339/87-38-03, pending NRC determination of

'the acceptability of the relief valve being downstream of a blocked open

isolation' valve.

On December.7, the inspectors witnessed portions of the Unit I startup per.

1-0P-1.4, Unit Startup from Hot Shutdown Condition (Mode 4) to Hot Standby

Condition (Mode 3). at 547 degrees F. Also, on-December 7,.the inspectors

witnessed portions of- 1-0P-1.5, Unit'Startup from Hot Standby Condition

(Mode 3) to Startup Condition (Mode 2) with Reactor Critical at less Than

or Equal to 5% Power, for Unit 1. During the performance of the procedure,

the rod bottom light for rod B2 in Bank A failed to go out when the rods

in Bank A were pulled past 35 steps. When the Instrumentation and Control-

(I&C) technicians could not quickly resolve the problem, the operators

elected to drive the rods in Bank A back into the core. A bistable card

was replaced.to correct the problem.

No violations or deviations were identified.

10. Operating Reactor Events (93702)

The inspectors reviewed activities associated with the below listed

reactor events. The review included determination of cause, safety

significance, performance of personnel and systems, and corrective action.

The inspectors examined instrument recordings, computer printouts,

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operations journal entries, scram reports and had discussions with

operations, maintenance and engineering support personnel as appropriate.

At 0009, on November 23, Unit 1 experienced a turbine trip and resulting

reactor trip. The turbine trip was caused by a level switch in the number

SA feedwater heater which failed high. This failure of the level switch

also tripped the condensate pumps which in turn caused the feedwater pumps

to trip and the feedwater regulating valves to go shut. Steam generator

level was restored and maintained by the auxiliary feedwater pumps until

the condensate and feedwater pumps could be restarted. The reactor

coolant system TAVE dropped to approximately 520 degrees F, pressure

dropped to approximately 1860 psig and pressurizer level dropped to less

than 15% at their lowest points.

The licensee is investigating the cause of the level switch failure.

Also, during this event, the following problems occurred:

a. With the steam dumps in the steam pressure mode below 547 degrees F,

three dump valves came open. Only two dump valves are supposed to

open; the third valve had to be de-energized shut.

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b. Two of the three main feedwater isolation valves failed to go fully

closed when the operator manually closed the valves from the control

room to reduce the leakage past the feedwater regulation valves.

c. One of the turbine trip valves failed to provide a reactor protection

trip signal or indicate a shut position in.the control room following

the turbine trip. The licensee discovered that the valve actually

went shut, but the position indication linkage was broken.

d. Two control rods, G-13 and B-6 did not indicate fully inserted

following the trip. The licensee determined that the control rods

were actually inserted and the problem was with the Individual Rod

Position Indication for those two control rods.

The inspectors will follow the licensee's actions related to the above

problems and review their corrective actions to ensure that they are

adequate.

No violations or deviations were identified.

11. Compliance Bulletin No. 87-02

On December 3,1987, the inspector participated in the selection of

fasteners in accordance with the guidelines given in the subject bulletin.

The licensee selected the fasteners by reviewing the usage rates from the

storeroom and warehouse. Sections of threaded stock were also selected.

The licensee site and corporate engineering staff as well as plant quality

assurance group participated in the selection from the storeroom and

warehouse. After the destructive testing is completed on the selected

fasteners, the results of the test will be sent by the licensee to the

NRC.

12. Cold Weather Preparation (71714) - Units 1 and 2

The inspectors reviewed the following preventative maintenance procedures

which are performed prior to cold weather:

a. PM-E-00-HT/A-1 - Heat Trace Verification

b. PM-E-00-HV/A-1 - Heaters

c. PM-M-00-SY/A-1 - Walkdown of Outdoor Areas

d. PM-M-00-SY/A-2 - Plant Winterization Program, Storeroom

e. PM-M-00-SY/A-3 - Plant Winterization Program, Mechanical Department

f. PM-M-00-SY/A-4 - Installation of Thermal Barriers

g. PM-M-00-FP/SA-1 - Fire Gate talve Lubrication

No problems were identified.

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13. Health Physics

On November 24, 1987, during the Unit 1 startup, auxiliary operators were

throttling the feedwater outlet valve from the main feedwater regulator.

This area was designated as a contaminated area by RWP E7-3156 due to

leakage from FW-110. The inspector observed that the operators were not

following the portion of the RWP that required them to obtain a whole body

frisk.

Technical Specification 6.11 requires that procedures for personnel

radiation protection shall be prepared consistent with +he requirement of

10 CFR Part 20 and shall be approved, maintained and adhered to for all

operations involving personnel radiation exposure. Licensee procedure

HP 5.310 establishes a work permit program. Health Physics procedure

5.320, "Initiating, Using, Extending and Terminating a Radiation Work

Permit (RWP)" is part of that program. It requires a radiation worker

to comply with the requirements, instructions, and precautions of the

RWP. The failure of the auxiliary operators to 3erform a whole body

frisk constitutes a violation of TS. 6.11 and is 'dentified as Violation

87-38-01.

14. Previous Inspection Followup

(Closed) Unresolved Item (338,339/87-36-03), Potential Inadequate Post

Maintenance Testing. During a review of this item, that inspectors

discovered several problems. The first deals with the discovery by the

licensee on November 4,1987, during the Unit 2 startup, the steam flow

instrument FI-2474 was inoperable due to the instrument leads being

reversed (LER 87-15). The inspector was informed by the licensee that

maintenance had been performed on this steam flow instrument during the

refueling outage in the form of replacement of the Raychem splices per

Engineering Work Request (EWR)87-206. The inspector reviewed the EWR

87-206 and discovered that for Steam Flow Instrument FI-2474, the signoffs

for post maintenance testing were not completed. The inspector determined

that this EWR had been reviewed by all the required personnel including

the station safety committee without detecting that the proper signoffs

had not been made for the post maintenance testing of FI-2474. A review

by the inspector of the actual post maintenance test revealed that if the

test had been performed on FI-2474 it would have detected the reversed

leads.

Considering the fact that there is no complete documentation of a post

maintenance testing being conducted on FI-2474, that if the test had been

performed the problem of the reversed leads would have been detected and

finally that steam flow channel FI-2474 instrument leads were in fact

reversed without being detected indicates that a proper post maintenance

test was not conducted on FI-2474 following maintenance. The result of

this lack of post maintenance testing was that the licensee operated

Unit 2 from Mode 3 through Mode 1 up to 27 percent without having the

Reactor Protection System (RPS) and Engineering Safety Feature (ESF)

trip signal associated with FI-2474 operable.

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Technical Specification 6.8.1.c requires written procedures be established,

implemented and maintained covering surveillance and test actuators of

safety related equipment. The failure of the licensee to conduct a 3 roper

post maintenance test of steam flow instrument FI-2474 following ma' nten-

ance which resulted in a degraded RPS and ESF system trip protection will

be identified as violation (339/87-38-01).

The second problem involves the delay by the operators in declaring steam

flow instruments FI-2474 ("A" Steam Flow Channel III) and FI-2485 ("B"

Steam Flow Channel IV) inoperable. During the review of the unresolved

item the inspectors reviewed the oaerator's (both SRO and CRO) shift logs

and the operator's Technical Specification (TS) required channel check

logs. Thi s review revealed that as early as 1200 noon on November 4,

1987, the operators had enough information to declare the steam flow

channels FI-2474 and FI-2485 inoperable and place then in the trip

condition as required by TS. The 1200 noon channel check logs indicated

that both the above channels were essentially reading zero steam flow

while their redundant steam flow channels as well as boths the C loop

steam flow channels were indicating approximately 0.5 x 10 pounds mass

per hour. The licensee's accgptance criteria for a proper channel check

is a maximum of i 0.25 x.10 pounds mass per hour difference between

redundant channels on a steam line. The licensee's operations standard

which addresses channel check criteria states in part that an instrument

channel shall be declared inoperable when the stated acceptance criterial

tolerances are exceeded and the applicable actions of TS shall be

implemented. At this point, the operators failed to declare the steam flow

channels inoperable and to place them in a trip condition for both RPS and

ESF trip signals as required by TS.

On November 4,1987, Unit 2 which was in Mode 2 continued with the

startup. At approximately 17:54 on November 4, Unit 2 was placed on line

and per the SRP log entry at 1816 on November 4, with the unit at 24

percent power, the steam flow channels FI-2474 and FI-2485 were reading

zero steam flow. Also a review of the channel check logs revealed that

the 2000 channel check stated that both FI-2474 and FI-2485 were pegge4

low with the redundant steam flow channels reading approximately 1 x 10

pounds mass per hour. The operators again failed to comply with TS

channel check criteria and place these steam flow channels in the trip

condition.

It was not until 2153, approximately 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months after Unit 2 achieved greater

than 20 percent reactor power, that steam flow channels FI-2474 and FI-2485

which were still reading zero (ie, failed flow) steam flow were declared

inoperable. It was later discovered that the reason for FI-2474 being

inoperable was due to the instrument leads being reversed and for FI-2485

mechanical agitation conducted on the instrument in containment caused the

channel to indicate properly. Therefore it is clear that the steam flow

channel FI-2474 was inoperable and would not have provided its RPS or EFS

trip signals from the time Unit 2 was in Mode 3 up through Mode 1 at

approximately 27 percent power and should have been placed in the trip

condition as soon as the operators had indication of a problem. Also the

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steam flow channel FI-2485 which required mechanical agitation to become

operable appeared to have been inoperable for Mode 3 through Mode 1 and

again should have been placed in the trip condition as soon Das the

operators had an indication of a problem.

TS 3.3.1.1 and 3.3.2.1 requires that all of the steam flow channels be

operable with the Unit in Modes 1, 2, and 3 and Action Statement 7 and 14

respectively state that operation.may proceed until the performance of

the next required channel functional test provided the inoperable channel

is placed in the tripped condition within 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months . The failure of the

licensee to. comply with TS 3.3.1.1 and 3.3.2.1 and place steam flow

channels FI-2474 and FI-2485 in the tripped condition within 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months

resulting in degraded RPS and ESF trip protection will be identified as a

Violation (339/87-38-02).

ML20149E621

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