ML20155A191

Insp Repts 50-338/88-22 & 50-339/88-22 on 880716-0819. Violations Noted.Major Areas Inspected:Plant Status,Maint, Sueveillance,Esf Walkdown,Operational Safety Verification, Operating Reactor Events & LER Followup

ML20155A191
Person / Time
Site:	North Anna
Issue date:	09/15/1988
From:	Caldwell J, Cantrell F, King L NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II)
To:
Shared Package
ML20155A185	List: ML20155A182 ML20155A186 ML20155A191
References
50-338-88-22, 50-339-88-22, NUDOCS 8810050242
Download: ML20155A191 (13)

See also: IR 05000338/1988022

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J* ' '4 UNITED STATES

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]* NUCLEAR REGULATORY COMMISSION

REGION 11

%e'.,.[ 101 MARIETTA ST., N.W.

ATLANTA. GEORGIA 30323

Report Nos.: 50-338/88-22 and 50-339/88-22  ;

Licensee: Virginia Electric and Pcwer Company

Richmond, VA 23261

Docket Nos.: 50-338 and 50-339 License No:.: NPF-4 and NPF-7

Facility Name: North Anna 1 and 2

Inspection Conducted: fuly 16 - August 19, 1988

Inspectors: - /fh[

J. E. Caldwell, Seni6/ es ent Inspector Da'te Signed

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L. Ff.~ King, Resident Inpf4 tor

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Date S'igned

Appioved by: ~ d.

F. S.'Cantrell, Section C) W

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Dafe Signed

Division of Reactor Projects

SUMMARY

Scope: This routine inspect.f on by the resident inspectors involved the

following areas: plant status, maintenance, surveillance, ESF

walkdown, operational safety verification, operating reactor events,

licensee event report (LER) followup, and licensee action on previous

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enforcement matters. During the performance of this inspection, the i

resident inspectors conducted reviews of the licensee's backshif t

operations on the following days - July 18, 25, 26, and August 1, 2,

4, 5, 7, 10, 11, and 12.

Results: Within the areas inspected, one violation was identified with three

examples for failure to follow procedure, and one Inspector Followup

Item (IFI).

(0 pen) IFI 338/88-22-01, followup on the cause of Unit 1 "C" main

feedwater isolation va've failure to close (paragraph 3).

(0 pen) Violation 338/88-22-02, failure to follow a containment entry ,

procedure with three examples (paragraph 6).

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8810050242 880913

PDR ADOCK 05000338

0 PDC

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REPORT DETAILS

1. Persons Contacted

Licensee Employees

M. Cowling, Assistant Station Manager

J. Downs, Superintendent, Administrative Services

• R. Orfsco11, Quality Control Manager

R. Enfinger, Assistant Station Manager

G. Gordon, Electrical Supervisor

L. Hartz, Instrument Supervisor

D. Heacock, Superintendent, Technical Services

• G. Kane, Station Manager

M. Kansler, Superintendent, Maintenance '

• T. Maddy, Supervisor, Security

T. Porter, Superintendent, Engineering

J. Stall, Superintendent, Operations

A. Stafford, Superintendent, Health Physics

F. Terminella, Quality Assurance Supervisor

D. Thomas, Mechanical Maintenance Supervisor

• 0. VandeWalle, Corporate Licensing

Other licensee employees contacted included engineers, technicians,

operators, mechanics, security force members, and office personnel.

• Attended exit interview

NRC Management Site Visit: M. Ernst, Deputy Regional Administrator;

C. Hehl, Deputy Director, Division of Reactor Projects (DRP); B. Wilson,

Chief, Reactor Projects Branch 2, DRP; H. Berkow, Director, Projects

Directorate II-2, Nuclear Reactor Regulation (NRR); L. Engle, Project

Manager, NRR; and C. Pate11, Project Manager, NRR visited the North Anna

site on July 27, 1938. The visit involved a tour of the station and the

presentation of the SALP results to the licensee.

2. Plant Status

Unit 1

Unit 1 began the inspection period operating at approximately 100% power.

On August 6, Unit 1 tripped from 100*. power due to a steam flow / feed flow

mismatch with a low water level in the "B" steam generator (S/G) (see

section 7 for details). Prior to the trip, the unit had been operating at

approximately 100% power since March 25, 1988. On August 8, the unit

restarted and, following the secondary chemistry holds and instrumentation

repairs, achieved 100% power on August 13. Unit 1 operated at

approximately 100% power for the remainder of the inspection period.

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REPORT DETAILS

1. Persons Contacted

Licensee Employees

M. Bowling, Assistant Station Manager

J. Downs, Superintendent, Administrative Services

"R. Driscoll, Quality Control Manager

R. Enfinger, Assistant Station Manager

G. Gordon, Electrical Supervisor

L. Hartz, Instrument Supervisor

D. Heacock, Superintendent, Technical Services

• G. Kane, Station Manager

M. Kansler, Superintendent, Maintenance

• T. Maddy, Supervisor, Security

T. Porter, Superintendent, Engineering

J. Stall, Superintendent, Operations

A. Stafford, Superintendent, health Physics

F. Terminella, Quality Assurance Supervisor

D. Thomas, Mechanical Maintenance Supervisor

• D. VandeWalle, Corporate Licensing

Other licensee employees contacted included engineers, technicians,

operators, mechanics, security force members, and office personnel.

• Attended exit interview

NRC Management Site Visit: M. Ernst, Deputy Regional Administrator;

C. Hehl, Deputy Director, Division of Reactor Projects (DRP); B. Wilson,

Chief, Reactor Projects Branch 2, DRP; H. Berkow, Director, Projects

Directorate 11-2, Nuclear Reactor Regulation (NRR); L. Engle, Project

Manager, NRR; and C. Patell, Project Manager, NRR visited the North Anna

site on July 27, 1938. The visit involved a tour of the station and the .

presentation of the SALP results to the licensee.

2. Plant Status

Unit 1

Unit 1 began the inspection period operating at approvimately 100% power.

On August 6, Unit 1 tripped from 100% power due to a steam flow / feed flow

mismatch with a low water level in the "B" steam generator (S/G) (see

section 7 for details). Prior to the trip, the unit had been operating at

approximately 100% power since March 25, 1988. On August 8, the unit

restarted and, following the secondary chemistry holds and instrumentation

repairs, achieved 100% power on August 10. Unit 1 operated at

approximately 100% power for the remainder of the inspection period.

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Unit 2

Unit 2 began and ended the inspection period operating at approximately

100*4 power.

Both Units

On July 18, the licensee requested and received discretionary enforcement

from the NRC to allow them to exceed the Technical Specification (TS)

containment temperature limit of 105 degrees Fahrenheit. At the time of

the request, both containments were approximately 103 degrees Fahrenheit

due to the inoperability of the mechanical chiller during an extended

period of 95-100 degree waather. The licensee had submitted a TS

amendment to the NRC in March 1988 to' change the TS containment tempera-

ture limit to 120 degrees Fahrenheit. Based on this submittal, the NRC

granted the licensee discretionary enforcement to allow the containment

temperature to exceed 105 degrees Fahrenheit, but not to exceed 110

degrees Fahrenheit for the time necessary to repair the mechanical

chiller. On July 19, the mechanical chiller was repaired. Technically,

the discretionary enforcement was not required since only Unit 2 exceeded

the 105 degree F limits and was returned to less than the limit well

within the TS action statement time limit. Both units' containments are

being maintained around 100 degrees.

On July 27, 1988, Region II and headquarters personnel presented the SALP

results to the North Anna Station management and staff. The presentation

was conducted at the site in the North Anna Information Center (NAIC)

auditorium. The Virginia Electric and Power Company personnel who

attended the presentation included J. Ferguson, President and C.E.O. ; W.

Stewart, Senior Vice President, Power Operations; D. Cruden, Vice

President, Nuclear Operations; G. Kane, Station Manager, North Anna;

R. Saunders, Manager, Nuclear Programs; J. Wilson, Manager, Nuclear

Operations Support; N. Hardwick, Manager, Nuclear Licensing; R. Hardwick, 1

Manager, Quality Assurance; R. Enfinger, Assistant Station Manager, North

Anna; M. Bowling, Assistant Station Manager, North Anne., and approximately

150 other station and corporate personnel. NRC representatives are

identified in paragraph 1.

3. Maintenance (62703)

Station maintenance activities affecting safety related systems and

components were cbserved/ reviewed to ascertain that the activities were

conducted in accordance with approved procedures, regulatory guides and

industry codes or standards, and in conformance with the Technical

Specifications (TS).

On August 4, the inspectors witnessed the licensee adjust the inboard

packing on motor driven auxiliary feedwater pump 2-FW-P-3A. The packing

adjustment was performed per Mechanical Maintenance Procedure MMP-C-GP-1,

Inspection and Repair of Safety Related Pumps in General. The only noted

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problem was identified by the operator and mechanics performing the work.

The outboard packing was also leaking excessively and needed adjustment.

Since the work order only addressed the inboard packing adjustment, the

mechanics were unable to adjust the outboard packino without violating

procedures. The pump was secured, and a work request was initiated to

adjust the outboard packing during the next scheduled pump operation. The

leak was not of a nature to affect the operability o'/ the pump. No other

problems were noted.

On August 7, the inspectors witnessed portions of the MOVATS test of the

"C" main feedwater line motor operated isolation valve. The maintenance,

performed per Electrical Maintenance Procedure EMP-P-MOV-3, Predictive

Analysis of MOVs, was necessary because the valve failed to fully close

during the reactor trip that occurred the day before (see discussions of

this event in the end of section 7). The electrician informed the

inspectors that the valve's limit switches for both opening and closing

were of f and needed adjustment. The closing limit switch appears to be

the cause of the valve failing to fully close when the automatic closure

signal was received. No problems were identified with the performance of

the maintenance. The inspector has requested the licensee provide

information concerning the cause of limit switches being out of

adjustment. This will be identified as Inspector Follow-up Item (IFI

338/88-22-01).

On August 11, the inspectors witnessed the calibration of feedwater flow

instrument 1-FW-FI-1486 for the "B" main feedwater line per Instrument and

Control Proedure ICP-FW-1-F-1486, SG 1B Feed Flow Protection Channel IV.

The calibration was being performed because the feed flow indication in

the control room was out of the TS required tolerance. Unit 1 was in the

process of a startup at the time, and the licensee had placed the

protection channel associated with the feed flow instrument in trip. The

inspector observed that the technicians were unable to calibrate the

instrument. Folicwing the determination that the calibratien procedure

could not be completed successfully, the licensee attempted to repair the

transmitter. This repair was also unsuccessful, consequently, the

licensee replaced the feed flow transmitter, calibrated the new

instrument, and placed the instrumentation back on linc. No problems were

identified by the inspector,

ho violations or deviations were identif'.ed.

4. Surveillance (61726)

The inspectors observed / reviewed TS 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.

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The licensee informed the inspectors that on July 23, during the perfor-

mance of 1-PT-31.7.2, Pressurizer Level Channel II (L-460) Functional

Test, an Eutomatic isolation of the charging system letdown line occurred.

The licensee investigated the event and determineo the cause of the

isolation was an inadequate procedure. The procedure required the

operator to olace a defeat switch in the wrong position, and consequently,

the automatic isolation of letdown occurred when the test signal was

generated. Further investigation by the licensee determined that

1-PT-31.7.2 had recently been revised, and this was the first time the

procedure had been used since the revision. A review showed that the

switch position was correct in the previous procedure, consequently, the

revision and suosequent int.dequate review resulted in an inadequate

procedure.

Following the letdown isolation, the operators were able to re-establish

letdown withot;t causing a transient on the unit. A review by the inspector

did not identify any safety concerns reltting to the event. However,

TS 6.8.1.c requires that w itten procedures to be established, imple-

mented, and maintained covering surveillance and test activities of safety

related equipment. The failure of the licensee to establish and maintain

an adequate procedure to perform a surveillance on the pressurizer

level channel without resulting in automatic action is a violation of

TS 6.8.1.c. Since this violation was identified, investigated, and

corrected by the licensee and meets the criteria of 10 CFR 2, Appendix C,

for licensee identification, this item will be considered a Licensee

Identified Violation (LIV 338/88-22-03, Failure to Prov'de Adequate Test

Procedure). LIVs are considered first-time occurrence violations which

meet the NRC enforcement policy criteria for exemption from issuance of a

Notice of Violation. These items are identified to allow for proper

evaluation of corrective actions in the event that similar events occur in

the future.

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On July 25, the inspectors witnessed the surveillance test on the Unit 2

"B" component cooling water pump. The test was conducted per test

procedure 2-PT-74.28, Component Cooling Pump (2-CC-P-18). The inspectors

did not identify any problems associated with the performance of the test.

The licensee informed the inspectors that there was an inadvertent

l automatic start of the 2-CH-P-1A charging pump on July 26. This pump,

! which is also the high head safety injection (HHSI) pump, was autometi-

cally started due to a safety injection related undervoltage signal. The

inadvertant start was caused by personnel error during tne performance

of surveillance test procedure 2-PT-36.9.1.J. Degraded Voltage / Loss of

Voltage Functional Test, 2J Bus. The personnel error involved the

improper reinstallation of the relay cover on relay 27C such that the

contacts remained closed even af ter tht: relay was de-energized. This

relay, 27C, which becomes energized on an undervoltage signal, or in

this case, a test signal, will start the Unit 2 "A" and "C" charning

pumps. Prior to the initiation of the test signal, the licensee p aced

! the "A" charging punp in pull to lock, by procedure, to prevent the punp

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from automatically starting. The "C" charging pump was already operating.

Following the initiation of the test signal, test personnel verified that

the relay 27C was energized, replaced the relay cover, and removed the

test signal which de-enerigized relay 27C. The licensee took the "Ad

charging pump controller out of the pull to lock position. As soon as the

controller was taken out of pull to lock, the Unit 2 "A" charging pump

automatically started. The operator verified that this pump was not

required to be operating, and secured the pump by placing the controller

back in pull to lock.

The licensee investigated the event and found that the cover on relay 27C

had been misaligned when it was reinstalled. Following the removal of the

cover and proper reinstallation, the automatic start signal no longer

existed. Using a similar relay, the licensee demonstrated to the

inspectors the sequence of events which could lead to this situation. The

licensee was able to install the relay cover in such a way to cause the

relay contacts to remain closed even though the relay was not energized.

The licensee determined the event to be reportable. A four-hour report

was made and an LER was issued. The inspectors will followup on the

corrective actions, and close out the issue during the review and close

out of LER 88-02, Inadvertent Engineering Safety Features System

Actuation.

On August 2,1988, the inspe-tors witnessed test 2-PT-71.1, Steam Driven

Auxiliary Feedwater Pump and Valve Test. The test was performed

satisfactorily.

On August 17, the inspectors witnessed portions of the surveillance test

on one of the hydrogen recombiners per 1-PT-68.1.2, Hydrogen Recombiner

Functional Test 2-HC-HC-1. During the performance of the test, several

problems were identified associated with non technical issues. The first

problem involved steps 4.9.1. 4.9.2, 4.13, 4.14, 4.20, 4.21, 4.33, and

4.34 which identified the motor control switches for the blower and the

cooling fan differently than the actual label plates. The second problem

involved the placement of the master control switch (HS-1) in the start

position, but the procedure did not take the switch out of start. The

licensee corrected both of these discreoancies with a procedure deviation.

The inspectors did not identify any other problems.

On August 18, the inspectors witnessed 2 .0T-57.1A, which was the 2-SI-P-1A

low head safety injection pump test. The test was performed

satisfactorily.

No violations or deviations were identified.

5. ESF System Walkdown (71710)

The following selected ESF systems were verified operable by performing a

walkdown of the accessible and essential portions of the systems on

August 11, 1988. Using procedure 1-0P-21.9A, Va've Checkoff Control Room

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Bottled Air Pressurization System, the resident inspector walked down the

control room bottled air system. The following comments were noted:

a. Fill connection sample valves 1-CA-33 and 2-CA-36 and, the pigtail

isolation valves 2-CA-31-1 thru 2-CA-31-42 were observed not to be

labeled.

b. Bottles 1-CA-1-7, 1-CA-1-9, and 1-CA-1-10 are labeled out of

sequence.

No violations or deviations were identified.

6. 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 shif t 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 LCOs.

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

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

i various shifts of the security force were observed in the conduct of 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.

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 inform e >n a daily basis, of the overall status of

both units and of any sd '

icant safety matter related to plant

operations. Discussions w. held with plant management and various

members of the operatite- teaff on a regular basis. Selected portions of

operating logs and data s w ; 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,

and annuciator alarms; and observing housekeeping.

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On August 8, the inspector witnessed Unit 1 startup to criticality. No

problems were encountered and the reactor was critical within the

estimated critical position. On August il, the inspectors witnessed the

licensee increasing power above the 5% chemistry hold point and cnanging

from Mode 2 into Mode 1. When the licensee reached approximately 12%

power, just prior to placing the generator on line, Channel IV of the "B"

feed flow instrumentation was determined to be inoperable. The licensee

placed the protection channel in trip and decided to correct tne

instrument problem prior to placing the turbine generator on line (see the

end of paragraph 3). During the repair of the feed flow instrument, the

inspector observed that Channel III of the "C" steam flow instrumentation

had failed low. Subsequently, the licensee placed the steam flow

protection channel in trip. Also, during the time while the

instrumentation was being repaired, the inspector observed the licensee

vent pressure from the Primary Relief Tank (RPT) using Operating Procedure

1-0P-5.7.

On August 12, following the repair of the feedwater flow instrument, the

licensee, af ter verifying that the prob'eem with the steam flow instrument

was not in the instrumentation, decided to continue with the startup with

the steam flow protection channel in trip. With the unit at approximately

20 percent power, Channel III of "C" steam flow instrumentation came back

into specification and was taken out of trip. The startup continued

without further instrumentation problems. The licensee has written 1 work

request for the "C" steam flow instrumentation to determine the cause of

the problem. This work request will be performed during the next

available outage.

On August 9, 1988, at 1618, a first aid emergency was declared at Unit 1

containment hatch. Unit 1 was in Mode 2 at less than 5 percent power. A

contractor employee experienced heat exhaustion. He was administered

oxygen and carried to the Health Physics office, where a nurse examined

and released him to return to duty. The entry was made at 1528 by two

health physics technicians and two contractor personnel to inject

Furmanite into a leaky packing gland on a disc pressurization valve

(RC-187) for the "A" cold leg isolation valve.

The inspector requested and received the maintenance history on 1-RC-187.

The maintenance history indicates that 1-RC-187 had never had the packir.g

replaced and the valve had not been scheduled to be repacked. Futher

review of the event by the inspectors revealed that two previous entries

had been made to determine the problems identified with the valve. One

entry identified the leak path and the other entry was an attempt to

adjust the packing to stop the leak. Af ter adjusting the packing as much

as possible, the valve still leaked and a decision was made to inject

Furmanite into the valve. A review of the containment entry procedures by

the resident inspector indicated the following:

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a. Attachment 1 of Administrative Procedure (AP) 20.9, Containment

Ingress and Egres', is a subatmospheric containment entry checklist.

The resident obtained a copy of the checklist while the containment

was being exited (on August 9). Only the portion of the checklist up

to incore detectors tagged out was initialed. The inspector was told

that several other steps had been completed but not signed off. Step

7.1 of the procedure requires that each department comolete the

applicable sections of attachment 1 as the steps are completed. The

failure of the licensee to follow AP 20.9 and complete the checklist

as required will identified as a violation (338/88-22-02).

b. In the entries made on August 8 at 0924 and 1618, the required wet

bulb temperatures were not documented and the calculated stay times

were not determined as required by step 7.14 of Administrative

Procedure 20.9. The failure of the licensee to follow AP 20.9 will

be identified as an additional example of violation (338/88-22-02).

7. Operating Reactor Events (93702)

The inspectors reviewed activities associated with the below listed

reactor events. The review included determination of cause, safety

i significance, perfcemance of personnel and systems, and corrective action.

The inspectors examined instrument recordings, computer printouts,

operations journal entries, scram reports, and had discussions with

operations, maintenance and engineering support personnel as appre?riate.

At 2257 on August 6, 1938, Unit 1 of the North Anna Power Station tripped

due to a steam flow / feed flow mismatch with a coincident low steam

generator (S/G) water level in the "B" S/G. Just prior to the reactor

trip, the operators had placed the shunt reactors (additional inductive

loads) in service at the request of the load dispatcher. These shunt

reactors are loads directly of f of the 34.5 kv buses which supply the

emergency buses through the reserve station service transformers (RSST).

Following the connection of the shunt reactors, the 34.5 kv buses

decreased in voltage, and consequently, so did the 4160 volt emergency

buses which are the secondary side of the RSSTs (34.5 kv/4.16 kv

transforners). The design of the RSSTs include an automatic tap changer

on the secondary (emergency bus) side of the transformer which will

compensate for decreases in the primary side voltage by changing the taps

necessary to maintain required voltage on the secondary side. However, in

this case, the licensee determined that the automatic tap changer for the

RSST supplying the Unit 1 J emergency bus did not operate. The 1 J bus

sensed a degraded voltage and separated itself from the RSST. The 1 J

emergency diesel generator (EOG) started and loaded onto the bus as

designed.

The problem with the transfer of the 1 J emergency bus to the 1 J EDG in

itself did not result in the reactor trip. However, some of the non-vital

loads on the 1 J bus, which are shed during a degraded voltage situation,

involve some secondary system steam valves which closed along with the

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feedwater recirculation valves which resulted in a steam /feedwater

transient. This transient resulted in a demand on the feedwater

regulating valves to close. The "B" feedwater regulating valve failed to

reopen resulting in the team flow / feed flow mismatch and low S/G water

level trip signal. An inspection by the licensee revealed that the "B"

feedwater regulating valve stem had broken, separating the disc from the

actuator. Consequently, once the valve went closed the actuator could no

longer reopen the valve. The licensee has experienced problems with feed

regulating valve stems breaking in the past, and modifications have been I

performed on both Unit 1 and Unit 2 feedwater regulating valves. The

modifications on the Unit 2 valves are more advanced, including a bigger

stem, and appear to have solved the problem. The licensee had scheduled

the same modifications on the Unit 1 valves during the next refueling

outage.

Following the trip the Unit 1 feedwater regulating valves were inspected

and repaired as necessary. The "B" feedwater regulating valve stem and

actuator were replaced.

All of the systems operated as required with a few exceptions. The major

problem following t'ie trip was the f ailure of the "C" main feedwater

isolation valve to fully close. The failure of the feedwater system to

fully isolate resulted in a cooldown below the normal 547 degrees F to

approximately 538 degrees F with a resulting pressure decrease to 1870

psig. The licensee manually isolated feedwater and maintained S/G levels

with the auxiliary feedwater system which was already in operation. The

problem relating to the failure of the "C" feedwater isolation valve to

close is discussed in Section 3 of this report. Followup will be via

inspector follow-up item (IFI) 338/88-22-01.

The only other problems associated with the trip were several valve

position indicators whici, did not function properly; a problem with one of

the steam dump valves, and the failure of the General Electric Transient

Analysis recording systems to actuate. The inspectors will followup on

the licensee's actions and closeout these issues based on the LER review

and closecut.

No violations or deviations were identified.

8. Licensee Event Report (LER) Follow-up (90712)

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

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 technical specifications (TS) conditions

had been identified.

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LERs that identify violation (s) of regulation (s) and that meet the

criteria of 10 CFR, Part 2, Appendix C,Section V are identified as

License.2 Identified Violations (LIV) in the following closecut paragraphs.

LIVs are considered first-time occurrence violations which meet the NRC

enforcement policy criteria for exemption from issuance of a Notice of

Violation. These items are identified to allow for proper evaluation of

corrective actions in the event that similar events occur in the future,

a. (Closed) LER 338/87-12, Rev. 0: Inadvertent Partial Solid State

Protection System Actuation

A safety injection slave elay (K602) was energi:ed during the

performance of Reactor Protection and Engineered Safety Features

Response Time Test (Periodic Test 36.5). The root cause of the

inadvertent actuation was procedure inadequacy. The procedures have

been revised and approved by SNSOC.

b. (Closed) LER 338/87-14, Rev. 0: Loss of RCS Inventory While In Cold

Shutdown

The licensee has issued an operations directive and station manager's

memo notifying personnel to be aware of any testing not covered in

the Final Safety Analysis Report (FSAR). It outlines the steps to be

taken for a 10 CFR 50.59 evaluation. Training has also been

accomplished for the operators on loss of inventory. Other

corrective actions are being tracked by the violations identified in

inspection report 87-21.

c. (Closed) LER 338/87-21, Rev. O and Rev. 1: Loss of Environmental

Qualification of SI Accumulator Tank Pressure Transmitters

STO-GN-0001, Instructions For DCP Preparation, has been revised to

provide additional guidance and instructions for design change

package (DCPs) which require the installation of equipment per the

manufacturer's installation instructions,

d. (Closed) LER 338,339/87-23, Rev. O and 1: Kaman Process Vent Normal

Range Radiation Monitor Exceeded T.S. Action Statement.

The monitor has been repaired. An alternate method using the

Westinghouse monitor was available to accomplish automatic actions.

Additionally, the Nuclear Research Corporation radiation monitors

continued to operate throughout this event as the Technical

Specification required preplanned alternate monitoring method on the

process vent release path,

e. (Closed) LER 338/87-17, Rev. 1: Steam Generator Tube Rupture

Responses will be tracked under the items identified in AIT report

338/87-24 dated August 28, 1988.

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f. (Closed) LER 338/88-15, Rev. 0: RHR Pumps Not Tested During Steam

Generator Tube Rupture Outage

A station deviation report was submitted to notify the responsible

department of the missed surveillsnce and to schedule it for the next

time the unit is in Mode 5. The ISI Pump and Valve program was

reviewed to ensure there were no other missed surveillances. This

item is identified as a LIV (338/83-22-04) for failure to conduct a

surveillance on schedule. Based on the licensee's corrective action

and program this LER and LIV are closed.

9. Licensee Action on Previous Enforcement Matters (92702)

(Closed) Licensee Identified Violation (LIV) 338,339/87-19-17: Core

Alteration Without A Charging Pump

The licensee investigated this and similar instances where mode changes

were made without taking proper action. This was investigated using the

Human Performance Evaluation System (HPES) techniques. The licensee had

developed mode change checklists to avoid these problems in the future.

10. Exit

i The inspection scope and findings were summarized on August 19, 1988, with

those persons indicated in paragraph 1. The inspectors described the

areas inspected and discussed in detail the inspection results listed

below. The licensee did not identify as proprietary any of the material

providad to or reviewed by the inspectors during this inspection.

Dissenting comments were not received from the licensee.

<

l Item Number Description and Reference

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338/88-22-01 Inspector Followup Item (IFI) - Followup on the cause

1

of Unit 1 "C" main feedwater isolation failure to

4

fully close (paragraph 3) j

338/88-22-02 Violation - Failure to follow a containment entry

procedure with three examples (paragraph 6)

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