ML20151B498

Insp Repts 50-338/88-01 & 50-339/88-01 on 880116-0223. Violations Noted.Major Areas Inspected:Plant Status, Unresolved Items,Licensee Action on Previous Enforcement Matters,Ler Followup & Review of Inspector Followup Items

ML20151B498
Person / Time
Site:	North Anna
Issue date:	03/30/1988
From:	Caldwell J, Cantrell F, King L NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II)
To:
Shared Package
ML20151B480	List: ML20151B476 ML20151B489 ML20151B498
References
50-338-88-01, 50-338-88-1, 50-339-88-01, 50-339-88-1, NUDOCS 8804080259
Download: ML20151B498 (14)

See also: IR 05000338/1988001

Text

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

A8 #80uf UNITED STATES

Do NUCLEAR REGULATORY COMMISSION

"

[\ c REGION il

$ g j 1o1 MARIETTA STREET. N.W.

• ' 2 ATLANTA, GEORGI A 30323

\+...+/

Report Nos.: 50-338/88-01 and 50-339/88-01

Licensee: Virginia Electric and Power Company

Richmond, VA 23261

Docket Nos.: 50-338 and 50-339 License Nos.: NPF-4 and NPF-7

Facility Name: North Anna 1 and 2

Inspection Conducted: January 16 - February 23, 1988

Inspectors: Y #ceI d eqt"Inspector

A- Mf/

Date Signed

J. t.7 Caldwell, wb Senior

bi ig{e Y)f/f$

L. P M ing, Resident 171 'o r f Date Signed

Approved by: ,n I 8k 3 3MF9_

F. 'Cfntrell, Section Utgy'V Da(e Si%ned

Division of Reactor Projects

SUMMARY

Scope: This routine inspection by the resident inspectors involved the

following areas: plant status, unresolved items, licensee action on previous

enforcement matters, licensee event report (LER) followup, review of inspector

follow-up items, monthly maintenance observation, monthly surveillance

observation, ESF walkdown, and operator safety verification. During the

performance of this inspection, the resident inspcetors conducted reviews of

the licensee's backshift operations on the following days - January 18, 24, 28,

29, 31, February 1, 2, 3, 5, 6, 9, 11, 12, 15 and 16.

Results: One violation with two examples for failure to follow procedure and

failure to have an adequate procedure.

8804080259 880331

PDR ADOCK0500g8

0

. .

.

REPORT DETAILS

1. Licensee Employees Contacted

• E. W. Harrell, Station Manager

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

• G. E. Kane, Assistant Station Manager

• M. L. Bowling, Assistant Station Manager

J. A. Still, Superintendent, Operations

M. R. Kansler, Superintendent, Maintenance

• A. H. Stafford, Superintendent, Health Physics

• D. A. Heacock, Superintendent, Technical Services (Acting)

• J. L. Downs, Superintendent, Administrative Services

J. R. Hayes, Operations Coordinator

E. S. Hendrixson, Engineering Supervisor ( Acting)

D. E. Thomas, Mechanical Maintenance Supervisor

G. D. Gordon, Electrical Supervisor

L. N. Hartz, Instrument Supervisor

F. T. Terminella, QA Superviror

J. P. Smith, Superintendent, Engineering

D. B. Roth, Nuclear Specialist

J. H. Leberstein, Engineer

• G. G. Harkness, licensing Coordinator

• D. B. Roth, Nuclear Specialist

• T. R. Maddy, Superintendent, Security

• G. D. Miller, Licensing Coordinator (Surry)

Other licensee employees contacted include technicians, operators,

mechanics, security force members, and office personnel.

• Attended exit interview

NRC Regional Management Site Visit: B. Wilson and F. S. Cantrell

conducted a visit of the North Anna Power Station on February 3, 1988.

2. Exit Interview (30703)

The inspection scope and findings were summarized on February 23, 1988,

with 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 338/88-01-01: Failure to follow procedure and failure to

have ar. adequate procedure resulting in a 1000 gallon leak from the RCS

(see paragraph 8).

(0 pen) Inspection Follow-up Item 338,339/88-01-02: Disc separated from

stem on RTD loop isolation valves.

__

__

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

. .

. .

'

.

(0 pen) Unresolved Item 339/88-01-01: Potential for failure to perform a

post maintenance test (see paragraph 9).

3. Plant Status

Unit 1

Unit 1 began the inspection period in Mode 5, day 4, of an unscheduled

27-day outage. Unit 1 entered the outage due to resin being discovered in

the secondary systems and the steam generators. On January 23, a 35 gpm '

leak developed on the "B" Reactor Coolant System (RCS) loop RTD bypass

line. The unit was still in Mode 5 with the RCS level being maintained at

approximately 10 inches above nozzle centerline. The cause of the leak

was the performance of maintenance on the wrong flange in the RTD bypass

line (see section 8 for details). 1he leak was identified and isolated

without any affect on the unit or the operating Residual Heat Removal

(RHR) punp. As a result, the station manager stopped all work inside ,

'

containment until the work in containment could be reviewed to ensure that

personnel performing the work had conducted proper pre-job planning. Work

in centainment was allowed to recommence on January 24.

On February 2, a pressurizer Power Operated Relief Va?;u (PORV) lifted at

its low pressure setpoint of 345 psig while starting the "A" Reactor

Coolant Pump (RCP) (see section 11 for details). On February 8, day 27 of

the resin intrusion outage, the licensee restarted Unit 1. The reactor ,

was taken critical at 0323 on February 8 and achieved 100% power on

February 12. The unit is operating at approximately 100% power as of the

end of the inspection period.

,

Unit 2

i

I Unit 2 commenced the inspection period operating at approximately 100% i

power. On February 12, the licensee voluntarily shutdown Unit 2 based on

l

NRC concerns relating to the ASME Code Section XI compliance with several

containment isolation valves (see Inspection Report 338, 339/88-02). The

unit was in Mode 3 by 0135, the valves in question were tested and

repaired as necessary to ensure compliance with ASME Code Section XI, and

the unit was restarted on February 14. As of the end of the inspection '

period, Unit 2 is operating at approximately 100% power.

Both Units

On January 21, 1988, the NRC conducted an enforcement conference with the

.

licensee i n the Region II Atlanta of fice. The enforcement conference

j involved a discussion on environmental qualification type violations (see

i Inspection Report 338,339/87-32) and the violations cssociated with

l

inoperable steam flow instruments discovered during the Unit 2 start-up on

'

November 4 (see Inspection Report 338,339/87-38).

l On January 26, Station Management conducted a meeting with all the station i

j supervisors to discuss the significance of the recent problems and ,

l

,

,

,n---.,-,r-,-,e---------r--e.e v- -m- - - ~ - - ---.,.-,------,r ,--+--,--+,w -----,-rw-~mq-w,,-------- -,r,w--,- --.-w v~w '

.. . - . . . ~ . . .- . . . . ..

. .  !

. .

-

.

3

,

violations that had been identified in the last several months. The

meeting was conducted to ensure that station supervision was aware that

problems have occurred, that they understood their significance, and

finally that they understood the necessity to prevent their recurrence.

<

The resident inspector attended the meeting.

4. Unresolved Items

'

An Unresolved Item is a matter about which more information is required to

4 determine whether it is acceptable or may involve a violation or

deviation.

One unresolved item was identified during this inspection and is discussed

in paragraph 9.

,

5. Licensee Action on Previous Enforcement Matters (92702)

(Closed) Violation 338/87-24-01: Failure to have a Safety Evaluation for

i

Leaking Steam Generator Plugs and Foreign Objects. Maintenance procedures

have been revised to include criteria for requiring a deviation report to

be submitted for any abnormal occurrence. Administrative Procedure 5.3

includes a step in the list of review criteria to instruct the reviewer

that a station deviation report be submitted when unexpected activities

are encountered,

l

Licensee Event Report (LER) Follow-Up (90712 & 92700)  !

'

6.

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

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

i inspectors confirmed that no unreviewed safety questions were involved and t

l that violations of regulations or Technical Specification (TS) conditions j

. had been identified. t

!

(Closed) LER 338/87-17: Steam Generator Tube Rupture. Responses will be

tracked under AIT report 338/87-24 dated August 28, 1988.

,

7. Review of Inspector Follow-up Items (92701)

!

(Closed) IFI 338/87-24-08: Review Securing of LHSI Pump Early. The

i licensee has received concurrence from Westinghouse that the pump was

secured in the proper sequence as directed in the Emergency Response  ;

Guidelines. The licensee has determined that overheating of the pumps on r

recirculation is not a valid concern for North Anna. Therefore, the  !

I

licensee has changed their Emergency Operating Procedure to secure the  !

! LHSI pumps after the leak has been isolated. '

l i

'

?

'

i

i

4

i

_ - . _ _ . . _ __ ___ __ _.,_ _._ _ _ _ _ _

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

. .

. .

.

.

.

,

8. 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 Technical i

Specifications.

Unit 1 outage commenced on January 13 to flush and drain the steam

. ' generators due to resin intrusion.

"

The most significant work accomplished during the outage was:

4

a. Replacement of "A" reactor coolant pump seal;

i b. "C" main steam trip valve overhaul;

I c. Motor changeout of "A" recirculation fan;

,

d. Overhaul of 1-SI-P-1B (LP I pump B);

I e. Flush and fill of steam generators to remove resin fines,

i

'

i

The inspector made containment entries to observe work on items (a) and

(c) above. No problems were identified.

'

j

1

! The Low Head Safety Injection Pump,1-SI-P-1B, was overhauled due to its [

marginal acceptance of the differential pressure criteria during previous  !'

periodic tests. (See Inspection Report 338, 339/87-34)

i r

Following the pump overhaul, the inspector observed the installation of

i 1-SI-P-1B (Low Pressure Injection Pump) and reviewed the purchasing of the

!

spare parts that were replaced on 1-SI-P-18. It was determined from

i discussion with the licensee's Engineering and Quality Assurance

'

Departments that several of the parts were purchased from another

facility as non-safety related. This included three shaft sleeves and "0"

rings. The inspector had a concern that these were purchased as

l

non-safety related parts instead of safety related. The licensee had

written a risk release document which was dispositioned by Engineering

l saying that the non-safety related parts could be used until the next

outage. The risk release document is a licensee internal docurnent which

allows parts which do not meet all of the requirements to be released for

installation pending further engineering review. This review must be

l completed before the piece of equb.aent for which the parts were t; sed is

,

declared operable.

l

l

The licensee has written a Technical Report No. ME 0011, Rev. 1, which

'

accepts the journal sleeves as meeting the three criterial for commercial

l

grade as described in 10 CFR 21. The licensee then dedicated these sleeves

for use as a base component in the LdSI pump based on the dimensional

requirements being verified by recefst inspection and receipt of a letter

from the pump vendor stating that the material is the some for commercial

!

l

l

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

n __ - _

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

.

. .

5

as for nuclear grade. The licensee's intention, based on a letter from

the vendor verifying the parts as acceptable and Revision 1 of Technical

Report ME-0?ll, is not to replace the journal sleeves, but to accept them

as is. This process was discussed with the NRC staff in Region 11 and

determine ' to be acceptable.

On Jant 23, with Unit 1 in Mode 5 and vessel level being maintained at

approximately 10 inches above nozzle centerline, the operator noticed an

increasing reactor sump level. The vessel level which was being monitored

by a standpipe located in the containment with a television monitor in the

control room also indicated a decreasing level. The operators secured

letdown, increased makeup to the vessel and entered 1-AP-16, Excessive

Primary Leakage. Shortly af ter discovering the loss of water from the

primary, the operators were contacted by mechanics in the containment and

informed of a leak from a loop B RTD bypass line flange which the

mechanics could not isolate. The operators maintained vessel level well

above that necessary to provide Net Positive Suction Head (NPSH) to the

operating RHR pump, continued to monitor the operation of the RHR pump and

dispatched four operators into the containment to isolate the leak.

The leak was isolated approximately 30 minutes after discovery by an

operator shutting one of the RTD bypass line isolation valves (1-RC-59)

inside containment. The leak was determined to be approximately 35 gpm

and a little over a 1000 gallons had leaked into the containment sump.

The Health Physics (HP) Staff conducted sampling activities and determined

that an airborne condition did not occur and that there was no indication

of any radioactive release.

Following the leak isolation, the operators vented the operating RHR pump

and determined that no air or gases had entered the pump. Also the Shift

Supervisor had entered containment and determined that the standpipe level

scale (ruler) had been installed approximately six inches above where it

should have been, therefore, actual vessel level was being maintained at

approximately 16 inches instead of 10 inches above nozzle centerline.

Based on the above and the fact that the elevation of the flange which

caused the leak was actually above the top of the nozzle there did not

exist a potential for a loss of all RHR.

The inspector reviewed the licensee's procedures for installation of the

standpipe and the level scale (ruler). The instructions for installation

of the standpipe were contained in 1-0P-5.4, Draining the Reactor Coolant

System, which stated, "Request the planning dept, to generate repetitive

work orders to remove blank flanges and install the desired spool pieces

and level hose." There were no other instructions for installation with

the exception of a signoff in 1-0P-5.4 for the level hose installed

between 1-RC-104 and pressurizer vacuum breaker tee. The inspector

determined, based on discussion with the operators, that the ruler is

installed by the operators without any procedure. The standpipe, a tygon

hose, is connected to valve 1-RC-104 which penetrates the Reactor Coolant

System (RCS) at an elevation approximately nozzle centerline. Conse-

quently, the operators locate the ruler next to the tygon hose so that the

bottom of the ruler is located approximately the same elevation as the

. . - - . - - - . - -

. .

.

. .

i 6

.

?. t

valve's,1-RC-104, penetration into the loop. Since there is no formal

method or procedure to install the standpipe and level scale, then there

are no checks, signoffs or second verification to ensure that the

standpipe and level scale is installed properly. The failure to have an  !

adequate procedure to ensure proper installation of the RCS level i

standpipe and reference level scale will be identified as the first  ;

example of Violation (338/88-01-01). ,

The licensee determined the cause of the leak to be the failure of the

'

mechanics to perform maintenance on the right flange inside containment.

The mechanics were requested to repair a leak on flow element flange

1-RC-FE-1491 per work order 5900070293. The mechanics were to perform

4 their repair per Mechanical Maintenance Procedure, K9-C-P-4,

Oisassembling, Inspection, Repairing, Reassembling Safety-Related Piping

System Bolted Flanges in General.

,

There were two flanges located in the same general area on the loop B RTO

bypass line, one to the flow element 1-RC-FE-1491 which was the flange

that was supposed to be worked and the other to flow ori fice 1-RC-R0-1.

Both flanges had their lagging removed, neither had identification tags

i installed and the wrong flange 1-RC-RD-1 was the only one with boric acid

! on it because the other flange had been cleaned in preptration for work.

Consequently, the mechanics choose the flange to wrrk, liased on the boric

acid buildup and the fact that they found several loose bolts, instead of

leaving the containment to make sure which was the right flange. The

licensee also determined that the locatior of the item to be worked or

whether it would be identified was not discussed during the mechanics

a pre-work briefing.

The inspector questioned why maintenance on a loop RTD bypass line flange

1 had not had isolation set prior to the start of work. The licensee

,

informed the inspector that isolation had been considered but based on the

'

elevation of the flange and the fact that vessel water level was being

maintained well below that elevation, the Shift Supervisor considered

j isolation unnecessary. The inspector is aware of a desire on the part of

j the licensee not to use the RTO bypass line isolation valves because most

j of them have had their discs separated from the valve stem. This

! condition was discovered by the licensee back in 1985 but was determined

j to be acceptable as long as flow through the RTD line was sufficient to

'

keep the loop RTD's operable. Consequently closing these valves may

prevent them from being reopened by the RTO bypass line flow which would

result ia inoperable RTO loop protection signals. During the restart

'

following the outage sufficient flow was developed in the "B" loop RTO

4 bypass line indicating that the valves did unseat and continued operation

with these valves was considered acceptable. Based on the continued

acceptable RTD bypass ficw through these valves and the high dose that

would be encountered during their repair or replacement, t% licensee has

elected not to perform permanent repairs at this time. However, the

licensee informed the inspectors that they intend to make oermanent

repairs in the future and are still in the process of determining the best

rae thod . The inspector reviewed the licensee justification for operation

i

.

'

'

. .

.

i

.

.

'

7

1

4

with inoperable valves, and requested regional review of this problem.

This is identified as laspection followup item (338,339/88-01-02).

i

The failure of the licensee to properly isolate and perform work on the

correct comoonent per Maintenance Work Order 5900070293 and MMP-C-P-4

resulting in approximately a 1000 gallon leak from the. RCS constitut's a

,

failure to follow procedure. This failure to follow procedure will .e

identified as the second example of Violation (338/88-01-01).

'

As a result of the event, the Station Manager stopped all work inside

containment until the event could be fully evaluated and until all othar

work could be reviewed to ensure that proper pre-job planning had been

performed. Work was allowed to recommence on January 24. It should also

be noted that this event occurred just prior to the scheduled licensee

management meetings with all station personnel to discuss the importance

of attention to detail and proper adherence to procedures. This

particular event was used as one of the examples of the problems that had

occurred stressing the importance of following procedures. The meetings i

commenced on January 26, two days after the flange leak incident. l

All three steam generators were flushed and drained to remove any

intrusion of powdex resins. The feedwater and condensate lines were also

i flushed and sampled. An inspection of the condensate polishers indicated

that several internal candles had come loose at the bottom allowing resin

'

fines to escape. The licensee has had a manufacturer's representative in

4

to look at the problem. Procedures and tests are being developed to

i prevent recurrence. The licensee is writing a voluntary LER.

1

'

The "C" Main Steam Trip Valve (MSTV),1-MS-TV-101C, was investigated to

determine possible problems due to unusual noise. After the

! investigation, wMch was inconclusive, the valve failed to pass the

, periodic test procedure 1-PT-212.9 for valve stroke. The closing time

t took greater than six seconds on several attempts to perform 1-PT-212 9.

l This is greater than the maximum five seconds allowed by Technicil

l Specifications requiring the valve to remain inoperable. ,

The inspector reviewed work request 530643 to overhaul the C MSTV. The

! licensee replaced the springs in both actuators for the valve and the

, valve still failed. An engineering work request was written which

i increased the size of the bleed-off line from the actuators from a

! one-half inch line to a one inch line and an additional solenoid valve was

installed (via an approved modification). Retest of the valves then  ;

j indicated a 3.9 second closure which was acceptable. l

.

I The inspector reviewed work request 371640 and observed the work on main

'

steam non-return valve (1-NRV-102C) on Unit 1 steam generator "C" outlet. *

l The non-safety related valve had been previously Furmanited to stop a leak

i and the Furmanite was being removed to allow repacking the valve for the l

l permanent repair. '

l

l I

!

!  !

-_ _. _ __ _ ____ _ _ _ _, . _

-- _.

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

.

+

.. .

'

.

8

i

4

'

The inspector also observed replugging of leaky tubes on the first stage

feedwater heater 2-FW-E-1A for Unit 2.

f

The inspector reviewed and observed work being performed per work request 238703 on Unit 2 auxiliary turbine driven feedpump. The pump was being

repacked, the oil was drained and replaced, and a leaky lube oil cooler

was removed, plugged and reinstalled. The inspector observed the

surveillance test performed after the work had completed (see Surveillance

Section for 2-PT-71.1). .

'

9. Monthly Surveillanco (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

4 conditions for operation (l.CO) were met and that any deficiencies

identified were properly reviewed and resolved, s

The inspector observed the following surveillances:  ;

a. 2-PT-71.1, Test of Auxiliary Turbine Driven Feedpump. The test

'

. failed due to a high differential pressure which caused the relief

! valve to open. The governor was readjusted and the pump was retested ,

satisfactorily. During the course of the test, the motor driven

l auxiliary feedpump room filled with steam. The licensee traced the

i problem to the drain lines from the turbine driven feedpump to the

motor driven feedpump room being crosstied and isolated by a foot i

i valve which stuck open. This allowed drains from the turbine driven

auxiliary feedpump to back up into the motor driven pump room. The

licensee worked on the foot valve and the volume of steam was

! reduced. The licensee stated the amount of steam still leaking was ,

l insignificant and would be removed by the exhaust system. ,

j b. On February 3,1988, the inspector observed Periodic Test 1-PT-212.4

4 to determine closing time of 1-MOV-FW-154C, the main feedwater

isolation valve for "C" steam generator. This valve failed the

periodic test by closing in excess of the required maximum of five

i seconds, A deviation report anc work request was submitted to

Engineering who dispositioned them, stating under 6.5 seconds was

acceptable 'or the safety analysis (FSAR allowed closure time is 9 i

j seconds).

t

l c. On February 3, 1988, at 1817, the Unit I reactor coolant pump "C" was

1 secured to stroke 1-TV-CC-102A and 1-TV-CC-100C using periodic test

l 1-PT-212-1. No prcblems were identified.

i

( d. On February 11, 1988, as a resu; of a concern by an NRC Quality

l

Assurance Audit Team, the lict : sue decided to stroke 2-TV-CC-203 A

and B, which are the componen cooling water from the residual heat

l removal and excess letdown heat exchanger (see Inspection Report 338,  ;

l 339/88-02).

!

l -

_ _ _ _ _ _ _ _

. .

. .

.

9

The resident inspector entered the Unit 2 outside penetration area

with a licensee engineer to witness the stroking of the valves using

Periodic Test 2-PT-212.1,

When the stroke test was performed on 203A, the valve closed limit

switch light never actuated in the control room. It was observed by

the inspector that the valve started to close approximately 30

seconds after the solenoid was deenergized and the valve rotated 90

degrees to the close position. A retest of the valve using a

stopwatch in the penetration area indicated the valve closad in 47.8

seconds. Valve 203 B was also tested and closed in 62.5 secords.

This was above the required 60 seconds in Technical Specification

3.6-1.

The licensee engineer and inspector noted that one-fourth inch piping

was :nstalled on the outlet port of the solenoids. The inspector

questioned if a modification had been made and was inf' med that the

valves were modified during the Unit 2 outage. The ir.spector asked

the licensee to retest the valves without the tubing and research the

stroke times before and after the modification change. The research

showed the times had changed significantly af ter the modification.

The licensee wrote an engineering work request and removed the tubing

and the valves retested at 16.5 and 24.4 seconds, respectively.

The inspector obtained copies of engineering work requests86-498 A,

B, and C, which installed the tubing on the discharge of the solenoid

valves. It was determined that "ASC0" recommended to the licensee

that the exhaust port of their catalog NP-1 valves should be fitted

with downward pointing street elbows to prevent moisture from

entering the internal areas of the valve. It stated that moisture

entering the internal areas of the valve could cause degradation of

internal parts, galling of piston, scale buildup and mechanical

failure of the valve.

In addition, QDR 35.1 and ASCO qualification reports AQR-67368 and

21678 require the solenoid operated valves be ven'ad and arranged

such that chemical spray will not enter the system through any vent

opening.

A review of the licensee Engineering Work Request that installed the

modifications revealed that the licensee allowed the use of tubing to

fitting adapters as well as street elbows to be installed. The

tubing restricted the air flow causing the valves to close more

slowly. A further review iiMicated that Administrative Procedure

3.8, Attachment 1 (Design Procedure Input Checklist) indicated on

page 3 that test requirements inu'uding in plant tests was marked not

applicable for all three engineerins work requests86-498 A, B and C.

The inspector was concerned that modifications had been made to the

valves without testing. The Technical Specification requires the

valves to be operable in Mode 1 thru 4.

- -

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

. .

. .

.

10

The inspector was informed that some of the valves were tested by

Operations during performance of routine periodic test before

entering Mode 4 and even though the valves passed, some of the stroke

times had increased. The licensee did not identify at that time that

the stroke times had increased due to the modification. The licensee

is investigating to determine if any modifications were made after

leaving Mode 5. Any modifications made af ter leaving Mode 5 would

require post modification testing prior to the valve being declared

unoperable. This will be identified as Unresolved Item (URI)

339/88-01-01, pending inspector review to determine if the

modifications were installed after leaving Mode 5 and if post

maintenance testing was performed,

e. On January 29, the inspectors witnessed Special Test 1-ST-77 which

performed a retest on the LHSI pump 1B following its overhaul (see

Maintenance, Section 8). The test first placed the LHSI pump in the

recirculation mode and completed 1-PT-57.1B, ECCS Subsystem Low Head

SI Pump (1-SI-P-1B) satisfactorily. Then with the unit in Mode 5, the

pressurizer level at 10% and the pressurizer PORVs blocked open, the

licensee opened the LHSI pump discharge valve to perform a full flow

test of the pump which was not requireo by regulations. Shortly

after the discharge valve was opened, and flow and pressure data were

taken, the LHSI pump was secured to prevent filling the pressurizer

solid (approximate 40 second run time).

Based on full flow data and associated discharge pressure data taken,

the pump was determined to be operating well above the design

operating curve. The licensee determined that the flow reading was

correct, based on a comparison with the change in pressurizer level,

and in line with the expected flow rate for those conditions.

However, the discharge pressure was too high. The licensee

determined, based on a calculation of the horse power needed to

develop the recorded discharge pressure and flow rate, that the pump

had an efficiency greater than one, which is impossible. Since the

flow rate had been determined to be accurate, the licensee concluded

that the discharge pressure data at full flow was not correct. Using

the data recorded from the recirculation phase of the pump operation,

both at full recirculation, approximately shutoff head and full flow,

the licensee was able to calculate, based on some conservative

assumptions, a best estimate of the discharge head of the pump at

full flow This discharge head and flow data point was just below

the design head curve but above the curve used for the basis for

Emergency Core Cooling System (ECCS) performance. After discussion

with the vendor, a review of the vibration data which was very low,

achieving a satisf actory flow rate, the satisfactory performance of

the Technical Specification required surveillance, and an engineering

review of the calculational bisis for the estimate of the pump head

at full flow conditions, the licensee declared the LHSI pump 1B fully

operational. The licensee has been unable to determine the cause of

the incorrect discharge pressure reading.

_ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ - _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _

. .

. .

'

11

f. On January 29, the inspectors witnessed the stroke time testing of

MOV 18900, a LHSI pump discharge valve. The test which was conducted

per 1-PT-213.8, Valve Inservice Inspection (Safety Injection System)

was performed satisfactorily.

No violations or deviations were identified.

10. 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

February 16, 1988.

The inspectors walked down the valve alignment of the Unit 1 Low Head

Safety Injection System using valve checkoff list 1-0P-7.1A. The manual

valves inside containment and the valves in the safeguard valve pit area

were not checked. No problems were identified.

The inspectors informed the licensee of the following observations:

a. The valve area had various tools and trash laying around;

b. Staging was installed in the Low Head Safety Injection (LHSI) pump

cubicles;

c. Valves 1-SI-217 and 1-SI-314 need caps installed;

d. Valve 1-SI-307 (Recirculation Line Vent) had boron residue on the

pipe cap and packing gland indicating a leak.

The licensee has removed the tools, trash, and staging from the LHSI area.

The inspectors also requested that the licensee perform safety evaluations

in the future prior to installing any equipment such as staging around

safety related equipment. The licensee has committed to performing these

safety evaluations.

No violations or deviations were identified.

11. 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 Technical Specification (IS) and Limiting Conditions for

Operations.

_ _ _ _ - _ _ - _ - _ _ _ _ - - _ _ _ _ _ _ _ _ _ _ _ _ _ _ _

-, .

. .

.

12

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

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

4

various shifts of the security force was 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. In

addition, the resident inspectors observed protected area lighting,

protected and vital areas barrier integrity and verified an interface

2 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

.

1

3

conducted per the RWPs.

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; and confirming valve positions, instrument and recorder

readings, annuciator alarms, and housekeeping.

'

The following comments were noted:

On February 2, with Unit 1 in Mode 5 preparing to return to power

operation, a Power Operated Relief Valve (PORV) lifted at it's low

. pressure setpoint. The Unit was solid with pressure approximately

320 psig and the "B" Reactor Coolant Pump (RCP) operating just prior to

the event. The licensee had just started the "A" RCP and the operators

.j were increasing pressure to maintain the necessary differential pressure

j across the number one seal on the "A" RCP. By the pressure indication

1 available to the operator in the control room, primary pressure appeared

! to be stable around 335 psig. However the PORV lifted at its setpoint of

345 psig. The operators immediately began reducing pressure by increasing

letdown to reclose the PORV but also tried to maintain the necessary

200 psig across the "A" and "B" RCP number one seals. The PORV reclosed

but the operators were unable to maintain the necessary differential

. pressure across the number one seals and the "A" and "B" RCPs had to be

4

secured. Initial NRC review of the events surrounding this value lifting

i indicated no operational problems.

!

l The licensee has determined several corrective actions which should

l prevent recurrence of PORV activations during solid plant operations.

! These corrective actions will be detailed in the LER 88-008 to be issued

l by the licensee before March 2. The inspector will review and follow up

1 on these corrective actions during the associated LER review and close

. out.

l

1

!

,

I

,

t

. .

.

13

On February 12, the licensee voluntarily shut Unit 2 down in response to

questior.s raised by the NRC concerning compliance with ASME Code Section

XI on certain containment isolation valves (see Inspection Report

338, 339/88-02 for details). These containment isolation valves were

associated with component cooling water to the RCPs and should not be

stroke tested with the RCPs running. Consequently, the licensee shut the

unit dcwn to allow securing of the RCPs for stroke testing and repairs as

necessary of the component cooling water containment isolation valves.

The inspectors witnessed the testing of several of the valves per

1-PT-212.1, Valve Inservice Inspection (Component Cooling System). All of

the valves were tested satisf actorily with the exception of TV-CC-201B

which closed in 62.4 seconds. The Technical Specification (TS) require-

ment for this valve is less than 60 seconds and the results from the last

satisfactory test performed on October 25, 1987, indicated the valve

closed in 6.6 seconds. The valve was declared inoperable and the

appropriate TS action statement was entered.

The licensee removed, overhauled and reinstalled the solenoid valves

associated with TV-CC-201B and all other valves that had previously failed

or were in the alert condition. The overhaul and inspection of the

solenoid valve TV-SOV-CC-201B did not reveal any proolems which would have

caused the solenoid to stick. The licensee completed retests of the

component cooling water containment isolation valves prior to the unit

restart. All the valves were tested satisfactorily and TV-CC-201B closed

in approximately 6.2 seconds. Unit 2 was restarted on February 14 and

placed back on line on February 15, 1988.

No violations or deviations were identified.