ML20126B522

Insp Rept 50-440/92-22 on 921020-1120.Violations Noted.Major Areas Inspected:Ler Followup,Surveillance Observations,Maint Observations & Operational Safety Verification

ML20126B522
Person / Time
Site:	Perry
Issue date:	12/10/1992
From:	Lanksbury R NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION III)
To:
Shared Package
ML20126B491	List: ML20126B488 ML20126B507 ML20126B522
References
50-440-92-22, NUDOCS 9212220118
Download: ML20126B522 (18)

See also: IR 05000440/1992022

Text

,

,

-

V. S. NUCLEAR REGULATORY COMMISSION

REGION 111

Report No. 50-440/92(22(DRP)

Docket No. 50-440 License No. NPT-58

Licensee: Cleveland Electric illuminating Company

Post Office Box 5000

Cleveland, Oil 44101

facility Name: Perry Nuclear Power Plant

inspection At: Perry Site, Perry, Ohio

inspection Conducted: October 20 through November 20, 1992

Inspectors: A. Vogel

P. Hiland

E. Duncan

Approver' By: b Im _ tt\ 60 st

R. D. LanksbupyTChief Date

Reactor Projects-Section 3B

JJupection Summary

Jnspection on October 20 throuah November 20. 1932 (Report No.

50-440/92022(DRfil

Arras inspecteA: Routine unannounced safety inspection by resident inspectors

of licensee event report- followup, surveillance observations, maintenance

observations, operational safety verification, event followup, cold weather

preparations, and evaluation of licensee self-assessment capabilities.

Results Of the seven areas inspected, one violation was identified

concerning a failure to enter the Technical Specification (TS) 3.0.3 action.

statement when the limiting condition for operation could not be met following

identification of excessive secondary containment bypass leakage (paragraph

6.b.3). In addition, one non-cited violation (NCV) was identified in the area

of licensee event report followup (paragraph 2.b).

The following is a summary of the licensee's performance during this

inspection period:

Plant Operations

The reactor plant was operated at or near full power until October 23

when a reactor shutdown was commenced to repair a crack in the

condensate header. On October 24, during the shutdown, the reactor was

tripped from 22 percent power due to an inability to. complete a

, surveillance of the rod pattern controller. The plant was restarted on

l October 30 and remained at or near full power for the duration of the '

O

h$k $bo

G.

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

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

--

. i

+

report period. Operator control of the plant shutdown and startup was

good, with the exception of a missed average power range monitor gain

adjustment surveillance on November 1.

Maintenance / Surveillance

l

The quality of observed maintenance and surveillance activities was I

good. During a tour of the drywell, the inspector identified tools and I

other debris left behind from previous work activities. . An apparent  !

lack of management supervision to ensure work area cleanliness during '

and after maintenance activities was a significant contributing cause

for the deficiencies.

[naineerino and Technical S.unnqti

The engineering evaluation which supported continued plant operations

with the condensate pipe crack was assessed as weak by the NRC staff.

Subsequent discussions with the NRC resulted in the licensee shutting ,

the plant down to repair the crack. -

Safety Assessment and Ouality Verification

The quality of reviewed event reports was acceptable. The on-site

review committee was evaluated as effective. On November 5, an apparent .

'

weakness in the licensee's understanding of the basis for Technical

Specification requirements contributed to the licensee's failure to take

action in accordance with TS 3.0.3.

,

'

E

b

b

e

1

~

2

,

-

_ _ _

, - - e- gp - - T --

p V ~- -*E'--y

_

.

. DETAILS

l

1. Persons ContAcied

a. Cleveland Electric 111uminatina Company

R. Stratman, Vice President - Nuclear, Perry Nuclear Power

Plant (PNPP)  !

• K. Donovan, Manager, licensing and Compliance l

• M. Gmyrek, Operations Manager, PNPP  !

• S. Kensicki, Director, Perry Nuclear Engineering i

'

Department (PNED)

• F. Stead, Director, Perry Nuclear Support Department

(PNSD)

• H. Hegrat, Compliance Engineer, PNSD

• E. Riley, Director, Perry Nuclear Assurance Department

(PNAD)

• W. Coleman, Manager, Quality Assurance Section, PNAD

• V. Concel, Manager, Technical Section, PNED

• D. Conran, Compliance Engineer, PNSD

M. Cohen, Manager, Maintenance Section, PNPP 4

P. Volza, Manager, Radiation Protection Section

• G. Cad, Supervisor, Maintenance Section, PNPP

D. Cobb, Superintendent, Plant Operations, PNPP

• W. Wright, Manager, Instrumentation and Controls Section, PNPP

b. U. S. Nuclear Reaulatory Commission

,

• R. Lanksbury, Chief, Reactor Projects Section 3B,-RIII

P. Hiland, Senior Resident inspector, RIII

• A. Vegel, Resident inspector, Rill

• E. Duncan, Reactor Engineer, Rill

• Denotes those attending the exit meeting held on November 20,

1992. ,

2. Licensee Event _ Report (LER) Followun (90712. 92700)

Through review of records, the following event reports were reviewed-to

determine if reportability requirements were fulfilled, immediate

corrective actions were accomplished in accordance with Technical

Specifications (TS) and corrective action to prevent recurrence had.been

established:

a. fClosed) LER 50-440/92004-00: On March 21, 1992, during a planned .

manual shutdown of the plant, a reactor water cleanup (RWCU) '

system containment _ isolation occurred as a result of high system

differential flow. Immediate corrective action was taken to

'

verify that no actual system leakage had occurred. The RWCU ,

system was' secured and subsequently returned to service.

3

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

.

-

Licensee Investiaation of Root Cause and Corrective Actions

Root Cause

The licensee determined the root cause for this event was a design

deficiency associated with the unexpected formation of steam voids

in the RWCU regenerative heat exchangers (RHXs) while opcrating-in

the reduced feedwater temperature mode of operation. As the RWCU

system cool down progressed, the voids collapsed and return flow

refilled the RHXs instead of returning to the reactor pressure

vessel (RPV) v;a the feedwater injection line. A high

differential flow was sensed by the leak detection ' system and

resulted in a RWCU containment isolation.

Corrective Action

Pursuant to corrective actions for previous similar events, the

licensee submitted to the NRC on October 30, 1991,- a Technical

Specification Change Request, " Reactor Water Cleanup System

Isolation Actuation Instrumentation." The request included

changes to various instrument setpoints to alleviate spurious

system isolations. In addition, modifications were made to the

computer monitoring program to alert the operators that conditions

for steam voiding may exist in the system. All licensed operators

were trained on the lessons learned with regard to this event. At

the time of this report the proposed Technical Specification

change was still under review by the NRC.

Inspectors Review

The_ _ initial investigation of this event was documented in

Inspection Report 50-440/92003, paragraph 6.b.(5), dated April 27,

1992. A review of licensee efforts in response to similar RWCU.

isolation events was also documented in the above report in

paragraph 3.a. During this inspection period, the inspectors

reviewed applicable licensee documentation and noted that all

corrective action commitments specific to this event were ,

completed. This item is closed,

b. (Cl_ossd) LER 50-440/92011-00: Failure to perform surveillance

results in two inoperable intermediate range monitor (IRM)

channels and violation of TS 3.3.1.a. On May 3, 1992,'while in .

Operational Condition 5, REFUELING, two IRM channels-became

inoperable for approximately 10 hours1.157407e-4 days <br />0.00278 hours <br />1.653439e-5 weeks <br />3.805e-6 months <br /> due to failure to complete

the surveillance requirements. In addition, the-TS 3.3.1.a action

requirement to insert a half scram on the reactor protection

system (RPS) for. the inoperable IRMs was not performed within the

1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> TS time limit.

4

.

w4 - --e. v -,.m y 3 * m mew m- c+- swr e e -w i e - , . . - . . . . , , - ----.v--i...v. . ,mm..,%---ve- - .g- e m .. -.w.-

_

.

-

Licensee Investiaat. ion of Root Cause and Corrective Actions

Root Cause

The licensee determined the root cause of this event was personnel

error, failure to follow procedure. When reviewing the

surveillance schedule on May 2, 1992, the Unit Supervisor (US)

failed to refer to surveillance instruction SVI-C51-T0022C "lRM C

and G Neutron Flux Trips channel functional Test for IC51-K601C

and IC51-K60lG" to determine TS requirements pricr to deferring

the surveillance. This review was required by Plant

Administrative Procedure (PAP-1105), " Surveillance Test Control."

Corrective Action

Corrective actions included counselling the US with respect to the

requirement for procedural compliance. Additionally, as part of

the established requalification training program, all plant

licensed operators were instructed on the lessons learned from

this event.

Inspecton Review

The inspectors reviewed the applicable licensee documentation and

noted that all corrective action commitments were completed. The

inspectors concluded that the licensee's corrective actions

appeared reasonable and adequate to prevent recurrence. Failure.

of the licensee ~ to insert a half scram on RPS Channel C within

I hour of the IRMs being rendered inoperable was a violation of TS-

action statement 3.3.1.a. This violation was not cited because

the licensee's efforts in identifying and correcting the violation

met the criteria specified in Section VII.B of_ the " General

Statement of Policy and Procedure for NRC Enforcement Actions,"

(Enforcement Policy, 10 CFR Part 2, Appendix C (1992)). This-item

is closed,

No violations or deviations were identified; however, one non-cited

violation was identified. ,

3. Monthly Surveillance Observation (61726)

for the surveillance activities listed below, the inspectors verified

one or more of the following: testing was performed in accordance with

procedures; test instrumentation was calibrated; limiting-conditions for-

operation were met; removal _ and restoration of-the affected components

were properly accomplished;: test results conformed with technical

specifications, procedure requirements, and were reviewed by personnel

other than the individual directing the test; and any deficiencies

identified during the testing were properly reviewed _and resolved by

appropriate management personnel.

5

J

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

l

.

-

hirveillance Activity Title

SVI-E32-T0398A Main Steam Isolation Valve (MSIV) Leakage

Control System - Outboard Steam Line

Header Pressure Functional for IE32-N655.

SVI-E22-Til83 High Pressure Core Spray Valve Lineup

Verification and System Venting.

SVI-C71-T0039 MSIV Reactor Protection System Channel  !

Check. l

No violations or deviations were identified.

4. Monthly Maintenance 0bservation (62703)

Maintenance activities of safety-related systems and components listed ,

below were observed and/or reviewed to ascertain-that activities were

conducted in accordance with approved procedures, regulatory guides and

industry codes or standards, and in conformance with Technical

Specifications.

The following items were considered during this review: the limiting

conditions for operation were met while components or systems were

removed from service, approvals were obtained prior to initiating the  :

work, activities were accomplished using-approved procedures and were

inspected as applicable, functional testing and/or calibrations were

performed prior to returning components or systems to service, quality

control records were maintained, activities were accomplished by

qualified personnel, parts and materials used were properly certified,

radiological controls were implemented, and fire prevention contr_ols

were implemented.

Work requests were reviewed to determine the status of outstanding jobs

and to assure that priority was assigned to safety-related equipment

maintenance which may affect system performance.

Specific Maintenance Activities Observed: i

Hork Order / Repetitive Task No. _Jitle

WO-91-3399 Valve IN25F05368 - Body to Bonnet Gasket

Replacement.

WO-92-4178 Replace Motor on Reactor Water Cleanup!

Valve IG33F0004.

WO-92-4023 Replace Motor Pinion Gear Set on Reactor

Core isolation Cooling for Valve

IE51F0064.

'I

6 .

m.

. -

-

.

-

WO-92-3115 Install Strainer Basket on Service Water

Pump A.

WO-92-3116 Install Strainer Basket on Service Water

Pump B.

No violations or deviations were identified.

5. Operational Safety Verification (71707)

The inspectors observed control room operations, reviewed applicable

logs, and conducted discussions with control room operators during this

inspection period. The inspectors verified the operability of selected

emergency systems, reviewed tagout records, and verified tracking of

limiting conditions for operation associated with affected components.

Tours of the pump houses, control complex, the intermediate, auxiliary,

reactor, radwarte, and turbine buildings were conducted to observe plant

equipment conditions including potential fire hazards, fluid leaks, and

excessive vibrations, and to verify that maintenance requests had been-

initiated for certain pieces of equipment in need of maintenance. The

inspectors by observation and direct interview verified that the

physical security plan was being implemented in accordance with the

station security plan. ,

The inspectors observed plant housekeeping, general plant cleanliness

conditions, and verified implementation of radiation protection

controls, in addition, the inspectors observed construction of the low- 4

level radioactive waste building and the emplacement of a new breakwall

on site property,

a. Condensate Pipe Crack

On October 19, 1992, the licensee identified a steam-leak in the

vicinity of the direct contact heater. Subsequent investigation

of the leak on October 22, which included removal of insulation,

uncovered a crack approximately 9 inches (22.8 cm) in length. The

crack was located near a welded connection between the 30-inch

(76.2 cm) main condensate header and one of three.18-inch (45.7

cm) lines which fed the direct contact heater. The licensee set

up a camera to monitor the crack and initiated plans to

temporarily repair the leak with a clamping device. On

October 23, following discussions with NRC management concerning

the possibility of crack propagation, the licensee _ commenced a

plant shutdown to repair the crack. While shut down, the licensee

weld repaired the crack and restored the condensate system back to-

operation on October _ 27, 1992. The licensee's root cause

determination was in progress at the end of the inspection period.

The inspectors reviewed documentation, observed repair efforts,

and discussed with licensee management the significance.of the

crack. Though the licensee did shut down the plant to repair the

leak, the inspectors were concerned with the licensee's initial

-7

- . --- _--_

,

.

-

plans to only monitor the leak while temporary repairs were being

formulated. The inspectors concerns were based on the uncertain

cause for the leak and the potential personnel hazard that the

leak presented in case a rupture occurred abruptly while repairs

were in progress, in addition, NRC regional and headquarters

management questioned the licensee's engineering evaluations

supporting continued operation until temporary repairs could be

affected. Specifically, the licensee's engineering staff appeared

to have only accounted for stresses imposed on the crack by normal

system pressure, not taking into account other potential stresses

including manufacturing and/or vibration induced stresses. Though

the licensee did eventually take the conservative action of

shutting down, the inspectors were concerned with the licensee's

apparently inadequate engineering evaluation which supported

continued operation with the crack. The adequacy of licensee

engineering evaluations will be further reviewed in future

inspections of licensee engineering and technical support

activities,

b. Plant Housekeepina and Eauipment Condition

During the forced outage to repair the condensate pipe crack, the

inspectors conducted walkdowns of areas normally not inspected

during power operations. The inspectors toured the drywell, the

main steam line tunnel, and other areas in the turbine building

and heater bay. As a result, several discrepancies were noted

concerning plant housekeeping and equipment condition,

in the drywell, the inspector identified tools, bolts, scaffolding

material, and other debris left over from previous maintenance and

surveillance activities. The licensee subsequently removed the

material from the drywell. The inspector discussed with licensee

management what controls were in place to ensure that work areas

were maintained clean and that tools were accounted for. Though

licensee procedures do provide guidance on post work cleanup and

tool accountability, the licensee concluded that an apparent lack

of supervisory oversight to ensure that the guidance was being

followed was the cause for the discrepancies. Licensee action to

improva supervisory performance in this area was being evaluated

in a programmatic review of supervisor responsibilities. The

adequacy of the licensee's corrective actions to improve post

maintenance cleanup will be evaluated in future inspections of

plant maintenance activities and during routine observation of

plant housekeeping.

While conducting an inspection of the lower elevations of the

turbine building, the inspector observed a U-bolt pipe hanger

support on the floor. Upon further investigation, the inspector

determined that the U-bolt apparently was from a pipe support for

the 12-inch (30.5 cm) circulating water box drain tank pump

discharge header. Subsequently, upon being notified of the

discrepancy by the inspector, the licensee conducted a walkdown of

8

_ __

e

.

-

the system. As a result, the licensee discovered an additional U-

bolt missing, weld cracks on several pipe supports, and several

loose nuts on Hilti anchor bolts. A nonconformance report (NR-92-

N-298) was initiated to evaluate and document the deficiencies and

corrective action was initiated to repair the affected supports.

The licensee determined the root cause for the failure was a

possible system transient due to previous problems with the

waterbox drain pump and discharge check valve. The inspector '

questioned the licensee on why a system walkdown was not performed

by the system engineer during the shutdown, since problems with

the system were experienced earlier in the operating cycle. As a

result of discussions with licensee management, the inspector

concluded that due to the workload on the engineering staff during

the outage, particularly in support of repairs to the condensate

pipe, a system engineer walkdown of the circulating water system

was not performed in the turbine building. The licensee

determined that improved management of the system engineer

workload was required to ensure that system walkdowns were

performed. The inspectors will continue to evaluate licensee

performance in this area during routine evaluation of the

condition of plant equipment,

c. Plant Shutdown and Startuo Observations

On October 24, 1992, during the plant shutdown to repair the crack

in the condensate header, the operators manually tripped the

reactor from 22 percent reactor power. The reactor trip was

necessitated by the inability to perform steps 5.1.3.5 or 5.1.4.5

of Technical Specification required surveillance SVI-Cll-T1019,

" Rod Pattern Controller System Test Below Low Power Setpoint."

The steps required that an insequence rod not at an insert or

withdrawal limit be selected to verify that block and inhibit

indications reset. At the time this surveillance was performed,

all insequence rods were at the insert or withdrawal limits.

Therefore, the operators could not complete the steps in the

surveillance procedure. The operators subsequently tripped.the

reactor in accordance with plant operating procedures and

proceeded to place the plant in a cold shutdown condition. To

prevent recurrence, the licensee revised surveillance procedure

SVI-Cll-T1019 to allow for rods at the withdrawal limit to be

tested to verify operability of the rod pattern controller._ The

procedure was revised on October 28, 1992, prior to the plant

restart.

During the plant shutdown, repairs were conducted on the

condensate header crack and maintenance was performed to repair

various other minor steam leaks in the plant. In addition, the

outboard reactor water cleanup and reactor core isolation cooling

containment isolation valves were modified to correct deficiencies

previously identified in inspection report 50-440/91018(DRS) dated

November 5, 1992.

9

_. .

. _ _ _ _ _ ~ .

_

q

i

.

l

On October 30, 1992, upon completion of maintenance and repair

activities, reactor startup was commenced. During the ascension  !

to full power, a problem was identified with feedwater flow

indications, and a Technical Specification required surveillance i

'

was not performed when required. These problems are discussed

separately in paragraphs 5 d and 5.e of this report.

During the plant shutdown and startup, the inspectors observed

control room activities, in general, both evolutions were

performed in a controlled and deliberate manner. With the

exception of the missed surveillance, discussed in paragraph 5.e,

the operators performed their tasks in accordance with plant

instructions. Overall, the inspectors concluded that the

operators remained attentive to changing plant conditions and i

maintained positive control of the evolutions in progress.

,

d. Feedwater Flow Anomalies at low Power

On November 1,1992, during plant startup, difficulties with

feedwater flow instrumentation were experienced which prevented

operators from obtaining an accurate heat balance. Specifically,

feedwater flow, as determined by the differential pressure across

the feedwater venturis was indicating lower than expected at low

power based upon independent indications such as steam flow,

reactor feed pump turbine (RFPT) suction flows, and megawatts

(electric).

The licensee verified that pressure transmitters and associated

instrumentation were within calibration limits and reviewed

historical data for trending analysis. As a result, the licensee

determined that during each startup a_ higher _ reactor power level

hed been required before reactor power based on feed flow (from

the venturis) would agree with reactor- power based on other

indications. In Cycle 1 it was possible to obtain a core heat

balance at 15 percent thermal power. During Cycle 2, power had to

be increased to 20 percent to obtain a balance; during Cycle 3, _to

25 percent; and now in Cycle 4, to greatcr than 25 percent.

During the November 1,1992, startup, power was at 52 percent when

agreement between power indications was obtained. _ At the end of

the inspection period, the licensee was investigating this

phenomenon. Though the cause for the indication problems'at low -

power had not been determined, the licensee evaluated'that at

higher reactor _ power the: flow venturis.were ;pparently providing

accurate indication of_ feed flow. Due to tne unknown cause for

the indicated flow disparity,'the licens* conservatively decided

to limit reactor power to 99 percent until a better understanding

of the phenomenon could be made. The power limit of 99 percent is

based upon an_ apparent 0.5 psid error in differential pressure

across the venturi extrapolated to e .1 M1bm/hr error at 100

percent reactor power. The iresp w ors will continue to monitor

licensee efforts to deter 6 e the root cause for the feed flow '

venturi indication probi m

10

_ _ _ -

y t-w <t v4W * t- * --'?P-9? - W 'T * *"'7 )

_ _ _ _ _ _-_ _ - _ _ __ - __ _ _ _ _ _ - ____________ _____ _ _ _ __ _ _ ___ _ _ - _ - -

.

c. Missed Averaae Power Ranae Monitor Gain Ad.iustment Surveillance

On November 1, 1992 the licensee identified that the average power

range monitor (APRM) gain adjustment surveillance had not been

performed as required by TS. Specifically, TS table 4.3.1.1-1

footnote (d) required that APRM channels be calibrated to conform

to the power values calculated through a heat balance during

Operational Condition I when thermal power is greater than or

equal to 25 percent of rated thermal power. Additionally, for the

provisions of TS 4.0.4 not to be applicable, the surveillance was

to be performed within 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> of reaching 25 percent power.

Technical Specification 4.0.4 prevents entry into an operational

condition unless the surveillance requirements associated with the

limiting condition for operation (LCO) have been performed within a

the applicable surveillance interval. During the startup, with--

the plant in Operational Condition 1 at 24.4 percent power, the

licensee completed surveillance SVI-C51-T0024 "APRM Gain and

Channel Calibration" on October 31, at 8:12 p.m. (EST), using

feedwater pump inlet feedwater flow data. Subsequently, power was

raised to greater than 25 percent at approximately 1:00 a.m. on

November 1. At 2:48 a.m. preparations were commenced to reperform

the surveillance, but difficulties were encountered with the

indicated flow received from the feedwater venturis. Plant

procedures required that feedwater flow for- the heat balance be

obtained from the venturis when greater than 25 percent reactor

power. Consequently SVI-C51-T0024 could not be performed as

written. The feedwater flow venturi problem is discussed in

paragraph 5.d of this inspection report. At 3:45 p.m. the

oncoming unit supervisor noted that the surveillance had not been

performed within 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> of reaching 25 percent power. Following

power increase to 52 percent, SVI-C51-T0024 was completed

satisfactorilly at 10:30 p.m.

The licensee initiated condition report CR-92-255 to document

event investigation and track subsequent corrective action. In

addition, an LER was to be submitted. The inspectors will review- _

the results of _the licensee's investigation and evaluate the

-

adequacy of corrective action in -a future inspection report. *

f. Incoerable Containment Pressure Channel Due to Improper Valve

Lineun

On November 8,1992, while in Operational Condition 1, _ POWER . _

OPERATIONS, plant operators noticed a discrepancy between the-two-

wide range containment pressure channels displayed on the

Emergency Response Information System (ERIS). Containment

pressure instrument 023-N270A read -0.3 psig, while the other

k channel's instrument,-D23-N2708, read +0.3 psig. The licensee

l commenced an investigation. On November 10, 1992, Instrumentation

,

and Control (I&C) personnel discovered that containment pressure

i instrument 023-N270A was in an improper valve lineup, rendering

the instrument inoperable. The licensee initiated condition

11

!

~

L

l

,

. . . - - - .. -

-

,

.

report CR-92-261 to document event investigation and track ,

subsequent corrective action. In addition, an LER was to be

submitted at a later date.

The inspectors will review the results of the licensee's

investigation and evaluate the adequacy of corrective action in a

future inspection report,

g. Feedwater Control Problemi

On November 11,1992, at 7:45 p.m., with the plant operating _ at 99

percent power, a perturbation in the feedwater control system

resulted in a reactor water level and power transient. Reactor

water level increased to above the level 7 high level alarm

setpoint then decreased to below the level 4 low level alarm

setpoint before settling out in the normal operating band.

Reactor power oscillated for approximately 1 minute then returned

to normal. The peak reactor thermal power during the transient

was 100.9 percent. Initial troubleshooting determined there was a

problem in the "B" reactor feed pump turbine (RFPT) control

system, and the controller was placed in manual. On November 12,

at 6:35 a.m., with the "B" RFPT in manual, a similar transient

occurred. Again reactor water level 7 and level 4 alarms were

received and power oscillations peaked at 100.9 percent.

Subsequent troubleshooting isolated the cause of the feedwater

controller problem to a circuit board in the feed flow logic

circuitry. Specifically, the indicated feed flow from the "B"

RFPT circuit card apparently spuriously spiked causing RFPT. "A" to

respond to the false feed flow signal. As a result, the "A" RFPT

would initially respond to the false feed flow variance then react

to correct the subsequent reactor level changes. The licensee

replaced the suspected circuit cards and returned the RFPT to the

master level controller on November 13. Following repairs, the

feedwater co'itrol system operated normally without fur.her

problems . The licensee was investigating the root cause of the

circuit card problems.

h. Inadeouate Retest of Lower Containment Airlock Door

On October 21, the lower containment airlock was declared

inoperable for maintenance to investigate seal inflation light

indication problems for the inner door. A faulty. pressure switch

was identified as the cause for the indication problem. The

pressure switch was replaced and leak-checked. A_ retest, which

required cycling of the airlock inner door three times while

verifying proper operation of the door, lights, and pressure

switch was performed. On October 23, at 3:15_a.m. the lower

containment airlock was declared operable.

On October 23, at 10:00 a.m., the licensee determined that the

retest performed earlier was inadequate because the pressure

integrity of the lower containment inner airlock door seal

12-

. ___ - . _ _ __ .-,

_ - ____ -_ _ __ _

m

e

'

pneumatic system was broken by the maintenance performed. As a

result, TS surveillance requirement 4.6.1.3.e (conducting a seal

pneumatic system leak test) was not met. Consequently, the

airlock was again_ declared inoperable. On October 24, at

6:32 a.m., the airlock was declared operable following

satisfactory performance of surveillance SVI-PS3-T7305, " Lower

Containment Airlock Pneumatic System Leak Test, Pen #305."

On November 12, the licensee identified a discrepancy between the -

piping system diagram, the electrical elementary diagram, and the

pressure switch as installed in the field for the lower

containment airlock. Further investigation determined that the-

retest on October 24 was done on the wrong pneumatic system,

rendering the retest invalid. As a result, the lower containment

inner airlock door was declared inoperable at 1:30 p.m. _ On

November 13, at 6:43 a.m., the test of the seal pneumatic system

associated with the pressure switch was completed satisfactorily

and the lower cont 61nment airlock was declared operable.

The licensee initiated an investigation of this event and-

documented their findings and corrective actions in LER 92-20

dated November 20, 1992. The inspectors will review the results

of the licensee's evaluation and evaluate the adequacy of

corrective action during review of LER 92-20 in a future

inspection report.

No violations or deviations were identified.

6. Onsite followun of Events at Operatina Power Reactors (93702)

a. General

The inspectors performed onsite followup activities for events

which occurred during the inspection period. Followup inspection

included one or more of the following: reviews of operating logs, '

procedures, and condition reports; direct observation of licensee

actions; and interviews of licensee personnel. For each event,.

the inspectors reviewed one or more of the following: the

sequence of actions; the functioning of safety systems required by

plant conditions; licensee actions to verify consistency with

plant procedures and license conditions; and verification of the

nature of the event. Additionally. -in some cases, the inspectors

verified that the' licensee's investigation identified root causes

of_ equipment malfunctions and/or personnel errors and the licensee-

was taking or had taken appropriate corrective actions. Details

of the events and licensee corrective actions noted during the

inspector's followup are provided below.

13

s -

-__ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _

,

l

.

'

b. Details

(1) B_eactor Protection System Actuation

On Octobar 24, 1992, at 12:56 a.m., during the plant

shutdown to repair the condensate header crack, following a

manual reactor trip from 22 percent reactor power, a reactor

protection system (RPS) actuation occurred on low reactor

water level. A full scram signal was generated by the RPS

when reactor water level decreased below the level 3

setpoint. This event followed a planned manual scram

performed in accordance with plant operating procedures.

All of the control rods were already inserted and no rod

movement occurred due to the second RPS actuation. The

licensee informed the NRC Operations Center of this event

via the Emergency Notification System (ENS) at about 3:30

a.m. on October 24, 1992.

The licensee conducted a review of this event and determined

that the level 3 RPS actuation was an expected plant

response. Due to the reactor water level shrink and swell

characteristic of a boiling water reactor (BWR), the level

decrease was expected and was accounted for by procedural

steps to raise water level to the top of the operating band

before the scram was initiated. Additionally, operations

personnel anticipated the level transient by reviewing

appropriate instructions before the manual reactor trip was

initiated. The licensee concluded that the water level

decrease below the level 3 setpoint was part of a preplanned

sequence during reactor operation and need not be reported.

On November 13, the licensee informed the NRC Operations

Center and retracted the October 24 notification.

The inspectors reviewed licensee procedures, interviewed

plant operators, and reviewed data from previous reactor

trips. The inspectors concluded that the operators were

cognizant of the expected plant transient and that the plant

response was similar to previous reactor trips from

approximately the same power level.

(2) Loral Leak Rate Testina of Nuclear Closed Caplina

Containment Isolation Valve

On October 27, 1992, at 11:00 p.m., the licensee determined

that containment secondary bypass leakage exceeded Technical

Specification 3.6.1.2.d limits following local leak rate

testing (LLRT) of nuclear closed cooling (NCC) containment

isolation valve IP43F140. The licensee informed the NRC

Operation: Center of this event via the ENS at about

2:00 a.m. on October 28, 1992.

. 14

!

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

U

..

1' During performance of "NCC Containment Isolation Valve

Operability Test" surveillance on October 27, outboard-

containment isolation valve IP43F140 gave dual indication

when in the closed position. Following maintenance, in

which the valve position limit switches were adjusted to

correct the indication problem, a LLRT was performed. The

LLRT was required because IP43F140 was a butterfly valve

whose leakage characteristics could be affected by limit

switch adjustments. Excessive leakage was noted and the ENS-

notification was made. At the time of the notification . it

was not known if the maintenance caused the leakage or if

the valve had been leaking during operation.

The licensee conducted an investigation and determined that

the failure of the post maintenance test did not provide = w

evidence that the valve was leaking during the modes of

operation for which the Technical Specification was

applicable. Technical Specifiation 3.6.1.2.d applied in

Operational Conditions 1,-2, and 3. At the time of the post

maintenance test, the plant was in Operational Condition 4,

where the leakage requirements were not applicable. The

licensee determined that the cause for the excessive leakage

was the maintenance activity performed on the limit switches

and that there was no firm evidence to indicate that the

valve was leaking during the modes- of operation for which

the Technical Specifications were applicable. Based on the

above, on November 13 the licensee informed the NRC

Operations Center and retracted the October 27 notification.

(3) Secondary Containment Bvoass leakaoe in Excess of Linita

On November 5,1992, while in Operational Condition 1, POWER

OPERATIONS, at 99 percent reactor power,-the licensee

diacovered that based upon the results of local-leak rate

testing (LLRT) of a 42-inch (106.68 cm) coitainment purge -

supply line penetration, the secondary containment bypass

leakage rate exceeded TS limits. Upon recognizing that

contalnment bypass leakage limits were exceeded, the

licensee failed to take appropriate-action as specified in

TS 3.0.3.

On November 5, at 4:15 p.m., upon reviewing the deta

obtained during performance of SVI-M14-T9313, " Type C Local.

t eak Rate Test of IM14 Penetraticn V313," a leakage rate of

3130-standard cubic c u timeters per minute (sccm) was

calculated for the penetr. tion. Specific to this

penetration, TS 4.6.1.8.4 allowed leakage up to_.05 L,

(5011.6 sccm). Therefore tie penetration' leakage was within

limits. However, when the leakage from the penetration

(3130 sccm) was combined w'.th the previously recorded

secondary containment byp.ss-leakage, the total,

15

,

.

_ _ _

.

t

6598.34 sccm, was greater than the total secondary

containment bypass leakage limit of .0504 L, (5051.74 sccm)

allowed by TS 3.6.1.2.d. The subsequent action statements

applicable in Operational Conditions 1, 2, and 3 required,

in part, that secondary contai nent bypass leakage paths be

restored to less than or equal to .0504 L, prior to

increasing reactor coolant temperature above 200 F. Since

the plant was in Operational Condition- 1 at 99 percent

reactor power, the licensee's staff questioned the-

applicability of the TS in their current plant condition.

Though the licensee did recognize that they might-be in a

condition outside of the TS LCO, and therefcre TS.3.0.3

would be applicable, no action was taken in- accordance with

the TS 3.0.3 requirement. At approximately 7:00 p.m. the

licensee contacted a member of the NRC staff to discuss the

situation. At that time it was not apparent that the TS 3.0.3 requirements were applicable. On November 6, 1992, at

approximately 6:00 a.m., the containment purge supply

penetration was declared operable following valve repair and

satisfactory retest. Af ter a review of TS requirements by

the NRC staff and discussions between the staff and the-

licensee on November 6 it became apparent that the licensee-

did not take appropriate action in accordance with TS 3.0.3.

On November 6, at 6:30 p.m., the licensee notified the'NRC-

Operations Center via ENS that required actions in

accordance with-TS 3.0.3 were not taken on November 5

following discovery of excess secondary containment bypass

leakage.

Technical Specification 3.0.3 required that when a limiting

condition for operation (LCO) is not met, except as provided

in the associated action. requirements, within 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> action

shall be initiated to place the unit in an operational

condition in which the specification does not apply.

Contrary to the above, on November 5, 1992, upon not meeting

the LC0 action requirements of TS 3.6.1.2, the licensee-

failed to initiate action within 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br />, in accordance with

TS 3.0.3, to place the plant in Operational Condition-4,

COLD SHUTDOWN, where TS 3.6.1.2 would not be applicable.

This is a violation (440/92022-01(DRP)).

One violation and no deviations were-identified.

7. Evaluation of Licensee Self-Assessment'Capabilitv(40500)

a. On-Site Review Committee-

c During the report period, the inspectors observed on-site review

committee meetings to evaluate that organization's effectiveness-.

For the meeting attended, the inspectors considered the following.

16

m

.

attributes: 'the degree of-plant management involvement and/or

domination of discussions;'if constructive discussion occurred; if. .

the-majority of the committee consistently voted the same as the

chairperson; if_the committee was biased toward operation or

safety; and,'if the committee used design basis, the Updated

Safety Analysis Report (USAR), or vendor' technical manuals for

their determinations in addition to the.. Technical Specifications.

In preparation for the meeting, the inspectors reviewed the draft

submittals given to the on-site review committee for approval.

Itemt presented to the on-site review committee included safety

evaluations, temporary changes to procedures, setpoint change

requests, procedural revisions, and design change packages.

During this report period, the following on-site review committee

meeting was observed by the inspectors:

Meetina No, Date

92-128 11/19/92

For the meeting observed, the inspectors cencluded that the

function of the on-site review committee was effectively

implemented.

~

No violations or deviations were identified.

8. Cold Weather Preparations (71714)

The inspectors reviewed the licensee's implementation of the -freeze

protection program. This included a review of freeze protection off-

normal instruction ONI-R36 and various system operating instructions,

including those for emergency service water, condensate storage and

transfer, and heat tracing. A walkdown of heat trace control panels-and

other freeze protection systems to verify proper operation was

performed. Also, the-inspectors discussed implementation-of the freeze

protection program with operations and engineering personnel to essess

their familiarity with cold weather preparations.

Off-nornal instruction ONI-R36 and-pertinent system operating

instructions: appeared to provide adequate freeze protection when

l- implemented. The portions of the freeze protection-systems walked down

l by the inspectors were observed to be operating properly, and plant

i personnel questioned were familiar with ONI-R36 and its contents. The-

'

inspectors noted that although heat tracing had not been reinstalled ,

,

following the circulating water system pipe. rupture event'on December

22, 1991,- contingency plans'to prevent this-piping from freezing in the

i event of a system shutdown appeared adequate. _ The inspectors also noted

i that specific procedures to-address freeze protection in the event of-a

failure of the freeze protection system did not exist. However,

discussions with operations and engineering personnel indicated that-

l

L 17

l  :

I

_

.-

9- contingency plans had been considered and appeared reasonable. Based

-

upon the above observations, the inspectors-concluded that the

licensee's freeze protection program had been adequately implemented.

No violations or deviations were identified.

9. Manaaement Chanaes

The licensee announced that Mr. Mike Lyster, Vice President - Nuclear,

the senior licensee manager on site, resigned his position effective

December 17, 1992. Mr. Lyster will become the site vice president at

the Dresden Nuclear Power Station. At the end of this inspection period

the licensee had not announced his successor.

10. Items for Which a " Notice of Violation" Will Not Be issued _

.

During this inspection, certain activities, as described above in

paragraph 2.b, appeared to be in violation'of NRC requirements.

However, the licensee identified this violation and it will not be cited

because the criteria specifieo in Section VII.B. of the " General

Statement of Policy and Procedure for NRC Enforcement Actions,"  :

(Enforcement Policy, 10 CFR Part 2, Appendix C, (1992)), were satisfied,

11. Exit Interviews

The inspectors met with the licensee representatives denoted in i

paragraph 1 throughout the inspection period and on November 20, 1992. '

The inspectors summarized the scope and results of the inspection and

discussed the likely content of the inspection report. The licensee did

not indicate that any of the information disclosed during the inspection

could be considered proprietary in nature.

q

During the report period, the inspectors attended the following exit

interviews:

~

Inspector Exit Date

'

J. R. Kniceley (Security) 11/20/92

4

18

l

.- - _ ________:______________-___