ML20056D167

Insp Repts 50-338/93-18 & 50-339/93-18 on 930509-0619. Violations Noted.Major Areas Inspected:Examinations of Procedures & Representative Records,Interviews W/Personnel & Observaton of Activities in Progress

ML20056D167
Person / Time
Site:	North Anna
Issue date:	07/13/1993
From:	Belisle G, York J NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II)
To:
Shared Package
ML20056D154	List: ML20056D153 ML20056D158 ML20056D167
References
50-338-93-18, 50-339-93-18, NUDOCS 9308050053
Download: ML20056D167 (10)

See also: IR 05000338/1993018

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UNITED STATES '

NUCLEAR REGULATORY COMMISSION

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$ E 101 MARIETTA STREET, N.W., SUITE 220

. :; >f ATLANTA, GEORGIA 303234199

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Report Nos.: 50-338/93-18 and 50-339/93-18 ,

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Licensee: Virginia Electric & Power Company

5000 Dominion Boulevard

Glen Allen, VA 23060

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

Facility Name: North Anna 1 and 2 ,

Inspection Conducted: May 9 - June 19, 1993 ,

Inspectors: 4 W// dev 7//?/f *h

JohnYork,TcKngSeniorResidentInspector Date Signed

8 $<W We 7//5/43

D. R. TayloffRp) dent Inspector Date Signed

Accompanying Inspector: A. B. Ruff i

R/s

G. A. Belisle, SectidTPChief

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Division of Reactor Projects

SUMMARY

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Scope:

This routine inspection by the resident inspectors involved the following ,

areas: plant status, operational safety verification, maintenance -

observation, modifications, surveillance observation, and licensee event  :

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report followup. Inspections of licensee backs':ift activities were conducted

on the following days: June 5 and 6, 1993.

Results:

In the operations area:

A switching order was carried out to isolate switchyard transformer No. 1 for

preventive maintenance. The procedures used to perform the evolution and

communications to the control room were effective (para 4.b). ,

In the maintenance / surveillance area:

. A violation was identified when hydrogen analyzer (1-HC-H2A-101) pressure

switch (PS-3) tubing (sensing line) was discovered to be disconnected. This

rendered the hydrogen analyzer inoperable for a period of time that exceeded

the Technical Specification Limiting Condition for Operation. The problem was

930B050053 930713

PDR ADOCK 05000338

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thought to have been caused by failure to implement steps in an I&C  ;

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calibration procedure and is another example of recent problems identified

with implementing I&C procedures (para 3.a).

Small concentrations of water were identified in the Unit 2 turbine AFW pump ,

lube oil. The amount of water was determined not to be an operability l

concern. ,

In the engineering technical support area:

The addition of eleven vent valves on the Unit 1 LHSI system appears to have

decreased the pressure transients and pressure peaks on the system during LHSI ,

pump starts. System engineering involvement with testing of the system and ,

data analysis was evident (para 6.a). l

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The inspectors observed the replacement of some Thermo-Lag and will continue  ;

to observe the modification (para 5).

In the safety assessment / quality verification area:

A critique of a practice emergency drill was self-critical. Some weaknesses,

primarily attributed to poor communications, were identified. A second ,

practice drill is being held in July (para 3.b).

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REPORT DETAI S

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1. Persons Contacted

Licensee Employees ,

L. Edmonds, Superintendent, Nuclear Training I

• R. Enfinger, Assistant Station Manager, Operations and Maintenance

J. Hayes, Superintendent of Operations

D. Heacock, Superintendent, Station Engineering

• G. Kane, Station Manager

• P. Kemp, Supervisor, Licensing

W. Matthews, Superintendent, Maintenance ,

J. O'Hanlon, Vice President, Nuclear Operations

• D. Roberts, Supervisor, Station Nuclear Safety (Conference Call)

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R. Saunders, Assistant Vice President, Nuclear Operations

D. Schappell, Superintendent, Site Services

R. Shears, Superintendent, Outage and Planning

• J. Smith, Manager, Quality Assurance

A. Stafford, Superintendent, Radiological Protection  !

• J. Stall, Assistant Station Manager, Nuclear Safety and Licensing

Other licensee employees contacted included engineers, technicians,

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

NRC Resident Inspectors

• J, York, Acting Senior Resident Inspector

• D. Taylor, Resident Inspector

• Attended exit interview

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Acronyms and initialisms used throughout this report are listed in the

last paragraph.  ;

2. Plant Status

Both units operated the entire inspection period at or near 100 percent

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power.

3. Operational Safety Verification (71707)

The inspectors conducted frequent visits to the control room to verify

proper staffing, operator attentiveness and adherence to approved

procedures. The inspectors attended plant status meetings and reviewed

operator logs on a daily basis to verify operational safety and

compliance with TS and to maintain awareness of the overall operation of

the facility. Instrumentation and ECCS lineups were periodically

reviewed from control room indications to assess operability. Frequent

plant tours were conducted to observe equipment status, fire protection

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programs, radiological work practices, plant security programs and .

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housekeeping. Deviation Reports were reviewed to assure that potential

safety concerns were properly addressed and reported. Selected reports

were followed to ensure that appropriate management attention and

corrective action was applied. ,

t. . Inoperable Hydrogen Analyzer

The inspectors reviewed DR 93-800, which stated that the tubing

(sensing line) for pressure switch PS-3 was found disconnected. ,

The pressure switch is for containment hydrogen analyzer

1-HC-H2A-101. This condition was discovered on May 9 by an e

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auxiliary operator while hanging configuration control labels.

A review conducted by the licensee showed this tubing was last

disconnected e February 9, 1993, Instrument Calibration Procedure

ICP-HC-1-H2A-101, Containment Hydrogen System Reactor Containment

Hydrogen Analyzer. The tubing was discennected during the

procedure while performing calibrating of pressure switch PS-3.

It is believed that the tubing was not properly reconnected

following this calibration. The pressure switch is used to

provide a system trouble alarm in the event of low flow through

the analyzer while in operation. Once this condition was

discovered, the analyzer was calibrated and returned to service.

With the sensing line disconnected, the hydrogen analyzer is

inoperable beccuse it would give an erroneous analysis.

TS 3.6.4.1 requires two independent containment hydrogen analyzers

(shared between units). The action statement allows one analyzer

to be inoperable for up to 30 days and both to be inoperable for

seven days. The hydrogen analyzer in question was thought to be

inoperable for a period of 89 days without the requirements of the

action statement be;ng performed. The inspectors reviewed the SR0

logs and confirmed that the second analyzer was never

out-of-service for a period longer than that allowed by TS. The

failure to meet the TS requirements for hydrogen analyzer

operability is identified as violation 50-338/93-18-01.

The inspectors reviewed the ICP and discussed this concern with

the licensee. Step 4.'4, of the procedure, gives instructions for

calibrating pressure switches PS-2 and PS-3. Following the

calibration, there is a procedural step which states, " Remove test

equipment from the test connection and restore PS-3 tubing to

normal . " The connection is also checked by return-to-service step.

4.5.6 which states, " Verify PS-2 and PS-3 tubing restored to -

normal"; however, this is not an independent verification and can

be perform =d by the same individual who originally connected the

tubing. Further, performance of step 4.4 " analyzer calibration"

would have caught this condition by receiving the low flow alarm  !

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during the calibration. However, step 4.4 was performed prior to

step 4.3. Nothing in the procedure prohibited this. To prevent

this condition from recurring, a PAR was made to the procedure.

The inspectors also discussed with the licensee the possibility of

a containment breach during system operation. Based on the

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operation of the system and the location of the i" PS-3 tubing,

the opening would create a point of in-leakage not out-leakage.

The licensee confirmed this with the hydrogen analyzer vendor.

Prior to finding PS-3 tubing disconnected, an adverse trend in the

performing I&C procedures was noted by the licensee and the

inspectors. A violation for performance errors was issued in NRC

Inspection Report Nos. 50-338,339/93-14 along with a summary of

errors. Since that time, the inspectors attended an 508 meeting

to discuss a CNS North Anna I&C performance review report. The

report provided a detailed description of recent I&C events and 4

causes. Recommendations from the report included revising )

expectations and providing training on independent and

simultaneous verifications. Further recommendations included a

procedure upgrade program review to determine corrective actions

needed to address the identified weaknesses with the technical

review and validation of technical procedures. The report also

stated that the procedure update program needs to be reviewed with

respect to limited expertise, limited resources and performance

measures. The report also identified several enhancements. A

Management level 1 project activity was initiated to implement the

I&C Human Performance Improvement Plan. To date, licensee

management has been aggressive in identifying causes for the

apparent trend in I&C performance and implementing corrective

actions. The PS-3 tubing disconnect event was reported to the NRC

, by LER 50-338/93-16.

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b. Practice Emergency Drill

On June 16, the inspectors observed the licensee perform a  ;

practice emergency drill. This drill was not required by l

regulations. The control room simulator, TSC, and OSC were manned l

during the drill. The scenario cor.sisted of an operational basis i

l earthquake causing several equipment related challenges including

i a small RCS leak, total loss af charging capability, and a i

i containment breach. The drill scenario led to declaring a site

area emergency and full accountability of station personnel.

During the drill, the inspectors noted several deficiencies

concerning communications. These deficiencies were also l

identified by the licensee. These communication deficiencies,

along with other licensee identified deficiencies were discussed

during the drill critique.

To ensure that the drill deficiencies are properly resolved, the

licensee intends to have a second practice drill in July. i

l c. Potential Problem With Rod Control System

The licensee evaluated the rod control event that occurred at the

Salem plant to determine if it applied to North Anna. This

potential problem involved the rod control system that could cause

an inadvertent withdrawal of one or more control rod cluster

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assemblies in a selected bank. Westinghouse and the owners group

are evaluating this event. The licensee briefed the licensed

operators on this event and explained the potential failure mode.

The operators were cautioned to be alert for rod movement. The

operators continue the normal process of verifying that rod motion

is proper for the required movement. The inspectors reviewed the

safety evaluation 93-SE-JCO-004 and the justification for

continued operation 93-04.

One violation was identified.

4. Maintenance Observation (62703)

Station maintenance activities were observed / reviewed to ascertain that

the activities were conducted in accordance with approved procedures,

regulatory guides and industry codes or standards, and in conformance

with TS requirements.

a. AFW Pump 011 Change

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On May 27, lube oil for the Unit 2 steam turbine driven AFW pump

was changed due to a high concentration of water. The work was

performed using skill-of-the craft per WO 162481. The inspectors i

witnessed removing the pump from service per M0P 31-03 and tagout

for the work, and also observed change out of the lube oil and

removal of the lube oil cooler to test for leakage. Performance

of the M0P and tagout by the auxiliary operator are thorough. The

oil was changed because the water content exceeded manufacturer's

recommendations. Following the monthly PT of the turbine driven ,

AFW pump on May 18, the oil was sampled. The analysis and results i

of that sample were determined to be out-of-spec at 0.4% water

content, but it was not reported to maintenance engineering until

May 26. At that time, a second sample was taken from the oil

reservoir and it indicated a 4% water content. This sample was a i

stagnant sample was not representative oil sample. The inspectors I

noted that the oil being removed from the reservoir was milky, {

indicating water intrusion. A sample drawn from the reservoir  !

while purging the bad oil confirmed water but at a lower

concentration of 0.326%. The lube oil cooler was tested and no

leaks were identified.

The inspectors discussed the water content of the oil with site

engineering to verify that low water concentrations are not an

immediate operability concern. The system engineer stated that

operability was not a problem but noted that low water in the oil l

concentrations could have a long term degradation effect on the I

bearings. The manufacturer recommends oil changes when the '

percent water reaches 0.2%. The inspectors reviewed DR 93-267 l

written February 9,1993, for the same problem. The DR resolution

recommended increased sampling from once per quarter to once per

month to correspond with the monthly pump run. The DR further

recommended maintenance engineering involvement if the percent of

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water approaches 0.2%. For this last case, the sample was drawn

on May 18, but maintenance engineering was not informed until 8 i

days later. After the oil was changed out, the pump was run

satisfactorily. Deviation report 93-909 was issued to document

the most recent problem.

b. Switchyard Maintenance

On June 15, the inspectors observed performance of a switching

order which isolated switchyard transformer No.1 (500 KV/36.5 KV)

for preventive maintenance. The switching, isolation of the '

transformer, and the lineup to ensure that the power for vital

loads supplied by transfer Bus "F" remained available from an

offsite source was performed in a satisfactory manner. The

inspectors verified that TS 3.8.1.1 requirements for two

independent circuits between the offsite transmission network and

the onsite Class IE distribution system were maintained.

The switching operation was accomplished using 0-M0P-26.5,

Transferring "C" RSS transformer from Bus 3 to Bus 5 and returning ,

to Bus 3 from Bus 5; 0-M0P-26.20, 34.5 KV Bus No. 3 Maintenance, '

and 0-M0P-26.9, 230 and 500 KV Equipment Switching. The

inspectors observed that the personnel involved discussed each {

procedure step prior to performing it and they also informed the j

control room prior to any action that could effect the units. The -

M0Ps were well written and the switchyard components were well

labelled.

No violations or deviations were identified.

5. Modifications (37828)

Thermo-Lag Replacement in the Auxiliary Building

The licensee uses Thermo-Lag 330 fire barrier systems in panel and

conduit shapes as radiant shields (one half hour fire rating) and as one

and three hour fire barriers at North Anna. Thermo-Lag is not used as a

fire barrier system for cable trays. The Thermo-Lag in conduit shapes

is used as a fire barrier to protect the power cables for Unit I

charging pump IC and Unit 2 component cooling pump 1A. The licensee is

currently replacing this material with Interam E-50 wrap (a 3M product).

The inspectors observed removing part of the Thermo-Lag in locations

where additional supports were required because of the additional weight

added due to the higher density 3M Interam E-50 wrap. Three layers of

3M Interam E-50 are being installed on the two armored cables. Part of

the installation of the first two layers was observed by the inspectors.

A discussion was held concerning overlap, banding of the wrap, caulking,

and training of the installers by the 3M company. Inspections and

acceptance criteria were discussed with the QC inspector observing the

job.

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In the licensee's response of April 12, 1993, to Generic Letter 92-08,

Thermo-Lag 330-1 Fire Barriers, it was stated that preliminary _ plans for

replacement had been made and that final plans would be conveyed to the

NRC. This supplemental response was being prepared at the end of the

inspection period. The original submittal states that any new fire

barrier system installed will satisfy NRC regulatory requirements for

one and three-hour rated barriers. Licensee management stated in a

telephone conference with the NRC that until the applicable licensing

actions are taken, fire watches will be maintained in order to comply

with the 10 CFR 50 Appendix R requirements.

No violations or deviations were identified.

6. Surveillance Observation (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 LCOs were met and that any

deficiencies identified were properly reviewed and resolved.

a. LHSI Pump PT

On May 24, the inspectors observed performance of I-PT-57.lA,  ;

Emergency Core Cooling Subsystem-Low Head Safety Injection Pump

(1-SI-P-1A). Incorporated into the procedure was a one time

change to allow measuring transient the pressure surges during the

pump start and to calculate the gas void in the system. During

the last refueling outage,11 additional vents were added to the

Unit 1 LHSI system to allow for better venting. Gas voids in the

piping have been the cause for a long standing problem with

excessive pressure spiking during pump starts. Pressure spiking l

has lead to a cracked weld on instrument tubing and relief valves

lifting. One relief valve on Unit 2, 2SI-RV-28458, failed to

reseat following lifting and is currently gagged shut. The gagged

relief valve is scheduled to be replaced during the next refueling i

outage. The Unit 2 LHSI system is also going to be modified 1

during this outage.

During the test, a peak pressure of 318 psi occurred for about 0.2

seconds. This pressure is above the relief valve setpoint of 257

psig and the relief valve briefly unseated. Seventy ml of water  ;

discharged from the relief valve during the pressure transient. ]

The inspectors noted that LHSI pipe movement (a normal result of )

pressure transient pump starts) was not nearly as severe as was j

observed during previous pump starts before the additional vent l

installation. Following the test run, the void in the LHSI piping

was determined by slowly depressurizing the system to a collection

bottle and measuring the amount of water displaced. Based on the

calculation, 0.55 cubic feet of gas void existed.

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On May 28, the inspectors attended a SNSOC meeting which included

an update of the LHSI pressure surge problem. The most recent

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pump start was compared to previous starts. From this testing, it

was concluded that the peak pressure decreased and that there are

fewer transient pressure peaks. For example, during a September

1992 test, peak pressure reached 449 psig. In December 1992, the

pressure reached 420 psig. The current pressure test shows a 25

percent pressure decrease. The licensee will continue to collect

data to establish an optimum venting periodicity. It appears the

addition of the vents has decreased pressure transients and

pressure peaks on the system during LHSI pump starts. System

Engineering involvement in analysis of the test data and

presentation of data to SNS0C was evident.

b. Feedwater Valves Partial Stroke Test

On June 14, the inspectors observed 1-PT-213.24, Valve Inservice

Inspection (Feedwater Regulator Valves Partial Stroke). The

procedure verifies that the main feedwater regulator valves and

the bypass feedwater regulator valves are operable by performing a

partial stroke of each valve.

Test observations were made from the Unit I mechanical equipment

room where an auxiliary operator was also stationed to observe i

valve stem motion. The test was satisfactory. The surveillance

was performed to meet Section XI inservice test requirements for

the valves.

No violations or deviations were identified. '

7. Licensee Event Report Followup (92700)

The following LERs were reviewed and closed. The inspectors verified l

that reporting requirements had been met, that causes had been

identified, that corrective actions appeared appropriate and that

generic applicability had been considered. Additionally, the inspectors 1

confirmed that no unreviewed safety questions were involved and that  !

violations of regulations or TS conditions had been identified. l

(Closed) LER 50-338/92-06, Manual Reactor Trip during Startup when Four I

Rods Dropped into the Core

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Unit I was in a shutdown condition and a reactor startup was initiated )

on March 5, 1992. During the start up with control bank A rods at 208

steps and control bank B rods at 80 steps, the rods in group 2 (4 rods)

of control bank B dropped into the core. The reactor trip breakers were

manually opened in accordance with Abnormal Procedure (AP-1.2) and all

the other rods were inserted (dropped) into the core. The NRC was i

notified, EN 22941, as required by the Code of Federal Regulations.

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An investigation by the licensee identified that the CRDM firing cards

were degraded with circumferential cracks in the soldering joints. The

card was replaced, and subsequently all firing cards for both Unit I and j

2 were visually inspected. Cards that showed excessive aging and cracks I

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in solder joints were replaced with a new style firing card. In >

addition, preventive maintenance procedures I-IPM-RCS-001 and

2-IPM-RCS-001, which were reviewed by the inspector, were developed to ,

routinely inspect the Rod Control Cabinets every refueling outage.

9. Exit (30703) .

The inspection scope and findings were sumarized on June 23, 1993, 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  :

provided to or reviewed by the inspectors during this inspection,  !

Dissenting coments were not received from the licensee. *

Item Number Description and Reference

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VIO 50-338/93-18-01 Inoperable Hydrogen Analyzer (Paragraph 3.a) '

10. Acronyms and Initialisms

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AFW Auxiliary Feedwater

CFR Code of Federal Regulations

CNS Corporate Nuclear Safety  ;

CRDM Control Rod Drive Mechanism

DR Deviation Report

ECCS Emergency Core Cooling System

Instruinentation and Control

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I&C

ICP Instrument Calibration Procedure ,

KV Kilovolts

LC0 Limiting Condition for Operation i

LER Licensee Event Report  !

LHSI Low Head Safety injection i

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ML Milliliter

, M0P Maintenance Operating Procedure  ;

NRC Nuclear Regulatory Comission j

OSC Operational Support Center  ;

PAR Procedure Action Request i

PSIG Pounds Per Square Inch Gage  :

PT Periodic Test i

QC Quality Control  :

RSS Reserve Station Service _,

SNSOC Station Nuclear Safety and Operating Comittee l

SOB Station Oversight Board l

SRO Senior Reactor Operator l

TS Technical Specification

TSC Technical Support Center

WO Work Order