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Insp Rept 50-458/88-01 on 880101-0215.Violation Noted.Major Areas Inspected:Nrc Bulletin 87-002,10CFR21 Repts, Surveillance Test Observation,Maint Observation,Safety Sys Walkdown & Operational Safety Verification
	ML20150B505
Person / Time
Site:	River Bend
Issue date:	03/04/1988
From:	Chamberlain D, Holler E, William Jones; NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION IV)
To:	;
Shared Package
ML20150B491	List: ML20150B488; ML20150B493; ML20150B505;
References
	50-458-88-01, 50-458-88-1, IEB-87-002, IEB-87-2, NUDOCS 8803170026
	Download: ML20150B505 (12)
	v • d • e

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APPENDIX B

U. S. NUCLEAR REGULATORY C0FNISSION

REGION IV

NRC Inspection Report: 50-458/88-01

Docket: 50-458

Licensee: Gulf States Utilities Company (GSU)

P. O. Box 220

St. Francisville, Louisiana 70775

Facility Name: River Bend Station (RBS) :

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Inspection At: River Bend Station, St. Francisville, Louisiana

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Inspection Conducted: January 1 through February 15, 1988

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Inspectors: E .

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D. D." Chamberlain, Senior Resident Inspector Date

Project Section C, Division of Reactor Projects

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Y"$ $'bh

W. B.VJ ones, Resident ::nspector (> Date

Project Section C, Division of Reactor Projects

Approved: n N

E. J./1(oller, Chief, Project Section C D'a t e/

Division of Reactor Projects

8803170026 880309

PDR ADOCK 05000458

0 PDR

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Inspection Summary

Inspection Conducted January 1 through February 15, 1988

(Report 50-458/88-01)

Areas Inspected: Routine, unannounced inspection of licensee action on

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previous inspection findings, NRC Bulletin 87-02, 10 CFR Part 21 Reports,

surveillance test observation, maintenance observation, safety system

walkdown, and operational safety verification.

Results: Within the areas inspected, one violation was identified

(failure of timely follow-up review to verify corrective action completion,

paragraph 2).

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DETAILS

1. Persons Contacted

D. L. Andrews, Director, Nuclear Training

. R. J. Backen, Supervisor, Operations Quality Assurance (QA)

C. L. Ballard, Supervisor, Projects

W. J. Beck, Supervisor, Reactor Engineering

J. E. Booker, Manager, Oversight

J. L. Burton, Supervisor, Independent Safety Engineering Group

E. M. Cargill, Supervisor, Radiation Programs

J. W. Cook, Lead Environmental Analyst, Nuclear Licensing

T. C. Crouse, Manager, QA

J. C. Deddens, Senior Vice President River Bend Nuclear Group

D. R. Derbonne, Assistant Plant Manager, Maintenance

L. A. England, Supervisor, Nuclear Licensing

P. E. Freehill, Outage Manager

A. O. Fredieu, Supervisor, Operations

P. D. Graham, Assistant Plant Manager, Operations

J. R. Hamilton, Director, Design Engineering

G. K. Henry, Supervisor, Electrical Engineering

K. C. Hodges, Supervisor, Chemistry

L. G. Johnson, Site Representative, Cajun

G. R. Kimmell, Director, Quality Services

R. J. King, Supervisor, Nuclear Licensing

A. D. Kowalczuk, Director, Oversight

J. W. Leavines, Director, Field Engineering

I. M. Malik, Supervisor, Quality Systems

J. H. McQuirter, Licensing Engineer

V. J. Normand, Supervisor, Administrative Services

W. H. Odell, Manager, Administration

T. F. Plunkett, Plant Manager '

M. F. Sankovich, Manager, Engineering

R. R. Smith, Engineer, Nuclear Licensing

K. E. Suhrke, Manager, Project Management

B. E. Tate, Supervisor, Project Scheduling

R. J. Vachon, Senior Compliance Analyst '

R. G. West, Supervisor, General Maintenance

The NRC inspectors also interviewed additional licensee personnel during

the inspection period.

Denotes those persons that attended the exit interview conducted on

February 19, 1988.

2. Licensee Action on Previous Inspection Findings

a. (Closed) Open Item (458/8632-01): Licensee implementation of power

line conditioner modifications and development of low voltage panel

load lists,

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This open item relates to the licensee efforts to correct a tripping

problem with Elgar power line conditioners (PLC). The trip problem

occurred during electrical distribution system transients. The PLC

are designed to provide a stable 120 volt AC power source for control

and indication circuits for both safety and nonsafety-related loads.

In addition to correcting the trip problem, the licensee instituted

an effort to provide low voltage distribution panel load lists. The

licensee has completed design modifications to correct the trip

problem. An electrical panel load list manual has been developed

which provides a general description of breaker loads and power loss

effects. Also, low voltage electrical panels were labeled and power

distribution schedules were inserted in each panel.

This open item is closed.

b. (0 pen) Open Item (458/8615-02): Monitor licensee actions to correct

electrical drawing discrepancies on the standby gas treatment

system (SGTS) recirculation dampers.

In April 1986, the licensee identified discrepancies between the

electrical schematic drawings and the actual field wiring

configuration for the SGTS recirculation dampers. Condition

report (CR) 86-0442 was issued on April 12, 1986, to affect

corrective action for the identified discrepancies. Corrective

actions included operationally configuring the system with the

dampers closed during standby operation and verification of system

operability by surveillance testing. Also, additional design

I documents were reviewed for similar errors and only six minor

I administrative discrepancies were found. Modification request

l (MR) 86-0642 was issued to correct the initial condition found.

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CR 86-0442 was closed with MR 86-064^ issued to correct the

nonconforming field wiring condition. MR 86-0642 was issued on

April 19, 1986, but it was not released for field work until

January 7,1988. Although several plant outages occurred during 1986

and 1987, including the first refueling outage for 3 months in 1987,

this modification has not been implemented to correct the

nonconforming condition. The licensee's quality assurance program

requires timely follow-up reviews by the appropriate department to

verify that specified corrective action has been properly

implemented. The apparent lack of timely follow-up review to verify

completion of corrective action for CR 86-0442, which included

completion of MR 86-0642, was identified by the SRI as a potential

violation. (458/8801-01)

This open item remains open.

3. Licensee Action on f4RC Bulletin 87-02

This area of the inspection was conducted to review licensee actions

relative to fiRC Compliance Bulletin No. 87-02, "Fastener Testing to

Determine Conformance With Applicable Material Specifications." The

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purpose of this bulletin is to request that the licensee: (a) review

their receipt inspection requirements and internal controls for fasteners;

and (b) independently determine, through testing, whether fasteners in

store at the facility meet required mechanical and chemical specification

requirements.

The licensee's program for receipt inspection requirements and internal

controls for fasteners is described in Quality Assurance Instruction

QAl-2.2, "QA Review of Procurement Documents and Identification of Receipt

Inspection Requirements," and Quality Control Instruction QCI-3.0,

"Receiving Inspection." The resident inspector verified that the

licensee's program for receipt inspection requirements for ASME fasteners,

as described in their response to NRC Compliar.ce Bulletin 87-02, is

reflected in the above two procedures.

The licensee has received the test results for the fasteners selected with

the participation of the resident inspector. Seven of the selected

fasteners were found to be out of specification conditions. The failures

occurred for both mechanical and chemical properties. The licensee has

evaluated each of the failures and determined that no adverse impact on

safety-related components exists. The basis for this evaluation is given

as an attachment to the licensee's response dated January 29, 1988. A

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copy of the response has been submitted to the Vendor Branch of Nuclear

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Reactor Regulation. NRC Region IV actions associated with temparary

instruction TI 2500/26 are complete.

No violations or deviations were identified in this a.ea of the

inspection.

4. 10 CFR Part 21 Reports

The resident inspectors were provided copies of selected 10 CFR Part 21

reports by NRC Region IV, which may be applicable to equipment or services

supplied to River Bend. These reports were provided to the licensee, who

verified that the reports either had been or were being evaluated for

applicability at River Bend. Any reports that were not already entered

into the lir le tracking system were immediately entered. A listing of

reports by date, manufacturer, and subject is provided below:

o October 2,1987 - Borg Warner Corporation, Nuclear Valve

Division - Potential failure of fasteners between valve yoke and yoke

adapter.

o November 13, 1987 - Limitorque Corporation - SMB-00 motor operators

found with abrasion damage to the motor lead wires.

The resident inspectors will continue to provide copies of potentially

applicable 10 CFR Part 21 reports for licensee evaluation, and a follow up

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of licensee action on selected 10 CFR Part 21 reports will be conducted

during future NRC inspections.

No violations or deviations were identified in this area of the

inspection.

5. Surveillance Test Observation

During this inspection period, the resident inspector observed the

performance of Surveillance Test Procedures STP-511-4504, "RPS/ Isolation

Actuation-MSLI-Main Steam Line Radiation-High Monthly Chfunct

(017-K6100)," and STP-309-0202, "Diesel Generator Division II Operability

Test." The results are documented below,

o STP-511-4504: This surveillance test procedure was performed on

January 16 and 17,1988, to meet the channel functional test

requirements for the main steam line isolation on high main steam

line radiation with the reactor in operational condition 1. The

operability requirements are identified in Technical

Specification (TS) 4.3.1.1 and 4.3.2.1, Tables 4.3.1.1-1.7

and 4.3.2.1.-l.2.b. During the performance of the surveillance test,

the licensee found that the high radiation trip setpoint for

instrument D17-K6100 exceeded the TS allowable value of less than or

equal to 3.6 times full power operation radiation background. This

determination was based on the main steam line 100 percent power

radiation monitor background values established on January 8,1988, .

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in licensee memorandum RPG-88-010. The licensee periodically adjusts '

the calibration values to allow for changes in ionization chambers

and other system responses. The previous main steamline 100 percent

power monitor background values were established on April 27, 1987,

in memorandum RPG-87-160. This was prior to the licensee beginning

power coastdown for the end of the first fuel cycle. The resident

inspector met with licensee personnel to discuss what. actions were

being taken to ensure that changes to the main steam line radiatior,

background monitors are promptly identified to assure the trip <

setpoints reflect the latest radiation monitor values and the

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associated TS requirements. The licensee has initiated CR 88-0056 to

review the incident and document their corrective action. The

licensee's corrective action will be an open item (458/8801-02)

pending further review during a future NRC inspection,

o STP-309-0202: On February 11, 1988, at 12:40 a.m., CST, the licensee '

experienced a loss of preferred station transformer D. Preferred

station transformer D was supplying the Division II safety-related

bus 1 ENS *SWG1B at the time of the event. This resulted in a

subsequent loss of offsite power to 1 ENS *SWG18. The Division II

emergency diesel generator started on undervoltage on the bus and the

output breaker closed within 10 seconds to support the required

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loads. At 2:42 a.m., CST, the licensee paralleled offsite power to .

1 ENS *SWG1B through normai station transformer C and the alternate

supply breaker. The diesel generator was then loaded between 3030

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and 3130kw for 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months to meet the requirements of the surveillance -

test. The start time and times to rate voltage and frequency were

determined through review of data points collected on the emergency

response information system (ERIS) computer. All of the associated

times were found to meet the requirements of TSs and the surveillance

test. A further discussion of this partial loss of offsite. event is

described in paragraph 8 of this report. A review of the

surveillance test data by the resident inspector revealed no problems

with using this diesel start to meet the diesel operability

requirements.

No violation or deviation was identified in this area of the

inspection.

6. Maintenance Observation

On February 7,1988, with the reactor in operational condition 2, the

resident inspector observed maintenance activities for replacement of the

reactor core isolation cooling (RCIC) system isolation actuation

instrument, 1E31*N610A. This instrument is required by TS 3.3.2 to be

operable whenever the reactor is in operational conditions 1, 2, or 3.

The instrument serves to close the RCIC steam supply line outboard

isolation valve, 1E51*MOVF064, en a residual heat removal (RHR) room, high

ambient temperature. The instrument was identified as inoperable during a

channel check required by surveillance test procedure STP-000-0001, "Daily

Operating Logs." The licensee initiated limited condition of operation

(LC0)-88-43 to identify the failed instrument and prevent entry into l

mode 1. Prompt maintenance work order (PMW0) 56017 was initiated to

replace the instrument. The resident inspector verified through

observation and/or review of records that: i

o the requirements of TS 3.3.2 were met;

o the required administrative approvals were obtained prior to

initiating work;

o controls for lifted leads and jumpers were followed;

o a quality control inspector observed the performance of the

maintenance activity as required for PMW0s; and

o the instrument was tested before being returned to service.

No violations or deviations were identified in this area of the

inspection.

7. Safety System Walkdown

During this inspection period, the resident inspector performed a walkdown

of the main steam-positive leakage control system (MS-PLCS) with the plant

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in operational condition 1. Two independent MS-PLCS divisions are

required by TS 3.6.].5 to be operable in operational conditions 1, 2,

and 3. The MS-PLCS is used to seal between the inboard and outboard

mainstream isolation valves (MSIV) and between the outboard MSIV and the

main steam shutoff valves. In the event of a loss of coolant accident,

the system is designed to maintain leakage from the containment within the

10 CFR Part 50 Appendix J Guidelines. The MS-PLCS walkdown consisted of a

verification of accessible valve positions, instrument 11oeups and

electrical lineups. The MS-PLCS valves which are located in the steam

tunnel will be verified in the required positions when plant operating

conditions permit. Review of the control board lineup dia not reveal any

conditions which would adversely affect MS-PLCS operability.

No violations or deviations were identified in this area of the

inspection. __

8. Operational Safety Verification

l The resident inspectors observed operational activities throughout the

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inspection period and closely monitored operational events. Control room

activities and conduct were generally observed to be well controlled.

Proper control room staffing was maintained and access to the control room

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operational areas was controlled. Selected shift turnover meetings werc

observed and it was found that information concerning plant status was

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being covered in each of these meetings. System walkdowns of the "A,"

"B," and "C" low pressure coolant injection systems were conducted to

verify major flow path alignments for operabil1ty. Also, a detailed

system walkdown of the main steam positive leakage control system was

conducted and the results are documented in paragraph 7 of this report.

Plant tours were conducted, and overall plant cleanliness was good.

General radiation protection practices were observed and no problems were

noted. Personnel exiting the radiation control area were observed and

radiation monitors were being properly utilized to check for

contamination.

In addition to the routine observation of security activities by the

resident inspectors, the resident inspector participated in the security

Regulatory Effectiveness Review (RER) conductea during this inspection

period. The RER was performed by NRC personnel and members of the Army

Special Forces.

The resident inspector provided comments to the RER team leader for

inclusion in the NRC assessment of the security program at River Bend

Station as appropriate. Plant perimeter walkdowns were conducted and

personnel entry and exit from the protected area were observed and no

problems were noted.

The resident inspectors also reviewed licensee actions on operational

events and potential problems. The results of reviews of selected items

are described below:

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a. Annulus Radiation Monitors

On January 6,1988, the licensee discovered the cooling water supply

valves (3042 and 3043) isolated to the annulus radiation monitors

(RE11A&B). The valves were immediately opened and CR 88-0011 was '

issued for investigation and corrective action. Subsequent

investigation by the licensee revealed that these valves were

included within the boundary of a clearance issued during the

refueling outage. The clearance was issued to allow cleaning of the

cooling water lines that had plugged. The actual work performed ,

included replacement of a section of the piping which included the

valves that were later found isolated. Apparently these valves were

replaced and the maintenance mechanics left them closed on

December 10, 1987. The clearance was released on December 13, 1987,

but only the boundary valves included in the clearance were reopened.

The post maintenance testing performed was only an operational leak

test and no verificaticn of flow was performed. The subject valves

were then found closed by an operator during his routine rounds on

January 6,1988. The valve alignments for these radiation monitors

had been performed prior to issuance of the clearance and the

clearance restoration should have restored the valves to the proper

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position. The licensee has evaluated tha root cause of this problem

to be inadequate controls to verify proper position of valves located

within t'en boundaries of a clearance. The licensee also performed a

detailed engineering evaluation of the safety significance of the

isolation of cooling water to the annulus radiation monitors. The

evaluation confirms that cooling water is not required for these

monitors to perform their intended safety function. It was also

determined that the annulus exhaust radiation monitors are not

necessary to initiate the standby gas treatment system since

redundant and diverse actuation signals are provided by high drywell

pressure and low reactor water level. Licensee corrective actions

for this, problem included:

o a review of other modification activities performed during the

refueling outage for similar problems;

o addition of a hold point on all mechanical job plans by the

maintenance planner for operations to verify final position of

all manual valves affected during the performance of maintenance

activities; and

o revision to Administrative Procedure ADM-0027, "Protective

Tagging" to require that' all valves located within the boundary

of a clearance to be restored when the clearance is restored.

The resident inspectors have monitored licensee actions on this

problem. No NRC violation will be issued because the licensee

identified the problem and took prompt and extensive corrective

action. Also, the isolation of these valves had no impact on sate

operation of River Bend. ;

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b. Scram Discharge Volume

During the performance of surveillance test STP-052-3301 for control

rod drive operability on January 26, 1988, the licensee discovered

that the scram discharge volume drain valve IC11*A0V011 would not

fully close. This valve is an air operated valve which fails open on

loss of air pressure. The valve is in series with another automatic

valve on the scram discharge volume drain line. Both valves are

normally open and receive a close signal during a reactor SCRAM.

When the SCRAM is reset both valves open to allow the scram discharge

volume to drain. The failure of either one or both of these valves

to close would not prevent a reactor SCRAM from occurring. The

licensee initiated CR 88-0086 to investigate the cause of the valve

not fully closing. Subsequent investigation by the licensee revealed

that a manual handwheel used to jack the air operated valve to the

closed position was partially closed. A similar valve 1C11*A0V010 on

the scram discharge volume vent line was also.found to have the same

condition. The licensee immediately positioned the manual handwheels

for both valves to allow free movement of the valves. The valve

lineup for this system only required placing these valves in service

and with no mention of the manual handwheels. The licensee has

revised the valve lineup to require the manual handwheels to be

rotated to the full clockwise position and locked in place. The

licensee is continuing investigation of this problem for action to

prevent recurrence. The resident inspectors will continue to monitor

licensee actions,

c. Division II Preferred Power

On February 11, 1988, with the plant at 10 percent power, preferred

station service transformers RTX-XSRIB and 10 tripped off line

causing a loss of power to the Division II emergency bus. This

equates to the loss of 1 of 2 offsite power sources. The Division II

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emergency diesel generator auto started and supplied power to the

Division II emergency bus as per design. The licensee entered a

72-hour shutdown limiting condition fo^ operation as required by TSs

while the cause for the trip was investigated. The cause of the trip

was determined to be a bad grounding transformer on the 1B preferred

station service transformer. The ID transformer was then returned to

service to supply offsite power to Division II emergency bus before

the 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months were expended. The grounding transfonner on the

IB preferred station service transformer has been replaced and normal

electrical lineups restored. The licensee is continuing the

investigation for the cause of the grounding transformer failure.

The resident inspectors will continue to monitor licensee actions,

d. Reactor Shutdowns

During this inspection period, there were two unplanned reactor

shutdowns and one planned reactor shutdown. The details of these

events are discussed below:

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o Alternate Rod Insertion SCRAM: On January 10, 1988, with the

plant at 100 percent power, a reactor SCRAM occurred during the

performance of surveillance test procedure STP-051-4269 on the

alternate rod insertion system. The alternate rod

insertion (ARI) system was added during the recent refueling

outage as an anticipated transient without a scram (ATWAS).

i feature. This surveillance test was required to be performed on

a monthly basis and it had been performed at least one other

time. During perforn.ance of the test, technicians incorrectly

lifted wiring from "TB6" terminals 4 and 5 instead of from

"TB0006" terminals 4 and 5. These terminal blocks were both

located in the saroe electrical panel. Lifting of the incorrect

wiring resulted in breaking the common ground circuit for two

trip units which initiated the ARI reactor shutdown. Licensee

corre:tive actions for this event included shop training of

technicians.on the event, revising of ATWAS procedures to more

clearly define the correct terminal board locations, and marking

of control room ATWAS panels with caution signs to note

potential for a reactor SCRAM by lifting one electrical lead.

The licensee has also initiated engineering action requests to

evaluate changes to the AT11AS wiring so that the comon wiring

configuration does not affect multiple trip units. The resident

, inspectors will continue to monitor licensee actions in this

area.

o Reactor High Pressure SCRAM: On January 28, 1988, with the

plant at 100 percent power, a reactor SCRAM occurred from

reactor high pressure. The reactor high pressure condition

occurred from a main turbine runback because of a high stator

cooling water temperature signal. Subsequent investigation by

the licensee revealed that a piece of linkage on a stator

cooling water temperature controller had broken. This caused

the control valve to go full open and bypass the generator

stator coolers. The stator water temperature increased to the

turbine runback setpoint of 178*F. The operators could not drop

reactor power fast enough to account for the reduced turbine

load and reactor pressure increased to the SCRAM initiation.

The licensee determined that the temperature controller had

failed because of excessive vibration at the mounted location.

The controller has been relocated to a vibration free location

and the temperature switch for turbine runback initiation has

also been relocated. The licensee also installed a mechanical

stop on the temperature control valve so that the stator coolers

will never be fully bypassed. The stator coofing water

temperature alarm has also been lowered by 10 to allow

operators more response time for future events of this nature.

The licensee actions for this event are considered responsive

and thorough.

o Manual Reactor SCRAM: On February 6,1988, the licensee

initiated a manual reactor SCRAM with the plant at 13 percent

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power. The main turbine was being taken off line in order to

repair a main generator exciter coupling. This exciter coupling

had developed a lubrication leakage. During the main turbine

coastdown a high vibration condition developed and the shift

supervisor decided to b*eak condenser vacuum and initiate a

manual SCRAM. The exciter coupling was repaired and-a plant

restart was conducted on February 7,1988. No vibration

problems were encountered with the main turbine during the plant

restart. The licensee speculates that operating the turbine

unloaded during the coastdown caused hot spots along.the turbine

shaft and subsequently caused the high vibration condition. The

licensee is continuing to investigate the problem.

No violations or deviations were identified in this area of

inspection,

9. Exit Interview

An exit interview was conducted with licensee representatives (Identified

in paragraph 1). During this interview, the senior resident inspector

reviewed the scope and findings of the inspection. ,

ML20150B505

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