ML20059K490

Insp Rept 50-458/93-26 on 930822-0925.Violations Noted.Major Areas Inspected:Plant Status,Onsited Response to Events, Operation Safety Verification,Employee Concerns Program, Maintenance & Surveillance Observations

ML20059K490
Person / Time
Site:	River Bend
Issue date:	11/04/1993
From:	Gagliardo J NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION IV)
To:
Shared Package
ML20059K457	List: ML20059K455 ML20059K473 ML20059K490
References
50-458-93-26, NUDOCS 9311160077
Download: ML20059K490 (32)

See also: IR 05000458/1993026

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APPENDIX B

U.S. NUCLEAR REGULATORY COMMISSION  ;

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REGION IV

Inspection Report: 50-458/93-26

Operating License: NPF-47 ,

Licensee: Gulf States Utilities

P.O. Box 220

St. Francisville, Louisiane 70775-0220

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facility Name: River Bend Station

Inspection At: St. Francisville, Louisiana

Inspection Conducted: August 22 through September 25, 1993

Inspectors: W. F. Smith, Senior Resident Inspector-

P. H. Harrell, Chief, Technical Support Staff

R. B. Vickrey, Reactor Inspector, Division of Reactor Safety

J. E. Whittemore, Reactor Inspector, Division of Reactor Safety

P. C. Wagner, Team Leader, Division of Reactor Safety ,

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Approved: d' % st t 9

J. E.L6agliardo, Chief, Project Section C Date

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Inspection Summary i

Areas Inspected: Routine, unannounced inspection of plant status, onsite-

response to events, operational safety verification, employee concerns  ;

program, maintenance and surveillance observations, followup on corrective-

actions for violations, other followup, and review of licensee event reports.

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Results:

• The licensee's response.to.the main cooling tower blowdown radiation

alarm was not conservative and followup actions-were not well

coordinated. The operators failed- to appropriately consider the-

potential significance of allowing the main cooling tower- blowdown to .

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continue. The subsequent-operator actions to assess the validity of the

alarm were poorly coordinated and untimely. Two violations were

identified for the failure to establish alarm response procedures for  !

the safety-related Radioactive Monitor Panel RM-11 annunciators. and the  !

failure to promptly identify and correct the' conditions which resulted

in an unexpected main cooling tower blowdown high radiation alarm. It -i

was subsequently determined that the LRW discharge had contaminated the:

main cooling tower blowdown radiation monitor. The radioactive j

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discharge activity was within the planned level and did not exceed the

Technical Specification limits (Section 2.1). .

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. The modification request (MR) which implemented design changes to the-

LRW system was only marginally adequate. The effect the design change

had on interfacing systems was not appropriately considered and the MR  !

status was not effectively communicated to the operators and.other  :

essential plant personnel (Section 2.1). -

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. The licensee's corrective action program implementation was mixed. The

root cause investigation of the effluent radiation alarm event was well ,

conducted and comprehensive. The-corrective actions appeared to address a

the root cause to prevent a recurrence. However, the licensee's

investigation of the danger tag violations, related to the

nonsafety-related sodium hypochlorite system, was narrowly focused. The

review of motor-operated valves which may not have been worked in

accordance with vendor maintenance recommendations was adequate and the -

operability assessment was appropriate. A heightened sensitivity to '

indeterminate root cause determinations was demonstrated-(Sections 2.1,

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2.2, 2.3, and 3.3).

e The condition reporting process was not well utilized to ensure a fire

protection commitment was appropriately implemented (Section 8).

• A potentially significant weakness was identified for plant personnel

operating plant equipment without sufficient training (Section 2.2).

. The licensee was not effective in implementing vendor maintenance

recommendations for motor-operated valves into the applicable

procedures. The reactor core isolation cooling (RCIC) pump vendor

manual was also determined to be inaccurate. An unresolved item was

initiated to review the implementation of the vendor technical

information program and equipment operability concerns (Section 2.3). [

. The control room operators demonstrated good communications and positive

control of plant conditions during conduct of'(average power range  !

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monitor) APRM surveillance testing' concurrent with power ascension

(Section 3.1).  !

• Plant housekeeping practices remained essentially unchanged. Personnel- 3

housekeeping practices within areas which have been significantly

enhanced was very good; however, these practices were not demonstrated i

in less frequented areas, including work areas within radiologically -!

contaminated zones. The control of nonpermanent equipment within i

safety-related areas was determined to be adequate (Section 3.2). i

• The information on the licensee's employee concerns program (ECP) as i

requested by Temporary Instruction 2500/28 has been provided (Section 4

and Appendix C). 7

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• The licensee's implementation of maintenance work activities was mixed.

The control rod drive troubleshooting and fire protection modification

activities were effectively implemented. Excellent work coordination .

was noted between operations, engineering, and maintenance personnel.

The work plans were found to be very good. However, the work activity  ;

associated with the replacement of the RCIC pump thrust bearing was  !

poorly implemented. Inaccurate vendor manual instructions and I

inadequate preparation by maintenance personnel contributed to the RCIC

system being inoperable through the end of the inspection period

(Sections 5.1, 5.2, and 5.3).  ;

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• Appropriate surveillance activities were in place to detect degraded r

performance on safety-related ventilation systems. The preventive a

maintenance program was enhanced to inspect ventilation system flexible -

seal s . Building penetration seals were previously included in a

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preventive maintenance task (Section 5.4).  !

• Testing of the steam pressure control systems was conducted in an ,

excellent manner. The procedure was well written and informative, good i

briefings were conducted, and the implementation was well controlled 4

(Section 6.1).

• Inservice testing of the RCIC pump was not well planned. Delays and

poor communications were experienced as a result. The personnel 1

involved in the RCIC testing were not familiar with the procedure change 1

implemented the prior week. The licensee implemented appropriate l

actions to ensure the personnel performance problems were not repeated

during subsequent tests (Section 6.2). '

Summar_y of Inspection Findings:

• Violation 458/93026-1 was opened (Section 2.1). j

• Violation 458/93026-2 was opened (Section 2.1).

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• Unresolved Item 458/93026-3 was opened (Sections 2.3).

• Unresolved Item 458/93026-4 was opened (Section 5.2).

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Violation 458/92018-1 was closed (Section 7.1).

• Violation 458/92032-1 was closed (Section 7.2). .

Violation 458/92032-2 was closed (Section 7.3).

Violation 458/92032-3 was closed (Section 7.4).

• Violation 458/92035-1 was closed (Section 7.5).

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e Inspection Followup Item 458/92022-2 was closed (Section 8.2). ,

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• Unresolved Itein 458/93003-3 was closed (Section 8.3).

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• Licensee Event Reports 458/89-011, 458/91-016, 458/92-014, 458/92-019,

and 458/92-026 were closed (Section 9).

Attachment:

• Persons Contacted and Exit' Meeting

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DETAILS

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1 PLANT STATUS

At the beginning of this inspection period, the plant was in hot shutdown -

(Mode 3), and reactor pressure was at approximately 165 psig and decreasing

from the ambient decay heat loss. The reactor had scrammed on August 10 while -

technicians were troubleshooting the main turbine electrohydraulic control.  ;

system. Repairs to this system as well as several other maintenance items t

were in progress to support startup.

On August 25 the plant was ple.td in cold shutdown (Mode 4). A reactor

startup was initiated on August 31 and full power operation achieved 5 days -

later. On September 18 power was reduced to about 80 percent for main turbine  ;

valve testing and then returned to full power operation the following day.

The plant operated at 100 percent power from September 19 through the end of .

this inspection period. l

On September 28 the licensee announced several senior management level changes

to become effective immediately. These changes included the addition of a

Senior Vice President to be located part of the time on site, a_new Vice ol

President-RBNG, a new Plant Manager, and a new Manager-Safety Assessment and

Quality Verification (SA/QV).

2 ONSITE RESPONSE TO EVENTS (93702)

2.1 Contamination of Main Coolina Tower Blowdown Radiation Monitor  ;

On September 7,1993, at approximately 6:45 p.m. (CDT), while conducting

control room observations, the inspector was informed that the main cooling  ;

tower blowdown Radiation Monitor RMS*RE108 had alarmed. The monitor was

designed to help ensure that discharges to the Mississippi River did not  ;

exceed radioactivity levels allowed by the plant Technical Specifications. 1

The operators had stopped the main cooling tower blowdown and a' concurrent  ;

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liquid radioactive waste (LRW) discharge pending results of a grab sample to

determine the validity of the alarm. At approximately 8:25 p.m. the main

cooling tower fiume sample result was determined to be negative and an LRW

release with a greater activity than planned had not occurred. However, the  !

sample taken at radiation Monitor RMS*RE108, which was approximately one-half

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- of the monitor alarm setpoint had become unexpectedly contaminated from the 4

LRW release.  !

The inspector determined that the control room operators became aware of the

alarm condition on Radiation Monitor RMS*RE108 at approximately 4:08 p.m.

through annunciation on Radiation Monitor Panel RM-11. Although the alarm

could have indicated a significant event was in progress, the event was not l

entered into the control room log and no immediate actions were taken to .i'

secure the main cooling tower blowdown or verify the validity of- the alarm.

Had the alarm been valid, the' licensee's emergency implementing procedure

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would have required the shift supervisor to declare the Emergency Plan l

Classification, " Notice Of Unusual Event." The inspector noted that the first

control room log entry was made at 6:25 p.m. (CDT) when the operators gave the  ;

order for the auxiliary control room operators to secure the LRW discharge. l

The main control room log indicated that at 6:41 p.m. (CDT) the order was  :

given to secure the main cooling tower blowdown due to Monitor RMS*RE108 being

in an alarm state. By 6:42 p.m. the discharges were logged as terminated. '

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The inspector reviewed the guidance provided to the operators on logging

annunciators. It was determined that the failure to log the radiation monitor

panel alarm was not consistent with the licensee management's expectations

established in Operations Policy 5. This policy stated that significant

annunciator alarms would be recorded with the actions taken. l

The inspector also determined that the licensee had not established alarm  !

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response procedures for the Radiation Monitor Panel RM-11 safety-related

annunciators. This panel provided an audible alarm and a trend display in the- -

main control room for many radiation monitors, including Monitor RMS*RE108.

Technical Specification 6.8.1 and Regulatory Guide 1.33 require such

procedures to be established, implemented, and maintained for all safety-

related alarms. The inspector determined that the failure to provide an alarm

response procedure for Monitor RMS*RE108 and the other .ladiation Monitor Panel ,

RM-11 safety-related annunciators is a Technical Specification 6.8.1  ;

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violation (458/93026-1). It was found that the required alarm response

procedures had been established and implemented for the main control panel

annunciators that were also actuated by Radiation Monitor Panel RM-11.

The inspector reviewed the operator's initial response to the Radiation i

Monitor Panel RM-11 alarm. It was found that because the operator's did not ,

believe their control room indication, they did not terminate the potentially  !

contaminated effluent discharge until 21/2 hours after the main cooling tower i

effluent radiation alarm was received. More than 500,000 gallons were

discharged to the Mississippi River before the blowdown was terminated. In  :

addition, the main control room log identified that the grab sample results to

assess the validity of the effluent radiation alarm were not communicated to .

the main control room until 8:25 p.m. (CDT). The inspector concluded that no J

apparent sense of urgency was communicated to the chemistry department- to

obtain the grab samples to confirm or invalidate the alarm. The operator's i

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failure to promptly initiate measures to identify and correct the condition

which resulted in the unexpected Radiation Monitor Panel RM-11 alarm is a i

violation of Criterion XVI to 10 CFR 50, Appendix B (458/93026-2). 4

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The inspector subsequently reviewed with the cognizant system engineer the

conditions which resulted in radiation Monitor RMS*RE108 becoming

radioactively contaminated. He identified that radiation Monitor RMS*RE108 'l

had been contaminated by the effluent from the new LRW system discharge l

piping. This piping had recently been connected to the blowdown piping by l

plant MR 86-0156. The MR was initiated to increase LRW discharge capacity by j

utilizing an existing 3-inch service water line originally designed for J

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alternate dilution of service water to the main cooling tower blowdown line.

The licensee explained that this line was never used and it had become l

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obsolete with the completion of the closed loop service water system in 1992.

Since this line was already connected to the blowdown line, the MR focused on

the design of the LRW system piping connections to the service water line

within the plant and the potential impact to the LRW effluent process  :

radiation Monitor RMS*RE107 and its associated automatic isolation function. t

The licensee further explained that, throughout the design conception, '

development, review, and installation, adverse ~ impacts to Monitor RMS*RE108

had not been evaluated. It had not been identified that the LRW effluent,

which was monitored by radiation Monitor RMS*RE107, would be mixed with the

blowdown water from the main cooling tower flume and again__ monitored by

radiation Monitor RMS*RE108. Consequently, the design function of radiation

Monitor RMS*RE108 to detect low level contamination from the main cooling

towers was defeated. ,

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The licensee. performed a root cause determination of this event and developed

a comprehensive " Events and Causal Factors" chart. The inspector found that

the chart showed a timeline of events and inappropriate actions, with

associated contributors. The licensee then developed and was implementing a

corrective action plan at the end of the inspection period to correct the

identified root causes.

The licensee determined that the root causes for inappropriate operator

actions were: (1) the operators did not meet the safety culture expectations  ;

established by plant management, (2) there were no alarm response

procedures (ARPs) for critical radiation monitoring system alarms to provide

guidance on immediate and subsequent operator actions, and (3) the operating

crew was not informed of the current status of MR 86-0156. The following

corrective actions were initiated by the licensee:

• Initiated counseling and administrative actions to reenforce the safety l

culture expectations for each operating crew. ,

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• Standing Order 104 was promptly issued to provide interim guidance in I

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the event of future Monitor RMS*RE108 alarms. i

• Development of ARPs for Panel RM-11 and an evaluation of the feasibility I

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of developing ARPs for similar panels in the control room, such as the

fire protection and process computer panels. )

• A review of the emergency action levels (EALS) .to determine if there are

other cases similar to the EAL-for Monitor RMS*RE108 where there was no j

alarm procedure or that existing procedures failed to reference to the i

emergency implementing procedures. l

• Revise the EAL for the RMS*RE108 alarm to specifically allow

verification of the alarm via' grab sample from the cooling _ tower flume

before entering the emergency classification.

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• Evaluate the expediency of MR-related training provided to the. operators

and crews on plant changes, and the impacts to the modified system and

associated systems.

The root causes identified for failure of MR 86-0156 to be properly-  !

implemented were: (1) the modification process, controls and reviews focused

on what was contained within the MR package and not on potential adverse '

impacts to peripheral systems, and (2) information contained on the system

diagram relating to Monitor RMS*RE108 caused confusion concerning sample _ and

purge line functions and the location of those lines in relation to other

lines. The corrective actions established were: <

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• Relocate the inlet for Monitor RMS*RE108 upstream of all blowdown line

LRW connections to preclude future contamination of the detector.

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a Update the system diagram to reflect the above changes and clearly

identified the line designations for Monitor RMS*RE108.  ;

• Perform a review of all system diagrams showing process radiation  ;

monitors and clarify line designations, if necessary.

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• Update MR checklists and completion signoffs to include licensed

operators or shift technical advisors. >

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The inspector found the root cause analysis to be comprehensive, and the

corrective actions that had been completed at the end of the inspection period  !

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were appropriate.

2.2 Operation of Danger Taqqed Eauipment

The inspector noted during a review of the licensee's condition reports (CRs),

that, on August 31, 1993, CR 93-0522 identified a problem where danger-tagged

valves on the circulating water makeup clarifier sodium hypochlorite system

(nonsafety-related) had been operated with the danger tags in place. No

apparent damage resulted to the system and no personnel were injured.

The licensee's investigation of this occurrence identified that a system

engineer had manipulated the danger-tagged components. The inspector reviewed

the licensee's procedural requirements for personnel authorized to operate ,

equipment and for protective tagging. In addition, the inspector reviewed the

protective tagging training provided to all plant personnel. It was found ,

that the system engineer did have the.authcrity to operate the valves; i

however, the individual was not fully tognizant of the protective tagging

requirements and limitations. The ins 0ector reviewed the licensee's  ;

corrective actions and concluded that the generic implications had not been J

appropriately considered. This was discussed with licensee management. 1

The licensee expanded its corrective actions review. The actions which were

subsequently implemented included specific training for all system engineers

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on Procedure ADM-0027, " Protective Tagging," requirements and revising the

General Employee Training study guides to emphasis protective tagging in the

instructor's course outline. The Plant Manager also directed plant staff l

management to include this issue in the next employee safety meetings.

2.3 Potential Failure of Limitorque Motor Pinion Gears

On September 1,1993, the inspector informed the licensee that a

safety-related motor-operated valve at Cooper Nuclear Station had failed to

operate because the key and set screw Lad become disengaged from the

limitorque motor pinion gear. This resulted in the inability of the motor to

operate the valve.

The Limitorque Corporation had issued Maintenance Update 83-1 in 1989, which

provided details on how to properly lock the pinion key and set screw when '

replacing pinions on Limitorque operators. This letter only addressed user

replacement of motor pinions because Limitorque had initially supplied the

operators with pinion keys and set screws locked in place. The inspector

reviewed the licensee's actions taken with regard to the maintenance update.  ;

letter. It was found that Corrective Maintenance Procedure CMP-1253, '

Revision 9, "Limitorque Motor Operator Valves," (dated 1989) identified the

recommended method for locking the pinion key and referenced the Limitorque

Maintenance Update 89-1 letter.  ;

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The inspector requested information on how the pinion gears were replaced at

River Bend Station before Update 89-1 was incorporated into the maintenance '

procedure. The licensee subsequently identified that the Maintenance

Update 89-1 letter had not been incorporated into the valve-specific

corrective maintenance procedures. It was determined that 24 maintenance. work  ;

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orders had been worked on valves which involved replacement of the motor, but

the work instructions did not include the maintenance update recommendations. j

The licensee initiated a review of the 24 maintenance work orders. It was

determined that 11 of the work activities were performed on Limitorque .

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Models SMB-00 and SMB-000, which were of such internal configuration that the

pinions could not become disengaged. The licensee demonstrated this to the  !

inspector using disassembled valves in the motor-operated valve training j

facility. The Model SMB-000 key slot did not go to the end of the motor. shaft '

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and, thus, the key was captive in a milled groove. The Model SMB-00 key could

slide out, but would be held captive by the manual operator bracket.

The remaining 13 work orders involved valves which were subject to the failure:

encountered at Cooper Nuclear Station. Eleven were safety-related and had l

motor. work done between 1987 and 1993. These valvesc had all- been recently and l

successfully stroked as a function of the licensee's inservice testing program j

and, because of their record of satisfactory performance, the licensee did not

consider them to be inoperable. The licensee subsequently informed the

inspector that it would remove the motor from Valve SFC*MOV120 and inspect the '

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pinion gear. Concurrently, the licensee was in the process of revising the

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valve-specific corrective maintenance procedures by incorporating the

information provided by Limitorque Maintenance Update 89-1.

This is an Unresolved Item (458/93026-3), pending the inspector's review of

the implementation of the vendor technical information program and potential

equipment operability concerns.

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2.4 Conclusions

The licensee's response to the main cooling tower blowdown radiation alarm was

not conservative and followup actions were not well coordinated. The

operators failed to appropriately consider the potential significance of ,

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allowing the main cooling tower blowdown to continue. The subsequent operator.

actions to assess the validity of the alarm were poorly coordinated and

untimely. Violations were identified for the failure to establish alarm  !

response procedures for the safety-related Radiation Monitor Panel RM-11

annunciators. j

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The MR which implemented design changes to the LRW system was only nearginally

adequate. The effect the design change had on interfacing systems was not

appropriately considered and the MR status was not effectively communicated to j

the operators and other essential plant personnel.

A potentially significant weakness was identified for plant personnel

operating nonsafety-related plant equipment without sufficient training. _The

licensee's initial review of the danger tag violations- appeared to be narrowly ,

focused on the individual's department involved.

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The licensee was not completely effective in implementing vendor

recommendations into the applicable procedures. The subsequent determination

of motor operated valves, which may have been effected, and the operability -

assessment were appropriate. Appreciable licensee actions remained to

independently verify the bases for the operability determinations and to i

correct any configuration deficiencies which may be identified,

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3 OPERATIONAL SAFETY VERIFICATION (71707) i

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The objectives of this inspection were to ensure that_ this facility was being

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operated safely and in conformance with regulatory requirements and to ensure  !

that the licensee's management controls were effectively-discharging the j

licensee's responsibilities for continued safe oper_ation.  ;

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3.1 Control Room Observations j

On-September 16 the inspector observed control room activities associated with

the performance of the reactor protection system (RPS) weekly surveillance.

During the conduct of the test, reactor power was slowly increased from 90 to

100 percent thermal power. Reactor power had been reduced to less than

90 percent after both reactor water cleanup (RWCU) pumps were removed from

service for corrective maintenance. This action was taken to reduce the rate

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at which impurities were collecting in the reactor vessel while the RWCU

system was out of service.

The tests were being performed to meet the APRM Technical Specification +

channel functional test and calibration requirements. When the power increase .

was initiated, the Instrumentation and Control technicians had completed four

of the eight channels in accordance with Procedures STP-505-5501 through .

STP-505-5508, "RPS/ Control Rod Block-APRM Weekly Channel Functional and Weekly -

Channel Calibration. The inspector noted that the simultaneous change in

power along with the conduct of the surveillance test both required extensive

involvement from the At-The-Controls (ATC) operator.

The inspector observed the following:

• Prior to increasing power, the ATC operator, control operating foreman,

and shift supervisor discussed the rate and method for increasing

reactor power, and' reviewed their decision with the reactor engineer.

• Communications were appropriately established between the technician

performing the surveillance test at the APRM cabinets and a technician ,

located inside the reactor controls area with the ATC operator.  ;

• When a step in the surveillance procedure was expected to cause a change i

in plant indication or annunciator alarms, or require verification, the

technician at the APRM cabinets informed the technician in the ATC area

who, in turn, informed the ATC operator. The ATC operator repeated back

the message to the technician in the ATC area, who informed the

technician at the cabinets that the operator understood the original

message. After the alarm or condition occurred, the ATC operator e

announced to the other control room operating personnel what the

condition or alarm was and that it was expected due to the surveillance

in progress.

• Prior to each increase in reactor power, the surveillance test was

halted at a convenient step.

The inspector observed that all face-to-face messages were repeated back to ,

the originator and, on two occasions, potential communication errors were ,

corrected by the use of this technique. The overall command and control

demonstrated by the operators was very good.

3.2 Plant Tours

3.2.1 Control of Nonpermanent Plant Equipment l

The insnector noted that portable eyewash stations located in each of the

safety-related battery rooms were not properly secured. Since the eyewash j '

stations were metal cylinders approximately 8 inches in diameter and-24 inches

high, the inspector questioned the seismic qualification of the battery  :

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installation with the eyewash stations unsecured. The inspector was informed

that a-formal evaluation had not been conducted to determine if an unreviewed- '

safety question existed. It was also identified that two separate seismic

walkdowns had been performed, but neither of the walkdowns had . identified a ,

seismic problem with the eyewash stations being unsecured in the battery '

rooms. It was noted that, had the eyewash stations fallen during a seismic

event, they would not-likely come in contact with the battery terminals. The

licensee did, however, remove the eyewash stations from the battery rooms to -

resolve any immediate seismic concern. During the exit meeting on

September 30, the licensee indicated that plans were to reinstall the eyewash

stations in a location where the seismic qualification of the batteries would

not be potentially degraded. -

The inspectors toured other safety-related areas of the plant and found that

other nonpermanent plant equipment, such as carts and lifting rigs, had been  ;

properly secured.  ;

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3.2.2 Plant Housekeeping

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During the conduct of plant tours, the inspectors noted that the general i

housekeeping conditions had continued to show some improvements. However, it .;

was noted that good housekeeping practices were not being consistently l

utilized. For example: .

• The structural channels between the control rod drive hydraulic control

units was littered with debris.  ;

• A few tools were left laying on top of safety-related Motor Control  !

Center IEHS*MCC2E with no apparent work underway.

• The 95-foot elevation floor in the main condenser bay (radiologically l

controlled area) was dirty.  ;

• The turbine building Unit Cooler 2 located on the 67-foot elevation had

water flowing over the collection pan and no deficiency tag had been  ;

initiated.  :

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• The RWCU pump room access control point'was cluttered with full

anticontamination clothing receptacles, tools, and polyethylene bags. l

The inspector reviewed each of these examples with licensee management. The

licensee removed the tools and initisted actions to improve the housAeeping

in the other areas.

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3.3 CRs with Indeterminate or Unknown Causes

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The inspectors requested information from the licensee as to how many CRs were

dispositioned with indeterminate or unknown causes. The inspectors reviewed

the 1993 S;cond Quarter Trend Report and the Second Quarter Executive Summary  ;

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.eport

R issued by the Independent Safety Engineering Group. These' reports l

indicated that there was a significant percentage of CRs with indeterminate or  ;

unknown causes. CRs in the maintenance and testing category were at

10 percent. Those related to equipment manufacture and installation were at

7.4 percent. Plant and system operations were 14 percent. Plant and system

design and analysis were at 14.3 percent.

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The inspectors reviewed the licensee's assessment of what appeared to be a

significant percentage of CRs with indeterminate or unknown cause

determinations. The licensee provided the inspectors with a draft copy of

Special Analysis93-005, " Root Cause Analysis." This report examined the root

cause analysis program at River Be'.d Station, including the overall program  ;

quality, personnel training, procedural adequacy, and other issues related to i

root cause analysis. It was found that the licensee had identified several

means of improving the root cause analysis program implementation. ,

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3.4 Conclusions ,

The control room operators exhibited good communications and positive control  ;

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of plant conditions during conduct of APRM surveillance testing concurrent

with power ascension. t

Plant housekeeping practices remained essentially unchanged. Personnel

housekeeping practices within areas which have been significantly enhanced was

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very good; however, these practices were not demonstrated in less frequented  !

areas, including work areas within radiologically contaminated zones. Tha

control of nonpermanent equipment within safety-related areas was detemined  ;

to be adequate

The licensee demonstrated a heightened sensitivity to indeterminate root cause ,

determinations.

4 REVIEW OF EMPLOYEE CONCERNS PROGRAM (T1 2500/028)

On August 26 the inspector completed a review to determine.the characteristics

of the licensee's ECP. This program is referred to as the " Quality Concern ,

Program" at River Bend Station. The review was conducted in accordance with l'

Temporary Instruction (TI) 2500/028, dated July 29, 1993. . Appendix C of this

inspection report contains questions specifically' presented by the TI. The i

inspector obtained the information requested as documented in the appendix.  !

The Quality Concern Program was implemented under the direction of the f

Manager, SA/QV, who reported to the Vice President, River Bend Nuclear Group. 1

The Manager, SA/QV delegated the day-to-day coordination of the program to a j

Senior Quality Assurance Engineer through the Director, Quality Assurance.

Coordination of the investigation and disposii. ion of quality concerns under -i

this program was accomplished by one individual, who utilized other quality

assurance engineers, as necessary, to keep up with the work load. . In cases

where concerns were raised involving quality a surance personnel or senior

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managers, the concerns were referred to a subcommittee of the Nuclear Review

Board to assure independence and eliminate any conflicts of interest.

The Quality Concern Program was defined and implemented by Quality Assurance .

Procedure QAP-1.14, Revision 4, " Quality Assurance Tracking of Quality

Concerns." The program was confidential and designed to encourage employees

to voice their concerns so that carly identification of deficiencies would ,

result in timely corrective action. The procedure delineated the methods used ~ ,

to identify, follow up, and document concerns expressed in the program.

The program as evaluated during this inspection' closely. resembled the program

that existed in 1985, when an NRC- inspection was performed as documented in .

NRC Inspection Report 50-458/85-25, dated April 25, 1985.

During the exit meeting of September 30 the Vice President, River Bend Nuclear '

Group, indicated that Gulf States Utilities was evaluating the current ECP for

the purpose of implementing any improvements that would be appropriate. ,

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5 MONTHLY MAINTENANCE OBSERVATIONS (62703) ]

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The station maintenance activities addressed below were observed and

documentation reviewed to ascertain that the activities were conducted in t

accordance with the licensee's approved maintenance programs, the Technical

Specifications, and NRC Regulations.  ;

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5.1 Troubleshootino of Control Rod 28-49

On September 11 the inspector began observing troubleshooting activities

associated with Control Rod 28-49, in accordance with Maintenance Work

Order (MWO) 171382. On September 8, while performing Surveillance Test

Procedure STP-052-0101, " Control Rod Movement Operability Check," the

operators noted that Rod 28-49, which had been inserted one notch _from

Position 48 to Position 46, would not respond to a command-to return to

Position 48 (fully withdrawn).

The operators considered the rod to'be inoperable but trippable, as provided

for in Technical Specification 3.1.3.1. Technical' Specification

Surveillance Requirement 4.1.3.1.2 had required the control rod to be inserted

one notch to prove the rod will insert. The surveillance test procedure ,

required the operator to return the control' rod to its pretest position. The

operators questioned engineering and licensing personnel as-to whether it was '

necessary to restore the control rod _to its pretest position to meet the

Technical Specification surveillance requirement to move at least one notch.

The licensee determined that the control rod was operable in accordance with

the Technical Specification requirement. The inspector found the decision to

be appropriate and in compliance with the license. However, inserting the  ;

control rod one notch each week to demonstrate control rod operability would '

create a rod pattern problem. Therefore, the licensee contacted General  :

Electric and initiated troubleshooting activities to determine the cause-for

the inability to withdraw the control rod.  ;

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Electric and initiated troubleshooting activities to determine the cause for

the inability to withdraw the control rod. '

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The MWO directed the operator to attempt to withdraw the control rod using  ;

normal control rod drive pressure and then determine from the stall flow and  ;

! hydraulic control unit valve manipulations whether it was the directional  ;

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control valves er the control rod drive mechanism seals that were leaking.

The inspector witnessed the troubleshooting and nated that no conclusion could' '

be reached.

On September 13, with General Electric assistance, the operators successfully  ;

withdrew the control rod to Position 48 after incrementally raising the '

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control rod drive pressure to 400 pounds per square inch (psi). This was

approximately 150 psi above the normal drive pressure. ,

On September 18 the inspector observed additional troubleshooting activities

to confirm the operability of the control rod and establish what corrective

action was necessary to enable the rod to withdraw normally.

The control rod was subsequently individually scrammed in accordance with  :

Surveillance Test Procedure STP-052-3701, " Control Rod Scram Testing," and it

met the acceptance criteria. Stall flows were then determined in accordance

with Plant Engineering Procedure PEP-0037, "CRD Performance Testing," and it ,

was confirmed that the problem was leakage past seals in the control rod drive

mechanism and not with any of the valves associated with the hydraulic control -

unit. The insert line of the control rod drive mechanism was then vented in  !

accordance with Station Operating Procedure 50P-0002, " Control Rod Drive

Hydraulics," and under the supervision of Reactor Engineering, the control rod .

was recovered to the fully withdrawn position using 350 psi drive pressure.  !

The entire troubleshooting evolution was preceded by a comprehensive briefing' ,

and conducted in a carefully controlled manner in accordance'with plant

l pr o dures. The licensee concluded that the control rod could be scrammed

normally and inserted normally. The only operational ' problem the control rod

caused was the necessity to increase drive water pressure to withdraw it after  ;

it is inserted for surveillance purposes. The inspector verified that

l- Procedure SOP-0071, " Rod Control and Information System," was revised to

j provide the necessary instructions for withdrawing the rod at elevated drive--

I pressures. This control rod has been scheduled for overhaul during the next

L refueling outage.

5.2 Plant Modification of Safe Shutdown Fuses

, On September 9, while performing the associated circuits, common enclosure  ;

! portion of the River Bend Station post-fire safe shutdown analysis, the

I licensee discovered that 4160 volt and 480 volt loads required for. safe j

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shutdown in the event of a control room fire may not be available. Fuses i

protecting the control circuits for these loads may not adequately protect the

associated cables. It was found that, in the event of a main control room ,

fire, these circuits could short in the main control room. Due to the length  !

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of the cable in these circuits, there'may be insufficient short circuit

current to blow the fuse before cable damage occurred. The' postulated 10

minutes to exit the control. room and operate the transfer switches to isolate ,

the main control room from the remote shutdown system was greater than the

estimated time in which cable damage would occur. The cables which would be -

damaged contain conductors which are required for. remote shutdown as well as

conductors that are isolated by the remote shutdown transfer switch. '

Approximately 25 circuits (46 fuses) were affected. ,

Technical Specification 3.3.7.4 required specific remote shutdown monitoring

instrumentation channels and controls to be operable. Because a number of the

shutdown system controls required to be operable may not have been'available

during a control room fire, Technical Specification Action 3.3.7.4.b required

the licensee to restore the inoperable controls to operable within 7 days or

place the plant in at least hot shutdown within the next 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br />. This

action statement was entered immediately.

By the time the licensee was able to issue a modification request to reduce '

the fuse ratings and obtain the new fuses, much of the Technical Specification

allowed outage time had been consumed. In anticipation of needing additional  !

time, on September 15, the licensee presented a request for Regional '

enforcement discretion to extend the allowed outage time an additional 7 days,

if needed. The request provided the necessary justification for avoiding the

plant transient of a shutdown and was presented in advance of the expiration

time of 9:30 a.m. on September 16, so that a decision to grant-the' enforcement

discretion could be made in a timely manner.

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On September 15, the inspector observed the implementation of MR 93-0060, as

delineated in MW0s R181786, R181787, R181788, R181791, and R181792. The fuse

replacement was well coordinated with the operators as each circuit was

removed from service, fuses replaced, and circuits retested. There was good

electrical maintenance department supervisory oversight to ensure the work '

activities were well supported. The electricians conducted prejob walkdowns

before starting the work to make sure there were no equipment label problems

or physical interferences. On their own initiative, the electricians checked i

the MWO against the modification request to verify correct fuse ratings.

Also, they performed continuity checks on each fuse. prior to installation.

The work and retesting was completed satisfactorily by 3:30 a.m..on '

September 16, and Technical Specification Action 3.~3.7.4.b was exited, without '

the need for enforcement discretion. On September 17, the licensee documented

a formal withdrawal of the request for enforcement discretion. The resolution

of the remote shutdown panel operability deficiencies is an Unresolved

item (9458/93026-4), pending the NRC staff's review of these issues.  ;

5.3 RCIC Pump Thrust Bearino Replacement

On September 22 the inspector observed portions of the replacement of the

thrust bearing on the RCIC pump. This work was authorized by MWO R179179.

The pump had exhibited excessive vibration during inservice testing.

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The inspector attended the prejob briefing conducted by the mechanical

maintenance foreman. The salient points of the job were adequately covered. L

Measurements were taken on the new bearing, journal, and bearing housing. It  ;

was determined that the new bearing would have to be heated.to facilitate its  ;

installation. While reviewing the work instructions, the inspector noted that '

the work instructions did not identify how, in what medium, and at what-

temperature to heat the new bearing. The inspector expressed concern about

the apparent incomplete work instructions. The mechanical maintenance foreman -  !

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indicated that he would ensure the instructions were provided.

The inspector observed the installation of the bearing nut. It was noted that

the technician had to modify a tool to install the nut. The technician

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utilized a socket wrench milled out to fit into the spanner wrench slots. The '

technical manual required the nut to be torqued to 200 foot-pounds. When the

technician attempted to torque the nut, the modified tool kept slipping off

the nut. After several attempts, the technicians were able to achieve the '

required torque. During the postmaintenance test run, high bearing oil

temperatures were noted. The vendor representative was contacted and reviewed

the work instructions. He noted that the 200 foot-pounds was excessive and .

that the technical manual was incorrect. He stated that the bearing nut only ,

needed to be " wrench tight."

The inspector observed the work activities associated with the second bearing

replacement using the " wrench tight" technique. It was noted that the work

instructions did not provide for the appropriate sequencing of work activities

to install the second bearing and that the maintenance personnel had not

obtained the appropriate tools prior to beginning the work activity. A

repairman had to leave the contaminated area in which the pump was located in

order to obtain the correct torque wrench, a special allen wrench made to

torque the bearing housing socket-head cap screws broke as a result of poor

pulling angles, and the 1/2-inch socket wrench broke under the 128 foot-pound '

torque applied.

The inspector subsequently discussed the inaccurate vendor manual requirement

with the licensee. The licensee stated that they intended to investigate why-

the pump technical manual had not been updated to delete the torque

requirement, especially after the vendor representative indicated that the

" wrench tight" requirement had been used for no less than 13 years.

CR 93-0567 and CR 93-0605 were initiated to review this concern. The results

of the investigation were that after consultation with the pump vendor .

(Sulzer-Bingham) and General Electric, the licensee found that no technical

manual revision had been made, and no technical bulletin had been issued. The

vendor's position was that the 200 foot-pound torque requirement was not

detrimental to the pump, but their current practice has been to tighten the  !

bearing lock nut " snug" or " wrench" tight. They stated that'no manual change 't

was required. General Electric, in a memorandum to the licensee dated  !

October 7,1993, stated that the vendor's current practice was acceptable.

The inspector reviewed the documentation of the disposition of this question,

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and found it to be satisfactory. The licensee revised their copy of the

. vendor technical manual, in accordance with their administrative controls, to  :

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reflect the vendor's current practice.

The licensee stated that a case study to determine the root causes of problems and (

delays encountered with the RCIC outage will be performed. Section 6.2 of this "

report addresses additional problems encountered during RCIC p'u mp testing. ,

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5.4 Ventilation System Preventive Maintenance Activities

During a plant tour _ on August 26, the inspector noted that several flexible

connections between- the ventilation fans and the interfacing ducts and plenums r

were beginning to look aged and, in some cases, had been patched. The inspector

questioned the licensee on whether the preventive maintenance program included

periodic inspection and testing of these connections, and also.the shield building  ;

penetration seals, which appeared to be of similar material. +

The licensee responded that for ventilation fans there was no specific preventive

maintenance task addressing the flexible connections but, in the case of critical i

systems such as standby gas treatment, the surveillance tests addressed. leak '

tightness. On September 17 the Supervisor, Process System-Mechanical Systems

Engineering directed that the existing preventive maintenance task for.all

ventilation fans be~ revised to include a step to inspect the flexible connections y

on the inlet and outlet of the fans for any holes, tears, or abnormal signs of

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wee The licensee did identify that the shield building flexible seals were-

inspected in accordance with Surveillance Test Procedure STP-000-3604,'" Fire

Barrier 18 Month Visual Inspection, Scaled Penetrations," Sections 6.2.1 and 6.2.4

on a 10 percent sampling basis,

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5.5 Conclusions ,

The control rod drive troubleshooting. and fire protection modification activities ~

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were effectively implemented. Excellent work coordination was noted between- . 3

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operations, engineering, and maintenance personnel. The work plans were.found to

be very good.

The work activity associated with the replacement of the RCIC pump thrust bearing ,

was poorly implemented. The vendor manual instructions were not correct and -

maintenance personnel were not appropriately prepared.

Appropriate surveillance activities were in place to detect degraded performance

on safety-related ventilation systems. The preventive maintenance program was

enhanced to inspect ventilation system flexible seals. Building penetration seals ,

were previously included in a preventive maintenance task.

6 BIMONTHLY SURVEILLANCE OBSERVATIONS (61726)

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The inspectors observed the surveillance testing of safety-related systems.and  ;

components addressed below to verify that the activities were being performed in >

accordance with the licensee's approved programs and the Technical Specifications. j

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6.1 Testing of Steam Pressure Control Systems

On September 2 the inspector witnessed portions of Test Procedure TP 93-0017,

Revision 0, " Pressure Regulator System Tuning and Dynamic Response

Verification." The purpose of this procedure was to determine the optimum

settings for the reactor pressure control loop by analysis of transients

' induced in the pressure control system by means of pressure regulator step

changes. Step changes of 1, 2, 3, 5, 7.5, ard 10 psi were applied to the

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pressure setpoint of each channel with the plant operating at 10 percent power

and while on the turbine bypasses, and at 15 to 20 percent, and 50 percent

power with the main turbine on line.

The inspector reviewed the procedure before the test and found it to be well

written and informative and to contain appropriate controls for safe operation ,

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of the plant during the test. An extensive prejob briefing was conducted.by-.

the shift supervisor for all the test the participants.

The test yielded excellent results. The systems exhibited _ good stability at

each pressure step change and at each power level. No adjustments had to be

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made. Full power was achieved by September 5 and the pressure control' system

continued to exhibit good stability characteristics. ,

6.2 RCIC Pump Inservice Testing

On September 17 the inspector observed the partial performance of the RCIC

pump quarterly operability and flow inservice test. The test was conducted in -

accordance with Surveillance Test Procedure STP-209-6310, Revision 0, "RCIC

Pump Quarterly Operability and Flow Test."

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The inspector accompanied two licensee personnel who had been assigned to

install the test instrumentation and perform the required local RCIC pump test i

measurements. The test personnel obtained the designated measuring and test

equipment (M&TE) from the hot tool room and proceeded to the RCIC room.~ The

inspector verified that the M&TE was in calibration. In the RCIC room, one

individual dressed out, entered the contaminated area, and attempted to

install the M&TE. The one individual was unable to complete installation of

the test instrumentation in accordance with the procedure and informed the

inspector that they were going to exit the RCIC area and obtain information_or

assistance on the proper installation. The inspector exited the RCA and

proceeded to the control room.

Later, the inspector observed the remainder of the test from the c6ntrol room.

Communications were established between the control room and the RCIC room

using radios. The RCIC pump was started and required test conditions

established. Upon starting the pump, the quality of radio communications

became poor. Control room operators experienced difficulty in obtaining the

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required test conditions for flow, discharge pressure, and -pump speed. Upon

attaining the proper conditions as indicated in the control room, the local .

test personnel informed the control room that local. test tachometer indication

was 3400 RPM. Control room indication showed greater than 4400 RPM. Shortly

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thereafter, the personnel in the RCIC room reported that the local test

equipment indicated increasing pump vibration. The shift supervisor ordered i

the pump to be tripped locally and the test was terminated. The shift 1

supervisor declared the RCIC pump inoperable and entered the appropriate  !

Technical Specification action statement. Additionally, orders were issued to

sample the lubricating oil. for the RCIC pump and turbine bearings, check the  :

pump / turbine coupling for misalignment, and check the calibration of the speed

indication in the control room and the test instrument.

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The inspector subsequently conducted a review of the M&TE and machine

interface problems, apparent procedural inadequacies, and personnel

performance issues. The following concerns were identified: <

• Procedure Change Notice 93-0801 was added to Procedure STP-209.-6310,

10 days prior to the attempted conduct of the test. The method and i

locations for installing the M&TE had been revised. The personnel

responsible for setting up the test equipment were not fully cognizant  ;

of the changes and had not received a comprehensive pretest briefing  ;

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• The licensee identified that the previous RCIC tests had been conducted

using headsets on the plant telephone system. This was apparently the

first time the use of radios had been attempted. Personnel stated that  ;

radios were used because a headset was not available in the RCIC room

contaminated zone. Communication difficulties resulted in  ;

misinformation being obtained in the control room. An example involved ,

control room personnel understanding that the RCIC turbine speed was

steady at 3400 RPM when personnel in the RCIC room had actually reported

a vibration frequency of 3400 hertz.

On September 23 after the RCIC pump outboard bearing was replaced, the i

inspector observed a repeat performance of Procedure STP-209-6310.

Preparations were coordinated better and communications were established H

between the control room and the RCIC room using headphones. The operators 'I

again experienced difficulty in obtaining the necessary inservice testing .

reference values for differential pressure and pump speed with an acceptable I

flow rate. With the improved communications, the conditions were met. l

However, after approximately I hour of run time, the outboard bearing oil l

temperature exceeded ti e alarm setpoint of 152.7 degrees and was approaching j

160 degrees. Again, the pump was tripped and the test terminated. i

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As discussed in Section 5.3 of this report, the licensee was in the process of :I

developing an investigation into the entire RCIr, outage, including test and l

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maintenance performance, delays encountered, and failure to have the latest

information in the pump technical manual. The inspectors will address the

outcome of these issues during the next inspection period.

6.3 Conclusions

Testing of the steam pressure control systems was conducted in an excellent ]

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manner. The procedure was well written ~ and informative, good " briefings were ;l

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Inservice testing of the RCIC. pump on September 17 was not well planned;_

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Delays and poor communications were experienced as a result. .The personnel l

involved in the RCIC testing were not familiar with the procedure change j

implement'ed the prior week. Additionally, it was doubtful that the -Lest could '

have been completed if the test had not been terminated for the-increasing 1

pump vibration unless the communications had been improved. .The licensee- j

implemented appropriate ' actions' to ensure the personnel performance problems ~

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were not repeated during the September 23 and-29 tests. j

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7 FOLLOWUP OF CORRECTIVE ACTIONS FOR VIOLATIONS. (92702) ]

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7.1 JClosed) Violation 458/92018-1: Containment Intearity Not Maintained -

During Fuel Movement ]l

The licensee had failed to maintain containment integrity during a period when I

fuel was being moved. The breach in containment integrity occurred because  :

work was being conducted that cut a service water system pipe-inside the 1

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containment while.the outside isolation valve was open. This condition ~was-

initially documented as Unresolved Item 50-458/9208-01 and was addressed as a 1

violation in NRC Inspection Report 50-458/92-18.- Additional information was- J

included in Licensee Event Report _458/92-008. In response to this' violation, j

the licensee committed to provide further guidance.and training to inv'olved 1

personnel and to develop a methodology for review of- outage l work. packages.- 3

The' inspectors verified that the licensee had implemented the above corrective ,

actions. Training had been conducted and.a Plant-Modification Installation  ;

Group had been designated to perform final design- reviews prior to j

implementing the design modification request. The inspector also reviewed:  :

Station Support Manual Procedure- ENG-3-006, . " River Bend Station Design and. ,

Modification Request Control Plan." . The inspector noted 'that Interim .

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Procedure Change 5 had been issued on May 19, 1992. Section'6.6.5, "Posti

Design Review and Adverse Impact Review," included:in the interim procedure

change required an evaluation of operability and constructibility questions.  ?

The inspector found the revised requirements to be acceptable. 3

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7.2 (Closed) Violation 458/92032-1: Failure to Follow a System Ooeratinq l

Procedure 1

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This violation involved the failure of an operator. to place both trains of the~  !

standby. gas treatment system in operation while performing a containment i

purge. j

To address this issue, the licensee revised Station Operating  !

Procedure SOP-0059, " Containment HVAC System," to include a. step'that requires  !

- that the operator verify that both trains of,the standby gas treatment system - .;

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-are operating prior to initiating'a containment purge. In addition, training;

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was provided to all licensed operators on this event to ensure that each' _

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individual fully understood the requirements for purging containment. 1

The inspector reviewed the actions taken by the licensee. The actions were

appropriate to. address this issue. i

7.3 (Closed) Violation 458/92032-2: Failure to Verify Offsite Power Supply

Operability ,

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While performing prestart checks for a diesel generator test, the licensee .

identified a problem with the starting air system. The problem was corrected,

but the work resulted in the diesel generator being in the maintenance mode

for greater than the allowable I hour. The plant Technical Specifications

required an offsite power supply verification within I hour, which was.not

completed. In response to the violation, the licensee committed to revise'the

procedures prior to their next implementation and to conduct training on this  ;

incident. ,

The inspector verified that the surveillance procedures with a frequency less

than every 18-months had been revised and that training was conducted. The

inspector also requested a list of the procedures that were scheduled to be

revised prior to the next refueling outage. The licensee performed a review ,

and compiled a list of the involved procedures. The licensee has entered

these procedures into the commitment tracking system. The inspector found ,

these actions to be appropriate  :

7.4 (Closed) Violation 458/92032-3: Failure to Control Safety-Related

Maintenance

following maintenance of the Division I emergency diesel generator, the engine

could not be turned using the pneumatic barring device. The licensee

discovered that a valve train had the adjusting screws installed further into

the rocker arm assembly than allowable for operation. The primary cause.of -

the misadjustment was a lack of specific guidance in the work instructions and

the vendor instruction manual. In response to this violation, the licensee

committed to include additional guidance obtained from the vendor in the

technical manual and in future work instructions. The licensee also committed

to train the involved personnel on proper valve train installation techniques.

During this inspection, the completion of the training was verified. The

inspector also verified that the vendor's additional instructions had been ,

received and were being processed by the licensee's vendor' technical ,

information program as VTI 93-021.

7.5 (Closed) Violation 458/92035-1: Failure to Control Site Access Training

A violation was issued because people had gained access to the facility even .

though their site access training was not current. The events and the

licensee's corrective actions were discussed in NRC Inspection ,

Report 50-458/92-35. By letter dated April 5,1993, the licensee presented a

detailed chronology of the events and the corrective actions that had been

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implemented. Included in the licensee's corrective actions was the revision

of Procedure TPP-7-018, " General Employee Training." 3

During this inspection, Revision 6 of Procedure TPP-7-018 was reviewed and

found to contain the provisions the licensee had committed to include. The .

inspector determined that the revised provisions should preclude a recurrence ,

of the problem. ,

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8 FOLLOWUP (92701)

8.1 Fire Protection Engineering Review i

On August 20, 1993, licensee personnel called the Region IV office to brief j

the NRC staff on the status of their engineering review of fire hazards

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associated electrical circuits. This review was prompted as a result of an

inspection (NRC Inspection Report 50-458/93-09) and commitments made in

connection with Enforcement Action (EA)93-091. During the conference call

the licensee described recent findings by their contractor that involved seven

120 Vdc associated circuit cables that had been found to be in common

enclosures with other cables relied upon to provide safe shutdown of the plant i

in the event of a fire in the control room. These 7 cables were included with  :

18 cables previously identified during the review as not being adequately

protected by fuses or breakers to prevent fault induced actions in safe

shutdown circuits in the event of a fire. J

The licensee proposed corrective actions for this and other issues that were

discussed, including their plans to establish a continuous fire watch in the i

control room to reduce the potential for fire by monitoring for ignition

sources and the accumulation of transient combustibles. On August 27, 1993,

the licensee informed the NRC Region IV staff that, due to a miscommunication,

the continuous fire watch had not been implemented as discussed during the

previous telephone communication. They elaborated further that, on'

reflection, a continuous fire watch would not be needed because the control

room cabinets were protected by fire detection and Halon, the control room was

continuously staffed, and that a heightened awareness of issue has resulted in

appropriate sensitivity to, and control of, transient combustibles.  ;

On September 7 the licensee met with the inspector and explained that ,

personnel involved in the response to CR 93-0464 had assumed that individuals l

involved in CR 93-0496 wre going to handle the implementation of the' '

continuous fire watch. t.icensee Procedure RBNP-030, Revision 2, " Initiation

and Processing of Condition Reports," required immediate notification of the -!

shift supervisor if there was a change to the disposition of a CR during its  ;

investigation and analysis, se that the shift supervisor could assess the

operability status of the equipment in question. The licensee issued Quality  ;

CR 0-93-09-07 to document the failure of Engineering to notify the shift  !

supervisor. Additional training was being considered for all engineers who

disposition CRs.

The licensee's failure to implement a verbal commitment appeared to be an

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isolated case, and the licensee's response wa3 adequate.  ;

(Closed) Inspection Followup Item 458/92022-2: Inconsistency Between

8.2

Procedures

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An apparent inconsistency between two facility procedures was identified

following the onsite portion of a previous inspection. During this  ;

inspection, Procedures PEP-0054, Revision 0, " River Bend Check Valve Program," -

and RBNP-030, Revision 2 " Initiation and Processing of Condition Reports," .:'

were compared.

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The inspector noted that Prt, .re RBNP-030 required a condition report to be-

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initiated "when a repair / rep.. cement of an ASME item-is required due to

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failure." The inspector also noted that Procedure PEP-0054 required a

condition report to be initiated "for a check valve experiencing an excessive -,

failure rate." An excessive failure rate was defined as more than one failure .i

in a 10-year period. These findings were consistent with the earlier finding. 1

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However, Procedure PEP-0054 furthur required a detailed root cause analysis

and a corrective action plan for any check valve that experienced excessive  !

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failures. These additional requirements in Procedure PEP-0054 resolved the  ;

concern of an inconsistency between the two procedures.

8.3 (Closed) Unresolved Item 458/93003-3: Restoration of Systems to Service t

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This item involved the apparent lack of guidance for restoring systems to

service when planned modifications have not been fully completed. In'the case '

reviewed, modifications were to be performed on the instrument air system;

however, the modifications were not completed, and the system was returned to

service without a formal evaluation being completed to verify that _the system t

could perform its design basis function. The inspector questioned whether

adequate formal guidance existed to identify the level and types of review

required to ensure that an operability determination was completed and left

the concern unresolved pending a subsequent inspection of the licensee's

practices for restoring equipment previously r_emoved from service.

During the followup inspection, the inspector noted that the requirements for-

restoring systems to service had existed under Administrative

Procedure ADM-022, " Conduct of Operations," but were vague for partially

completed plant modifications. The inspector determined that the licensee had

provided adequate guidance and a violation of its license had not occurred.

However, to address this overall issue, the licensee revised

Procedure ADM-0022, " Conduct of Operations," to specify the items that must be

completed, when only a portion of a modification is installed, prior to

declaring the system operable.

9 ONSITE REVIEW 0F LICENSEE EVENT REPORTS (LERs) (92700) )

9.1 (Closed) LER 458/89-011: Failure of Local Leak Rate Test

The licensee reported that two service water system penetrations had failed ,

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their local leak rate test. The licensee determined that the excessive

leakage was caused by corrosion product buildup that prevented tight closure I

of the isolation valves. A service water system heat exchanger wall thinning

problem was also discussed in the report. The licensee cleaned the isolation

valves and repaired the heat exchanger. The penetrations were retested with

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acceptable results.

During this inspection, the acceptable completion of the local leak rate tests -

were verified. An inspection of the local leak rate test program was

documented in NRC Inspection Report 50-458/92-27. In addition, the licensee .

recently modified the service water system to be a closed system that will be ,

less susceptible to corrosion product buildup and damage. The licensee's

actions were determined to be appropriate.

9.2 (Closed) LER 458/91-016: Failure of local Leak Rate Test

The licensee reported another failure of a service water system penetration

leak rate test on September 23, 1991. Tne failure was again determined to

have been caused by corrosion products in the valves. The licensee

established an increased surveillance frequency for Penetration 1KJB*52A until -

permanent corrective actions were completed. As stated above, the service

water system was modified to a closed system to limit corrosion problems.

9.3 (Closed) LER 458/92-014: Inadeauate Testing

During a review of NRC Information Notice 92-40, the licensee discovered a. ,

discrepancy. in the testing that was being performed on electrical circuits.

The normal power supply circuit breakers for the Divisions I and II, 4160 volt

standby electrical busses were not being tested to ensure that they would open

during sustained undervoltage conditions. When identified, the licensee ,

performed appropriate testing to ensure proper circuit' breaker operation. The

licensee also committed to revise the procedures to ensure proper testing in

the future.

During this inspection, Procedures STP-309-0601, " Division I 18 Month ECCS

Test," and STP-309-0602, " Division II 18 Month ECCS Test," were reviewed. The

inspector noted that the procedures had both undergone more than one

significant change. Included in the changes were provisions for appropriate

circuit breaker testing. The inspector found the file copies of the

procedures difficult to follow because the changes had not been incorporated

into a completed procedure. For example, it was necessary for the inspector

to review Revision 8 of Procedure STP-309-0601, dated October 25, 1990, in

conjunction with the 36 pages of the 241-page procedure that were changed in i

Revision 8A, the 7 pages changed in Revision 88, and the 118 pages-that were

changed in Change Notice 92-1095 dated September 17, 1992.

The inspector questioned the acceptability of implementing a procedure that

appeared to be fragmented and was informed that the copies of the procedure

that were issued for implementation purposes consisted of properly collated

pages rather than just attaching the changes to the procedure. The inspector

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was also informed of an action plan to update all of the facility procedures.

The licensee's goal was to have all of the station procedures updated by the i

end of 1994. The licensee's corrective actions were found to be appropriate.

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9.4 (Closed) LER 458/92-019: Planned Reactor Shutdown and Scram from

60 Percent Power

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This event report detailed a planned reactor scram from 60 percent power -

because of indicated problems with a reactor recirculation pump motor. The

indicated problems were winding leakage and increased thrust bearing

temperatures. This event was reviewed at the time of the occurrence, as .

documented in NRC Inspection Report 50-458/92-30. The report noted that all .

safety systems functioned as designed. l

The licensee investigated the cause of the abnormal conditions with the  !

recirculation pump. The investigation revealed that water, from leaking valve

packing, entered the instrumentation junction box, causing false indications.

The licensee repaired the leaking valve packing and sealed the junction box.

The plant was restarted without further problems. The inspector concluded

that the licensee had implemented the appropriate actions to address this ,

event.

9.5 (Closed) LER 458/92-026: Reactor Scram Due to Failures in the Steam -

Bypass Pressure Regulation System

This event was related to a reactor scram caused by a mismatch between. '

Regulators A and B in the electrohydraulic steam pressure control system.

These regulators change the position of the main turbine control valves to

control the load on the turbine generator. When Regulator A failed because of

a faulty amplifier card, the control function automatically switched to

Regulator B. Because there was a mismatch between the regulators, the turbine

control valves were repositioned from 35 to 23 percent open. The rapid

partial closure of the control valves resulted in a reactor scram. 4

The initial review of this event was documented in NRC Inspection

Report 50-458/92-34. As noted in that report, all safety systems functioned

as designed. The licensee replaced the failed components and evaluated the

preventative maintenance activities that were performed on the system. During

this inspection, the inspectors verified that the extensive testing and  ;

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calibration activities had been implemented to provide assurance that future

mismatches were avoided. These corrective actions were found to be

appropriate. l

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ATTACHMENT 1

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1 PERSONS CONTACTED

1.-1 Licensee Personnel

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• R. E. Barnes, Supervisor, ASME/ISI

J. B. Blakely, Assistant Piant Manager, System Engineering

B. R. Burke, Chemistry Supervisor l

• F. N. Carver, Director, Employee Relations '

• D. R. Clymer, Senior Human Performance Engineer

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• W. L. Curran, Cajun Site Representative ..

D. R. Derbonne, Assistant Plant Manager, Operations & Radwaste

L. L. Dietrich, Supervisor, Nuclear Licensing

R. G. Easlick, Radwaste Supervisor

• C. L. Fantacci, Radiological Engineering Supervisor ,

• J. J. Fisicaro, Manager, Safety Assessment & Quality Verification

• R. W. Frayer, Procurement Services & Materials

A. O. Fredieu, Supervisor, Maintenance Services

• P. E. Freehill, Assistant Plant Manager - Outage Management l

• K. D. Garner, Licensing Engineer

• K. J. Giadrosich, Director, Quality Assurance

• P. D. Graham, Vice President, Nuclear Integration

• J. R. Hamilton, Manager-Engineering

W. C. Hardy, Radiation Protection Supervisor

• H. B. Hutchens, Director, Nuclear Station Security i

R. T. Kelly, Instrument and Controls Supervisor

G. R. Kimmell, General Maintenance Supervisor

• J. W. Leavines, Supervisor, Nuclear Safety Assessment Group

• D. N. Lorfing, Supervisor, Nuclear Licensing ,

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R. C. Lundholm, Supervisor, Mechanical Process Systems

• I. M. Malik, Supervisor, Corrective Action & Reviews

• C. R. Maxson, Supervisor, Performance Assessment Group

• J. R. McGaha, Vice President, RBNG

J. F. Mead, Supervisor, Control Systems

W. H. Odell, Director, Radiological Programs

• S. R. Radebaugh, Assistant Plant Manager-Maintenance

C. R. Coats, Electrical Maintenance Supervisor

L. W. Rougeux, Senior ISEG Engineer

• J. P. Schippert, Manager, Nuclear Performance Analysis

• M. B. Sellman, Plant Manager

B. R. Smith, Mechanical Maintenance Supervisor

M. A. Stein, Director-Plant Engineering

K. E. Suhrke, Manager, Site Support ,

• R. P. Thurow, Assistant Plant Manager, Continuous Improvement

W. J. Trudell, . Assistant.0perations Supervisor

• J. E. Venable, Operations Supervisor ,

• Denotes personnel that attended the exit meeting. In addition to'th'e

personnel listed above, the inspectors contacted other personnel during this  ;

inspection period.

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2 EXIT MEETING

An exit meeting was conducted on September 30, 1993. During this meeting, the

inspectors reviewed the scope and findings of the report. A supplemental exit

was held on November 5,1993, to review Violation 458/93026-2 and Unresolved

Items 458/93026-3 and -4. The licensee acknowledged the inspection findings

documented in this report. The licensee did not identify as proprietary any '

information provided to, or reviewed by, the inspectors.

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APPENDIX C-

EMPLOYEE CONCERNS PROGRAM

PLANT NAME: River Bend DOCKET: 50-458

LICENSEE: Gulf States Utilities (GSU)

A. PROGRAM:

1. Does the licensee, have an employee concerns program? -

Yes, the licensee's Quality Concerns Program was

established in 1983.

2. Has NRC inspected the program? The quality assurance

program was assessed in 1985 and the results are

documented in NRC Inspection Report No. 50-458/85-25.

B. SCOPE:

1. Is it for:

a. Technical Yes

b. Administrative? Yes

c. Personnel issues? Yes

2. Does it cover safety as well as non-safety issues? Yes

3. Is it designed for:

a. Nuclear safety? Yes

b. Personal safety? Yes

c. Personnel issues - including union grievances? Yes,

although union grievances are usually referred

to the Union Steward. The license may handle some issues on

a case basis. An individual may utilize the quality

concerns program if unable to get a satisfactory response

from the Union Steward.

4. Does the program apply to all licensee employees? Yes

5. Contractors? Yes

6. Does the licensee require its contractors and their subs to have a

similar program? No, the GSU program applies to all personnel on

site.

7. Does the licensee conduct an exit interview upon terminating

employees asking if they have any safety concerns? Yes

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C. INDEPENDENCE:

1. What is the title of the person in charge?

Quality Concern Program Coordinator

2. Who do they report to? ,

The Director Quality Assurance

3. Are they independent of line management? No, the Director,

Quality Assurance reports to The Nanager, Safety

Assessment / Quality Verification (SA/QV), who then reports to

Vice President, River Bend Nuclear-Group

4. Does the ECP use third party consultants? Yes, especially for

10 CFR 50.7 concerns

5. How is a concern about a manager or vice president followed

up? The concern is referred to a subcommittee of the

Nuclear Review Board'(NRB). If a QA Employee has a concern,

or any employee has a concern about QA, the issue is

referred to the NRB subcommittee. Other management issues

are referred on a judgement call basis. -

D. RESOURCES:

1. What is the size of the staff devoted to this program? One

individual has been designated as the quality concerns

program coordinator. The QA and engineering staffs are

available as needed.

2. What are ECP staff qualifications (technical training,

interviewing training, investigator training, other)? The

staff has been trained in interview and investigator.

techniques in accordance with Procedure TQR-3001, " Quality

Concern Interviewer / Investigator."

E. REFERRALS:

1. Who has followup on concerns -(ECP staff, line management, other)?

Typically the NRB subcommittee or the QA staff will followup

on a concern.

F. CONFIDENTIALITY:

1. Are the reports confidential? Yes

2. Who is the identity of the alleger made known to (senior

management, ECP staff, line management, other)? The

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quality concerns program permites the concern to be known to ECP j

staff. The Director QA and the Manager SAQV also have access. i

3. Can employees be: }

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a. Anonymous? Yes q

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b. Report by phone? Yes, the Hat Line number is 504-381-4607.

G. FEEDBACK: h

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1. Is feedback given to the alleger upon completion of the

followup? _ Yes, the licensee provides for-each individual to - i

be informed of the followup results. If the item is i

non-technical and designated a " management" item, and 'is not  !

investigated by management choice, the individual is thanked

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for his concern but not told what was or was not done. The

individual does have a recourse, but most persons do not l

exercise it.

2. Does program reward good ideas? No ,j

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3. Who, or at'what level, makes the final decision of. 1

resolution? The Quality Concern Program  :

Coordinator reports the followup results to the Director QA and  ;

the Manager SA/QV.

4. Are the resolutions of anonymous concerns disseminated? No }

5. Are resolutions of valid concerns publicized-(newsletter, .

bulletin board, all hands meeting, other)? No- i

H. EFFECTIVENESS: _;

1. How does the licensee measure the effectiveness of the  ::

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program? On a monthly basis the Manager SA/QV receives.a

reading file of all new concerns.

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2. Are concerns:

a. Trended? Yes

b. Used? Not' unless the concerns have been identified in -l

tt.a corrective' action program. i

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'3. In the'last three' years how many concerns were. raised? 616 l

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Of the concerns raised, how may were closed? 577

What percentage were substantiated? 29% -

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4. How are followup techniques.used to measure effectiveness (random

survey, interviews,other)? Random surveys are conducted of each

department (usually 10 percent). These surveys are conducted in

accordance with Procedure QAP 1.14, " Quality Assurance Tracking of

Quality Concerns," Section 5.6.

5. How frequently are internal audits of the ECP conducted and '

by whom? The ECP is not subjected to QA audits; however,

< the NRB subcommittee performs periodic reviews of random

files in accordance with Procedure QAP 1.14, Section 1.3.

I. ADMINISTRATION / TRAINING:

1. Is ECP prescribed by a procedure? Procedure QAP 1.14.

2. How are employees, as well as contractors, made aware of this

program (training, newsletter, bulletin board, other).? Initial

site orientation, posters newsletters, and paycheck inserts.

ADDITIONAL COMMENTS: (Including characteristics which make the program

especially effective, if any.)

The quality concerns program is open to all employees. The

licensee has indicated they fully support an employees right to go

directly to the NRC, but encourages people to utilize the Quality

Concern Program first.

CONTACT:

NAME: TITLE: PHONE N0: DATE COMPLETED:

W. F. Smith Senior Resident Inspector 504-635-3193 August 26, 1993