ML20057C897

Insp Rept 50-458/93-23 on 930718-0821.Violations Noted. Major Areas Inspected:Plant Status,Onsite Response to Events,Operational Safety Verification,Hurricane Preparedness & Maint & Surveillance Observations

ML20057C897
Person / Time
Site:	River Bend
Issue date:	09/24/1993
From:	Gagliardo J NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION IV)
To:
Shared Package
ML20057C895	List: ML20057C893 ML20057C897
References
50-458-93-23, NUDOCS 9309300124
Download: ML20057C897 (24)

See also: IR 05000458/1993023

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APPENDIX

U.S. NUCLEAR REGULATORY COMMISSION

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REGION IV

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Inspection Report:

50-458/93-23

Operating License:

NPF-47

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Licensee: Gulf States Utilities

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P.O. Box 220

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St. Francisville, Louisiana 70775-0220

Facility Name:

River Bend Station

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Inspection At:

St. Francisville, Louisiana

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Inspection Conducted: July 18 through August 21, 1993

Inspectors:

W. F. Smith, Senior Resident Inspector

D. P. Loveless, Senior Resident Inspector, South Texas Project

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R. B. Vickrey, Reactor Inspector, Engineering Section, Division

of Reactor Safety

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Approved: L/Q.E.Uagliardo, Chief,ProjectSectionC

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Inspection Summary

Areas Inspected:

Routine, unannounced inspection of plant status, onsite

response to events, operational safety verification, hurricane preparedness,

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maintenance and surveillance observations, followup on corrective actions for

violations and deviations, followup of other issues, and review of licensee

event reports.

Results:

A noncited violation was identified for the licensee's failure to meet

Technical Specification surveillance frequency requirements.

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surveillance coordinator's httention to detail, questioning attitude,

and prompt identification of the problem was good. The licensee also

took appropriate corrective action to prevent a recurrence

(Section 2.1).

The licensee's actions to evaluata the consequences of the lightning

strike on August 4, 1993, were appropriate (Section 2.2).

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The licensee demonstrated good, comprehensive management overview and

corrective action in the reviews and evaluations that followed the

reactor scram caused by a personnel error on August 10, 1993 (Section 2.3).

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A concern was raised over the licensee's failure to determine the exact

cause(s) of the unexpected reactor core isolation cooling system steam

supply isolations during surveillance testing on August 13, 1993, and

previously on December 30, 1992. The licensee's plans to instrument the

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affected circuits and closely monitor testing during future surveillance

tests appeared appropriate in view of the circumstances (Section 2.4).

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A stop work directive and hold on startup was issued by the Vice

President - River Bend Nuclear Group because of a negative trend of

human performance errors that the licensee classified as "overall

unacceptable performance." The licensee's action reflected positively

on their resolve to improve human performance and reduce the error _ rate

(Section 3.3).

The licensee's procedural plans to cope with hurricanes appeared to be

lacking in detail, based on the lessons learned from Hurricane Andrew at

Turkey Point Nuclear Generating Station in 1992 (Section 4).

Maintenance observations by the inspectors indicated an improvement in

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the content and detail in work instructions observed in previous

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inspections (Section 5).

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During the observation of surveillance testing, the inspector noted

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that, while the equipment was tested as intended by the procedures, the

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performers demonstrated a willingness to work around minor procedure and

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hardware discrepancies rather than initiating action to resolve the

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problem (Section 6).

Summary of Inspection Findinas:

A noncited violation was identified (Section 2.1).

Deviation 458/90016-1 was closed (Section 7.1).

Violation 458/92026-2 was closed (Section 7.2).

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Violation 458/92026-3 was closed (Section 7.3).

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Violation 458/92034-1 was closed (Section 7.4).

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Violation 458/92034-2 was closed (Section 7.5).

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Violation 458/92034-3 was closed (Section 7.6).

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Inspection Followup Item 458/92010-1 was closed (Section 8.1).

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Licensee Event Report 458/90-032 was closed (Section 9.1).

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Licensee Event Report 458/90-041 was closed (Section 9.2).

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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 shut down and cooled

to ambient conditions for Forced Outage 93-02.

The purpose of the outage was

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to repair a leaking bonnet seal ring on Feedwater Isolation Valve FWS*MOV7B

(discussed in NRC Inspection Report 50-458/93-20) and to open and inspect the

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Suppression Pool Cooling Return Valve IE12*M0VF024A.

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On July 31, 1993, the licensee commenced a plant startup. On August 6, during

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the startup, the licensee experienced instability problems with the main

turbine electrohydraulic control system.

This problem delayed ascension to

full power operations. On August 10, while technicians were troubleshooting

the electrohydraulic control system, a reactor scram occurred.

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The plant remained in hot shutdown (Mode 3) from August 10 through the end of

this inspection period.

2 ONSITE RESPONSE TO EVENTS (93702)

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2.1 Hissed Surveillance Due to Schedulina Error

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On July 23, 1993, the licensee identified a surveillance testing schedule

anomaly where certain reactor water cleanup (RWCU) and reactor core isolation

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cooling (RCIC) system isolation time response tests were inappropriately

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staggered over a 3-year cycle, when they should have been tested at least once

every 18 months.

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Technical Specification 4.3.2.3 states, in part, "Each test shall include at

least one channel per trip system such that all channels are tested at least

once every N times 18 months, where N is the total number of redundant

channels in a specific isolation trip system."

RWCU and RCIC only had two isolation trip systems, A and B.

Each trip system

had only one channel and, because there were no other (redundant) channels

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within each of the trip systems, N should have been equal to one, and both of

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the isolation trip system channels should have been tested every 18 months.

As a result of the scheduler incorrectly assuming N was two, the Channel B

isolation trip systems for RWCU and RCIC had not been tested since October 12,

1990.

The plant was in Mode 4 at the time of the discovery, and the B isolation trip

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systems for RUCU and RCIC were satisfactorily tested prior to the plant

startup on July 31, 1993.

From April 1992 until July 1993, during the periods

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when the plant was in Modes 1, 2, or 3, the B isolation trip systems for RWCU

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and RCIC were inoperable because the surveillance requirement had not been

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met.

Consequently, the licensee operated the plant during these times in a

condition prohibited by Technical Specification 3.3.2.b, which required the

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inoperable trip systems to be in the tripped condition. This is a Technical

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Specification violation.

The licensee reviewed the surveillance test schedule to determine if there

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were any other inappropriately staggered tests and found none. The three test

procedures covering the B channels of the isolation systems for RWCU and RCIC

were entered into the proper 18-month scheduling frequency.

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The schedulers developed a new matrix that clearly identified which trip

systems had redundant channels- that could be staggered in accordance with

Technical Specifications similar to that of Technical Specification 4.3.2.3.

The licensee had already developed plans to place the new surveillance

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scheduling computer software on line by the end of 1993. This would automate

the staggered frequency test schedules. Until the new software is

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implemented, the licensee stated that they would have to schedule staggered

tests manually.

The licensee committed to revise the Surveillance Scheduling Guidelines to

provide more detailed guidance to schedulers. The revised guidance was to be

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published by December 1,1993.

The licensee informed the inspectors that this incident would be reported to

the NRC in accordance with 10 CFR 50.73.

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This violation will not be cited because the licensee's efforts in identifying

and correcting the violation met the criteria specified in paragraph VII.B.(2)

of Appendix C to 10 CFR Part 2 of the NRC's " Rules of Practice."

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2.2 Lightning Strike Caused Turbine Bypass Valves to Open

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On August 4, 1993, while the piant was operating at approximately 18 percent

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power, lightning struck the standby service water cooling tower, which is the

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ultimate heat sink for safe shutdown. Alarms occurred in the seismic

monitoring system, positive valve leakage control system, digital _ radiation

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monitoring systems, standby cooling tower level instrumentation, and sewage

treatment plant, but the alarms promptly cleared and were reset.

In control room Panel 1H13-P637, which contained control circuits for the

Turbine Bypass and_ Pressure Control System, Circuit Breaker No. I tripped

open, causing a loss of valve position feedback from the two turbine bypass

valves. Consequently, both bypass valves were opened by the bypass control

system reducing main generator output from approximately 180 megawatts to

80 megawatts.

Indicated reactor power increased by about 1 percent of full

power because of the transient. The operators manually positioned the valves

into the open position so that they could be closed at an appropriate time by

operator command.

The inspector followed up on the licensee's corrective actions and noted that

the licensee restored the turbine bypass and pressure control system,

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inspected all of the other control room panels for signs of damage or open

breakers and fuses, performed a control board verification in accordance with

Operations Section Procedure OSP-0017, Revision 3B, " Normal. Control Board

Lineups For Safety Related Systems," inspected the standby cooling tower

structure and grounding system, and performed surveillance _ tests on the

standby service water system fans and pumps. No problems were identified.

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The licensee's actions in response to the lightning strike were considered

appropriate.

2.3 Reactor Scram Resultino from Troubleshootina Error

On August 10, 1993, a reactor scram occurred because the main steam isolation

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valves (MSIVs) closed. At the time of the event, the plant was operating at

75 percent power, and the licensee was conducting troubleshooting and testing

activities on the main turbine steam bypass and pressure control system.

While performing a time response test of the system, an instrumentation and

control technician inadvertently shorted to ground the 22 volt DC power supply

in Control Room Panel H13-P637. The inspectors noted that the terminals were

closely spaced, and the technician performing the troubleshooting activities

had failed to take reasonable measures to cover and insulate adjacent

terminals. As a result, Power Supply Breaker CB-5 opened and deenergized

several components in the system. The main torbine control valves opened due

to failure of the flow demand signal, and the turbine bypass valves opened due

to loss of power to the bypass valve setpoint adjust card. This caused

reactor pressure to decrease below the setpoint for MSIV isolation (nominally

849 psig), and the MSIVs closed. An automatic reactor scram occurred with

MSIV closure, as designed.' The plant responded normally to the transient.

The inspector reviewed the licensee's post-scram evaluations and monitored

their actions. The licensee reviewed the following issues concerning the

plant responses to the transient-

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Design Engineering determined that the main turbine steam bypass and

pressure control system responded to the trip of Breaker CB-5 as

expected.

Turbine Control Valves 1 and 2 closed at a different speed than Turbine

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Control Valves 3 and 4.

Design Engineering determined this to be in

Tccordance with the design.

. Multiple reactor vessel Level 3 conditions occurred after the MSIVs

closed.

This raised operator concerns about the feedwater system

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operation during the transient. System Engineering determined that the

feedwater system responded as designed.

Increased radiation readings were noted on the off-gas system. System

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Engineering and Radiation Engineering determined that the off-gas

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pretreatment and post-treatment radiation monitors responded as

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designed. The high readings.were proportional to the reduced flow

through the system, which was considered normal.

Reactor Engineering determined that the leaking reactor fuel assembly

did not experience any further degradation as a result of this

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transient.

A safety evaluation of this event was performed by Nuclear Engineering

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and they determined that the key parameters important to plant safety

remained within safety limits.

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The inspectors reviewed Condition Report 93-0485, which was written to

document the scram and the subsequent evaluations and reviews as summarized

above. The inspectors found the evaluations to be supportive of the

licensee's conclusions.

The licensee established a "Significant Event Response Team" to review the

scram and develop an action plan to address the turbine control problems. The

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plant manager was the team manager and the team consisted of 15 members, one

of which was designated the team leader. The team's goals were:

Determine the root cause of the scram, contributing factors to the

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event, and corrective actions to prevent recurrence. This effort

included a broad overview of testing methodology and sequence of test

and calibration to resolve the turbine control and bypass valve

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oscillations and instabilities experienced during the recent startup.

Review maintenance activities associated with the bypass control and

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pressure regulator cabinet, including precautions required prior to

resuming these activities.

Review the plant response to the transient.

Determine required actions prior to plant restart.

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These goals were further subdivided into enabling objectives with individual

members assigned the responsibility for the goals and for maintaining a system

for tracking the status of the goals. The team addressed other items such as

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the capture of data, including the level swings, for incorporation into the

simulator. They also identified items required for startup.

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The inspector attended:two team status meetings.

The team leader discussed

the status and progress of each enabling objective with the responsible team

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members. The inspectors considered the team's approach to be well developed

and comprehensive.

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2.4 Inadvertent Engineered Safety Feature Actuation

On August 13, 1993, while performing Surveillance Test Procedure STP-207-4241,

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Revision 7, " Reactor Core Isolation Cooling (RCIC) System Isolation, RCIC'

Equipment Room Ambient Temperature High Monthly Channel Functional,18 Month

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Channel Calibration,18 Month LSFT (E31-N602B)," a Division II RCIC isolation

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occurred, closing RCIC steam supply Valves E51*MOVF063 and -076.

At the time,

the plant was in hot shutdown (Mode 3).

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The operators entered the appropriate Technical Specification action statement

and declared RCIC inoperable until the cause of the actuation could be

determined and corrected.

The licensee's investigation did not determine a cause.

The technicians

appeared to be performing the test in accordance with the procedure, and the

procedure was correct and had been used many times successfully since the last

revision in 1989. When they performed Step 7.1.13 of the procedure by using a

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digital volt-ohm meter (Fluke Model 45) to check for continuity across a set

of closed contacts, a small arc was observed, and the isolation occurred.

There should have been no voltage at the terminals. The test was repeated in

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the presence of the system engineer, but the condition could not be repeated.

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The system engineer performed an analysis of the event and concluded that

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although no cause could be determined, a momentary failure of the RCIC

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isolation bypass switch was considered the most likely cause. The switch was

replaced and the test was successfully completed again. ' The RCIC was then

restored to an operable status.

Examination of the removed switch did not

reveal any problems.

On December 30, 1992, a similar actuation occurred on Division I during

conduct of the prIC isolation test for the residual heat removal equipment

area high ambient temperature. The licensee investigated (Licensee Event

Report 92-029) a list of possible causes and found none. As corrective

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action, two similar switches and a relay were replaced.

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The inspector expressed concern that failure to determine the root cause of

these actuations may result in future actuations which would result in

unnecessary and undesired challenges to the system. The licensee agreed and

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informed the inspector that a plan was in place to instrument the suspected

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parts of the circuits during future testing to help identify the cause, if the

isolation occurs again.

The inspector considered the licensee's actions to be appropriate to the

circumstances.

2.5 Conclusions

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The licensee's surveillance coordinator demonstrated good attention to detail

and a questioning attitude in identifying the inappropriate staggering of the

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RWCU and RCIC isolation time response tests. Although the plant was operated

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in a condition prohibited by Technical Specifications, a violation was not

cited because of the prompt identification, documentation, and corrective

actions applied to the problem.

The licensee's response to the lightning strike on the standby cooling tower

was appropriate and sufficient to establish confidence that there were no

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other safety-related systems rendered inoperable.

The inspectors considered the licensee's approach to evaluating the scram of

August 10 to be appropriate and comprehensive. The formation and use of the

Significant Event Response Team was seen as a positive action by the licensee

to evaluate the event and improve future operations.

The inspectors concluded that the licensee's actions to determine the cause of.

the unexpected RCIC isolation that occurred during this inspection period and

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previously in December 1992 were less than fully effective. The licensee's

plans to instrument the circuits during future testing and to closely monitor

testing activities appeared appropriate to the circumstances.

3 OPERATIONAL SAFETY VERIFICATION (71707)

The objectives of this inspet. tion were to ensure that the facility was being

operated safely and in conformance with regulatory requirements and to ensure

that the licensee's management controls were effectively discharging their

responsibilities for continued safe operation.

3.1 Control Room Observations

The inspectors conducted routine observations of control room activity on a

daily, or more frequent, basis when on site. Control room formality appeared

to r nach a balanced level conducive to formal communication and

acknowledgement. The operators were alert and sensitive to plant condition

changes.

They formally acknowledged incoming and clearing annunciators and

repeated back specific instructions from the control operating foremen. When

questioned by the inspectors, the operators were responsive and knowledgeable.

The inspectors monitored portions of the plant startup that took place between

July 31 and August 9, 1993. The evolutions monitored were.well controlled and

distractions were all but eliminated so that the operators could concentrate

on the tasks at hand.

Procedural controls were good, and steps were signed

off appropriately.

There was a minct concern raised by the inspector which is

addressed in Section 6, " Surveillance Observations."

3.2 Plant Tours

The inspector conducted inspection tours of the accessible portions of the

plant and found the licensee's housekeeping practices to be continually

improving.

Specifically, the congestion of stored materials in the

radiologically controlled machine shop has shown a significant improvement.

The main turbine and bypass control electrohydraulic skids have been cleaned

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and painted and appeared nearly free of oil leaks.

The Division III emergency

diesel generator and the room in which it was housed was cleaned and painted

and reflected well on the performance of the painters.

It was particularly

noteworthy to find that the_ painters had been sensitive to not fouling moving

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parts, such as fuel rack linkage, with the paint.

On July 26, prior to startup, the inspector toured the drywell before its

final closure.

Licensee management was observed performing their inspection.

The inspectors noted a few scraps of metal and plastic sheeting, which were

removed. The inspectors also noted a general presence of metal chips, dirt,

and small pieces of trash on structural ledges and under the walkway gratings.

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The licensee explained that there were plans in place to clean all such areas

in the plant, as resources and the opportunity to minimize radiological

exposures permitted.

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3.3 Human Performance Stand Down

On August 14, 1993, the Vice President - River Bend Nuclear Group placed a

hold on startup from the forced outage and issued a stop work directive to the

Plant Manager for all activities in maintenance, operations, radiation

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protection, engineering, system engineering, chemistry, radwaste, and outage

management.

Those activities necessary for safe plant operation in accordance

with the plant license were to be allowed.

The inspectors were promptly informed of this action with the explanation that

licensee management was concerned that poor human performance issues continued

to manifest themselves in errors and overall unacceptable work performance.

The licensee's staff, and NRC, have been identifying procedural and

performance errors in recent months. The licensee had taken various

corrective actions, but reached a conclusion that there had been insufficient

improvement evident from these efforts.

There was also a "near miss" associated with corrective maintenance on the

suction relief valve for Main feedwater Pump C on August 4.

A clearance was

issued to isolate the relief valve after it lifted prematurely.

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clearance was improperly reviewed and approved for removal of the relief valve

for maintenance, and the reviewers failed to recognize that a vent path was

not established to keep the piping depressurized. The inappropriate clearance

was accepted by Maintenance and, had it not been for the alertness and

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attention to detail demonstrated by the radiation protection technician

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surveying the job site, the repairmen might have attempted to remove the

relief valve from piping which was pressurized to approximately 500 psig. A

near miss accident ' critique was held, which was attended by the inspectors,

and out of that investigation extensive corrective actions were taken.

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addition, on August 4, the Plant Manager issued a stop work order on

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protective tagging until certain corrective actions were taken.

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On August 19, the Vice President - River Bend Nuclear Group rescinded the stop

work directive after recovery plans and employee training were developed and

implemented.

Each affected department implemented a human performance

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improvement plan, and the Plant Manager implemented a human performance

observation program. Each day, 44 to 52 assorted field work activities were

observed by independent individuals selected by plant management. Attributes

observed and graded were:

(1) communications, (2) procedural adherence,

(3) self-checking, (4) work prcctices, (5) procedure adequacy, (6) questioning

attitude by the individual perfsming the task, and (7) attention to detail.

The licensee stated that the hold on startup would be lifted only upon

completion of error-free plant activities for 3 consecutive days. At 6 a.m.,

on August 25, the plant staff met that goal, and the hold was lifted. The

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Plant Manager assured the inspectors that the human performance improvement

and observation plans would continue indefinitely, at reduced intensity.

The inspectors found that during the week ending August 21 (after the recovery

plans were implemented) 29 procedure change notices were issued. This was a

marked increase from the 12 procedure change notices issued during the week

ending on August 7 and the 8 notices issued during the week ending August 14.

The step change in the issuance of procedure change notices indicated a marked

increase in attention to procedural detail by the plant staff.

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The inspectors considered the above actions taken by licensee management to be

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noteworthy.

3.4 Loose Parts Alarm

On July 8,1993, prior to the July 12 plant shutdown for Forced Outage 93-02,

a loose parts alarm occurred on Channel 3, which reflected a noise in the

reactor recirculation piping at Azimuth 180 degrees.

The audible sound was a

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metallic " clanking." Because the sound was audible only on Channel 3, the

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licensee could act triangulate with other channels to obtain the exact

location of the loose part.

The engineers concluded that the noise was outside the reactor vessel, and the

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loose part was constrained (not moving around the system). When recirculation

flow was reduced below 80 percent, the noise subsided.

During the outage, the licensee reviewed the work done on the recirculating

system and noted that the suction isolation valve for Recirculating Pump A had

its actuator replaced during the previous outage.

There was indication that

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the disc, which has a travel of 20 inches, could have been withdrawn another

3/4 inch beyond its fully open position. According to the vendor, this may

have subjected the disc to flow forces.

The licensee adjusted the valve to open 3/4 inch wider and installed two

additional temporary sensors in the loose parts monitoring system to

facilitate triangulation should the noise reappear during power operations.

The inspectors will monitor the licensee's handling of this issue to its

conclusion. The actions taken as of the end of this inspection period

appeared to be appropriate.

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3.5 Conclusions

Overall, control room operations appeared to be sufficiently formal and

confucive to careful and safe plant operation.

During plant tours, the inspectors noted continued improvement in housekeeping

and plant preservation.

The painting of Division III emergency diesel

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generator was particularly noteworthy because of the overall appearance of the

unit after being painted and the inspectors observed that the painters had

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taken care to assure that moving parts, such as linkage connections, had not

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been covered with paint and were free to operate.

The stop-work directive issued by the Vice President - River Bend Nuclear

Group was made in response to the "overall unacceptable work performance" at

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the plant, and indicated management's resolve to improve human performance at

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River Bend Station.

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Licensee actions taken to disposition the Channel 3 loose parts monitor alarm

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appeared appropriate to the circumstances.

4 HURRICANE PREPAREDNESS INSPECTION (92701)

The inspector reviewed the licensee's procedures and vulnerabilities

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pertaining to hurricane preparedness to ascertain their plans to assure safe

operation of the facility during the weather extremes associated with a

hurricane.

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4.1 Timing Plant Shutdown in Anticipation of a Hurricane

The inspector reviewed the plant license and the licensee's commitments with

regard to weather extremes, but found no guidance to plant staff that

addressed shutting down the plant in the event of a hurricane. The only

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operating procedure established that referred to hurricanes was Abnormal

Operating Procedure A0P-0029, " Severe Weather Operation." Procedure A0P-0029

contained a checklist of actions to take within 60, 48, 24, and 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> of a

hurricane, but it did not specify when, or if, the plant should be shut down.

When the inspector pointed this out to licensee representatives, they

explained'that shutting down was to be a coordinated management decision,

based on the projected threat to plant safety.

Because some fossil plants

must be shut down due to fuel cutoff, the utility was reluctant to shut down

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the nuclear plant unless plant safety was threatened.

4.2 Vulnerability of Radioactive Material to Hurricanes

The licensee did not have a formal contingency plan to prevent the spread of

radioactive material during a hurricane, except as required by

Procedure A0P-0029, which only directed the operators to make arrangements

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with all contractors to remove, tie down, or secure all of their outside

equipment.

No reference was made to securing or removing radioactive

materials. However, when the licensee implemented Procedure A0P-0029 as

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Hurricane Andrew approached in 1992, all containers of radioactive materials

were moved inside the radwaste building.

The inspector identified two possible vulnerabilities to the licensee that may

require special attention before or during a hurricane. The licensee had a

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double-wide trailer located at the north side of the plant, in the protected

area, which housed the waste segregation facility.

Even though radioactive

waste was not stored in the trailer, contaminated sorting and packaging

equipment was permanently installed and appeared vulnerable. The trailer was

not tied down, but had an extra heavy frame.

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The licensee also had a sheet metal (American) building on top of the hill

south of the plant containing barrels of low level radioactive waste,

miscellaneous radioactive components and tools, sand from a previous spill,

and sewage sludge.

The building was approximately 35 feet by 120 feet, with a

steel frame anchored to a concrete slab. The contents were surrounded by an

8-foot hurricane fence inside the building. This building was at a high point

and appeared vulnerable to high winds.

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Although the licensee was successful in protecting radioactive materials from

Hurricane Andrew in 1992, the inspector noted that a documented contingency

plan beyond the limited scope of Procedure A0P-0029 might be of benefit in the

event of a more severe hurricane in the future.

Licensee representatives

stated that, based on the effects Hurricane Andrew had on Turkey Point Nuclear

Generating Station, they may provide more direction in preparing for

hurricanes in the future, but probably not in time for the 1993 season. The

inspector confirmed that the licensee also had a copy of NRC Information

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Notice 93-53, "Effect of Hurricane Andrew on Turkey Point Nuclear Generating

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Station and Lessons Learned."

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4.3 Conclusions

The inspector. concluded that, while the licensee had a severe weather

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procedure, it did not provide instructions on implementing a plant shutdown in

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a timely manner, nor did it address contingency plans for the protection of

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radioactive materials.

In view of lessons learned from Hurricane Andrew in

1992, a more detailed procedure addressing these issues appeared to be

warranted.

5 MONTHLY MAINTENANCE OBSERVATIONS (62703)

The station maintenance activities addressed below were observed and

documentation was reviewed to ascertain that the activities were conducted in-

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

Specifications, and NRC Regulations.

5.1 Repair of Residual Heat Removal Test Return Valve IE12*MOVF024A

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On July 19-22, 1993, the inspector observed portions of the opening,

inspection, and signature testing of Valve 1E12*H0VF024A (24A). Valve 24A had

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failed to indicate fully closed on the main control console while the plant

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was at power (NRC Inspection Report 50-458/93-20, Section 2.1).

The position

indicating light provided dual indication, which translated to partially

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closed.

The licensee performed extensive troubleshooting, tests, and analyses-

to determine the operability of this valve. They also adjusted the stem

thrust and position indicating light switches.

In order to do this

effectively, the licensee requested that the NRC allow a 72-hour extension to

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the 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> allowed by Technical Specification 3.6.3.3.a to restore the valve

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to an operable status or to shut down and cool down the plant.

Enforcement

discretion was granted by the NRC on the evening before the allowed outage

time expired. The licensee completed their reviews and testing by July 6

(within the allowed outage time interval) and declared the valve operable.

On July 12, the plant was shut down to repair a feedwater isolation valve that

had a bonnet seal leak. Licensee management indicated a desire to open and

inspect Valve 24A during the forced outage, but the work was not compatible

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with feedwater isolation valve work because of shutdown cooling and emergency

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core cooling system valve lineup constraints.

Instead, the licensee made a

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conservative decision and extended the outage by 4 days and scheduled

Valve 24A for repairs after the feedwater isolation valve work and testing was

completed.

On July.19, the inspectors observed maintenance repairmen as they disassembled'

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the valve in accordance with Maintenance Work Order (MW0) R173891. The

repairmen found that the guide-rail clearances were on the lower end of the

acceptable band and had caused miner misalignment of the valve disc. The

repairmen machined the guide rails and increased the clearance.

The

maintenance crew was observed being properly briefed on both the work to be

!

accomplished and on the radiological hazards involved with breaching a

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contaminated system. The inspector reviewed the MWO for technical content,

clarity, and detail and found it to be well prepared. The inspector reviewed

the clearance established for the work and noted that it was appropriate.

5.2 Conclusions

The above maintenance activity was another example of a complex maintenance

observation (see NRC Inspection Report 50-458/93-20) where the inspectors

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noted a significant improvement in the adequacy and detail in work

instructions.

6 BIMONTHLY SURVEILLANCE OBSERVATIONS (61726)

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

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Specifications.

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6.1 Main Turbine Overspeed Protection System Test

On August 3,1993, during the plant startup from Forced Outage 93-02, the

inspector observed the performance of the main turbine overspeed protection

system surveillance test in accordance with Surveillance Test

Procedure STP-110-0101, Revision 6E, " Turbine Overspeed Protection System

Weekly Operability Test." This test was implemented during the startup

sequence delineated in Attachment 1 to General Operating Procedure GOP-0001,

Revision 6, " Plant Startup."

The test was performed in a deliberate, step-by-step manner, with good

communications between operators. At the time of the test, reactor power was

approximately 9 percent, with steam discharging to the main condenser via the

turbine bypass valves.

Prior to the test, General Operating Procedure G0P-0001, Attachment 1,

Step F.5.c directed the operators to perform Operations Section Procedure

OSP-0101, Revision 5, " Turbine Generator Periodic Testing," Sections 4.1.2,

4.2, 4.3, and 4.4 only. These were tests consisting of a backup overspeed

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trip test, mechanical overspeed test, mechanical trip piston test, and

electrical trip test. However, Section 4.2 of Procedure OSP-0101 required

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completion of all of Section 4.1 (consisting of Sections 4.1.1, 4.1.2, and

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4.1.3) as a prerequisite to completing Section 4.2.

This was done but, even

though the action was technically correct, it was not as directed by

Procedure GOP-0001. When the inspector questioned the operators, they

explained that the requirement to perform only Section 4.1.2 was a known

typographical error and that it would be corrected. By August 4, the error

was corrected by a procedure change notice in accordance with the licensee's

administrative requirements.

Subsequently, during the conduct of Procedure STP-110-0101, the inspector

noted that main turbine load set was at 20 megawatts.

Precautions and

Limitations Section 5.3 required that, prior to testing intercept valves, the

operators were to ensure the load set was greater than 1065 megawatts, to

minimize pressure transients as the valve stroked.

Procedure Section 7.5.1.3

also stated, " Ensure main turbine load set is at or greater than 1065." This

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step preceded the completed steps that stroked the intercept valves.

The

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inspector questioned why this step was not done and was signed off as "not

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applicable." The operators explained that the requirement.was not applicable,

because the main turbine was off-line. The operators had documented contact

with the system engineer to verify this. The licensee's administrative

controls did not clearly allow this practice; however, a liberal

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interpretation was taken and, since the operators' actions were technically

correct, the inspector deferred the question to operations management at a

later date.

Upon discussing the above issues with operations management, the managers

explained that the operators' actions were administratively and technically

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correct, but they also agreed that their expectations were for the operators

to request a procedure change so that during the next startup it would not be

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necessary for the operators to repeat the same decision process.

The

inspector expressed concern that working around procedure errors in the manner

they chose was not consistent with the licensee's expressed desire to foster

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an environment of procedure compliance.

Further, the inspector commented that

this did not set a good example for the operator trainees present for the

startup.

Procedure STP-110-0101 was subsequently changed to allow the load

set to be at the lower value when the main generator was not synchronized on

the grid.

6.2 Average Power Range Monitor (APRM) Weekly Surveillance Test

On August 6, 1993, the inspector witnessed the performance of Surveillance

Test Procedure STP-505-4502, Revision 9, "RPS/ Control Rod Block-APRM Weekly

Channel Functional, Weekly Channel Calibration, and 18 Month LSFT for Two Loop

Operation (C51*K605B)," for APRM Channel B.

The technicians obtained the proper authorization from the control room

operators and set up proper communications between the APRM panel and the main

control room reactor control console, Panel P680. The technicians appeared

very knowledgeable of the test procedure and the instrumentation. They

performed the test in a professional and efficient manner. Test jumpers were

installed and removed with proper verification in accordance with

administrative procedures.

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At one point in the procedure, an installed test power potentiometer appeared

to have a worn spot which caused erratic test results on the digital

multimeter.

The technician halted the test and called his foreman, who then

came to the control room and observed the phenomenon. They exercised the

potentiometer, and obtained satisfactory results, but documented the problem

and initiated MWO R15909 to replace the potentiometer later. This problem had

no effect on the operability of the APRM, and the actions taken were

appropr1-te.

After the test was satisfactorily completed, the inspectors reviewed the

completed data and found it to be complete, correct, and legible.

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During the restoration of the APRM to service, the inspectors noted another

example of weakness in the licensee's independent verification program.

Section 7.2.2 of Procedure STP-505-4502 required the technician to place the

Flow Card (Z118) Switch 51 in the " operate" position and independently verify

this action. When the second technician attempted to verify the switch was in

the " operate" position, he found a makeshift pointer (discussed below)

pointing closer to the " test" position than to the " operate" position. Upon

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questioning the performer (the first technician), the performer explained that

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the switch was in the correct position, just the pointer was wrong.

The

verifier then signed off the step.

The inspector questioned the verifier as

to what convinced him the switch was in the correct position.

His response

was that, in view of the performer's qualifications, he had sufficient

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confidence in the performer's word that the switch was positioned correctly.

The inspector concluded that this verifiotion lacked independence.

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Weaknesses in the licensee's independent verification program were addressed

in a Notice of Violation contained in NRC Inspection Report 50-458/93-20. The

licensee was in the process of developing the corrective actions and had not

completed these actions as of the end of this inspection period. The

correction of this issue will be incorporated into the licensee's overall

improvements in their independent verification program.

The inspector noted several test switches on the APRM cabinets that had the

plastic pointer knob broken off, leaving just the metal core. The position

indicator contained a black mark made by a felt-tipped pen or equivalent. The

technicians indicated that it had been difficult to procure replacement knobs.

The inspector expressed concern to licensee management that this appeared to

be another example of minor degraded equipment conditions being worked around

rather than properly corrected.

6.3 Conclusions

The above surveillances were performed well in terms of implementing the

procedures to confirm that the tested equipment would perform its intended

safety functions. However, the employees performing the tests demonstrated a

willingness to work around minor discrepancies instead of insisting on them

being corrected.

7 FOLLOWUP OF CORRECTIVE ACTIONS FOR VIOLATIONS AND DEVIATIONS (92702)

7.1

(Closed) Deviation 458/90016-1: Deviation from Commitment to Regulatory

Guide (RG) 1.97

During a previous inspection, the inspectors identified three conditions that

represented deviations from the licensee's commitment to RG 1.97.

The

licensee acknowledged the deviation by letters dated August 30 and October 11,

,

1990.

,

The conditions identified were:

The instrument displays on the control panels did not contain a specific

common designation, nor was it apparent that consistent operator

training was conducted on which instrumentation was intended for use

under accident conditions.

The hydrogen monitoring instrumentation was not being calibrated on the

higher scale of the two scale instruments.

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The ranges.of the installed suppression pool water level instruments

were different from those presented in the licensee's June 24, 1985,

compliance report which had been previously approved by the NRC.

During a previous inspection, the inspectors verified that specific labels had

been placed at the appropriate instrumentation on the control panels.

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Operators had received training on the use of post-accident monitoring

instrumentation, and the RG 1.97 instruments were properly identified.

The licensee requested (by letter dated March 28, 1991) exemptions from

compliance with the RG 1.97 requirements for the hydrogen monitoring high

scale and the suppression pool level. The NRC responded to this request by

letter dated December 16, 1992. The NRC response letter stated that the staff

had completed the renuested review and, based on their review of the

licensee's submittals, they found that the River Bend Station design for

drywell hydrogen concentration and suppression pool water level was acceptable

with respect to conformance to RG 1.97, Revision 3.

7.2 1 Closed) Violation 458/92026-2:

Failure to Provide Documented

Instructions to Govern Seat Replacement on Safetv-Related Check Valves

On July 29, 1992, the inspector observed a mechanic installing a new soft seat

ring on the disc assembly of a check valve in the main steam safety relief

valve instrument air system. Another inspector had previously observed the

performance of this step on several of the disc assemblies. The inspector

noted that this step was performed differently by different mechanics.

It

appeared that differing amounts of torque were applied to the soft seat ring.

The vendor stated that failure to adequately tighten the seat could cause

bypass leakage, and the stellite seat would impact the retaining washer

instead of the intended soft seat ring. The licensee's inspector that made

the previous observations had determined that Corrective Maintenance

Procedure CMP-9173, " Check Valve Rework," was too generic and did not provide

an adequate level of detail for soft seal ring replacements.

The licensee's current inspector reviewed Procedure CMP-9273, " Soft Seat Check

Valve Rework," written by the licensee as corrective action.

Section 8.2.3

and Attachment 2 of the procedure provided the workers with adequate guidance

to properly install the soft seat. The licensee had contacted the vendor and

had obtained additional instructions to the Vendor Manual VEL-SFVM-92.

The

licensee incorporated the instructions into the vendor manual, maintenance

work orders, and the 5-year equipment qualification preventive maintenance

tasks.

The licensee also performed a review of Engineering

Procedure ENG-3-006, " Design and Modification Request Control Plan." Based on

this review, the licensee determined that procedural controls were in place to

ensure that vendor documents associated with modifications were reviewed and

included in the document control system.

The inspector reviewed the above documentation and concluded that sufficient

corrective action was taken to prevent a recurrence of this violation.

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7.3

(Closed) Violation 458/92026-3:

Failure to Full Stroke Exercise Air

Accumulator Check Valves

This violation was cited because the licensee's leak rate testing did not

prove that the check valves opened and that the disc had traveled to the seat

promptly upon cessation or reversal of flow, as required by Section IWV-3522

(a) of ASME Code Section XI, as implemented by Technical Specification 4.0.5.

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The licensee's corrective action was to revise Surveillance Test

Procedure STP-202-3603, " ADS /SRV Accumulator / Check Valve Leak Rate Valve

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Operability Test." This revision (Change Notice 92-1059) was written to

ensure that the valve was appropriately cycled and then tested for leak

tightness. The inspector reviewed the change notice using Engineering

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Drawing PID-3-1B, " Main Steam," and found it to be acceptable.

7.4

(Closed) Violation 458/92034-1:

Failure to Place the Reactor Core

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Isolation Cooling (RCIC) System in Service Prior to Exceeding 150 psia

Reactor Pressure

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On November 25, 1992, the licensee had exceeded 150 psig reactor pressure with

the RCIC system out of service.

Technical Specification 3.7.3 states that the

RCIC system shall be operable with an operable flow path capable of

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automatically taking suction from the suppression pool and transferring the

water to the reactor pressure vessel upon exceeding 150 psig.

.

The licensee developed a case study of this event, which included a recreation

of the event on videotape and a review and discussion of the event by each

operating crew during licensed operator requalification training. This

training was performed in accordance with lesson Plan RE0-803-0, " Operator

Miscellaneous Training." The lessons learned from this and other recent

operator errors were also reviewed.

The inspector reviewed the licensee's response to the' violation and noted that

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the causes were properly identified. The licensee also added a caution step-

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to General Operating Procedure G0P-0001, " Plant Startup," to emphasize the

requirement to initiate the warming sequence of RCIC. Additionally,

appropriate disciplinary action was taken for the individuals involved. The

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inspector verified that Change Notice 93-0062 had been issued for

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Procedure GOP-0001 and that the caution statement was adequate.

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To avoid further violations, the licensee provided training to all licensed

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operators on the requirements for RCIC operability.

The inspector reviewed

Lesson Plan RE0-404-1, " Technical Specification Sections 3.0 and 4.0,"

and

determined that it provided for a study. of the RCIC event and additional

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Technical Specification requirements. Additionally, each crew received

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4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> of simulator time for reactor startup training, including meeting the

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Technical Specification and Procedure G0P-0001 requirements.

The inspector

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also found that Simulator Scenario Number STS-005-1, Revision 2, " Plant Heatup

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From 45 psig," implemented this commitment.

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7.5 (Closed) Violation 458/92034-2: Failure to Lock the Mode Switch in

Shutdown with the Nuclear Instruments not Properly Tested

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On December 7, with the plant in cold shutdown, the shift supervisor realized

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that the functional test surveillances for all channels of the intermediate

range and source range monitors were not current at the time the plant was

placed in hot shutdown. With these monitors being inoperable Technical Specifications 3.3.1 and 3.3.7.6 required the reactor mode switch to be locked

in the shutdown position and all insertable control rods to be verified

inserted into the core within I hour of the scram. While the reactor operator

did immediately verify that all rods had been inserted into the core after the

scram, as witnessed by the inspector, the mode switch, which was in the

shutdown position, was not locked until the shift supervisor noticed the error

the next day.

The licensee determined that the event was caused by the failure of the shift

supervisor to recognize that entry into the action statements was required

because the surveillance tests were not current.

As corrective action, operations personnel initiated change notices to General

Operating Procedures G0P-0002, " Power Decrease / Plant Shutdown," and G0P-0003,

" Scram Recovery." The inspectors reviewed these changes and determined that

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they adequately cautioned the operators to verify that the nuclear instruments

were operable during shutdown preparations.

The inspectors have been monitoring plant management's actions to address the

negative trend with operators not adhering to procedural requirements and not

complying with Technical Specification requirements.

Policy revisions and

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reinforcement of existing policies were evident.

Repeat-back communications,

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self-checking, and control room formality were evident in day-to-day control.

room operations. The inspectors have attended group and departmental meetings

in which management personnel have stressed policy adherence and the

challenges of changing poor practices.

The specific corrective actions addressed in the licensee's submittal of

February 8,1993, were completed and acceptable.

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7.6

(Closed) Violation 458/92034-3:

Failure to Establish Measures to

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Identify Degradation of Safety-Related Unit Coolers

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On December 2, 1992, during an NRC management tour, the inspectors noted a

buildup of foreign material on the discharge screen from Auxiliary Building

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Unit Cooler 1HVR*UC5. This unit cooler provided cooling air to the high

pressure core spray pump room. Approximately one-third of the discharge

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screen was blocked. At that time, the licensee had developed a list of five

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additional safety-related unit coolers which had internal filters. Although

the problem with preventive maintenance scheduling had been identified on

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December 3, no action was taken to assess the extent of the degradation on the

other unit coolers until after a plant shutdown on December 6.

The licensee

had continued to run the plant in Operational Condition 1 from December 3-6

without evaluating the operability of the other unit coolers with internal

filters.

,

The initial licensee response was to evaluate and clean Cooler 1HVR*UC5. This

was performed under Preventive Maintenance Task P562428. Additionally,

maintenance was performed on the five other unit coolers. The licensee

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determined that the preventive maintenance tasks were only scheduled on an as-

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needed basis. Most unit coolers had external filters and were observed on

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operator rounds. However, the six unit coolers in question had internal

filters which could only be seen when opened for inspection.

Following the

implementation of corrective action, the inspector reviewed the preventive

>

maintenance schedule for all six unit coolers and determined that the filters

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were scheduled for inspection every 13 weeks.

The inspector reviewed the licensee's response to this violation documented in

a letter dated February 8, 1993. The maintenance department performed an

evaluation of all safety-related preventive maintenance tasks with a frequency

designated for an as-needed basis. This review did not identify any other

preventive tasks which required changes.

An operability evaluation documented in Condition Report 92-0930 indicated

that, although degraded, all unit coolers would have performed their design

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basis functions, if needed.

8 FOLLOWUP (92701)

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8.1

(Closed) Inspection Followup Item 458/92010-1:

Review of Design Controls

Applied to Use-As-Is Condition Reports

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This item involved " repair" and "use-as-is" condition reports that could be

dispositioned by other than design engineering (such as system engineers and

maintenance engineers).

Procedure RBNP-30, Revision 0, " Initiation and

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Processing of Condition Reports," stated "All dispositions that are determined

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to be one-time deviations must be processed by the Maintenance Codes and

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Standards, RBS Engineering Departments under the direction of the Manager -

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River Bend Engineering or Plant Staff Systems Engineering Departments."

The

licensee's QA Organization indicated that this process was under evaluatton.

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The inspectors reviewed Procedure RBNP-30, Revision 2, which adequately

assigned responsibilities and described the system for initiating, processing,

distributing, dispositioning, trending, and controlling condition reports at

River Bend Station.

Other editorial changes throughout Procedure RBNP-030, Revision 2, were made

in relation to the dispositioning of."one-time-deviations and nonconformances"

to indicate that the appropriate responsible engineering departments were

responsible for providing these dispositions.

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Procedure TPP-7-031, Revision 0, "10 CFR 50.59 Reviewer Training Program,"

delineates the training provided for qualification as a 10 CFR 50.59 reviewer,

including the initial training and continuing training necessary to maintain

qualifications.

This procedure =oplied to all River Bend Station personnel

performing 10 CFR 50.59 review..

>

Based on the inspectors review of Procedure RBNP-030, Revision 2, and.the

licensee's required 10 CFR 50.59 training, the inspector concluded that the

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licensee had addressed the areas of concern related to design controls applied

to " repair" and/or "use-as-is" condition report dispositions.

9 ONSITE REVIEW OF LICENSEE EVENT REPORTS (LER)

(92700)

9.1

(Closed) LER 458/90-032:

Snubber removed from Piping in Violation of

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TS 3.7.4

,

The licensee reported that five snubbers, which had been removed from standby

service water piping, were required to be operable. One of these snubbers was

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removed for a period exceeding the action statement of Technical Specification 3.7.4.

,

The five snubbers were attached to piping that was supplied by the normal

service water system during routine operations. However, this event occurred

while the piping was being supplied by the standby service water system.

'

Standby service water was also required to be operable for the shutdown

cooling mode of the residual heat removal system.

For these reasons, tasks

requiring snubber removal were typically scheduled according to the time

interval that the corresponding division would be out of service.

A

scheduling error placed these snubbers on the work schedule during the

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Division II interval.

]

The licensee determined that four of the five snubbers were reinstalled and

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returned to operable status within the 72-hour period allowed in Technical

Specification 3.7.4.

The fifth snubber, located downstream of the Division

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III diesel service water piping, was removed for approximately 111 hours0.00128 days <br />0.0308 hours <br />1.835317e-4 weeks <br />4.22355e-5 months <br />.

During that time, the piping was not subjected to any of the dynamic events

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for which the subject. snubber is required. Consequently, the integrity of the

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piping was not compromised.

!

The licensee determined that this event was caused by three factors.

First, a

scheduling error placed these snubbers on the work schedule while Divisions I

and III were required to be operable. Second, the in-service inspection

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coordinator had limited knowledge of the system alignments.

Finally, the

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administrative control operating foreman did not adequately review the work

packages and, thus, did not realize that the snubbers were to be removed from

operable equipment.

The licensee's corrective actions included providing

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training on this event for Outage Management, Inservice Inspection, and

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Operations personnel.

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The inspector reviewed the licensee's records and verified that the corrective

actions had been completed.

The inspector found these actions to be

acceptable.

9.2 (Closed)'LER 458/90-041: Operability of Containment Isolation Valve

,

+

Indeterminate due to improperly Installed Toraue Switch

The licensee reported that, during diagnostic signature testing of the RWCU

supply line inboard containment isolation Valve 1G33*MOVF001, it was

determined that the valve was not developing the vendor calculated thrust

required to fully close under design basis conditions due to improper

installation of the torque switch. Therefore, the operability of the valve at

that time was indeterminate.

The incorrect installation of the torque switch

[

would cause it to trip prematurely, which would lead to the motor stopping as

soon as the close torque switch bypass opened at 95 percent of full stroke.

The licensee's' corrective action was to remove and reinstall the torque switch

in the proper position. The correct. (balanced) functioning of the torque

switch was then verified by diagnostic signature testing.

In accordance with

,

the guidance of Generic Letter 89-10, all safety-related motor-operated valves

shall receive periodic diagnostic signature testing after maintenance. Based

!

on a review of the licensee's motor operated valve program, the inspector

found that the licensee had appropriately implemented these requirements.

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ATTACHMENT

1 PERSONS CONTACTED

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1.1 Licensee Personnel

R. L. Biggs, Supervisor, Quality Control

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

J. E. Booker, Manager, Safety Assessment and Quality Verification

M. E. Crowell, Maintenance Support Supervisor

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

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L. L. Dietrich, Supervisor, Nuclear Licensing

R. G. Easlick, Radwaste Supervisor

A. O. Fredieu, Supervisor, Maintenance Services

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

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K. D. Garner, Licensing Engineer

K. J. Giadrosich, Director, Quality Assurance

P. D. Graham, Vice President (RBNG)

J. R. Hamilton, Manager-Engineering (RBNG)

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W. C. Hardy, Radiation Protection, Supervisor

R. T. Kelly, Instrument and Controls Supervisor

G. R. Kimmell, General Maintenance Supervisor

0. N. Lorfing, Supervisor, Nuclear Licensing

R. C. Lundholm, Supervisor, Mechanical Process Systems

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1. M. Malik, Supervisor, Quality Operations

C. R. Maxson, Supervisor, Performance Assessment

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

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J. P. Schippert, Plant Manager

B. R. Smith, Mechanical Maintenance Supervisor

M. A. Stein, Director-Plant Engineering

K. E. Suhrke, Manager, Site Support

R. P. Thurow, Director-Nuclear Training

W. J. Trudell, Assistant Operations Supervisor

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J. E. Venable, Operations Supervisor

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S. L. Woody, Director, Nuclear Station Security

1.2 Other Personnel

W. L. Curran, Site Representative, Cajun Electric

J. E. Gagliardo, Chief, Project Section C, NRC Region IV

R. S. Starkey, Technical Assistant, Entergy Operations, Inc.

Denotes personnel that attended the exit meeting.

In addition to the

personnel listed above, the inspectors contacted other personnel during

this inspection period.

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2 EXIT MEDING

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An exit meeting was conducted on August 27, 1993. During this meeting, the

pspectors reviewed the scope and findings of the report. The licensee did

rst identify as proprietary any information provided to, or reviewed by, the

inspectors.

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