ML20056C851

Insp Repts 50-528/93-12,50-529/93-12 & 50-530/93-12 on 930427-0531.Violations Noted.Major Areas Inspected:Review of Plant Activities,Emergency Operating Procedures,Surveillance Testing,Plant Maint,Snubber Testing & Core Reload Analysis

ML20056C851
Person / Time
Site:	Palo Verde
Issue date:	06/30/1993
From:	Wong H NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION V)
To:
Shared Package
ML20056C849	List: ML20056C848 ML20056C850 ML20056C851
References
50-528-93-12, 50-529-93-12, 50-530-93-12, NUDOCS 9307260029
Download: ML20056C851 (30)

See also: IR 05000528/1993012

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U. S. NUCLEAR REGULATORY COMMISSION

REGION V

Report Nos.

50-528/93-12, 50-529/93-12, and 50-530/93-12

Docket Nos.

50-528, 50-529, and 50-530

License Nos.

NPF-41, NPF-51, and NPF-74

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Licensee

Arizona Public Service Company

P. O. Box 53999, Station 9082

Phoenix, AZ 85072-3999

Facility Name Palo Verde Nuclear Generating Station

Units 1, 2, and 3

Inspection

Conducted

April 27 through May 31, 1993

Inspection

location

Wintersburg, AZ

Inspectors

J. Sloan,

Senior Resident Inspector

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H. Freeman,

Resident Inspector

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A. MacDougall, Resident inspector

F. Ringwald,

Resident Inspector

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B. Olson,

Project Inspector.

6// e/91

Approved By

Al N

Date Signed

Reactor Projects' Secti[o/

H.rWong, Chief

n II

Inspection Summary:

Areas Inspected: Routine, announced, onsite, regular and backshift inspection

by the resident and regional inspectors. Areas inspected included:

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review of plant activities

surveillance testing - Units 1, 2, and 3

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plant maintenance - Units 1, 2, and 3

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snubber testing - Units 1, 2, and 3

emergency diesel generator maintenance planning - Unit 3

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. reactor t' rip breaker post-maintenance testing - Unit 3

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charging pump testing - Units 1, 2, and 3

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essential battery seismic issues - Units 1 and 2

essential cooling water seismic issue - Units 1, 2, and 3

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shutdown cooling thermal overload bypass design error - Units 1, 2, and 3.

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core reload analysis - Units 1, 2, and 3

emergency operating procedures.- Units 1, 2, and 3

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containment isolation valve operability determination - Unit 3

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inspection of quality verification function - Units 1, 2, and 3

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Plant Review Board activities - Units 1, 2, and 3

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9307260029 9307o2:-=

$DR

ADOCK 05000529

PDR[

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accountability drill - Units 1, 2, and 3

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followup on previously identified items - Units 1, 2, and 3 -

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review of licensee event reports - Unit 3

During this inspection the following inspection procedures were utilized:

35702, 37700, 40500, 42001, 60710, 61726, 62703, 62705, 71707, 82301, 92700,

and 92701.

Safety Issues Management System (SIMS) Item:

None

Results:

General Conclusion:; and Specific Findings:

Sionificant Safety Matters:

None.

Strengths:

The Plant Review Board was aggressive, thorough, and focused on nuclear safety

in performance of its functions (Paragraphs 5 and 15). The licensee

identified some significant design and testing errors, and management response

-to the issues was sound (Paragraphs 2.d.(4), 8, and 10).

Maintenance /

personnel appropriately questioned guidance-provided in two work orders and

obtained guidance prior to continuing the performance of maintenance

activities on an emergency diesel generator in Unit 3 (Paragraph 6).

Observations of three QC inspectors demonstrated that the inspectors were

thorough and exhibited good technical knowledge (Paragraph 14.d).

Weaknesses:

Testing of snubbers was not performed as required by Technical Specifications

(Paragraph 5). One operability determination was not conservative or

consistent with generic NRC guidance, and another was not promptly confirmed

by continued troubleshooting (Paragraphs 13 and 17.b). On two occasions-

management expectations were not met when operators left the "at the controls

area" in the control room (Paragraph 2.d.(3)).

The inspectors noted'that work

planning involving an emergency diesel generator was not thorough

(Paragraph 6). An accountability drill did not actually demonstrate the

capability to perform personnel accountability within 30 minutes of the

initial notification of an event (Paragraph 16). Several personnel errors

resulted in the Unit I diverse auxiliary feedwater actuation system being

inoperable for nine days without operators being aware (Paragraph 4).

Corrective actions related to lifted leads were found to be ineffective

(Paragraph 14.c. (1) .

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• Summary of Violations and Deviations:

Of the 18 areas inspected. one cited violation.was identified regarding.

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snubber; testing.'(Paragraph 5), and one non-cited . violation was identified

regarding an operator not following procedures in response to a load reject

event (Paragraph 17).

Open Items:

Nine new followup items.were opened, six followup items were closed, and one

followup item was left open.

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DETAILS

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1.

Persons Contacted

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The below listed technical and supervisory personnel were among those

contacted:

Arizona Public Service Comoany (APS)

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R. Adney,

Plant Manager, Unit 3

J. Bailey,

Director, Site Technical Support

T. Bradish,

Manager, Nuclear Regulatory Affairs

R. Cherba,

Manager, Quality Systems

P. Coffin,

Engineer, Nuclear Regulatory Affairs

R. Flood,

Plant Manager, Unit 2

R. Fountain,

Supervisor, Quality Audits. and Monitoring

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R. Fullmer,

Manager, Quality Audits and Monitoring

D. Gouge,

Director, Plant Support

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W. Ide,

Plant Manager, Unit 1

J. Levine,

Vice President, Nuclear Production

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D. Mauldin,

Director, Site Maintenance and Modifications

R. Prabhakar, Manager, Independent Safety and Quality Engineering

T. Radtke,

Supervisor, Unit 3 Operations

C. Russo,

Manager, Quality Control

R. Schaller,

Assistant Plant Manager,_ Unit 1

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J. Scott,

Assistant Plant Manager, Unit 3

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R. Stevens,

Director, Nuclear Regulatory Affairs,

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M. Woloszyn,

Supervisor, Quality Audits Supervisor (Acting)

Others

J. Draper,

Site Representative, Southern California Edison

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R. Henry,

Site Representative, Salt River Project

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Denotes personnel in attendance at the Exit meeting held with .the

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NRC resident inspectors on June 1,1993.

2.

Review of Plant Activities - Units 1. 2. and 3 (71707)

a.

Unit 1

Unit 1 operated at essentially 100% power throughout this inspection

period with the exception of a reduction to 12% power on May 15,

1993, to repair a hydrogen leak from the main generator T4 neutral

bushing. The plant returned to 100% power- on May 20, 1993. On

April 29,1993, the plant had_ preliminary indications of reactor

coolant system (RCS) leakage greater than 10 gallons per minute.

Subsequent confirmation showed the leakage to be approximately 9.5

gallons per minute. A packing leak'was identified from the

pressurizer spray line bypass valve and was promptly: isolated. .The

RCS leak rate was then measured to be 0.15 gallons per minute. On

April 29,1993, at 2:21 a.m., an earthquake occurred with an

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epicenter approximately 30 miles south of the Grand Canyon which

measured 5.5 on the Richter scale. There was no indication of the

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earthquake from plant seismic monitoring equipment, and the licensee -

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did not observe any impact on the units during subsequent walkdowns.

b.

Unit 2

Unit 2 began the inspection period in the midst of a refueling

outage with the core off loaded. The unit entered Mode 6 and

commenced core reload on May 5,1993, and completed the reload on

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May 9.

The unit entered Mode 5 operations on May 20, 1993. The

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licensee continued to investigate the cause of the steam generator

tube rupture. At the end of the inspection period, the licensee had

completed 74 days of a projected 99 day outage.

c.

Unit 3

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Unit 3 operated the entire inspection period at 100% power. On

May 24, 1993, main turbine control valve number 4 began experiencing

position oscillations causing turbine and reactor power to lower

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approximately 1 to 1.5%.

Other oscillations were noted on May 28

and 30, and the licensee installed recorders to capture data for

further investigation. The licensee was formulating a

troubleshooting plan at the end of the inspection period.

d.

Plant Tour

The following plant areas at Units 1, 2, and 3 were toured by ~the

inspector during the inspection:

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Auxiliary Building

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Control Building

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Diesel Generator Building

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Fuel Building

Main Steam Support Structure

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Radwaste Building

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Technical Support Center

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Turbine Building

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Yard Area and Perimeter

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Containment Building

The following areas were observed during the tours:

(1) Operating Logs and Records - Records were reviewed against

Technical Specifications and administrative control procedure

requirements.

In Unit 1, the inspector noted an inconsistency between the

May 9,1993, unit log and the work order troubleshooting the

half-leg main steam isolation signal (MSIS) trip on May 9,

1993. The unit log stated that the fuse was found to have

oxidatica, while the work order stated that no oxidation was

present on the fuse. The system engineer concluded that

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oxidation was the cause of the half-leg MSIS trip, despite the.

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statement to the contrary in the work order. The inspector

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noted that a late entry was made to correct this log

discrepancy.

(2)

Monitorino Instrumentation - Process instruments were observed

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for correlation between channels and for conformance with

Technical Specifications requirements.

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(3)

Shift Staffina - Control room and shift staffing were observed

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for conformance with 10 CFR 50.54.(k), Technical

Specifications, and administrative procedures.

In addition,

operator (A0) performed a spot check of Unit 1 auxiliarystaffing over

the inspector

found that the commitment to staff at least four A0s per shift

was maintained.

The inspector observed two occasions in Unit 3 when for brief

periods of time (around 10 to 20 seconds) no operators were in

the "at the controls" area as defined in procedure 40AC-90P02,

" Conduct of Shift Operations." Although the requirements of

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10 CFR 50.54(k) were met, the expectations documented in the-

procedure were not met. The inspector noted that the operators

were in the control room in view of the panels, in the

" controls" area, also defined in procedure 40AC-90P02.

In one

case, the operator was standing at a desk just beyond the,"at

the controls" boundary, and in the other case the operator was

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standing at the Assistant Shift Supervisor's desk about 10 feet

from the "at the controls" boundary.

These occurrences

appeared to be caused by a lack of attention by the operators

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to assure that another operator was in the "at the controls"

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area prior to leaving that area. The inspector identified this

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matter to shift supervision who acknowledged the problem. The

inspector noted that 10 CFR 50.54(k) requires at least one

licensed operator to be "at the controls" at all times. The

licensee considered this requirement to be satisfied as long as

one operator was in the " controls" area. The inspector

concluded that this interpretation was consistent with

Regulatory Guide 1.114 and that the licensee met the

requirements of 10 CFR 50.54(k).

Licensee management issued a night order reemphasizing their

expectations and " Conduct of Shift Operations" training was

being revised to include a thorough review of this subject.

The inspector did not observe any further occurrences of this

problem and concluded that management's actions were

appropriate.

(4)

Eauipment Lineups - Various valves and electrical breakers were

verified to be in the position or condition required by

Technical Specifications and administrative procedures for the

applicable plant mode.

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The inspector noted a procedure change which resulted in Units

1 and 3 administratively relying on a boration flowpath which

included valves which had not been tested in accordance with

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ASME Section XI. The licensee identified and corrected the

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situation shortly after the change was implemented. An

alternate boration flowpath was available, although not

administrative 1y controlled; therefore, the safety significance

of this issue is considered to be low. Although the licensee

identified this deficiency, .the inspector was concerned that

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the normal procedure review process failed to identify the

problem prior to issuing the procedure change. The licensee

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acknowledged the inspector's comments.

(5)

Eouipment Taqqina - Selected equipment, for which tagging

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requests had been initiated, was observed to verify that tags

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were in place and the equipment was in the condition specified.

(6)

General Plant Eauipment Conditions - Plant equipment was

observed for indications of system leakage, improper

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lubrication, or other conditions that could prevent the systems

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from fulfilling their functional requirements.

During a plant walkdown in Unit 3, the inspector discovered

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that a ground wire was missing on valve SIB-HV-695, which is

the low pressure safety injection containment spray from the

shutdown cooling heat exchanger cross-tie valve. The licensee

concluded that the purpose of the wire was for personnel

protection and component operability was not affected. The

inspector concluded that the licensee's resolution of this

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problem was appropriate.

(7)

Fire Protection - Fire fighting equipment and controls were

observed for conformance with Technical Specifications and

administrative procedures._

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The inspector observed fire watch tours being performed in the

Unit I main steam support structure and Unit 2 auxiliary

building and found them to be consistent with licensee

procedures and management expectations.

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While touring the Unit 2 control building and auxiliary

building, the inspector noted several instances where fire

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extinguishers were left unsecured in an upright position,

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including one fire extinguisher that was left near the shutdown

cooling switchgear. An unsecured upright fire extinguisher

could be knocked over and become a missile hazard to both

personnel and equipment. While the licensee's safety manual

discussed the safe handling of compressed cylinders (oxygen,

nitrogen, etc.), it did not specifically address fire

extinguishers. The inspector discussed the issue with the

licensee's safety department. The licensee agreed with the

inspector's safety concerns and intends to incorporate fire

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extinguisher safety into the-safety manual and into -fire watch

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training. The inspector considered these actions to be

appropriate.

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(8)

Plant Chemistr_v - Chemical analysis results were reviewed 'for

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conformance with Technical Specifications and administrative

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control. procedures.

(9)

Security - Activities observed for conformance with regulatory

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requirements, implementation of the . site security plan,-and

administrative procedures included vehicle and personnel

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access, and protected and vital area integrity.

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(10) Plant Housekeeoing - Plant conditions and material / equipment

storage were observed to determine the general state of

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cleanliness and housekeeping.

(11) Radiation Protection Controls - Areas observed included control

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point operation, records of licensee's surveys within the

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radiological controlled areas, posting of radiation and high

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radiation areas, compliance with radiation exposure

permits, personnel monitoring devices being properly worn, and

personnel frisking practices.

(12) Shift Turnover - Shift turnovers and special evolution

briefings were observed for effectiveness and thoroughness.

No violations of NRC requirements or deviations were identified.

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3.

Surveillance Testina - Units 1, 2. and 3 (61726)

Selected surveillance tests required to be performed by the Technical

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Specifications were reviewed on a sampling basis to verify that:

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surveillance tests were correctly included on the facility schedule, 2) a

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technically adequate procedure existed for performance of the

surveillance tests, 3) the surveillance tests had been performed at the

frequency specified in the Technical Specifications, and 4) test results

satisfied acceptance criteria or were properly dispositioned.

Specifically, portions of the following surveillances were observed by

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the inspector during this inspection period:

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Unit 1

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Procedure

Descriotion

36ST-95B04

PPS Functional Test - RPS/ESFAS Logic

77ST-1SB12

CEAC Number 2 Functional Test

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Unit 2

Procedure

Description

73TI-9ZZ28

Eddy Current Testing of Tubing (Steam Generators)

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Procedure

Description

43ST-3AF03

Auxiliary Feedwater Pump. AFB-P01 Operability

Test 4.7.2.A & C

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36MT-95A01

BDP ESFAS Functional Test

74ST-9SQ11

Radiation Monitoring Monthly Functional Test Procedure

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No violations of NRC requirements or deviations were identified.

4.

Plant Maintenance - Units 1. 2. and 3 (60710. 62703 and 62705)

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During the inspection period, the inspector observed and reviewed

selected documentation associated with maintenance and problem -

investigation activities listed below to verify compliance with

regulatory requirements, compliance with administrative and maintenance

procedures, required quality assurance / quality control department

involvement, proper use of safety tags, proper equipment alignment and

use of ,inmpers, personnel qualifications, and proper retesting.

The

inspector verified that reportability for these activities was' correct.

Specifically, the inspector witnessed portions of the following

maintenance activities:

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Unit 1

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Electrical determination of the spray chemical addition system

The inspector observed an electrician using the ." suggested resolution"-

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section of Engineering Evaluation Request (EER) 91-XE-34 (rather than.the

" engineering guidance" section). The electrician also did not. accurately

follow use the " suggested resolution" during wiring termination work to

remove the spray chemical addition system. . The electrician used plastic .

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sheeting, sealed with intermittent pieces of tape, to protect

Westinghouse ARD relays below the work area from debris. The EER

" suggested resolution" section called for complete sealing of the top

edge with tape, while the " engineering guidance" section did not specify

how to cover the relays. The inspector concluded that the actual work

performed was in accordance with the " engineering guidance" section. The

licensee initiated Condition Report / Disposition Request (CRDR) 1-3-0281-

to address the electrician's use of the EER. During a future inspection ~

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the inspector will review the CRDR evaluation and the licensee's

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determination of which portion of the EER should be used (Followup Item

50-528/93-12-01).

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On May 20, 1993, the inspector observed test leads with clip-on probes

attached to bare conductors on Unit 1 "A" High Pressure Safety Injection

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(HPSI) flow transmitter, FIT-303. Work Order 562936 was still open and

showed that no work had been performed on this equipment' since May 1,

1993. The inspector noted that leaving test leads installed when work

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was not in progress was contrary to the guidance issued on September 17,

1992, by the Maintenance and Work Control Newsflash. This Newsflash on

" Energized Equipment troubleshooting Expectations" stated, " Connections

made with clip-on type' connectors shall only be made for active

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troubleshooting - they shall be removed when work is not actually in

progress." The Newsflash was interim guidance promulgated while the

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licensee completed work to fulfill a commitment made in CRDR_080133,

which tracked actions resulting from the incident investigation for the

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ALERT (loss of all annunciators) that occurred on May 4,1992. _ According

to the Director, Site Maintenance and Modifications, MDG 24 and 25 were

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issued as the procedures to formalize management expectations in this

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area. The inspector noted that these MDGs did not include the

expectation stated in the Newsflash regarding clip-on connectors. The

Director, Site Maintenance and Modifications, committed to incorporate

this expectation into MDG 24. The licensee promptly removed the clip-on

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test probes and restored FIT-303. The licensee stated that this was

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contrary to management expectations and counselled the technicians

involved. The inspector concluded that the licensee's corrective actions

were appropriate. The inspector will review the revision of MDG 24 to

assure that the pertinent guidance is incorporated (Followup Item

50-528/93-12-02).

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On May 5, 1993, the licensee discovered that four of the eight bypass

keys were left installed in the auxiliary relay cabinet following .

maintenance of the diverse auxiliary feedwater actuation system (DAFAS).

This resulted in the DAFAS being unavailable from April 26, 1993, to

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May 5, 1993. DAFAS is not required to be operable under Technical

Specifications; however, the system was installed to respond to

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anticipated-transient-without-scram events. The licensee investigated

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this event under Condition Report / Disposition Request (CRDR) 1-3-0256,

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which was not closed at the end of the inspection period. The inspector

will review the completed CRDR during a future inspection (Followup Item

50-528/93-12-03).

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Unit 2

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Tube pulls

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Core Reload

Reinstallation of reactor vessel accelerometers

The inspector observed a portion of the activities to reinstall

accelerometers'on two reactor vessel studs. The accelerometers are used

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to provide signals to the vibration and loose parts monitoring system.

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Prior to entering containment to perform the reinstallation, the

instrument and control (I&C) technicians and inspector were briefed by

radiation protection personnel on dose rates, protective clothing

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requirements, and ALARA considerations. Radiation protection required

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. personnel in the work area to wear dosimetry on the head and the back, in

addition to dosimetry worn on the chest and an alarming dosimeter worn on

the arm.

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The work primarily consisted of: 1) torquing a mounting bolt on the

appropriate reactor vessel stud to 100 ft-lbs, 2) torquing a mounting

screw on the mounting bolt to 25 in-lbs, 3) torquing the accelerometer on

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the mounting screw to 18 in-lbs, and 4) connecting the electrical cable

to the accelerometer and lockwiring the connections.

The inspector

observed that the I&C technicians carried a copy of the procedure. and

used tools with current calibrations. Tape had been used to clearly

identify the appropriate studs for the accelerometers, and the stud holes

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in the reactor vessel head were numbered.

The technicians encountered

. difficulty with the removal of one of the mounting screws because the

screw had rusted to the mounting bolt.

Initial attempts to remove the

screw were unsuccessful because the bits of different screwdrivers would

slip out of the screw slot due to incorrect sizing.

The technicians

determined that a new mounting screw would be required after obtaining a

proper sized screwdriver and removing the screw.

Prior to leaving

containment, the technicians installed and torqued the mounting bolts and

demonstrated that sufficient torque could be developed with the torque

screwdriver to reinstall the mounting screws. The technicians also

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described the remainder of the installation process and indicated that

lockwiring the connections was difficult, but could be performed

especially when surgical gloves were worn. The inspector spoke with

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other technicians in the I&C shop who indicated that the use of surgical

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gloves improved the ability to perform the lockwire installation. The

installation of the accelerometers was completed on May 21, 1993, after a

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new mounting screw had been obtained.

Unit 3

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Emergency Diesel Generator "B" outage

calibrate jacket water high temperature switch

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replace shuttle valves

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replace governor oil

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test time delay relay on output breaker.

HPSI "B" motor lead splice.

GE reactor trip breaker maintenance.

No violations of NRC requirements or deviations were identified.

5.

Snubber Testing - Units 1. 2. and 3 (40500, 61726. and 92701)

The inspector continued an inspection of snubber testing, previously

documented in NRC Inspection Report 50-529/93-11, and found several

deficiencies.

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The licensee's snubber testing program was defined in procedure 73AC-

9ZZ01, " Testing and Control of PVNGS Snubbers." After discussions with

Region V and NRR personnel, the inspector concluded that the licensee did

not meet the specific requirements of Technical Specification 4.7.9.

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However, the NRC staff determined that the licensee's program was

acceptable based on current testing standards and that the testing

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conducted during previous outages was acceptable.

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In letters to the Region V Regional Administrator, dated June 22, 1987,

August 31, 1987, and January 12, 1989, the licensee selected sample plan

No. 2 per Technical Specification 4.7.9 for Units 1,- 2, and 3,

respectively.

Sample plan 2 requires that "a representative sample of

each type of snubber shall be functionally tested in accordance with

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Figure 4.7-1."

Figure 4.7-1 plots the total number of snubbers of a type

found not meeting acceptance requirements verses the cumulative number of

snubbers of a type tested at the end of the day's testing.. The. figure is

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divided into three regions: Reject, Continue Testing, and Accept.

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plotted point falls into the " Reject" region, all snubbers of that type

are required to be functionally tested.

If the plotted point falls into

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the " Accept" region, functionally testing of that type of snubber may be

terminated. When the plotted point falls into the " Continue Testing"

region, additional snubbers of that type are required to be tested until

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the plotted point falls into the " Accept" or " Reject" regions or all

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snubbers of that type are functionally tested. With no failures,_the

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minimum number of snubber of a type that must be tested is 37. .

Technical Specification 4.7.9 defines the " type of snubber" to mean

snubbers of the same design and manufacturer, irrespective of capacity.

Licensee procedure 73AC-9ZZ01 further clarified this definition and

grouped the snubbers into five groups: 1) steam generator hydraulic

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snubbers, 2) reactor coolant pump hydraulic snubbers, 3) PSA-1/4 and PSA-

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1/2 "small" size snubbers, 4) PSA-1, PSA-3, and PSA-10 " medium" size

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snubbers, and 5) PSA-35 and PSA-100 "large" size snubbers._ With these

definitions, Technical Specification sample plan 2 requires that a

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minimum of 37 snubbers of each of the five types be tested or 100% of the

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snubbers if there are less than 37 snubbers of that type. Technical Specification 4.7.9 further requires "that the representative sample

selected for the functional test sample plans shall be randomly selected

from the snubbers of each type...."

As implemented, the licensee's testing program treated all mechanical

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snubbers (PSA) as one type and then selected a sample of 37.

Additionally, the program essentially used sample plan.1 (functionally

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test 10%) for testing the hydraulic snubbers by selecting one steam

generator snubber, and one reactor coolant pump snubber. The snubbers

were selected by a computer program from a data base containing a list of

snubbers. For the mechanical snubbers, the program selected a number of

small, medium, and large size snubbers proportional to the actual number

of snubbers of each size. Additionally, the program selected snubbers

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from different locations / systems based upon an algorithm. While the

snubber data base originally contained all the snubbers in the unit, each

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snubber was removed from the data base after it had been tested.

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According tu the licensee, this would ensure that each snubber would be

tested at some point,

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The inspector met with licensee management on April 20, 1993, and

discussed the program. The inspector questioned the licensee's method of

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snubber sample selection and the program's overall compliance with

Technical Specification 4.7.9 samole plan 2 requirements. The licensee

told the inspector that they had reviewed the questions of type and

sample size previously and believed that the program did' meet the

requirements of the Technical Specification. The licensee initiated CRDR-

9-3-0367 on April 30, 1993, to review procedure 73AC-9ZZ01 for compliance

with Technical Specification 4.7.9.

The inspector observed a special Plant Review Board (PRB) convened on

May 10, 1993. The PRB met to discuss the implications of not having

performed surveillance testing on snubbers in accordance with Technical

Specification 4.7.9.

The PRB critically addressed safety concerns

regarding snubber testing that was required by the Technical

Speci fications. The PRB members reviewed the functional testing that was

performed during the previous outages in all three units to determine the

technical significance of not performing the testing in accordance with

'

the Technical Specifications.

The PRB determined that the testing that.-

was performed was equivalent to the testing required by the Technical

Specifications and did not represent a safety concern. The inspector

concluded that the special PRB met the requirements of Technical Specification 6.5.1 related to PRB responsibilities, and that the PRB was

!

thorough and effective in addressing this matter.

-

Upon further evaluation, the NRC concluded on May 6, 1993, that the

licensee did not meet the requirements of Technical Specification

~

Surveillance Requirement 4.7.9.e sample plan 2 and had not met these-

requirements during any of the previous testing periods. Speci fically,

the licensee had not randomly selected the representative sample and had

.

not tested the minimum number of snubbers of each type as required by

l

sample p_lan 2 (Violation 50-528/93-12-04).

In addition to not meeting the surveillance requirement, Technical

t

Specification 4.0.3 stated that failure to perform a surveillance

requirement within the prescribed interval constituted noncompliance with

the operability requirements for the Limiting Condition for Operation

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(LCO). This would require all snubbers in all three units to be declared

,

inoperable and the appropriate action statement be taken. The LCO for

Technical Specification 3.7.9 stated that, if one or more snubbers were

--

inoperable on a system, the inoperable snubber (s) be replaced or repaired

within 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> or the associated system be declared inoperable and the

ACTION specified for that system be followed. This would have led to-the

shut down of 'Jnits 1 and 3 which were operating at the time.

In a letter to the NRC dated May 14, 1993, the licensee described that

,

the snubber testing that had been performed, for the most part, met the

-

requirements intended by the NRC when it issued generic guidance for

snubber testing and that other nonconformances were minor deviations.

The licensee additionally requested enforcement discretion for Units 1

and 3 to prevent unnecessary shutdowns and for Unit 2 to allow mode

changes (Mode 6 to Mode 5) until emergency Technical Specification

,

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changes could be processed. The NRC determined that the course of action

taken involved minimal or 'o safety impact and that the exercise of

,

enforcement discretion was warranted when considering the public health

4

and safety. Therefore, on May 14, 1993, the NRC exercised discretion not

to enforce compliance with the ACTION statement of Technical Specification 3.7.9.

,

The licensee continued to examine the snubber failures. The small size

snubbers generally have failed due to bent shafts. The licensee believes

that some of the small size snubber failures were due to a water hammer

'

event. Other snubbers failures were due to-insufficient or degraded

lubrication, corrosion products, installation problems or excessive force

.

applied. The licensee did not find a root cause of failure which would

l

raise an operability concern for the snubbers in Units 1 and 3.

One violation of NRC requirements was identified.

6.

Emergency Diesel Generator (EDG) Maintenance Planning - Unit 3 (62703)

The inspector observed portions of a scheduled maintenance outage on the

"B" EDG which started on May 4, 1993. The inspector noted a mechanic

investigating leakage from the attached fuel oil booster pump identified

i

in work arder (WO) 846422. The inspector noted that the WO called for

.

replacing fittings on the pump that were recently replaced and did not

appear to be leaking. The craft did not believe that the WO specified

the correct location of the leak and notified the shop foreman.

The work

was deferred and the leak was subsequently found to be from the pump

packing during the post-maintenance run. Although craft personnel

appropriately questioned the work order and obtained guidance before

-

continuing, the inspectors were concerned that the work planning for this

'

activity was deficient in that the planner did not adequately evaluate

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the scope of the work to ensure the WO was for the leaking component.

,

!

The inspector also observed replacing the oil in the overspeed governor,

in accordance with WO 043764. The inspector noted that the WO included a

description of one component needing oil (UG-08); however, a description

of the other component was not available. The mechanics were unclear

what the other component was and had to refer to the vendor technical

manual (VTM) in the shop for clarification. After looking at the VTM,

!

'

they were able to identify the other component and completed the oil

i

replacement. Again, this showed appropriate consideration by the craft

to obtain clarification prior to continuing work; however, the work

planning was deficient in that the WO did not contain sufficient

information to allow the work to be performed.

The inspector also observed the post-maintenance run of the EDG and noted

good support in the field from the shop foremen,

2

The inspector concluded that the mechanics acted properly in stopping

work to resolve their questions, and that the shop foreman provided good

support. The inspector further concluded that work planning was not

thorough for these activities.

11

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No violations of NRC requirements or deviations were identified.

7.

Reactor Trio Breaker (RTB) post-Maintenance Testina - Unit 3 (62703)

During post-maintenance testing of RTB 3JSBAC03, operators misunderstood

'

a note posted by the breaker that described the proper position of the

undervoltage (UV) coil. The note said " verify proper UV position.after

i

each breaker close operation." The reactor operator and auxiliary

operator noted that after the breaker was tripped manually the UV coil

i

was not reset. The operators did not recognize that this was not the

correct position of the coil. The operators used pictures near the

,

breaker which showed both the proper and improper position. However, the

operators incorrectly reasoned that since the note said to verify the

proper UV coil position after each closing operation, and since they had

,

just opened the breaker, the proper position for the UV coil. should be

the opposite as shown in the pictures. Therefore, the control room

believed the UV coil was properly reset and suosequently attempted to

close the breaker, which immediately tripped because the UV coil was not

reset.

i

The inspector concluded that there was an appropriate level of management

attention during the testing; however, the inspector also noted there was

still confusion in the field concerning the identification of proper UV'

coil operation despite the attention which has been focused on reactor-

trip breaker and UV coil operation. Unit 3 operations personnel informed

the other units of the confusion surrounding the training aid and'

recommended that all licensed and non-licensed operators attend refresher

training on the operation of the UV coils. Additionally, the licensee

,

identified an inconsistency between the operations and maintenance

procedure concerning the actions to take if the UV coil does not reset.

This problem was being addressed by a procedure change to ensure all RTB

,

operations are controlled by the operations procedure and Condition

,

Report / Disposition Request (CRDR) 3-3-0237 was written to evaluate the

'

problem.

The inspector concluded that the licensee's response to this situation

was adequate.

No violations of NRC requirements or deviations were identified.

,

8.

Charoina pumo Testina - Units 1. 2. and 3 (71707)

!

On May 20, 1993, the licensee determined that testing of the charging

,

pumps had been performed with flow instruments with an instrument range

i

not meeting the requirements of Section XI of the ASME Code, Article IWP

!

4120. The ASME Code requires the flow instruments to have a range of.

!

less than or equal- to three times the reference flow value. The

,

reference flow value was 44 gallons per minute (gpm), so the maximum

!

allowed range was 0-132 gpm.

Flow instrument CHN-FL-212, which was used

for the tests in all three units, had a _ range of 0-150 gpm. The accuracy

'

of CHN-FL-212 was

1.0%, while the ASME Code only required an accuracy

-

of i 2.0%.

As a result of this concern, the licensee entered Technical

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Specification 4.0.3 and reperformed the' tests within the allowed time

period after adjusting the range of the instrument. 'The licensee also

notified NRC personnel of the condition and discussed its intentions in

-

parallel with its prompt actions. The licensee stated that it intends to

thoroughly review compliance of its inservice. testing program with

,

surveillance requirements. This issue is unresolved pending the

licensee's evaluation of the inservice testing program (Unresolved Item

50-528/93-12-05).

No violations of NRC requirements or deviations were identified.

9.

Essential Battery Seismic Issues - Units 1 and 2 (37700)'

a.

Essential Batterv Seismic Clearance - Unit 2 (37700)

In response to licensee-identified cracks near the terminal post of

Unit.1 essential (PK) batteries, the licensee modified the design

,

prior to replacing the Exide batteries. in-Unit 2 with AT&T round

-

cell batteries. This modification consisted of using more flexible

,

cables (to reduce. cable. relaxation stresses) and installing

horizontal support. brackets. The inspector noted that there was

less than 1/2" of clearance between the horizontal supports and the

battery cabinets in the battery "A" installation. Because the

horizontal brackets were fastened .to support structures which would

move independently from the battery rack during a seismic event, the

inspector was concerned about potential. damage to the batteries

during such an event. The licensee agreed with the. inspector's -

>

concern and promptly modified the installed supports so that there

was approximately 3" of clearance between the supports.and the.

battery rack. The "A" PK battery had been declared inoperable for

the modification installation and was.still in this status when the

concerns were identified. The inspector reviewed the installation

of the supports in Units 1 and 3 and determined that similar

conditions did not exist.

-

The licensee's design modification will be reviewed in a future

inspection to determine if the details were adequate (Unresolved

Item 50-529/93-12-06).

b.

Batterv Rack Partial Thread Engagement - Unit 1

"

While inspecting the essential batteries in Unit.'1, the inspector

noted that the bolts that fasten the retainer assembly' bars to the

i

foundation did not extend fully through the 1/2". steel plate. Th_e

essential batteries are held in place by 1/2" threaded rods which

extend from brackets at the top of the battery cabinet to the

-

foundation. The threaded rods are connected to retainer assembly

bars which in turn'are~ fastened to the foundation by 5/8" bolts.

The inspector estimated that the 5/8" bolts had approximately 3/8"

i

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of thread engagement with the foundation.

Drawing 13-E-ZJP-001,

,

sheet 2, required that the bolts have full thread engagement .into

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the 1/2" plate. This condition had been previously identified by

the licensee in CRDR 1-3-0095.

i

!

The licensee's generic procedure on fastener tightening /preload,

!

30DP-9MP02, Revision 01.08, required that "where the bolted

i

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connections attach to a tapped and threaded hole in the mating part,

the bolt length shall be sufficient to assure an engagement of at

.

least one bolt diameter. . . ." The observed condition, S/8" bolts

!

with 3/8" thread engagement, did not meet the generic criteria. The

'

inspector questioned if the condition was seismically acceptable and

'

if the condition had been previously documented.

Licensee personnel

'

determined that the seismic requirements of the installation

-

required approximately 3/8" of thread engagement, but that the

'

evaluation had not been documented at that time.

The licensee documented evaluation of the condition on material

nonconformance report (MNCR) 93-PK-1017. The resolution of the MNCR

s

stated that the bolts met the requirements of calculation 13-MC-XM-

204, " Thread Engagement for Partially Engaged Fasteners." However,

the inspector noted that the calculation stated that if the specific

materials were not addressed in the calculation,- a case specific

calculation should be prepared that considered the materials, the

application, and the design loading conditions. The specific

materials used in this application, ASTM A307 bolts and ASTM A36

}

foundation plate, were not specifically covered in the calculation.

The inspector will review the licensee's technical justification for

i

resolution of this MNCR in a future inspection (Unresolved Item

i

50-528/93-12-07).

No violations of NRC requirements or deviations were identified.

10.

Shutdown Coolino (SDC) Thermal Overload BYDass Desian Error - Units 1. 2.

and 3 (71707)

~

On May 5,1993, during post-modification testing of a design change to

remove the auto closure interlock on SDC isolation valves (S1-651 through

,

656), the licensee found that the thermal overloads on the valve motor

operators were only bypassed when system pressure was greater than 480

psi. Since the interlock circuit is closely related to the bypass

feature, the inspector concluded that licensee missed an opportunity to

identify the design error during the design review of the interlock

design change. Technical Specification (TS) 3.8.4.2 requires these

overloads to be bypassed continuously or under accident conditions

whenever the valves are required to be operable.

Since the accident

'

analysis and TS 3.7.11 require SDC to be available for entry into long

term cooling in Modes 1 through 3, the licensee determined that the

valves needed to be operable and the overloads bypassed when pressure is

a

less than 480 psi in Units 1 and 3.

Consequently, the valves and the SDC

J

systems in Units 1 and 3 were declared inoperable and the appropriate TS

3

action statements were entered. The thermal overloads were promptly

)

bypassed and the SDC systems were declared operable on the morning of

1

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May 6, 1993. Additionally, the licensee made a one-hour notification per

10 CFR 50.72 for being outside their design basis, and initiated

Condition Report / Disposition Request 9-3-0369 to determine the root cause

of the design error.

i

At the time of the discovery, Unit 2 was in Mode 6 and had commenced

'

refueling operations, and one SDC loop was in operation with the

isolation valves open.

In Modes 4 through 6 the purpose of the SDC

system is to provide decay heat removal per Appendix A to 10 CFR Part 50,

,

General Design Criterion 34, and is not required as part of accident

mitigation.

In Mode _6, TS 3.9.8.1 required one SDC loop to be operable

and one SDC loop in operation. The licensee's TS Interpretations

3.4.1.4-13-02-00 and 3.9.8.1-13-01-00 defined an operable SDC loop in

,

Modes 5 and 6 as a pump and an associated flow path but did not 'specify

that the isolation valves must be operable. Therefore, the licensee

determined that bypassing the thermal overloads in Unit 2 was not

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immediately required. The licensee subsequently bypassed the thermal

!

overload protection in Unit 2 on May 25,1993, while in Mode'5.

,

The licensee is evaluating its interpretation of TS 3.8.4.2 to determine

!

whether proper accident conditions have been evaluated and the need for

-!

bypassing of the thermal overloads for these and other valves.

The

j

licensee submitted Licensee Event Report (LER) _50-528/93-06 on this

issue. The inspector concluded that the licensee's initial

,

interpretation of the requirements and actions to correct the situation

'

were conservative. Additionally, the inspector concluded that it 'was

!

commendable that the licensee discovered this problem during post-

.,

modification testing although it appears that the error could have been

identified earlier in the design change process.

This issue will be

,

further reviewed during the review of LER 50-528/93-06.

-t

No violations of NRC requirement or deviations were identified.

.

11. Core Reload Anal _vsis - Units 1. 2. and 3 (37700)

The Office of Nuclear Reactor Regulation (NRR) and Region V personnel

'

conducted an inspection of the core reload analysis process in

preparation for the licensee performing independent reload analyses. NRR

,

will issue a special report (Safety Evaluation Report) describing this

review and its conclusions.

.

No violations of NRC requirements or deviations were identified.

12. Emergency Operatina Procedures (EOPs) - Units 1. 2. and 3 (42001)

The inspector reviewed the status of licensee actions regarding E0P-

~

related comments resulting _ from the Unit 3 Human Performance Study Report

!

performed by the NRC Office for Analysis and Evaluation of Operational

Data (AE00) as a result of the February 4,1993, reactor trip event in

.

Unit 3 (see NRC Inspection Report 50-530/93-04). The AE0D report was

,

issued on April 22, 1993, and Region V determined that the following

issues from the report warrant additional followup-

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a.

Several difficulties with the E0Ps occurred during recovery,

b.

Procedures did not quickly restore the electrical system and did not

consider using the main feedwater system to feed the steam

generators.

f

The licensee reviewed procedural guidance and determined that the

E0Ps should be changed to allow use of main feedwater, if available,

and that guidance for restoration of the switchyard electrical-

lineup should also be included. These changes are planned to_.be.

incorporated in October 1993.

c.

The procedure directed manual control of the pressurizer spray valve

,

which could result in excessive reactor operator task workload in

y

other emergency conditions.

The AEOD report described that operators may be unnecessarily tasked

with administrative and monitoring responsibilities as the result of

being required to operate some systems, such as pressurizer spray,

in the manual mode, instead of automatic control. The licensee

i

reviewed this issue for pressurizer spray only. Th'e reason-that the;

E0Ps require manual operation of the spray valve is that operators

>

are required by a Technical Specification surveillance requirement-

to log spray line -temperature every time the valve cycles, when less

than four reactor coolant pumps are operating. The licensee stated

that placing the controls in manual actually reduced the burden on -

-

the operators, because they would know when the valve is . cycled and

can log required information appropriately. The licensee considered

l;

and rejected reliance on computerized monitoring of the spray line

temperature to meet the surveillance requirement because operators

might not notice spray line temperature changes and:therefore might

allow continued automatic spray operation that might be detrimental

,

to the spray nozzle. The licensee did not think that monitoring in .

>

this fashion was consistent with the intent of the surveillance

requirement,- even though it would allow continued operation in the

i

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automatic mode. .The licensee does not plan to revise the E0Ps as a

result of this issue.

j

,

d.

The E0P prolonged the time from automatic initiation to shutdown,of

,

the emergency diesel generators.

,

The licensee determined that the E0Ps should be revised.to' allow

_

operators to move the step forward to secure the emergency diesel

generators when. appropriate and time permits. This change is

scheduled for October 1993.

.

.I

e.

The current computer system is not able to adequately display fast ~

transients.

.

f.

Auxiliary feedwater and safety injection system flows do not have a

,

recorder to readily identify the amount of water injected.

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g.

The emergency diesel generators were run unloaded for about four.and

'

one-half hours.

,

,

After the unloaded run, operators followed the carbon burnout

guidance of abnormal operating procedure 43A0-3ZZ52, " Diesel

l

Generator Operations After ESFAS Actuations " . This procedure

l

required the generator to be run at greater than or equal to 4.2 MW

!

for greater than or equal to 15 minutes, if the generator was

!

operated unloaded for more than six hours since its last loaded'

I

operation. The diesels had not been run unloaded for more than six

hours, and the operators did not perform a carbon burnout run.

}

(

During a future inspection, the inspector will review the procedural

<

guidance with industry and vendor recommendations.

,

h.

The audible alarm for computer alarms (system RJ) was intentionally

disabled.

These items will be further reviewed during a future inspection (Followup

Item 50-530/93-12-08 for items a, b, c, d, and h; and Followup Item

50-530/93-12-09 for items e, f, and g).

I

No violations of NRC requirements or deviations were identified.

13.

Containment Isolation Valve Operability Determination - Unit 3 (71707)

_

The inspector reviewed the operability determination of 3HPB-UV-004, the

'

Unit 3 containment hydrogen control downstream isolation valve (normally

closed), which tripped its thermal overloads when responding to a close

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signal on a containment isolation actuation signal (CIAS) on February 4,

!

1993. The inspector reviewed Condition Report / Disposition Request (CRDR)

3-3-0136, the unit logs and control room logs, and interviewed line

,

management concerning the operability of the valve. The CRDR discussed

i

'

troubleshooting on February 6 which verified that the motor currents were

normal and the overloads were the proper size. There was no discussion

!

in the CRDR or logs concerning what actions were done on February 4 to

verify the operability of the valve. The operations manager informed the

inspector that the valve was successfully stroked several times as part

i

ef ASME Section XI testing and the thermal overloads had' been tested,

j

without identification of the root cause of failure. The licensee

subsequently determined the valve to be operable based on these results

!

and the fact that the overloads that tripped are bypassed during a CIAS.

l

The valve was initially determined to be operable with'out fully

f

understanding why the overloads tripped, because the information

i

available supported the determination that the valve could perform its-

safety function. Additional troubleshooting.was not started until

~

March 9,1993, contrary to the guidance in Generic letter 91-18,

l

Technical Guidance 9900, Section 5.4, for continuous attention in the

decision making process. The inspector concluded that--these additional

efforts were comprehensive and led to eventually determining the cause of

the failure to be relaxation of the torque switch due to a gear ratio

i

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insufficient to ensure that relaxation did not occur. HPB-UV-004 was-

1

declared inoperable when troubleshooting commenced'again on March 9.

As-

a result of testing on similar Rotork actuators, HPB-UV-002 in Unit 3 was

i

also declared inoperable.

The licensee corrected these deficiencies by

-

installing a contact in the CIAS circuit that would open when the valve

-

was shut and prevent the valve from cycling. Although the licensee

stated that the delay was due to -scheduling conflicts, the inspector

,

concluded that the licensee did not aggressively pursue confirmation of-

the initial operability determination as described in Generic Letter 91-

18 in that troubleshooting to determine the root cause of the failure was.

t

delayed for over one month. .

,

No violations of NRC requirements or deviations were identified.

14.

Inspection of Quality Verification Function - Units 1. 2. and 3 (35702)

The inspector assessed the effectiveness of the licensee's quality

verification (QV) organizations in identifying safety significant

problems and in ensuring timely and effective corrective action.

In

conducting the review the inspector focused on the following areas:

performance assessment program, corrected on-the-spot (C0TS) program,

safety significant technical issues, and observation of quality control

(QC) inspectors.

a.

Performance Assessment Procram

,,

The inspector reviewed the following documents associated with the

assessment of plant performance:

Performance Assessment Trend

-

Report, Performance Assessment Annunciator Report, Trend Analysis

Coding Manual, and the current Issues Report.

The inspector

concluded that these programs were effective in focusing' appropriate

management attention on performance ' issues. The inspector also

observed that the documents reviewed provided a longer term summary

4

of plant performance (3 months and greater), and that the areas

described were generally broad in nature (site maintenance, human-

'

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performance,etc). The inspector concluded that the long term

,

nature of these documents was expected and that more real time

identification and trending was addressed using the COTS program.

b.

COTS Procram

,

t

The inspector reviewed the QC monthly reports for March and April

_

.

1993 and selected various COTS from these reports to review. The-

l

inspector interviewed line management and . supervisors to determine

.

how they respond to COTS issued in their areas. This inspection

1

evaluated the licensee's process, but did not include an in-depth

look at the corrective actions identified by the supervisors.

In

general, the supervisors were informed within a few days by the QC

supervisor issuing the COTS that there was a-problem. This

notification was either verbal or written. The line supervisors

would then perform some type of counseling and/or training and were

t

sensitive to monitoring trends in individual performance.

l

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The inspector concluded that the QC. organization was identifying

'

good issues and that they were appropriately documented. The

-

inspector also noted that work center supervisors were sensitive to

trending problems and to taking appropriate corrective action to

help prevent problems from becoming more serious.

c.

Technical Review of Safetv Issues

(1)

Lifted / Landed Leads

The inspector conducted a search in the corrective action

.

tracking system (CATS) for all documents associated with

"

lifted / landed leads. There were approximately twenty various

documents in the data base in the last two years on this

subj ect. The inspector reviewed the following corrective-

action documents: Condition Report / Disposition Requests

(CRDRs) 3-1-0014, 3-1-0018, 1-1-0130, 1-2-0355, and 1-2-0584;

Material Nonconformance Reports (MNCRs) 92-SQ-1010 and. 92-SQ-

1011; and Quality Control Reports (QCRs) 00450879-012 and

00562561-002. The inspector noted that there were-four CRDRs

written on this subject from May 1991 until May 1992. The

first three CRDRs did not require a formal root cause analysis

(RCA) and were designated for trend only or apparent cause.

evaluation. CRDR 1-2-0355, written on May 19,.1992, required a-

formal RCA that concluded the cause of the improper landing of

leads was inadequate procedures.

The inspector was concerned that the CRDRs were not being

effectively used to determine the underlying cause of the

personnel errors associated with lifted / landed leads.

'

Specifically, the failure to screen the first four CRDRs for a

formal RCA may have contributed to continued errors involving

lifted / landed leads.until a trend of over one year was

ebserved. The inspector was also concerned that the initial

RCA did not address broader generic maintenance issues, such as

inattention to detail and continued personnel errors.

In June 1992, Corrective Action Report (CAR) 92-0123 was

,

written to investigate the continued problems in this area.

The inspector noted that six additional CRDRs and several

QCRs/ COTS were issued in the area of lifted / landed leads after

the CAR was issued. This problem was identified by the

,

licensee in the fourth quarter 1992 Current Issues Report, and

!

a more comprehensive corrective action plan was initiated to

1

correct the broader generic' maintenance issues associated with

-

these personnel errors. The inspector noted-that lifted / landed

leads was a top priority for each of the unit QC shops, and

that the broader personnel performance issues were being

addressed by upper management. The inspector concluded that

the licensee's current actions appeared to be appropriate and

will review this item further in a future inspection (Followup

Item 50-528/93-12-10) .

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(2) Heat Exchancer Pluaaino Events

The inspector searched the CATS system for all reports related

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to heat exchanger work. There were five MNCRs, one CRDR, and

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two Plant Inspection Reports (PIR) written concerning essential

cooling water heat exchanger work. One of the PIRs was for

.

incorrectly installing plugs (00545315-M-02) and the other was

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for using the wrong plug map (00545315-M-03). The inspector _

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noted that these problems were immediately corrected.

The inspector reviewed all the events related to mis-plugging.

y

of steam generator (SG) U-tubes.

In 1990 during refueling

4

outage (RF0) 2R2, the licensee discovered that a tube in SG 22

was mis-plugged during the previous RF0, 2RI. The corrective

actions for this event . included developing a lessons-learned

folder for QC inspectors involved with verification of tube

plugging and a second party independent verification using a -

videotape of the tube sheet.

By using the videotape, the

licensee subsequently identified two tubes that were

incorrectly plugged prior to restarting from RF0 2R2.

The

licensee determined that the cause of the mis-plugging was-a

transposition error from the eddy current data to the MNCR.

In

March 1993 during RF0 2R4, the licensee identified another tube '

in SG 22 that had been mis-plugged during the previous outage,

4

2R3. A violation was issued in Inspection Report 50-529/93-11

for the licensee's failure to plug the proper tube despite

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similar failures in the previous outage. The inspector also

noted that the same process of transposing the eddy current

data to the MNCR was used during the current outage and that an

additional problem with properly controlling the tube sheet

maps was identified by licensee QC personnel during the current

Unit 2 outage.

QC personnel identified this problem then they

were performing a review of the circumstances surrounding the

latest mis-plugging incident.

The inspector participated in training course QMZAC-00 for QC

inspectors on independent verification of SG U-tube plugging.

'

This was a new training module developed as part of the

corrective action for the mis-plugged _ tube identified in the

current Unit 2 outage. The inspector noted the training was

positive and helped trainees understand the difficulties of

identifying the proper location of SG tube plugs. The

4

inspector also concluded that the lack of similar training in-

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the past may have contributed to plugging errors.

For example,

all five inspectors'that participated in the training quickly

identified the mis-plugged tube that was discovered during the

current outage. The licensee initiated CRDR 2-3-0222 to

determine the root cause of the latest mis-plugging event. The

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licensee's evalu'ation was not complete at the end of this

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inspection period.

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In summary, the inspector concluded that the previous mis-

plugging events involving the essential cooling water heat

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exchanger were appropriately reviewed by licensee personnel,

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and as discused in Inspection Report 50-529/93-11, the

licensee's previous corrective actions for SG tube mis-plugging

were ineffective.

d.

Observations of OC Inspectors

The inspector observed the conduct of three QC inspectors-during-the

following evolutions and the adequacy of the-associated QCR:

Installation of LDCP 03-LE-HP-042 on valve 3J-HPB-UV-0002, QCR

00603791-002; installation of Raychem in line kit on motor leads to

HPSI "B" pump, QCR 00601082; and installation of multi-stud

tensioner on the Unit 2 reactor vessel, QCR 00584537-002. The

inspector concluded that the QC inspectors were thorough and showed

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good technical knowledge. The inspection efforts included various ,

areas 'and not only the specific hold point / witness points. The

inspector noted that some items identified during the inspection

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activity were not discussed in the associated QCR. The inspector

discussed this with the QC inspector and his supervisor who agreed

that the items should have been noted.

In summary, the inspector concluded that the performance of the

three QC inspectors observed was a strength. However, some QCRs

should have included a discussion on observations that may no't meet-

the criteria of a COTS but warrant documentation so they ca.n be

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evaluated for potential enhancements or problems.

No violations of NRC requirements or deviations were identified.

!

15.

Plant Review Board Activities - Units 1. 2. and 3 (40500)

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The inspector reviewed Plant Review Board (PRB) activities as part-of an

overall evaluation of the effectiveness of the licensee's self-assessment

capabilities.

The inspector examined'PRB meeting minutes from four randomly-selected

meetings. Additionally, the inspector attended several PRB meetings

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during the last year, including the May 10,'1993, special PRB which met

to address snubber issues (Paragraph 5). The PRB was-found to be focused

on nuclear safety. Members demonstrated good understanding of the issues-

)

and were thorough in their evaluations. The inspector noted that in May

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1993, only six action . items were being tracked by the PRB, 'and that these

items were being closely managed. The inspector also noted that the'PRB

i

met much more frequently than required-by licensee procedures or NRC-

regulations.

In the meetings: attended and meeting minutes reviewed, the

PRB addressed most of. the items over which the PRB is required to

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maintain oversight. The inspector reviewed the membership and determined

that the members met the minimum qualification requirements. The

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inspector concluded that the PRB met regulatory requirements regarding-

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its oversight responsibilities and that it contributed substantially to

nuclear safety.

No violations of NRC requirements or deviations were identified.

16.

Accountability Drill - Units 1. 2. and 3 (82301)

The inspector observed an accountability drill on May 26, 1993, conducted

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to verify the licensees ability to account for all personnel within 30

minutes of declaring a site area emergency (SAE) or above. The inspector

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observed the drill from the Unit 3 operations support building, Unit 2

operations support center, and the central alarm station.

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The inspector noted that the drill started at approximately 8:00 a.m.

with the announcement of an Alert in Unit 3.

The announcement stated

that there was an alert and that all personnel were to report to their

assembly location. The event was not upgraded to a SAE until

approximately 9:00 a.m., when an announcement was made that

accountability was required and the 30 minute clock was started.

However, security personnel had been working toward-accountability since

the start of the alert and had a significant head start when the actual

call for accountability was made. The report of accountability to the

emergency response coordinator was made at 9:25 a.m., and met the

administrative requirement for a report within 30 minutes of declaring a

SAE.

However,' the inspector concluded that the drill did not adequately

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demonstrate the ability to account for all personnel within 30 minutes of

the initial event notification, since security had been working toward

the accountability report for over an hour. The inspector noted that

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there is no regulatory requirement covering this drill and the failure to

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demonstrate the capability to meet assembly and accountability

requirements is not a violation of regulatory requirements.

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The licensee agreed with the inspector's observations, and committed to

conduct another drill which would start as a SAE and immediately require

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accountability within 30 minutes,

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No violations of NRC requirements or deviations were. identified.

17.

Followup on Previously Identified Items - Units 1. 2. and 3

a.

(Closed) Followup Item 50-528/92-41-01. Reactor Trio due to Known

Defective Neoative Seauence Relay - Unit 1 (92701)

,

3

This item involved weaknesses in the vendor information program

which were identified following the reactor trip on December 8,

1992. CRDR 9-2-0743 was still open as a result of additional

actions which were identified by. the licensee to address these

program weaknesses. The licensee evaluation was completed on

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March 1,1993, and corrective actions were identified. The

corrective actions are scheduled to be complete.by November 11,

1993. These actions include expanding the scope of vendor technical

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documents, contracting with General Electric for vendor technical

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information support for non-quality related components, revising.

design change procedures to incorporate _ vendor technical manual

requirements, completing the search for missing model numbers,

superseding the first 500 old vendor manuals, and sampling vendor

contacts to determine the adequacy of these corrective actions. One

licensee action taken to address the program vulnerability

identified by the inspector regarding the quality of information:

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obtained by the vendor has been the implementation of a Vendor

Technical Information Exchange computer bulletin board system to

share vendor _ contact information among nuclear utilities. - The

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inspector considered the use of the bulletin board system to- be a

creative application to address the identified weakness. This item

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is closed.

b.

(Closed) Unresolved item 50-528/93-11-01. Feedwater' Isolation Valve

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Doerability Determination - Unit 1 (92701)

This item involved an evaluation of the operability determination of

SGB-UV-132 performed on June 9,1992, after the valve failed to

stroke during a surveillance test designed to demonstrate that the

valve would stroke. The inspector noted that after the second

surveillance test failure, operators considered the valve operable

because the pressure in the accumulator increased to above 5000

psig, and valve could have failed to move because of a failure of-

the logic circuitry, rather than the "M"

four-way valve.

Thq

inspector noted that a portion of the logic ' circuitry is shared by

the test circuit and must function correctly for the valve to

perform its safety function. A review of the history 'of the logic

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circuitry revealed that no failures had been recorded. A review of

the history of the. "M" four-way valve revealed numerous failures.

The inspector concluded that with the evidence available at the time

of the operability determination at 4:16 p.m., the operators no

longer had a basis to have confidence that the' vaive would perform

its safety function. The inspector acknowledged that there was

insufficient information available to conclusively demonstrate the

location of the failure; however, in accordance with Technical

Specifications, a component is only operable when it is " capable of

performing its specified function." Generic Letter 91-18 guidance

states that "the licensee's process should call for immediately

declaring equipment inoperable when reasonable-expectation of

operability.does not exist or mounting evidence suggests that the

final analysis will conclude that the equipment cannot perform its

specified' safety function (s) ."

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During an interview with the shift. supervisor, the inspector noted

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that one aspect of the decision to not declare the valve inoperable

following the second failure of the valve to stroke resulted from

the fact that surveillance testing was deemed to still be in

progress because steps had been added to the surveillance. test

procedure to test the valve separately from the logic circuitry.

The shift supervisor stated that the valve would have been declared

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inoperable if those steps were not present in the surveillance test

procedure and the additional actions had been in a troubleshooting

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work order. The inspector concluded that the operators focused so

closely on following good troubleshooting practices that attention

was diverted away from the operability consideration.

The inspector.

further concluded that the operability determination made at 4:16

i

p.m. on June 9,1992, was incorrect; however, the Technical.

[

Specification Limiting Condition for Operation was met as described

below. Therefore, Technical Specifications were not violated.

1

The licensee declared the valve inoperable at 3:56 p.m. to conduct

the second stroke test. Although the licensee determined that the

valve was operable at 4:16 p.m., the inspector concluded that the

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valve was not operable which resulted in the valve not being made

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operable within four hours as required by Technical Specifications.

However, the valve was restored to an. operable status within the

next six hours (at 1:50 a.m.), just six minutes before the Action

Statement would have required further action to reduce power and

change modes. The inspector further noted that this compliance _ was

not as a result.of planned actions.

The licensee agreed with the inspector's conclusions and committed

to adding additional FWIV technical training and troubleshooting

separate from operability determination training for all licensed

operators during continuing training. .The inspector concludgd that

1

this appeared appropriate. This item is closed.

c.

(Closed) Unresolved Item 50-529/93-11-03. Snubber Testing - Unit 2

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(40500, 61726. and 92701)

3

a

This item was left unresolved in a previous inspection to review the

snubber testing program, the causes of the failures, and the

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licensee's consideration of the Unit 2 snubber failures on Units.1

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and 3.

This item is closed based on the inspector's review,

documented in Paragraph 5.

d.

(Closed) Followup Item 50-530/93-04-03. Reactor Trio Breaker (RTB)

Documentation - Unit 3 (92701)

This item involved the identification of RTB undervoltage trip

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attachment (UVTA) binding. The vendor resolution of this issue was

to modify the UVTA design. When the licensee was asked which

breakers still-had the old style UVTAs installed, the response did

not include the Unit 2 "B"

RTB.

Later this breaker was noted to

c

have the old style UVTA. Followup questions revealed the need for

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the licensee to determine whether this was a material tracking

deficiency or an document review deficiency. -The licensee

investigation determined that the documentation existed; however,

the reviewers did not take sufficient time to thoroughly review the

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existing documentation. Since the most recent work order associated

with this UVTA showed warehouse requisition documentation, the

reviewer assumed that the UVTA obtained from the warehouse was a new

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style device when it was actually an old style device which had been

returned to the warehouse and later reissued. The inspector agreed

with the licensee's conclusion. This item is closed.

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e.

(0 pen) Followup Item 50-530/93-11-05. Macne-Blast Breaker

!

Inoperability - Close Latch Sprina Interference - Unit 3 (92701).

1

This item involved the inoperability of a safety-related General

Electric (GE) Magne-Blast breaker due to interference of the close

1

latch spring.with the close latch monitoring switch. The inspector

concluded that licensee immediate actions were appropriate.

Condition Report / Disposition Request (CRDR) 3-3-0152 was issued to

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evaluate the inoperability. Three long term actions were

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recommended for consideration by this CRDR. The first was to issue

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a Plant Change Request to annunciate any failure of the breaker

closing springs to charge in the control room. The second was~to

issue an Engineering Evaluation Request to permit the use of torsion

springs on Magne-Blast breakers. The third was for the licensee to

obtain Service Advice and other information regarding the spring

changes from GE. The inspector concluded that these actions

appeared appropriate. This item will remain open pending a review

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of licensee plans with regard to these recommendations.

f.

(Closed) Unresolved Item 50-530/93-11-06. Operator Response to

Turbine Trio - Unit 3 (92701)

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During the response to a turbine trip on April 21, 1993, the ;eactor

operator (RO) tripped one of the reactor trip breakers. -The

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inspector conducted interviews with the R0, control room supervisor

(CRS), operations supervisor, and operations training supervisor to

determine whether the R0's response to the event was appropriate.

'

The inspector noted that procedure 41A0-1ZZ02, " Load Rejection,"

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included steps to verify if. a reactor power cutback (RPCB) has

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occurred.

If a RPCB has occurred, the operators are directed to

monitor pressurizer pressure and to manually trip the reactor if the

high pressure setpoint is approached.

In this. event, the R0

announced he had a RPCB and observed reactor power-decreasing, but

he was'not monitoring pressurizer pressure.

Instead, when a low

departure from nucleate boiling ratio pre-trip on channel

"C" was

H

received (due to the rod motion and change in local neutron flux),

the R0 announced he was trippi.ng the reactor and placed his fingers

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on the manual trip push buttons. The R0 did 'not fully press' the-

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buttons because he was waiting for concurrence from the CRS. When

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he did not get verbal concurrence, he realized that a trip was not

R

required and withdrew his hand from the push buttons. However,

during this time he inadvertently pressed one of the buttons enough

to trip the breaker.

The inspector discussed this event with the operations training

supervisor.

During simulator training on load rejection, operators

were expected to monitor reactor power (to verify whether a RPCB

occurred) and pressurizer pressure.

If a RPCB did not occur, they

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were expected to manually trip the plant.

Since the simulator did

not model a RPCB at this time, the simulator scenarios had always

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led to a reactor trip. The inspector concluded that the training in

this area was consistent'with the actions directed by the abnormal

operating procedure.

!

The inspector acknowledged that it was noteworthy that numerous

plant systems responded as designed during the event which prevented

a reactor trip. Also, the fact that the. R0 did not trip the plant.

because he waited for concurrence from the CRS demonstrated

excellent teamwork and command and control. However, the inspector

concluded that the R0's response to the event was not consistent

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with the direction in the load rejection procedure to monitor

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pressurizer pressure, a violation of plant procedures.

The failure to follow plant procedures is not being cited because

the criteria specified in Section VII.B of- the enforcement ' policy

.

were satisfied (NCV 50-530/93-12-11). This event had relatively low

safety significance in that it was conservative to trip the reactor,

'

although an unnecessary reactor trip would have represented a'

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challenge to plant safety systems. The licensee promptly issued

night orders that emphasized the need to be aware of differences

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between the plant and simulator.

In addition, the licensee

subsequently installed the software to model the RPCB in the

simulator, reflecting the restoration of RPCB capability in 1.he

!

Units which was performed on February 3,1993 (see NRC Inspection

Report 50-530/93-04).

Based on this review, this unresolved item is closed.

!

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One non-cited violation of NRC requirements was identified.

18.

Review of Licensee Event Reports (LER) - Unit 3 (92700)

'

Through direct observations, discussion with licensee personnel, or.

review of the records, the following LER was closed.

t

Unit 3

i

92-05,

Revision LO

" Train B Low Pressure-Safety Injection Pump.

Breaker Inoperable"

[

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This LER reported the Magne-Blast breaker failure ~ discussed in

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Inspection Report 50-530/92-92-31, Paragraph 8.. No additional'

issue were identified in the~ LER. 'This LER is closed.

No violations of NRC requirements or deviations were identified.

19.

Exit Meetino (71707)

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An exit meeting was held on June 1,1993, with licensee management and

resident inspectors during which the observations'and conclusions in this

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report.were discussed. The licensee had no additional comment's. to the '

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inspector's findings. The licensee did not _ identify as . proprietary any

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materials provided to or reviewed by.the inspectors during the

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inspection.

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