ML20245L574

Insp Repts 50-498/89-17 & 50-499/89-17 on 890601-30. Violations Noted.Major Areas Inspected:Plant Status,Licensee Action on Previous Insp Findings,Operational Safety Verification & Monthly Maint & Surveillance Observations

ML20245L574
Person / Time
Site:	South Texas
Issue date:	07/26/1989
From:	Holler E NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION IV)
To:
Shared Package
ML20245L549	List: ML20245L545 ML20245L562 ML20245L574
References
50-498-89-17, 50-499-89-17, NUDOCS 8908220164
Download: ML20245L574 (12)

See also: IR 05000498/1989017

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APPENDIX B

U.S. NUCLEAR REGULATORY COMMISSION

REGION IV

NRC Inspection Report: 50-498/89-17 Operating Licenses: NPF-76

50-499/89-17' NPF-80

Dockets: 50-498

50-499

Licensee: Houston Lighting & Power Company (HL&P)

P.O. Box 1700

Houston, Texas 77001

Facility Name: South Texas Project (STP), Units 1 and 2

Inspection At: STP, Matagorda County, Texas

Inspection Conducted: June 1-30, 1989

Inspectors: J. E. Bess, Senior Resident Inspector, Unit 1

Project Section D, Division of Reactor

Projects

J. I. Tapia, Senior Resident Inspector

Unit 2, Project Section D, Division of Reactor

Projects

R. J. Evans, Resident Inspector, Unit 1

Project Section D, Division of Reactor

Projects

D. L. Garrison, Resident Inspector, Unit 2

Project Section D, Division of Reactor

Projects

Approved: . A "

d

T. Jp Holler, Chief. Project Section D Date

Division of Reactor Projects

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Inspection Summary

Inspection Conducted June 1-30, 1989 (Report 50-498/89-17; 50-499/89-17)

Areas Inspected: Routine, unannounced inspection of plant status, licensee

action on previous inspection findings, operational safety verification, i

monthly maintenance observations, power ascension test, monthly surveillance

observations, and startup test witnessing and observation,

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Results: Within the areas ins

fire watches (see paragraph 3)pected,

. Weaknessesonewere

violation noted was

in theidentified licensee's regarding

piping

and. instrument diagrams (P& ids) of the Unit I standby diesel generator (DG)

support. systems. The P& ids did not correctly reflect the as-built configuration

of the support systems. Other Unit 1 DG support system weaknesses included

identification tags missing from components, valves missing from the operating

procedures and P& ids, and valve positions different between P&lD aad operating

procedures (see paragraph 5). Licensee strengths were that all Unit 1 DG

support system valves and power supplies were in their correct position to

support DG operation despite the procedure /P&lD weaknesses and the fact that

the licensee had previously identified the deficiencies and implemented a

program to correct them. Also, maintenance and surveillance activities were

observed to be performed carefully and in accordance with procedures. Unit 2

successfully completed its startup testing program.

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DETAILS

1. Persons Contacted

• C. Ayala, Supervising Licensing Engineer

• S. M. Dew, Manager, Nuclear Purchasing

• A. C. McIntyre. Manager, Support Engineering

• J. R. Lovell, Technical Service Manager

• D. R. Keating, Quality Engineering Manager

• J. W. Loesch, Plant Operations Manager ,

• V. A. Simons, Plant Opera-tions Support Manager

• T. J. Jordan, Plant Engineering Manager

• H. W. Dannbardt, Lead Operations Specialist

• A. Khosla, Senior Licensing Engineer

In addition to the above, the inspectors also held discussions with

various licensee, architect engineer (AE), maintenance, and other

contractor personnel during this inspection.

• Denotes those individuals attending the exit interview cenducted on

July 6, 1989.

2. Plant Status

Unit 1 began the inspection period at 100 percent reactor thermal power

and remained at 100 percent until June 22, 1989. The reactor thermal

power level was decreased to 90 percent for maintenance and surveillance

testing of the turbine throttle and main steam isolation valves. The

reactor. thermal power level was increased to 100 percent power on June 24,

1989. The unit remained at 100 percent reactor thermal power through the

end of the inspection period.

Unit 2 began this inspection period at 75 percent reactor thermal power, ,

continuing with power ascension testing at that power plateau. On June 2 j

1989, a Unit 2 reactor / generator trip occurred. This unplanned trip is j

discussed in paragraph 3 of this report. On June 10, 1989, Unit 2  ;

achieved 100 percent reactor thermal power. The 100-hour nuclear steam  ;

supply system (NSSS) acceptance test at that power level was successfully -)

completed on June 16, 1989. Unit 2 was declared to be in commercial '

operation on June 19, 1989. At the end of this inspection period, Unit 2 '

remained at 100 percent reactor thermal power.

3. Onsite Followup of Plant' Events (93702)

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During the month of June, the boron concentration in Unit l's reactor

coolant system was slowly decreased to maintain reactor power at

100 percent. The unit is scheduled for a refueling outage to begin

August 4, 1989. Several activities were performed during the inspection

period to prepare the unit for the outage. A dummy fuel element with

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dimensions corresponding to a fuel element was used to verify the alignment

of the cell walls for the new spent fuel racks'. The dummy fuel element

was fully inserted and withdrawn from each fuel element storage cell in

the new spent fuel racks to assure that irradiated fuel elements could be

properly inserted into their designated storage positions. Also, the

spent fuel pool was filled and boric acid was added to increase boron

concentration to greater than 2500 ppm.

On June 2, 1989, Unit 2 tripped while in Mode 1 at 76 percent power.

Turbine inlet Throttle Valve TV-1 was closed during performance of the

Main Turbine Steam inlet Valve Operability Test. The valve was opened in

accordance with the procedure. The valve position was verified locally

and on the main control board. The operator did not notice the " TURBINE

STM STOP VLV RX PRETRIP" alarm, which actuated when the valve was closed

and that the bistable indication did not clear. This indicated that the

closed inlet valve input was still present at the solid state protection

system (SSPS) reactor trip logic. The test procedure did not specify a

check of this alarm or the bistable status after completing the valve

cycle.

Turbine inlet Throttle Valve TV-3 was closed per procedure. This

completed the two of four turbine inlet throttle valve closed logic at the

SSPS and generated a reactor turbine trip. The control rods inserted

normally following the trip. No unexpected posttrip transients were

noted. One steam generator power operated relief valve (PORV) was used to

control RCS temperature and pressure.

The licensee identified two causes of this event: (1) the test procedure

did not require the operator to verify that the bistable had cleared

following completion of the valve cycle, and (2) a defective limit switch

on Valve TV-1 stuck in the valve-closed position after the valve was

opened. The licensee replaced the defective switch and revised

applicable test procedures.

Each steam inlet throttle valve has a safety-related and a

nonsafety-related limit switch that is activated in the closed position.

The safety-related switch provides input to the reactor pretrip

annunciator and the SSPS bistable. The nonsafety-related switch provides

valve position indication on the main control board. When Valve TV-1 was

opened, the safety-related limit switch remained in the valve-closed

position and prevented the SSPS bistable from clearing. The

nonsafety-related limit switch operated normally and gave the proper <

indication of the valve position to the operator.

On June 6,1989, the licensee provided the inspector with a station

problem report regarding falsification of a fire watch log. The licensee

had briefed the inspector regarding the incident and immediate corrective

actions when the licensee first identified the issue in late April 1989.

The station problem report, completed on May 31, 1989, provided details

regarding the event and long-term corrective actions.

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Briefly, the event involved a contractor fire watchman who, after

discovering thd another contractor fire watchman on duty at the same time

l had apparently falsified an entry time on a fire watch log, reported the

matter to the general foreman who, in turn, escalated the matter to the

licensee's management. The licensee determined through an initial

investigation on the same day the matter was reported that a false entry

had been made and relieved the suspected fire watchman of duties. The

suspected fire watchman was terminated a week later. The licensee's

detailed investigation of the matter determined that the falsification had

been limited to the terminated fire watchman.

The safety significance of the missed fire watch round was relatively low.

The watches were provided to monitor affected areas where a fire barrier

was breached. The automatic fire detection and suppression systems were

operable in the affected areas. Because of a previous event involving

falsified fire watch log entries, the licensee had established procedures

whereby three fire watchmen were assigned to make a specified round in

succession. This was to ensure that an individual did not miss successive

rounds in the same area. In this case, the time to detect a possible fire

missed by the automatic fire detection system in the area where the

terminated fire watchman falsified making his round was extended from 1 to

2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br />.

The licensee determined that dereliction of duty by the terminated fire

watchman was the primary root cause. The licensee determined that the

practice of leaving a blank space on the fire watch log to highlight a

missed round was a contributing cause. Among its corrective actions, the

licensee emphasized the consequences, including potential criminal

prosecution, of falsifying documentation, stopped the practice of leaving

a blank space to highlight a missed round, and emphasized the requirement

to report a missed fire watch round to the shift supervisor or fire watch

coordinator.

Failure to perform fire watch rounds as required by licensee procedure is

an apparent violation. HRC, by provision of its enforcement policy.

10 CFR Part 2, Appendix C, Section V.G. 1, may refrain from issuing a

notice of violation for violations of relatively low safety significance

that are self-identified and corrected by a licensee. The provisions do

not apply to willful violations. For this reason, this apparent violation

will be cited (498/8917-01). The licensee's station problem report

regarding the falsified fire watch log adequately discusses the event

causes and corrective actions.

On June 8, 1989, the Unit 1 No. 13 Standby Diesel Generator (DG) was

started for testing in preparation for maintenance on a transformer. The

DG immediately tripped. The licensee found that the "high temp main and

conn rod brg or gen brg" alarm had actuated. This alarm had previously

actuated on May 24, 1989, but the indication was not valid. The licensee

could' not identify an actual problem that would have initiated either of

these alarms. The licensee performed troubleshooting to determine the

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cause of the DG trip. The licensee determined that the trips occurred

'because.of a trip signal which is bypassed in the emergency mode.

Inadequate air flow to' the shutdown air header prevented the pneumatic

trip switch from resetting before the electric trips were unblocked. The

licensee replaced the air filter, Jir regulating valve, and the pressure

switch in the--shutdown air header, and tested the DG successfully. These

events were classified as nonvalid failures in accordance with criteria

in Regulatory Guide 1.108. The test interval.for No.13 DG remained ac

31 days. The licensee determined that the DG would have performed the

required safety functions without tripping, should any have occurred.

There have been no valid failures of the No. 13 DG.

The primary meteorological tower was declared out of service on June 19,

1989, and was returned to service on June 29, 1989. Since the tower was

out of service more than 7 days, a special report regarding an inoperable

primary meteorological tower was required to be submitted to the NRC

(report was submitted July 6, 1989).

4. Licensee Action on Previous Inspection Findings (92701)

(Closed) Open Item (498/8902-01): Essential Chiller Temperature Control

Switch - In NRC Inspection Report 50-498/89-02; 50-499/89-02, the Unit 1

essential chilled water system was inspected. A temperature control point

switch was identified in the local chiller panels, but this switch was not

discussed in the operating procedure.

Since the inspection, Procedure 1 POP 02-CH-0001, " Essential Chilled Water

System," was revised to Revision 6. The updated procedure contained

Step 8.1.5 that instructed operations department personnel to adjust the

temperature control switch to the operating temperature range.

5. Operational Safety Verification (71707)

Operation safety verification inspections were performed to ensure the

facility was being operated safely and in conformance with licensee and

regulatory requirements. Items inspected on a routine basis included:

control room staffing, control room logbooks, plant housekeeping, plant

security, health physics, system and control board lineups, and general

plant / equipment conditions.

. Itsms noted and reported to the ' licensee during plant tours included:

The cable guards on two flexible conduit were noted to be pulled

loose from endpoint connections. The loose conduit (AIXG1CRX003 and

N1DGBDXC0051) required rework to protect the cables inside the

conduit. Both were located in DG Room 11.

A seal (yellow ty-rap) was noted not to be sealing on an " Emergency

Use Only" storage box. The licensee replaced all seals with metal

1ocks.

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Two drain valves (1-PD-0378 and.1-PD-0379) were required to be locked

shut per the locked valve program. The valves were locked shut in

_m the interest of good engineering practice and not for. reasons of

reactor safety. The locking devices were noted to be improperly

attached to the valves. This condition was reported to the Unit 1

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control room. ;0perations removed the cables and seals, then tagged

the valves in the shut position using the tag out procedure.

Inspections;of housekeeping were performed on a routine basis,

including.the Unit.1 mechanical auxiliary building (MAB). In the

MAB,' the floor of Room 327, 54-foot elevation, was noted to be

unusually dirty. - Trash, nails, bits of wood and sawdust, and other

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items were noted throughout the room, which was used as temporary

storage. The room has since been cleaned.-

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'As part of the operational safety verification portion of the inspection,

the standby DG No.-11 support systems were inspected. The support systems

were compared to the electrical, valve, and instrument lineups

. (Procedure IPOP02-DG-0001. " Emergency Diesel Generator No.11,"

Revision 6) and Loth the Bechtel and vendor (Cooper Energy Services)

supplied P& ids. The diesel generator support systems inspected included:

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Fuel Oil Storage and Transfer System (system designator F0)

Lube Oil System (LO)

Jacket Water. System (JW)

Cooling Water System (DG)

Starting Air System (SD)

Air Intake and Exhaust System (DI)

Observations made during the system walkdowns included:

Ten valves and one pressure indicator were missing identification

tags.

One nonsafety-related temperature indicator (DG No.12 L0

temperature) was reading 4*F less than the minimum value allowed by

Procedure IPOP02-DG-0002, Step 5.23. This was reported to the shift i

supervisor who initiated corrective actions.

• Local Level Indicator LI-9109A (fuel oil storage tank level) was

missingitsengineeringunits(%). The indicator was located on

local Control Panel ZLP102.

Twodifferentvalveshadthesameidentificationnumber(1-LU-3012).  ;

• The wrong cubicle was listed as power supply for Distribution

Panel DPA135 in the electrical lineup and on the local panel  !

nameplate (the lineup was corrected in Revision 7 of d

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Procedure IP0P02-DG-0001, which was approved June 27,1989).

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Five valves shown on the P& ids were not listed in Revision 6 of the

procedure lineup. One valve was subsequently added to the lineup by

Revision 7 to the procedure, two valves apparently did not exist, and

two valves (nonsafety-related vent valves) were added to the

procedure by recent field change requests (FCRs).

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Five valves were found to be in different positions in the valve

lineup than the position shown on the P&lDs. The P& ids were

apparently incorrect in all five cases. One valve, 1-JW-0031, was

shown locked shut on one drawing and open on another.

Valve 1-JW-0031 was in the correct position for system operation.

Several valves were found that were not shown on any P&ID, not

labelled, or not listed in the valve lineups. The valves included

several safety-related instrument root' valves, one L0 filter drain

valve, and two L0 strainer drain valves.

Walkdowns of the support systems were performed using both vendor and

Bechtel P& ids. For the SD and F0 systems, the Bechtel P&ID showed only

the Bechtel supplied items in detail, while the vendor P&ID showed only

vendor supplied items in detail. All SD and F0 P& ids were noted to have

minor errors, including missing valves and wrong valve positions. For the

JW, LO, and DG systems, Bechtel P& ids were drawn from vendor P& ids.

Numerous errors in the vendor P& ids were simply carried over onto the

Bechtel drawings. In the JW P& ids, the basic flowpaths were correct, but

many components were 'shown in the wrong locations. Instrumentation root j

valves were not shown on the JW P& ids. In the DG P& ids, the flowpaths for

the intercoolers and fuel oil coolers, a major portion of the vendor and

Bechtel P& ids, were incorrectly drawn. The L0 P& ids drawn by Bechtel

contained the most errors. Flowpaths were incorrectly drawn, valve

numbers were incorrect for about 20 valves, equipment was shown in the

wrong location, and at least one root valve was missing.

All valves and power supplies were noted to be in the correct position

needed to support DG No.11 operation. The details of the inspection were

presented to the licensee for corrective actions. The licensee was aware

of the problem with the diesel generator support systems P& ids. In

January 1988, plant engineering sent support engineering an engineering ];

support request, which identified the problem. In April 1989, support

- engineering generated an action item, which was a plan of action. At the

end of the inspection period, the action item was still in the review

process and system walkdowns were still in progress. The inspectors

discussed with the licensee a concern that corrective actions needed to

correct the drawing errors were not prompt. The licensee stated that .

manpower resources were being used to upgrade the vendor manuals, l

illegible vendor drawings, and design basis documents, which had

priorities over the P& ids. The licensee also stated that the work to

upgrade the P& ids would be completed by the end of the year. The work

scope would include completion of walkdowns, revision of drawings, and

tagging vendor supplied equipment. j

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No violations or deviations were identified in this area of the

inspection.

6. Monthly Maintenance Observation (62703)

Selected maintenance activities were observed to ascertain whether the

activities were conducted in accordance with approved procedures. The

activities included:

OPMP08-SI-0904, Revision 0, "HHSI Pump A Discharge Pressure

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Calibration (P-0904)"

PreventiveMaintenance(PM)IC-1-SI-86003948 Revision 2.C, "HHSI

Pump A Discharge Calibration"

PM MM-1-HF-89000869, Revision 0.B. " Fuel Handling Building Exhaust

Fan 11C Discharge Damper' Lube / Inspection"

The' inspectors determined through observations and procedure reviews

that approved procedures were being used, replacement parts were

properly certified. the equipment was properly returned to service, and

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housekeeping was being maintained. The inspectors also determined that

the technicians were familiar and knowledgeable of the work process and

the documentation was adequate to cover the process.

No violations or deviations were identified in this area of the

inspection.

7. Monthly Surveillance Observations (61726)

Selected surveillance activities were observed to ascertain whether the

surveillance of safety significant systems and components were being

conducted in accordance with Technical Specifications (TS) and other

requirements. The following surveillance tests were observed and

reviewed:

1 PSP 06-PK-0004, Revision 5, "4.16KV Class 1E Undervoltage Relay

Channel Calibration /TADOT-Channel 4," performed on 4.16KV Bus EIA

• 2 PSP 06-DJ0001, Revision 1, "125 Volt Class lE Battery 7 Day

Surveillance Test," performed on Battery E2C11

The inspectors verified that testing was performed using approved

procedures, final test data was within acceptance criteria limits,

housekeeping was maintained by the technicians, and test equipment was

within required calibration cycles. A technical review of the procedures

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was also performed, with no concerns being identified.

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No violations or deviations were identified in this area of the

inspection.

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8. Startup Test Witnessing and Observation (72302)

Selected Unit 2 startup tests were witnessed to ascertain conformance by

the licensee to procedural requirements, observe staff performance, and

. ascertain the adequacy of test program records. The tests that were

observed included:

• 2 PEP 04-ZG0002, Revision 0, " Loose Parts Monitoring System Baseline

Data"

2 PEPO 4-ZY-0070, Revision 1 " Test Sequence at 75% Power"

2 PEP 04-ZY-0072, Revision 0, "Incore-Excore Detector Calibration"

The inspectors monitored portions of the performance of the vibration and

loose parts monitoring system at the 90 percent reactor thermal power

level utilizing Procedure 2 PEPO 4-ZG-0002. The baseline data procedure

required data to be recorded for a minimum of 10 minutes at the 30-; 50 ,

75 , and 100 percent power plateaus, however, other plateaus were

included. The data were then used to produce power spectral density

signatures at center frequencies of 25 , 250 , 2500 , and 25,000Hz. The

procedure and signoffs were reviewed during and after the testing, as was

the calibration and setup of the equipment.

The data sheets and plots of each channel and frequency were reviewed and

found to'contain the required data. It was noted that two sensors had

become uncoupled from the reactor vessel and had been addressed in Problem

Report 89-113.

The inspectors continued the inspection of progressive testing of

equipment at various power levels in order to verify that the licensee was

correctly implementing the power ascension testing program.

The incore/excore cross calibration was performed at 75 percent reactor

power as specified in Procedure 2 PEP 04-ZY-0070 and as detailed in

Procedure 2 PEP 04-2Y-0072 and Field Change Request (FCR) 89-1510. The

purpose of the test was to determine the relationship between incore and

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excore axial offset, provide data for calibration of the excore axial flux

difference (AFD) amplifiers,andprovidedatatocalibratetheflux

(Delta = I) penalty to the over temperature, delta temperature protective

setpoints. The test method was as follows:

'*' Obtain a full core flux and thermocouple map with rods out.

Dilute Control Bank D inward and obtain quarter core flux map and

thermocouple map at each 2 percent decrease in AFD.

• Obtain full core flux and thermocouple map at 90 percent of axial

offset negative limit.

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Borate Control Bank D outward and obtain quarter core flux map and

thermocouple map at each 2 percent increase in AFD.

Obtain a full core flux and thermocouple map with AFD at its most

positive value.

On completion of the mapping, the data was reduced by computer to yield

incore/excore detector calibration values.

The inspectors witnessed the test preparation and the data acquisition.

The flux mapping used the standard Westinghouse data collection system with

the six channels recording simultaneously. Each flux det3ctor was fully

inserted and withdrawn. The detectors mapped the full leagth of the core

for each insertion. Each chart was stamped and identified and the data

sheets completed. All data were entered into the plant Proteus Ccmputer

from which further calculations were made for final data reduction and

comparison with test data.

On completion of the test and acquisition, the inspector reviewed the test

procedure for completeness through the step in the procedure that ended

the data collection (Step 6.30). The generated chart data were found to

be adequate in content and reflected the correct flux patterns that were

expected.

No violations or deviations were identified in this area of the

inspection.

9. Power Ascension Test - Plant Trip From 100% Power (72580)

The licensee performed a full load rejection test to demonstrate the

ability of Unit 2 to sustain a trip of the main generator from 100 percent

reactor thermal power. The test was performed using

Procedure 2 PEP 04-ZY-0102, " Plant Trip from 100% Power," Revision 0. The

inspectors witnessed performance of the procedure by the licensee. The

procedure provided instructions to record initial data prior to the plant

trip, to trip the plant, to record post trip data, and to perform a

posttrip review.

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Pertinent plant parameters were recorded to determine control system

response to the transient. A review of the posttrip data revealed all

acceptance criteria were met. However, two test criteria were not met:

the maximum pressurizer pressure recorded was higher than the initial

value by 41 psig (pressurizer pressure was expected to drop below the

initial value of 2235 psig), and the steam generator level for each loop

failed to drop out of the narrow range band. Subsequent evaluation and

feedback from Westinghouse disclosed that these two criteria had no impact

on the overall acceptability of the test. i

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Other observations made during the test included: the reactor coolant

system (RCS) cooled down to SEB*F. 9'F-lower than the no-load value of

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567'F, because of the slow. closure time of the moisture separator reheater

~ .temocrature control volves; an auxiliary feedwater regulating valve

,s ... indicated partially open while fully closed; and the digital rod position

' indication (DRPI) gave an erroneous flashing. general warning light for a

control' rod.that was full in.following the reactor trip. The licensee and

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c . Westinghouse reviewed and analyzed the cooldown from 567"F to 558"F. The

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cooldown was greater.than anticipated, but within the acceptance limits

for the test.

The effect of the Unit 2 trip'was noticed in the Unit 1' control room. A

variation in electrical grid frequency was recorded. Frequency dropped

from 60 to 59.7Hz, then returned to 60Hz. Several alarms were

momentarily received in the Unit I control room, including inverter

trouble, annunciator ground detected, and plant computer inverter failure

alarms.

A review of Procedure 2 PEP 04-ZY-0102 was performed. The procedure was

compared to licensee commitments, including Final Safety Analysis

Report Section 14.2.12.3.23, " Full Load Rejection Test."

No violations or deviations were identified in this area of the

inspection.

10. Exit Interview

The inspectors met with licensee representatives (denoted in paragraph 1)

on July 6, 1989. The inspectors summarized the scope and findings of the

inspection. The' licensee did not identify, as proprietary, any of the

information provided to, or reviewed by, the inspectors.

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