IR 05000498/1990024

Insp Repts 50-498/90-24 & 50-499/90-24 on 900701-0801.No Violations Noted.Major Areas Inspected:Plant Status,Onsite Followup of Events at Operating Power Reactors & Licensee Action on Previous Findings

ML20056B325
Person / Time
Site:	South Texas
Issue date:	08/17/1990
From:	Joel Wiebe NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION IV)
To:
Shared Package
ML20056B320	List: IR 05000498/1990024 ML20056B319
References
50-498-90-24, 50-499-90-24, NUDOCS 9008280127
Download: ML20056B325 (15)

Text

_

_ . .s ,.

_ .. ,.

.. .

.

-

g 1,

_

APPENDIX J ,

c U.S. NUCLEAR REGULATORY C0'NISSION JL REGION IV

_

NRC Inspection Report: 50-498/90-24 Operating License: NPF-76 50-499/90-24 NPF-80 Dockets: 50-498 i .50-499 L

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

P.O. Box 1700 '

E Houston, Texas 77261 e

Facility Name: South Texas' Project (STP), Units 1 and 2 L ' Inspection At: STP, Matagorda County, Texas

? Inspection Conducted: July 1 through August 1, 1990

-

Inspectors: J., I. Tapia, Senior Resident Inspector, Project Section D

- Division of Reactor Projects

_

R. J. Evans, Resident Inspector, Project Section 0

'

Division of Reactor Projects

-

Approved: /d

_

W1cbe, chief. Project Section D Datel vision of Reactor Projects

.

InspeltgnSummary

-

.ir.spection Conducted July 1 through August 1, 1990 (Report 50-4M/90,-24;

_

50-499/90-24)

e Areas inspected: Routine, unannounced inspection including pilant status,

' onsite followup of events at operating power reactors, licensta action on 1 previous inspection findings, operational safety verificatian, month'y if surveillance observations, and monthly maintenance observation Results: Within the areas inspected, no violations were identified. The frequency of events at the South Texas Project continued to be high. Unit 1 T- experienced three reactor trips and two Notices of Unusual Event resulting from i- Technical Specification-required shutdowns. Unit 2 was voluntarily shut down g to repair a main turbine bearing and a steam generator power-operated relief M valve. This valve problem had the potential to cause a Technical Specification-required shutdown if the phnt had not been shut down voluntarily. System

}= walkdowns were performed on three plant synems, the Units 1 and 2 reactor

,

makeup water systems and the Unit 1 mechanical auxiliary building chilled water system. All components were observed to be in a position to support system QB2$$

(

e  ;

-

..

_ - - - - _

.

.... wi,,

,. .-

,

,.- ,

,

j- >..

,

p t-

4 s

.,

2 i

.

l F

i~ , operation, except one nonsafety-related flow valve. Housekeeping and equipment '

condition were generally being maintained in the areas of the plant that were visited. Three surveillance and three maintenance activities ;; re observe ' The technicians appeared knowledgeable and conpetent and their actions were .

noted to be conservative.in nature. One example of incomplete documentation of

"k '

,

e * a ' safety-related cable lug termination was observed. However, the licensee r: took prompt corrective actions when informed of the inciden .

I f

I (

n b

..es, .

E ,, . .

. ,

,

.

DETAILS Persons Contacted

• G. E. Vaughn, Vice President Nuclear Generation

• J. R. Lovell, Manager Technical Services

• C. G. Sayko, Manager, Planning and Scheduling

• D. A. Leazar, Manager, Plant Programs

• A. C. McIntyre. Manager, Design Engineer

• W. J. Jump, Maintenance Manager .

• S. M. Dw. Manager Nuclear Purchasing and Material Management

"C. A. Ayala, Surarvising Engineer, Licensing

• M. A. McBurneta, ikclear Licensing Manager

• M. Wisenburg, General Manager Assestgent

• J. T. Westerneier, General Manager Site Facilities

• L. G. Weldon, Manager, Operations Training

• L. Giles, Manager, Unit 2 Plant Operations

• A. K. Khosla, Senior Engineer, Licensing

• J. D. Green, Manager, Nuclear Quality Control and Maintenance

• t. W. Harrison, Supervising Engineer, Licensing

• D. F. Bednarczyk, Consulting Engineer. Independent Safety Engineering Group In addition to the above, the inspectors also held discussions with various licensee, architect engineer (AE), maintenance, and other contractor personnel during this inspectio i

• Denotes those individuals attending the exit interview conducted on l August 1, 199 . Plant Status l Unit 1 began this inspection period increasing power 'n a systematic approach to 100 percent after having gone critical on June 28, 199 The unit experienced a reactor trip from 99.7 percent *eactor power on July 2,1990, when the overtemperature delta temperatut e protective circuitry coincidence was satisfied. After a posttrip eview, the unit was again restarted and reached 100 percent power on July 6,1990. On July 7,1990, the licensee declared a Notification of an Unusual Event (NOVE) as a result of a Technical Specification-required shutdown when Feedwater Isolation Valve (FWTV) 1A failed to partial stroke during q surveillance testing. After having reduced power to 92 percent, the FWIV ;

was repaired, the NOUE was terminated, and the reactor was again brought to 100 percent power. On July 16, 1990, the unit tripped from 100 percent power as a result of a faulty test switch in the solid state protection system. The test switch was replaced and the unit was again taken critical on July 18, 1990. On July 19, 1990, the plant was at 10 percent power and '

operators were attempting to synchronize the generator to the grid when a loss of powr to a main feedwater pump and a reactor coolant pump occurred as a result of operator error. A NOUE was declared and reactor power was reduced to the point of adding heat. After stabilizing the plant and

i

, . . , .

- .

',

,

restoring power to the pumps, reactor power was increased on July 12, 1990. Dr. July 30, 1990, the unit was manually tripped from 100 percent power when the "A feedwater isolation valve went fully closed during a surveillance tes The unit remained in Mode 3 at the end of the inspection perio Unit 2 began this inspection period at 100 percent power. On July 5, 1990, the unit was taken off line and a controlled shutdown was conenenced as a resu" ' elevated temperatures in a main turbine bearing and an inoperaf r sto generator power-operated relief valve. After repairs wera cc ,A eter .he unit was again taken critical on July 12, 1990, and '

,

reached e < cent power on July 14, 1990, where it remained at the close of this , s ction perio '

3. Onsite Followup of Events at Operating Power Reactors (93702)

On July 2, 1990, at 6',10 p.m. (CDT), Unit 1 tripped from 99.7 percent powe Operators had just completed a power increase from 88 percent power and .

'

erforming a Loop 4 delta temperature analog channel operating)

test p(ACOT). Channel 4 of overtemperature delta temperature (OT/DT were was, therefore, out of service with its bistables tripped. The reactor trip occurred when Channel 3 of OT/DT came in and satisfied the 2-of-4 logic necessary for a reactor trip. Subsequent, investigation identified a slow decrease in reactor system pressure which started about 10 minutes :

before the trip. This pressure decrease of approximately 3 pounds per minute brought reactor pressure from 2214 to 2180 psig. The slow decrease in pressure resulted when reactor operatori elected to remove Pressurizer Heater 1E from service in order to reduce spray flow in the pressurize The pressure decrease caused the OT/DT setpoints to decrease. The pressurizer pressure is controlled by one of two available pressure channels. The channel selected (Loop 1) was reading higher than the ,

=

others. These pressure channels also have input to the OT/DT setpoin Since controlling pressure was on a higher channel, the remaining channel OT/DT setpoint was allowed to drift low. Due to the decrease in reactor coolant system (RCS) Pressure Loop 3, OT/DT tripped when the setpoin reached the actual delta temperature. Since Loop 4 OT/DT was already tripped to perform a surveillance, the Loop 3 trip satisfied the 2-of-4 coincidence to initiate a reactor trip. A feedwater isolation occurred on low average RCS temperature and an auxiliary feedwater system actuation occurred on low steam generator level as expected. The main steam isolation valves were manually closed to limit the cooldown and the plant was stabilized in Mode 3. The RCS temperatures and pressures were within the allowable margins prior to and during the tri Subsequent to the trip, the Loop 3 pressure transmitter was calibrated ,

and found to be in tolerance. The pressurizer pressure controller was also calibrated and found to be in tolerance. Appropriate steps of the reload initial startup testing procedure were performed which verified that delta temperature calculationt were accurate. The Loop 4 delta temperature calibration was also to'P l eted satisfactorily,

f

.. ,.

.

r .

i' 5  :

'

The investigation disclosed that this event occurred due to less than adequate attennion to the decreasing margin to the OT/DT trip setpoint ;

during power at.cension. The operators did not recognize the combination of events that effected the reduction of the setpoints and the parameter differences which decreased the margin. As a result of ~ie posttrip investigation, the procedures controlling power ascens a were revised to require specific determination and monitoring of the 01/DT margin to trip '

at 90 percent and 98 percent power and to prevent proceeding with power -

ascension unless limits are met. The procedure was also revised to require that all channels of OT/DT be operable at 90 percent power prior to proceeding with power ascensio '

On July 7,1990, with Unit 1 at 100 percent power, the licensee declared ,

a NOUE because of a condition requiring a plant shutdown per TS 3.0.3. The licensee was performing a surveillance test on the feedwater isolation valves when the "A" feedwater isolation valve failed to stroke. The hydraulic solenoids of the valve would not open to allow the hydraulic .

fluid pressure to decrease. Two valves are provided in each feedwater line entering the containment. One is a swing check valve while the other is a hydraulically-operated, fail-closed, stop valv The licensee entered into TS 3.6.3, which requires the valve to be restored to operable or, within 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br />, close and deactivate the automatic valv ;

Because the licensee could not isolate the FWIV without causing a reactor trip on low steam generator level, the licensee entered TS 3.0.3. A NOUE was declared at 11:15 p.m. because of the shutdown requireo the TS.

,

L The licensee restored the isolation valve to operable by reducing the

,

valve accumulator pressure from 2800 psig to 2000 psig. The licensee subsequently exited from the NOVE. Reactor power had been reduced to 92 percent.

,

l The FWIVs are hydraulically operated with a nitrogen charge in the upper

! cylinder. The hydraulic reservoir is a 125-gallon tank and nitrogen

'

charge is at 750 psig, nominally, with the FWIV fully closed. Upon receipt of an "open" signal, two trains consisting of two pumps, one electric motor-driven and one air-driven, pump hydraulic fluid to the l lower cylinder housing causing the piston to rise. This force, transferred I to the gate assembly via the stem, causes the assembly to rise, opening l

the valve. The upward force compresses the nitrogen, sealed in the upper

'

cylinder, until it reaches a pressure of approximately 1500 psig. The valve should be near fully oper and the electric pumps will stop. The air-driven pumps will operate automatically to maintain set pressure and make up for internal leakage.

i When the system receives an isolation signal or a loss of power, dump valves will open allowing hydraulic fluid to flow back to the reservoi The force of gravity aided by the compressed nitrogen will drive the piston downward, closing the valv ,

,.o o,.

• '.

,

.

Normal operating pressure of the hydraulic fluid is approximately 2000 psig but had been increased to approximately 2800 psig by manually operating the air-driven pumps to ensure that the valve was fully open in support of l the tes ,

<

When the operat.or depressed the FWIV (nterlock button, the valve should have closed but remair:d fully open. Plant operations personnel believed :

the problem to be with a relay and began troubleshooting efforts in the ;

control cabinet .

I System engineers were notified and, af ter observing the situation, released the inlet seal to the air operated pump to depressurize the hydraulic

'

fluid. Once the pressure was dropped to approximately 2000 psig, the valve functioned normally. Initially, it was believed the hydraulic pressure was too high but conversations with the vendor indicated these valves are tested for 2070 strokes at 2850 psig during the cyclic aging portion of the equipment qualification tes On July 11, hydraulic stroke tests for Unit 2 FWIVs were conducted with all valves satisfactorily stroked at 2950 psig. This is 150 psig greater ,

than the pressure noted during the surveillance test for FWIV 1A. On July 16. Unit 1 FWIVs were tested satisfactorily. These tests indicated that there is not a generic problem with these valve Observation of the hydraulic system on FWIV 1A did not reveal any abnormal conditions but it is believed that a problem may exist with the dum)

valves which should have allowed the hydraulic fluid to return to t1e reservoir. The licensee, therefore, has replaced the solenoid operated dump valves and is sending the removed valves to the vendor for further investigation. With respect to the TS requirement for shutting down, a change has been submitted by the licensee to remove the FWIVs from.TS 3. and address them separatel On July 16,1990, at 2:36 a.m., Unit 1 tripped from 100 percent reactor power. The trip was caused by a faulty multiplexer test switch in the Train S logic cabinet of the solid state protection system (SSPS). Plant ,

operators were in the process of performing a surveillance on Train S i reactor trip breaker. The surveillance, a trip actuating device operational test (TADOT), verifies the Train S automatic tri) function of Train S reactor trip breaker. This, in part, satisfies tie TS surveillance for the reactor trip breaker and for the reactor trip bypass

'

breaker. During the performance of the test, Train S SSPS Logic Test Panel Logic Switch A is placed in Position 7 in order to create a Train S urgent alarm. In following steps, this switch is returned to the 0FF position. Interviews determined that logic Switch A was physically turned to the 0FF position but contact may not have been broken and the urgent alarm remained energize In a subsequent step, a multiplexer test switch is required to be placed from the normal to the R+S position for SSPS Train R Logic Cabinet (ZRR-011). This switch is a three-position switch (normal, inhibit, R+S)

..c*,.

.

r ', . -

and will cause a Train R urgent alarm. Since the Logic A switch for Train S had not broken contact, two of two SSPS train trip signals were initiated when the multiplexer test w1Mh was moved through the inhibit position, which caused t4e trip. It 6: not noted, until after the perfomance of this step, that the Train S urgent alarm had not cleare No verification step was required to ensure that the Train S urgent alam is disengaged prior to engaging the Train R train trip circuit. It was noted that more than one switch will engage an urgent alarm, (i.e.,

Logic A switch, multiplexer test switch, permissive switches, etc.). The Logic A switch was detemined to be the switch which had failed after it was adjusted and the urgent alarm indicator was noted to extinguis The primary cause of the trip was the failure of the Logic A switch for Train S urgent alarm (Train 5 trip circuit). A contributing cause was the.t a verification step was not included in the surveillance test procedure to ensure that urgent alarms for Trains R and S would not be engaged simultaneousl Accordingly, the licensee repleced the faulty switch and also revised all other procedures which operate multiplexer test switches to verify that no urgent alams are engaged prior to rotating the switch through the inhibit positio On July 19, 1990, at 9:10 a.m., Unit 1 experienced a NOUE due to a plant shutdown required by TS 3.4.1.1. Plant operators were making preparations to synchronize the generator to the grid with '.he reactor power at 10 percent. Part of these preparations was to transfer power from the auxiliary transformer to the standby transforn.ers in order to preclude a loss of power to vital equipment should a generator lockout occur upon synchronization. After having closed the breaker from the Unit 2 standby transformer to the 1H standby bus, the reactor operator was to then open .

the breaker from the Unit 1 standby transformer and close the tie breaker l between the standby bus and the auxiliary bus. The reactor operator performing this transfer inadvertently opened the unit auxiliary transfomer to the Auxiliary Bus 1H supply breaker instead of opening the Unit I standby transfomer to the Standby Bus 1H supply breaker. These breaker switches are located next to each other. This error was apparently ;

the result of applying the steps of the IJ transfer procedure (Bus 1J has no tie breaker or separate standby bus) to the IH bus. This error caused a loss of power to No. 11 main feedwater pump and the "C" reactor coolant pump. Because of the shutdown requirement in TS, reactor power was reduced to the point of adding heat by insertion of the control rod Operators then stabilized steam generator levels and restarted the "C" reactor coolant pump at 10:15 a.m., thereby exiting the action statement of TS 3.4.1.1 and terminating the NOVE, The licensee conducted an evaluation of the methodology for transferring buses from the auxiliary transformer to the standby transformer and issued instructions to the operators to close the tie breaker first in order to reduce the effect of an error. These instructions were implemented and the licensee again commenced a power increase at approximately 3 p.m. on July 19, 1990, i

- -

..c*,.

s

. ,f-

.

f

At 7:48 p.m. on July 30, 1990 Unit I was manually tripped when the

"A" FWIV fully closed during a surveillance procedure. The surveillance was being perfonned to verify that both the pennanent test circuitry and the electrohydraulic control fluid solenoid dump valves were operating correctly. This surveillance is accomplished by stroking the FWIV from fully open to 90 percent open and then back to fully open. The instrument and control technician inadvertently made contact with Terminal Block No. 10, causing the FWlV to fully close. Control room operators manually tripped the reactor when Steam Generator A level reached 40 percen An automatic reactor trip would have occurred at a level of 33 percen Subsequent to the trip, control room operators noted that the level in Steam Generator A was continuing to decrease even with auxiliary feedwater in service and feeding at 600 gpm. A reactor plant operator was dispatched to the auxiliary feedwater pump to attempt to identify the proble Meanwhile, AFW Pump No. 11 was secured and Steam Generator A was fed through the cross-connect valve. Steam Generator A level decreased to 35 percent before the level stabilized and started to increase. After verifying the integrity of the piping and the pump, the dispatched operator discovered that the long path recirculation valve was in the locked open position when it should have been in the locked closed position. This was causing auxiliary feedwater to be pumped back to the auxiliary feedwater storage tank instead of into the steam generator. The recirculation valve was repositioned and AFW was then established to Steam Generator IA via No. 11 AFW pump. The valve restoration took about 40 minutes. All other manual recirculation valves associated with ESF functions were verified to be locked closed in both unit The above event will be reviewed and discussed in detail in NRC Inspection Report 50-498/90-28; 50-499/90-28. The licensee's short-term corrective actions for all of the events were reviewed and found to be acceptable to restart the plant. The licensee's long-term corrective actions will be reviewed in detail during a future inspection after the licensee submits the required licensee event repor . Licensee Action on Previous Inspection Findings (92701)

(Closed)OpenItem(499/8870-02): Incomplete Documentation of postaccident Sampling System Components During a previous inspection, a review was performed on components supplied by subvendors for the Postaccident sampling system (PASS). Parts lists, drawings, and maintenance instructions were not provided by subvendors for selected PASS components. The procurement of the applicable documentation for these components was being tracked by the licensee but were not available for review at the time of inspection. This subject area was then considered an open item (499/8870-02).

During this inspection, the licensee's responses to the open item were reviewed. Actions completed by the licensee included: (1) the missing )

technical information was received from the primary vendor, APEX l

'

Technologies, Inc.; (2) the documentation that was received was added

,

u

,..+ ,- .-

,

,

,!

'

,

i

l to the PASS vendor manual via document change notices; (3) a new ion chromatograph was purchased b manual was obtained; and (4) y the licensee and an updated instruction added to the licenste's master parts list.all tubvendor supplied components were by the NRC inspector during the documentation review.No concerns were identified This open item is close (Closed)OpenItem(498/8801-10): Implementation of a Formal Process to Perform Quality Checks on the Surveillance scheduling computer Data Base During the January 1988 operational readiness team inspection, a concern was identified with the computer data base that was used to schedule surveillance Because no routine formal quality checks were required to be performed, errors could be introduced into the program which might go undetecte These errors had a potential of preventing a given surveillance requirenent from being perfonted at the right time. The licensee committed to performed these checks on a formal basis and an open item (498/8801-10) was generated to track the licensee's action The licensee's response to the open item was reviewed during this inspection period. Actions that were taken by the licensee included:

Procedure OPGP03-ZA-0055, " Plant Surveillance Scheduling," described the administrative structure and division of responsibilities for the scheduling of periodic TS surveillance requirenents. The procedure was revised to: (1) establish responsibilities for assuring the integrity of the surveillance data base was being maintaine (2) procedurally ensure the surveillance connitments were correctly scheduled, and (3) provide instructions on how to incorporate revisions into the surveillance data bas *

A validation and verification of the surveillance tracking application (software April 1989.package that schedules the surveillances) was completed in

A users guide was developed for the computerized surveillance test progra *

Audits of the surveillance data base were performed, and documentation existed that indicated that this annual audit was last completed in December 198 No concerns were identified by the NRC inspector during the revie This open item is close Operational Safety Verification (71707)

The purpose of this inspection was to ensure that the facility was being operated safely and in conformance with license and regulatory

..____ _ __ _ _ _ --------- -- - -

_

'

< . . , .

l ',. .

'

.

requirements. This inspection also included verifying that selected

'

activities of the licensee's radiological protection program were being implemented in conformance with requirements and procedures and that the licensee was in compliance with its approved physical security pla The inspectors visited the control rooms on a routine basis and verified that contN1 room staffing, operator decorum, shif t turnover, adherence to TS limiting conditions for operation (LCOs), and overall control room decorum were in accordance with requirements. The inspectors conducted tours in various locations of the plant to observe work operations and to ensure that the facility was being operated in conf orman:e with license and regulatory requirement As the part of makeup reactor the operational safety (verification portion of the inspection,RM) for both Units 1 water systems

'

to verify the operability and status of the systems. The inspection included comparison of as-found control switch, power supply breaker, and valve positions to those required by the operating procedures and piping and instrument diagrams (P& ids). The procedures reviewed and walked down included IPOP02-RM-0001, " Reactor Makeup Water System Standby Lineup,"

Revision 4 for Unit 1; and 2 POP 02-RM-0001, " Reactor Makeup Water System Standby Lineup," Revision 1, for Unit Items noted during a technical review of the RM systems included:

Operational instructions for the reactor makeup water pump room j

air handling (unit fans were listed in both the RM system OperatingProcedures 1 2)

fleating ProceduresVentilation and Air Conditioning 1(2) POP 02-HM-0001, (Operating Revision 5 2).

• The locations of disconnect switches in the electrical lineup was noted to be incompl' *e. Only the panel was listed, and the building locations of the panels were missin *

Identical typographical errors (typos) were observed in both procedures. This implied that typos present in the Unit 1 procedure were overlooked and carried over to the Unit 2 procedure when the i procedure was developed. This indicated a lack of attention to detail during procedure development and review. The inspector determined that none of the typos were detrimental to system  !

operabilit Items noted during a walkdown of the RM systems included:

The Unit 2 reactor makeup water storage tank level was noted to be 94 percent, however, Step 4.4 of the operating procedure provided instructions to maintain level between 60-90 percent. This higher-than-recommended level did not result in a safety concer :

,...,.

'

.

e-

.

. ,

• The valve handwheel for 2-RM-0022, boron recycle evaporator isolation valve, was noted to be jammed against an adjacent pipe. Repositioning the valve would have required handwheel remova *

A bag of clecning rags was found stuffed overhead on pipes located l in the nerhanical auxiliary building, Room 1088, of Unit *

The procedure valve lineups provided instructions to verify that process sampling TPiw Control Valves 1(2)-RM-FV-7664 were open, r However, local or remote indictions were not provided with the valve due to valve design, thereture, the valve positions could not be verified as open or shu The Unit 1 mechanical auxiliary building (MAB) chilled water system (CH) ,

was also inspected to verify the operability and status of the syste The inspection included a comparison of as-found control switch, power ;

'

supply breaker, and valve positions to those required by the operating procedure (IP0P02-CH-0002, "MAB Chilled Water System," Revision 7) and the system P&lD Items noted during a technical review of the MAB CH system included:

Several procedural mistakes were observed: (1)inValve Lineup 1 POP 02-CH-0002-1, incorrect names or locations (most due to typos) were observed for Valves 1-CH-1216. -1173, -1546, -0326. -1255-0181, -1261, and -0351; (2) Valves 1-CH-0413 and -0474 were listed twice in the valve lineup; (3) selected chiller handswitches were listed in the electrical lineup but should have been listed in the switch lineup; and (4) incorrect device numbers (due to typos) were listed for Panels DPS134 and DPK245 in the electrical lineu *

The Chiller 11C eva) orator outlet drain valve was shown as 1-CH.0138 on the system P&lD aut was listed as 1-CH-0318 in the procedure valve :

lineup and in the plan '

-

• Drain Valves 1-CH-0413 and 1-CH-0415 were normally shut vtives that were incorrectly shown as normally open on the system P&I Items noted during a walkdown of the MAB CH system included:

• MAB Chiller Condenser Flow Valve 1-CH-FV-9318 was a normally open valve that was found shut. This nonsafety-related valve was out of position but did not affect system operability.

L l

• Burned out status light bulbs were observed on the operating MAB L Chilled Water Chillers llB and 110. Two status lights on each chiller i required bulb replacemen * Valve 1-CH-1553, dr separator vent valve, was missing from the Valve Lineup 1 POP 02-CH-N02- The valve was found in the correct position to support system operation.

<

l

. _ _

, _ .

. .o*,.

'

,

• ..'

'

..

'

' A total of nine valves were found to be missing their identification tags, including 1-CH-1710, -1711, -1545 and six chiller evaporator pressure switch valves (no unique numbers were provided for these six valves).

Twelve chiller condenser vent or drain valves were listed in the MAB CH valve lineup, but these 12 valves were tagged es open loop auxiliary cooling water (OC) system valves in the plant. These 12 valves have since been deleted from the MAB CH valve lineu All components of the Units 1 and 2 RM systems and the Unit 1 MAB CH systems were in the correct positions to support plant operation, with the exception of one nonsafety-related flow valve (1-CH-FV-9318). The items noted b, the inspector did not appear to directly impact safe operation of the plant. All procedural observations were referred to the licensee for inclusion in the licensee's long-term program for procedure upgrad No violations or deviations were identified in this area of the inspectio . Monthly Surveillance Observations (61726)

Selected surveillance activities were observed to ascertain whether the surveillance of safety significant systems and components were being i conducted in accordance with TS and other requirements. The following surveillance tests were observed and the documents reviewed:

!

• OPSP02-FW-0547, Steam Generator D Narrow Range Level Set 4 Analog >

Channel Operational Test -(ACOT), Revision 0

'

.

• 2 PSP 02-NI-0044, Power Rangs Neutron Flux Channel IV ACOT, Revision 1 2 PSP 02-CM-4105, Containment Hydrogen Analyzer ACOT, Revision 0 Specific items inspected included verifying that as-left data was within acceptance criteria limits, test equipment used was within current

calibration cycles, and test performers were adhering to approved procedures. In addition to observation by the inspector of the L

surveillance activities, the procedures were reviewed for technical !

l accuracy and for conformance to TS requirements.

l Procedure OPSP02-FW-0547 was a monthly surveillance that was performed

by I&C technicians. The procedure provided instructions to verify that the Unit 1 Steam Generator ID (Channel C) Hi-H1 (87.5 percent) and l Lo-Lo (33 percent) trip setpoints were within TS limits. The setpoints

'

were found to be within acceptance criteria limits and no concerns were identifie Procedure 2 PSP 02-HI-0044 was a quarterly surveillance that was performed by I&C technicians on the Unit 2 Channel IV power range neutron flux circuitry. The procedure provided instructions to verify that the neutron

[

,

i

-

+y i

'

. . , < , , 7

, '

• *

.y ,

. .

-

r

,

-flux reactor trip setpoints were within TS limits. The following observations were noted by the inspector and reported to the licensee:

A trace recorder was used to plot voltage versus time to determine the power range rate circuit time constant. The trace produced by-the recorder was noted to be unusually light in color. The recorder pen should have been replaced to allow the recorder to produce a more readable trac "

While plotting the rate circuit time constant, fluctuations in,the~  ;

graph were recorded because of actual power fluctuations. Specific points on the graph were difficult to pinpoint due to che fluctuations in the graph's line. However, the technician's actions were noted to .

be conservative in nature while trying to extrapolate a single point

'

from the fluctuating chart lin *

The procedure provided instructions to the technicians to record the high range overpower trip. The allowable tolerance for the trip setpoint was plus or minus 1 percent, however, the meter was noted to fluctuate (due to actual power fluctuations) up to 1 percen The readings taken by the technicians were again noted to be conservativ Procedure 2 PSP 02-CM-4105 was a monthly surveillance that was r,erformed by I&C technicians on Unit 2 Containment flydrogen Analyzer C2-CM-AIT-410 The procedure provided instrc:tions to' verify that the containment hydrogen Hi(3.25 percent)andHi-H1(3.5 percent)alarmsetpointswerewithin , '

acceptance criteria limits. The following observations were made and reported to the licensee:

Step 4.1.a required the technicians to obtain two multimeters fo use during the surveillance, however, only one was needed to perfonn the tes _

i

Step 7.5.4 provided instructions to disconnect Leads 30 and 31 from Terminal Board TS1, but Terminal Board TS1 was not labelled in the plant. The correct board was located by tracing wires to the boar *

Step 7.8.6lights indicators p(rovided on orinstructions to verify off as required), but the status failed of localapanel to mention light labelled " Low Gas Pressure" that was located on the same pane This missing reference to the light had no effect on the performance of the ACO * A switch was installed on Local Panel ZLP-154 with positions labelled

"0FF-0N-0N." The same switch was labelled " STANDBY-0FF-ANALYZE" in the vendor manual. Additionally, the switch label was located on the opposite side of the switch from the normal location because there was a t room for the. label on the normal side of the switch. The licensee stated that corrective actions would be taken to revise the local switch labe ,

l

. - ._ _ . _ - _ _ - _ - -

r '

'

,.i.,-

'

.

..  !

• >

.

.

!

Licensee personnel who perfomed the surveillance activities: (1) appeared

'

knowledgeable and competent; (2) understood the intent of the surveillance; 1 were conservative in their actions.used proper test equipment; (4) adhered to No violations or deviations were identified in this area of the inspectio Monthly Maintenance Observations (62703)

' Selected maintenance activities were observed to verify whether the activities were being conducted in accordance with approved procedure The activities observed included:

'

PreventiveMaintenance(PM)EM-1-EW-90000694, Essential Cooling  !

Water Pump'1A Discharge MOV0121 Relay Calibration ';

Work Request (WR) NZ-78520 Saniple Testing of Comercial Grade Relays Prior to Stocking ,

• *

WR CH-!28881, Replacement of Essential Chiller 21B Discharge Temperature Shutdown Switch The inspector verified that the activities were conducted in accordance ;

with approved work instructions and procedures, test equipment was within the current calibration cycles, and housekeeping was being conducted in an ar:ceptable manner. All observations made were referred to the licensee for appropriate actio ,

PM EM-1-EW-90000694 was performed by electrical technicians on Agastat Relay A1PMMCEA3F3 (Device 2-1). Procedure OPMP05-ZE-0046, " Calibration of '

Agastat Timers," Revision 3, was used in conjunction with the PM. The relay was tested and was found out of tolerance. The relay was subsequently adjusted but failed the repeatability tests. WR EW-93983 was :

written to replace the relay and the new relay was retested. No significant concerns were identified by the inspector during the performance of this P WR N7-78520 was performed by electrical technicians on 6 of 52 relays '

that were purchased commercial grade. Sample testing of the 52 relays was required prior to stocking the parts in the warehouse. The relays were tested for pickup and drcpout times and voltages. A resistance check and visual inspection for damage was also performed. All 6 relays ,

failed to meet acceptance criteria requirements. Five of 6 relays were tested several times with inconsistent results. A receipt inspection deficiency report was subsequently written to evaluate the failures. The inspector planned to review the deficiency report following dispositio No other concerns were identifie WR CH-128881 was performed by I&C technicians on Temperature i

Switch B2-CH-TSH-9421. Essential Chiller 21B had previously tripped on

'

high compressor discharge temperature. A vendor representative recommended

_

, * r *. , s

.

.- ,

.

repair or replacement of the discharge temperature shutdown switch. Due to time constraints, the work consisted of testing a new switch, replacing the old switch, and performing followup testing on the old switch. The ,

old switch was found to be in good working order, so the work performed by the WR was an unnecessary, but conservative, action. The chiller was subsequently restarted, air was purged from it, and some Freon was adde The chiller compressor operated satisfactorily and the chiller was returned to service. A task force was recently established by the licensee to address long-term issues for all safety and nonsafety-related chiller This event will be considered when addressing these issue '

Step 3.03 of the work instructions stated, "Determ and remove switch B2CH-TSM-9421 in accordance with procedure OPGP03-ZM-0021."

Step 3.06 stated, " Terminate B2CH-TSH-9421 in accordance with procedure OPGP03-ZM-0021." Procedure OPGP03-ZM-0021 " Configuration ;

Change Log," Revision 3, was the governing procedure used for documenting the lifting and landing of leads. The new switch that was installed did not have ring lugs on the switch wires. The technicians installed new

,

ring lugs obtained from the ware'ouse with a calibrated crimping too Following work completion, the work package was reviewed by the inspecto No reference was made in the WR or remarks section of the WR to the ring lug terminations, except that the crimper was listed in the test equipment column and the ring lugs used were listed in the spare parts colum Procedure OPMP02-NZ-0013. " Cable Terminations " Revision 1, was the governing procedure that was to be used for documenting ring lug terminations, not Procedure OPGP03-ZM-0021. The work packare did not include Cable Termination Data Sheet OPMP02-NZ-0013-1, whic's is used to document the crimping sequence and acceptance criteria. The inspector

'

determined that the I&C technicians had incompletely documented a cable lug termination. The WR failed to provide specific instruttions on performing the ring lug terminations and fai4ed to reference Procedure OPMP02-NZ-0013. However, a safety concern did not exist because the terminations were performed by a qualified technician and the terminations were inspected by a quality control inspecto When informed of the inadequately documented cable lug terminations, the licensee: (1 wrote a station problem report to investigate and documant the concern, }'!) revised WR CH-128881 to properly document the replacement and crimping of the ring lugs, and (3) verified the terminations made were of acceptable quality per OPMP02-NZ-001 No violations or deviations were identified in this area of the inspectio . Exit Interview The inspectors met with licensee representatives (denoted in paragraph 1)

on August 1, 1990. The inspectors summarized the scope and findings of the inspection. The licensee did not identify as proprietary any of the infonnation provided to, or reviewed by, the inspectors.