IR 05000498/1989019

Insp Repts 50-498/89-19 & 50-499/89-19 on 890619-23.No Violations or Deviations Noted.Major Areas Inspected: Followup,Review & Evaluation of LERs & One Open Item

ML20246P137
Person / Time
Site:	South Texas
Issue date:	07/05/1989
From:	Holler E, Hunnicutt D NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION IV)
To:
Shared Package
ML20246P068	List: IR 05000498/1989019 ML20246P063
References
50-498-89-19, 50-499-89-19, NUDOCS 8907200116
Download: ML20246P137 (16)

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APPENDIX ,-

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U.S.~ NUCLEAR REGULATORY COMMISSION' j f

REGION IV

NRC Inspection Report: 50-498/89-19 Operating Licenses:

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NPF-76 l 50-499/89-19 NPF-80 ,

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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 19-23, 1989 Inspector: f/I nan # 7/5f89 '

D. M. Hunn'icutt, Senior Project Engineer Date /

Project Section D, Division of Reactor Projects

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Approved: . .- 4- - -

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- J./Holle'r, Chief, Project Section D Date'

Division of Reactor Projects i-Inspection Summary '

Inspection Conducted June 19-23, 1989 (Report 50-498/89 49)

Area Inspected: Routine, mannounced inspection of followup, review, and evaluation of licensee event reports (LERs) and one open ite Results: Within the area inspected,.no violations were identified. The licensee's corrective actions; including design changes, procedure preparations and revisions, equipment modifications, component and equipment installations, > testing to reso've the.LERs and one open item; were appropriate and had been completed. The licensee has shown definite improvement in the reduction of

spurious control room ventilation recirculation actuations due to toxic gas analyzer malfunctions during the last 6 month PDR ADOCK 0500 498

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Inspection Conducted June 19-23,'1989 (Report 50-499/89-19)

Area Inspected: . Routine, unannounced inspection of followup, review, and evaluation of licensee Incident Response Committee (IRC) Reports end one LE Results: Within the area inspected, no violations were identified. The licensee's corrective actions; including design changes, procedure preparations and revisions, equipment modifications, component and equipment installations, and testing to resolve the IRCs and the LER; were appropriate _and had been complete!. All IRCs for Unit 2 have been completed, reviewed, evaluated, and closed.

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DETAILS- Persons Contacted Houston Lighting & Power Company

• M. R. Wisenburg, Plant Superintendent

.*M. A. McBurnett, Licensing Manager

-*C. A. Ayala, Supervising Licensing Engineer

• A. Khosla, Senior Licensing Engineer

• S. D. Phillips, Staff Licensing ~ Engineer NRC

• J. I. Tapia, Senior Resident Inspector In addition to the above, the NRC inspector also held discussions with various licensee, architect / engineer (A/E), maintenance, and other contractor personnel during this inspectio * Denotes those individuals attending the exit interview conducted on June 23, 198 . Onsite Followup of Written Report of Nonroutine Events at Power Reactor

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Facilities - Unit 1 (92700)

(Closed) LER 87-18: " Initiation of Cooldown Due to Inoperability of Two Trains of Containment Spray" - Unit 1-On November 24, 1987, with Unit 1 in Mode 4 and prior to initial criticality, Train-A of the essential cooling water (ECW) system was declared inoperable. The licensee discovered a crack in a leinch diameter ECW pipe. ECW is a support system'of the containment spray (CS) syste Tra1n C of CS was inoperable and when Train A of the ECW was declared

' inoperable, the plant entered TS 3. The licensee determined that the root cause of this event was a design error. The system's annubar flow elements:(Model No. ANF-76M) were manufactured from aluminum-bronze material. The annubar material was a harder material than the ECW piping and wore away a portion of thc annubar flow element support hole. The licensee initiated a design chang Replacement annubar flow elements were fabricated in accordance with ASME Boiler and Pressure Vessel (B&PV) Code,Section III, Class 3, and were installed on each of the 3 trains of ECW. A similar design change was implemented and installed on Unit 2. The licensee performed the work in  !

accordance with Maintenance Work Requests (MWRs) 88003706 and 8800369 l The licensee's corrective actions were completed in accordance with  ;

approved procedures and commitments. This item is close !

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(Closed) LER 88-07: " Incorrect Formula in a HVAC Surveillance Procedure" - l i

Unit 1 9n January 15, 1988, with Unit 1 in Mode 5, prior to initial criticality,

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a licensee surveillance procedure review identified that incorrectly applied air density correction factors were used in' airflow calculation !

.The licensee determined-that the cause of this event.was an error that-originated during procedure development and a weakness in the independent review process for surveillance and preoperational. test procedures, including the heating, ventilation, and air conditioning (HVAC) filter test procedures (OPSP11-HE-0001, " Control Room Envelope Filter Airflow Capacity Test," OPSP11-ZH-0008, "EAB and FHB HVAC In-Place HEPA Filter ;

Leak Test," and OPSP11-ZH-0009, "EAB and FHB HVAC In-Place.Adsorber Leak l Test").

The licensee's corrective actions included: revising plant surveillance procedures to apply the method of calculating flows referenced in Industrial ~Ventilatdsn; reviewing preoperational tests (Supplement to Preoperational Test Wocedure 1-HB-P-02, " Control Room HVAC Cleanup & '

Makeup Units Charcoal /HEPA Filter Test") to verify that the tests had been performed to' meet surveillance requirements (Technical

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Specifications.(TS) 4.7.7, 4.7.8, and 4.9.12); and requiring a second,.

independent technical review of procedure revisions and new procedures (Station Procedure OPGP03-ZA-0002, " Plant Procedures," Revision ll, dated February,29, 1988). This item is close (Closed) LER 88-15: "Two MSIV's Inoperable Resulting in a Technical

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Specification Violation" - Unit 1 On February 5, 1988, with Unit 1 in Mode 3, prior to initial criticality, acking adjustments were performed on two main ' steam concurrent valve p(MSIVs). The Unit Supervisor did not believe that isolation valves adjusting valve packing would render the MSIVs inoperable. TS 3.7. only provides action for single MSIV inoperability. Because two MSIVs were inoperable, the licensee entered TS 3.0.3 and brought the plant to liode 4. Electrical power was removed from "A" and "C" MSIVs to comply with TS 3.6.3 action requirements regard'ng containment isolatio The licensee identified the root causes of the event as follows: failure of the Unit Supervisor to recognize that'the MSIVs were inoperable (TS 3.6.3 and 0.7.1.5) and failure of the Unit Supervisor to involve supervisors in deciding the operability of the MSIVs, Also, the TS did not clearly identify that TS 3.6.3 applied to the MSIVs and did not {

clearly specify the action requirements for this type of containment 4 isolatio The licensee's corrective actions included: issuance of an Office Memorandum, " Maintenance of Containment Isolation Valves at STPEGS " dated March 1, 1988, to the shift supervisors (the memorandum discussed this event and the applicability of TS LCO 3.6.3 to all containment isolation valves listed in FSAR Table 3.6.2.4-2); review of operability requirements j i

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for containment isolation with licensed operators during requalification training (March 28 through April 29,1988); evaluation of and revisions to the licensed operator training program (the Lesson Plan included discussions on appropriate TS Sections and simulator scenarios with emphasis on practical applications of the TS); and implementation of. Plant Procedure OPOP01-ZQ-0030 " Maintenance of Plant Operations Logbooks,"

Revision 5, dated September 8, 1988, which required a 3-party review by the shift supervisor, unit supervisor, and. shift technical. advisor of all.TS ,

LCO actions. This item is close (Closed) LER 88-17: " Containment-Isolation Valves for Personnel Air Loc'k Sealing Air (PALSA) System Design Error" - Unit 1 On February 11, 1988, prior to initial criticality, licensee personnel determined that the PALSA system containment isolation valves (four solenoid valves located outside containment and designed to isolate portions of the pneumatic lines supplying air to the personnel air lock)

did not meet the requirements of Gereral Design Criteria (GDC) 57. GDC 57 states that closed system isolation valves shall be either automatic or locked closed, or capable of remote manual operation. These valves ~were used in a normally open position. There was no capability for automatic or remote manual operation; therefore, the design did not comply with GDC 5 The licensee declared these four solenoid valves. inoperable. The ?icensee closed the personnel air . lock doors, closed the four valves, and : moved the electrical power supply to the solenoids as required.by TS.6.3. The licensee also removed the fuses from the applicable motor control center (MCC) cabinet and placed restrictions on the use of the personnel air lock doors as an entrance into containmen The licensee determined that the root cause of this event was a failure of the A/E to provide a design in compliance with GDC 57. 'The valves were originally listed in the specification for. purchase of the personnel air lock as containment isolation valves, but were not recognized as containment isolation valves on subsequently issued design document The licensee issued Station Procedure 1 TOP 02-XC-0001, " Personnel Airlock Operation", Revision 0, dated February 18, 1988, to provide:an interim measure of maintaining containment integrity of the personnel air lock door seal air supply containment isolation valves. Corrective Action

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Report 20268 was approved to implement automatic isolation and remote I

manual operation from the control room for the PALSA systcm containment l isolation valves. The changes to the valves were implemented by Change I Control Package (CCP) 2-J-FST-0617. Marual test valves were also added to {

permit Type'C leak rate testing (10 CFR 50, Appendix J) for the l

penetrations associated with these valve .{ ,

An engineering review determined that the pneumatic suppl; lines which supply air to the inner and outer containment personnel dc'r seals were the only process penetrations through containment which wer* not identified by unique penetration numbers. The licensee performed an ]

engineering review of the two other similar penetrations. The licensee

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- vciified that neither the equipment hatch nor the auxiliary air lock have process penetrations. The NRC inspector verified the status of these process penetrations. This item is close (Closed) LER 88-18: "Lo-Lo T-Cold Excessive Cooldown Protection Safety Injection During Reactor Coolant System Flow Testing" - Unit 1 On February 12, 1988, prior to initial criticality while Unit 1 was in Mode 3 at a reactor coolant system (RCS) temperature of 567'F and a pressure of 2235 psig, a safety injection (SI) actuation was initiated by the excessive cooldown protection logic system following an RCS flow coastdown measurement test. The licensee determined the cause of the SI actuation to be a localized reduction in reactor coolant temperature in RCS Loop D due to reactor coolant pump (RCP) seal water injection during the coastdown test. The licensee's evaluation of this transient considered the time response of the resistance temperature detectors (RTDI), the protection setpoint (532 F), the lead / lag time constants for the instrumentation circuitry, and verification that the. thermal hydraulic performance of the RCS protection circuitry was as designed. This SI logic is unique to STP and the licensee did not anticipate the SI. The event was unique to the conditions of the RCS following this initial startup flow coastdown test. The event should not recur because the reactor core now generates significant decay heat. The' decay heat'will cause natural circulation to occur in the RCS to preclude localized reduction in RCS temperature. This item is close (Closed) LER 88-22: " Reactor Trip from Safety Injection During Approach to Initial Criticality" - Unit 1 On February 28, 1980, with Unit 1 in Mode 2 and prior to initial criticality, a reactor trip occurred due to an unanticipated SI signa The licensee's investigation determined that an instrument channel low compensated T-cold comparator (setpoint 532*F) caused this event. The cause of the spurious trip signal was not identified and could not be reproduced during the investigation. No temperature excursion occurre The surveillance calibration procedures were performed after replacing the Q/6amic compensator and comparator modules in RCS Loop 3 compensated T-cold channels. Control room personnel were briefed through night orders on identification of spurious or unexplained instrument indications and the need for prompt reporting and investigation. The corrective actions covered the possible plant and/or instrumentation malfunctions. The licensee evaluated and investigated this event with the objective to determine whether this event was similar to the event reported in l LER 88-18 (see above for discussion). The SI reported in LER 88-18 was

! caused by an actual temperature excursion due to testing conditions. This item is close . _ _ _ - _ - _ _ _ _ _ _ _

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(Closed).LER 88-44: " Control Room Ventilation Actuation to Recirculation Mode Due to Halon Interference en a Toxic Monitor" - Unit 1 On July.14, 1988, with Unit 1 in Mode 1, an automatic actuation of the control room ventilation system to recirculation mode occurred. Investigation determined that an interference gas (Halon) caused a high l ammonium hydroxide trip on one of the two toxic gas analyzers. The trip occurred while the redundant analyzer was out of service for testing. The root cause of the event was the presence of Halon in the zero sample gas (embient air) due to an inadvertent Halon relcase. The Halon was inadvertently released into the computer room and subsequently transported through the HVAC system into the room containing the toxic gas analyzer The licensee prepared a design change (ECNP 88-0-0005) which required installation of a source of nitrogen for the zero sample reference. The work was performed in accordance with Contract Work Request (CWR) 395 This item is close (Closed) LER 88-53: "Non-Conservative Calculation of Gaseous Effluent Monitor Alarm Setpoints" - Unit 1 0:1 September 20, 1988, with Unit 1 in Mode 1, gaseous effluent rsdiation monitor alarm setpoints were not calculated in accordance with requirements. The cause of this event was an inadequate review of the Offsite Dose Calculation Manual (0DCM) for effects on gaseous effluent radiation monitor setpoints prior to receipt of the operating licens The methodology of the ODCM was used to recalculate and reset the gaseous effluent radiation monitor setpoints for Unit 1. The calculations for these setpoints are in conformance with.the ODCM. The gaseous effluent radiation monitor setpoints for Units 1 and 2 were set in accordance with the methodology in the ODCM. The NRC inspector verified that the applicable gaseous effluent radiation monitor setpoints were set in Units 1 and 2 in accordance with the recalculated values. This item is close (Closed) LER 88-55: " Control Room Ventilation Actuation to Recirculation ~

Mode Due to a High hcl Trip on a Toxic Analyzer" - Unit 1 On September 30, 1988, with Unit 1 in Mode 3, an automatic actuation of the control room ventilation to recirculation mode occurred. The actuation resulted from a high level trip of the hydrochloric acid (hcl)

channel on one of the two toxic gas analyzers. The licensee could not determine the cause of the high hcl. reading. There were no plant operations in arogress that could have caused the trip on the hcl channe '

The analyzer was replaced and required surveillance calibrations were completed. This Mem is close (Closed) LER 88-57: " Train A Load Sequencer Actuation Due to Personnel Error" - Unit 1 On October 4, 1988, with Unit 1 in Mode 5, the Train A ESF load sequencer j actuated. The actuation occurred when a maintenance electrician broke a j l

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sequencer status indicating lamp bulb. The broken lamp bulb initiated a short circuit which caused cascading failures and malfunctions of sequencer component The sequencer status module was replaced and the sequencer restored to normal operation. Training was. conducted for Units 1 and 2 electrical maintenance personnel on the proper method of changing sequencer indicating lamp bulbs and on the need to exercise caution whgn performing tasks which are unfamiliar. This item is close (Closed) LER 88-58: " Control Room Ventilation Actuation to Recirculation- i Mode Due to Load Sequencer Component Failure" - Unit 1

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On October 5, 1988, with Unit 1 in Mode 5, an automatic actuation of the-Train B.. control' room' envelop (CRE) ventilation system to the recirculation mode occurred. The cause of the actuation was a failed integrated circuit chip in the processing unit of the ESF load sequencer. The failed integrated circuit chip was replaced. The Train B sequencer was tested

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and returned to service. This item is close (Closed) LER 88-60: " Control Room Ventilation Actuation ~to Recirculation Mode Due to a High hcl Trip on a Toxic Gas Monitor" - Unit T'

On October 30, 1988, with Unit 1 in Mode 1, an automatic actuation of the control room ventilation to recirculation mode occurred. The actuation resulted from a high level trip of the hydrochloric acid (HC1) channel on i one of the two toxic gas analyzers. The licensee determined the cause of the event was excessive instrument drift between the automatic rezero cycles of the analyzer. The licensee removed the automatic actuation of-Kntrol room ventilation from the hcl channel of the toxic gas analyzers and routed the toxic gas analyzer output.to the emergency response

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facility data acquisition and display systen (ERFDADS) to provide control room indication of the analyzer readings. These modifications were accomplished in accordance with CCP 2-J-FST-0661, CWR 200743, MWR NR-47764, and MWR AM-74203. These implemented corrective actions increased the plant operators ability to correctly distinguish false alarms from actual toxic gas alarms without unnecessary ESF actuations. This item is close (Closed) LER 88-62: " Failure to Satisfy Technical Specification Requirements for Containment Isolation Due to Operator Error" - Unit 1 On November 21, 1988, with Unit 1 in Mode 1, the licensee discovered that the outside containment Supplementary Containment Purge Supply Isolation Valve was inoperable at the same time that the redundant inside containment valve had motor operator power available for more than 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br />. The cause of the event was failure of the control room supervisor to properly control the work activity on the outboard supplementary purge isolation valve. The licensee conducted shift briefings for control room operators to discuss this event and to reinforce the need to ensure that containment integrity is maintained in accordance with TS. A special test Procedure OPOP07-ZE-0003,

" Normal / Supplementary Purge Valve Failure / Troubleshooting," Revision 0, l

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'dat'ed' January'23, 1989, was develop"ed and. implemented for Units 1 and LThe_ equipment clearance order (ECO) and operability tracking ~ log

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-procedures ~ require that ECOs, which are issued as a-result of TS action-statements,:are properly reviewed prior to their releases .lhis item is

closed.. This item was cited as a Severity Level!IV violation in NRC'

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Inspection Report 50-498/88-73; 50-499/88-73.

g (Closed) LER 88i63: " Failure to Irbtail Vortex Breakers in the Containment Emergency Semps" - Unit 1

'During an independent review of the Emergency Core Cooling System (ECCS),

the= licensee discovered that the vortex suppressors, required lin the emergency containment sumps, were not. installed. CWRs 003991, 003992, and

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003993 were issued to fabricate and' install;the vortex suppressors in ,

Unit-1. The guidelines stated in Regulatory Guide 1.82,' Appendix;A,1for evaluating and. designing vortex suppressors were met by the licensee. The vortex suppressors'have.been installed in the containment sumps of Unit 1 in accordance with drawings and procedures.- An analysis conducted by Alden Research Laboratory. evaluated the' effects on vortex formation of both

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uniform and nonuniform distribution of debris on the containment sump screen. An analysis conducted by Creare, Incorporated, evaluated the ECCS pump performance under air vortexing conditions. This item is close This event was addressed for Unit 2 in:IRC 446. See paragraph 4 of this report. This event was cited as a Severity Level III violation (EA-89-01).

(Closed) LER 88-65: " Failure to Properly Perfbrm a Technical-

' Specification Required Channel Check Due to Procedural Inadeq'uacy" -

Unit 1 During a. review of completed control room logs,;the licensee discovered-that daily channel checks were not being properly performed on the-condenser air removal system (CARS) wide-range gas-monitor sample flow meters. The TS required channel checks on both the " wet flow" and " dry flow."~'Only the " dry flow" checks were recorded. The cause'of this event

'was an inadequate control room logging procedure. 'The' licensee's' corrective actions included revision of Plant Procedure 1 PSP 03-2Q-0002,.

l= * Routine Instrument Surveillance for Modes 1, 2, 3, and 4," to incorporate )

a channel check of the " wet" sample flow instrument. The control room

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procedures prepared by the Operations Department, which control the performance of TS surveillance, are now reviewed by technical 1-organizations familiar with the detailed system design. This item.is close (Closed) LER 88-66: " Fuel Handling Building Exhaust System Filter Heater Design Error" - Unit 1 On November 11, 1988, during a preoperational test of Unit 2, the licensee discovered that the fuel handling building (FHB) exhaust system filter heaters did not energize as required. The licensee. determined that the cause of this event was a design error which resulted in reduced airflow

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10 over the filter charcoal beds when both trains of the FHB exhaust system operated. The reduced airflow actuated a safety device which prevented energizing the filter charcoal bed heaters (Problem Report No. 880508,

"FHB Filter Heater Failure to Energize"). An additional error occurred which resulted in the licensee failing to properly account for failures in the control room HVAC system failure modes and eNects analysis (FMEA).

L The original analysis results presented in the FSAR, Chapter 15, Section 15.6.5, for the LOCA dose and Section 15.7.4 for the fuel handling accident were reviewed. This analysis assumed that'one train of FHB filters operated at full efficienc Both the offsite dose and control

, room dose calculations have been revised to include the effects of loss of

'both. trains of FHB exhaust filter heaters and various control room ventilation system failures. The licensee performed Calculation 5V120MC6119, "FHB - Filtration Trains Heater Capacity," to determine the required heater capacity of the fuel handling filtration units. Attachment 1, dated December 16, 1988, to these calculations was repared by Nutherm International, Inc., and contained a sketch p(No. SK55441-R3), a description and. instructions, and testing requirements related to the field rewiring of the heater The emergency operating procedures were revised to require securing of one FHB filter train in the event of a SI. The changes to the emergency procedures were removed subsequent to completion of the plant modification to the heaters. A from 50 kilowatts (plant modification kw) to_38 kw. A TS reduced the FHB filter change (Amendment 6 toheaters output Section 3/4.7.8, " Fuel Handling Building (FHB) Exhaust Air System)"

approved plant operation with the 38 kw output rating for the. heaters. The FMEAs for safety-related HVAC filtration or subsystems were reanalyzed for

.worst case failures.. The offsite and control room dose analysis was reviewed by the NRC inspector for impact from the revised FMEAs. This item is close (Closed) LER 89-03: " Control Room Ventilation Actuation to Recirculation Mode Due to a Toxic Gas Analyzer Malfunction" Unit 1 On' January 6, 1989, with Unit 1 in Mode 1, an automatic actuation of the control room ventilation to recirculation mode. occurred. The actuation resulted from a malfunction signal from one of the two toxic gas analyzers. No personnel wrre working in the vicinity of the analyzers when the event occurred. The analyzer indicated a malfunction. The licensee could not identify any cause for the malfunction. The malfunction indicating lamp circuit for the analyzer was reset. The i diagnostic capabilities of the analyzer gave no indication of the cause of l the malfunction. This item is close (Closed) LER 89-04: " Control Room Ventilation Actuation to Recirculation Mode Due to a Toxic Gas Analyzer Malfunction" - Unit 1 On January 12, 1989, with Unit 1 in Mode 1, an automatic actuation of the control room ventilation to recirculation mode occurred. The actuation i

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resulted from a malfunction signal'from one of the two toxic ga's analyzers. No personnel were working in the immediate vicinity of the

analyzers when the event occurred. The analyzer indicated a malfunctio There was.no apparent cause for the malfunction. The. malfunction indicating lamp circuit for the analyzer was reset. .The' diagnostic capabilities of the analyzer gave no indication of th9 cause of the-malfunction. This:LER is similar to LER 89-03, abov This item is-close . (Closed) LER'89-05: " Reactor Trip'Due to a Main Generator Fire" - Unit On January 20, 1989, a fire' was reported at Bearing 9 on the Unit 1 main generator. .The~de' luge system was actuated, the turbine was manually tripped and the reactor automatically tripped. The fire was extinguishe lhe licensee determined that the cause of the fire was a loose termination between the thermocouple reference block and the main generator hydrogen temperature controller which caused the hydrogen cooling system to fail and the main generator temperature to increase. Subsequently, hydrogen escaping from the bearing seal, because of increased pressure, was ignited by the hot bearin The licensee repaired the loose termination between the thermocouple reference block and the main generator hydrogen gas temperature controller. No other similar loose terminations were identified by the licensee. The design of the main generator hydrogen gus' temperature controller was modified by the licensee to ensure that a failure would 'not result in a complete loss of hydrogen cooling. The main generator was disassembled and the rotor was removed for a complete warranty inspectio No significant damage was identified. An inspection of the main turbine bearing pedestals was performe No damage was detecte An investigation was performed by a team that consisted of members from the Independent Safety Engineering Group (ISEG) and representatives from the Plant Operations, Plant Engineering, and Support Engineering Departments. Subsequent to this investigation, the licensee issued Final Report 89-06, " Investigation of Unit 1 Turbine Generator Fire Incident,"

dated April 198 The licensee's reviews, repairs, design modifications, and investigations determined eight root causes for the main generator fire. The licensee's corrective actions adequately addressed the root causes. This item is close . Licensee Action on Previous Inspection Findings (92701)

(Closed) Open Item 498/8739-07: "Obtain Vibration Signatures for the Turbocharger on all Three DGs and Compare Readings" - Unit 1 This Open Item suggested that the licensee obtain vibration signatures (VS)

for the turbocharger on all three diesel generators (DGs) and compare the VS to verify whether or not the turbocharger VS on DG No.13 varied l

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significantly from the VS of DG:Nos. 11 and:12.. The licensee also!

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invest.igated the possibility of excessive vibrations being; induced in the

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. piping by the flexible connection currently"in~ plac = Following the failure of a turbocharger support brack'et mountirig' bolt. .the

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licensee committed to monitor turbocharger vibration over 150 run hours on

the DGs. . The licensee prepared a procedure to collect data in.accordance with Station Procedure OPEP06-2G-0012, " Vibration Monitoring Data'

Collection Procedure.'.' The licensee collected data'in accordance with Procedure OPEP06-ZG-0012.. DG Nos. 11 and'12.ran continuously for 1"/ 100 hours0.00116 days <br />0.0278 hours <br />1.653439e-4 weeks <br />3.805e-5 months <br /> (during scheduled 100-hour endurance runs in July / August 1987).

DG No. 13.. completed the run after several unsuccessful attempts (almos '

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150 hours0.00174 days <br />0.0417 hours <br />2.480159e-4 weeks <br />5.7075e-5 months <br />'of DG run time were accumulated for.DG No. 13). The licensee

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recorded filtered, velocity vibration readings over a range of 600 to 600K cycles per minute (cpm), using calibrated-test equipment (Instrument Model^IRD 820/ Transducer, STPEGS ID No. 100-01254-01, and Instrument Model IRD 880/ Transducer, STPEGS ID No. 100-01254-02). Calibration due dates for the instrumentation were kept current. The accuracy of the-instrumentation was 5. percent of full scale. Data were collected at the outboard end of the turbocharger support brackets, at points on either-side of the center exis if each DG. . On the turbocharger, the data were '

'taken at the intake flange. With the exception'of data collected.at the

~ start of DG No.-13's successful continuous 100-hour run, the DGs had been

' running 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> or more before data were taken. In the case of DG No. 13, the DG.had been' running approximately 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> when vibration readings were recorded, a

In addition to vibration signatures, the'overall vibration across the frequency range was recorded and analyzed by the licensee. Changes in DG No. 11 overall turbocharger vibration were within the accuracy of the instrumentation. The VS showed a res.ponse at the 10K. cpm at the operating speed of the turbocharger. No change in the response at the 10K cpm was observed over'the running time. .VS readings on the support bracket,showed a slight rise in axial vibration on the right side of the support bracke .The VS were stable over a long perio DG No. 12 turbocharger vibration readings were the lowest and most stable of the three DGs and showed no detectable changes. The VS showed similar responses to DG No. 11. The DG No. 13 overall vibration readings for the turbocharger included. data taken at the beginning of the first aborted 100-hour run attempt. The vibration data spanned almost 150 h R rs of-engine run time for DG No. 13, at approximately 50-hour intervals. A drop

.in the overall horizontal vibration from the first to'the seccnd time" interval was evident on the graph. The data at the second print were taken approximately 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> after the DG was started. If this data point is considered a " fluke," there is no obvious change-in the overall vibration trend, if errors are taken into account. The VS were stable over time, except that the two-times-engine-RPM responses appeared to be depressed when the DG was not warmed u .. N fr

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-13 The NRC inspector's review of the VS data indicated that there were no detectable trends indicative of deteriorating performance over 100 to 150 hours0.00174 days <br />0.0417 hours <br />2.480159e-4 weeks <br />5.7075e-5 months <br /> of DG run time. The VS showed the expected characteristics of combustion impulses and acceptable rotational imbalance. This open item is close . Onsite Followup of Written Reports of Nonroutine Events at Power Reactor Facilities - Unit 2 (92777)

(Closed) IRC 223 (10 CFR 50.55(e)), " Flood Protection Deficiency" - Unit 2 The licensee revieMed the flood protection measures for Seismic Category I structures. The review determined that the following four areas could be flooded under postulated flood conditions: 1) cover for the top of the

' tendon gallery shaft, 2) two drdin systems with external discharge capability that do not have check valves on their respective discharge lines, 3) ductbanks learing the MEAB that are not provided with watertight covers, and 4) both 6-iuch drains under the trash pit which, if clogged, could cause water backup into the essential cooling water intake structure (ECWIS). The licensee completed design changes'and corrected the potential for flooding in these areas of Unit Corrective actions were completed for Unit 1 and reported closed in NRC Inspectico Report 50-498/87-27; 50-499/87-27. This item is close (Closed) IRC 257 (10 CFR 50.55(e)), " Tornado and Missile Protection for the EAB, Control Room and Technical Support Center" - Unit 2 The licensee determined that portions of the HYAC systems serving the electrical Auxiliary Building (EAB),-the control room, and the Technical Support Center (TSC) could be depressurized during, or as a result of, a tornado. The EAB, control room, and TSC must remain functional following a tornado event. Portions of the HVAC for the EAB, control room, and TSC are connected to a common air intake plenum that was not initially designed-for tornado conditions. The licensee installed a tornado damper and provided missile protection to the outside air intake where the TSC outside air duct penetrates the plenum wall. Corrective actions for Unit 1 were completed and reported closed in NRC Inspection Report 50-498/87-27; 50-499/87-27. This item is closed.-

(Closed) IRC 397 (10 CFR 50.55(e)), *FGP Series Agastat Relays" - Unit 2_

Cooper Industries (CI) supplied the DGs for Units 1 and 2. The DG control panels for Unit 1 used 1978 vintage Class 1E Agastat FGP relays and sockets. No operating problems Ive been identified with the Agastat relays and/or sockets on Unit 1 ,G ,

In 1980, Agastat redesigned the FGP series relays and sockets. The 1980 vintage relay base is slightly larger and required a different socket to I

accommodate the larger dimension relay base. The Unit 2 DG panels, supplied by CI, contained 19E0 vintage Agastat FGP series relays and the 1978 version of the a ting sockets. The 1980 version FGP series relays

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did not seat properly-in the 1978 version sockets; however, the electrica connections were accomplished. The seismic qualification of the 1980 version relays and the 1978 version of the socket connections was not analyzed by the license Maintenance personnel requested an Agastat FGP series relay from the warehouse for installation into a 1978 vintage socket in'the Unit 1 DG control panel. The mainter:ance personnel recognized that a 1980 vintage relay was received. QA personnel found that a 1980 vintage relay had been installed in a 1978 vintage socket. Further investigation identified that the same part number (2-04E-178-011) was issued by CI for the two difference vintages of relays. Site venor manuals did not distinguish between 1978 and 1980 vintage relay The licensee removed relays with CI Part No. 2-04E-178-011 from service in accordance with site procedures. Relays of the 1980 vintage installed in the Unit 2 diesel generator control panels have been replaced by qualified Agastat CGP series relays. The EGP series relays are compatible with the 1978 vintage FGP sockets. The only use of the FGP series relays at STP is in the DG panels. The licensee had reviewed 10 CFR Part 21 Report P21-87-28, "GE - Improper seating of Agastat GP set ies relays at Niagra fichawk Power Corporation," and determined that this Part 21 was not applicable at STP. This item is close (Closed) IRC 446 (10 CFR 50.65(c)), " Failure to Install Vortex Breakers in the Containment Emergelicy Sumps" - Unit 2 During an independent review of the Emergency Core Cooling System (ECCS),

the licensee discovered that the vortex suppressors, required in the emergency containment sumps, were not installed. Construction Work Requests (CWRs) 200271, 200272, and 200273 were issued to fabricate and install the vortex suppressors in Unit 2. The guidelines stated in Regulatory Guide 1.82 Appendix A, for evaluating and designing vortex suppressors were met by the licensee. The vortex suppressors have been installed in the containment sumps of Unit 2 in accordance with drawing ,

and procedures. An analysis conducted by Alden Research Laboratory t evaluated the effects on vortex formation of both uniform and nonuniform distribution of debris on the containment sump screen. An analysis conducted by Creare, Incorporated, evaluated the ECCS pump performance under air vortexing conditions. This item is clesed. This item was addressed for Unit 1 in LER 88-63. See paragraph 2 of this report.

L (Closed) LER 89-08: " Failure to Perform a Technical Specification l- Required Surveillance Test on a Steam Generator Power Operated Relief Valve Due to Personnel Error" - Unit 2 l l On March 23, 1989, with Unit 2 in Mode 3, the licensee discovered that the ASME Scction XI Valve Test requirements (IWV-3000) stroke time test on I steam generator (SG) Power Operated Relief Valve (PORV) 2D had not been performed within the required surveillance interval (TS 4.6.3.3 and 4.0.5). The licensee determined that this event was caused by a personnel l

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error. The increased surveillance frequency test of the 2D PORV was correctly scheduled; however, the licensee failed to specify that this test, ncrmally performed only in sold shutdown, (Plant-Procedure 2 PSP 03-MS-0002, " Main Steam System Cold Shutdown Valve") must be l

performed monthly even if the plant is not in cold shutdown when increased l surveillance is require l 1 The licensee performed and evaluated the results of the required SG 2D PORY stroke time test; revised the surveillance test database to identify that the increased surveillanra :s required regardless of plant i operating mode; reviewed ASME B&PV Code,Section XI, surveillance to  ;

ensure that the surveillance test database' correctly identified the permitted plant operating modes and frequency of required tests; performed a review of the datebase to ensure that no other tests with increased surveillance frequency had been missed; and prepared and implemented an instruction and a checklist (Section XI Checklist, " Routine for Handling Increased Frequency Items due to Section XI Trending Requirements"). The checklist contained a step that required the Reactor Operations Division i Surveillance Coordinator be notified when components are placed on an increased testing frequency. This item is close . Cross Reference of Unit 1 LERs Applicable to Unit 2 Licensee corrective actions described in the following LERs reported by Unit 1 were applicable to Unit 2:

LER 87-16, " Initiation of Cooldown Due to Inoperability of Two Trains of Containment Spray" LER 88-53, "Non-Conservative Calculation of Saseous Effluent Monitor Alarm Setpoints" LER 88-57, " Train A Load Scequencer Actuation Due to Personnel Error" ,

LER 88-62, " Failure to Satisfy Technical Specification Requirements For Containment Isolation Due to Operator Error" LER 88-65, " Failure to Properly Perform a Technical Specification Required Channel Check Due to Procedural Inadequacy" r LER 88-66, " Fuel Handling Building Exhaust System Filter Heater Design Error" 1 I

The licensee's corrective actions including procedure revisions have been ]

completed for applicable LERs for Unit 2 and<3re discussed in the above l listed Unit 1 LERs. The corrective actions for Unit 2 met the applicable i conditions. LER 88-57 and LER 88-62 were identified as a result of personne' errors at Unit 1. Similar personnel errors did not occur at Unit l l

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,,. Exit-Interview g. s The NRC inspector met with licensee representatives (denoted in paragraph 1)'on June 23,'1989. 'The NRC inspector 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 NRC inspector.-

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