IR 05000458/1986027

Insp Rept 50-458/86-27 on 860801-0915.Violations Noted: Failure to Meet Electrical Spec Requirements & Failure to Follow Surveillance Test Procedure

ML20215L126
Person / Time
Site:	River Bend
Issue date:	10/16/1986
From:	Bennett W, Chamberlain D, Jaudon J, William Jones NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION IV)
To:
Shared Package
ML20215L106	List: IR 05000458/1986027 ML20215L104 ML20215L117
References
50-458-86-27, NUDOCS 8610280484
Download: ML20215L126 (14)

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t APPENDIX B U. S. NUCLEAR REGULATORY COM11SSION

REGION IV

NRC Inspection Report: 50-458/86-27 Docket: 50-458 Licensee: Gulf States Utilities Company (CSU)

P. O. Box 220 St. Francisville, Louisiana 70775 Facility Name: River Bend Station (RBS)

Inspection At: River Bend Station, St. Francisville, Louisiana Inspection Conducted: August 1 through September 15, 1986 Inspectors: le e

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D. D. Manberlain,' Senior' Resident Inspector Date (pars. 1, 3, 5, 8, 9 and 11)

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W. B. Jones, Resid)iit Inspector

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Date (pars. 1, 2, 3, 4, 5, 6, 7 and 8)

kh W. R. Bennett, Project Engineer lYl6lN Date (par. 10)

Approved: ([// / [/}// /O!d J. P Ja don, hief,' Prdject' Section A Date R ct(r Pr ects Branch 8610280484 861024 PDR ADOCK 05000458 G PDR

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-2-Inspection Summary Inspection Conducted August 1 through September 15, 1986 (Report 50-458/86-27)

Areas Inspected: Routine, unannounced inspection of Licensee Event Reports (LER), licensee action on IE Notices, startup test result evaluation, safety system walkdown, surveillance witness, maintenance witness, operational safety verification, followup on allegations and in-office review of written reports of nonroutine events at power reactor facilitie Results: Within the eight areas inspected, two violations were identified (failure to meet electrical specification requirements, paragraph 5, and failure to follow a surveillance test procedure, paragraph 6) .

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-3-DETAILS Persons Contacted

• R. J. Backen, Supervisor (Acting), Operations Quality Assurance (QA)

W. J. Beck, Supervisor, Reactor Engineering W. H. Cahill, Jr., Senior Vice President, River Bend Nuclear Group E. M. Cargill, Supervisor, Radiation Programs T. C. Crouse, Manager, QA

• J. C. Deddens, Vice President, River Bend Nuclear Group

• R. G. Finkenaur, Electrical Engineer P. E. Freehill, Superintendent, Startup and Test A. O. Fredieu, Assistant Operations Supervisor P. F. Gillespie, Senior Compliance Analyst

• D. R. Gipson, Assistant Plant Manager, Operations

• E. R. Grant, Director, Nuclear Licensing

• B. R. Hall, Assistant Superintendent, Field Quality Control (Stone and Webster)

R. W. Helmick, Director, Projects G. K. Henry, Supervisor, Electrical Engineering K. C. Hodges, Supervisor, Quality Systems R. J. Kiag, Licensing Engineer A. D. Kowalczuk, Assistant Plant Manager, Maintenance

• J. H. McQuirter, Licensing Engineer

• J. Normand, Supervisor, Administration Services

• W. H. Odell, Manager, Administration

• T. F. Plunkett, Plant Manager

• S. R. Radebaugh, Assistant Plant Manager, Services D. Reynerson, Director, Nuclear Plant Engineering (NUPE)

• H. F. Sankovich, Manager, Engineering

• R. R. Smith, Licensing Engineer R. B. Stafford, Director, Operations QA K. E. Suhrke, Manager, Projects

• P. F. Tomlinson, Director, Quality Services D. Williamson, Operations Supervisor The NRC senior resident inspector (SRI) and resident inspector (RI) also interviewed additional licensee personnel during the inspection perio * Denotes those persons that attended the exit interview conducted on September 9, 1986. NRC resident inspector (RI), W. B. Jones also attended the exit intervie . LicenseeEventReports(LERs) Review During this inspection period, the RI reviewed LERs for compliance with the requirements established in 10 CFR 50.73 Licensee Event Report Syste . .

-4-Specifically, the RI reviewed the LERs for accuracy and clarity of the event description, the cause of each component or system failure or personnel error, the failure mode and the effect each component had on plant operations, operator actions that affected the course of the event, and the corrective actions taken to prevent reoccurrence of the even The following LERs were reviewed:

85-001 Reactor Protection System Actuation 85-002 Reactor Protection System Actuation 85-003 Reactor Protection System Actuation 85-004 APRM Surveillance Testing 85-005 Reactor Protection System Actuation 85-006 Reactor Protection System Actuation 85-008 Reactor Protection System Low Level Actuation No violations or deviations were identified in this area of the inspection and these LERs are close . Licensee Action on IE Notices The licensee is presently evaluating IE Information Notice 86-68, " Stuck Control Rod," and IE Information Notice 86-73, "Recent Emergency Diesel Generator Problems," for applicability to River Bend Station. The details and licensee's actions concerning each of these notices is described belo IE Information Notice 86-68 addressed a potential problem involving failure of a control rod to insert during a reactor scram and subsequent damage to the control rod drive (CRD) unit resulting from closure of the 112 scram discharge riser manual isolation valve. River Bend Station had initiated a locked valve control program prior to the issuance of this notice. Critical manual isolation valves on the CRD hydraulic control units (HCU) such as the 101, 102, and 112 valves are secured in the open position using lock wires. A formal audit of valve positions and locking requirements is performed by the operations department on an annual basi Commentsreceivedfromthenuclearequipmentoperators(NE0s)also revealed that the NE0s perform informal random verifications of critical CRD HCU manual isolation valve positions during tours in the containmen The RI independently verified all of the 112 valve positions during a tour of the containment on August 20, 1986, and noted the valves are of the rising stem design which allows for easy visual verification of valve position. Finally, the licensee is required by Technical Specifications (TS) to demonstrate the CRD HCUs are operable by individually scramming 10 percent of the control rods every 120 power days on a rotating basis and thus verify correct valve positions on the applicable HCUs. The RI concluded that the above listed licensee actions are adequate to prevent the incident as described in IE Information Notice 86-68 from occurring at River Bend Statio IE Information Notice 86-73 identified a potential design logic problem for diesel generators (DG) supplied by the General Motors Corporatio . .

-5-Specifically, when the DG accelerates past 475 rpm during a normal or emergency start, the logic is completed to flash the generator fiel Once the output voltage has built up, the field flash circuitry is automatically disabled and the engine speed must fall below 200 rpm to reset the field flash circuitr If however, during the 450 rpm 10-minute cooldown run, an emergency start signal is received, the diesel will accelerate to the normal 900 rpm operating speed, but the required field flash will not occur. The licensee comissioned General Electric to review the logic system used by the Division III DG for applicability to IE Information Notice 86-73. The review revealed that the Division III diesel at Rivur Bend Station does not utilize the automatic 10-minute cooldown run after the stop button is depressed. Instead, a 50-second time delay is locked in before the diesel can be restarted manually. This delay ensures that the diesel has come to a complete stop. If however, an emergency start signal were received during the diesel coast down, the diesel would restart when engine speed has dropped below 150 rpm and lube oil pressure is less than 20 psig. The generator flash circuitry logic ensures that any time the diesel may be restarted, the generator flash circuitry is availabl No violation or deviations were identified in this area of the inspectio . Startup Test Result Evaluation During this inspection period, the RI completed the review of Stcrtup Test Package 1-ST-27, " Turbine Trip and Generator Load Reject." For the test package reviewed, it was determined that the licensee startup organization and Facility Review Comittee (FRC) had reviewed and accepted the test results and analyzed the test data to verify that the acceptance criteria had been met. The NRC review of this test is documented belo Startup Test 1-ST-27, " Turbine Trip and Generator Load Reject": The purpose of this test was to evaluate plant response to a turbine trip within bypass capacity and a generator load rejection at high power and to determine the bypass valve capacity. Review of the test data revealed that the plant systems performed within the established acceptance criteri The bypass valve capacity was determined to be 11.13 percent which exceeds the Final Safety Analysis Report (FSAR) minimum required value of 10 percent. All test exceptions (TE) associated with this test have been reviewed by the FRC and were closed ou No violations or deviations were identified in this area of inspectio . Safety System Walkdown During this inspection period, the SRI and RI perfomed a walkdown of the Division I, II, and III DC batteries and distribution systems. During Operational Conditions 1, 2, and 3; the Division I, II, and III DC electrical power sources (each consisting of a 125 volt battery and a 125 volt full capacity Class IE source charger) are all required to be operable. During this walkdown, based on information received from NRC

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-6-Region IV and IE Information Notice 86-37, the RI examined the battery cell to battery rack spacing and the licensee was asked to address the spacing on the rack end pieces which was as much as 1 inch or more in some cases. The licensee obtained a copy of a memorandum from Gould which stated that the battery rack end cell spacing should be less than 1/4 inch. The licensee took immediate action to adjust the battery rack end pieces to obtain the desired less than 1/4-inch clearance. A review of the installation drawings and instructions revealed that no maximum cell to rack clearance was specified. Also, a review of the seismic qualification report for the battery rack system did not reveal any specific instructions on maximum cell to rack clearance. IE Information Notice 86-37, " Degradation of Station Batteries," which was issued on May 16, 1986, contained a statement that " Subsequent NRC inspections related to the cell-to-cell spacing and cell-to-rack spacing also revealed that the batteries were not installed in accordance with the battery vendor's seismic qualification recommendations." Although this notice had been reviewed by the licensee's contractor, a response dated June 28, 1986, did not address the cell to rack spacing. The SRI does not consider the licensee review of this IE Information Notice to be thorough or timel A review of licensee actions on IE Information Notices will be conducted during a future NRC inspection in order to evaluate the effectiveness of the licensee program in this area as an open item (458/8627-03).

Also, during the system walkdown it was noted that the three No. 2 electrical conductors leading to the positive post of the Division III battery contained splices and the section of cables (about 4 feet) which contained the splices between the conduit termination and the battery post were not supported to limit stress on the battery post. A review of River Bend electrical specification 248.000 revealed that cable splices are required to be made in junction or pull boxes, condulet fittings in conduit with single circuits, or within equipment enclosures. The splices noted were not made in any type of enclosure and the failure to meet the electrical specification requirements was identified by the SRI as an apparentviolation(458/8627-01). The identified lack of cable support to limit stress on the battery post should also be addressed in the response to this apparent violation. The licensee took immediate action to issue a condition report to initiate corrective action on the identified condition The remainder of the system walkdown revealed the following:

o battery rooms were clean and orderly; o total battery terminal voltage was greater than or equal to 130.2 volts on float charge as required by TS; o the cells and battery racks showed no visible signs of damage or deterioration; o battery room ventilation systems were operating;

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-7-o battery electrolyte levels were within limits; o chargers and battery electrical distribution systems were properly aligned; o no abnormal control room indications or alarms were presen . Surveillance Witness The RI witnessed surveillance testing activities conducted by the licensee during the inspection period and the following observations were made:

o Surveillance Test STP-203-3301 - The licensee performed section 7.12, of STP-203-3301, "HPCS Valve Operability and Pump Flow Test," on August 8, 1986, to meet the inservice inspection (ISI) requirement During the initial performance of this test, the test ratio for differential pressure was found to be in the unacceptable rang Based on the pump differential pressure test ratio being in the unacceptable range, declared inoperable thelimiting and high pressure condition core spray (HPCS)

of operation pump)was (LCO 86-638 was initiated at 1245 hours0.0144 days <br />0.346 hours <br />0.00206 weeks <br />4.737225e-4 months <br />. The licensee later determined that flow indicator IE22* FIR 603 was out of calibration. This flow indication was used to establish the required initial conditions for deternining the HPCS pump differential pressure test rati After reviewing the cause for the surveillance test failure, the licensee repeated the test at 2100 hours0.0243 days <br />0.583 hours <br />0.00347 weeks <br />7.9905e-4 months <br /> using an alternate means of determining HPCS flowrate. This test was satisfactorily completed with the differential pressure test ratio falling within the alert range. The HPCS system was subsequently declared operable and LC0 86-638 closed. However, because the differential pressure test ratio is in the alert range, the ISI testing frequency has been increased to every 46 day o Surveillance Test STP-305-1100 - The R1 observed the performance of STP-305-1100, " Battery Weekly Surveillance Test For Battery 1ENB* BAT 01A," conducted on September 8, 198 This surveillance test implemented the weekly requirements of TS paragraph 4.8.2.1.a and partially satisfied the requirements of TS paragraph 4.8.2.2 for the Division I batter In addition to observing procedure STP-305-1100, the R1 reviewed the surveillance test packages for procedures STP-305-1101, " Battery Weekly Surveillance Test For Battery 1ENB* BAT 01B," and STP-203-1102,

" Battery Weekly Surveillance Test For Battery 1E22*S001 BAT," for the month of September. The latest surveillance test packages of procedure STP-305-13CO, " Battery 1ENB* BAT 01A Quarterly Surveillance Test," STP-305-1301, " Battery 1ENB* BAT 018 Quarterly Surveillance Test," and STP-203-1302, " Battery 1E22*S001 BAT Quarterly Surveillance Test," were also reviewed. The R1 noted that Procedure STP-203-1302,

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-8-performed on August 12, 1986, identified pilot cells 33 and 37 as having the lowest corrected specific gravities of 1.210 and 1.208, respectively. Procedure STP-203-1102 requires that the person (s)

performing the STP obtain and record the pilot cell numbers with the lowest corrected specific gravities utilizing the latest performance of procedure STP-203-1302. However, procedure STP-203-1102 performed on September 3 and 8, 1986, utilized pilot cells 37 and 52, with pilot cell 52 having a corrected specific gravity of 1.212. This failure to properly identify the pilot cells with the lowest connected specific gravities from procedure STP-203-1302 for utilization in the subsequent performances of Procedure STP-203-1102 was identified by the RI as an apparent violation (458/8627-02). The RI notified the licensee of this condition on September 12, 1986, at which time the licensee declared the Division III batteries inoperative resulting in the HPCS and standby service water pump (SSWP) C being declared inoperative as required by TS 3.8.2.2. LC0 86-768 was initiated at 1630 hours0.0189 days <br />0.453 hours <br />0.0027 weeks <br />6.20215e-4 months <br /> as was STP-203-1102 utilizing cells 33 and 37 as the pilot cells. At 1725 hours0.02 days <br />0.479 hours <br />0.00285 weeks <br />6.563625e-4 months <br />, STP-203-1102 was completed and accepte LC0 86-768 was subsequently cleared and HPCS and SSWP C were declared operabl The licensee has reviewed the above procedural errors and issued temporary change notice (TCN) 86-1416 to procedure STP-203-1102 requiring an independent verification that the pilot cells are the cells with the lowest corrected specific gravities as identified in the latest performance of procedure STP-203-1302. TCNs 86-1417 and 86-1418 have also been issued to procedures STP-305-1100 and STP-305-1101, respectively, requiring the same type of independent verification. The licensee has also determined that the Division III batteries were not inoperative between the hours of 1630 and 1725 on September 12, 1986. This determination was based on a subsequent review of the Division III battery surveillance test data taken between August 8 and September 12, 1986, which showed that the lowest Division III battery cell corrected specific gravity did not fall below the TS limit of 1.195. Because of this determination, no LER will be issued on this inciden . Maintenance Witness The R1 observed maintenance activities performed under maintenance work request (MWR) 52804 which identified the reactor core isolation cooling (RCIC) warmup line inboard isolation valve 1E51*M0V076 as inoperative. This valve failed to completely close during isolation time surveillance testing performed on September 8, 1986. LC0 86-748 was initiated at 1415 hours0.0164 days <br />0.393 hours <br />0.00234 weeks <br />5.384075e-4 months <br /> and the RCIC system declared inoperative. The requirements of TS 3.6.4 were carried out within the required 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> by closing and deactivating outboard RCIC steam supply isolation valve 1E51*M0V064. A 3 amp DC current was run through the motor windings from September 8-11, 1986, in an attempt to remove any moisture which may have accumulated in the motor housing. On September 11, 1986, the valve was energized and stroked to the full open poH tion. An attempt was then made to stroke the valve closed but the breaker tripped before reaching the

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-9-full closed position. Subsequent attempts to operate the valve in either the open or close direction were unsuccessful. Modification request (MR) 86-0092 was issued on September 11, 1986, to increase the magnetic trip setting to 9.7 amps. The unreviewed safety question determination (USQD)performedonSeptember 12, 1986, stated that the probability of wire and penetration damage due to the temporary modifica-tion is not increased because the maximum breaker setting (9.7 amps) is less than the maximum continuous current rating of the circuit (20 amps).

The FRC reviewed MR 86-0092 and the USQD on September 12, 1986, and approved tie temporary change to the magnetic trip setting. Attempts by the operators to stroke 1E51*MOV076 later the same day were unsuccessfu The licensee is presently reviewing what actions may be taken to close IE51*MOV076. The RI will continue to monitor licensee actions during subsequent inspection No violations or deviations were identified in this area of the inspectio . Operational Safety Verification The SRI and RI observed operational activities throughout the inspection period and closely monitored operational events. Control room activities and conduct were observed to be well controlled and efficient. Proper control room staffing was maintained and access to the control room operational areas was controlled. The licensee was adhering to LCOs as they occurred. Operators were questioned regarding lighted annunciators and they understood why the annunciators were lighted in all case Selected shift turnover meetings were observed and information corcerning plant status was being covered in these meetings. A walkdown of tLe Division I, II, and III battery systems was conducted and the results ara documented in paragraph 5 of this report. Several plant tours were conducted and while overall plant cleanliness was good, the SRI observed some problems with storage and use of combustible materials. No specific problems were noted in or near safety-related areas or equipment, but the SRI discussed the areas of concern with licensee management. Licensee management has initiated action to review control of combustible materials and the SRI will continue to monitor these actions during future inspec-tions. During these plant tours, radiation protection area postings were observed to be accurate. The SRI and RI participated in a security drill conducted on the evening of August 27, 1986, with NRC Region IV security personnel. The results of the drill will be documented in NRC Security Report 458/86-29. The resident inspectors also reviewed licensee actions on several operational events and potential problems. The results of reviews of selected items are described below: Diesel Generator Fuel Oil Storage Tanks Sampling - This area of inspection was conducted to evaluate the licensee's program for the sampling and monitoring of water and particulate matter in the diesel generator fuel oil storage tanks and transfer system per a request from NRC Region IV. Prior to operating the diesel generators for surveillance testing, the operations department obtains a sample of

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fuel oil from the bottom drain located on the fuel oil day tan This sample is visually inspected for water and ) articulate matte During the operation of the diesel generators, tie differential pressure across the fuel oil strainers is monitored as well as fuel oil pump presst.re. The maintenance department performs monthly preventive maintenance (PM) on the diesel generators. This PH includes the inspection and cleaning of the fuel oil strainers. The chemistry department takes samples of the fuel oil storage tanks on a monthly basis. These samplers are taken from multiple points in the tanks to assure that particulate matter with densities equal to, less than, and greater than that of diesel fuel oil are identifie Records of the amount of particulate matter and water identified in the storage tanks are maintained by the chemistry department and trending analysis performed to identify any potential problems. The licensee also introduces microbiological growth inhibitors into the fuel oil to assure that the fuel oil transfer system does not become clogged due to the growth of microbiological organisms, b. Trip Of Safety Related Electrical Switchgear Breaker - On July 31, 1986, and again on August 2,1986, an electrical switchgear breaker tripped causing engineering safety feature actuations and a temporary loss of ventilation systems for certain areas. The SRI monitored licensee actions for these events and reviewed LER 86-047 issued to document the event and corrective actions taken by the license After the event on July 31, 1986, the licensee found the feeder breaker to containment unit cooler 1A tripped with an overload indication. They also found the main switchgear breaker trippe The licensee tested the equipment and circuitry and found no problems. As a precaution, they returned the switchgear to service with the unit cooler 1A in standby. The August 2, 1986, event occurred with the identical results including the overload indication on unit cooler IA even though it was not in service at the time of the event. Subsequent investigation by the licensee revealed that a BrownBovari,ModelITE500rglaywouldfailinthetripcondition when placed in an oven at 120 F for over 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br />. The malfunction of this relay caused the containment unit cooler overload indication and the switchgear feeder breaker trip. The licensee stated that a acw relay was tested under the same tem)erature conditions and no malfunction occurred. Therefore, tie defective relay was replaced with a new unit and the defective relay was returned to the manu-facturer in order to determine the failure mode of the relay. The LER stated that the manufacturer determined that the output transistor of the relay was defective which caused the trip. The manufacturer

'as recommended this transistor, identified as Q3 by the vendor on bis circuit board, be replaced with a different type transistor. The licensee has initiated actions to replace the output transistors on all affected relays in accordance with the manufacturer's recommendation ,

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The SRI review of LER 86-047 revealed several questions which will be addressed with licensee representatives prior to closure of this event followup. These questions are:

o Why did the equipment vendor recommend replacement of the original transistor?

o Was the original relay qualified for the environmental conditions in which it operated?

o Will the relays with new transistors be properly qualified and what will their qualified life be?

o Have all applications of this relay type been identified and corrected? Reactor Scram From Backup Scram Valve Opening - On August 31, 1986, with the unit at approximately 100 percent power, the loss of a cooling tower transformer led to a sequence of events that caused a reactor scram. Subsequent investigation by the licensee revealed the following events and cause of the scram:

o a cooling tower transformer fault occurred which caused a 13.8KV feeder breaker to trip; o feeder breaker trip caused the loss of a nonsafety-related electrical bus feeding power to the reactor protection system (RPS) 'A' motor generator set; o a half scram occurred due to loss of RPSA' power; o control operator noticed control rods moving in with only a half scram present and initiated a manual scram; o just prior to the initiation of the manual scram, a full automatic scram occurred on low reactor water level because of the initial power decrease from rods inserting; o the cause of the initial rod movement was found to be caused by a backup scram valve opening which vents the air off of the scram air header; o the opening of the backup scram valve was caused by the loss of power to RPS 'A' which provided half of the initiation logic and by a failed DC relay which provided the other half of the initiation logi The unit remained shutdown while the licensee investigated the cause of the event, and the f ollowing imediate and long term corrective actions were initiated prior to restart:

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o the faulted cooling tower transformer was isolated and a temporary replacement was installed; o oil and gas samples from the other cooling tower transformers were tested for any indication of failure potential; o circuit was replaced; ,

o a daily surveillance of the backup scram circuit relay status was initiated; o a plant modification request was initiated to install status lights in the backup scram valve initiation circuit; o a plant modification request was initiated to provide a more reliable source of power to the RPS motor generator set The imediate licensee actions in response to this event are considered prompt and thorough and final closure of this event followup will be documented during routine LER revie d. Reactor Scram From Turbine Trip - On September 2,1986, with the unit at approximately 90 percent power, a reactor scram occurred when the main turbine tripped from a RCIC system initiation. The unit remained shutdown while the licensee investigated the cause of the event. The probable cause of the event was determined to be air in a level reference leg which is comon to level instruments which would cause an RCIC initiation and, after a 15-second time delay, a main turbine trip would occur. This main turbine trip from a RCIC initiation is intended to prevent main turbine damage from water carryover when RCIC injects into the reactor head spray line. Maintenance personnel were troubleshooting a narrow range level transmitter problem just prior to the event, but they apparently had done nothing which should have caused a hydraulic disturbance in the instrument lines. However, the licensee's conclusion was that air was trapped in the instrument lines or reference leg and a small bump may have caused the air bubble to dislodge and produce the pressure / level spike in the instruments. No actual level transient occurred prior to the even Subsequent venting of the reference leg did reveal some air in the system. The licensee checked the other level reference legs and no indication of trapped air was found. In addition to returning the narrow range level instrument to service and checking for air in the other reference legs, the licensee initiated a condition report to investigate the correct setting for the time delay for main turbine trip following RCIC initiation. The event was also reviewed with operations personnel in order to heighten their sensitivity to RCIC initiation and the ensuing main turbine trip if RCIC is not reset within the time delay period. Also, the maintenance department is reviewing procedures to detail precautions needed when performing work on instruments which have common reference legs. The licensee's

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immediate responses to this event are considered prompt and thorough and final closure of this event will be documented during routine Licensee Event Report revie No violations or deviations were identified in this area of inspectio . Followup On Allegations Concerns were received by NRC Re Nos. 4-86-A-085 and 4-86-A-086) gion IV regarding (reference publicity allegation at River Bend on the problem with meeting the cooling tower discharge temperature limit on hot summer days and the measures taken to maintain that limit. The SRI had monitored and evaluated this condition during the times of occurrence, and the following information is provided from that monitoring and evaluatio The non.a1 cooling towers at River Bend provide a source of cooling water to the main turbine exhaust condensers so that the exhaust steam from the turbines can be condensed and returned for makeup water to the reactor vessel for normal electrical power production operation. This source of cooling water is nonsafety-related and is nonessential for safe shutdown of the reactor under any design basis events. A separate safety-related ultimate heat sink cooling tower and separate safety-related sources of cooling water are provi(ed for safe shutdown of the reactor and these safety-related sources are independent of the normal cooling tower During operation to produce electrical power from the main turbine, the normal cooling towers are in operation and although it is a closed loop cooling system, a certain amount of cooling water evaporates to the atmosphere. Therefore, a certain amount of makeup water from the Mississippi River is required to make up for the water that is lost due to evaporation. Also, this evaporation and makeup process tends to concentrate cooling water solids and chemicals in the cooling towers. In order to limit this concentration and to maintain the desired water chemistry, a certain amcunt of cooling tower water is returned to the rive Typical flow rates for cooling tower makeup and discharge with the plant at 100 percent power on a hot summer day would be about 14,000 gallons per minute makeup and 2200 to 3500 gallons per minute discharge back to the river. This discharge back to the river is allowed by both federal and state environmental permits. Poth of these permits were requested during the early design stages of River Bend, and the temperature limits established at that time were 91*F for a daily average and 96*F for a daily maximum. Although exceptions to these strict temperature limits are apparently allowed if justification is provided, no exceptions or changes were requested by Gulf States at this early design stage. River Bend was operated at 100 percent power during the hot sunner months of this year and they discovered problems with maintaining the restrictive 91*F daily average limit. In order to meet this 91*F daily average limit, several

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water from the cooling tower makeup routed through the heat exchanger to cool the discharge water prior to release to the river. Also, on certain hot summer days this temporary heat exchanger was sprayed with water, and on one very hot day ice was even used to cool the heat exchanger. All of these temporary measures were taken in order to meet the established environmental temperature limits until a request for a change to the environmental permits could be processed. Gulf States personnel stated that they had checked with other plants in the area that discharge water to the river and limits as high as 105 F with a much higher flow rate than River Bend have been approved. As stated previously, this condition was monitored and evaluated by the NRC Senior Resident Inspector at River Bend and the condition had no effect on safe operation or safe shutdown of the plan . In-Office Review of Written Reports of Nonroutine Events at Power Reactor Facilities The purpose of this portion of the inspection was to ascertain whether corrective actions discussed in the licensee's event reports appeared to be appropriate, and whether information reported satisfied reporting requirement The NRC inspector reviewed LERs 86-22 through 86-44. All reporting requirements were found to have been met, and all reports were adequate to assess the events reported. Corrective actions specified in the reports appeared to be adequate to identify the root causes and to correct these Cause No violations or deviations were identified in this area of inspectio . Exit and Inspection Interview An exit interview was conducted on September 16, 1986, with licensee

} representatives (identified in paragraph 1). During this interview, the j SRI reviewed the scope and findings of the inspection.

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