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Insp Repts 50-327/92-36 & 50-328/92-36 on 921129-930102. Violations Noted.Major Areas Inspected:Operations,Plant Maint & Surveillance,Evaluation of Licensee self-assessment Capability,Ler Closeout & Followup on Previous Findings
	ML20128A458
Person / Time
Site:	Sequoyah
Issue date:	01/12/1993
From:	Holland W, Kellogg P; NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II)
To:	;
Shared Package
ML20128A407	List: IR 05000327/1992036; ML20128A403; ML20128A430;
References
	50-327-92-36, 50-328-92-36, NUDOCS 9302020220
	Download: ML20128A458 (33)
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'+4 ****$ t Report No .: 50-327/92-36 and 50-328/92-36 1 Licensee: Tennessee Valley Authority !

6N 38A Lookout Place 1101 Market Street Chattanooga, TN 37402-2801 ;

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Docket Nos.: 50-327 and 50-328 License Nos.: DPR-77 and DPR-79 facility Name: Sequoyah Units 1 and 2 -

Inspection Conducted: November 29, 1992 through January 2, 1993 Lead 1ispector: @ Ke ~d5T Inspector krp DR

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Inspectors: S. M. Shaeffer, Resident inspector S. E. Sparks, Resident inspector L. S. Mellon, Reactor Inspecto L. i ., R ac o insp tor ,

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2 e r Faii, 4fKe l lo M~f,esection i P Da e iT0ned Diftsionof e ctor Projects

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SUMMARY Scope:

This routine resident inspection was conducted on site in the areas of plan ,

operations, plant maintenance, plant surveillance, evaluation of licensee -

self-assessment capability, licensee event report closecut, and followup on -

previous inspection findings. Region based inspectors also reviewed balance of plant performance during unit transients that occurred during this period.

l-During the performance of this inspection, the. resident inspectors conducted c several reviews of the licensee's backshift or weekend operations, i

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. 2 Results:

In the area of Operations, an apparent violation of Technical Specification 6.8.1 was identified for inadecuate and/or failure to follow throttle valve setting procedures. These inacequacies resulted in configuration control

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problems'which potentially had a significant effect on the ability of safety- y i

related systems to perform their intended safety function. In addition, <

training weaknesses were identified associated with several operators regarding the proper method to get throttle valve positions (paragraph 3.b).. ,

in the area of Operations, an unresolved item was identified for additional review of a licensee event involving a failure to maintain the Unit-2 . l refueling water storage tank solution tem >erature above the minimum _ Technical ~

Specification value for approximately 24 1ours (paragraph 3.d). ;

In the area of Operations, a violation of Technical Specification 6.8.1 was identified for inadequate and/or failure to follow procedures resulting in l lack of configuration control of the Unit 2 refueling water storage-tank immersion heater switches, and loss of configuration control of the 18 emergency diesel generator fuel oil transfer pump switch (paragraph 3.d).

In the area of Maintanance, the licensee was effective in-planning and ;

performing activities associated with the 48 volt-solid stato protection '

system power supply replacement (paragraph 4.a). ;

in the area of Engineering / Technical Support, a violation of Technical .

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Specification 4.0.5 was identified for failure to complete portions of the -

required 10 year inservice inspections of ASME Code Class components for numerous safety-related systems and associated equipment (paragraph 5). 3

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During a special review of recent control air system events, it was conclude that: the lack of information available to operators in the main control room

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prior to and during these events with regard to.the control air system status-L negatively impacted operators ability to respond and mitigate the events;L ther application of the FCV-6-105 valves in their current configuration may not be appropriate for system parameters, and subsequently may have contributed to .

t1e failures of the two valves; water or corrosion products apparently.did not contribute to the FCV-6-105 valve failures; however the inspectors were unable to determine if the previous water intrusion event generated corrosion

- products which resulted in erratic. operation of the 2-LIC-6-106 controller prior to the Unit 2 runback event of December 8 (paragraph ~9).- :

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REPORT DETAILS f Persons Contacted Licensee Employees

R. Fenech, Site Vice President

J. Baumstark, Manager

R. Beecken, Plant Manager ,

L. Bryant, Maintenance Manager ;

H.= Burzynski, Manager, NCRA- "

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L. Bush, Acting Operations Manager

M. Coo)er, Site Licensing Manager

R. Dra(e, Manager, Project Management / Project Controls

T. Flippo. Site Quality Assurance Manager

J. Gates, Technical Support Manager ,

C, Kent, Radiological Control Manager

R. Leonard, Site Manager, Bechtel

K. Heade, Licensing Engineer

R. Rausch, Modifications Manager H. Rogers, Acting Technical Support Manager

M. Skarzinski, Technical Support J. Smith, Regulatory Licensing Manager

R. Thompson, Compliance Licensing Manager

P. Trudel, Nuclear Engineering Manager

J. Ward, Engineering snd Modifications Manager i

N. Welch, Operations Superintendent t

K. Whittenburg, Public Relations NRC Employees ,

B. Wilson, Chief, DRP Branch 4

P. Kellogg, Chief, DRP Section 4A

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Attended exit intervie Other licensee employees contacted included control room operators, shift technical advisors, shift supervisors and other plant personne On December 1, 1992 Mr. Robert Fenech assumed the duties-of Sequoyah-Site Vice President. Mr. Fenech replaced Mr. Jack Wilson who had announced his retirement earlier this yea Acronyms and initialians used in this report-are listed in the last ,

paragrap . Plant Status Unit 1 began the inspection period operating at approximately full:

power. On December 3, the unit reduced power to approximately 80% to conduct maintenance activities.on one of the high pressure heater. drain

tank pumps. The unit returned to full power on December 4, _ On

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2 December 9, Unit I reduced power to 86% after the licensee identified a

7A heater drain tank pump oil cooler leak. The cooler was replaced, and the unit returned to full power on December 10. On December 15, the unit experienced a secondary induced runback to approximately 72 percent power due to problems in the control air system. The unit returned to approximately full power on December 17. On December 31, the unit experienced a reactor trip due to an electrical fault in the 500 KV switchyar The unit remained in Mode 3 for the remainder of the inspection perio Unit 2 began the inspection period at operating at a> proximately full power. On December 8, the unit experienced a runbac( (automatic and continued manually) due to a secondary transient. The transient was induced during set)oint adjustments to the 13 heater drain-tank level control valves. T1e unit was stabilized at approximately 30 percent:

power. Later on December 8, the unit increased power to approximately 60 percent while troubleshooting and repair activities were being accomplished on the # 3 heater drain tank leul control valves. The unit was returned to approximately full power on December 10. On December s, the unit experienced a secondary induced runback to approximately 68 percent power due to problems in the control air system. The unit returned to approximately full power operation on December 16. On December 31, the unit experienced a reactor trip due to an electrical fault in the 500 KV switchyard. The unit was restarted'

January 2 and ended the inspection period in Mode 1 (praparations being made to tie the turbine generator to the grid).

3. Operational Safety Verification (71707) Daily inspections The inspectors conducted daily inspections in the following areas:

control room staffing, access, and operator behavior; operator adherence to approved procedures,-TS, and LCOs; examination of panels containing instrumentation and other reactor protection system elements to determine that required channels are operable; and review of control room operator logs, operating orders, plant deviation reports, tagout logs, . temporary modification' logs, -and tags on compt nents to verify compliance with approved procedure The inspectors also routinely accompar.ied plant management-on plant tours and observed the effectiveness of management's influence on activities being performed by plant personnel.-

December 8, 1992 Unit 2 Turbine Runback On December 8, 1992, the: inspectors reviewed licensee activities related to a secondary induced turbine runback on Unit 2 from 100 -

percent powe Prior to the transient, on December 7, a slight level increase in the # 3 HDT was noted by Operations. Early on L December 8, an AVO identified that the level in the tank was high

! and level was-being controlled erratically. -Operations contacted-

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System Engineering to review the situation. An AVO and the system engineer then attempted to make adjustments to 2-LIC-6-106, which is the controller for the two, # 3 HDT LCVs, 2-LCV-6-106A and 2-LCV-6-106B. After several adjustments to the controller, erratic operation was still exhibited. The system engineer then observed that the level in the # 3 HDT was increasing and decided to depress a controller relay air cleanout plug to remove any possible debris. This small push button plug (spring return to close) cleans out the orifice between the controller's chamber These evolutions were performed at approximately 9:42 During a second attempt of this cleanout evolution, the push button stuck in for approximately 4 to 5 seconds. The sticking condition resulted in the controller output pressure decreasing to zero and-the 106A and 1060 valves fully closing. These valves going closed caused a loss of ap?roximately 30 percent of the available FW flow being supplied to t1e SGs. At the same time, operators in the CR -l received a condensate booster pump seal water flow alarm and ,

observed condensate booster pump suction pressure decrease substantially. When the system engineer unstuck the clean out plug, the 106A and 106B valves both stroked full open. The engineer and the AVO then checked the condition of the # 3 HDT level and the # 3 HDT bypass LCVs (105A and 105B) and determined that the conditions could soon initiate a turbine runback and 1 promptly informed the SOS in the C Operations subsequently 1 monitored the control board in anticipation of a runback. Wit the 106A and 1060 valves in a full open position, a runout- !

condition on the # 3 HDT pumps caused an automatic closure of the 106B valv This, in, turn increased the # 3 HDT level such that subsequently, at 9:44 a.m., a turbine runback occurred due to a #3 heater drain tank bypass valve (2-LCV-6-1058) opening to divert level from the tank to the condenser. The opening of the bypass valve initiates an automatic turbine runback by system desig '

The unit automatically decreased to approximately 75 percent power. At this time, operators observed that feedflow was less-than steamflow and SG levels were decreasing, despite the runback of the turbine. Operators then took manual control of the two

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running MFW pumps and further reduced turbine load. .At-9:45=a.m.,

the A MFW pump tripped on low seal injection water pressur Operators subsequently took actions'to manually start the two MDAFW pumps due to a' continuing drop in all SG levels. Operators continued to reduce turbine load and eventally stabilized the-unit at approximately 30 percent power. The lowest SG levels were-13 percent with the reactor tri) setpoint being 8 percent SG level. Throughout the event, tle control rods remained in automatic and no anomalies were observed on the primary side of the unit. At 9:48, operators stopped the MDAFW pumps and took manual control of the SG levels. Operator response to the '

transient appeared. adequat The licensee initiated an incident investigation of the-even I Plant Management requested that the team evaluate whether plant

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, 4 equipment required for escalation of reactor power to l approximately 60 percent was availabic. This request was due to a current high electrical demand on the grid. The team recommended that unit power could be safely increased while the affected secondary equipment was further evaluate Power was subsequently increased to approximately 60 percent on December The !! team identified several abnormalities on the non-safety equipment involved in the transient. These included: apparent -i problems with pressure switches that triaped the MfW pump, a high vibration alarm on the A MfW pump, and tie original. problems with 2-LIC-6-106, which was being explored during the initiation of-the event. The inspector evaluated the licensee's resolution to the above problems and of her issues prior to further escalation in ,

powe During the event, secondary conditions appeared to be such that both of the MrW pumps should have tripped. This would have resulted in a reactor trip. The licensee identified that the setpoint for the low seal water injection pressure device for the A MFW pump was set high such that the A MfP tripped too soon.- The B MfW pump, which did not trip, apparently operated as designe '

The licensee also evaluated high vibration on the tripped MFW pump as being a normal alarm due to the tripping of the pump. The-licensee stated that the alarm was trought in during coastdown of i the pump under the tripped conditions. Subsequent observations of the pump, which were made during restart, did not identify any abnormal operatio The licensee also investigated problems encountered with 2-LIC-6-106, the controller for the # 3 HDT LCVs, prior to the even The

3 HDT LCVs (known as 106 valves) were recently upgraded during the last forced Unit 2 outage in late October 1992. The inspectors monitored troubleshooting activities for the controller. After change out of the regulator,- an electric relay, and the mechanical cleanout plug which was stuck during the event,

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Plant Management decided to place tho'106 valves in service at a power level (60 percent)'which would. not result in a plant transient if the erratic operation problem had not been correcte '

No root cause of the controller anomalies was identified; however, the licensee identified several possibilities. One of the potential causes was that debris in the air system may have adversely affected operation of the component prior to the event, The licensee recently experienced an air system water intrusion 4 event which likely has increased the potential for particulate contamination in the air system. The-erratic operation of 2-LIC-6-106 could have been caured by particulate contamination; however, the licensee could not definitively. determine this as the root caus The inspectors monitored licensee actions late on December 8 and early on December 9 to place 2-LIC-6-106 in service for monitoring-prior to power escalation above 60 percent. The level in the # 3 HDT was being controlled via the two HDT bypass valves to the

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condenser 2-LCV-6-105A and 2-LCV-6-1058 (known as 105 valves).

These valves control level when the heater drains are not in service and no flow is through the 100 LCVs. During placement of 2-LIC-6-106 (the controller) in service, it was identified that the level in the # 3 HDT was above the tank sight glass. The tank sight glass is located slightly above the 50 percent level on the tan The licensee subsequently discovered that the 105A bypass valve was in the closed position, for the given conditions, with the high level in the # 3 HDT, both the 105A and 105B should have been open and bypassing flow to the condense The 105B valve was full open as required for the conditions. Upon investigation, the licensee discovered that the 105A valve was stuck in the closed position, although control air gages on the valve indicated an open demand signa Attempts were made to manually bleed control air off of the valve in order to move the valve to the open position; however, the valve was unable to be opened. During the disassembly of one of the air lines during this effort, approximately one pint of water was drained from the air supply line to the valve. After the water was drained, the valve still could not be opene The inspectors monitored the above activities. The plant was operating at approximately 60 percent power during these evolutions with the 105A valve failed shut. Due to this condition, the level in the # 3110T was above the normal operating level. Operatorr, could not determine where the tank level was and unless appropriate actions were taken, the level would continue to increase. The increasing level was due to the ongoing condition where flow into the tank exceeded the capacity of the 1058 valve to dumpback to the condenser, liigh levels in the #3 liDT could cause feedwater heater string isolations and could result in a reactor trip. The inspector discussed the secondary plant conditions with the 505. The SOS determined that due to the identification of water in the air system, the failed closed 105A valve, and an unknown level in the # 31101, the operators should slowly decrease power until the level in the # 3 IIDT was in the sight glass range. The inspectors considered this decision appropriate due to the known plant conditions and presumed rising level in the tank. At 12:13 a.m. on December 9, a unit power reduction was begun from 60 percent pcwer, lhe controlled power reduction continued until the # 3110T level was in the normal operating range as indicated on the sight glass. Additional review for the licensee corrective actions for the 105A valve is discussed in paragraph December 15, 1992 Dual Unit Runback On December 15, the inspectors monitored the licensee's response to a dual unit secondary induced runback. The event occurred at approximately 11:46 a. Both unit 1 and 2 experienced secondary induced transients initiated by an apparent partial loss of control air system pressure. Both units were at approximately

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100 percent power prior to the event. The transient began with ,

Unit I receiving alarms-associated with isolation of the service air system. Subsequent alarms were received regarding isolation of ice condenser glycol and radiation monitor containment isolation valves. Shortly afterwards, a bw main feedwater (HfW)

pump suction pressure alarm prompted the Unit =1 operators to take '

manual control of the MfW regulating valves _to maintain adequate steam generator levels. Operators then initiated a manual turbine

runback in order to further stabilize the unit. Shortly :

afterwards, an automatic turbine runback signal _ occurred due t high heater drain tank levels.- The unit was subsequently stabilized at approximately 72 percent reactor powe A Unit 2 transient also resulted from the partial loss of control air system pressure event. The unit experienced an automatic turbine runback- from 100 percent power due to high levels in the #

3 heater drain tank, which were initiated due to su) ply air porturbations to the tanks level control valves. Tae unit was i stabilized at approximately 67 percent reactor powe Early on December 16, the licensee tested suspect electrical components which may have caused the partial loss of control ai '

The results indicated that a loose handswitch connection in the-air system compressor loading sequencer allowed the compressors to not pick up air demand as required. 0ther circuitry in the sequencer was tested satisfactorily. The licensee stationed an auxiliary operator at the air compressor location throughout the evening to monitor automatic control of the air syste Based on the December 8 and 15, 1992 Units' transients, region based inspectors were dispatched to Sequoyah to review recent >

runback events. The inspectors reviews are discussed in paragraph-9 of this repor ;

b. Weekly Inspections

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The inspectors conducted weekly inspections in the following areas: operability verification of selected ESF systems by valve alignment, breaker positions, condition of equipment or component, and operability of instrumentation and support items essential to . ,

system actuation or performance. Plant tours were conducted which '

included observation of general plant / equipment-conditions, fire protection and preventative measures, control of activities in-progress, radiation protection controls, missile hazards,.and plant housekeeping conditions / cleanliness.-

Containment Spray and RHR lieat Exchanger Mispositioned Valves-On December 16. 1992, during the performance of SI-566, ERCW FLOW VERiflCATION TEST, Revision 22, the licensee identified that .ERCW-flow to the Unit 1 18 CSHX was not set as required. Actual ERCW flow through the CSHX was approximately 1,788 gpm while the

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. 7 requwed flow was approximately 3,600 gpm. Adequate ERCW flow for I the CSHX is set during SI-566 via adjustments to 1-67-5378, ERCW i CSHX throttling valve. The valve is an 18 inch Pratt butterfly i valve, and is manually set for the throttled positio The l required flow setting of 1-67-537B is identified by counting the '

number of hand-operator turns from the full open position (with '

valve at full open stop position) to achieve the desired flo I Upon discovery of the event, Operations personnel immediately identified the significance of the inadequate flow and, after documenting the as found position of the valve from the full _open ,

position, reset the ERCW valve to achieve the required flow _ The as found hand-operator position was approximately 4.25 turns greater than the required position (too far closed). The licensee ;

immediately verified adequate flow through the other CSHXs on both- <

units via SI-566. No other flow conditions below the requirements of 51-566 were identified at this time with regard to ERCW flow to the other CSHXs. As of late December 16, the licensee continued 51-566 for the remaining portions of the ERCW system. The licensee reported the event to the NRC as discussed in paragra)h '

3.f, for potential operation outside of ti design basis for t1e uni *

The licensee initiated an Incident Investigation due to the _ '

mispositioned valv During this review, it was identified that a potential existed to misposition these types of-valves by not including any hand-positioner slack in the required number of turns to reset the valve to the correct throttle position. =The licensee initially identifies and sets the throttle position (ie, number of turns from the full open-position) for all of the' ERCW CSHX valves via SI-566. The correct valve position is determined '

by actual flow conditions in the heat exchanger (ie. flow balancing). The number of turns identified via SI-566 for each ,

valve is then transferred to 0-SI-0PS-067-682.M. ERCW FLOW BALANCE VALVE POSITION VERIFICATIO This procedure utilizes the '

information to reset the ERCW valve to the required flow )osition if, for reasons such as maintenance, the ERCW valves to t1e CSHXs are manipulated, it was postulated that during resetting of 1-67-5378 utilizing 0-SI-0PS-067-682.H that the valve was mispositioned, :

Licensee corrective actions were expanded to include verifications of the throttle valve positions in the CCS, These verifications were being performed by counting the actual position of the CCS throttle valves from the full osen position. ~ Un December 19, '

1992, Unit 2 valve 2-70-546A, tie CCS throttling valve for the 2AA RHRHX, was found to be at 23 turns, while the required position-was 19.75 turns. The amount of degraded flow to the RHRHX could-not be-immediately determined without engineering calculations; however, the licensee assumed the flow to be below the required value. Subsequently, this was also reported to the NRC as described in paragraph 3.f, as a potential' for operation outside

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i of the design basis of the plan Later analysis determined that the reduced flowrate was approximately 3,500 gpm whereas the required flow was 5,000 gpm. Once 2-70-546A was identified as mispositioned, the throttle valve was reset to-the required position. The mispositioned CCS throttle valve was also an 18

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inch Pratt Butterfly valve. The amount of slack travel in 2-70- ,

546A further confirmed that the mispositioning of the valves could have been attributed to errors in counting the required number of .(

hand positioner turns from the full open position and not allowing for slack in the valve operato Based on the above findings, the licensee took the following corrective actions:

- Completed performance of SI-566 for the ERCW system (adequacy of throttle valvo position by flow parameters).

No other flow requirements were identified as being exceeded; however, subsequent review identified that one other valve was mispositioned by 5/8 turn (1-67-537A).

This is further discussed later in this repor Retrained personnel currently involved in throttle valve positioning on the correct methods to account-for valve

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slac Utilized the retrained personnel to reverify that all '

ERCW throttle valves were set properly (per 0-SI-0PS-067-682.H).

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Verified all CCS throttle valves were set properl Reviewed other systems utilizing throttle valves for similar problems. The licensee did not identify any other systems as being susceptible to the identified proble In addition to the identification that 1-67-5378 and 2-70-546A were mispositioned, a position verification 'of the ERCW throttle valves identified that 1-67-537A, Unit 1 CSHX ERCW throttle valve, was mispositioned by 5/8 of a hand wheel turn from the required ,

position.- However,_the mispositioning of 1-67-537A did not reduce the flow below the acceptance criteria of the'previously performed SI-566. The licensee concluded that 1-67-537A was mispositioned in the same manner as the other heat exchanger valve The inspectors reviewed >the safety significance of the event.- The mispositioning of 1-67-5378 and 2-70-546A resulted in the flow in each of the valves respective heat exchangers to be .less than that required by the controlling procedures. The effect ofLthis degraded flow would be an increase in 'the peak containment pressure experienced during a. large break LOCA accident scenario.-

The licensee performed computer modeling to determine the

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postulated maximum increase in the peak containment pressure for

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each unit and whether the units were operating within their_ design basis. Sequoyah's containments are designed to 12.0 psig with an analyzed peak of 10.9 psig for the design basis accident. The results of the licensee's analysis indicated that the pressure >

peak for Units 1 and 2 respectively was 11.3 and 11.4 psig for tb worst case conditions. Therefore, the licensee concluded that the

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reduced flow conditions in the heat exchangers did not result in-either units operation outside of its design basi '

The inspectors requested that the_ licensee evaluate the potential effect of previous ice condenser discrepancies in conjunction with the degraded flow through the two heat exchangers. The two ice condenser problems dealt with inoperable ice condenser inlet doors and degraded ice weights for specific periods of time. The i inspectors reviewed engineering evaluations regarding the combined effect that the ice condenser problems and the degraded flow to the heat exchangers would have on maximum containment pressure design allowable limits. The licensee concluded-in these evaluations that the ice condenser problems did not increase the analyzed peak containment pressure which occurs immediately after ice meltout during a large break LOCA accident scenari Therefore, the licensee concluded that the_ combined effects of the ;

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ice condenser problems and the degraded flow through the RHR and containment spray heat exchangers did not exceed the maximum containment pressure design limit of 12 psi j The inspectors reviewed the root causes for the event. ' It was concluded that if, for example,- 3 to 4 turns of freeplay (low ,

resistance turning of the hand positioner) was not included in the required number of turns to set the throttle valves, mispositioning of the valve would result. One root cause of the event was that operators did not properly include the free) lay of the valves in the required number of turns identified in-tie -

procedur All of the valve misposition problems occurred _on 18 inch Pratt butterfly. valves. The licensee inspected new and old j valves of this type and concluded that a varying amount of freeplay existed in the valve operators regardless of _its ag However, if the freeplay in the operator is_ correctly included when the throttle position is being set, the required valv positions could be obtaine The inspector reviewed the event with regard to adequacy'of plant procedures. SI 0-SI-0PS-067-682.M, ERCW FLOW BALANCE VALVE POSITION VERif!CAliCN, Revision 2, implements configuration control for th position of throttled valves in the ERCW syste Similarly, S: RI-0PS-070-032.A, COMPONENT COOLING-WATER VALVES POSITION VERIF 4 CATION TRAIN A, Revision 1, implements '

configuration control for- the position of throttled valves. in the CC Both_of these procedures contained guidance in the Precautions and Limitations (Section 3.0), that " Failure to allow for slack which exists between valve' stem and handle on some-

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throttled valves may lead to mispositioning of valves". The-inspectors concluded that the guidance in 0-SI-0PS-067-682.M and 2-SI-0PS-070-032.A was inadequate in that the appropriate method ;

to allow for freeplay in the valves was not specifie '

Technical Specification 6.8.1 requires, in part, that the written )

procedures se established, imp!emented and maintaine This -i includes procedures for control and operation of safety-related system Contrary to this requirement, performance of the i aforementioned procedures resulted in the mispositioning of the Unit 1 18 Containment Spray Heat Exchanger ERCW throttle valve (1- 'i 67-537 B) from November 30, 1991 through December 16, 1992, the

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Unit 1 1A Containment Spray Heat Exchanger ERCW throttle valve (1-67-537 A) from November 30, 1991 through December 18, 1992, and the Unit 2 2A Residual Heat Removal Heat Exchanger CCS throttle valve (2-70-546A) from approximately March 1, 1989 through December 19, 1992. This is identified as an apparent violation of '

TS 6.8.1 (327, 328/02-36-01, Inadequate Throttle Valve Settinc Procedures). ,

The inspectors also reviewed SI-566, ERCW TLOW VERIFICATION TEST, ;

- UNITS 0, 1, AND 2, REVISION 22, which determines new throttle vat i positions for ERCW cooled components. Step 6.4.17 of SI-566 *

requires, in part, (for the example of B train ERCW) that-the Operations Supervisor or SOS be provided with an updated list on B train ERCW throttle valve positions for 0-SI-0PS-067-68 '

However, this step did not include requirements to ensure that data contained in SI-566 was incorporated into 0-SI-0PS-67-68 The licensee identified that in seven examples, the data in 51-566 '

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was not properly transferred to 0-SI-0PS-067-682.M. In one of the seven examples, SI-566 indicated that the ERCW throttle valve position for the 2B centrifugal charging pump room cooler should be throttled nine turns; however, 0-SI-0PS-067-682.M indicated that the valve position should be full open. The valve was found .

set in the correct nine turn position; however, if maintenance had been performed, the valve could have been mispositioned via-the incorrect value in 0-SI-0PS-067-682.M. The other six examples involved deviations of 1/8 to 1/4 turns between the two .

procedures. None of the examples resulted in inadequate ERCW flow to the associated c'omponents. The inspectors review of SI-566 determined that the procedure was inadequate in that there was no positive administrative t.ontrols-identifled in SI-566 to assure completion of the required updating activities. This is identified as an additional example of apparent violation 327, ,

328/92-36-0 The licensee and the inspectors concluded that a main contributor to the valve mispositioning problems was unclear guidance in throttle valve setting procedurt:s. It was also concluded that operator training with regard to the basic knowledge of correct methods for setting throttle valve positions was weak. Thes ~

combined procedural problems and training inadequac M resulted in

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a condition which potentially could have resulted in operation of the units outside of the design basis for a substantial period of time. The inspectors considered the event to be a significant :

example of configuration control problems at Sequoya ;

c. Biweekly Inspections lhe inspectors conducted biweekly inspections in the following areas: verification review and walkdown of safety-related tagouts !

in effect; review of the sampling program !

secondary coolant samples, boric acid tank (e.g., primary and: samples, i '

and gaseous samples); observation of control room shift turnover; review of implementation and use of the plant corrective action program; verification of selected portions of containment isolation lineups; and verification that notices to workers ar i posted as required by 10 CFR 1 ,

d. Other inspection Activities !

Inspection areas included the turbine building, diesel generator building, ERCW pumphouse, protected area yard, control room, vital 6.9 KV shutdown board rooms, 480 V. breaker and battery rooms, an !

auxiliary building areas including all accessibic safety-related .

pump and heat exchanger rooms. RCS leak rates were reviewed to ensure that detected or suspected leakage from the system was recorded, investigated, and evaluated; and that appropriate y actions'were taken,'if required. The inspectors routinely .

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independently calculated RCS leak rates using the NRC RCS leak' ;

rate computer program specifically formatted for- Sequoyah. - RWPs ,

were reviewed, and specific work activities were monitored to :

assure they were being accomplished per the RWPL.z Selected radiation protection instruments were periodically checked, and-equipment operability and calibration frequencies were verifie (1) During an operator control _ board walkdown_on December 24_,

1992, the licensee identified that one of the t o RWST temperature indicators for-Unit 2 was below- the required TS limi TS 3.5.5 requires that the RWST minimum solution temperature be 60 dearent F in~ Modes I through 4.- Typical RWST temperature for the winter season is-approximately 70 degrees F. One of the temperature indicators was found at 60 degrees F while the other was found to be indicating at '

58 degrees F. Based on this information, the licensee entered the ACTION statement of TS 3.5.5, which requires that, with the RWST inoperable, restore the tank to operable:

status within I hour-or be in at least Hot Standby within-6 1 hours1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months and in Cold Shutdown in the following 30 hours3.472222e-4 days 0.00833 hours 4.960317e-5 weeks 1.1415e-5 months > i The licensee initially determined that the RWST cooldown was caused by the previous running of one containment spray pump >

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in recirculation to the RWST in conjunction with ERCW

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12 I cooling supply to the applicable containment spray heat exchanger not being isolated. The licensee was performing two testing evolutions concurrently to complete inservice inspection activities for these two systems as discussed in paragraph 5 of this report. The licensee determined that the ERCW system was started at about 11:00 p.m. on December 22. On December 23 at approximately 5:10 a.m., the containment spray pump was started in accordance with the quarterly pump test procedure to support ISI activities, and ran for approximately two and one half hours. On December 24, at approximately 3:00 a.m., during the performance of 2-SI-0PS-000-003.0, Daily Shift Log, Rev. 6, a control room operator identified that the RWST temperature was outside of TS limits. TS LCO 3.5.5 ACTION Statement was entered, and the licensee initiated actions to raise the RWST. temperature to within TS limits. These actions included running one containment spray pump and one safety injection pump-in recirculation with ERCW isolated to add heat to the RWS Approximately four hours after entering the action statement, the RWST temperature was increased above the required minimum TS valu The licensee evaluated the effect of the lower RWST temperature on containment due to an inadvertent containment spray event in conjunction with an inadvertent containment; air return system operation. The design basis maximum containment external pressure differential as' stated in Tah'e 6.2.6-1 of the FSAR is 0.5 psid. In addition, the assumed initial conditions required for accident evaluation with regard to the minimum RWST temperature: as stated-in-Table 15.4.1-4 is 60 degrees F. The licensee performed an additional analysis as a result of this event, and determined that an.RWST temperature of 50 degrees:F or greater would be acceptable, based on the design capacity' of ,

the containment vacuum relief valves. The licensee determined, based on plant computer data and cooldown rates',

that the estimated actual minimum temperature of the RWST was approximately 56 degrees F. Thus, the licensee concluded that the containment external design pressure differential would not be exceeded during an inadvertent-containment spray event.- In addition, the_ licensee-determined that the lower RWST temperature would'have a negligible effect on boron solubility and thermal shock to the reactor vessel upon injectio '

As part of corrective actions,-the licensee initiated an Incident Investigation. As stated above, the licensee determined as a result of this event that an RWST

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temperature of 50 degrees F or lower would exceed the design-

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could negatively affect containment integrity. The

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estimated actual minimum temperature of the RWST was L

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approximately 56 degrees F. However, the licensee's RWST design temperature was assumed to be 60 degrees Fahrenheit, which is also the TS valu The inspectors stated that the licensee may need NRC review and approval if a new design temperature for the RWST is used to support a new formal containment external pressure differential design evaluatio The inspectors reviewed the event with regard to configuration control of the RWST and containment spray system The licensee was performing 2-SI-SXI-067-00 INSERVICE PRESSURE TEST OF ESSENTIAL RAW COOLING WATER SYSTEM - SUPPLY HEADER 20-B, Rev. 1, in conjunction with a test procedure in order to operate the containment spray pump to pressurize the containment spray system. These activities were being conducted concurrently to facilitate the completion of inservice inspection activities which had not been completed as scheduled (paragraph 5 of this report). The inspectors concluded that a root cause of the above event was the lack of proper planning, coordination, and configuration controls during the corrective actions being implemented for missed ISI pressure tests. The licensee did not adequately identify the of fect of running the containment spray pump in conjunction with s,upplying ERCW to the heat exchange At the end of the inspection period, the inspectors were continuing with their review of the root cause of the RWST cooldown even The inspectors were focusing on the following reviews when the inspection period ended:

- Adequacy of procedures involved in testing evolution Administrative requirements for conduct of testin Administrative requirements for conduct of operations during test evolution Licensee administrative requirements for making changes to procedures and whether these requirements are in compliance with TS 6.5.lA and/or 6. Based on continuation of the reviews into the next resident inspection period, this item is unresolved (URI 327, 328/92-36-02, Determination of root cause of event involving a failur to maintain the Unit 2 refueling water storage tank solution temperature above the minimum Technical Specification value for approximately 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months ),

in addition, during the above investigation, the licensee also discovered that handswitch 2HS-63-132 for two of the four RWST 9 KW immersion heaters (four heaters per RWST,

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14 each handswitch controls two heaters) was in the off rather than the automatic position. The inspectors requested design information on the RWST heater Initially, the licensee informed the inspectors that the design basis for ;

the RWST heaters was for freeze protection purposes. The -!

inspectors questioned whether the RWST heaters were being ,

utilized to maintain the RWST solution temperature above the !

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TS minimum temperature limit. The RWST heaters provide the only heat source to the RWST (other than running a pump and recirculating back to the RWST), and are calibrated to energize at between 62 - 70 degrees F. In addition, the inspectors could not identify any procedures to control RWST temperature. Due to the specified heater temperature range, the lack of proced:res to regulate RWST temperature, and the acidic nature of the RWST tank, the inspectors considered that the RWST heaters were providing heat during cool ambient temperature periods to maintain the RWST solution above the TS minimum tem)erature limit of 60 degrees F. The inspectors again met wit 1 licensee engineering personnel and were informed that an additional requirement of the RWST heaters was to maintain the RWST above 60 degrees F during normal standby condition t The inspectors reviewed the adequacies of procedures related-to the event. Periodic Instruction 0-PI-0PS-000-006.0, FREEZE PR01ECT10N, Rev. O, identifies equipment needing . "

freeze protection, identifies the means of protection, and provides requirements to ensure equipment operability during the months needed. The PI identifies the Unit I and Unit 2 RWST immersion heaters as freeze protection _ equipment, and ,

3rovides a checklist to verify that- the breakers to these .

1 eaters are closed. However, this.PI did not require that "

the handswitches be in the automatic position. The inspectors concluded that 0-PI-0PS-000-006.0 was' inadequate in that no requirement existed to ensure RWST immersion heater operabilit Technical Specification 6,8.1 requires, in part,_that written procedures be established, implemented and maintained. This includes procedures for control and operation of safety-related systems. ' Contrary to this -

requirement, 0-PI-0PS-000-006.0 did not arovide for configuration control of RWST immersion ;1 eater power supply switches resulting in inoperability of two of the four Unit 2 RWST immersion heaters for an unknown period.of tim This .is identified as a violation of TS 6.8.1 (327, 328/92--

36-03, Inadequate Procedure for Configuration Control of.the RWST Immersion Heater Switches).

The inspectors discussed with 0perations Management ~the similarities of this event to other events in which-components were not maintained in preferred or required

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configuration. An additional example was identified as i discussed below-in which the EDG fuel oil transfer pump !

handswitch was found to be in the improper position. In a some instances these components were not covered under any configuration control; although, they could ultimately affect the operability of a safety-related component or system. Due to these problems, Operations and Technical Support management initiated corrective action to review all 501s to identify other important to safety components which may need to be under configuration contro (2) .0n December 21, the licensco identified during an AVO shiftly round of the EDG building that a handswitch for the 101-B and 182-B day tank supply pump was-in the OFF position instead of the AUTO position. Although this handswitch was not on the EDG building AVO rounds checklist, an AVO identified-this switch to be in the incorrect position. The licensee's-initiated an incident Investigation to determine the circumstances surrounding this event. The licensee determined that on December 17 and IB, calibration-activities were being conducted on the level' switches for the IB EDG day tanks. A PI was used to control these calibration activities, and noted that the handswitch was returned to AUTO position. Subsequent to these activities, ,

calibration of the 7-day fuel oil tanks was to be conducte The licensee determined that the-most probable cause of t handswitch being left in the OFF position was due to an AVO placing the switch in the OFF position to prevent any 7-day tank level fluctuations during tank calibration'. The inspectors and the Itcensee reviewed the safety significance of the above even The normal position of the handswitch is the AVIO position, as stated in'S01-82.2, Diesel Generator IB-B, Rev. 39, Section 82.2G, V. During c fully loaded EDG operation (emergency. demand condition), EDG fuel consumption is approximately 75 gallons per hour. A control room annunciator alarms at a day tank level-of 250 gallons. _ Therefore, after the day tank low level annunciator alarms, operators would have.approximately three hours to take action, which would involve placing the-o handswitch from the 0FF position to the AUT0 position and l- refilling the day tanks. The inspectors concluded this to i be an example of failure to adhere to the requirements _of L

S01-82.2 fn that-the handswitch for the fuel oil transfer pump from the 7-day tank to the skid mounted day tank was in

the 0FF position instead of the AUTO position. This is identified as an additional example of a violation of TS 6.8.1 (327, 328/92-36-03, Failure to follow Procedure

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.Resulting in_ Loss of. Configuration Control of the.lB EDG Fuel 011 Transfer Pump Switches).

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16 Physical Security Program Inspections in the course of the monthly activities, the inspectors included a review of the licensee's physical-security program. The performance of various shifts of the security force was observed in the conduct of daily activities to include: protected and vital area access controls; searching of personnel and packages; escorting of visitors; badge issuance and retrieval; and patrols and compensatory posts. In addition, the inspectors observed protected area lighting, and protected and vital areas barrier integrit Licensee NRC Notifications (1) On December 1, 1992, the licensee made a four hour >

notification to the NRC as required by 10 CFR 50.72 when the licensee determined Units 1 and 2 operated outside of design basis. Through a review of ice condenser ice weight data for Unit 1, cycles-4 and 5, the average ice basket weight in Row 1 Group 1 at a 95% confidence level was less than the value used in the safety analysis. A subsequent evaluation -

for Unit 2, cycle 4, as found data also concluded that the average ice basket weight.for Row 1 Group 3 was less than -

the value used in the safety analysis. This issue is further discussed in paragraph ."

(2) On December 2, 1992, the licensee made a four hour notification to the NRC as required by 10 CFR 50.72 with regard to a notification made to the FAA when it was discovered that the aircraft warning light atop the meteorological instrumentation ~ tower was not li (3) On December 8, 1992, the licensee made a four. hour-notification-to the NRC as required by 10 CFR 50.72 with regard to a Unit 2 ESF actuation. At'9:44 a.m., a Ur.it 2 turbine runback occurred due to a #3 heater-drain tank bypass valve opening while the # 3 heater drain tan discharge valve was undergoing setpoint adjustment Subsequent to the automatic runback,-the 2A MFW pump tripped on low seal injection water pressure due to condensate pressure swings. Operators then manually-reduced Unit 2 power to approximately 28% in conjunction.with taking manual control of the running:MFW pump and manual initiation- of the MDAFW. pumps in response to low steam generator level The unit was stabilized at approximately-30% power. The licensee conducted an incident investigation of the transient. This event is further discussed in paragraph of this Inspection Repor (4) On December 15, 1992 the licensee made a four hour notificatior to the NRC as required by 10 CFR 50.72 with:

. regard to an automatic ESF actuatio The ESF nctuation was

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considered to be inadvertent and occurred when various containment isolation valves went clnsed due to a loss of control air to the valves during a dual unit turbine runback. The transient is further discussed in paragraph 3.a of this inspection Repor (5) On December 17, 1992 the licensee made a one hour notification to the NRC as required by 10 CFR 50.72 with regard to Unit 1 being identified as operating outside of its design basis. During the performance of an ERCW flow balance test, the licensee identified that ERCW flow through the Unit 1 IB Containment Spray Heat Exchanger was approximately 1,788 gpm; however, the required flow was approximately 3,600 gpm. The licensee immediately placed the valve in the required position. This event is further discussed in paragraph 3.b of this inspection Report. The licensee subsequently retracted this 50.72 report on December 28, 199 (6) On December 19, 1992 the licensee made a one hour notification to the NRC as required by 10 CFR 50.72 with regard to the identification that valve 2-70-546A, 2A RHR Heat Exchanger CCS Inlet Throttle Valvo, was mispositioned resulting in the possibility that the cooling capacity of the heat exchanger could have been outside of its design basis limits. The licensee identified the event as part of an ongoing investigation into another mispositioned valve as described in paragraah 3.f (5) of this report. The licensee immediately placed tie valve in the required position. This event is further discussed in paragraph 3.b of this Inspection Report. The licensee subsequently retracted this 50.72 report on December 28, 199 (7) On December 31, 1992 the licensee made a one hour notification to the NRC as required by 10 CFR 50.72 with regard to entry into the plant emergency plan and declaration of a NOVE, On December 31, at approximately 9.50 p.m., Sequoyah Units 1 and 2 experienced reactor trips from approximately full power due to undervoltage conditions being sensed by protective relays on the units' electrical boards. The electrical disturbance was caused by a fault occurring in the plant switchyard. The fault resulted in a loss of most of the distribution for the 500 KV switchyard and also resulted in a loss of the intertie transformer between the 500 KV and 161 KV switchyard (Preferred power is supplied by the 161 KV switchyard to the common station service transformers for both units.) The 161 KV switchyard experienced a voltage perturbation for approximately 90

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cycles during the electrical transient.- This condition resulted in both unit's shutdown boards isolating from offsite power and all four emergency diesels starting and connecting to loads from the shutdown boards. The licensee I -- - _ __- -_____- ___-

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declared a NOUE based on the unknown cause of the electrical transients ;.nd remained in this condition until offsite power was determined to be reliable in the 161 KV yard and the shutdown boards were transferred back to offsite preferred powe All safety systems performed as designed; however, during recovery of Unit 2 af ter the reactor trip, operators disabled both high head injection pumps for approximately 2 minutes due to a f ailure of valve coordination control between the pumps' suction supplies (VCT and RWST isolation valves). The licensee subsequently made an additional 4 hour4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months notification to the NRC as required by 10 CFR 50.72 with regard to a condition that alone could have prevented the fulfillment of the safety function that was needed to mitigate the consequences of an acciden A Special inspection Team reviewed this event and the results of this review were discussed in inspection report 327, 328/93-0 Within the areas inspected, one violation and one apparent violation were identifie . Maintenance Inspections (62703 & 42700)

During the reporting period, the inspectors reviewed maintenance activities to assure compliance with the a)propriate procedures and requirements. Inspection areas included tie following: On December 1, 1992, the inspectors observed planning and maintenance activities associated with replacement of the Unit 2 SSPS train 'A' 48 volt power supply. This power supply is 1 of 2 auctioneered 48 volt train 'A' powqr supplies for the safeguards driver cards and undervoltage drivec card, and was producing approximately 13 volts. The inspectors reviewed the licensee's SSP-7.1, LIMITING CONDITIONS FOR OPERAil0N - MAINTENANCE PLANNING CHECKLIST, Rev. J, and attended various licensee meetings discussing the replacement. Although failure of the above power supply did not require entry into any TS LLO, the licensee determined that it would be prudent to enter TS LC0 3.3.1, item 21, action 12, to perform maintenance to replace the failed power supply. This TS LC0 requires Mode 3 entry within 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months , and subsequent entry into TS LC0 3.3.2 requiring Mode 4 entry within an additional 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months . Tha licensee concluded that continued operation with the train 'A' power supply in the feiled condition places Unit 2 in jeopardy of receiving an automatic reactor trip should the second of the two auctioneered 48 volt power supplies decrease to less than the required voltage to hold the reactor undervoltage coil in t% energized condition. Also, failure of any one of the four train 'B' SSPS power supplies (2-48 valt

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supplies, 2-15 volt power supplien), or failure of vital invertor 2-11, 2-111, or 2-IV would also result in a reactor trip. Licensee :

activities also included a burn-in of the replacement power supply 1 to verify proper operation and performance of a mock-u) repai :

Prior to performance of work activities, the licensco 1 eld a PORC meeting, which is discussed in paragraph 6.a of this inspection i report. The inspectors also observed the performance of WR C127880, which was used to replace the 48 volt and 15 volt power supply (the drawer contains both power supplies as a set). Work activities were completed in a satisfactory manne No previous failures of these power su) plies on either unit have occurred. In addition, voltages are caecked every 62 days on each train and no previous degradation has been noted. The licensee has scheduled WR Cl31287 to determine the failure mechanism of the 48 voit power suppl The inspectors concluded that the licensee was effective in -

planning and performing activities associated with the 48 volt SSPS power supply replacement. A well thought out action plan was developed, and appropriate contingencies were discussed with the a)propriato personnel. The licensee's technical support for the a)ove activity was effective, and contributed to the overall success of work. activitie On December 2,1992, the licensee performed scheduled monthly maintenance and surveillance of EDG.28-B. Previous problems with load swings and oscillations had been experienced, as discussed in Inspection Report No. 327,328/92-35. The licensee made arrangements for an electric governor vendor representative to observe testing, and assist in troubleshooting activities if problems were experience The licensee. attempted to connect recorders to the electric governor control circuitry; however, .

minor problems with the recorder hookup prevented the recorder from being used. EDG 28-B was started and performed satisfactorily, however, prior to the conclusion of S1-102 M/M, load oscillations were experienced. The recorder was connected to various locations of the control circuitry, but was purposely not turned o The load. oscillations stopped when licensee persotmel removed electrical connections from the recorder to the electric gcVernor.- Licensee personnel could not- definitively conclude that -

the oscillations were attributed to the recorde Additional troubleshooting activities were conducted, and EDG 28-B was started and loaded on December The EDG performed satisfactorily again, however, at the conclusion of troubleshooting, load swings of approximately 500 KW were again experienced. 1he recorder was turned on during the run, however, upon-inspection, the licensee determined that some electrical connections were landed incorrectly (they were connected to the terminal blocks instead of on the amplifier card).

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The licensee brought in an additional individual with EDG '

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e:tportise to assist in troubleshooting. On December 3 and 4, the 1 licensee identified that electrical noise, on cables between the protective relay cabinet and the electric governor, was the apparent cause of the load swings. The licensee initiated TACF 2- !

92-0038-082 to replace the existing cables with new shielded '

cables, along with some changes in where wiring was terminate '

The licensee performed successful post-maintenance testing of EDG 2B-B on December 4. Discussions with licensee personnel indicated {

that the EDG 28-8 has not exhibited the load oscillations and the general rough operation of the electric governor after the troubleshooting was performed on December 2-4. The licensee also indicated tha6 continued monitoring of EDG 28-8 will be performe .

Although not-required, the licensee considered it-prudent to plan a retest of EDG 28-B on December 16, as part of an enhanced effort- !

to monitor EDG performanc The results of this testing were satisfactory, with no load oscillations or swing ,

The inspectors concluded that the licensee's initial observations t and troubleshooting activities on December 2 were not well coordinated and performed. Subsequent activities, including

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technical support during. troubleshooting, resources,-and-management oversight, were properly focused on evaluating the EDG-28-B performance probleni ~

g Wthin the areas inspected, no violations were identifie a Surveillance inspections (61726 & 42700) .

During the reporting period,- the inspectors reviewed various :

surveillance activitias to assure compliance with the appropriate procedures and requirements. The inspection included a review of the following procedures and observation of surveillances:

On December 22,1992, the inspectors were -informed by the licensee that certain 151 requirements were not met as part of the first 10 year ISI surveillance periods.. TS 4.0.5 requires, in part, that surveillance

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y requirements for ISI and inservice testing of ASME Code Class 1, 2, and-3 components be performed as required by 10 CFR 50.55a(g). :ASME-Section XI requires, in aart,'that a visual inspection (VT-2) be performed during each of tie three inspection--periods for each 10 year inspection interval.- During. review of inspection- verifications for the second inspection period, the licensee identified that the pressure test visual-inspecticas were not performed for the following systems and components: a Unit I and Common Auxiliary feedwater - Turbine driven pum .

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Safety injection System - from FCV-63-5 through SIS pumps to secondary check valve Containment Spray System - from pump suction isolation valve to the last valv ERCW - Entire system (except for Class 3, inside containment).

Spent fuel Pit - The fuel pool cooling system and the demineralize VDiLZ

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Auxiliary feedwate'.' - lurbine drivtn pum Safety injection System - from FCV-63-5 through SIS pumps to secondary check valve Containment Spray System - from pump suction isolation valve to the last valv ERCW - Entire system (except lower compartment piping inside containment),

RHR Hot Leg injection - from FCV-63-172 to secondary check valve ,

Upon identilication of the missed surveillances per TS SR 4.0.5, the licensee entered the applicable LCOs AC110N statements. Due to both trains of containment spray for both units and both trains of ERCW for Unit 2 Deing affected, TS 3.0.3 was entered. However, as allowed by TS SR 4.0.3, the action requirements were delayed for up to 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months to allow for completion of the missed SRs. The licensee initiated actions "

to perform the missed ISI pressure tests within the allowed TS action requirements for at least one train of each dual train affected syste This work was begun on December 22. This work, which was required to be completed within 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months consisted of the B train of the containment snray system for each unit and the B train of ERCW for both units. Also on December 22, the licensee informed the NRC that the scope of work for the inspections may exceed the TS allowable tieeframes. On December 23, the licensee confirmed that the volume of work for one train of ERCW could not be completed, In addition, it was also determined that completion of the A train ERCW inspections for both units per TS LC0 3.7.4 could also not be completed in the TS allowed LC0 ACTION tim Subsequently, a telephone conference was conducted on December 23, between the licensee, NRC Region 11, and NRC Headquarters personnel, in

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which the licensee requested a Temporary Waiver of Compliance. The licensee requested a waiver of TS 4.0.3 for an additional period of time not to exceed 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months form 11:30 a.m. on December 23, 1992 and a Temporary Waiver of Compliance of TS LC0 3.7.4 ACTION for an additioncl period of time not to exceed 96 hours0.00111 days 0.0267 hours 1.587302e-4 weeks 3.6528e-5 months from 11:30 a.m. oa December 25, 1992, The purpose of the Waivers was to allow sufficient time to

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complete the total scopo of pressure tests of the ERCW system and ;

thereby satisfy the SR without unnecessarily requiring the shutdown of both units. At the conclusion of the conference call,' the NRC verbally approved the Waiver of Compliance. Written approval was subsequently documented in a letter-to the licensee dated December 24, 1992. On December 27, 1992 the licensee completed the required inspections to satisfy the requirements of T .

The inspectors reviewed the event with regard to the requirements of 1S-4.0.5. TS SR 4.0.5 specifies inservice. inspection and testing :

requirements of ASME Code Class 1, 2, and 3 component These requirements maintain, in part..that inservice inspection of ASME Code !

Class 1, 2, and 3 components and inservice _ testing of ASME Code Class 1, >

2, and 3 pumps and valves shall be performed in accordance with Section XI of the ASME Boiler and Pressure vessel _ Code and applicable Addenda as -

required by 10 CFR 50 Section 50.55a(g), exc:pt where specific written ;

relief has been granted by- the Commissier, pursuant to 10 CFR 50, Section l 50.55a(g)(6)(1).

ASME,Section XI, Table IWD-2500-1, requires a visual inspection (VT-2)-

as a part of an inservice pressure test of safety-related components *

within each of the three intpection periods during each 10 year inservice inspection interva Contrary to the above requirements, on December 22, 1992, the licensee discovered that required pressure tests on various safety-related .

systems (e.g., containment spray, essential raw cooling water, auxiliary feedwater) had not been performed during the second inspection period.of the first 10 year surveillance interval.' This condition existed since 1 the end of the second inspection period which occurred on September 15, 1991 and February 21, 1992, for Units 1 and 2, respectively. Failure to perform ASME Code surveillances as required by TS 4.0.5 is identified as a violation (327,.328/92-36-04).

The inspectorc~ also concluded that this event exhibited a lack of ownership with regard to_the ISI pressure testing program. At the end of the inspection period, it was also apparent that previous organizational changes were completed without adequate controls in place ,

lto provide for adequate transition of ISI program responsibilitie Within the areas inspected, one violation was identifie i 6, Evaluation of Licensee Self-Assessment Capability (40500)

During this inspection period, selected reviews were conducted of the licensee's ongoing-self-assessment programs in order to evaluate the -

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effectiveness of these programs. The inspectors specifically focused on several of the licensee's incident investigations during the inspection period.

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' The Inspectors attended a PORC meeting on December 1, 1992, associated with replacement of the 48 volt SSPS power supply, as discussed in paragraph 4.a of this inspection report. The PORC meeting discu: sed the licensee's SSP-7.1 evaluation concerning

, entry into a TS LC0 for maintenance activities. Discussions also included the proposed action plan and work request, alternatives to performing the replacement, and planning and scheduling. The inspectorsobservedthemeetingtobeeffectiveinproperly eva.uating all aspects associateo with the replacement of the 48 volt SSPS power supply, On December 15 and 16, 1992 the' inspectors. attended PORC meetings associated with the Units 1 and 2 transients and associated corrective actions relating to Unit 1 and Unit 2 runbacks during a partial loss of control air event._ Portions of the PORC sessions discussed currant plant stability with regard to the common control air system and possible continued problems on the-nnn safety-related portions of the plant which could ultimately affect-the safety-related systems. Also discussed were compensatory measures put in place to quickly take manual control of the control air system equipment, if further loss of air parameters existed. The inspectors considered that appropriate management review was given-to conclude that the post runback plant conditions were stabl Within the areas inspected, no violations were identifie * Licenseo Event Report Review (92700)-

The inspectors reviewed the LERs listed below to ascertain whether NRC reporting requirements were beingl met and to_ evaluate _ initial adequacy of the corrective actions. The inspector's review also included followup on implementation of corrective actirn and/or review of licensee documentation that all required corrective action (s):were either complete or identified in the licensee's program for tracking of outstanding action (Closed) LER 328/92-09, inadvertent' Containment isolation During Performance of Surveillance Requiremen The inspectors. reviewed the licensee's investigation 'of the CVI, which occurred on July 1,1992, on Unit 2, Train A. The licensee initiated ll-S-92-057 as a result of the-event, The CVI occurred during the performance of SI-82.2, functional Tests for the Radiation Monitoring System, as required by TS. The functional test utilizes a " block switch" (0-HS-90-136A1) to prevent an actual CVI, while allowing testing of-the radiation monitor 2-RM-90-130. The licensee's investigation concluded that an undetermined circuit failure initiated the. event. The ,

11, however, identified two possible:causes of the CVI: (1) the block-switch malfunctioned, and (2) Instrument Maintenance technicians inappropriately placed test leads into the incorrect test point. The

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i- licensee also developed and performed periodic instruction 2-PI-IST-090-

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130.A, VERiflCATION OF' CONTAINMENT PURGE AIR EXHAUST RADIATION MONITOR (TRAIN A) 2-RM-90-130 CVI ACTUATION, Rev. O, to further test the 2-RM-90-130 circuitry for possible causes of the CVI. The test did not identify the cause of the CV The inspectors reviewed the above information, and concluded the .'

licensee's investigation into the inadvertent-CVI to be adequate, although the inspectors noted that no definitive root cause could be-determine Within the areas inspected, no violations were identifie . Action on Previous-Inspection Findings (92701, 92702)

' (0 pen) URI 327, 328/92-31-01, Determination of requirement of TS 4.6.5.1 during performance for "as found" ice condenser status.

p This issue was identified during inspectior activities discussed l in inspection report 327, 328/92-31, The issue involved a question as to whether the licensee was required to follow TS 4.6.5.1 when they were conducting "as'found" testing of.the. ice condenser during an outage period. The inspectors had noted that

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a Safety Evaluation Report for Amendment.No. 131 to the Unit 1 TS-stated that " operability of the ice beds in the ice condenser requires that the ice inventory be distributed evenly throughout-the ice condenser bays in containment...".

On December 1, after the licensee had completed t'h eir review of-the issue of ice condenser as found weights for 'the UIC5: refueling outage, the NRC was-notified that the plant had operated outside *

of the design basis for both operational periods prior to the Cycle 4 and Cycle 5 outages (see paragraph-3.f(l)).

On December 4, 1992 the inspectors met with licensee compliance and engineering personnel and discussed _the technical evaluations -

i that were conducted to resolve the above issue. Two evaluations-

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were discussed. One evaluation addressed past operating .

conditions, i.e. operational periods prior to cycle 4 and cycle 5:

refueling outages. That evaluation resulted in the licensee notifying.the NRC.that they had operated outside the design basis

,t: of the system. Also the evaluation' concluded that a 10 CFR 50.59

! evaluation was not required as the condition clearly represents-anL unreviewed safety question. The= inspectors specifically di'scussed with the licensee why operation outside the design basis for the-ice condenser was considered acceptabl Licensee engineering- personnel stated that their evaluation discussed the containment r

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pressure analysis provided in section 6.2.1 of the FSAR and .the computer programs.used by Westinghouse (LOTIC 1) which determined ice condenser response during design basis accidents. -The

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licensee's evaluation concluded that enough conservatism was l included -in the ice condenser technical specification requirements such that there would be an insignificant effect on the_ analyses and the peak accident pressure would be :less.than the design

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pressure and that there would be no effect on peak temperatur The inspectors also questioned the licensee as to whether the "as found" ice condenser conditions should be determined as stated in TS 4.6.5.1.d and they responded that only the "as left" ice condenser conditions are required to be verified in meeting the requirements of the TS. The inspectors (lid note that the licensee used the "as found" information to perform the technical evaluatio The inspectors then discussed the second evaluation that was done to determine how long Unit I could operate in its current operational cycle. That evaluation concluded that the unit should be able to operate until the end of its current operational cycle (scheduled to end on April 2, 1993). The conclusion was also based, in part, on the containment not exceeding its design pressure of 12 psig if a design basis accident occurred during the remainder of the current operational cycle. The inspectors stated that some of the information presented in the two technical evaluations may not have been reviewed by the NRC staff. They further stated taat until NRC staff review and disposition of this issue is complete, the issue remains unresolve (Closed) URI 327, 328/92-35-02, Review of Licensee Documentation to Assure Compliance with 10 CFR 50, Appendix B, Criterion XVI The subject of the URI regarded whether the licensee was complying with 10 CFR 50, Appendix B, Criterion XVII for records of firewatch rounds which were performed to fulfill TS ACTION statement requirements. The ins)ectors requested specific information in order to verify t1at the licensee was maintaining the appropriate retrievable records information. During this inspection period, the licensee provided the inspectors with documentation which allcwed the inspectors to conclude that proper documentation was being .naintained as retrievable records to satisfy 10 CFR 50, Appendix B, Criterion XVil requirement Within the areas inspected, no violations were identifie . Main Turbine Runback In recent months there have been three independent events that resulted in a main turbine runback. These events were the October 26, 1992, water intrusion into the instrument air system; the December 8, 1992, stuck air relay orifice cleanout plug for the valve controller for 2-FCV-6-106; and the December 15, 1992, faulty sequencer resulting in loss of instrument air pressur Background Level in the #3 heater drain tank is maintained within the proper range by modulating control valves (FCV-6-106A and B) at the discharge of the #3 heater drain pumps. Tank level in excess of

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l ( normal initiates opening of the modulating bypass valves to the l condenser (FCV-6-105A and B).

Indication that the bypass valves to the condenser have left the closed position is provided in the MCR. Additional increase in #3 heater drain tank level, to a point above the range of the bypass valves, annunciates a high level alarm. Low level in the #3 heater drain tank results in a trip of all operating #3 heater drain pump The FCV-6-105 valves require instrument air to open and are normally closed. On a loss of instrument air they will remain in the closed position. The FCV-6-106 valves require instrument air -

to modulate and on a loss of instrument air they will close causing the level in the drain tank to increase. On a failure of instrument air, the domineralizer bypass valves will open and increase the pressure in the condensate system that the drain pumps will have to discharge against. This will also cause the level in the #3 heater drain tank to increas With all drains from the #3 heater drain tanks being bypassed to the condenser the condensate - feedwater system can deliver approximately 85% flow to the steam generators. A load runback to 85% power is initiated when there is indication that the FCV-6-105B valve has left the fully closed positio Auxiliary Control Air System There are two incependent systems located on elevation 734 of the Auxiliary Buildirg. The compressors start on loss of air from the SCSA system at 75.5 psig decreasing. The ACA system is automatically isolated from the SCSA system when the pressure -

falls below 68 psig. Local position lights give indication upon ',

closure of any isolation valv Audible alarms are produced in the MCR for ACA compressor high air temperature, ACA compressor e oil level, high dewpoint of control air, and low control air pressure (68 psig).

Station Control and Service Air System Audible alarms are produced in the MCR for low compressor oil pressure, high oil temperature, and high air pressure for each of the four SCSA compressors. Clcsure of service air isolation valve is also annunciated in the MCR-Flow / Level Control Valves The FCV-6-105A is a 12 inch, fail closed, ball valv The valve is fully open at 15 psi and is fully closed below 9 ps The valve opens af ter the FCV-6-105B valv _ - _ _ - _ _ - _ _ _ _ _ _ _ _ _ _ _ _ - _ - _ _ _ - _ _ _ ___ _ _ _ _ _ _ - _ _ _ - - _ _ - - _ _

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The-FCV-6-105B is a 8 inch, fall closed ball valve. The valve is '

fully open at 9 psi and is- fully closed below-3 psi. The_ valve-i opens before the FCV-6-105A valve and provides the main turbine runback signal from the open limit _ switc The FCV-6-105A and B valves were replaced 'during each units last refueling outage. The original valves were Masoneilan Dresser?

36000 Series Control Ball- 1 Valve with a stellite hardfaced bal The replacement valves were Masonellan Dresser 36002 Series Control Ball 11 Valve with 17-4PH ball with an MN-7 sea October 26, 1992 Main Turbine Runback The October 26, 1992, water intrusion into the control air-' system -

L was described in detail in NRC inspection report 50-327, 328/92--

L 34. In addition to the conclusions reached in the referenced

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l- report, the inspectors evaluated the information available in .the-MCR and locally. There was no air consumption indication-and-there were no direct means to determine how many' air compressorc; were running and if they were fully loaded or half loaded -in the ;

MCR. The precursors of the water intrusion ~ event should have been-available over aLperiod of time.

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December 8, 1992 Main Turbine Runback l On December 8,1992, while performing a #3 heater drain. tank level ,

controller adjustment, the air relay metering orifice cleanout plug whisker for the valve controller 2-LIC-6-106 failed to

, reseat. This failure to reseat caused a partial; loss of-l instrument air to.2-LIC-6-106. This loss of instrument-air caused l= the 2-FCV-6-106' valves to fail closed. The failure of the 2-FCV--

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t 6-106 valves caused the 2-FCV-6-105B to- open and this. valve -

initiated a main turbine runback signal. During the runback recovery the valve 2-FCV_-6-105A-did not ope The licensee unsuccessfully attempted to mechanically assist the valve ope Upon further investigation the licensee found the stainless 1 steel-backing ring for this valve was significantly deflected. T_he -

deflection was completely circumferential and there were. chatter marks on the interior of ring and on the exterior of the_ bal This deflection may have :resulted from the-unsuccessful' mechanical assis December 15, 1992 Main Turbine' Runback-On December 15, 1992, the-licensee received a. service' air isolation annunciator in the MCR. Upon_ investigation the licensee-discovered that all instrument air compressors _ were unloade 'Before the instrument air compressors were successfully loaded, the plant experienced a dual unit main turbine runback.- Upon further investigation the licensee determined that the sequencer selector switch which had been in the number 1 position had failed. The failed _ sequencer selector switch unloaded in l

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28 positions 1 and 4 and loaded in positions 2 and The positions switch aligns the compressors as follows:

Position 1 - Compressor A Lead, Compressor C Lag and Compressors B and D in Standby Position 2 - Compressor B Lead, Compressor D Lag and Corapressors A and C in Standby Position 3 - Compressor C lead, Compressor A Lag and Compressors B and D in Standby Position 4 - Compressor D Lead, Compressor B Lag and Compressors A and C in Standby There had been an outstanding work request on written against position 4. The licensee did not perform any troubleshooting when the work request was issued. Following this event it was discovered that the screws that held the switch backing plate were loose and the 1 and 4 positions had intermittent contac The inspectors reviewed the applicable annunciator response procedures. These included PS-32-104 Train A Aux Control Air Press Low,'ZS-33-4 Service Air Isol Closed, Turbine Run Back B0P, LS-6-lll No 3 Heater Drain Tank Level Abnormal, and ZS-6-105A & B No 3 HTR DR TK Bypass to Cond "C" Open. The procedures provided adequate guidance for responding to the specific alarm condition The inspectors also reviewed A01-10, Loss of Control Air, Section A, loss of Nonessential Air in Modes 1, 2, or 3. This A01 did not address the conditions present during a gradual or partial failure of nonessential air, such as that experienced during the December 15, 1992, event. The procedure did not address the possibility of the generation of a main turbine runback from the movement of the FCV-6-1058 valves. The inspectors concluded that while the supporting procedures were not detailed they provided the minimum guidance to respond to this even Conclusions The first inuication available to the MCR operator that indicated there was a problem in the instrument air system m s an annunciator for the isolation of the Service Air System. With additional MCR indication the operators could have been aware that the compressors were sequencing on and not loading properl The FCV-6-105 valves are of the type that are generally used for laminar flow chemical slurries. The valves are of the floating valve type and are not designed for turbulent system flow. The preliminary review by the manufacturers's representative indicated that the valve internals appeared to have been driven off center by the flow characteristics of the system piping. This corresponds to the failure mechanism experienced in both the

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December 8 and 15 failures. The valves are installed directly adjacent to an elbow and just down stream of a piping branc The licensee and the manufacturer's applications engineers are investigating long term corrective actions which may include pinning or staking the bal The instrument air consumption was not frequently monitored in the plant. The system engineer periodically monitored the flow rates from the dryer effluent. However, this information was not part of routine operator logs and was not monitored by operation The inspectors reviewed available pertinent information, observed the damaged FCV-6-105B valves, walked down the affected portions .

of the instrument air system, discussed the failures with the valve manufacturer, and conducted an independent review of the failure mechanism. The inspectors found no evidence that water or corrosion products had contributed to the FCV-6-105 valve failures. However, the inspectors were unable to determine if the previous water intrusion event generated corrosion products which resulted in erratic operation of the 2-LIC-6-106 controller prior to the Unit 2 runback event of December . Exit Interview The inspection scope and results were summarized on January 6, 1993'with those individuals identified by an asterisk in paragraph I above. The inspectors described the areas inspected and discussed in detail the inspection findings listed below. Proprietary material was not reviewed during the inspection period. Dissenting comments were not received from the license Item Number Description _and Reference VIO 327, 328/92-36-01 Apparent violation of TS 6.8.1 for inadequate and/or failure to follow throttle valve setting procedure URI 327, 328/92-36-02 Determination of root cause of event involving a failure to maintain the Unit 2 refueling water storage tank solution temperature above the minimum Technical Specification value for approximately 24 hour2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months <

VIO 327, 328/92-36-03 Violation of TS 6.8.1 for inadequate and/or failure to follow procedures resulting in lack of configuration control of Unit 2 RWST immersion heaters, and loss of configuration control of the IB EDG Fuel Oil Transfer Pump Switc I,

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VIO 327, 328/92-36-04 Violation'for failure to_ perform-ASME Code surveillances as required -

by TS 4. Strengths and weaknesses summarized in the results paragraph wer discussed in detai Licensee management was informed of the items closed in paragraphs 7 and L 1 List of Acronyms and Initialisms ACA -

-Auxiliary Control Air AFW -

Auxiliary Feedwater Al -

Administrative Instruction ALARA - As low As Reasonable Achievable -

A01 -

Abnormal Operating Instruction ASME -

American Society of Mechanical Engineers ASOS -

Assistant Shift Operations Supervisor AVO -

Assistant Unit Operator CAQR -

Condition Adverse to Quality Report CCP -

Centrifugal Charging Pump CCS -

Component Cooling System CFR -

Code of Federal Regulations DCR -

Control Room CREVS - Control Room Emergency Ventilation System CSHX - Containment Spray Heat Exchanger CVI -

Containment Ventilation Isolation DCN -

Design Change Notice-DRP -

Division of Reactor Projects

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Emergency Diesel _ Generator-EHC -

Electro-hydraulic Control'

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Essential. Raw Cooling Water l ESF -

Engineered Safety Feature FAA -

Federal Aviation Administration

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FME -

Foreign Material Exclusion

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FSAR1-- Final Safety Analysis Report

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Feedwater GPM -

Gallons.per Minute HDT -

Heater Drain' Tank ISI- -

Inservice Inspection KV -

Kilovolt LC0 -

Limiting Condition for Operation LCV -

Level- Control Valve LER -

Licensee Event Report LOCA - Loss of Coolant Accident MCR -

Main Control Room MDAFW - Motor Driven Auxiliary ~ Feedwater MFP -

Main Feed Pump MFW- - Main Feedwater MSIV - Main Steam Isolation Valve

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M&TE - Measurement and Test Equipment'

NOUE -

Notification of Unusual Event NRC -

Nuclear Regulatory Commission NRR -

Nuclear Reactor Regulation ODCM - Offsite Dose Calculation Manual PCR -

Personnel Contamination Report '

PEDS -

Plant Engineering Data System PER- -

Problem Evaluat']n Report PERP -

Plant Evaluation Review Panel PMT -

Post-maintenance Test PORC - Plant Operations Review Committee PRT -

Pressurizer Relief Tank PSID -

Pounds per Square Inch Differential PSIG - Pounds per Square Inch Gauge RCS -

Reactor Coolant System RHR -

Residual Heat Removal RilRHX - Residual Heat Removal Heat Exchanger RPI -

Rod Position Indication RPM -

Revolutions Per Minute RTD -

Resistance Temperature Detector RWP -

Radiation Work Permit SCSA - Station Control and Service Air SFP -

Spent Fuel Pit SG- -

Steam Generator SI -

Surveillance Instruction SIP -

Safety Injection Pump

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S01 -

System Operating Instruction

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SOS -

Shift Operating Supervisor j SR -

Surveillance Requirement SR0 -

Senior Reactor Operator SSP -

-Site Standard Practice i

SSPS - Solid State Protection System TI -

Test Instruction

[ TROI --

Tracking and Reporting of Open Items

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Technical Specifications.

L TVA -

Tennessee Valley Authority i URI -

Unresolved Item-L USAR - Updated Safety' Analysis Report L UICS - Unit 1 Cycle.5 l VCT -

Volume Control- Tank L 'VIO -

Violation WP -

Work Plan WR -

Work Request

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v t e Inspection Report - Sequoyah - 1992036
80 \| 81 \| 82 \| 83 \| 84 \| 85 \| 86 \| 87 \| 88 \| 89 \| 90 \| 91 \| 92 \| 93 \| 94 \| 95 \| 96 \| 97 \| 98 \| 99 00 \| 01 \| 02 \| 03 \| 04 \| 05 \| 06 \| 07 \| 08 \| 09 \| 10 \| 11 \| 12 \| 13 \| 14 \| 15 \| 16 \| 17 \| 18 \| 19 \| 20 \| 21 \| 22 \| 23 \| 24 \|
1992 Quarterly Integrated 1Q (0) 2Q (0) 3Q (0) 4Q (0) Assessments Mid Cycle End of Cycle 25(0) 26(0) 27(0) 33(0) 35(0) 36(0) 37(0) 38(0) Security Operator Exams 302(0) Emergency Planning Other

IR 05000327/1992036

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