IR 05000327/1996014
| ML20133F716 | |
| Person / Time | |
|---|---|
| Site: | Sequoyah  |
| Issue date: | 12/31/1996 |
| From: | NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II) |
| To: | |
| Shared Package | |
| ML20133F709 | List: |
| References | |
| 50-327-96-14, 50-328-96-14, NUDOCS 9701140334 | |
| Download: ML20133F716 (30) | |
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l U.S. NUCLEAR REGULATORY COMISSION
REGION II
Docket Nos: 50-327, 50-328 License Nos: DPR 77, DPR 79 Report No: 50 327/96 14, 50 328/96 14 Licensee: Tennessee Valley Authority (TVA)
l Facility: Sequoyah Nuclear Plant, Units 1 & 2 Location: Sequoyah Access Road Hamilton County, TN 37379 Dates: October 27 through December 7, 1996 !
Inspectors: M. Shannon, Senior Resident Inspector ;
R. Starkey, Resident Inspector l D. Seymour, Resident Inspector i P. Harmon, Reactor Inspector (Sections 02.9, 02.10 and !
04.2) i E. Testa, Reactor Inspector (Sections R1.1, R2, R7 and R8)
Approved by: M. Lesser, Chief Projects Branch 6 Division of Reactor Projects
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Enclosure 9701140334 961231 PDR ADOCK 05000327 O PDR
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EXECUTIVE SUMMARY Sequoyah Nuclear Plant, Units 1 & 2
, NRC Inspection Report 50 327/96 14, 50-328/96 14 i
This integrated inspection included aspects of licensee operations, maintenance, engineering, plant support. and effectiveness of licensee controls in identifying, resolving, and preventing problems. The report covers a six week period of resident inspection. In addition, it includes the results of an announced inspection by a radiological controls inspector.
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Operations e The conduct of operations during ihe ins)ection period was considered to be good. This conclusion was baseci on t1e a)propriate operator responses following two reactor trips, a tur)ine runback, a loss of condenser circulating water incident and an ESF actuation (Sections
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01.1, 02.1. 02.4, 02.5, 02.6 and 02.7).
. e A positive observation was noted for the decision to take the turbine off line to drain the extraction steam line (Section 02.3),
e A negative observation was made when a CCW discharge gate fell and caused the tripping of the three running CCW pumps on Unit 2, which caused the operational loss of the main condenser, which in turn resulted in the lifting of the main steam line PORVs. The installation of the locking bars on the discharge gate would have prevented this event (Section 02.4).
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e A negative observation was made for o)erations failure to adequately control the filling of the feedwater 1 eaters resulting in an ESF AFW actuation (Section 02.7).
e A weakness was identified for the failure of operations to properly
'; monitor and maintain the AFlux recorders and to promptly identify deficiencies with the recorders (Section 02.8).
e A negative observation was made in that some caerators did not understand that the AFlux recorders were not o)solete (Section 02.8).
e A negative observation was made for the failure of an operator to properly "self check" prior to operating a control switch (Section 04.1).
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Maintenance i e The licensee's freeze protection program appeared to be acceptable l (Section M2.3).
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e A positive observation was made for the licensee's decision to schedule a maintenance outage, which included the performance of 36 scheduled
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work activities and six emergent work activities in the 500 kilovolt (kV) switchyard, and to correct potentially defective ASCO solenoid
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valves (Section M2.1 and H2.4).
e A negative observation was made for housekeeping deficiencies in the
main feedwater and main steam piping rooms (Section H2.5).
e A positive observation was identified regarding the overall housekeeping / material condition in the auxiliary and turbine buildings in addition to improvements in the licensee's coatings program (Section
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M2.5).
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e A positive observation was made for the immediate reporting of an improper connection of a multimeter in the solid state protection system
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(SSPS) cabinets (Section M4.1).
- Enaineerina e Recent efforts to improve the operation, maintenance and reliability of secondary plant equi) ment, have not been fully effective. A controller failure led to a tur)ine runback on November 9 (Section 02.5), an
- improperly set controller led to a manual reactor scram on November 16 (Section 02.1), water in extraction lines resulted in a downpower on November 19 (Section 02.4), the 1A MFW pump failed to respond during a downpower of unit 1 (Section M2.2) and the steam dump systems on both
- units continued to experience difficulties (Section E2.3).
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Additionally, improper operation of the feedwater heaters during a filling evolution led to an ESF actuation of Auxiliary Feedwater (Section 02.8). The integrated secondary plant problems are considered to be a weaknes e The licensee *s technical support organization did not perform an adequate evaluation arior to changing the proportional band setting of the heater drain tanc 105 valve controller. This led to weak operational and maintenance instructions for the operation and calibration of the controller, which eventually resulted in a plant l trip (Section 02.1).
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e A positive observation was made for the comprehensive nature of the
- licensee's Vertical Slice Audit of November 20, 1996 (Section E7.1).
e A non cited violation (NCV) was identified for the failure to perform a
. detailed evaluation of a potential problem associated with a Unit 2 l containment purge air valve (Section E8.2).
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Plant Sucoort e The licensee effectively implemented the radwaste shipping program including waste characterization, shipping paper preparation and waste radiological surveys (Section R1.1).
e The licensee met their performance goal of greater than 98 percent operability for liquid and gaseous effluent monitors. Containment upper I and lower post accident monitors for Unit 2 were calibrated by procedure and were operable. One system walkdown and procedure review for a safety assessment in the radwaste operations area was performed and no problems were identified (Section R2).
e Licensee surveys were taken as required and results were selectively spot checked by the inspector and found comparable. Postings were appropriate and labels affixed. Independent smear surveys were counted and found below limits (Section R2.1).
e The 1-icensee was performing detailed and probing self assessments and taking timely and comprehensive corrective actions. Whole body quality assurance tests were reviewed and the results demonstrated acceptable count bias and precision (Section R7).
e The licensee was aggressively sampling and monitoring the primary and secondary water chemistry parameters. Operation of Unit 2 with a small fuel leak that was reinserted into cycle 8 is contrary to the licensee's zero fuel defect policy. Chemistry parameters were maintained at a few percent of TS policy. The Offsite Dose Calculation Manual has been appropriately revised and X/0 values revised to reflect the most recent onsite measured 10 year meteorological data (Section R8).
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Report Details Summary of Plant Status Unit 1 began the inspection period in power operation. On November 15, the unit began a controlled shutdown for a planned 72 hour8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> maintenance outage (Sections M2.1 and H2.4). On November 16, operators had to !
manually trip the unit from approximately 35 percent power due to the i automatic isolation of all three feedwater heater strings (Section 1 02.1). The unit remained in Mode 3 during the subsequent scheduled '
maintenance outage. On November 17, the unit commenced a reactor startu) and entered Mode 2. The unit entered Mode 1 on November 18, when t1e main generator was tied to the grid. On November 19, Unit I was downpowered to 30 percent and the turbine was removed from service in order to drain water condensed in the C 4 heater extraction steam line (Section 02.3). The turbine was synchronized to the grid on November 20. Unit 1 ended the inspection period in power operatio Unit 2 began the inspection period in Mode The unit entered Mode 3 on November 1 and entered Mode 2 on November Mode 1 was entered on November The unit continued power operation until December 6, when a i reactor trip occurred (Section 02.6). The unit remained in Mode 3 through the end of the inspection perio I. Operations 01 Conduct of Operations 01.1 General Comments (71707)
Using Inspection Procedure 71707, the inspectors conducted frequent reviews of ongoing plant operations. The inspectors observed portions of plant shutdowns and plant startups during this inspection perio In addition, an ins)ector was on site observing control room activities
! during the Novem)er 16, shutdown of Unit 1 and observed the manual reactor trip and subsequent recovery actions. In general, the conduct of operations during the inspection period was considered to be good.
Post trip operations activities were considered to be approariate.
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Other events and observations are detailed in the sections Jelow.
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02 Operational Status of Facilities and Equipment 02.1 Unit 1 Manual Reactor Trio Due to Feedwater Heaters Isolation a. Inspection Scope (71707)
The inspector observed a Unit 1 shutdown and was present in the control room at the time of a unit trip. The inspectors reviewed the sequence
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of events annunciator printout and discussed with operations personnel the cause of the feedwater heaters isolation.
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b. GLservations and Findinas On November 16, 1996, operators manually tripped Unit 1 from a> proximately 36 percent power due to the automatic isolation of all t1ree intermediate pressure feedwater heater strings (feedwater heaters 2, 3, and 4 of heater strings A, B, and C). Following the trip, operators stabilized the reactor in Mode Due to reactor coolant system (RCS) temperature falling below 540 degrees F (the minimum observed temperature was 538 F), emergency boration was initiated as required by procedur At the time of the trip, the unit was in a controlled shutdown in preparation for a 72 hour8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> planned maintenance outage. The licensee determined that the cause of the feedwater heater isolation was an incorrect opening setpoint on the No. 3 heater drain tank high level dump valves (105A and B valves) which discharge the contents of the No. 3 heater drain tank directly into the main condense The licensee noted that the controller was routinely adjusted when placing the heater drain pumas in service in order to ensure the "105" valves were fully closed wit 1 the heater drain pumps in operation. The adjustments were made by assistant unit operators (AU0) and/or the maintenance instrument grou) per a plant procedure. However, the procedure did not specify t1e appropriate "as left" setting. During the last adjustment, the controller was apparently adjusted such that the valve would no longer open on increasing heater drain tank level and this subsequently resulted in the high level isolation of the heater strings following removal from service of a heater drain pum The licensee's event review team determined that, in 1993, the controller's gain was changed which changed the controller's proportional band from 100 percent to 50 percent. This made the controller more reactive / sensitive but also reduced the working band of the controller (for example: instead of operating between a band of 1 to 10, the controller was full open at 2.5 and full closed at 7.5).
Additionally, the team noted that when engineering had proposed changing the proportional band, they had not performed an adequate evaluation to determine the overall effect of the change. Therefore, operations and maintenance did not understand the overall effect of the 3roportional band change and eventually adjusted the controller such t1at it locked up and was unable to control heater drain tank leve c. Conclusions The licensee's technical support organization did not perform an adequate evaluation arior to changing the proportional band setting of the heater drain tanc 105 valve controller. This led to weak operational and maintenance instructions for the operation and
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calibration of the controller, which eventually resulted in a plant trip. This is identified as a weaknes !
02.2 Rod Position Indication Out of Steo with Demand Indication
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On November 18, 1996, with Unit 1 in Mode 1 and with the generator not yet tied to the grid, limiting condition for operation (LCO) 3.0.3 and the action statement for LCO 3.1.3.1 were entered as a result of two rod
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position indicators (RPI) for Control Bank D being greater than 12 steps i out from their respective demand position. Previous recent rod deviation problems of this type were documented in Licensee Event Reports (LER) 50-327/95009 and 50 327/96007. LER 50-327/96011 will be written on this most recent occurrence. The previous root causes for the rod deviations stated that the res>onse of the RPI was nonlinear, and the resulting difference between t1e RPI readout and the actual rod position was most pronounced near mid scal In each case, boration was
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initiated to bring the RPI into a range where the effect of the nonlinear RPI response was less pronounced. The inspectors will review'
this issue during closure of the three LERs.
d 02.3 Unit 1 Downoower to Drain Extraction Steam Line
, Inspection Scope (71707)
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During the power increase on Unit 1, engineering raised concerns with possible water accumulation in the turbine extraction lines. On
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November 19 management directed the turbine be taken off line and the extraction line drained. The inspectors observed activities associated with the reduction of power and draining of the extraction line Observations and Findinas
At ap3roximately 55 percent power, operations held a Sensitive Activity crew arief to discuss possible methods for draining the C-4 feedwater i
heater extraction steam line (water had condensed in the line while the turbine was on line with the feedwater heater isolated). Plant
- management and operations were concerned that placing the C4 heater in service with water in the line could cause a water hammer. Several
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possible methods for draining the line were discussed, however, the licensee concluded that none would preclude the possibility of a water
hammer event while the main turbine was in operation. Shortly after the briefing, operations and plant management decided to reduce reactor
- power to 30 percent, remove the main turbine from service, and drain the extraction lin During the draining of the extraction line, the licensee noted that the line had accumulated a significant amount of water and that it was an appropriate decision to reduce power and remove the turbine from service prior to draining the extraction lin
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4 Conclusions The inspectors concluded the licensee's decision to take the turbine off line to drain the extraction steam line reflected the appropriate sensitivity to a potential water hammer event. This is considered a positive observatio .4 Unit 2 Condenser Circulatina Water (CCW) Pumo Trio Inspection ScoDe (71707)
On October 3 during the power increase on Unit 2, the 2A, 28 and 2C CCW pumps tripped, the steam dumps valves closed, and the steam generator atmospheric reliefs opened due to loss of condenser vacuum. The inspector was onsite observing plant startu) activities and reviewed / observed activities associated wit 1 the loss of circulating water even Observations and Findinas On October 3, with a secondary plant startup in progress, all three CCW pumps tripped, causing a loss of main condenser signal, isolation of main steam dumps and subsequent operation of the main steam power operated relief valves. A subsequent investigation by the licensee determined that the CCW pumps tripped when the 2B CCW discharge gate dislodged and fell, isolating condenser outlet flow. The licensee noted that a placard on each breaker for the gate hoists stated, "Bar installed in gate sprockets to prevent drifting closed. Do not ene:91ze unless bar is removed." However, the bar, which would have prevented
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the gate closure and subsequent loss of CCW pumps, was not installe The licensee determined that the locking bars were not installed on 3 out of 4 (28, 1A and 1B) gate sprockets. In addition, the licensee noted that systems operations procedures, general operating instructions, and preventive maintenance )rocedures did not reference the necessity of removing or installing tie bars. Problem Evaluation Report (PER) No. SQ962813PER was written to document and further review this even Conclusions A CCW discharge gate fell and caused the tripping of the three running CCW pumps on Unit 2, which caused the operational loss of the main condenser, which in turn resulted in the lifting of the main steam line PORV Installation of the locking bars on the gate would have prevented this event. This is considered to be a negative observatio ,
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02.5 Unit 2 Runback Insoection Scope (71707)
The inspector reviewed the activities associated with the November 9, 1996, main turbine runbac Observations and Findinas On November 9, 1996, a Unit 2 main turbine runback was initiated due to a low heater drain tank pump flow signal (<5,500 gallons per minute)
with turbine impulse power grater than 85 percent. The plant responded as designed and operators stabilized the plant at 77 percent reactor power. The event recorders indicated that the heater drain tank condenser dump level control valves (LCV) 105A and 105B had opened, causing a decrease in the heater drain tank level, which reduced the heater drain tank pump flow. Initial reports indicated that the controller relay had failed. PER No. SQ962876PER was initiated to document and followup on this deficienc The licensee subsequently determined that debris, from the manufacturing process for the controller internal components, had plugged up the controller, which resulted in the controller forcing the valve to go full open. The controller was replaced and similar controllers were inspecte .6 Unit 2 Automatic Reactor Trio j Inspection Scooe (71707)
The inspectors reviewed the activities associated with the automatic I reactor trip of Unit 2 on December 6,199 ' Observations and Findinas At 12:33 a.m., on December 6, 1996, Unit 2 experienced an automatic reactor trip from 100 percent power. The cause of the tri) was an under voltage condition on the 6.9 kV busses that supply t1e #1 and #3 reactor coolant pumps (RCP). The under voltage condition was caused by the loss of power to the Unit 2, 6.9 kV start bus. All four emergency diesel generators (EDG) started as required and the 2B EDG automatically tied to its shutdown bus as designed. All systems and components operated as expected. RCS temperature dropped to 536 F and emergency ;
boration was initiated as required. The operators appropriately !
stabilized plant conditions in Mode 3 with RCS temperature being ,
maintained at 547 i i
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The licensee determined that the supply breaker to the 6.9 Kv start bus had tripped. The breaker had no visible flags to indicate a cause for trip)ing and did not indicate any ap)arent abnormal conditions. The brea(er was removed and shipped to t1e manufacturer for further evaluation. At the time of the trip, workers were performing maintenance activities in an associated breaker cubicle and discussions indicated that a mechanical interlock in the cubicle could have caused the breaker to trip. When the re) ort ended, the licensee had not yet determined the cause for the breater trip. The breaker was replaced with a refurbished breaker prior to startup of the unit. The licensee was still investigating the cause of the breaker trip at the conclusion of the inspection perio .7 Enaineered Safeauard Features (ESF) Actuation Durina Unit 2 Startuo Inspection Scope (71707)
On December 7, an ESF signal was generated which started the turbine driven auxiliary feedwater pump. The inspector was in the control room observing plant startup activities and observed the ESF actuation and subsequent control room response. The inspector reviewed activities associated with the ESF actuatio Observations and Findinas On December 7, 1996 Unit 2 received an ESF actuation signal which caused the turbine driven auxiliary feedwater pump (TDAFW) to automatically start. At the time of the actuation Unit 2 was in Mode 3 and preparations were underway for Mode 2 entr Prior to the actuation, both motor driven auxiliary feedwater pumps were in service and the TDAFW was in standb Both of the MFPs had been
" reset" but were not in service. Assistant unit operators were filling feedwater heaters from the condensate system. However, only one hotwell Jump was in operation due to the remaining two hotwell pumps not having aeen returned to service following restoration of the start bus (Section 02.6) following the Unit 2 trip on December During the evolution of filling the feedwater heaters, the operators diverted too much flow in filling the feedwater heaters, which caused condensate pressure to decrease. This reduced the supply of condensate to the MFP seal injection pumps, which caused a low seal injection water pressure signal to the MFPs, which in turn initiated a trip signal. The tripping of both MFPs initiated an AFW automatic start signal. The licensee initiated a four hour notification to the NRC for the ESF actuatio ._ . .. -.
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, Conclusions The inspectors concluded that operations failed to adequately control the filling of the feedwater heaters either by starting a second hotwell pump to ensure adequate condensate pressure, or by more carefully l controlling the rate at which the heaters were filled. This is considered a negative observatio .8 Control Room AFlux Recorders Insoection Scooe (71707)
During routine observations and observations during plant shutdown and startup activities, the inspectors noted problems with the AFlux recorders on both units. (There are four AFlux recorders, which record the reactor core upper and lower AFlux as monitored by nuclear instruments 41, 42, 43 and 44.) Observations and Findinas Following the Unit 2 turbine runback on November 9 the inspector reviewed the AFlux recorders for reactor core response during the runback. The ins)ector noted that one recorder was not recording / moving due to its paper aeing misaligned. In addition, during the review of the runback response, the inspector noted that one recorder was reading ;
low and had not responded as expected during the transient. A work l request for the improperly respor, ding recorder had not been writte The control room operator was notified and a work request was initiate During the Unit 1 shutdown on November 16 the ins >ectors noted a l malfunctioning channel on a AFlux recorder (straig1t-lining during the I power reduction) and that another AFlux recorder was out of aape Subsequently, a licensee Quality Assurance inspector noted t1e problems and notified the control room operators. A work request was written on the malfunctioning recorder, and the paper was replace On a subsequent inspection, the inspector noted that another AFlux recorder was out of pa)er, and an additional recorder appeared to have a malfunctioning pen. W1en the inspector notified the operators, the operators indicated that the recorders "were obsolete, were scheduled for removal, and were no longer required." This information was later re)eated to the inspector by another control room operator during a su) sequent control room tou .
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The inspector noted a design change request (DCR) sticker on each AFlux recorder and followed up on the deficiency to verify whether the recorders were abandoned in place and/or due for removal. The review of the DCR and discussions with engineering noted that the recorders were
"not obsolete" and should be maintained to provide a permanent record of AFlux. In addition, the inspector noted that the recorders were scheduled for replacement with a new mode Conclusions The failure of operations to properly monitor and maintain the AFlux recorders and to promptly identify deficiencies with the recorders, is considered to be a weaknes The failure of some operators to understand that the AFlux recorders were not obsolete, is considered to be a negative observatio .9 System Status Inspection Scoce (71707)
The inspector reviewed control room logs, tagout records, and temporary modification records. Control room personnel were interviewed to determine the accuracy of the system and equipment status trackin Observations and Findinos The inspector did not identify deficiencies or errors in the licensee's status tracking during the inspection period. Control room personnel were adeouately informed and aware of the status of the plant equipmen All LC0 entries were accurate and curren The inspector noted that 0)erations does not track or classify components or systems whic1 are conditionally operable. This could lead to inadvertent entry into LCOs if the condition supporting o>erability is removed or compromised. The licensee responded, during tie exit, to the observation by indicating that tracking conditionally operable equipment has been a burden in the past. The licensee currently classifies such equi) ment accordingly in the work request process (4E)
and assigns it a hig1 priorit .10 Rod Control System Insoection Scoce The inspector reviewed the Unit I control room logs and interviewed the licensed operators concerning the status of the Unit 1 Rod Control Syste ._
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) Observations and Findinas The inspector noted that the Unit 1 control rods had been at the OUT WITHDRAWAL LIMIT since Monday, 2 December. There is no direct requirement to adjust boron concentration in the RCS to keep the rods off the out limit and the licensee indicated that this condition was acceptable. Unrelated to this, the licensee had recently been trending spurious rod control spiking which has caused incremental rod movemen A control card was replaced and appears to have solved the proble Operator Knowledge and Performance 04.1 Inadvertent Operation of 1A A Residual Heat Removal (RHR) Pumo On November 27, 1996, with Unit 1 in Mode 1 at 100 percent power. an l
. operator inadvertently started the 1A A RHR aump while attempting to i initiate an RCS dilution. The RCS dilutionhoration hand switch is l located a3 proximately six inches from the IA A RHR start /stop handswitc1. The operator had notified the Unit Supervisor of his l intention to dilute the RCS, but operated the RHR start switch by l mistake. The operator immediately recognized his error and stopped the RHR pump. The IA A RHR pump was subsequently run to verify operability and was inspected locally. No pump abnormalities were identified. PER No. SQ963052PER was initiated to document the event. The inspectors I concluded that the inadvertent starting of the 1A A RHR pump was caused by operator failure to properly "self check" prior to operating equipment. This was considered to be a negative observatio .2 Review of Reliability Study Inspection Scope (71707)
During the week of December 2 to December 6, the inspector reviewed the identified root causes and the corrective actions associated with the licensee's self evaluation titled "Sequoyah Nuclear Plant Reliability Study" dated March 5, 199 Observations and Findinas Finding #1 of the study concluded that knowledge levels of operators, maintenance technicians, and other plant staff had contributed'to less
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than adequate plant reliability. The corrective actions included re-emphasizing accountability for each of the supervisory and management personnel. Additional on the spot supervision and witnessing of !
training routines was initiated. The corrective actions stipulated l goals for reducing errors attributed to inadequate training or skill 1
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levels. The expected reduction is scheduled to be assessed at the end '
- of the first quarter of 199 c. Conclusions
! The licensee was not able to provide data on the current rate of error reduction due to limitations in data sorting. These limitations make
- current status and trending very difficult. The inspector was not able
- to determine whether the corrective actions already applied would result in the desired improvements in this area by the target date.
i 08 Miscellaneous Operations Issues 08.1 (Closed) LER 50-327/95008 Reactor Trip Occurred as a Result of Lo Lo
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Steam Generator Level Caused by Personnel Error. This event was discussed in Inspection Report (IR) 50-327,328/95 15 and resulted in 1 Violation 50 327, 328/95 15 01. The violation was closed in IR 50 327, 328/96 04. No new issues were revealed by the LE II. Maintenance M1 Conduct of Maintenance M1.1 General Comments (62703)
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a. Insoection Scope (61726 & 62707)
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The inspectors observed and/or reviewed all or portions of the following work activities and/or surveillances:
e 2-SI SXP-003-201A Motor Driven Auxiliary Feedwater Pump 2A A Performance Test e 0 PI 0PS 000 00 Freeze Protection, Revision 7
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e WO 9504109 Provide Clearance Between 2 FCV 062-0035 and
. Crane Wall e 1 SI-0PS 082-00 Electrical Power System Diesel Generator 1B-B
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11 Conclusions
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The inspectors noted that the work activities and the performance of
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f M2 Maintenance and Material Condition of Facilities and Equipment M2.1 Results of Unit 1 ASCO Solenoid Valve Inspection Insoection Scoce (62707)
The inspectors reviewed the activities associated with the ASCO solenoid replacements in Unit Observations and Findinas IR 50 327, 328/96 13 discussed the failure of a Unit 2 ASCO solenoid valve on an RCP seal leakoff isolation valve. The licensee identified that the valve had failed due to temperature age hardening of its Buna-N rubber o ring seals. Due to the identification of this problem on Unit 2. the licensee decided to enter a planned maintenance outage on Unit 1 to inspect ASCO solenoid valves. During the subsequent Unit 1 planned maintenance outage on November 15 17, 1996, the licensee inspected a total of 38 ASCO solenoid valves. Of that total of 38 valves, 28 were replaced because they contained the incorrect seals, nine were inspected and determined not to contain Buna N rubber seals, and 1 was deferred due to the valve being adjacent to a high radiation are As a followup to the previous RCP #1 seal leakoff isolation valve failure on Unit 2, discussions with the licensee indicated that the only seal leakoff isolation valve ASCO solenoid to have Buna N material was the valve that failed on October 1 Conclusions The licensee's initiative to shutdown Unit 1 to correct potentially i defective ASCO solenoids valves was considered to be a positive observatio ,
H2.2 Failure of Main Feedwater (MFP) Pumo 1A to Respond Durina Unit Shutdown Inspection Scope (62707)
The inspectors observed and reviewed activities associated with the 1A MFP control problems noted during the Unit 1 downpower on November 1 ,O
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12 Observations and Findinas On November 15, during the Unit 1 power reduction, the 1A MFP did not respond in automatic or in manual. After a couple of hours of troubleshooting activities, the operators took manual control of the governor valve positioner at the local HFP control panel and manually decreased the MFP turbine speed. The licensee initiated a Level B PER, PER No. SQ962923PER, to document the event. When the report period ended, the licensee had not yet completed the root cause and corrective action pla In June and July 1996, the 1A MFP also experienced control problem Those problems were documented in IR 50 327, 328/96 08. At that time, the 1A MFP was drifting and the controls were adjusted to stop the driftin It was not clear whether the previous adjustments were related to the present lockup conditio Conclusions The continuing 1A MFP control problems was considered to be a negative observatio M2.3 Cold Weather Preparations Insoection Scope (71714)
The purpose of this inspection was to determine whether the licensee has effectively implemented a program to protect safety-related systems against extreme cold weathe Observations and Findinos The inspectors reviewed 0 PI-0PS-000-006.0, Freeze Protectio Revision 7. This procedure was performed in its entirety during the week of October 1. Appendices E through H of the procedure were performed weekly starting November 1, and are scheduled to be performed through March 31. Two additional procedures were also used. The first, Modifications and Additions Instruction (H&AI) 27, Freeze Protection, Revision 2, described the activities required for installing and removing freeze protection to protect main steam pressure transmitters and other instruments in the east and west main steam valve vaults and the moisture separator reheater dog houses from freezing. This instruction may also be used for temporary installation of freeze protection in other areas of the plant when normal freeze protection fails. The second additional procedure, 1 PI EFT 234 706.0, Freeze Protection Heat Trace Functional Test, Revision 7, functionally tested
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heat trace and cabinet heaters associated with feedwater flow transmitters, refueling water storage tank level transmitters, condensate storage tank level transmitters, high pressure fire protection (HPFP) discharge pressure switches, and HPFP pressure control valve sense line The inspectors reviewed the most recently completed of each of the above three procedures, and each week reviewed the weekly performance of PI 006. Special attention was paid to identified deficiencies and how the licensee was addressing the deficiencies. The inspectors also attended several of the licensee's weekly freeze protection meetings where outstanding freeze protection issues were discusse The inspectors walked down several areas of the plant, including the essential raw cooling water pum)ing station, refueling water storage tank and condensate storage tan (s, and feedwater flow transmitter areas, to verify that the licensee had taken action to ensure operable heat tracing or to provide compensatory freeze protection measure The inspectors had classified the freeze protection program, as it existed during the winter of 1995/1996, as weak and an inspector followup item (IFI), IFI 50 327, 328/96-04-13, was written. That IFI will remain open until the inspectors have more opportunities to observe the effectiveness of the freeze protection program during the coming winter months of 1996/199 c. Conclusions l
The inspectors concluded that the licensee has a program, including procedures, in place to protect safety related systems against extreme cold weather. The freeze protection program appeared to be acceptabl M2.4 Switchyard Activities Insoection Scope (61726 & 62707)
On November 15. Unit 1 began a controlled shutdown for a scheduled 72-hour maintenance outage. The inspectors reviewed the documented maintenance activities completed in the 500 kv switchyard during this outag .
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b. Observations and Findinas
, The licensee provided the following listing of the activities completed
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during the outage in the 500 kV switchyard outage:
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e Work on the main transformer bank, including: inspection and repair of bushing hot spots: disassembly, cleaning and retinning
, of all shunt conductors: retorquing all high and low side transformer bushing connections: replacement of two fan motors:
and installation of a design change notice to delete the trip function on the Bucholtz relays, e Performance of routine and special tests on 3 Bus 2 Section 1 potential transformer e Replacement of the A phase potential transforme e Adjustment, lubrication, inspection and repair of 15 motor '
operated disconnects (MOD) and 3 ground switche e Replacement of nine chipped insulators on M00s 5065 and 5075 i
e Resetting of the phase discordance timer setpoints on power circuit breakers (PCB) 5028 and 503 !
e Performance of minor mechanical inspections on PCBs 5028, 5034, 5038, 5058 and 507 e Inspection of all overhead ground wire attachments to the tops of tower e Replacement of Bus 2 potential fuses, c. Conclusions The' inspectors concluded the licensee *s decision to schedule a
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maintenance outage, which included the performance of 36 scheduled work activities and six emergent work activities in the 500 kV switchyard, to be a positive observatio M2.5 Plant Material Conditions a. Inspection Scope (62707)
The inspectors noted the plant material condition during tours of the facilit . .- -- --. - . .
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! b. Observations and Findinas During routine tours of the main feedwater and main steam pipe rooms,
- the ins)ectors noted various plant material /housekeeaing deficiencies.
- In the Jnit 2 west main steam piping room the steam alowdown system telltale drains were draining steam and water on the floor of the room.
i There were 480 V AC electrical cables in the vicinity of the drainage.
. In addition, there was an uncontrolled fire extinguisher 31 aced on the room floor. In a Unit 1 feedwater and main steam room, t1e inspectors noted that temporary lighting cables were draped over high temperature steam and feedwater lines and that the general area lighting was poor due to the number of burned out lights. In general, the cleanliness of the rooms was considered to be poo In addition, the ins)ector noted the material condition of the Auxiliary Building and the Turaine Building during plant tours. Pump rooms, walkways and basement areas were examined for general housekeeping and cleanliness. The plant was clean and uncluttered and extensive painting and general material improvement was noted. The inspector noted two instances of improperly secured maintenance ladders which were promptly corrected by the persons responsible for the space. The inspector evaluated the coatings program at Sequoyah and noted that the program was well advanced and was credited with improving both contaminated space cleanup and ALARA at the statio c. Conclusions The housekeeping deficiencies noted in the main feedwater and main steam l piping rooms were considered to be a negative observatio !
The overall general housekeeping / material condition in the auxiliary and turbine buildings in addition to improvements in the coatings program were considered to be a positive observatio M4 Maintenance Staff Knowledge and Performance M4.1 Personnel Error Initiates Main Control Room (MCR) Annunciators l a. Inspection Scooe (62707)
The inspectors reviewed the licensee activities associated with a personnel error in the Solid State Protection System (SSPS) cabinet b. Observations and Findinas On November 27, 1996, an instrumentation technician inadvertently shorted two leads at a digital multimeter which he was using to test the i power supply to a SSPS demultiplexer. The shorted multimeter caused the -
15 volt direct current power supply to trip and resulted in several MCR
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annunciators and bistable lights illuminating. The tripped power supply I affected only annunciators and related bistables and did not affected ;
the actual functioning or operability of the SSPS system. The
technician immediately notified the Unit Supervisor of his error and subsequently the multimeter was removed and the tripped breaker was reclosed. PER No. S0963055PER was initiated to document the even c Conclusions
The immediate reporting of the error was considered to be a positive l observation. However, the im) roper connection of the multimeter was !
considered to be a negative caservatio MB Miscellaneous Maintenance Issues (92902)
, M8.1 (Closed) LER 50 327/95010. Revision 1, Turbine and Reactor Trips l Resulting From a Failure of the "A" Phase Main Transformer Sudden
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Pressure Relay. This issue was discussed in irs 50 327, 328/95-16 and 50 327, 328/96 02. Revision 0 of this LER was closed in IR 328, 328/96-02. Revision 1 of this LER was issued to provide root cause failure
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analysis information. The licensee determined that the relay non- !
orificed control bellows was being deformed when the sudden pressure I relay was isolated and heated. The heat source could be sola '
transformer operation, or the oil purification process. Lessons learned were provided to the appropriate personnel. New Qualitrol relays were being installed and placed in servic i III. Enaineerina !
E2 Engineering Support of Facilities and Equipment
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E2.1 Installation of Manual Vent on Unit 1 RHR System i
. On November 11, 1996, during the Unit 1 scheduled maintenance outag the licensee installed a manual vent in the A Train RHR system in a 160 ;
foot section of piaing, which 3reviously was not ventable. The licensee
will evaluate the 3enefit of t1is vent during subsequent RHR ventings which are presently conducted every other week. As discussed in IR 50-327, 328/96 08, the licensee plans to install a continuous venting modification during the next two refueling outage a i
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E2.2 Over Pressure Condition On the Safety In.iection System Inspection Scope (37551)
The inspectors reviewed the activities associated with the observed over pressure condition of the safety injection syste Observations and Findinas On November 2, 1996, Unit 2 operators noted that the safety injection system pressure was indicating 1850 psig. The design 3ressure for the system is 1750 psig. The over pressure condition was wing caused by minor backleakage through RCS isolation check vahes. The o wrators took actions and successfully stopped any additional backlea(age and reduced the safety injection system pressure to its normal standby pressure. However, the operators had concerns over the operation of the three safety injection system relief valves and questioned why the relief valves had not limited system pressure below the design pressure of 1750 psig. Work requests and a PER'were generated to address this conditio Further review by the licensee indicated that the relief valves were functioning within an acceptable range as documented in the licensee's relief valve program. However, the inspector noted that the relief valve design requirements listed in American National Standards Institute (ANSI) B31.7, Section 1 702.2.4 requires that the first system relief valve shall be set to begin relieving at no higher than the design pressure. The reasons for the differences in the licensee's relief valve program and the ANSI requirements were not a Further review will be necessary to resolve this concern.pparen The safety injection relief valve setpoint issue is being identified as IFI 328/96-14 0 E2.3 Desian Problems with the Unit 1 Steam Dumo Syst_em Insoection Scooe (37551)
Following the shutdown of Unit 1, the inspectors walked down the Unit 1 steam dump syste Observations and Findinas The licensee noted that the steam dump system has been a source of recurrent problems since initial plant startup and that a number of modifications over the years have not been fully effective in eliminating the system problems. In addition, Unit 2 experienced a significant water hammer event on October 11, 1996, apparently due to
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water accumulation in the steam dump aischarge lines. Unit 1 also experienced abnormally high rates of water accumulation during the cooldown and startup evolution The inspectors walked down the steam dump system following the unit shutdown. The system was experiencing moderate water hammer conditions l (loud banging with approximately 1 inch of piping movement) on several l of the steam dump lines. In addition, the inspectors noted that the '
steam dump lines did not appear to be draining properly due to the continuous open condition of steam dump valves 50 103, SD 107 and SD-111, which prevented the automatic drain lines to the drain tank from opening as necessar Engineering and maintenance personnel were also involved with monitoring / observing operation of the syste The insaectors notified licensee management of the apparent misoperation of the Jnit 1 steam dump valve drain system. Subsequently, based on the licensee's review, interim actions (procedural manual actions) were developed to ensure the steam dump lines were draine !
l Due to the continuing problems with the steam dump systems on both
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units, the licensee brought in an independent contractor (FPI) to review the design and operation of the steam dump systems. The contractor made several recommendations for improving the operation of the SD system l The followup of the implementation of the licensee's corrective actions for the SD system problems is being identified as IFI 96 14 0 l
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In addition to the Unit 1 steam dump problems, following the Unit 2 trip on December 6, 1996, steam dump valve SD-107 exhibited erratic operation. It was later noted that a stem locking bar hold down bolt (one of two bolts) was broken. The S0107 isolation valve was closed and 50107 will be repaired during the next outag c. Conclusions The continuing problems with the steam dump systems on both units are considered to be a negative observatio E7 Quality Assurance in Engineering Activities E7.1 Review of Vertical Slice Audit a. Scone (40500)
The ins)ectors reviewed the results of the licensee's vertical slice audit w1ich related to the main feedwater, auxiliary feedwater, and portions of the safety injection (accumulators) and attendant electrical power system . _ -. . - - .. . - _ _ .
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19 Observations and Findinas On November 20, 1996, the licensee completed Audit Report SQA9615 -
Sequoyah Nuclear Plant Vertical Slice Inspection Audit. The audit was conducted to evaluate the: 1) adequacy and maintenance of the design and licensing bases; 2) effectiveness of the design change control process; and 3) adequacy of maintenance and operation activities as they related to the main feedwater, auxiliary feedwater, and portions of the safety injection (accumulators) and attendant electrical power system Five audit findings and several less significant implementation I
' weaknesses were identified and resulted in six Level B PERs being :
initiated. The audit stated, and the inspectors concluded, that none of 1 the identified deficiencies adversely affect the function of the systems evaluated during the audit. The inspectors will review the licensee's corrective actions related to the closure of the six Level B PERs initiated as a result of this audit. This item is identified as IFI 50-
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327, 328/96 14 03, Review Corrective Actions Related to the Six Level B PERs Initiated by Vertical Slice Audit SOA9615 Dated November 20, 1996.
. Conclusions
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The licensee's Vertical Slice Audit of November 20, 1996, was comprehensive and resulted in the identification of five audit finding ;
This is considered a positive observatio i E8 Miscellaneous Engineering Issues (92903)
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E (Closed) Unresolved Item 50 327. 328/96 09 05. Determine Whether the Licensee's Method of Determinina the Maximum Permissible RHR Gas Void i Size is Acceotable. The licensee contracted Westinghouse to perform an
) analysis of the Unit 1 RHR system piping to determine the forces resulting from system operation with various volumes of gas in the piping system. The analysis. TVA 96175, was completed on October 21,
, 1996. The analysis calculations were performed using seven different gas volumes ranging from 0.3 cubic feet to 50 cubic feet. The analysis concluded that the hydraulic forces built up are higher with increasing volumes of gas but level off when the gas volumes go beyond more than 10 cubic feet. The Westinghouse analysis supported the licensee's evaluation (August 29, 1996) which, based on RHR gas accumulation
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history, had concluded that at least 24 cubic feet of gas had accumulated in the past (prior to regular venting) without causing water
' hammer damage. The inspectors had no further concerns regarding the
! licensee's evaluation or the Westinghouse analysis.
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20 E8.2 LClosed) LER 50 328/95004. A Containment Purae Air Isolation Valve Ma_y Not Have Sufficient Clearance for the Valve to Function Properly Durina a loss of Coolant Acciden In May 1995, walkdowns were performed to support the closure of the Individual Plant Examination for External Events (IPEEE) for the Severe Accident Vulnerabilities Program. During the walkdown the licensee c,bserved that the Unit 2 containment aurge air inboard isolation valve may not have sufficient clearance for t1e actuator to function properly during a loss of coolant accident (the valve is normally closed, but the assumption was made that if an
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accident occurred while the system was operating, the valve may not
- close because of changed clearances from local environmental conditions.
l' This valve is typically opened 2-3 times daily during routine venting of containment). The spring can for the valve actuator touched the bell housing for the B train containment air return fan. The condition was evaluated, and the licensee determined that the valve operability was not assured but that the operability of the fan was not affecte l Omrations subsequently entered the appropriate LCO action statement for tie affected isolation valve until the valve was isolated and power removed from the valv The licensee discovered, during their review for this LER, that in April i
1993, an engineering contractor had identified a potential clearance
- problem associated with the Unit 2 containment purge air valve. In
July August 1993, the licensee performed an initial evaluation of the condition and incorrectly determined that the condition was acceptable based on the fan and valve being supported by the same structur During the fall of 1993, TVA performed a detailed evaluation of the contractor's walkdown observations and findings, but failed to evaluate
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the containment air purge valve condition because the information,
, identified by the contractor concerning that purge valve had been misplaced. It was not until May 1995, during the walkdown for the IPEEE closure, that the licensee determined that an evaluation of the containment air purge valve interference problem had not been performe Following the licensee's evaluation in May 1995, the corrective actions described in the LER were initiated and completed.
I 10 CFR 50, Appendix B, Criterion XVI, Corrective Actions, requires, in part, that measures shall be established to assure that conditions
- adverse to quality, such as deficiencies, are promptly identified and correcte In the fall of 1993, the licensee failed to perform a detailed evaluation of a walkdown which identified a potential problem associated with a Unit 2 containment purge air valve. This licensee-
identified and corrected violation is being treated as an Non Cited Violation, consistent with Section VII.B.1 of the NRC Enforcement Policy (NCV 50-328/96-14 04).
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IV. Plant Support F8 Miscellaneous Fire Protection Issues F8.1 Fire Protection Enforcement Conference i
, An October 24, 1996, predecisional enforcement conference in Region II !
discussed the results of an NRC inspection conducted July 8 through d
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August 22, 1996 that was documented by NRC Inspection Report 50 327,
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328/96 10. This report was sent to the licensee in a letter, dated September 27, 1996, and identified the following four apparent violations that were being considered for escalated enforcement:
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EEI 50 327, 328/96-10 01, Inadequate Identification and Resolution
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of Fire Protection Deficiencies EEI 50 327, 328/96-10 02, Inoperable CO2 System i EEI 50 327, 328/96 10 03, Inadequate Surveillance Procedures for
- Fire Hose Stations Inside Reactor Buildings I
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EEI 50 327, 328/96-10-04, Failure to Perform Surveillance j Inspections of Fire Barrier Penetration Seals Based on information developed during the ins)ection and information
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provided during the enforcement conference, t1e NRC determined that violations of NRC requirements had occurred. These violations were i
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classified as a Severity Level III aroblem. The licensee was advised of this decision by letter dated Novem)er 19, 1996, which also enclosed a
- Notice of Violation and Proposed Imposition of Civil Penalty in the amount of $50,000.
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The four escalated enforcement items previously identified as apparent violations are closed and reissued as escalated enforcement violations.
. These violations are identified as follows:
VIO 50 327, 328/EA 96 269 01013, Inadequate Identification and Resolution of Fire Protection Deficiencies
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VIO 50 327, 328/EA 96 269 01023, Inoperable C02 System VIO 50 327, 328/EA 96 269 01043 Inadecuate Surveillance
- Procedures for Fire Hose Stations Insice Reactor Buildings i
VIO 50 327, 328/EA 96 269 01033, Failure to Perform Surveillance Inspections of Fire Barrier Penetration Seals
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R1 Radiological Protection and Chemistry (RP&C) Controls R1.1 Transportation of Radioactive Material a. Inspection Scope (86750. TI 2515/133)
The inspectors evaluated the licensee's transportation and radioactive materials programs. Implementation of revised Department of Transportation (DOT) and NRC trans)ortation regulations for shipment of radioactive materials as required )y Title 10 Code of Federal Regulations (CFR) Part 71.5 and 49 CFR Parts 170 through 189 were also inspecte b. Observations and Findinas The inspectors reviewed shipping papers for five recent radwaste shipments (SNP 96-1128. SNP 96 1129, SNP 96 1130, SNP 96 1201, SNP 96 1202) and found them complete and accurate. The inspector witnessed the packaging, survey and preparation of the shipping papers for shipment SNP 96 1211 and found all activities performed as required by the licensee's procedures and Federal Regulation The inspectors reviewed the scaling factors used in the shipping papers to characterize waste and the Certificate of Compliance 6568 Revision 9 Docket 71-6568 for the licensee's resin shipping cask "TVA 83" and found no discrepancie The inspectors reviewed the procedural compliance for selected sections of Technical Instruction TI 61 Waste Classification. Scalina Factor and Quantity Determination , Revision 25 effective July 23, 1996 and found the resin 10 CFR 61 Analysis Report for SNP 96 1114 Chemical Volume Control System (CVCS) Resin reported on December 4, 1996 to have been performed as required by procedure and Federal Regulation c. Conclusions The licensee effectively implemented the radwaste shipping program including waste characterization, shipping paper preparation and waste radiological survey R2 Status of Radiation Protection Facilities and Equipment a. Inspection Scoce (84750. 86750)
The inspectors reviewed selected effluent radiation monitors for calibration and alarm set points. A 10 CFR 50.59 safety assessment for procedure changes for resin sluicing operations was reviewe ,
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b. Observations and Findinas i The inspectors reviewed selected effluent set points and calibration data and determined that monitors were within their calibration interval. Alarm set points were correctly set. Radiation monitor operability is tracked with a goal of greater than 98 percent operability. The operability for Fiscal year 1996 was above the 98 percent goal (about 98.2) and thus far in Fiscal year 1997 about 9 percent. Each of the required liquid and gaseous radiation monitors is independently tracked for performanc l The insaectors reviewed the data packages for Unit 2 Channel Calibration of the Jpper Inside Containment Post Accident Hi Range area Monitor 2 R-90 271 and 2 R 90 272 performed May 30, 1996 and May 27, 1996 respectively. The inspectors also reviewed Lower Inside Containment Post Accident Hi Range Area Monitor 2 R-90-273 and 2R-90 274 performed May 21, 1996. The tests were 3erformed using surveillance instruction 2 SI-ICC 90-27(1)(2)(3)(4). T1e monitors were satisfactorily calibrated by procedure and met regulatory requirement The inspectors reviewed the safety assessment (February 16, 1995) for a new procedure for resin sluicing operations 0-S0 77 29. It replaced procedure 501 77.3. The new procedure changed the normal configuration of the valve 0 FCV 77 401 from normally closed to normally open. The inspectors performed a walkdown of the system and found the correct configuration of the 401 valve and the procedures and check list correctly revised to include the evaluated change Conclusions The licensee met their performance goal of greater than 98 percent operability for liquid and gaseous effluent monitors. Containment upper and lower post accident monitors for Unit 2 were calibrated by procedure and were operable. One system walkdown and procedure review for a safety assessment in the radwaste operations area was performed and no problems were identifie R2.1 Tours of Licensee Radiological Control Areas (RCAs)
a. Inspection Scoce (84750. 86750)
During tours of the 'icensee facilities, the inspectors selectively verified that radiological postings and labels were appropriate for the radiological hazar .
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l b. Observations and Findinas The inspectors observed surveys and the control of contaminated and radioactive material and housekeeping within the licensee's auxiliary, ;
truck bay, waste shipping area, radwaste storage warehouse and outside l radwaste storage trailer vans and found the areas ap3ropriately posted i and labeled. Selected independent smears taken in t1e truck bay and l radwaste storage warehouse were counted clea l c. Conclusions Licensee surveys were taken as required and results were selectively l spot checked by the inspector and found comparable. Postings were !
appropriate and labels affixed. Independent smear surveys were counted and found below limit R7 Quality Assurance in RP&C Activities a. Inspection Scone (84750)
The inspectors reviewed the licensee's program for identifying and correcting deficiencies or weaknesses related to the control of radiation or radioactive material. Whole body counting measureme quality assurance was reviewed by the inspector b. Observations and Findinas The inspectors reviewed the Nuclear Assurance and Licensing Audit Report No. SSA9610 Browns Ferry, Sequoyah, and Watts Bar Nuclear Plants Radiological Effluent and Environmental Monitoring /0ffsite Dose Calculation Manual, and Chemistry dated November 1,1996. The audit was performed during the time period August 19 - October 4. 1996. The audit for Sequoyah was detailed, in depth and probing. The followup actions were reviewed with the Manager RadChem. The audit team leader was interviewed and the audit details and followup actions were discusse The audit team cualifications were discussed and the inspector judged their backgrounc and experience was appropriate for this audit. No audit findings were identifie The inspectors reviewed the whole body counting measurement quality assurance performance test results, for the period January through June 1996. The results for the whole body Co 57, Co-60, Cs 137, for the 60 second count time and the 500 second count time for both FastScan #1 and FastScan #2 showed acceptable comparisons between the reported activity and the measured activity. The Eu 152 used for the thyroid checks was also appropriately counted and the FastSc - "I and FastScan #2 results were found acceptable. The preliminary . ,.ts for the July through December 1996 period were reviewed and found acceptabl .
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c. Conclusions The licensee was performing detailed and probing self assessments and taking timely and comprehensive corrective actions. Whole body quality assurance tests were reviewed and the results demonstrated acceptable count bias and precisio R8 Miscellaneous Radiation Protection and Chemistry Issues a. Insoection Scope (86750. TI 2515/133)
The inspectors reviewed and discussed the results of the licensee *s primary and secondary chemistry program. The inspectors also reviewed Revision 39 of The Sequoyah Nuclear Plant Offsite Dose Calculation Manual which will become effective January 17, 199 b. Observations and Findinas The inspectors reviewed the chemistry results for the Technical Saecification (TS) data associated with the Primary and Secondary Water C1emistry parameters for the period from January 1,1996 through December 6, 1996, and determined that all required TS chemistry results were maintained at small percentages of the limit During a discussion of the measured primary chemistry parameters, the inspectors were informed that Unit 2 has a confirmed defect in a single rod of approximately 25,000 MWD /MTU burnup. This was confirmed by iodine spiking following the October 11, 1996 and December 6, 1996 reactor trips. Unit 2 has been placed in Action Level 1 per the Fuel Integrity Assessment Program (SSP 12.55). The Fuel Integrity Assessment Team has been meeting to consider mitigating actions. Review of the Sequoyah Nuclear Plant Fuel Performance Summary Report April and May 1996 dated June 17, 1996, discussed a suspicion that there was a fuel defect. This was confirmed by transient primary water chemistry data from a Unit trip December 21, 1995 and April 20, 1996. An analysis performed by the licensee determined that there was about a 1 in 3 chance of reinserting the defect fuel from the Cycle 7 refueling without performing fuel inspection testing. The licensee chose not to perform any fuel inspection and refueled and aaparently reinserted the rod with the defect. The inspectors reminded t1e licensee that they are committed to a zero fuel defect policy in their source term reduction initiative in their ALARA progra The inspectors also reviewed Revision 39 of The Sequoyah Nuclear Plant Offsite Dose Calculation Manual (0DCM) which will become effective January 17, 1997. The most notable change involved the revised X/0
value which is now 6.94 E 6 s/m . The current value is 5.12 E-6 s/m 3 .
The revised X/Q reflects the onsite measured meteorological data for the 1986 through 1995 time period. The use of the revised X/Q value for dose assessment will increase the resultant calculated dose values. The other changes were judged to be minor word revisions and clarification .
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26 Conclusions The licensee was aggressively sampling and monitoring the primary and l secondary water chemistry parameters. Operation of Unit 2 with a small fuel rod leak that was reinserted into cycle 8 is contrary to the stated zero fuel defect policy. Chemistry parameters were maintained at a few l percent of TS limits. The 00CM has been appropriately revised and X/Q values revised to reflect the most recent onsite measured 10 year
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meteorological data, s
V. Manaaement Meetinas X1 Exit Meeting Sunnary The inspectors ) resented the inspection results to members of licensee management at tie conclusion of the inspection on December 19, 1996.
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The licensee acknowledged the findings presente The inspectors asked the licensee whether any materials would be considered proprietary. No proprietary information was identified, j PARTIAL LIST OF PERSONS CONTACTED
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Licensee
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i * Adney, R., Site Vice President
- Beasley, J., Acting Site Quality Manager
- Bryant, L., Outage Manager
- Burzynski, M., Engineering & Materials Manager !
- Driscoll, D., Training Manager
- Fecht, M., Nuclear Assurance & Licensing Manager Fink F., Business and Work Performance Manager
- Flippo T., Site Support Manager Harrington, W., Acting Maintenance Manager !
- Herron, J., Plant Manager '
- Kent, C., Radcon/ Chemistry Manager i
- Lagergren, B., Operations Manager l
- Rausch, R. Maintenance and Modifications Manager
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Reynolds, J., Operations Superintendent
- Rupert, J., Engineering and Support Services Manager
- Shell, R., Manager of Licensing and Industry Affairs Skarzinski, M., Technical Support Manager j l
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- Smith, J., Licensing Supervisor Summy, J., Assistant Plant Manager Symonds, J. Modifications Manager i
- Attended exit interview INSPECTION PROCEDURES USED IP 37551: Onsite Engineering IP 40500: Effectiveness of Licensee Controls In Identifying, Resolving, & Preventing Problems
, IP 61726: Surveillance Observations IP 62707:
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Maintenance Observations IP 71707: Plant Operations IP 71714: Cold Weather Preparations IP 84750: Radioactive Waste Treatment. And Effluent And Environmental
, Monitoring IP 86750: Solid Radioactive Waste Management And Transportation Of Radioactive Materials IP 92902: Followup - Maintenance IP 92903: Followup Engineering TI 2515/133: Implementation of Revised 49 CFR Parts 100 179 And
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10 CFR Part i ITEMS OPENED. CLOSED. AND DISCUSSED Opened
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Iyge Item Number Status Descriotion and Reference IFI 50 328/96 14 01 Open Safety Injection Relief Valve i
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Setpoint Discrepancies (Section E2.2)
IFI 50-327, 328/96 14-02 Open Review Corrective Actions Related to
! Continuing Steam Dump System Operational Problems (Section E2.3)
IFI 50 327, 328/96 14 03 Open Review Corrective Actions Related to the Six Level B PERs Initiated by Vertical Slice Audit SQA9615 Dated November 20, 1996 (Section E7.1).
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NCV 50-328/96 14 04 Open/ Failure to Perform a Detailed Closed Evaluation of a Potential Problem Associated With a Unit 2 Containment Purge Air Valve (Section E8.2)
VIO 50 327, 328/EA 96 269 Open Inadequate Identification and 01013 Resolution of Fire Protection Deficiencies (Section F8.1)
VIO 50 327, 328/EA 96 269 Open Inoperable CO2 System (Section F8.1)
01023 VIO 50 327, 328/EA 96-269 Open Inadequate Surveillance Procedures 01043 for Fire Hose Stations Inside Reactor Buildings (Section F8.1)
VIO 50-327, 328/EA 96 269 Open Failure to Perform Surveillance 01033 Inspections of Fire Barrier Penetration Seals (Section F8.1)
Closed Tvoe Item Number Status Descriotion and Reference LER 50 327/95008 Closed Reactor Trip Occurred as a Result of Lo-Lo Steam Generator Level Caused by Personnel Error (Section 08.1).
LER 50 327/95010 Closed Turbine and Reactor Trips Resulting Revision 1 From a Failure of the "A" Phase Main Transformer Sudden Pressure Relay (Section M8.1).
URI 50 327, 328/96-09-05 Closed Determine Whether the Licensee's Method of Determining the Maximum Permissible RHR Gas Void Size is Acceptable (Section E8.1).
LER 50-328/95004 Closed A Containment Purge Air Isolation Valve May Not Have Sufficient Clearance for the Valve to Function Properly During a Loss of Coolant Accident (Section E8.2).
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EEI 50 327, 328/96 10-01 Closed Inadequate Identification and Resolution of Fire Protection Deficiencies (Section F8.1)
EEI 50 327,-328/96 10 02 Closed Inoperable CO2 System (Section F8.1)
EEI 50 327, 328/96 10 03 Closed Inadequate Surveillance Procedures i for Fire Hose Stations Inside !
Reactor Buildings (Section F8.1)
EEI 50 327, 328/96 10 04 Closed Failure to Perform Surveillance Inspections of Fire Barrier i Penetrations Seals (Section F8.1) j Discussed IFI 50-327, 328/96 04 13 Open Weak Freeze Protection Program (Section M2.3).
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