|Report date||Site||Event description|
|05000334/LER-2017-003||4 January 2018||Beaver Valley|
On November 7, 2017 at 05:04 EST Beaver Valley Power Station (BVPS) Unit 1 experienced an automatic Reactor Trip from 100 percent power due to an automatic Turbine Trip. The Turbine Trip was initiated by a Main Unit Generator Overcurrent Protection Trip.
The Reactor Trip was without complications. All control rods fully inserted into the core. The Auxiliary Feedwater System automatically actuated as expected and performed as designed. The plant was stabilized in Mode 3 with the normal Main Feedwater System in service and the Auxiliary Feedwater System properly secured.
The Main Unit Generator trip was caused by foreign material in the isophase bus duct. The isophase bus ducts have been properly inspected and cleared of all foreign material.
This event was reported (EN 53056) as an actuation of the Reactor Protection system 10 CFR 50.72(b)(2)(iv)(B) and a Specified System Actuation (Auxiliary Feedwater System) 10 CFR 50.72(b)(3)(iv)(A).
This event is being reported pursuant to 10 CFR 50.73(a)(2)(iv)(A) as a condition that resulted in the automatic actuation of the Reactor Protection System (RPS) and the expected automatic actuation of the Auxiliary Feedwater System.
|05000334/LER-2017-002||13 September 2017||Beaver Valley|
In order to address the concerns outlined in NRC Regulatory Issue Summary (RIS) 2015-06 "TORNADO MISSILE PROTECTION", evaluations of tornado missile vulnerabilities and their potential impact on Technical Specification (TS) plant equipment were conducted. This particular evaluation concluded that the following Structures, Systems, and Components (SSCs) are potentially vulnerable to tornado generated missiles:
The Beaver Valley Power Station Unit 1 (BV-1) Emergency Diesel Generators (EDGs) engine exhaust piping is potentially vulnerable as a result of tornado generated missiles striking and subsequently crimping or crushing this piping rendering the EDGs inoperable.
On July 19, 2017, both of the BV-1 TS required EDGs were declared inoperable and Enforcement Guidance Memorandum (EGM) 15-002 Rev 1 "Enforcement Discretion for Tornado-Generated Missile Protection Noncompliance," was applied. Compensatory measures were implemented within the time allowed by the applicable Limiting Condition(s) for Operation and both EDGs were then declared operable but nonconforming.
The apparent cause of this issue was a lack of clarity during the original design and licensing of the plant that led to inadequate understanding of the tornado missile protection regulatory requirements.
Actions will be taken to establish compliance for BV-1 EDGs either by a plant modification or employing a methodology for addressing tornado missile non- conformances for the EDG exhaust piping.
This issue is reportable under 10 CFR 50.72 for a loss of safety function. However, enforcement discretion is being applied. As stated in EGM 15-002, Rev. 1, the NRC will exercise enforcement discretion for subsequent tornado missile 10 CFR 50.72 notifications. On February 23, 2017, FENOC provided the NRC the initial 10 CFR 50.72 notification in Event Notification (EN) number 52571 concerning tornado missile protection issues known at that time.
|05000412/LER-2017-001||2 May 2017||Beaver Valley|
A review of the current licensing basis revealed that intentionally coupling the Seismic Category I Service Water System 'SWS) with the not Seismic CAT I Standby Service Water System (SWE)(KG) is a non-conformance with the current icensing basis, and renders the SWS inoperable. As a result, a review of the SWS Design Basis Accident (DBA) full flow surveillance test revealed that during the past three years performance, there were two trains of SWS concurrently inoperable for a time period, as logged, greater than the seven hour shutdown completion time required by Technical Specification 3.0.3.
This condition is reportable as an operation or condition which was prohibited by the plant's Technical Specifications under 10 CFR 50.73 (a)(2)(i)(B), and could have prevented the fulfillment of a safety function under 10 CFR 50.73(a)(2) (v)(B) for the SWS along with the systems that it supports of Emergency Core Cooling (ECCS), Primary Component Cooling Water System (CCP), and the Recirculation Spray System (RSS) .
The plant was not aligned to this configuration at the time of discovery, and all procedures have been revised to eliminate this condition.
|05000334/LER-2017-001||18 April 2017||Beaver Valley|
In order to address the concerns outlined in NRC Regulatory Issue Summary (RIS) 2015-06 "TORNADO MISSILE PROTECTION", an evaluation of tornado missile vulnerabilities and their potential impact on Technical Specification (TS) plant equipment was conducted. This evaluation concluded that the following Structures, Systems, and Components (SSCs) are potentially vulnerable to tornado generated missiles:
The steam discharge flow paths to atmosphere of the Beaver Valley Power Station Unit 1 (BV-1) and Unit 2 (BV-2) Main Steam Safety Valves (MSSVs) (reference TS 3.7.1) are potentially vulnerable to tornado generated missiles.
The steam discharge flow paths to atmosphere of the BV-1 and BV-2 Atmospheric Dump Valves (ADVs) (reference TS 3.7.4) are potentially vulnerable to tornado generated missiles.
On February 23, 2017, the BV-1 and BV-2 TS required MSSVs and ADVs were declared inoperable and Enforcement Guidance Memorandum (EGM) 15-002 Rev 1 "Enforcement Discretion for Tornado-Generated Missile Protection Noncompliance," was applied. Compensatory measures were implemented within the time allowed by the applicable Limiting Condition(s) for Operation and the associated systems were then declared Operable but nonconforming.
The apparent cause of this issue was a lack of clarity during the original design and licensing of the plants that led to inadequate understanding of the tornado missile protection regulatory requirements.
In addition, as part of the evaluation of tornado missile vulnerabilities, two BV-2 tornado missile barrier doors were found to be open. Specifically, Auxiliary Building door (A-35-5A) was found open and Fuel Building door (F-66-3), was found to be partially open. These doors were then closed and latched.
Actions will be taken to establish compliance for the MSSVs and ADVs either by plant modification or by employing a methodology for addressing tornado missile noncompliance for the MSSVs and the ADVs.
These conditions (as applicable) were reported to the NRC on February 23, 2017 in Event Notification (EN) number 52571 under 10 CFR 50.72(b)(3)(ii)(B) and 10 CFR 50.72(b)(3)(v)(A).
|05000334/LER-2015-001||11 June 2015||Beaver Valley|
At 0411 EDT on April 15, 2015 the Beaver Valley Power Station (BVPS) Unit 1 reactor was manually tripped from approximately 85 percent power following a condensate pump trip. Prior to the manual reactor trip the unit was performing an emergent power reduction after the identification of a degrading condition on the "A" condensate pump motor. All control rods fully inserted into the core. The auxiliary feedwater system actuated as designed.
The unit was stabilized in Mode 3 with the normal main feedwater system in service and the auxiliary feedwater system properly secured.
The "A" condensate pump trip was caused by the failure of the inboard motor bearing due to lack of oil lubrication.
The root cause evaluation determined that responses to technical questions were provided without the appropriate technical rigor or validation of assumptions regarding acceptable oil level for the pump motor.
This event was reported (EN 50985) as an event or condition that results in the actuation of the reactor protection system when the reactor is critical, 10 CFR 50.72(b)(2)(iv)(B) and specified system actuation, 10 CFR 50.72(b)(2)(iv)(A). This event is reportable pursuant to 10 CFR 50.73(a)(2)(iv)(A) as a condition that resulted in the manual actuation of the Reactor Protection System, 10 CFR 50.73(a)(2)(iv)(B)(1), and the automatic actuation of the Auxiliary Feedwater System 10 CFR 50.73(a)(2)(iv)(B)(6).
|05000412/LER-2014-002||21 July 2014||Beaver Valley|
On May 20, 2014, at 0835 hours during a plant startup following the seventeenth refueling outage, Beaver Valley Power Station (BVPS) Unit 2 operations personnel manually tripped the reactor when it was recognized that the pre-determined trip criteria of 85 percent narrow range water level in the 'A' Steam Generator would be met. This manual trip criterion was reached after the steam generator water level began to oscillate following the start of the second condensate pump. Due to low decay heat input the main steam line isolation valves were shut in order to limit reactor coolant system cool down. Plant trip response was as expected without complications, and all control rods fully inserted in the core.
This event is being reported pursuant to 10 CFR 50.73(a)(2)(iv)(A) as a condition that resulted in the valid manual or automatic actuation of any of the systems listed in (a)(2)(iv)(B) - (1) Reactor Protection System (RPS) and (2) Multiple Main Steam Isolation Valves (MSIVs). A 10 CFR 50.72 notification was made at 1052 hours on May 20, 2014, to report the manual reactor trip and main steam line isolation (EN# 50124).
The cause of this event has been determined to be the lack of an integrated secondary startup procedure.
Station operating procedures will be revised to prevent recurrence.
|05000334/LER-2014-002||7 March 2014||Beaver Valley|
On January 6, 2014, the Beaver Valley Power Station (BVPS) Unit 1 tripped from full power due to a main transformer differential protection main unit generator trip as a result of a main unit transformer failure. All three Auxiliary Feedwater (AFW) pumps automatically started, as expected, due to lowering steam generator levels. The Turbine Driven Auxiliary Feedwater (TDAFW) pump ran for 1 hour and 49 minutes at which time the pump tripped due to governor oscillations. The TDAFW pump was declared inoperable. Subsequent investigation determined that the governor oscillations were due to a misadjusted governor needle valve that was last set during refueling outage 1R22 in October, 2013. Therefore the pump was inoperable from the time Mode 3 was entered on November 1, 2013 at 1006 hours. Technical Specifications (TS) require three trains of AFW to be operable in Modes 1 through 3. Entry into Mode 3 and operation with an inoperable pump, for longer than permitted by the TS, constitute conditions prohibited by TS. During this time each of the Motor Driven AFW pumps were rendered inoperable, separately, for maintenance and/or testing. This constitutes a condition that could have prevented the fulfillment of a Safety Function. The governor has been properly adjusted and the appropriate procedures will be revised.
This event is being reported under 10 CFR 50.73(a)(2)(i)(B) as a condition prohibited by Technical Specifications and under 10 CFR 50.73(a)(2)(v)(B) as a condition that could have prevented the fulfillment of a Safety Function - Remove Residual Heat.
|05000334/LER-2013-002||14 February 2014||Beaver Valley|
During the Beaver Valley Power Station (BVPS) Unit 1 1R22 Refueling Outage, a through wall defect was discovered during a planned visual examination of the Reactor Containment Building (RCB) steel liner. The BVPS Unit 1 containment design consists of an internal steel liner that is surrounded by reinforced concrete.
Investigation and laboratory analysis determined that there were indications of two through wall penetrations with a possible third penetration slightly off-set from the second. The total combined area of the three penetrations was calculated to be 0.395 square inches. A visual inspection of 100 percent of the accessible liner area was completed. No additional significant indications of corrosion were identified. Prior to startup from 1R22, the RCB steel liner was repaired and tested satisfactory.
The direct cause of this event was determined to be pitting type corrosion, originating from foreign material introduced during the original construction of the containment wall.
An evaluation determined that there is reasonable assurance that the containment was operable during the period of time that the plant was operated with the small areas of through wall corrosion on the steel liner.
Therefore, there was no loss of safety function and the safety significance is considered to be very low. This event is being reported under 10 CFR 50.73(a)(3)(ii)(A) as a condition resulting in a principal safety barrier being degraded.
|05000334/LER-2013-003||6 January 2014||Beaver Valley|
On November 5, 2013 at 1747 hours, Beaver Valley Power Station (BVPS) Unit 1 was operating at 47 percent power after the 1R22 Refueling Outage. The Unit 1 Control Room received multiple unexpected alarms. The Turbine/Generator tripped due to Unit Station Service Transformer (USST) "BV-TR-1C" differential protection relay actuation. This transformer was energized but not in service at the time. The reactor operator manually tripped the reactor due to multiple unexpected alarms. An automatic reactor trip signal was not generated due.to the fact that the reactor was operating at a power level less than the turbine trip - reactor trip setpoint of 49 percent power. The Steam Driven Auxiliary Feedwater (AFW) pump automatically started due to low level in the "C" Steam Generator. The "B" Motor Driven AFW pump was manually started to assist in maintaining steam generator levels. An Unusual Event was turbine building mezzanine. The cause of this event was determined to be a fault in the "B" 4KV bus supply cables from BV-TR-1C that resulted in an arc flash and subsequent fire. Corrective actions include planned replacement of the faulted supply cables and inspections of the remaining Unit 1 and Unit 2 4KV bus supply cables for signs of degradation and aging.
This event is being reported under 10 CFR 50.73(a)(2)(iv)(A) as a condition that resulted in the valid manual and automatic actuation of systems listed in (a)(2)(iv)(B) - (1) manual Reactor trip, (6) manual and automatic Auxiliary Feedwater pump start. A 10 CFR 50.72 notification was made at 1927 hours on November 5, 2013 to report entry into an Unusual Event, RPS Actuation and a Specified System, Auxiliary Feedwater actuation (EN 49505).
|05000334/LER-2013-001||27 November 2013||Beaver Valley|
At approximately 0228 hours on September 30, 2013, during a planned shutdown of Beaver Valley Power Station (BVPS) Unit 1 for a refueling outage, the "B" motor driven Auxiliary Feedwater (AFW) pump was manually started, while in Mode 3, due to lowering levels in the steam generators.
The condensate pump recirculation flow control valve opened to approximately 40 percent, which resulted in a reduction of the condensate flow to the steam generators and a decrease in the steam generator levels.
The operators recognized that adequate feedwater flow was not available using the normal flow path of the condensate pump through the bypass feedwater regulating valves to the steam generators. In response to the lowering steam generator levels, the operators manually started the "B" motor driven AFW pump to restore the steam generator water levels. Following the start of the AFW pump, the steam generator levels were returned to their normal operating control band. The apparent cause of this event was that the condensate flow control valve opened when it was not intended due to the associated flow controller being out of calibration. The controller was repaired and functionally checked during the refueling outage.
This event is being reported under 10 CFR 50.73(a)(2)(iv) as a condition that resulted in the valid manual start of a system listed in (a)(2)(iv)(B)(6) - Auxiliary Feedwater. The safety significance associated with the manual start of the AFW pump is considered to be very low.
|05000412/LER-2013-001||23 August 2013||Beaver Valley|
On 6/24/2013, Beaver Valley Power Station (BVPS) Unit No. 2 was at 100 percent power. At 0836 hours, the Control Room was notified of a void in the suction piping of the "A" train High Head Safety Injection (HHSI) pump. During a routine performance of a void monitoring procedure, a void of approximately 0.62 cubic feet was discovered at the suction of the "C" HHSI pump which was aligned to the "A" train. The pump was declared inoperable and Technical Specification (TS) LCO 3.5.2, ECCS Operating, was entered. The "B" HHSI pump, aligned to the "B" train, was operable and in service. The "A" HHSI pump was inoperable, due to planned maintenance.. Following venting and verification that the suction piping of the "C" HHSI pump was sufficiently full of water, the "A" train of HHSI was declared operable and TS LCO 3.5.2 was exited at 1623 hours on 6/24/2013. It was subsequently determined that the gas void had existed prior to the "C" pump being credited as the stand-by HHSI pump on the "A" train eight days previously. The "C" HHSI pump was inoperable during the eight day time frame. TS LCO 3.5.2, ECCS Operating, requires two trains of ECCS to be operable. As this condition existed for greater than the allowed restoration and shut down completion times of this LCO, a condition prohibited by technical specifications had existed. At no time during this event were both trains of ECCS inoperable simultaneously.
The void source was determined to be from an inadequate fill and vent of the reactor coolant pumps seal return line.
The root cause of this event is the minimum flow required to move entrained air through the seal water return piping was not present. The procedure used to fill and vent the seal return lines did not ensure a minimum flow was obtained that would move the entrained air to the vent location. The plant risk associated with this event was evaluated to be very low.
|05000334/LER-2011-002||16 March 2012||Beaver Valley|
On November 4, 2011, plant personnel identified that a maintenance activity performed on December 13, 2010, may have resulted in non-compliance with the Required Actions of Technical Specification (TS) 3.7.5. Specifically, on December 13, 2010, the Beaver Valley Power Station Unit Number 1 (BVPS-1) "A" Train Motor Driven Auxiliary Feedwater (AFW) system pump (1FW-P-3A) was removed from service and declared inoperable at 0339 hours to perform maintenance. TS 3.7.5 Condition B for one AFW Train being inoperable was entered due to removal of 1FW-P-3A pump from service. The turbine driven AFW pump (1FW-P-2) remained aligned to the "A" train supply header as required by TS 3.7.5 Required Action B.1. This Required Action applies when both AFW supply headers are Operable. With the 1FW-P-3A pump inoperable and the 1FW-P-2 pump aligned to the "A" supply header, the automatic open signal timing circuit for the Train "A" AFW flow throttle valves was de-energized as part of a clearance to perform a calibration on relay 62-AFPA at 0950 hours on December 13, 2010, and was not re-energized until 1642 hours on December 13, 2010. Although the Train "A" AFW flow throttle valves were in the open position, this action resulted in the inability to meet TS Surveillance Requirement 22.214.171.124 and, therefore, resulted in Train "A" AFW flow throttle valves being inoperable. TS 3.7.5 Condition D for two AFW trains being inoperable was not applied when the automatic open signal timing circuit for the Train "A" flow throttle valves was de-energized. As a result, the required action of TS 3.7.5 Condition D to place the plant in Mode 3 within the following six hours was not met. This event is reportable per 10 CFR 50.73(a)(2)(i)(B) (Operations or Condition prohibited by TS) due to two trains of AFW being inoperable for greater than six hours while the BVPS-1 was operating in Mode 1.
The Apparent Cause of this event was the lack of knowledge/correct interpretation of the auto-open feature and its impact on operability by the on-shift crew tasked with approving and issuing the clearance for posting. The safety significance of the event was very low.
This supplement is being issued due to four additional events that have been identified as violations of TS 3.7.5 as a result of the extent of condition investigation from the original event. The safety significance of each of these four events was very low.
|05000334/LER-2011-001||20 December 2011||Beaver Valley|
On November 2, 2011, the Beaver.Valley Power Station NFPA 805 transition team personnel identified that samples taken from the outer coating from certain liquid tight flexible conduits installed through fire barrier penetrations did not exhibit expected flame resistant characteristics and were not in conformance with documented previously tested fire barrier configurations at Beaver Valley Power Station Unit 1 (BVPS-1). The liquid tight flexible conduits installed through fire barrier penetrations are non-conforming with the provisions of NRC Branch Technical Position (BTP) APCSB 9.5-1. The BVPS-1 plant areas that require fire barriers for train separation for safe shutdown equipment are potentially affected, except for the reactor containment and the river water main intake structure. The concern is whether the liquid tight coating could ignite and spread the fire to the opposite side of the barrier. The apparent cause of this latent issue is inadequate review of the accumulative effects from all field changes. Specifically, subsequent installation of otherwise qualified fire seals did not consider potential compromise by the jacket material of the previously installed liquid tight flexible conduit acting as a penetrant.
Following identification of this issue, compensatory actions were promptly implemented to provide an adequate level of protection for redundant equipment. These include a twice per twelve hour shift fire watch patrol in the affected plant areas, and the restrictions for performing hot work in the vicinity of the affected penetrations. In addition, transient combustible materials are prohibited in affected plant areas from being stored adjacent to electrical penetrations fire seals or adjacent to conduit within five feet of an electrical penetration fire seal as a compensatory action.
A fire has not occurred in the affected fire areas that has challenged these penetrations. The overall safety significance due to the impact of these potentially non-compliant flexible conduits being used in penetration fire barriers is considered to be low to moderate, based on the summation of all the analyzed individual fire compartment delta Core Damage Frequencies for the affected areas. Degraded fire barriers, such that the required degree of separation for redundant safe shutdown trains is lacking, is reportable as an unanalyzed condition that significantly degraded plant safety. Therefore, this report is being submitted pursuant to 10 CFR 50.73(a)(2)(ii)(B).
|05000334/LER-2003-007||7 January 2004||Beaver Valley|
At 1135 hours on November 13, 2003, the Beaver Valley Power Station Unit 1 reactor received an unexpected automatic reactor trip signal while operating at 100 percent power. The reactor trip signal was inadvertently generated during the performance of a maintenance surveillance procedure on the Solid State Protection System. Instrument and Control Technicians connected a digital volt meter (DVM) across the incorrect terminals in the Reactor Trip Breaker Switchgear cabinet when verifying breaker position contact state. This incorrect action created a current path across an open contact and energized the turbine trip relay. The turbine trip initiated an automatic reactor trip. The operating crew entered Emergency Procedure E-0, and transitioned to ES-0.1 in response to the trip. During the event, all required plant safety systems responded as required. This event is reportable pursuant to 10 CFR 50.73(a)(2)(iv)(A) as an event that resulted in automatic actuation of systems listed in 10 CFR 50.73(a)(2)(iv)(B)(1).
The cause was self-checking and peer checking that did not meet expectations. The 'B' train of Solid State Protection System (SSPS) had just been returned to service, exiting the applicable Action of the technical specifications (a two hour allowed outage time). Because the crew had exited the time critical portion of the technical specification, they did not complete the remaining portion of the surveillance procedure with the same sense of rigor as was used in the prior steps. The safety significance of this event was low.
NRC FORM 360 (7-2001) �
|05000334/LER-2003-006||12 November 2003||Beaver Valley|
On September 22, 2003, Westinghouse issued Nuclear Safety Advisory Letter 03-9, which addressed an error in the Westinghouse steam generator water level setpoint analysis due to previously incorrectly addressing a differential pressure which occurs across a mid-deck plate within the steam generator during steam flow. This differential pressure adversely affected the steam generator low-low level setpoint uncertainty for Beaver Valley Power Station (BVPS) Unit 1 and Unit 2. During operation prior to when the steam generator water level low-low setpoints at both BVPS Units were recently raised, there was inadequate margin available to offset this newly identified effect which needed to be addressed as a non- conservative bias in the uncertainty calculations. Therefore, the design basis feedwater line break analysis of record may not be valid since it relied upon steam generator level to initiate a reactor trip.
This event is reportable pursuant to 10 CFR 50.73(a)(2)(ii)(B) as an unanalyzed condition that significantly degrades plant safety since the impact of crediting another reactor trip function which may occur in place of steam generator low-low level during the specific postulated feedline break transient has not been calculated and is unknown. Similarly, this also represents a condition that could have prevented the fulfillment of the safety function of structures or systems that are needed to shut down the reactor and maintain it in a safe shutdown condition as described in each Unit's UFSAR and is reportable pursuant to 10 CFR 50.73(a)(2)(v)(A). The cause of this event was inadequate Westinghouse design analysis of steam generator mid-deck plate differential pressure. The safety significance of this event was low.
NRC FOAM NG (7.20D11
|05000334/LER-2003-005||15 September 2003||Beaver Valley|
On July 18, 2003, during a routine post-refueling outage review of the Reactor Coolant System (RCS) precision flow calorimetric data from a test procedure on RCS Total Flow Measurement, it was determined that one of the nine channels of RCS flow (3 channels per loop) was set non- conservatively with respect to Technical Specifications. Specifically, it was Identified that channel F-1RC-424 on the 8-RCS loop was set to 89.2 percent of full power RCS flow when the Technical Specification allowable value for loop flow is greater than or equal to 89.8 percent. The root cause of the non-conservative RCS flow setpoint is an inadequate process to verify RCS flow setpoints are within Technical Specification limits prior to reaching ten-percent power. Since, this condition existed longer than the allowed outage time of 6 hours permitted by Technical Specifications, it was a condition prohibited by plant Technical Specification 126.96.36.199; therefore this event is reportable pursuant to 10 CFR 50.73(a)(2)(i)(B). Additionally, there were two occasions where maintenance removed an operable instrument from service placing the plant in a condition outside of the action statement. Therefore, Technical Specification 3.0.3 was unknowingly in effect and actions to commence plant shutdown were not initiated within one hour. Thus, these events were also conditions that are prohibited by plant Technical Specification and are reportable pursuant to 10 CFR 50.73(a)(2)(1)(8). Review of this event for effect on core damage frequency (CDF) for BVPS Unit 1 was performed and the cumulative safety significance of these events was _ determined to be small.
NRC FORM 3E4 (74(101)
|05000334/LER-2003-002||30 May 2003||Beaver Valley|
On February 5, 2003, during an extent of condition review of the potential to over-pressurize a fire area if the Carbon Dioxide (CO2) fire protection system discharges, it was discovered that the East and West Cable Vaults fire areas at Beaver Valley Unit 1 (BV-1) were susceptible to this concern. If the total flooding CO2 fire suppression systems in the East and West Cable Vaults were discharged, the resultant pressure transient could cause the fire barriers within the subject areas to be structurally challenged, causing the fire barriers to be breached. Losing the fire barrier integrity could result in a decrease in CO2 concentration in the area, which would reduce the effectiveness of the CO2 system to extinguish the fire. If the fire were not extinguished it could result in the potential for a postulated fire in one fire area to spread to an adjacent fire area. This would invalidate the assumptions made in the BV-1 10 CFR 50 Appendix R fire protection safe shutdown analysis and thus represents an unanalyzed condition. As a compensatory measure, the automatic CO2 suppression systems in the East and West Cable Vaults were disabled on February 5, 2003 at 2150 hours in response to the initial identified issue and a fire watch was established in the affected areas.
The fire protection system alarm function remained enabled in order to provide notification in the Control Room if a fire would occur. These measures eliminated the potential for a CO2 overpressure transient condition to occur in the affected areas.
The root cause of this event was determined to be insufficient design and system interface applicable to engineering work practices with a secondary cause of inadequate or incomplete design aspects. These were chosen because the impact to the CO2 protected areas, due to the more tightly sealed areas resulting in a higher pressure peak, was never recognized by the fire barrier program owner when the new seals were installed.
This condition is reportable pursuant to 10 CFR 50.72(b)(3)(ii)(B) (EN# 39573) and 10CFR 50.73 (a)(2)(ii)(B) as an unanalyzed condition that significantly degrades plant safety.
|05000334/LER-2002-002||8 January 2003||Beaver Valley|
On November 11, 2002, Beaver Valley Power Station (BVPS) Unit 1 was performing a planned power reduction from full power at a rate of approximately 12 percent per hour for a scheduled maintenance outage. At approximately 1946 hours, the plant was at 53 percent power and the Turbine Motoring Condition alarm was received. An automatic turbine trip will occur if this alarm is received for more than 30 seconds. An automatic reactor trip will also occur following a turbine trip signal, if the plant power level is above 49 percent power. After approximately 20 seconds from the time of the alarm, the Control Room Unit Supervisor directed a manual reactor trip. Control room personnel implemented Emergency Operating Procedure E-0 for a reactor trip. The Auxiliary Feed Water System actuated as expected and all other systems functioned as required.
An investigation into the event determined that the turbine motoring condition alarm was caused by a failure of the turbine differential pressure instrument that measures the differential pressure between the turbine impulse pressure and the turbine exhaust. The failure was due to a misapplication of the instrument to the service conditions. The failed instrument was replaced with a new instrument more suited for the application.
The manual initiation of a reactor trip via the Reactor Protection System by the BVPS Unit 1 control room operator on November 11, 2002, was a valid manual reactor trip signal and was not part of a pre-planned sequence during testing or reactor operation. Therefore this event is reportable pursuant to 10 CFR 50.73(a)(2)(iv)(A). The safety significance of the manual reactor trip on November 11, 2002 was small.
|05000334/LER-2002-001||15 November 2002||Beaver Valley|
On September 25, 2002, it was determined that previously measured silt levels in three bays of the Beaver Valley Power Station (BVPS) Main Intake Structure had exceeded acceptable limits to assure adequate inflow from the Ohio River into the Intake Structure bays in order to provide sufficient ultimate heat sink cooling needs during the design basis / licensing basis bounding extreme low river water event. This was identified during follow-up evaluations of issues raised during a Latent Issues design review of the BVPS Service Water System. Even though the Ohio River has never approached the design basis / licensing basis extreme low water level, the BVPS Unit 1 safety related River Water System and the BVPS Unit 2 safety related Service Water System must have adequate ultimate heat sink capability to adequately support the bounding low probability low river water level design basis / licensing basis postulated scenario. Current BVPS design analyses show that adequate inflow to the suction of the River/Service Water System pumps may not be assured with greater than 22 inches of solid blockage in an Intake Structure bay.
Previously identified as-found silt levels in Intake Structure bays have exceeded 22 inches. This represents a potential unanalyzed condition that could significantly degrade plant safety. Therefore, this is being reported pursuant to 10 CFR 50.73 (a)(2XiiXB).
The cause of this event was inadequate/incomplete design aspects. The accumulation of silt in the Intake Structure is only a potential concern during an extreme low river water level condition. The probability of an extreme low river water level is small. The silt is considered to form a completely solid dam as a conservative assumption. However, the silt is not qualitatively expected to be capable of forming a solid dam if an extreme low river water level condition were to occur. The safety significance of prior conditions where the Intake Structure silt levels exceeded 22 inches in the past was low.
|05000334/LER-2001-004||4 February 2002||Beaver Valley|
At 1353 hours on December 7, 2001, the operating station air compressor 1SA-C-1A tripped while station air compressor 1SA-C-1B was de-energized for preventive maintenance. The running compressor tripped due to a blown fuse in its control circuitry. The blown fuse was caused by a short circuit that was the result of uninsulated screwdriver contact in an energized circuit between compressors 1SA-C-1A and 1SA-C-1B. The on-shift operations crew responded per the appropriate alarm response procedure, and entered Abnormal Operating Procedure (AOP) 1.34.1, 'Loss of Station Instrument Air". Operators were dispatched locally to compressor 1SA-C-1A, the compressor's supply breaker and to the backup diesel air compressor 1SA-C-2. A local start of 1SA-C-1A was unsuccessful due to the blown control power fuse. The backup diesel air compressor was started and placed in service; however, system pressure had already reached an abnormally low level and the backup diesel compressor was unable to restore system pressure due to insufficient capacity. The low system air pressure caused Loop 1C main steam trip valve, TV-1MS-101C, to begin to close as indicated by alarm "Steamline Stop Valve Not Fully Open".
At 1401 hours, Beaver Valley Power Station (BVPS) Unit 1 reactor was manually tripped due to the loss of station air in accordance with AOP-1.34.1. All control rods fully inserted into the reactor core and all required safety systems operated as designed. Emergency Operating Procedure E-0 for Reactor Trip was performed and the plant was stabilized in Mode 3. The direct cause for the manual trip was a loss of station air due to the unavailability of both station air compressors. The root cause of the event was determined to be the failure of the station work process to adequately plan, review, control, assign risk significance, and provide adequate oversight for work activities. This event is reportable pursuant to 10 CFR 50.72 (b)(2)(iv)(B) and 10 CFR 50.73(a)(2)(iv)(A) as a valid reactor trip and was not part of a pre-planned sequence during testing or reactor operation. The safety significance of this event was low.
|05000334/LER-2001-003||21 December 2001||Beaver Valley|
At 1416 hours on November 6, 2001, Beaver Valley Power Station Unit No. 1 reactor automatically tripped from 100% power due to low-low level in the C Steam Generator. The Feedwater Level Control Valve on the C Steam Generator unexpectedly failed closed causing the C Steam Generator water level to rapidly drop and reach the low-low water level reactor trip setpoint. Prior to the reactor trip, the Control Board Operator attempted to open the Feedwater Level Control Valve in manual control and observed no increase in the demand signal indicator or feedwater flow. After the reactor trip, Emergency Operating Procedure E-0 for Reactor Trip was performed and the plant was stabilized in Mode 3.
The automatic initiation of a reactor trip from 100% power via the Reactor Protection System on November 6, 2001, was a valid reactor trip and was not part of a pre-planned sequence during testing or reactor operation. Therefore this event is reportable pursuant to 10 CFR 50.72(b)(2)(iv)(B) and 50.73(a)(2)(iv)(A). The cause of the unexpected closure of the C Main Feedwater Regulating Valve was a random failure of a diode in the 7100 process rack module that controls the valve actuator. The safety significance of the automatic reactor trip on November 6, 2001 was small.
|05000334/LER-2001-002||29 November 2001||Beaver Valley|
On October 6, 2001, Beaver Valley Power Station Unit No. 1 testing personnel and the Control Room operators were performing a Control Rod Drop Testing surveillance in preparation for reactor startup following Unit l's fourteenth refueling outage. The plant was in a sub-critical condition in Mode 3 with Shutdown Bank B control rods withdrawn. At 1959 hours, the Control Room operators observed indications of two dropped control rods (via rod position indication reading zero steps and rod bottom lights on), and entered Unit 1 Abnormal Operating Procedure (AOP) 1.1.8 for Rod Inoperability. The Reactor Operator opened the reactor trip breakers in accordance with the AOP and the Reactivity Management Plan. Emergency Operating Procedure E-0 for Reactor Trip was performed and the plant remained in Mode 3. The manual initiation of a reactor trip via the Reactor Protection System by the BVPS Unit 1 control room operator on October 6, 2001, was a valid manual reactor trip signal and was not part of a pre-planned sequence during testing or reactor operation. Therefore this event is reportable pursuant to 10 CFR 50.73(a)(2)(iv)(A).
It was subsequently discovered that the two dropped control rod indications were caused by the testing personnel repositioning knife switches to place the rod drop computer in service. There were no dropped control rods. This action by the testing personnel and resulting expected indications were not communicated to the Control Room operators prior to their occurrence. The opening of the reactor trip breakers was caused by a lack of good communication practices and a lack of procedure adherence by an inexperienced test engineer. This engineer failed to read a step in the test procedure which required the engineer to inform the Reactor Operator that the control room would be losing indication on control rod Shutdown Bank B. The safety significance of the manual reactor trip on October 6, 2001 was small.