05000259/LER-2007-004
| Browns Ferry Unit 1 | |
| Event date: | 06-03-2007 |
|---|---|
| Report date: | 08-02-2007 |
| Reporting criterion: | 10 CFR 50.73(a)(2)(i)(B), Prohibited by Technical Specifications |
| 2592007004R00 - NRC Website | |
I. PLANT CONDITION(S)
Prior to the event, Unit 1 was operating at approximately 38 percent of rated thermal power (approximately 1300 megawatts thermal). Units 2 and 3 were operating in Mode 1 at 100 percent rated thermal power (approximately 3458 megawatts thermal) and were not affected by the event.
II. DESCRIPTION OF EVENT
A. Event:
On June 4, 2007, WA determined that BFN Unit 1 operated in a condition prohibited by the Technical Specifications (TSs). Previously, Unit 1 commenced start-up from an extended outage in late May of 2007. On June 2, 2007, at approximately 1727 hours0.02 days <br />0.48 hours <br />0.00286 weeks <br />6.571235e-4 months <br /> central daylight time (CDT), BFN Unit 1 attained 30 percent rated thermal power (RTP). On June 2 and 3, 2007 as part of the startup activities, WA performed 1-SR-3.1.4.1, Scram Insertion Times. This surveillance scrams individual control rods thus, causing fluctuations in reactor power.
Subsequent to the testing activities, WA noted that during the test, the scram initiation signal was being bypassed when RTP was between 32 and 34 percent. As such, the scram initiation signal for the turbine control valve [FCV] (TCV) and the turbine stop valve closure [SHV] (TSV) is also bypassed. The bypass is intended to occur when the reactor power, as determined by the turbine first stage pressure, is being bypassed when RTP was between 32 to 34 percent instead of the 30 percent RTP prescribed by the TSs.
The Unit 1 Technical Requirements Manual (TRM) requires two operable or tripped Reactor Protection Systems (RPS) [JC] or tripped systems with a minimum of two operable instrument channels per trip system for the Turbine First Stage Pressure permissive. The permissive is controlled by pressure switches. The first stage permissive pressure switch setting was incorrect at 30 percent RTP. Inoperability of the Turbine First Stage Pressure permissive also affects Technical Specification 3.3.1.1.
Technical Specification 3.3.1.1, Reactor Protection Instrumentation, states: The Reactor Protection System instrumentation for each function in TS Table 3.3.1.1-1, Reactor Protection Instrumentation, shall be operable, furthermore, the Turbine Stop Valve [SHV] - Closure and the turbine Control Valve Fast Closure, trip Oil Pressure - Low, are not bypassed when core thermal power is >1= 30 percent. TS 3.3.1.1 Action E requires, within 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br />, reduce reactor power to was attained until scram time testing was completed June 3, 2007.
Because TVA exceeded the 4 hour4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> LCO action time limit, TVA is submitting this report according to 10 CFR 50.73(a)(2)(i)(B), as any operation or condition prohibited by the plant's Technical Specifications.
B. Inoperable Structures, Components, or Systems that Contributed to the Event:
None.
C. Dates and Approximate Times of Major Occurrences:
May 2007 � TVA commences Unit 1 startup activities following an extended outage.
June 2, 2007�1727 hours CDT�Reactor power is greater than 30 percent.
June 4, 2007 TVA determined Unit 1 operated outside TS 3.3.1.1.
D. Other Systems or Secondary Functions Affected None.
E. Method of Discovery An engineering review determined that Unit 1 had operated in a manner prohibited by the TSs.
F. Operator Actions None.
G. Safety System Responses None.
III. CAUSE OF THE EVENT
A. Immediate Cause The actual turbine first stage pressure used for the scram function at 30 percent RTP was incorrect. The setpoint would not have enabled the reactor scram function at 30 percent RIP.
B. Root Cause The design calculation that determines first stage turbine pressure at 30 percent RTP is incorrect. The calculation utilizes a turbine first stage pressure versus steam flow curve which assumes that all of the feedwater heaters [SM] are in service. Historically, BFN does not have all of the feedwater heaters in service during low power startup activities. This results in a non-conservative calculated pressure setpoint.
C. Contributing Factors In anticipation of operations at extended power uprate conditions, WA modified the high pressure turbine to pass additional steam flow. The modifications to the Unit 1 high pressure turbine resulted in a lower first stage pressure at 30 percent RIP.
IV. ANALYSIS OF THE EVENT
In anticipation of operating Unit 1 at extended power uprate (EPU) operations, the Unit 1 High Pressure Turbine was modified to pass additional steam flow. The modified Unit 1 High Pressure Turbine passes more steam flow at a given power level than the unmodified High Pressure Turbine.
TVA evaluated Unit 1 plant data and confirmed that the turbine first stage pressure at 30 percent RTP was less than 136 psig. Above 34 percent RTP, turbine first stage pressure remained above 136 psig. TVA found the pressure switches for the turbine first stage pressure were functioning as designed. The indicated turbine first stage pressure agreed closely with the GE calculated values and the modified turbine was operating as expected.
The setpoint calculations agreed with the GE Thermal kit. The calculation used the appropriate first stage pressure versus steam flow curve for the Unit 1, however; the calculation was based on plant heat balance calculations performed with all of the feedwater heaters in service. The steam flow to the turbine at a given power level with the feedwater heaters out of service is less than the steam flow with the feedwater heaters in service, therefore; the predicted turbine first stage pressure is lower with the feedwater heaters out of service. Normally, plant procedures place the feedwater heaters in service at power levels higher than 30 percent RTP. This results in an actual first stage pressure less than the calculated first stage pressure.
V. ASSESSMENT OF SAFETY CONSEQUENCES
The safety consequences of this event were not significant. During the time that Unit 1 operated outside the TSs, the scram function would be enabled at >1= 34 percent RTP. If a turbine trip had occurred during the timeframe the reactor operated between 30 and 34 percent RTP, the majority of the steam would have been directed to the main condenser [SG], via the turbine bypass valves [FSV]. If the steam flow through the bypass valves is in excess of their design capacity, a reactor scram will occur on high dome pressure.
The conditions described in this report are bound by the BFN Updated Final Safety Analysis Report. Section 14.4.2.6, Bypass valves Failure Following Turbine Trip, Low Power, discusses a turbine trip at the approximately 30 percent RTP bypass valve failure, and no credit for reactor scram on TSV closure. With total bypass valve failure, the transient analysis indicates the reactor will scram on high vessel pressure. The neutron flux remains acceptable. No fuel damage occurs.
Main Steam Relief Valves [SB] open to control vessel pressure and relieve the transient. The peak pressure remains below the ASME code limits for the reactor. Therefore, the failure to meet the TSs during the low power ascension testing did not adversely affect the safety of plant personnel or the public.
VI.� CORRECTIVE ACTIONS
A. Immediate Corrective Actions
BFN established an operator action that requires the operator to either trip the first stage pressure switches, which will enable the scram function, or requires that the RTP be less than 30 percent power.
B. Corrective Actions to Prevent Recurrence (1) TVA revised the turbine first stage pressure calculation to reflect the Unit 1 high pressure turbine first stage pressure at 30 percent RTP with the feedwater heaters out of service. At the first opportunity WA will implement the change.
(1) TVA does not consider these corrective actions as regulatory requirements. The completion of these actions will be tracked in TVA's Corrective Action Program.
VII.�ADDITIONAL INFORMATION
A. Failed Components
None.
B. Previous LERs on Similar Events None.
C. Additional Information
Browns Ferry Corrective action document PER 125755.
D. Safety System Functional Failure Consideration:
No safety functions were compromised as a result of this event. Therefore, this event is not considered a safety system functional failure in accordance with NEI 99-02.
E. Loss of Normal Heat Removal Consideration:
This event was not the result of a reactor scram, therefore; this event did not result in a scram with a loss of normal heat removal as defined in NEI 99-02.
VIII. COMMITMENTS
None.