05000388/LER-2012-003
| Susquehanna Steam Electric Station Unit 2 | |
| Event date: | |
|---|---|
| Report date: | |
| Reporting criterion: | 10 CFR 50.73(a)(2)(iv)(A), System Actuation |
| Initial Reporting | |
| ENS 48598 | 10 CFR 50.72(b)(2)(iv)(B), RPS System Actuation, 10 CFR 50.72(b)(3)(iv)(A), System Actuation, 10 CFR 50.72(b)(2)(iv)(A), System Actuation - ECCS Discharge |
| LER closed by | |
| IR 05000387/2013011 (18 November 2013) IR 05000387/2014008 (12 September 2014) | |
| 3882012003R01 - NRC Website | |
On December 16, 2012, at approximately 0156 hours0.00181 days <br />0.0433 hours <br />2.579365e-4 weeks <br />5.9358e-5 months <br />, the Susquehanna Steam Electric Station (SSES) Unit 2 reactor automatically scrammed during the performance of Technical Specification (TS) surveillance testing of the #2 turbine control valve (CV). The test being performed was the quarterly channel functional test of the turbine CV fast closure channels of the Reactor Protection System (RPS). At 0151 hours0.00175 days <br />0.0419 hours <br />2.496693e-4 weeks <br />5.74555e-5 months <br />, the #4 CV was tested and a Division 2 half-scram signal was received and cleared as expected. At 0153, CV #1 was tested, but was aborted due to nail meter glare. At 0153 hours0.00177 days <br />0.0425 hours <br />2.529762e-4 weeks <br />5.82165e-5 months <br />, the CV #1 test was successfully completed. At 0155 hours0.00179 days <br />0.0431 hours <br />2.562831e-4 weeks <br />5.89775e-5 months <br />, during testing of the #2 CV, a RPS half-scram was received as expected (specifically, the 'B' channel, Division 2 of RPS). Prior to the Division 2 scram signal clearing, an unexpected momentary Division 1 (A' channel of RPS) scram signal was also received from the CV #1 fast closure signal, resulting in a full RPS reactor scram.
All control rods fully inserted, with two control rods inserting beyond position "00" following reset of the reactor scram. Both reactor recirculation pumps tripped at -38 inches. All containment isolations occurred as expected. Both the High Pressure Cooling Injection (HPCI) and Reactor Core Isolation Cooling (RCIC) systems automatically initiated and injected water into the reactor vessel but were overridden by the control room operators once reactor water level was restored above the HPCI and RCIC initiation setpoints. The scram was reset to aid in preventing reactor vessel thermal stratification.
At approximately 0210 hours0.00243 days <br />0.0583 hours <br />3.472222e-4 weeks <br />7.9905e-5 months <br /> on December 16, 2012, a secondary scram occurred on reactor low water level (+15 inches). This occurred when operations attempted to raise the Feedwater Integrated Control System (ICS) reactor water level setpoint setdown value from +18 inches to +35 inches. However, reactor water level lowered to the scram setpoint, resulting in a second reactor scram signal. No control rod motion occurred, as all rods were inserted.
There were no safety relief valve actuations or emergency diesel generator starts during the event. Reactor pressure was controlled via turbine bypass valve operation. There were no structures, systems, or components that were inoperable at the start of the event that contributed to this event.
In accordance with 10 CFR 50.72(b)(2)(iv)(A) and 10 CFR 50.72(b)(2)(iv)(B), on December 16, 2012, a 4-hour ENS notification (# 48598) was made to the NRC for an event or condition that results in Emergency Core Cooling Systems (ECCS) discharge into the reactor coolant system as a result of a valid signal, and any event or condition that results in the actuation of the RPS when the reactor is critical, respectively. This event was also reportable as an 8-hour notification in accordance with 10 CFR 50.72(b)(3)(iv)(A) for any event or condition that resulted in a valid actuation of the RPS, and the HPCI and RCIC systems.
This LER is being submitted in accordance with 10 CFR 50.73(a)(2)(iv)(A) for an event or condition that resulted in the automatic actuation of the RPS, and the HPCI and RCIC systems.
No direct cause of the unexpected Division 1 scram signal was identified. This conclusion is based on laboratory results from the disassembly and inspection of the #1 Turbine CV.
The root cause of the event was SSES failed to incorporate industry best practices with other impacted work groups (Operations) for half scram reduction. Specifically, Dresden OE (from 2000) regarding the station's success in reducing the number of half scram by using an RPS test box, and the 2005 Boiling Water Reactor Owners Group (BWROG) scram reduction effort, Recommendation #30 regarding the use of a test box to reduce RPS half-scram signals. An RPS test box allows testing of a scram contactor without actualizing the contactor and creating a half scram. SSES's evaluation of the above OE recommendations did not recognize the OE's applicability to operations surveillance test procedures.
The following two causal factor also contributed to the event:
Causal Factor 1 — Poor maintenance practices related to insulation stripping and connection crimping created resistance leading to less than designed power applied to the solenoid coil.
Causal Factor 2 — Failure to incorporate GE SIL 226 (from 1977) recommendations for adequate wait time between testing into the SSES Quarterly Turbine Valve Cycling surveillance procedures.
Scram #2:
A root cause analysis was performed to evaluate the cause(s) of the second reactor low water level scram event. The analysis identified the following two root causes:
Step 10 of procedure OP-245-001, "RFP and RFP Lube Oil System," was not performed. Step 10 directs the operator to reset the ICS reactor water level setpoint setdown prior to raising the ICS reactor water level from +18 inches to +35 inches (Step 11). Because Step 10 was not completed, when Step 11 was performed, reactor water level could not be raised.
The ICS design control value of +18 inches for setpoint setdown did not provide adequate margin to prevent operational overlap with the RPS low level scram setpoint of +15 inches. This lack of margin was the result of design requirements not being aligned with post scram expectations from NRC PI 1E04, "Unplanned Scrams with Complications.
ANALYSIS / SAFETY SIGNIFICANCE
Actual Consequences All control rods inserted and both reactor recirculation pumps tripped at -38 inches. HPCI and RCIC both automatically initiated as expected. No steam relief valves opened.
The Unit 2 risk significance and potential consequences for the initiating event experienced on December 16, 2012 due to an RPS automatic scram non-isolation event was less than 1E-06 for Core Damage Probability (CDP) and 1E-07 for Large Early Release Probability (LERP) significance thresholds as defined in NRC Inspection Manual Chapter (IMC) 609. These thresholds represent a Green significance level which is of "Very Low Safety Significance.
In summary, there were no actual consequences to the health and safety of the public as a result of the event.
CORRECTIVE ACTIONS
Key Completed Actions Scram #1:
Revised the Unit 1 and 2 Quarterly Turbine Valve Cycling surveillance procedures to require the use of an RPS test box when performing Main Turbine Control Valve Testing.
Replaced the Unit 1 CV #1 Fast Acting Solenoid Valve and Shutoff Valve.
Revised OE procedures to ensure condition reports are initiated when there is risk identified in OE that may impact SSES.
Inspected all four Unit 1 Fast Acting Solenoid Valves (FASV) for secure butt splice connections.
Revised the Unit 1 and 2 Quarterly Turbine Valve Cycling surveillance procedures to require a 3-minute wait time between tests.
Revised MT-GE-010 sections 5.20 and 5.21 to incorporate industry accepted tug test to ensure connection is mechanically secure.
Scram #2:
Revised ON-100(200)-101 to specify reactor water level bands that would not create a reactor low water level scram.
Revised procedure OP-245-001 and hard card OP-245-001-01 to provide direction for resetting the ICS setpoint setdown.
Revised ON-100(200)-101 to direct closing of the accumulator charging water isolation valve to mitigate thermal stratification. This action will delay time to stratification and thus reduce the immediate need to reset the scram.
Evaluated the differences between the simulator and the plant level trip sepoint and reprogramed the simulator loads with RPV level trip setpoints that are more conservative than the actual setpoints in the plant.
Aligned Operations department standard for procedure place-keeping to site standard.
Revised the level control strategy after the scram (reset of setpoint setdown) to prevent repeat Level 3 scrams.
Provided training to all operators on specific lessons learned as they pertain to reactor level control.
Include this training in initial license and licensed operator requal training.
Implemented a change to the Unit 1 & 2 ICS setpoint setdown to raise the setpoint from + 18 inches to + 22 inches.
Key Planned Corrective Actions:
Revise procedure MFP-QA-1220 to ensure that necessary design considerations are in place to avoid or mitigate post-scram complications
Previous Similar Events:
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