A host of preventable scams, shutdowns and down powers continue to plague this plant. This damages equipment and risk of a much more significant accident.
So they replace the 3A and 3C SRV values. They only admitted one was broken, These new safety valves within weeks of first startup in 2011 began to leak and since have been plagued with premature degradation, leaks and failures. I solely blame the NRC for not using their so called big hammer to enforce safety reliability issues.May 11, 2015Summary of Plant StatusPNPS began the inspection period at 100 percent power. On January 27, 2015, during a severe winter storm, operators reduced reactor power to 52 percent due to degrading switchyard conditions when an automatic reactor scram occurred with the loss of 345 kilovolt (kV) offsite electrical power sources (line 355 and line 342). The operators took the unit to cold shutdown that same day and remained in that condition for restoration of the 345kV offsite electrical power sources, replacement of
This is the first time we hear this, they had some damage on the Y2 vital "instrument" bus. The storm and the shutdown damaged the vital instrument bus. Just saying, the NRC and Entergy doesn't disclose all the safety problems on a event, they slowly leak it out for months knowing everyone is sleeping.the 3A and 3C safety relief valves (SRVs), and repairs to the Y2 vital instrument bus. Operators commenced a
Well never know how many down power and shutdown there will be in the future with a degraded condenser. Remember all those down powers and shutdowns over Fitzpatrick's leaking main condenser tubes until they replace them all. I think for reliability of the NE grid Pilgrim needs a new main condenser or extra glue.reactor startup on February 6, 2015, and returned the unit to 100 percent power on February 8, 2015. Operators reduced reactor power to 55 percent on February 9, 2015, to perform a rod pattern exchange, and returned to 100 percent power that same day. On February 14, 2015, the operators performed a controlled shutdown and proceeded to cold shutdown based on procedural requirements during blizzard conditions. Operators performed a reactor startup on February 17, 2015. On February 18, 2015, after achieving 20 percent power, troubleshooting of the main
Did they think the "A" degraded or weak...didn't want to use it? Usually they cycle using all the remain operating valves?condenser was performed due to condenser tube leaks. Following repair of the condenser tube leaks, operators proceeded with power ascension on February 19, 2015. Operators returned the unit to 100 percent power on February 20, 2015. On February 21, 2015, operators reduced reactor power to 60 percent to perform a rod pattern adjustment. Operators returned the unit to 100 percent the same day. On March 18, 2015, operators reduced power to 70 percent to perform a rod pattern adjustment. The unit was returned to 100 percent power the same day and remained at 100 percent power for the remainder of the inspection period.
3B and 3D SRV continued use after 3C SRV
Description. 4160V undervoltage relays 127-509/1 & 2 are designed to provide an alarm to the control room operators in the event of an undervoltage and overvoltage condition on 4160V safety-related electrical bus A5. In 1989, problem report PR-1989-2244 was issued regarding a degraded voltage scenario that was identified from operating experience at other boiling water reactors (BWRs). The scenario specifically looked at the potential for a voltage regulator failure of the operating EDG during a simultaneous LOOP and LOCA. Given that the LPCI valves are powered from 480V electrical bus B6, which receives power from 4160V Bus A5 and A6, a failure of the EDG voltage regulator during a LOOP/LOCA would cause the LPCI valves to fail to open or fail in place and not fully open. This would prevent the ECCS from injecting at low pressures and potentially lead to core damage. The corrective action to this scenario included two parts that were implemented at different times. First, in 1989, to ensure this event did not impact the ECCS injection
I wonder how often the shift practice this kind of failure. I basically call the shift in a Cat 4 complexity hurricane. There are so far out on the limb with complexity at this point, humans are very unreliable. They are solving a technical problem...not thinking holistically and pondering the complexity storm this shift is entrained in. Basically there are tons of blinking annunciation and alarms going on all over the place in the control room.
function, a step was added in alarm response procedure ARP-C3L to trip the operating EDG to protect the 4160V bus and other associated electrical equipment. Second, in 1997, relays were installed to protect respective electrical feeds to the B6 480V electrical bus; preventing potential damage to the LPCI injection valves if the EDG were to fail during a LOOP/LOCA.
On March 6, 2015, Entergy staff performed 4160V electrical bus A5 relay testing in accordance with work
So they never tested the new relays...operators go to bed with nightmares thinking the engineering staff could screw the operating staff in a accident. In the heart of a terrible accident equipment and alarms would't works. A plant have 100,000 of relays and compo-nets, how many of the not working components in very complex accident would it take to confuse the shift?
How many none tested critical to protect the core relays aren't tested for decades?
order 52425333 and procedure 3.M.3-1, “A5/A6 Buses 4kV Protective Relay Calibration/Functional Test and Annunciator Verification – Critical Maintenance,” Revision 140. In preparation for this testing, Entergy staff noted a change in the drawing which contains the acceptance criteria for the 127-509/1 and 127-509/2 relays. The Entergy staff appropriately updated their relay testing equipment with the proper acceptance criteria; however, did not recognize that the relays had not been tested for the undervoltage dropout setting prior to this date. Testing of the undervoltage dropout setting for relays 127-509/1 & 2 revealed the “as-found” set point to be at 82V compared to the requirement of 106V. Upon inspectors request for information regarding past performance of relays 127-509/1 & 2, Entergy staff discovered that no prior testing for the undervoltage dropout setting had ever been performed. Given that Entergy had not tested these relays over the life of the plant, there was no method to effectively track and trend relay drift from required setpoints which impacted operators’ ability to carry out actions in alarm response procedures. Entergy entered CR-PNP- 2015-1614 and CR-PNP-2015-1623 into the CAP to address the degraded condition. An immediate operability determination was performed and the relays were re-calibrated to their required set points successfully prior to restoration of the X107A EDG. UFSAR Section 8.4.7 for the auxiliary power distribution system establishes a testing frequency for non-technical specification, safety-related 4160V relays in Table 8.4-3 for every four years. These relays are typically tested in accordance with Entergy’s preventive maintenance program and implementation of procedure 3.M.1-1. However, Entergy did not establish testing requirements or a testing frequency to ensure that the undervoltage dropout relay was properly being maintained and functional. Entergy entered CR-2014-1898 into the CAP to address this issue. The immediate operability determination noted that the 480V electrical bus relays installed in 1997 would have performed a similar function to protect the ECCS injection equipment; however, it would not have protected other safety-related equipment in the event of a voltage regulator failure during a LOOP/LOCA. The inspectors confirmed that the 480V electrical bus relays were properly tested and within acceptance criteria as of 2013 to ensure it could have prevented LPCI injection failure.
So you get it, relays critical in a accident to prevent core damage indicating their only remaining power source is failing only gets a insignificant violation. Over all these years with the money spent on inspector and a assortment of inspections, take the starling noneffective CDBI in-depth inspections...why didn't the NRC uncover this first decades ago. What do these inspector do on site???
(NCV 05000293/2015001-01, Failure to Perform Testing of Safety Related Undervoltage Alarm Relays)This not a professional staff: Bet you the NRC whispered in their ears fix it.
The inspectors performed an in-depth review of Entergy’s apparent cause evaluation and corrective actions associated with CR-PNP-2014-1851, “A Negative Trend of Valves\ Trended to Satisfy IST Requirements Has Been Identified.” Specifically, the monitoring of valve stroke times for multiple safety-related valves was not identifying adverse trends in an effective and timely manner, which resulted in equipment operability issues and emergent repairs.
Entergy staff determined there were two apparent causes: 1) component and system engineers and supervisors were generally unaware of their responsibilities to review and trend IST component data as required by Entergy fleet procedures, and 2) the IST engineer did not take timely action to initiate CRs in accordance with program requirements. Entergy staff also determined that system monitoring challenge board meetings were not conducted on a regular basis during this period as required by procedure EN-DC-159, “System Monitoring Program.”
The inspectors concluded that Entergy staff conducted an appropriate review to identify the likely causes of the IST trending issue. The inspectors also concluded that Entergy staff identified the extent of condition which was mostly the trending of IST program data for the in scope systems; however, the review included an evaluation of the other programs where trending is performed as part of condition monitoring. Corrective actions included a review of the procedure requirements conducted between the system engineers and their supervisors, establishment of a reoccurring schedule for system monitoring challenge board meetings, training for system engineers on monitoring and trending expectations, and revisions of system monitoring plans to include IST data parameter.
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