Cook Nuclear Power Plant

Cook Nuclear Power Plant
Technical Topics and Troubleshooting the Secondary Cycle of Cook Unit 2

Technical Topics and Troubleshooting
Unit 2 was experiencing the following: The #4, #5 and #6 FWH were initiating rashes of multiple level alarms, 30–50 alarms per shift. During periods of warm circulating water, >70F, thermal power (TP) oscillations became excessive. TP oscillations were ~ +/- 0.3% and acceptable oscillations are <+/- 0.1%. These conditions were occurring for 3 years.

MOV Manual Valve AOV Main Turbine DP 2-MSR 4-S/G Drain Tank 2-HDP ###666 74 psi #6 FWH 4-MFRV #5 FWH #4 FWH Dump Valve 2-Hotwell Condensate Booster (2) Condenser 4-FWH 270 psi 2-MFP BYPASS Spares

Multiple Issues Were Present TP Oscillations Causes: Erratic Feedwater, Condensate and/or Heater Drain Flow Control Valves-Pump Recirculation, FWH Level Drain, FWH Alternate/Dump MFP Turbine Speed Control which is directly influenced by the DP Control scheme.

What did we look at? It was assumed that the FWH level alarms were a control problem and pursued tuning the FWH level control. TP oscillations were the result of improper SGWLC and pursued tuning these controls.

What was the Outcome? Flurries of FWH level alarms continued and tuning the FWH level control was a regular open work order. SGWLC were tuned with a some improve-ment in control. Each summer TP oscillations received a ODM-Operational Decision Maker for DP Control of the MFP.

What were the Issue(s)? Is this “the definition of insanity”? Did we understand the Problem(s)? Did Engineering listen to what people were telling us? Would we let our doctors get away with this type of diagnosis?

What was not heard or listened to? FWH-I&C stated that the controls were maintaining FWH level BUT there would be a surge in the level THEN the FWH level control would respond AND this surge would cascade through the FWH string!! The FWH level swings started WHEN we installed the new MSR!! The TP oscillations only occur WHEN we have warm circulating water!!

What given information do we need to validate our assumption(s)? FWH operation: What do we know about inlet flows? (extraction steam, cascaded & MSR drainage) Constant unit load results in constant extraction steam flows. Varying inlet flows caused erratic FWH levels due to cascaded drainage from one FWH to the next. Varying flows from the MSR’s can occur due to drain tank level control or some other anomaly in the MSR.

What given information do we need to validate our assumption(s)? MSR operation: What do we know about varying flows from the MSR’s flows? MSR drain tank level control was stable. MSR Separator drainage flow is constant. The remaining path is the flow through the 4th pass manual drain valve!!

What given information do we need to validate our assumption(s)? MSR operation: How do we verify if the drain flow is stable and remembering that the problem of FWH level alarms started WHEN we installed the new MSR’s!! Answer-We need to verify if there is condensate slugging due to improper manufacturing, installation or commissioning!!

What given information do we need to validate our assumption(s)? 1. At full power checking manufacturing deficiencies can not be performed and TEI had a good history. 2. Installation appeared acceptable. 3. Verify if commissioning was properly performed!! Reviewed the post mod testing and it revealed that the manufacturer’s protocol (ASME PTC 12.4) was not followed 100%.

What given information do we need to validate our assumption(s)? How do we validate that the performance of the MSR satisfies the manufacturer’s protocol (ASME PTC 14.6)? Ans. We run the test to gather the data only to validate our assumption(s)!!

What given information do we need to validate our assumption(s)? What was outcome of the performance of the manufacturer’s protocol (ASME PTC 12.4)? Ans. We did NOT satisfy the manufacturer’s protocol !! The protocol required achieving 10 to 20 F of sub-cooling and we had 0 F of sub-cooling!! >>>> CONDENSATE SLUGGING!!

What given information do we need to validate our assumption(s)? The manufacturer’s protocol was implemented to achieve 10 to 20 F of sub-cooling along with throttling main steam flow due to the MSR being 20% oversized for EPU. Results: We achieved F of sub-cooling!! >>>> No MORE CONDENSATE SLUGGING!!

What given information do we need to validate our assumption(s)? The patient is still in need of help! During periods of warm circulating water, >70F, thermal power (TP) oscillations became excessive. This condition can be caused by a multitude of problems!!

What given information do we need to validate our assumption(s)? During periods of warm circulating water, >70F, thermal power (TP) oscillations became excessive. This condition can be narrowed down by virtue of being dependent upon warm circulating water and the affect upon MFP Turbine operation!!

What given information do we need to validate our assumption(s)? MFP Turbine Operation: What do we know about the effects of warm circulating water? Turbine vacuum increases. In turn-To maintain the same horsepower requirements necessitates an increase in steam flow. (Remember that thermodynamic nonsense > Q = ṁ x {hsteam in – hsteam out})

What given information do we need to validate our assumption(s)? MFP Turbine Operation: What do we know about the effects of increased in steam flow? Ans. - The turbine admission/inlet valves must open further.

What given information do we need to validate our assumption(s)? MFP Turbine Operation: Is there adequate turbine admission/inlet valve available? Ans. – With the turbine admission/inlet valves open further there is very little pressure drop available!! Then the admission/inlet valves will modulate MUCH more than before and in turn cause increased oscillations in the feedwater flow through the MFP which directly impacts TP!!

What given information do we need to validate our assumption(s)? MFP Turbine Operation: With the turbine admission/inlet valves open further is an alternate source of high pressure steam available to increase pressure drop?? Ans. Yes but the alternate source of high pressure steam was designed to automatically open at 80% admission /inlet valve position and the flow oscillations become unacceptable above 65% admission/inlet valves position!! Solution: Decrease the setpoint that the alternate source of high pressure steam is opened automatically. This provides for more stable admission /inlet valve operation and avoids increased oscillations in the feedwater flow through the MFP which directly impacts TP!!

Outcome of this effort was completed in September of 2012. FWH levels continue to be stable as is evident by the LACK of the multitude of alarms that were previously experienced. MFP Turbine Operation has been stabilized with: A setpoint change that the alternate source of high pressure steam is opened. Procedural guidance has been provided to open the alternate source of steam at 60%. This threshold anticipates the potential for increased oscillations in the feedwater flow through the MFP which directly impacts TP. This change for Operations was a culture change that was initially slow to implement by Operations but has proven successful.

QUESTIONS ?

Unit 2 experienced a manual SCRAM 7/28/13 due to a low suction pressure trip of a MFP. The following precursors were in place prior to the manual SCRAM: There was an imbalance of #6-#5-#4 FWH drainage flows between the A and B strings by 10%. The dump valve for the #4A FWH was manually open 20% to the condenser. The East MFP Turbine has a Servo Positioning Controller (SPC) that was suspect. The East MFP Turbine was in Speed Control only and not in DP Control (load following). Troubleshooting regarding the #4B FWH Level control was not investigated. The supply steam MOV to the MSR was open 7% and the AOV was open 100%

The initiating event/failure was a failure of the pneumatic line that supplied the open signal to the AOV that provides main steam to the MSR. The following are the chronological events: The AOV failed close disrupting most of steam flow to the MSR (MOV was still open 7%). This steam flow is 50% of the condensate mass flow into the #6 FWH. Received a high level alarm in the MSR drain tank due to a lack of pressure to convey the drainage to the #6 FWH. This disruption in condensate flow cascaded through to the #5 and finally to the #4 FWH which caused excessive level oscillations. (The loss of drain flow was 25% by mass)

Due to the dump valve being open to the condenser the drain cooler section in the #4A FWH emptied and cause the respective Heater Drain Pump (HDP) to trip. The spare Hotwell and Condensate Booster Pumps automatically started due to the decreased MFP suction pressure as a result of a HDP trip. It was not immediately realized but when the first HDP tripped the discharge check valve failed open causing additional condensate to be diverted away from the MFP suction to the condenser via the open dump valve.

The 4B FWH has a significant amount of tubes plugged in the sub-cooler which contributes to poor operation during excessive levels oscillations. Further exacerbating the level control is the length of the pneumatic control tubing runs. Eventually the oscillations were of such a magnitude to cause the respective HDP to trip. Since the condensate from both 4A/B FWH is diverted to the condenser along with additional condensate through the failed open HDP check valve the automatic starting of spare Hotwell and Condensate Booster Pumps should provide the motive force to maintain the MFP suction pressure above the MFP suction pressure trip setpoint of 180 psi. The decreased MFP suction pressure should have caused the BYPASS control valve to modulate open to maintain 240 psi to avoid the MFP suction pressure trip of 180 psi. The BYPASS provides an additional path around the four FWH for all the condensate to the maintain adequate MFP suction pressure.

MFP Suction Transmitters (Actual-180 psi) Bypass Controller (Actual psi) MFP Suction Strainer P P

The BYPASS controller setpoint was at 188 psi INSTEAD of 240 psi. Due to the 22 psi difference in the location of the control devices due to the hydraulic differences the BYPASS controller NEVER opened because the BYPASS could not detect the MFP suction pressure properly. The West MFP Turbine was in DP Control (load following) and was increasing in speed to compensate for the East MFP Turbine in Speed Control (due to low MFP suction pressure and in turn caused the steam generators to decrease). The West MFP Turbine eventually tripped due to low suction pressure and the unit was manually SCRAM’ed by Operations prior to the unit automatically tripping the unit on low steam generator level.

There were significant barriers that failed which contributed to this Manual SCRAM. Multiple precursors to this event due to maintenance of the equipment. Setpoint of the BYPASS controller. Lack of rigor regarding the understanding of compensating for dynamic hydraulic differences when installing instrumentation. Lack of understanding that FWH sub-cooler degradation will negatively influence stable level control.

QUESTIONS ?

Cook Nuclear Power Plant

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