NEISO: Low Wholesale Electric Prices In June?

So far this summer the wholesale electric prices spikes have remained rather mild. Price spikes have been amazingly docile this summer...

Why, because the politicians are breathing down their throats? 

Wholesale electricity prices and demand in New England

Wednesday, July 15, 2015 at 2:20PM

Wholesale power and natural gas prices set new records in June, dropping to lowest monthly levels in 12 years

Mild weather, low demand, and the lowest average natural gas price since 2003 brought June’s wholesale power price to under $20 per megawatt-hour, by far the lowest monthly price in the 12 years New England has had competitive power markets in their current form. June’s average real-time electric energy price of $19.61/MWh was nearly half the June 2014 average price of $37.92/MWh and nearly 23% lower than the previous record-low average monthly price of $25.39/MWh, recorded during March 2012.

Matthew White, chief economist at ISO New England, said the explanation for such low power prices is simple. “It’s supply and demand. With June’s mild weather, demand for natural gas and electricity were both low, and the pipeline capacity was available to deliver a plentiful supply of exceptionally low-priced natural gas to generators in New England. Seasonal demand for natural gas has abated, and New England is able to access that low-cost supply because we aren’t seeing winter’s recurring pipeline constraints.

“But the swing in prices over just five months, going from the third-highest power price during February to the lowest in June, underscores the price volatility attributable to pipeline infrastructure constraints,” White added. “During February’s record cold, demand for natural gas was so high that the pipelines into New England—which haven’t expanded at the same pace as natural gas demand growth—were running at or near capacity. When natural gas demand is so high and the supply available to generators is limited, the price for natural gas delivered to New England rises dramatically—and so does the price for the electricity made from it.”

During February, the average wholesale price of power was $126.70/MWh, while the average price of natural gas was $17.27 per million British thermal units (MMBtu) **, the fourth-highest monthly level since 2003.
The US Energy Information Administration noted in its July 9, 2015, Natural Gas Weekly Update, entitled “Northeastern trading points set record low prices”, that natural gas prices at the Algonquin delivery point in Boston fell to an historic daily low of $1.19/MMBtu on June 5 before breaking that record with new daily low of 82 cents on July 2.
June highlights:

• Lowest average wholesale electric energy price since March 2003
  • June 2015: $19.61 per megawatt-hour (MWh)*
  • March 2012: $25.39/MWh
  • April 2012: $25.41/MWh
  • April 2015: $25.88/MWh
  • May 2015: $26.12/MWh

• Lowest average monthly natural gas price since March 2003
  • June 2015: $1.68/MMBtu
  • May 2015: $1.85/MMBtu
  • April 2012: $2.39/MMBtu
  • May 2012: $2.63/MMBtu
  • August 2014: $2.64/MMBtu

• Second-lowest energy consumption during any June since 2003
  • June 2009: 9,960 gigawatt-hours (GWh)
  • June 2015: 10,146 GWh
  • June 2002: 10,317 GWh

• Third-lowest average June temperature since 2003
  • June 2009: 63.1° Fahrenheit
  • June 2003: 65.1° F
  • June 2015: 65.2° F

Drivers of Wholesale Electricity Prices

In general, the two main drivers of wholesale electricity prices in New England are the cost of fuel used to produce electricity and consumer demand.

Power Plant Fuel: Fuel is typically one of the major input costs in producing electricity. Natural gas is the predominant fuel in New England, used to generate nearly half of the power produced in the region, and natural gas-fired power plants usually set the price of wholesale electricity in the region. As a result, average wholesale electricity prices are closely linked to natural gas prices.

The average natural gas price during June dropped to $1.68/MMBtu at the Algonquin pipeline delivery point in Massachusetts, a decline of nearly 60% from the $4.07/MMBtu natural gas average price during June a year ago. The June 2015 price was also nearly 10% lower than the May 2015 average price of $1.85/MMBtu, which briefly held the record for the lowest monthly average natural gas price in New England since 2003.

Electricity Demand: Demand is driven primarily by weather as well as economic factors. The average temperature was 65.2° Fahrenheit in New England, the third-lowest June temperature recorded region-wide since 2003, while the dewpoint, a measure of humidity, came in at 54.2°, about the same as the 54.5° in June 2014. The mild weather and the effects of energy-efficiency measures dropped energy usage to 10,146 GWh, the third-lowest level of energy consumption during any June since 2003, and about 2.5% lower  than consumption during June 2014 when the average temperature was about 67.8°F. The impact of weather is reflected in heating and cooling degree days***. During June, the region saw 26.2 cooling degree days (CDD), a slight decline from  the 27.5 CDD recorded during June 2014.

Peak demand for the month hit 20,895 MW on June 23 during the hour from 3 to 4 p.m.,  when the average temperature in New England was 84°F and the dewpoint was 69°. The June 2015 peak was down 1.7% from the June 2014 peak of 21,263 MW, set during the hour from 4 to 5 p.m. on June 30 when the temperature was 85°F and the dewpoint was 61°. The all-time peak demand in New England was 28,130 MW, recorded during an August 2006 heat wave, when the temperature was 94°F and the dewpoint was 74°. Peak demand is driven by weather, which drives the use of heating and air conditioning equipment. Air conditioning use is far more widespread than electric heating in New England, so weather tends to have a relatively greater impact on the summer peak than the winter peak.

Fuel Mix: The mix of resources used in any given time period depends on price and availability, as well as unit commitments made to ensure system stability. Natural gas-fired and nuclear power plants produced most of the 9,176 GWh of electric energy generated within New England during June, at 47% and 31%, respectively. Hydroelectric resources in New England generated 10%. Renewable resources generated 8% of the energy produced within New England, including 5.6% from wood and refuse, 1.4% from wind and 0.5% from solar resources. Coal units generated 0.05% and oil-fired resources produced 0.02% of the energy generated within New England. Dual-fuel units, which generally are capable of burning natural gas or oil and typically use the less expensive fuel, generated about 4%. The region also received net imports of about 1,124 GWh of electricity from neighboring regions.

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June 2015 and Percent Change from June 2014 and May 2015	June 2015	Change from June 2014	Change from May 2015
Average Real-Time Electricity Price ($/megawatt-hour**)	$19.61	-48.3%	-24.9%
Average Natural Gas Price ($/MMBtu***)	$1.68	-58.7%	-9.4%
Peak Demand	20,895 MW	-1.7%	+7.1%
Total Electricity Use	10,146 GWh	-2.46%	+4.5%
Weather-Normalized Use****	10,456 GWh	-2.7%	+9.9%

  * One megawatt (MW) of electricity can serve about 1,000 average homes in New England. A megawatt-hour (MWh) of electricity can serve about 1,000 homes for one hour. One gigawatt-hour (GWh) can serve about 1 million homes for one hour. ** A British thermal unit (Btu) is used to describe the heat value of fuels, providing a uniform standard for comparing different fuels. One million British thermal units are shown as MMBtu. *** A degree day is a measure of heating or cooling. A zero degree day occurs when no heating or cooling is required; as temperatures drop, more heating days are recorded, when temperatures rise, more cooling days are recorded. The base point for measuring degree days is 65 degrees; each degree of a day’s mean temperature that is above 65 degrees is counted as one cooling degree day. A day’s mean temperature of 90 degrees equals 25 cooling degree days.  **** Weather-normalized demand indicates how much electricity would have been consumed if the weather had been the same as the average weather over the last 20 years

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River Bend Talking Points to Region IV Alligations

RIVER BEND STATION – NRC SPECIAL INSPECTION REPORT 05000458/2015009; PRELIMINARY WHITE FIND

http://steamshovel2002.blogspot.com/2015/07/river-bend-talking-points-to-region-iv.html

River Bend Talking Points to Region IV Allegations

Reactor high level: Issues of not putting corrective action program. Hiding issues from NRC.  A fleet wide tactic with Entergy.

Request a reset of River Bends simulator and simulator fidelity of all Entergy simulator?

“During power ascension following startup, RFP B did not start. The licensee re-racked its associated circuit breaker and successfully started RFP B.”

“The team identified an apparent violation of 10 CFR 55.46(c)(1), “Plant-Referenced Simulators,” for the licensee’s failure to maintain the simulator so it would demonstrate expected plant response to operator input and to normal, transient, and accident conditions to which the simulator has been designed to respond.”

Pilgrim simulator problems and River Bend within a months of each other only discovered in a troublesome plant trip?

Another work around tripping MFP to control level because of leaking FRVs…

*“On several occasions, the team noted that the licensee chose the expedient solution rather than complete an evaluation to determine that corrective actions resolved the deficient condition.”

“Other examples included the licensee’s choice to have operations personnel rack in and out breakers (MFP), and have maintenance personnel manually operate a limit switch, on the makeup and start logic for the RFP C minimum flow valve, when the RFP did not start.”

NRC widely allow a plant to spin out of control in a complex system, eventually leads to a ANO event (dropped stator and flooding problems).

“Only four minutes elapsed from the time of the scram until the time the Level 8 (high) reactor water level isolation signal was reached. Consequently, operations personnel did not have sufficient time to gain control and stabilize reactor vessel level in the required band.”

“However, operations personnel stated that the plant did not respond in a manner consistent with their simulator training.”

*However, operations personnel stated that the plant did not respond in a manner consistent with their simulator training.”

*It looks like operations works for everyone else instead of everyone else working for operations.” Engineering centric instead of operations centric.”  

HB Robinson breaker event:  “The team identified that the licensee’s maintenance programs for Division I, II, III, and non-safety 4160 V and 13.8 kV breakers installed in the plant may not meet the standards recommended by the vendor, corporate, or Electric Power Research Institute (EPRI) guidelines.”

Why so many issues with faulty cards: SFRV in manual and RPS?

The operations staff is amazingly adaptive with not approved work-arounds and degraded components.

If looks to me the staff went to the SFRV because the FRVs were grossly leaking…

“In reviewing the feedwater system data from the December 24, 2014, scram, the licensee estimated 500,000 lbm/hr leaked past the closed FRVs. This represents approximately 3 percent of the full-power feedwater flow and significantly exceeds the design specification for leakage of 135,000-150,000 lbm/hr.

The licensee identified excessive leakage past the FRVs during testing in 1986. At the time of inspection, the licensee could not produce any corrective actions taken to identify or correct leakage past the FRVs. Further, the licensee had not quantified the amount of leakage past the FRVs prior to the December 24, 2014, event and NRC Special Inspection.”

So why isn’t this A COVER-UP: “The team reviewed the history of Level 8 (high) RFP trips and noted that similar issues of concern were raised by the NRC in 2012. Specifically, a Supplemental Inspection, performed in 2012, for a White performance indicator associated with reactor scrams with complications documented the failure to recognize a Level 8 (high) trip as an adverse condition and enter it into the corrective action program. This non-cited violation was documented in NRC Inspection Report 05000458/2012012.”

“The team identified an apparent violation of 10 CFR 55.46(c)(1), “Plant- Referenced Simulators,” for the licensee’s failure to maintain the simulator so it would demonstrate expected plant response to operator input and to normal, transient, and accident conditions to which the simulator has been designed to respond. As of January 30, 2015, the licensee failed to maintain the simulator consistent with actual plant response for normal and transient conditions related to feedwater flows, alarm response, and behavior of the SFRV controller. As a result, operations personnel were challenged in their control of the plant during a reactor scram that occurred on

December 25, 2014.”

“During an investigation into the report at the OSRC (Onsite Safety Review Committee) for the SCRAM on December 25, 2014, that feed regulating valve leakage (FRV) contributed to the Level 8 received reactor vessel, it was determined by analysis that there is sufficient evidence that leakage by the Feedwater Regulating Valves presents a significant challenge to Operations during a scram event.”

Is a single issue, or is it really an intentional or a inability to keep the simulator accurate?  

Work arounds:

• Work Order WO-RBS-00404323: RFP B supply breaker repetitive failures to close potentially reduces the number of feedwater pumps available to operations personnel during a transient following reactor pressure vessel water Level 8 (high). Operations personnel would rack out and then rack the breaker back in until the breaker would function properly. This work order was initiated on February 3, 2015, following discussions with the NRC inspection team.

how long did this go on?

• Work Order WO-RBS-00396449: RFP C minimum flow valve does not stroke fully open which prevents starting the C feed pump. Maintenance personnel would manually operate a limit switch on the valve to make up the start logic for the RFP. This work order was initiated on October 10, 2014.

• Work Order WO-RBS-00346642: leakage past FRVs when closed complicated post-scram reactor water level control. Operations personnel proceduralized the closure of the main feedwater isolation valves to stop the effect of the leakage.

This work order was initiated on March 27, 2013.

Very Influential Exelon Ex Offical Says: Dump The Six Dog Nuclear Plants

Former Exelon CEO Rowe: Shutting down struggling nukes is 'the proper market-driven answer'

Those worthless egg sucking economic dog nuclear plants...

Energy Wire: Why are certain nuclear plants having trouble competing right now?

Rowe: And in a world that's driven by unfriendly market prices and unfriendly public policy, you shut them down.

Rowe: If I were there, I think I'd have shut the New Jersey plant [Oyster Creek] down first

The six plants facing the preverbal electric chair...

Clinton one plant

Quad Cities two plants

Byron two Plants

Oyster Creek one plant

I think there will be an intensification of lower energy prices here is the USA...Iran jump starting their petroleum industry (good) and issues with growth in china and their stock market problems.

We are getting ready to lose Texas.

What the hell going to go on when American fracting comes to the Iranian oil fields. 


EnergyWire: Monday, July 27, 2015

Energywire: So, what's the right policy solution to keep existing nuclear viable, such as the three Exelon plants in Illinois that are said to be losing money?

EnergyWire: Why are certain nuclear plants having trouble competing right now? Is it just natural gas and wind?

Rowe: Yeah, wind and gas and energy efficiency. The combination of the recession and energy efficiency -- and no one knows the percentages -- has caused demand for electricity to stay below '07 levels through today and probably for another seven or eight years in the Northeast. In a supply-and-demand market, reduced demand hurts. That's the first factor. The second factor is much of the time a nuclear plant is competing against natural gas in the market, so cheap gas really hurts. The third factor is the subsidized wind -- which you really pay for, and it runs whether it's economic or not -- that hurts. The wind really annoys utility people because it runs at night. At night, you have more than enough electricity, and wind just ruins the price.

EW: It has been said that preserving existing nuclear plants is key to helping the U.S. achieve climate goals. So, what's the right policy solution to keep existing nuclear viable, such as the three Exelon plants in Illinois that are said to be losing money?

Rowe: I'm living in a fairy world because I don't have the numbers and I'm not responsible for them anymore. But in my opinion, you shut those three plants down. You say they have become uneconomic just like some old coal plants are uneconomic. And in a world that's driven by unfriendly market prices and unfriendly public policy, you shut them down. That's what I think the answer is, which is a setback for our low-carbon goals and a setback for the high-paying industrial jobs that people want to keep. But it is the proper market-driven answer.

EW: That would be unpopular with your former colleagues.

Rowe: I don't know. I can ask, but I don't want to ask. They have to figure this out for themselves. I love nuclear power plants. For [current Exelon CEO] Chris Crane, it's his life. He would probably go further to keep a plant running than I would go. I don't believe there's anything divine about markets, but I believe they're pretty important. Chris has only seen the sour side of the markets. I don't believe you can run a good utility letting public policy push you toward something but not pay you for it.

In some ways, I believe the only way a utility has credibility in saying that something isn't making any money is if it's actually willing to shut it down. If I were there, I think I'd have shut the New Jersey plant [Oyster Creek] down first. It's the oldest, it's the smallest, and it would have given credibility to what Exelon is saying about the other four. Nuclear power plants have been shut down before around the country. Am I saying that's the desirable answer? No, I'm not. What I'm saying is if the real reason to keep them running is a public policy reason, then the public has to help bear the cost of doing that…

Callaway Plume In Contaiment: Is This How the Nucler Industry Ends in the USA?

Everyone thinks it will end with mass radiation causalities...I say it will more end in a event like this?

Power Reactor	Event Number: 51253
Facility: CALLAWAY Region: 4 State: MO Unit: [1] [ ] [ ] RX Type: [1] W-4-LP NRC Notified By: WALTER GRUER HQ OPS Officer: JEFF HERRERA	Notification Date: 07/23/2015 Notification Time: 04:21 [ET] Event Date: 07/23/2015 Event Time: 01:15 [CDT] Last Update Date: 07/23/2015
Emergency Class: NON EMERGENCY 10 CFR Section: 50.72(b)(2)(i) - PLANT S/D REQD BY TS	Person (Organization): HEATHER GEPFORD (R4DO) SCOTT MORRIS (NRR) JEFFERY GRANT (IRD)

Unit	SCRAM Code	RX CRIT	Initial PWR	Initial RX Mode	Current PWR	Current RX Mode
1	N	Y	100	Power Operation	0	Cold Shutdown

Event Text

INITIATION OF PLANT SHUTDOWN DUE TO RCS LEAKAGE "On July 23, 2015 at 0115 [CDT], Callaway Plant initiated a shutdown required by Technical Specifications (TS). At 2139 [CDT] on July 22, 2015, TS 3.4.13 Condition A was entered due to unidentified RCS leakage being in excess of the 1 gpm TS limit. The leak was indicated by an increase in containment radiation readings, increasing sump levels, and decreasing levels in the Volume Control tank (VCT). "A containment entry identified a steam plume; due to personnel safety the exact location of the leak inside the containment building could not be determined. "At this time radiation levels inside [the] containment are stable and slightly above normal. There have been no releases from the plant above normal levels. "The [NRC] Senior Resident Inspector was notified."

Callaway nuclear plant shut down after 'non-emergency' leak

JIM SALTER, Associated Press

Originally published July 23, 2015 at 1:19 p.m., updated July 23, 2015 at 4:36 p.m.

The Ameren Corp. nuclear power plant in central Missouri was shut down for the second time in eight months Thursday after a "non-emergency" leak was found in the reaction control system.
The shutdown occurred at 1:15 a.m. at the plant near Fulton. Jeff Trammel, a spokesman for St. Louis-based Ameren, called it a "minor steam leak." He said no one was hurt and there was no risk to the public.
Ameren officials are investigating the cause. Trammel said it was unclear when the plant would restart.
The U.S. Nuclear Regulatory Commission was advised of the leak and inspectors are at the plant, spokeswoman Lara Uselding said.
"The plant is in a safe shutdown condition and there is no risk to public health and safety or the environment," Uselding said.
The Callaway plant also shut down in December, due to an electrical equipment failure. That shutdown was the first in more than two years. No one was hurt and the public was not threatened in that leak, Ameren said.
An NRC report on the latest incident classified it as a "non-emergency." The report said the shutdown was initiated after a reaction control system leak was detected at the plant that sits about 100 miles west of St. Louis.
"A containment entry identified a steam plume; due to personnel safety the exact location of the leak inside the containment building could not be determined," the NRC report said.
The NRC report said radiation levels were "slightly above normal," but stable inside the containment building, and there were no releases from the plant "above normal levels."
Ed Smith of the Missouri Coalition for the Environment said the shutdown raises concerns for the plant, which turned 30 last year.
"As the Callaway nuclear reactor ages, I think we're going to see more incidents like this," Smith said.
Ameren, based in St. Louis, provides electrical power to customers in Missouri and Illinois. Trammel said customers will see no impact from the shutdown. The Callaway plant generates about 20 percent of electricity for Ameren's 1.2 million Missouri customers.
Earlier coverage:
Ameren Missouri's Callaway Nuclear plant was shut down today by a "minor steam leak."
The company said the incident occurred in the plant's containment area, and "poses no threats to the health and safety of the public or Callaway employees."
Company officials are trying to determine the cause of the problem, which they said "has been contained."
No "return to service date" has been set, but service to customers "has not been affected."
Ameren provides electricity to more than 1 million customers in Central and Eastern Missouri

Why Are Nuclear Plants Having So Many Safety Related HVAC Problem?

July 23

Is excessive HVAC NRC reporting a symptom of too large plant work back log???

July 22:

Bet you most of the HVAC systems were rushed add on systems during troublesome construction and post TMI...

I think the NRC and industry would come back and say...this is where prescriptive regulations got it wrong. There is a insignificant chance these HVAC problems would lead to core damage and a offsite release.

I would say this is where this perspective incentivizes broadly setting up and tolerating safety component degradation and obsolesces.

If we broadly tolerate component degradations in these amazingly complex machines and organizations...then we become much closer to the day when one of these plants runs away from us.

Is there such a thing as boiling frog with priorities metaphor...normalization of deviance?

Is risk perspective numbing us to threats and real risk...
 

The truth is, if the NRC demanded just a few of this plants to shut down over HVAC problems, the industry would update all their problematic HVAC systems. It is common for these guys to fix these problems in a isolated way…instead of thinking holistic it is more efficient with our resources just to buy a new car or buy a new HAVC system.   

The question is if this is an essential safety system, then why is there only one and doing maintenance on it makes it inop.

If this is essential for accident mitigation, why is it taken off line at 100% full power operation, unless the plant has carefully schedule a DBA not to occur while the essential HVAC system is down for repair?"

 July 21:

All 2015 events.

Is it my VY leaking roofs deal…didn’t realize the system had come to end-of-life.

I bet you HVAC problems would be at the bottom of the barrel of maintenance and budgets priority systems.

What do you make big picture and why this is happening...are the issues trending up?

Would having four HVAC systems powered from two independent buses fix it...

Not a complete list: 

###Power Reactor    Event Number: 51103
Facility: CATAWBA
Region: 2 State: SC
Unit: [1] [2] [ ]
RX Type: [1] W-4-LP,[2] W-4-LP
NRC Notified By: THOMAS GARRISON
HQ OPS Officer: JOHN SHOEMAKER    Notification Date: 05/29/2015
Notification Time: 20:17 [ET]
Event Date: 05/29/2015
Event Time: 12:30 [EDT]
Last Update Date: 06/12/2015
Emergency Class: NON EMERGENCY
10 CFR Section:
50.72(b)(3)(xiii) - LOSS COMM/ASMT/RESPONSE
Person (Organization):
KATHLEEN O'DONOHUE (R2DO)

Unit    SCRAM Code    RX CRIT    Initial PWR    Initial RX Mode    Current PWR    Current RX Mode
1    N    Y    100    Power Operation    100    Power Operation
2    N    Y    100    Power Operation    100    Power Operation
Event Text
TECHNICAL SUPPORT CENTER VENTILATION SYSTEM OUT OF SERVICE DUE TO DISCOVERED CONDITION

"This is non-emergency eight hour notification for a loss of Emergency Assessment Capability.

"This event is reportable in accordance with 10 CFR 50.72(b)(3)(xiii) as the discovered condition affects the functionality of an emergency response facility.

"A condition impacting functionality of the TSC [Technical Support Center] Ventilation system was discovered on 05/29/2015 at 1230 [EDT]. The issue involves a loss of cooling capability of the TSC ventilation system due to a failed relay. Maintenance will begin repairs at 0700 [EDT] on 05/30/2015. Estimated time to repair is unknown at this time.

"If an emergency is declared requiring TSC activation during this period, the TSC will be staffed and activated using existing emergency planning procedures unless the TSC becomes uninhabitable due to ambient temperature, radiological, or other conditions. If relocation of the TSC becomes necessary, the Emergency Coordinator will relocate the TSC staff to an alternate location in accordance with applicable site procedures. The Emergency Response Organization team will be notified of the condition and the possible need to relocate during an emergency. This condition does not affect the health and safety of the public or station employees. An update will be provided once the TSC ventilation has been restored to normal operation. The NRC Resident Inspector will be notified."

* * * UPDATE FROM AARON MICHALSKI TO DANIEL MILLS AT 1557 EDT ON 6/12/15 * *

The TSC ventilation system has been returned to service. The licensee will notify the NRC Resident Inspector.

Notified R2DO (Guthrie).

###Power Reactor    Event Number: 51154
Facility: BRAIDWOOD
Region: 3 State: IL
Unit: [1] [2] [ ]
RX Type: [1] W-4-LP,[2] W-4-LP
NRC Notified By: BLAKE BAXTER
HQ OPS Officer: DANIEL MILLS    Notification Date: 06/15/2015
Notification Time: 17:42 [ET]
Event Date: 06/16/2015
Event Time: 07:00 [CDT]
Last Update Date: 06/15/2015
Emergency Class: NON EMERGENCY
10 CFR Section:
50.72(b)(3)(xiii) - LOSS COMM/ASMT/RESPONSE
Person (Organization):
PATTY PELKE (R3DO)

Unit    SCRAM Code    RX CRIT    Initial PWR    Initial RX Mode    Current PWR    Current RX Mode
1    N    Y    100    Power Operation    100    Power Operation
2    N    Y    100    Power Operation    100    Power Operation
Event Text
TSC VENTILATION TO BE REMOVED FROM SERVICE FOR PLANNED MAINTENANCE

"On 6/16/2015, planned preventive maintenance activities [will be] performed on the Braidwood Generating Station Technical Support Center (TSC), Ventilation System. The work will be completed within approximately 48 hours. This activity includes preventative maintenance that requires the TSC ventilation system to be out of service which will render the TSC ventilation system non-functional.

"If an emergency is declared requiring TSC activation during this period, the TSC will be staffed and activated using existing emergency planning procedures unless the TSC becomes uninhabitable due to ambient temperature or other conditions. If relocation of the TSC becomes necessary, the Emergency Director will relocate the TSC staff as necessary.

"This event is reportable per 10 CFR 50.72(b)(3)(xiii) for 'any event that results in a major loss of emergency assessment capability.' The planned maintenance will not be able to restore the TSC condensing unit or ventilation system to service within the facility activation time specified in the emergency plan (1 hour) in the event of an accident. The Emergency Response Organization team has been notified of the maintenance and the possible need to relocate during an emergency.

"The licensee has notified the NRC Resident Inspector."

###Power Reactor    Event Number: 51164
Facility: LASALLE
Region: 3 State: IL
Unit: [1] [2] [ ]
RX Type: [1] GE-5,[2] GE-5
NRC Notified By: TODD CASAGRANDE
HQ OPS Officer: JEFF HERRERA    Notification Date: 06/17/2015
Notification Time: 23:39 [ET]
Event Date: 06/17/2015
Event Time: 18:41 [CDT]
Last Update Date: 06/18/2015
Emergency Class: NON EMERGENCY
10 CFR Section:
50.72(b)(3)(xiii) - LOSS COMM/ASMT/RESPONSE
Person (Organization):
PATTY PELKE (R3DO)

Unit    SCRAM Code    RX CRIT    Initial PWR    Initial RX Mode    Current PWR    Current RX Mode
1    N    Y    100    Power Operation    100    Power Operation
2    N    Y    100    Power Operation    100    Power Operation
Event Text
TECHNICAL SUPPORT CENTER VENTILATION SYSTEM RETURN DAMPER FAILED CLOSED

"On June 17th, 2015 at 1841 CDT, it was determined that the onsite Technical Support Center (TSC) Ventilation System return damper 0VS119Y was failed closed, the failed closed damper affects the TSC Emergency Makeup Train filtration efficiency. There is currently no emergency event in progress requiring TSC staffing. If an emergency is declared and the TSC ERO [Emergency Response Organization] activation is required, the TSC will be staffed and activated unless the TSC becomes uninhabitable due to ambient temperatures, radiological, or other conditions. If relocation of the TSC staff becomes necessary, the Station Emergency Director will relocate the staff to an alternate TSC location in accordance with applicable site procedures.

"The licensee has notified the [NRC] Senior Resident Inspector of the issue."

* * * UPDATE AT 1700 EDT ON 06/18/15 FROM TODD CASAGRANDE TO S. SANDIN * * *

"After repairs were completed, the TSC Ventilation was restored to service at 1650 EDT on 06/18/2015.

"The licensee has notified the NRC Resident Inspector."

Notified R3DO (Pelke).

###Power Reactor    Event Number: 51154
Facility: BRAIDWOOD
Region: 3 State: IL
Unit: [1] [2] [ ]
RX Type: [1] W-4-LP,[2] W-4-LP
NRC Notified By: BLAKE BAXTER
HQ OPS Officer: DANIEL MILLS    Notification Date: 06/15/2015
Notification Time: 17:42 [ET]
Event Date: 06/15/2015
Event Time: 07:00 [CDT]
Last Update Date: 06/18/2015
Emergency Class: NON EMERGENCY
10 CFR Section:
50.72(b)(3)(xiii) - LOSS COMM/ASMT/RESPONSE
Person (Organization):
PATTY PELKE (R3DO)

Unit    SCRAM Code    RX CRIT    Initial PWR    Initial RX Mode    Current PWR    Current RX Mode
1    N    Y    100    Power Operation    100    Power Operation
2    N    Y    100    Power Operation    100    Power Operation
Event Text
TSC VENTILATION TO BE REMOVED FROM SERVICE FOR PLANNED MAINTENANCE

"On 6/16/2015, planned preventive maintenance activities [will be] performed on the Braidwood Generating Station Technical Support Center (TSC), Ventilation System. The work will be completed within approximately 48 hours. This activity includes preventative maintenance that requires the TSC ventilation system to be out of service which will render the TSC ventilation system non-functional.

"If an emergency is declared requiring TSC activation during this period, the TSC will be staffed and activated using existing emergency planning procedures unless the TSC becomes uninhabitable due to ambient temperature or other conditions. If relocation of the TSC becomes necessary, the Emergency Director will relocate the TSC staff as necessary.

"This event is reportable per 10 CFR 50.72(b)(3)(xiii) for 'any event that results in a major loss of emergency assessment capability.' The planned maintenance will not be able to restore the TSC condensing unit or ventilation system to service within the facility activation time specified in the emergency plan (1 hour) in the event of an accident. The Emergency Response Organization team has been notified of the maintenance and the possible need to relocate during an emergency.

"The licensee has notified the NRC Resident Inspector."

* * * UPDATE AT 1102 EDT ON 6/18/15 FROM DAVID KORTGE TO JEFF HERRERA * * *

"Braidwood Generating Station TSC ventilation was restored to available status at 0700 CDT on June 18, 2015.

"The previously reported system preventative maintenance has been completed."

The licensee notified the NRC Resident Inspector.

Notified the R3DO (Pelke).

###Power Reactor    Event Number: 51212
Facility: HARRIS
Region: 2 State: NC
Unit: [1] [ ] [ ]
RX Type: [1] W-3-LP
NRC Notified By: RAYMOND MOORE
HQ OPS Officer: MARK ABRAMOVITZ    Notification Date: 07/08/2015
Notification Time: 17:43 [ET]
Event Date: 07/07/2015
Event Time: 11:05 [EDT]
Last Update Date: 07/08/2015
Emergency Class: NON EMERGENCY
10 CFR Section:
50.72(b)(3)(xiii) - LOSS COMM/ASMT/RESPONSE
Person (Organization):
GERALD MCCOY (R2DO)

Unit    SCRAM Code    RX CRIT    Initial PWR    Initial RX Mode    Current PWR    Current RX Mode
1    N    Y    100    Power Operation    100    Power Operation
Event Text
TECHNICAL SUPPORT CENTER VENTILATION OUT OF SERVICE

"This is a non-emergency eight hour notification for a loss of Emergency Assessment Capability. This event is reportable in accordance with 10 CFR 50.72(b)(3)(xiii) as the discovered condition affects the functionality of an emergency response facility.

"A condition impacting functionality of the TSC Ventilation system was discovered on July 7, 2015 at 11:05 EDT. The issue involved a loss of cooling capability of the TSC Ventilation system due to failed ventilation system components. Maintenance started repairs immediately following the discovery of the component failures and completed repairs to restore functionality of the TSC Ventilation system on July 8, 2015 at 17:07 EDT. On July 8, 2015, at approximately 15:30 EDT, further review of the impact of this equipment failure determined that this condition was reportable as a loss of emergency assessment capability.

"If an emergency were declared requiring TSC activation during the non-functional period, the TSC would have been staffed and activated using existing emergency planning procedures unless the TSC became uninhabitable due to ambient temperature, radiological, or other conditions. If relocation of the TSC became necessary, the Emergency Director would have relocated the TSC staff to an alternate location in accordance with applicable site procedures. The Emergency Response Organization team was notified of the maintenance and the possible need to relocate during an emergency. This condition did not affect the health and safety of the public or station employees. The NRC Resident Inspector has been notified."

###Power Reactor    Event Number: 51213
Facility: LASALLE
Region: 3 State: IL
Unit: [1] [2] [ ]
RX Type: [1] GE-5,[2] GE-5
NRC Notified By: BRADLEY BRUMUND
HQ OPS Officer: VINCE KLCO    Notification Date: 07/08/2015
Notification Time: 21:53 [ET]
Event Date: 07/08/2015
Event Time: 18:37 [CDT]
Last Update Date: 07/08/2015
Emergency Class: NON EMERGENCY
10 CFR Section:
50.72(b)(3)(xiii) - LOSS COMM/ASMT/RESPONSE
Person (Organization):
ANN MARIE STONE (R3DO)

Unit    SCRAM Code    RX CRIT    Initial PWR    Initial RX Mode    Current PWR    Current RX Mode
1    N    Y    100    Power Operation    100    Power Operation
2    N    Y    100    Power Operation    100    Power Operation
Event Text
TECHNICAL SUPPORT CENTER VENTILATION OUT OF SERVICE

"This telephone notification is provided in accordance with Exelon Reportability manual SAF 1.10, 'Major Loss of Emergency Preparedness Capabilities', and 10CFR50.72(b)(3)(xiii).

"On July 8th 2015 at 1837 [CDT], it was determined that the onsite Technical Support Center (TSC) Ventilation System Supply Fan belts had failed, resulting in loss of ventilation for the facility. Repairs were not completed within the time required had the TSC needed to be staffed. There is currently no emergency event in progress requiring TSC staffing. If an emergency is declared and the TSC ERO [Emergency Response Organization] activation is required, the TSC will be staffed and activated unless the TSC becomes uninhabitable due to ambient temperatures, radiological, or other conditions. If relocation of the TSC staff becomes necessary, the Station Emergency Director will relocate the staff to an alternate TSC location in accordance with applicable site procedures.

"The licensee has notified the [NRC] Senior Resident Inspector of the issue."

###Power Reactor    Event Number: 51213
Facility: LASALLE
Region: 3 State: IL
Unit: [1] [2] [ ]
RX Type: [1] GE-5,[2] GE-5
NRC Notified By: BRADLEY BRUMUND
HQ OPS Officer: VINCE KLCO    Notification Date: 07/08/2015
Notification Time: 21:53 [ET]
Event Date: 07/08/2015
Event Time: 18:37 [CDT]
Last Update Date: 07/11/2015
Emergency Class: NON EMERGENCY
10 CFR Section:
50.72(b)(3)(xiii) - LOSS COMM/ASMT/RESPONSE
Person (Organization):
ANN MARIE STONE (R3DO)

Unit    SCRAM Code    RX CRIT    Initial PWR    Initial RX Mode    Current PWR    Current RX Mode
1    N    Y    100    Power Operation    100    Power Operation
2    N    Y    100    Power Operation    100    Power Operation
Event Text
TECHNICAL SUPPORT CENTER VENTILATION OUT OF SERVICE

"This telephone notification is provided in accordance with Exelon Reportability manual SAF 1.10, 'Major Loss of Emergency Preparedness Capabilities', and 10CFR50.72(b)(3)(xiii).

"On July 8th 2015 at 1837 [CDT], it was determined that the onsite Technical Support Center (TSC) Ventilation System Supply Fan belts had failed, resulting in loss of ventilation for the facility. Repairs were not completed within the time required had the TSC needed to be staffed. There is currently no emergency event in progress requiring TSC staffing. If an emergency is declared and the TSC ERO [Emergency Response Organization] activation is required, the TSC will be staffed and activated unless the TSC becomes uninhabitable due to ambient temperatures, radiological, or other conditions. If relocation of the TSC staff becomes necessary, the Station Emergency Director will relocate the staff to an alternate TSC location in accordance with applicable site procedures.

"The licensee has notified the [NRC] Senior Resident Inspector of the issue."

* * * UPDATE FROM TODD CASAGRANDE TO DANIEL MILLS AT 1510 EDT ON 7/11/15 * * *

"After repairs were completed, the TSC Ventilation was restarted on 7/9/15 at 0625 EDT for a maintenance run, the TSC Ventilation was restored to operable status at 1500 EDT on 07/11/2015.

"The licensee has notified the NRC Resident Inspector."

Notified R3DO (Stone).

###Power Reactor    Event Number: 51232
Facility: DRESDEN
Region: 3 State: IL
Unit: [ ] [2] [3]
RX Type: [1] GE-1,[2] GE-3,[3] GE-3
NRC Notified By: PATRICK HAARHOSS
HQ OPS Officer: VINCE KLCO    Notification Date: 07/15/2015
Notification Time: 01:04 [ET]
Event Date: 07/15/2015
Event Time: 00:04 [CDT]
Last Update Date: 07/17/2015
Emergency Class: NON EMERGENCY
10 CFR Section: 
50.72(b)(3)(xiii) - LOSS COMM/ASMT/RESPONSE
Person (Organization): 
STEVE ORTH (R3DO)

Unit    SCRAM Code    RX CRIT    Initial PWR    Initial RX Mode    Current PWR    Current RX Mode
2    N    Y    100    Power Operation    100    Power Operation
3    N    Y    100    Power Operation    100    Power Operation
Event Text
TECHNICAL SUPPORT CENTER OUT OF SERVICE DUE TO PLANNED MAINTENANCE 

"At 0004 [CDT] on Wednesday, July 15, 2015, the Dresden Nuclear Power Station (DNPS) Technical Support Center (TSC) emergency ventilation system will be removed from service for planned maintenance activities. During the maintenance, the TSC Ventilation will be shut down. The TSC air filtration fan and dampers will be non-functional, rendering the TSC HVAC accident mode non-functional. This maintenance is scheduled to minimize out of service time. The planned TSC ventilation outage is scheduled to be completed in approximately 24 hours. 

"Contingency plans are in place so that if an emergency is declared requiring TSC activation during this period, the TSC will be staffed and activated using existing Emergency Planning (EP) procedures and checklists. If radiological or environmental conditions require TSC facility evacuation during ventilation system restoration; the Station Emergency Director will relocate the TSC staff in accordance with station procedures." 

"The NRC Resident Inspector has been notified." 

* * * UPDATE FROM TRAVIS PRELLWITZ TO DONALD NORWOOD AT 1733 EDT ON 7/17/2015 * * * 

"At 1347 CDT on July 17, 2015, Dresden TSC Ventilation was restored. The Dresden TSC Ventilation is Functional at this time. 

"The NRC Resident Inspector has been notified." 

Notified R3DO (Orth).

Safety Valves In Our Nuclear Power Plants Going Wild

Licensee Event Report # 2015-002-01, "Technical Specification Prohibited Condition Caused by Four Main Steam Safety Valves Outside Their As- Found Lift Set Point Test Acceptance Criteria"

Indian Point Unit No. 3

Docket No. 50-286
 

Reference: 1. LER-2015-002-00 submitted by letter NL-15-065 dated April 27, 2015

An extent of condition (EOC) was performed to determine where potential conditions with similar valves and environments could occur. The review determined that EOC round in the failure of MSSV MS-45-4, MS-46-2 and MS-47-4 is restricted to the other 17 MSSVs at unit 3 and the 20 MSSVs at unit 2 due to the valve design. All MSSVs are exposed to high vibrations during their operating cycle during which wear can occur. Previous failures of MSSVs have included wear due to spring skewing and set point…

Why is Entergy having so many problems with Safety Relief Valves and now the Main Steam Safety Valves? The MSSV provide overpressure protection in the main steam lines. 

If I hear fretting or normal main steam line vibrations damaging these valve again I am going to vomit.

Why can’t the engineers design this valves for the duty and conditions of the plant? They just sit there doing nothing for 99.99% of the time.
 

For only three years below, this is shocking. So how have the failure changed in the last decade... is less testing and maintenance behind this.

A review was performed of Licensee Event Reports (LERs) for the past three years for any events reporting TS prohibited conditions due to multiple valve test failures. LER-2011-004 reported two MSSV's outside their as-found lift set point acceptance criteria due to spindle wear and spring skew. LER-2013-001 reported two MSSVs (MS-46-3 and MS-48-3) outside their as-found set point acceptance criteria. The cause of MS-46-3 failure was galling around the circumference of the spindle rod as a result of vibration. MS-48-3 evidenced similar fretting on one side of the spindle consistent with what was found on valve MS-46-3. Failure cause was determined to be due to internal friction caused by foreign material between the guide bearing and spindle. The causes for the previous events reported in LER-2011-004 are similar to this event.

Recent issues with fretting and normal vibration issues with SRVs and MNSSV include the following plants:

Hatch

Oyster Creek (yellow finding)

Dresden
 

Quad Cities
 

Pilgrim

These valves are failing because the vendor can’t control the component dimensional or material conditions in the valves. These are equivalent to the valves that gave us TMI.
  

I am amazed pre-plant testing haven’t picked up the weaknesses of these valves. Pre-plant testing either can't pick up the defect or the testing damages the fragile valves:) 

I am shocked the manufacturers don’t provide completely durable and bullet proof components and valve to these nuclear power plants? Just to be clear, the MSSV come from PWRs and the SRVs comes from BWRs.

You get it, Indian Point don’t trust the safety of their valves, don’t understand the degradation mechanism, talking about “another” valve design…they are testing these valves twice as frequently now because they don't understand the degradation mechanisms.

LER 2011-004-00 plus two other LERs in 10 years...

During the Preventive Maintenance (PM) of both valves, run-out and wear along the radius of the spindles were noted. In a high flow system, the result would be increased wear along the spindle in the form of steps which were found with MS-47-4 and MS-48-4.

It is a runaway train, in defective component these identical problems happen over and over without fixing the problem. These plants are great at churning paperwork...poor a fixing problems so they never show up again.

LER 2009-002-000: Over and over again, half ass fixes for at least 6 years...the runaway degradation occurring unabated at least since 2009. 

Spindle problems, who cares indeterminate and this seems to be the beginning of this problem. What changed before 2009?   

Cause of Event

The apparent cause of the two MSSVs lifting greater than 3% of their nominal setpoint is indeterminate but most likely caused by setpoint drift. MS-45-1 and MS-48-3 were disassembled and inspected and identified to have some scoring on their valve spindles. Assessment with Original Equipment Manufacturer (OEM) could not directly relate the indications discovered on the valves' spindles to the As-Found test results

   

Fort Calhoun Shutdown Again

Sounds like a reactor coolant pump seal...

Three Stage Safety Valves No Longer In Hatch or Pilgrim

Three stage Safety Valves No Longer in Hatch or Pilgrim

As I said, I call the three stage INOP because there was an active defect in the valve and there was no understanding with their failure mechanism. This is called being conservative.   

* * * UPDATE FROM JOHN DeBONIS (VIA EMAIL) TO STEVEN VITTO AT 1256 EDT ON 6/30/15 ***

Curtiss-Wright provided an update to state their root cause analysis findings and corrective actions. Corrective actions are estimated to be completed within 12 months.

"The following plants were supplied 0867F MS-SRVs:

Pilgrim (Model 09J-001) Quantity Shipped = 8

FitzPatrick (Model 09H-001) Quantity Shipped = 4, Quantity on order= 8

Hatch 1 and 2 (Model 09G-001) Quantity Shipped = 24, Quantity on order= 12

"The following plants will be supplied 0867F MS-SRVs:

Hope Creek (Models 14J-001, 14J-002) Quantity on order = 7

"Valves Currently Installed

 

"Target Rock recommends valves currently installed be inspected to ensure the main piston shoulder has contact with the main disc stem shoulder. These inspections should be scheduled based on plant-specific indications of the potential for fretting. These inspections can be performed by removing the base assembly from the main body and physically measuring for shoulder-to-shoulder contact.

"Should you have any questions regarding this matter, please contact Michael Cinque, Director of Program Management at (631 ) 293-3800."

Notified NRR Part 21 Group (via email), R1 DO (Dimitriadis), and R2DO (Suggs).

Junk Hatch plant Target Rock Three Stage Safety Valves

Three take homes.

1) they changed out the 2 stage for three stage...the problems only got worst.

• 2011: LER 2-2011-002, identified multiple SRV setpoint drift for 8 of the 11 SRVs. Corrective actions included replacement of the 2-stage SRVs with 3-stage SRVs during the Unit 2 Spring 2011 refueling outage which was considered at that time to be the long term fix for this corrosion bonding issue.

It sounds like they yanked out the three stage with this below eight failure. So why didn't Pilgrim take out their reliefs early like Hatch???

• 2012 with three stage: LER 1-2012-004, identified multiple SRV setpoint drift for 8 of the 11 SRVs

• 2013:  LER 1-2014-003, identified multiple SRV setpoint drifts for 5 of the 11 two-stage SRVs installed on Unit 1.

• LER 1-2014-003, identified multiple SRV setpoint drifts for 5 of the 11 two-stage SRVs installed on Unit 1. The two-stage SRVs with platinum-coated pilot discs were

• 2015: 2 of 11

2) We have no idea of the magnitude of trhe leakage.

3) Hatch has problems with steam line vibration damaging these valves. 

4) We know this state is totally inaccurate: "3-stage SRVs typically do not exhibit set point drift and the modified pilot reduces instances of vibration induced spurious openings and leak-by." 

5) I don't think you ever can trust the public disclosure dance between a vendor and a licensee.  

I believe for each of these outside tech spec lift inaccuracies, if the plant would have known it...they would have been required to shutdown.
  
JUL 10 2015

Safety Relief Valves As Found Settings Resulted in Not Meeting Tech Spec 

Surveillance Criteria

On May 11, 2015 at approximately 0923, Unit 2 was at 1 00 percent rated thermal power (RTP) when the "as found" testing results of the 2-stage main steam safety relief valves (SRVs) were received which indicated that two of eleven of the Unit 2 SRVs had experienced a setpoint drift during the previous operating cycle which resulted in their failure to meet the Technical Specification (TS) opening setpoint of 1150 +1- 34.5 psig percent as required by TS Surveillance Requirement (SR) 3.4.3.1.

The root cause of the SRV setpoint drift is attributed to corrosion-induced bonding between the pilot disc and seating surfaces. This conclusion is based on previous root cause analyses and the repetitive nature of this condition at Hatch and within the BWR industry. All 2-stage SRVs with platinum coated pilot seats were removed from Unit 2 during the 2015 refueling outage and replaced with 3-stage SRVs with amodified pilot. 3-stage SRVs typically do not exhibit set point drift and the modified pilot reduces instances of vibration induced spurious openings and leak-by.

A 3-stage SRV with a similar modified pilot was installed on Unit 2 during the ·2013 refueling outage. Based upon "as-found" testing results, it was seen that pressure lift setpoints were maintained during plant operation.

DESCRIPTION OF EVENT

On May 11 2015, at approximately 0923, with Unit 2 at 100 percent rated thermal power (RTP), "as-found" testing of the 2-stage main steam safety relief valves (SRVs) (EllS Code RV) showed that two of the ten main steam SRVs that were tested had experienced a drift in pressure lift setpoint during the previous operating cycle such that the allowable technical specification {TS) surveillance requirement (SA) 3.4.3.1 limit of 1150 +1- 34.5 (+/- 3%) psig had been exceeded. Below is a table illustrating the as found testing results of Unit 2 SRVs that were removed from service during the Spring 2015 refueling outage and replaced with 3-stage SRVs

.

MPL Pilot Serial No. Lift Pressure Percent Drift

2B21-F013B 1006 1155 0.40%

2B21-F013C 1231 1172 1.90%

2B21-F013D 303 1184 3.00%

2B21-F013E 315 1210 5.20%

2B21-F013F 1189 1179 2.50%

2B21-F013G 302 1174 2.10%

2B21-F013H 1230 1190 3.50%

2B21-F013K 1229 1164 1.20%

2B21-F013L 1228 1163 1.10%

2B21-F013M 1008 1179 2.50%

The 2-stage SRVs that were installed on Unit 2 during the previous cycle (Cycle 23) utilized platinum coated pilot discs. The 3-stage SRVs currently installed on Unit 2 have a modified pilot that helps reduce the possibility of inadvertent lift and leak by due to system vibration. The one 3-stage SRV that was installed on Unit 2 during Cycle 23 was recently successfully tested and found to be within the allowable TS SA pressure lift setpoint limit of 1150 +1- 34.5 (+/- 3%) psig.

CAUSE OF EVENT 

The root cause of the SRV setpoint drift is attributed to corrosion-induced bonding between the pilot disc and its seating surface. This conclusion is based on previous root cause analyses and the repetitive nature of this condition at Plant Hatch and in the industry. In General Electric (GE) Service Information Letter (SIL) 196, Supplement 16, GE determined that condensation of steam in the pilot chamber of Target Rock 2-stage SRVs can cause oxygen and hydrogen dissolved in the steam to accumulate. As steam condenses in the relatively stagnant pilot chamber, the dissolved gases are released. In a volume such as the pilot chamber which is normally at approximately a 1000 psig pressure and a temperature of 545 degrees F, the total pressure consists primarily of water vapor partial pressure because 544.6 degrees F is the saturation temperature at 1000 psi g. This wet, hot, high-oxygen atmosphere can be very corrosive and can increase the likelihood of corrosion-induced bonding of the pilot disk to its seat. It was also noted that proper insulation minimizes the accumulation rate of non-condensable gases and the steady-state oxygen partial pressure. Despite improvements made in maintaining the integrity of insulation for the previously installed 2-stage SRVs and installing new platinum coated pilots, the corrosion-induced bonding continued to occur as evidenced by the test results from this most recent outage.

REPORTABILITY ANALYSIS AND SAFETY ASSESSMENT 

This event is reportable in accordance with 10 CFR 50.73(a)(2)(i)(B) because a condition occurred that is prohibited by TS Surveillance Requirement (SR) 3.4.3.1. Specifically, an example of multiple test failures is given in NUREG-1022, Revision 3, "Event Reporting Guidelines 10 CFR 50.72 and 50.73" which describes the sequential testing of safety valves. This example notes that "Sometimes multiple valves are found to lift with set points outside of technical specification limits."

NUREG-1022 further states in the example that "discrepancies found in TS surveillance tests should be assumed to occur at the time of the test unless there is firm evidence, based on a review of relevant information (e.g., the equipment history and the cause of failure), to indicate that the discrepancy occurred earlier. However, the existence of similar discrepancies in multiple valves is an indication that the discrepancies may well have arisen over a period of time and the failure mode should be evaluated to make this determination." Based on this guidance and the fact that the development of the corrosion occurred over a period of time of plant operation, the determination was made that this "as found" condition is reportable under the reporting requirements of 10 CFR 50.73(a)(2)(i)(B). There are eleven SRVs located on the four main steam lines within the drywell in between the reactor pressure vessel (RPV) (EllS Code RPV) and the inboard main steam isolation valves (MSIVs) (EllS Code ISV). These SRVs are required to be operable during Modes 1, 2, and 3 to limit the peak pressure in the nuclear system such that it will not exceed the applicable ASME Boiler and Pressure Vessel Code Limits for the reactor coolant pressure boundary. The SRVs are tested in accordance with TS surveillance requirement 3.4.3.1 in which the valves are tested as directed by the In-Service Testing Program to verify lift set points are within their specified limits to confirm they would perform their required safety function of overpressure protection. The SRVs must accommodate the most severe pressurization transient which, for the purposes of demonstrating compliance with the ASME Code Limit of 1375 psig peak vessel pressure, has been defined by an event involving the closure of all MSIVs with a failure of the direct reactor protection system trip from the MSIV position switches with the reactor ultimately shutting down as the result of a high neutron flux trip (a scenario designated as MSIVF).

The results from this MSIVF event analysis was performed by the Nuclear Fuels Department in order to bound the "as-found" results of the U2 Cycle 21 2-stage SRVs pressure setpoint drift. The results from this analysis showed a small increase in peak pressures relative to the Hatch-2 Cycle 21 reload licensing analysis (ALA) results. The higher peak pressures were due to the fact that eight of the eleven SRVs opened at pressures higher than that which was assumed in the ALA. It should be noted that in this analysis, the larger actual valve bore size was used in the calculations for nine of the valves rather than the smaller bore size which was conservatively assumed in the ALA. Therefore, higher steam flow capacities than those assumed in the ALA were used in this analysis for those nine valves.

Based on the analysis, the calculated minimum margin to the 1375 psig ASME Boiler and Pressure Vessel Code overpressure limit for peak vessel pressure would have been 27.7 psig and the minimum margin to the 1325 psig Tech Spec Safety Limit for the reactor steam dome pressure would have been 2.9 psig during an MSIVF event during Cycle 21 operation. Therefore, these test results show that in this case, where two of the eleven SRVs would have opened at pressures higher than that which was assumed in the RLA, the peak pressure at the bottom of the vessel would have remained below the ASME Boiler and Pressure Vessel code limit and the peak RPV dome pressure remained within the TS Safety limits.

Additionally, a highly reliable, though non-credited, electrical actuation system serves as a redundant, independent method to actuate the SRVs. During Cycle 23 this redundant electrical logic system was fully functional. Based on the analyses performed, the overpressure protection system would have continued to perform its required safety function if called upon in its "as found" condition. Therefore, this event had no adverse impact on nuclear safety and was of very low safety significance.

CORRECTIVE ACTIONS 

The 2-stage SRVs with platinum-coated pilot discs were removed from Unit 2 during the 2015 refueling outage and replaced with 3-stage SRVs that have a modified pilot. 3-stage SRVs typically do not exhibit set point drift due to their design. The modified pilots will help reduce spurious openings and leak-by due to system vibration.

ADDITIONAL INFORMATION

Other Systems Affected: None

Failed Components Information:

Master Parts List Number: 2B21-F013E, H

Manufacturer: Target Rock

Model Number: 7567F

Type: Relief Valve

Manufacturer Code: T020

EllS System Code: SB

Reportable to EPIX: Yes

Root Cause Code: B

EllS Component Code: RV

Commitment Information: This report does not create any licensing commitments.

PREVIOUS SIMILAR EVENTS:

LER 1-2014-003, identified multiple SRV setpoint drifts for 5 of the 11 two-stage SRVs installed on Unit 1. The two-stage SRVs with platinum-coated pilot discs were removed from Unit 1 during the 2014 refueling outage and replaced with 3-stage SRVs that have a modified pilot. The modified pilots will help reduce spurious openings and leak-by due to system vibration.

LER 1-2012-004, identified multiple SRV setpoint drift for 8 of the 11 SRVs. Corrective actions included replacement of the 2-stage SRVs with 2-stage SRVs whose pilot discs had undergone a platinum surface treatment which was considered at that time to be the long term fix for this corrosion bonding issue.

LER 2-2011-002, identified multiple SRV setpoint drift for 8 of the 11 SRVs. Corrective actions included replacement of the 2-stage SRVs with 3-stage SRVs during the Unit 2 Spring 2011 refueling outage which was considered at that time to be the long term fix for this corrosion bonding issue. Subsequent to that outage the 3-stage SRVs exhibited signs of unacceptable leakage which resulted in two separate outages that involved changing out four SRVs during the first outage and the remaining seven SRVs during the subsequent outage in May 2012. The 3-stage SRVs were replaced with 2-stage SRVs containing pilot discs that had undergone the platinum surface treatment.

LER 1-2010-001, identified multiple SRV setpoint drift for 5 of the 11 SRVs. Corrective actions included refurbishment of the pilot valves and included the replacement of the pilot discs with discs made from corrosion-induced bonding. These were the same actions that were taken following similar failures reported in LEA 2-2009-001, since improved results had been seen to some degree in the industry for at least one operating cycle when these actions were implemented.