Durbin blast Exelon For FutureGen Betrayal

March 4:

Just saying, our political system has severely polluted our energy and electricity system with ghost cost to us little people...

Is that our future, all the electricity players get to burden their expensive pet project on the bottom half as they are draining our income away from us...then these sources get to pay the elections bills of the politicians.

Typically the highest priced electricity source sets the prices on everyone else...the highest price electricity that gets on the grid they pay to everyone else.

I am just saying, I am against all sources of energy that survives by heavy government subsidies, then this expensive electricity comes on as the highest price source of electricity on the grid, this then set the cost we pay of even the lowest cost producers...

 So Durbin wants to undermine the rate player and Exelon to support 200 workers and his getting elected through the green folks.

For a second here, I pity Exelon...

Effectively Durbin wants to turn Exelon into his piggy bank...

Exelon got a huge dividen cut, natural gas is breathing down their thoats...and wind is sucking the rest out of them...

Durbin blasts Exelon for FutureGen 'betrayal'
U.S. Sen. Dick Durbin today blasted Commonwealth Edison Co. and its parent Exelon Corp. for what he termed a “heavy-handed corporate betrayal” after Crain's report of ComEd's plan to challenge a state decision to impose a surcharge on electricity customers statewide to pay for development of the FutureGen 2.0 “clean coal” power plant downstate.

In a statement, Mr. Durbin, the No. 2 Democrat in the Senate, said Chicago-based Exelon, the state's largest power generator and the country's largest nuclear plant operator, acted as a member of the FutureGen Alliance for more than two years.

Exelon, he said, “was an intimate party to our state's strategy to negotiate this historic energy research project and the 2,000 jobs it will bring to our state. Exelon sent its smiling representatives to press conferences lauding the virtues of FutureGen.”

Then, Mr. Durbin went on, “last month Exelon abruptly resigned from the FutureGen Alliance without explanation, and today we learned Exelon has filed an appeal challenging the (Illinois Commerce Commission) ruling which is a critical part of our FutureGen strategy. This heavy-handed corporate betrayal has few parallels in Illinois history.”

Earlier today, before Mr. Durbin's broadside, an Exelon spokesman said the company never joined the alliance despite a January 2010 announcement that it intended to do so.

“Our decision reflects our long-held position that customers should not be forced to pay enormous above-market charges for electricity, as the project is now seeking,” the spokesman wrote in an email.

Asked about that, a Durbin spokeswoman confirmed that Exelon never paid any money or signed formal papers to join the FutureGen board. But, she said, the company participated in strategy and planning for two years and only stopped participating last month.

In a Feb. 18 letter from Exelon CEO Christopher Crane to Mr. Durbin furnished by Exelon, Mr. Crane said his company opted not to join the alliance because its financing plan shifted from one relying more heavily on corporate equity investment to one focused on charging Illinois consumers more for energy. In January 2010, when Exelon announced its intention to join the alliance, the plan was to ask 20 corporate members to contribute up to $30 million each.

“Unfortunately in 2012 this original structure was scrapped in favor of a new structure where corporate contributions are significantly reduced and customers are now required to fund approximately $150 million in annual above-market costs for the entire 30-year life of the project — a total of $4.5 billion,” Mr. Crane wrote.

The $1.6 billion project, which aims to retrofit a shuttered power plant formerly run by Ameren Corp. in downstate Meredosia and construct a pipeline to carry carbon dioxide for burial in nearby Morgan County, needs more than $600 million in private financing. The ICC in December approved a plan to require household and business power customers, whether they buy from utilities or competing retail suppliers, to purchase output from the plant at above-market prices.

Under the plan, the FutureGen Alliance projects household customers will pay a little over $1 per month extra for 20 years to finance the project.

Mr. Durbin finished his statement with this: “We fought Texas to win this project and we fought the odds to move it forward. Now we are prepared to fight Exelon to save 2,000 jobs for our state.”

The LaSalle Nuclear Plant Cooling Lake and NRC Idiocracy

LASALLE COUNTY STATION UNIT 2 NRC SPECIAL INSPECTION REPORT 50-374/01-017(DRP) 2001017

LASALLE COUNTY STATION NRC INSPECTION REPORT 50-373/01-16(DRP); 50-374/01-16(DRP) 2001016

Feb 26, 7 pm: You get it, a forced two year shutdown by the NRC beginning in 1996. A massive capitol under investment in their nuclear fleet for the first half of the 1990's and enormous problems fleet wide. So they had a huge re-think brought about by a newly serious NRC. ComEd stated massively reinvesting back in their nuclear fleet. This directly lead to the huge 1999 Chicago electric power distribution and transmission crisis. Lots of electric blackouts in this summer of 1999. They plowed monies into their nuclear fleet and started starving their transmission system

It wasn't a nuclear technology crisis...it a management crisis of one of our largest electric utilities. 

What was growing on at the end of the 1990s, in the weakened end of president Clinton's era, the rabid mad dog republicans had taken over congress. They intimidated the NRC by threatening to cut their budget, the 1990 rendition of the republicans shutting down government over deficits and the new obstructionist blackmail politics.  

This was when the NRC moved towards massive historic public opaqueness. The nuclear industry moved in a unparalleled historic manner towards nuclear industry deregulation. Building a hundred new nuclear plants was on the horizon. It was a boomerang from the re-regulation area, trying to gain control of the poor performing and unsafe early 1990s nuclear industry.

Right, 1999 Chicago was in a terrible drought and heat wave, terrible fear was in the air over electric deregulation and ComEd stock prices were pitifully weak. Enron and the California power crisis were just a few years away. The "Exelon" name was just a knockoff of the Enron name.

So happy days were here again on July 24, 1998.                  

NEWS ANNOUNCEMENT: RIII-98-46 July 24, 1998
CONTACT: Jan Strasma 630/829-9663

NRC STAFF FINDS SUFFICIENT IMPROVEMENTS FOR RESTART
OF UNIT 1 OF THE LASALLE NUCLEAR POWER STATION
The Nuclear Regulatory Commission staff has determined that
Commonwealth Edison Company has made sufficient improvements at Unit 1 of the LaSalle Nuclear Power Station for the unit to resume operations. The two-reactor facility is located near Seneca, Illinois.

The utility is planning to begin startup of the unit next week. Both units were shut down in September 1996 for refueling and maintenance and remained shut down for extensive plant modifications, staff retraining, and other performance improvement initiatives.

So the lights go out in Chicogo in 1999 

Comed Pays For Misspent Decades

Aging Infrastructure Now Haunting Utility

August 15, 1999|By Peter Kendall and Laurie Cohen, Tribune Staff Writers. 

Like most everything at ComEd, following the trail of the problem eventually leads back to the utility's struggles with its nuclear generation program, the most ambitious in the nation.  

Even a decade ago, many were warning that some of the billions of dollars spent to build the nuclear plants should have been spent on wires and transformers. 

Ironically, at the point at which ComEd seems to have turned around its mismanaged nuclear plants--this summer, for the first time in years, all five plants were up and running--it is now suffering the fallout from what many say has been equally shoddy management of its more prosaic electricity delivery system.

By 2001, with all the leaking safety relief valves seen throughout the Exelon fleet of nuclear power plants, particularly the six pack of SRV valves leaking at both LaSalle plants: they raising their suppression pool temp limit to 105 F to accommodate poor maintenance and quality safety parts; beginning to overload their cooling pond with plant heat; then panically trying to raise the cooling pond temperature..I thought these guys had marginally adequate systems and components at the plants, had marginally competent employees running the nuclear fleet just after a prolonged shutdown for safety reasons in the late 1990s. It was startling.     

We knew we were on our way to nirvana with “balls to the wall” George Bush assuming office in Jan 2001, with LaSalle by-passing 10% of power from their turbine through their SRV valves, then demanding their suppression pool safety pumps run on continuously

...the 2002 Davis Besse head leak was frosting on the cake.  

Where do we sit today. Exelon just slashed their dividend by 41% because of the cheap natural gas problem, poor electric demand...they are threatening to shutdown nuclear plants. By the grace of god and fracting, they have cancelled all the nuclear plant Extended Power uprates as too expensive. They are cutting $2.4 billion dollars from Exelon’s nuclear capital expenses.  Exelon’s stock price in 1999 was $24, a massive Exelon stock price speculative bubble led to a historic high price of $91 dollars...the current price is $31 dollars. After the stock price speculative bubble burst in 2008 to about $50 dollar...the stock price has been slowly declining to today price of $31 dollar.         

...Graphical Climatology of Chicago Temperatures, Precipitation, and Snowfall (1871-Present)

Right, they are planning for a extended 12% power up rate per plant by 2015 without building cooling towers. 

So, the below is Aug 15, 2011 NRC request for information posed to Exelon after their May 6, 2011 LAR.
If the agency would have done a proper "due diligence" data search in the lead up to their Exelon's LAR response...they would have known the high historic cooling pond temperature of 101.33 °F occurred on August 12, 2010  and was in their Aug 12/13 daily event report page. Doesn't seem to be in the 2010004 inspection report. Maybe this was the reason for the write-up on the 2012004. It is spotty inspectors reporting on these events.

The NRC in their IR 2010004 says Lasalle was down powering through the summer of 2010 to control the high temperature of the LaSalle cooling water pond. 

This Aug 15, 2011 NRC document is grossly inaccurate with these NRC officials in assuming Exelon-LaSalle was "approaching the TS limit of 101.25 F" (they exceeded it with 101.34 Aug 12, 2010) and the "actual peak accident post-accident UHX temperature of 104" (it is actually 106F).

Who can you trust?

No question the agency should have demanded a voluntary thorough and detailed LER out of Exelon on the Aug 12 2010 event and certainly the NRC failed to do a immediate detailed inspection.

(Aug 15, 2011)Exelon's request for amendment to TSs dated May 6, 2011 states:

"High temperatures and humidity during the daytime, in conjunction with minimal cooling at night and little precipitation during the summer months, results in elevated water temperatures in the LSCS UHS. Weather conditions in the future may result in the temperature of the [Core Standby Cooling System] CSCS pond challenging the current TS limit of 101.25 F.'' 

LSCS updated final safety analysis report (UFSAR) Section 9.2.6.3.2, "Ultimate Heat Sink Temperatures and Evaporation Losses During Shutdown Conditions," states:

"The results of the analysis for the worst-case historical weather effect on the temperature of cooling water supplied to the plant from lake/UHS indicate the peak temperature of cooling water from the lake will be 97.5 F and it occurs late in the afternoon (approximately 6 pm)." 

If the analysis shows that the worst case historical weather effect on the cooling water to the plant from the lake/UHS results in a peak temperature of 97.5 F.

(a) Why is the CSCS pond temperature exceeding 97.5 F and approaching the TS limit of 101.25 F?

(b) With the CSCS pond exceeding the UFSAR peak temperature of 97.5 F and the high temperatures and humidity (as stated above), discuss the validity of the 1.3 F post accident heatup in the CSCS pond and its affect on the actual peak accident post- accident UHX temperature of 104 106F

Can you imagine that, this is the first or maybe the second summer after the 2000 five percent power uprate...they are already begging the NRC for a raise in the LaSalle cooling pond water temperature limits.

As in engineer's plant language,  the "prolonged hot weather" term to totally fictitious and they know it...they are falsifying federal documents. At the least they can say, the prolonged hot weather is a minor factor, the major cause is we are overloading the lake with heat from the power unrate.   

They are already overloading the cooling pond with nuclear plant heat: To a 103 degrees, not yet? This is the amendment :

August 2, 2001 
RS-01-152 
Subject: Application for Amendment to Technical Specifications Surveillance Requirement 
for the Ultimate Heat Sink Temperature 

Prolonged hot weather in the area has resulted in sustained elevated cooling water temperature supplied to the plant from the CSCS pond. High temperatures and humidity during the daytime, in conjunction with very little cooling at night and very little precipitation, have resulted in elevated water temperatures in LaSalle County Station's UHS. 

The average temperature of the UHS reached 98 OF on July 21, 2001.

 The current SR verifies that the temperature of the cooling water supplied to the plant from the Core Standby Cooling System (CSCS) pond is •100 °F every 24 hours. This request will modify SR 3.7.3.1 to allow continued operation of both units with CSCS pond temperature of •103 OF through September 30, 2001. 

The NRC's  Licencing Amendments Request (LAR) requires a sworn and certified signature. It is the accepted culture of lying and half truths for self protection.

AFFIDAVIT 
I affirm that the content of this transmittal is true and correct to the best of my knowledge, information, and belief.

K. A. Ainger (C/ 
Director- Licensing Mid-West Regional Operating Group 

SUMMARY OF JUNE 28,2012, PRE-APPLICATION MEETING WITH EXELON GENERATING COMPANY, LLC, TO DISCUSS LICENSING AMENDMENT REQUEST FOR LASALLE COUNTY STATION UNIT 1 AND UNIT 2 ULTIMATE HEAT SINK AT AT EXTENDED POWER UPRATE POWER LEVELS (TAC NOS. ME8866 AND ME8867)

It's called magical thinking...you let them get away with it for over a decade.

Previously, the staff has reviewed LSCS UHS LARs in 2001,2006,2007, and 2011 (only the 2007 UHS LAR concluded in an NRC approval). (Ouch) The licensee stated that they did not consider the UHS LAR linked to the future EPU application.

only nuclar enginners think this inside the boxthinking is safe and wha the public wants  ...wow...did not consider the UHS LAR linked to the future EPU application.

I feel sympathy for the Exelon's monsters the inspectors are dealing with...feeling sorry for these little inspector whose big bosses aren't backing them agianst the monster corporatim

...At least the 2012 flextime safety cooling pond amendment proposed 30 day worst case aligns with either 1995 drought and heatwave. The current worst case of record is in left field. The 1 day July 2001 aligns with   the IR 2001010 (2001)/

How come the cooling lake peak historic temperature of August 12, 2010 and the second worst on Aug 8, 2005 is totally disconnected for the worst meteorological worst case choices of Exelon's 2012 flextime amendment request. How come the severe droughts and heatwaves of 1995 and 1999 didn't challenge the 100 F limits of the LaSalle... how come in the inspection report 2010004 and the 2012004 they didn't talk about the cooling pond highest historic peak temperature wasn't in the severe droughts and heat wave of 1995 or 1999. 

It is simple as hell, they overload their cooling pond with heat from the two 5% power uprates in 2000. 

According to the Exelon's  2012 flextime UHX, the proposed worst 30 day weather is from July 21, 1995, 3:00 p.m. to August 20, 1995, 3:00 p.m., the great Chicago heatwave of July 12-16 1995, how come we see no record high temperature LaSalle cooling pond temperatures in the summer of 1995?     

Current UHS TS Analysis 
(through primitive fluid dynamic computer models:) 

Period Analyzed: July 4, 1948, through June 30, 1996

Worst Temperature Weather Periods:

• 1-day: July 15 to July 16, 1995


• 30-day: July 10, 1983 to August 9, 1983


• Worst 30-Day Evaporation Weather Period: June 18, 1954, to July 18, 1954

Proposed UHS TS Analysis 
Weather Period Analyzed: July 4, 1948, through June 30, 1996 (Peoria and Springfield, IL) January 1, 1995 to September 30, 2010 Worst Temperature Weather Periods:

• 1-day: July 24, 2001, 6:00 a.m. to July 25, 2001, 6:00 a.m.


• 30-day: July 21, 1995, 3:00 p.m. to August 20, 1995, 3:00 p.m.


• Worst 30-Day Evaporation Weather Period: June 18, 1954, to July 18, 1954"

Inspection report 05000374/2012004 dated Oct 30, 2012

"from the cooling water temperature from the CSCS pond reaching 101.34 °F on August 12, 2010. This was the highest inlet temperature ever reached to date and had exceeded the TS 3.7.3.1 limit of 101.25 °F. The previous highest temperature for the cooling water from the CSCS pond was 99.8 °F on August 8, 2005." 

The  1999 Illinois drought and heat wave. 

Drought of 1999-2000 Overview
Dry conditions began in Illinois in July 1999 due to a sudden and consistent reduction in the amount of precipitation that was falling over the state (Figure 1). Precipitation in the prior six months (January-June 1999) showed a statewide total of 22.70 inches or 22 percent above average. The other water resources of the state, soil moisture levels, streamflow amounts, and shallow well ground-water depths, reflected the above average precipitation condition, and gave no indication of concern as to the availability or status of the water resources in the state.

The Nature and Impacts of the July 1999 Heat Wave in the Midwestern United States: Learning from the Lessons of 1995
The July 1999 heat wave in the Midwest was an event of relatively long duration punctuated by extreme conditions during its last 2 days. The intensity of the heat wave on 29 and 30 July rivaled that of the 1995 heat wave that killed more than 1000 people in the central United States. In 1999, however, the death toll was about one–fourth of this amount in the same region. The 1999 heat wave 2–day maximum apparent temperature was slightly less than during the 1995 heat wave at most Midwestern first–order stations. In addition, the 2–day peak was preceded by several hot days that allowed some short–term acclimatization to occur prior to the intense final days. In Chicago, conditions during the peak of the 1999 heat wave were very similar to those during the 1995 heat wave peak, especially the extreme nocturnal conditions of temperatures and humidity. Therefore, it seems unlikely that the reduction in the heat wave death toll in Chicago from about 700 in 1995 to 114 in 1999 is due solely to meteorological differences between the two heat waves. In St. Louis, the 1999 heat wave was intense for a much longer duration than the 1995 heat wave, thus partially explaining the increase in heat–related deaths there from the 1995 event to the 1999 event.

Feb 26: Do you really think the high Illinois temperature was the cause of the tech spec change. They would be bypassing 10% of the power from their turbine though the leaks in their SRV valves...10% power was going into their suppression pool. This is what men do with with a mechanical conscience.  

They just got a culture of acceptable lying...engineering lying going on. The NRC allows them to lie for protection from the public. it is still going on...they are lying to protect you. From the revising the Tech Spec from 100 F to 105 F, to the acceptance massively leaking SRV valves, this is all a huge reduction in safety margin for no good reason...

From the NRC in 1989: Specifically, the proposed change would raise the suppression pool temperature limit during normal operation from 10°0F to 105'F.

"The licensee stated that the unusually high temperatures in Illinois, the temperature of the LaSalle lake, which serves as the ultimate heat sink for the plant service water and residual heat removal (RHR) systems, have risen to the point where an insufficient differential temperature is available to maintain the suppression pool temperature below 100'F.

This is the really bad old days (2001010) Sept 2001:

This revised operability evaluation identified that LaSalle Unit 1 and Unit 2 each have six leaking SRVs. The impact of this issue has been an increase in suppression pool level as well as a slow heatup of the suppression pool. To address suppression pool temperature issues, operators run the RHR system in the suppression pool cooling (SPC) mode to cool the suppression pool to maintain the suppression pool temperature below the Technical Specification 3.6.2.1 limit of 105 F.

The operating time of the RHR system in the SPC mode is dependent upon the heat input into the pool and the LaSalle cooling lake temperature. Recently, the Unit 1 SRV leakage rate and lake temperature increased to the point that RHR operation on a daily basis was required. As a result, licensee management made a decision to operate one train of the Unit 1 RHR system in the SPC mode continuously and implemented this action on June 6, 2001. The technical basis for this decision was documented in Analysis L-002766, .GE NEDC & Continuous Operation of RHR in the Suppression Pool Cooling Mode,. Revision 0, dated May 10, 2001, and reviewed and approved by the Plant Onsite Review Committee (PORC) on June 8, 2001.

The inspectors reviewed OE00-009, Revision 2, and verified that the RHR system would automatically re-align from the suppression pool cooling mode to the injection mode within the time required to satisfy design basis assumptions.

In them days, the industry was demanding less testing of the RHR components saying the operation of the system was damaging and wearing out their equipment. But using the RHR component to compensate for poor maintenance and poor quality of safety relief valves leakage does not wear out extremely important RHR components.

 ...I mean, there is a huge disconnect with the meteorological one day worst weather and actual effects on the LaSalle cooling pond temperatures. How come the instrumented meteorological data don't line up with the plant service water inlet temperatures? Meteorological data is supposed drive pond temperatures? 

How come on the amendment the proposed July 24, 2001  historic "one day worst weather" doesn't line up with the historic highest peak cooling pond temperature in IR 2012004. The highest and second to the highest pond summertime temperature peak  is  101.34°F on Aug 12, 2010 and 99.8 °F on August 8, 2005. Exelon says the worst on record is July 24, 2001. You guys worried about spending a $ 1 billions on cooling towers for just three weeks in the summer? Is that what the lying and federal document falsification is all about?  

In the current worst weather analysis and proposed, what it the fixation of the middle of July and the end of July with the worst one day weather, as also an inclination on the 30 day worst weather too? Why the worst weather not heavily weighted in August from your meteorological list...instead of July. Inspection report 2012004 tells us historically the highest temperature of the cooling water occurred Aug 9 and Aug 12 with LaSalle. Millstone shuts down also on Aug 12 last year...is this all a coincidence? Generally across the board on cooling water bodies nationwide, the peak summertime pond, mostly closed cooling bodies, and streams and rivers, occur mostly around mid to late August. It is the so call worst one day or 30 day weather, along with the fuel load for potential fire, that is the as is temperature load of the pond that drives risk?  

I'd like to see a list of peak summertime pond temperatures and the dates for 2 decades.

Is an algae bloom taken into consideration with the Aug solar radiation and cooling pond temps?

The historic 2005 and 2010 peak summertime temperature falsifies your worst weather analysis and it questions the integrity of its predictions.

And service water temperatures are more indicative of risk than the diurnal pond temperature...a three day, week or a monthly rolling average of lake water temperatures.

Why in the world would the NRC accept a 1976 one dimensional computer model in a safety applications in 2013 for flow and thermal dynamics for a UHX? What a disgrace. Does it give you the profit calculations you want?   

The computer program used to model the LaSalle UHS during the design event is LAKET-PC developed by Sargent and Lundy in 1976 as a one-dimensional thermal prediction model for bodies of water.

I called this their flextime nuclear safety amendment...safety limits bent to the convenience of a nuclear utility.

RS-12-084
July 12, 2012
U. S. Nuclear Regulatory Commission
Attn: Document Control Desk
Washington, DC 20555-0001
LaSalle County Station, Units 1 and 2
Facility Operating License Nos. NPF-1 1 and NPF-1 8
NRC Docket Nos. 50-373 and 50-374

Subject: In accordance with 10 CFR 50.90, "Application for amendment of license or construction permit," Exelon Generation Company, LLC (EGC) is requesting a change to the Technical

"The weather data was evaluated to determine the worst 24-hour and 30-day weather periods resulting in maximum plant intake temperature (i.e., minimum heat transfer to the atmosphere) and for the worst 30-day period of net evaporation. The following summarize the results of the limiting weather data periods.

Current UHS TS Analysis
(through primitive fluid dynamic computer models:)

Period Analyzed: July 4, 1948, through June 30, 1996

Worst Temperature Weather Periods:

• 1-day: July 15 to July 16, 1995


• 30-day: July 10, 1983 to August 9, 1983


• Worst 30-Day Evaporation Weather Period: June 18, 1954, to July 18, 1954

Proposed UHS TS Analysis
Weather Period Analyzed: July 4, 1948, through June 30, 1996 (Peoria and Springfield, IL) January 1, 1995 to September 30, 2010 Worst Temperature Weather Periods:

• 1-day: July 24, 2001, 6:00 a.m. to July 25, 2001, 6:00 a.m.


• 30-day: July 21, 1995, 3:00 p.m. to August 20, 1995, 3:00 p.m.


• Worst 30-Day Evaporation Weather Period: June 18, 1954, to July 18, 1954"

Inspection report 05000374/2012004 dated Oct 30, 2012

The inspectors reviewed AR 1101063, “Dual Unit Limiting Condition for Operation (LCO) Entered Due to High Lake Temperature,” that documented a reduction of power to approximately 80 percent for both units due to problems caused by the fish kill resulting from the cooling water temperature from the CSCS pond reaching 101.34 °F on August 12, 2010. This was the highest inlet temperature ever reached to date and had exceeded the TS 3.7.3.1 limit of 101.25 °F. The previous highest temperature for the cooling water from the CSCS pond was 99.8 °F on August 8, 2005.

You guys are confusing the hell out of me. So if you used the post March 13, 2006 UHX service/ circ water temperature accuracy on the Aug 8 2005 peak temperature the indicated temperature would be °F? It is a huge jump from 98.3°F to 101.34 °F. I am drowning here, if we are using the pre March 13, 2006 instrument accuracy on Aug 12, 2010 it would really be 102.84 °Fand still a huge jump from 98.3 °F.

It still don't add up to the limit of >100°F in pre 2006 and less than or equal to 101.5°F post March 13, 2006 amendment?

1) Request a OIG investigation on the massive public lying and other fraud going on here for over a decade.

2) The NRC withdrawal all past LARs on the UHX...limit plant operation to less than 95 degrees F pond temperatures.
4) I consider the worst accident as August plant operations with severe plant heat overload, then breaking historical pond/service water intake temperatures killing many 1000s of lake fish in a historic drought or heat wave, a dike failure and then the DBA nuclear plant accident. The living, dead and dying fish all collecting in the deep water areas, the heat killing them all... it damages all traveling screens and clogs up all cooling water into the plant then leading to LOOP. Just like the pond historical temperature event in 20100004 on Aug 12, 2010 and the Oct IR 2012004.

5) Does the computer model only take into account a uniform temperature in a column of water...while the lake depths has temperature stratifications. Might we have a much higher temperature on the surface, much higher than the limits, while the plant intake sucks on a lower temperature stratification layer. Could the increasing hot surface layer quickly infiltrator the cooler layers...unexpectedly thereby spiking to inlet temperatures as we exceed the historic record temperatures.

6) So the transport time for the lake is 30 hours with two plants up at full power and full circulation water, from the discharge back to the inlet of the plant. Does anyone really know what the lake flow and thermal effects does for two shutdown plants and on emergency service water loads. The full power circulation water flow dwarfs the emergency flows. How do you know the full flow mode...the 30 hour transport time is a worst case more than much less pump drive. Obviously the transport time would be slowed down. You trust your intuitiveness on this? Request the cooling pond be three dimensionally computers modeled with a real transport time and it include all flow and temperature characteristics.


di·ur·nal

I made a lot of mistakes in my first video...

Fantastic new scientific invention by our nuclear folks...flextime nuclear plant safety limits.. Safety limits that are convenient to utility profits...

So if the cooling lake exceeds the 100.25 degree limit at 6 am, say 102 degrees. The requirements are they have to be shut down in 12 hours. They can drag their feet and they do drag their feet. So all they do is put their hand in their pockets until the graph rises at about 8:30 am past the limits. They can do that all summer long if they wish.

They keep uprating power to the nuclear power plant with a too small cooling lake leading to a reduction is safety margins and to unpredictable results.

Can dead fish lead Fukushima?

October 11, 2002:  Ultimate Heat Sink

Mr. Michael Mulligan
P.O. Box 161
5 Wood Lawn Lane
Hinsdale, NH 03451

Dear Mr. Mulligan:

I have reviewed your e-mails dated June 18, July 22 and August 7, 2002, all of which were addressed to the U.S. Nuclear Regulatory Commission’s (NRC’s) Office of Public Affairs via Mr. Victor Dricks. Most of your comments were addressed in previous letters to you [specifically our letter dated February 13, 2002, which addressed your Yankee Nuclear Power Station (Vermont Yankee) November 30, 2001, petition, as supplemented on December 3, 2001; your January 4, 2002, petition on Vermont Yankee; and your LaSalle petition dated December 28, 2001, as superseded on January 4, 2002]. As discussed in our letter to you dated August 23, 2002, I am only addressing issues in the e-mails that are within NRC's jurisdiction and that warrant additional actions on our part. As stated in our letter to you on August 22, 2002, the allegations of wrongdoing by the NRC staff have been forwarded to the NRC’s Office of the Inspector General.

You requested an explanation of the sentence on page 2 in the Cooper Nuclear Station (CNS) ultimate heat sink (UHS) amendment (ADAMS Accession No. ML022060152), "Assuming 102 percent reactor power is typical and consistent with what the NRC considers to be acceptable for design-bases applications, we consider this assumption to be acceptable." The NRC staff agrees that this sentence could have been better stated. For the UHS amendment, CNS was not as conservative as their original calculations which assumed 104 percent. However, to account for instrumentation error 10 CFR Part 50 Appendix K requires that the licensee assume at least 102 percent reactor power. Therefore, the NRC staff found CNS’s assumption of 102 percent, for the UHS amendment, to be acceptable.

You asked why the UHS amendment was issued on an exigent and not an emergency basis. The NRC staff evaluated the licensee's rationale against Section 50.91(a)(5) of Title 10 of the Code of Federal Regulations (10 CFR) which requires licensees to "explain why the emergency situation occurred and why it could not avoid the situation." The licensee's letter of July 3, 2002, did not address why the emergency could not be avoided. Therefore, the NRC staff had determined not to act on the licensee's request pursuant to 10 CFR 50.91(a)(5). The NRC staff, however, recognized that for continued operation of CNS, the licensee and the Commission needed to act quickly, and time did not permit the Commission to wait for the 30 day prior public comment period. In accordance with 10 CFR 50.91(a)(6), the staff processed the two amendments concerned on an exigent basis to prevent an unnecessary plant transient.

You expressed concern that there has been an increasing trend with license amendment requests asking for higher UHS limits in the last few years. Generally, trends in license amendments have been attributed to various reasons. For instance, licensees have utilized topical reports as templates for submitting amendment requests. Therefore, related amendments are typically requested following the approval of a topical report. Other times, important inspection findings at one plant have prompted other plants to request license changes. UHS amendments have been issued to remove unnecessary restrictions in the technical specifications (TSs) on plant operators in severe weather conditions. TSs limits on UHS parameters such as temperatures and water levels are based on assumptions made in design and licensing analyses. Changes in weather patterns have resulted in many plants approaching the values assumed during original licensing reviews performed 20 to 30 years ago. In this case, the utility was able to prove that operation at higher UHS temperatures was safe. The NRC determined the licensee’s request was justified and approved the change to the TSs 

You asked why additional changes were needed (beyond the heat sink limit) in related limits, if there is so much safety margin built in. Many systems are related. Therefore, in considering a change to one system’s parameters, the effect on other systems must be considered. The reactor equipment cooling (REC) system is cooled by water from the UHS, consequently the temperature of the REC system will increase as the UHS temperature increases. Therefore, an increase in the REC system temperature limit was also required.

You stated that CNS has an alcohol abuse problem. After reviewing several of the plants’ fitness-for-duty (FFD) reports over the past two years, the facts do not agree with your assertion that CNS staff has a significant problem. FFD reports are submitted by the licensee biannually per 10 CFR 26.71 to ensure a rigorous drug and alcohol screening policy is in effect. FFD reports are available in the Agencywide Documents Access and Management System (ADAMS) Public Electric Reading Room.
Finally, you stated that you believe the NRC purposely did not include your initial comments regarding the amendment request. The NRC does not purposely leave out public comments received in reference to a Federal Register notice. In this case, your comments contained in the June 18, July 22, and August 7, 2002 e-mails were not forwarded to the staff working on the amendment until after the amendment was issued. The only way to ensure your comment on an amendment is addressed is to follow the instructions outlined in the Federal Register which states:

Written comments may be submitted by mail to the Chief, Rules and Directives Branch, Division of Administrative Services, Office of Administration, U.S. Nuclear Regulatory Commission, Washington, D.C. 20555-0001, and should cite the publication date and page number of this Federal Register notice. Written comments may also be delivered to Room 6D22, Two White Flint North, 11545 Rockville Pike, Rockville, Maryland, from 7:30 a.m. to 4:15 p.m. Federal workdays.

If you have questions on this matter, please contact Mr. Brian Benney of my staff at 301-415-3764.

Sincerely,
/RA/
Stephen Dembek, Chief, Section 2
Project Directorate IV
Division of Licensing Project Management
Office of Nuclear Reactor Regulation
Docket No. 50-298

If you have questions on this matter, please contact Mr. Brian Benney of my staff at
301-415-3764.

Sincerely,
/RA/
Stephen Dembek, Chief, Section 2
Project Directorate IV
Division of Licensing Project Management
Office of Nuclear Reactor Regulation
Docket No. 50-298

DISTRIBUTION:
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PDIV-2 Reading
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ACCESSION NO.: ML022730516 PKG: ML022270713 NRR-106
Incoming: ML022250558 d/d 08/04/02 (Attached-6/18/02)
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NRC/Exelon with falsified...incomplete documents and investigations?

We are trying to signal to the nuclear industry they have a higher calling for truth telling other than the limited rules and mandates of the NRC.

　10 CFR 2.206 Petition Review Board RE Peach Bottom Units 2 and 3 Transcripts

Feb 13 2013

"Anyway, anybody listen to the State of the Union speech last night? The White House basically frames it like it's time to apply the same rules from the top to the bottom. President Obama laid out a blueprint for an economy built on American manufacturing, American energy, skills for the American worker, and a renewal of American values, and American built to last. We can either settle for a country with a shrinking number of people who do well while a growing number of Americans barely get by, or we can restore an economy where everybody gets a fair shot, everybody does his fair share, and everybody plays by the same rules.

So, one of the components he outlined was a fair shot, a fair share, and a fair set of rules. Millions of American -- millions of Americans who work hard and play by the rules every day deserve a government, financial systems that do the same. So, you know, as far as being complete and honest and stuff like that, you know, it's a privilege that I'm -- for you people that I'm here and asking questions. And that's the way you should look at me. I'm a very rare individual that comes here and asks some difficult questions and stuff like that. And I'm an American citizen. I live in the best country on the planet, and that should afford me some special rules. And you people should answer me honestly because really, you're answering the public out there and stuff.

　
I needn't remind you that LERs and the special reports are not necessarily about following the rules. A lot of times it's being honest and ethical and disclose everything. That's the way our system is supposed to run, our free market is supposed to run. We're supposed to all have access to adequate information, and as far as our financial system is concerned and our rate payers, and the stockholders, they ought to get a fair shot of understanding what's going on with these companies. And if these politicians make all these rules that limit what the NRC can do, and say, and stuff like that then you're screwing the rate payer and the financial people, and the stockholders.

Ultimately, these things end in a crash when people aren't honest and truthful, and I don't care if they're following the rules. The ultimate income is to do good for us all, and not just follow the rules. They need to have a higher calling than following the rules."

　
　
Markey: Did San Onofre Operator Violate Federal Securities Law?
　

Feb 21 2013 SEC letter

Company May Have Failed to Fully Inform Investors about Design Issues, Rejected Safety Fixes, Attempted to Avoid New License Requirements

WASHINGTON (February 21, 2013) – Rep. Ed Markey (D-Mass.) today raised the possibility that the utility in charge of the San Onofre nuclear power plant in southern California may have violated federal securities laws by failing to publicly report safety information to investors.

According to a letter sent by Rep. Markey to Securities and Exchange Commission head Elisse Walter, the lawmaker says investors do not appear to have been fully and accurately informed of design flaws found by Southern California Edison and Mitsubishi in advance of the replacement of parts of the plant, and that SoCal Edison decided to reject recommended safety modifications for fear that they would be required to undertake a new license process before the parts could be installed. SoCal Edison is the operator of the plant and hired Mitsubishi as a contractor.

The plant’s two nuclear reactors have been shuttered since January 2012 because of unusual amounts of wear found in tubes in the replaced steam generators. In his letter to the SEC, Rep. Markey raises the question of whether by hiding potential design flaws in the replacement generators, and omitting that the company reportedly did so to avoid having to apply for an amended license to operate the reactors, SoCal Edison may have violated the Securities Act of 1933. That law says that all “material facts” -- information that an investor would consider important -- must be fully disclosed.

“Investors presumably would want to know whether a company is choosing not to implement additional safety protocols because such actions might require a nuclear reactor to go through a more strenuous licensing process,” writes Rep. Markey, who is the Ranking Member of the Natural Resources Committee. “Such choices could be evidence of poor management or even possible future civil liability.”

The full letter to SEC Acting Chairman Walter is available HERE.

Rep. Markey also asked the SEC what the penalties would be for violations of this law, and whether other enforcement actions have been taken against energy companies for failing to disclose under similar facts and circumstances. Last week, the Nuclear Regulatory Commission confirmed that they are investigating the completeness of information SoCal Edison provided on the replacement of steam generators.

Palisades Component Cooling Water System Leak

See, this system is nothing but junk...keeps causing troubles.

 IR2011001/005

Inspection Scope

The inspectors reviewed the following issues:

• cooling tower degradation;

• service water pinhole leaks;

• pressurizer pressure indicator degradation;

• C Primary coolant pump due to increased vibrations; and

• component cooling water heat exchanger flow degradation.

...containment spray during ‘B’ pump maintenance;

• component cooling water during ‘B’ pump maintenance;

• 1-1 diesel generator during 1-2 diesel generator inoperability for emergent

ventilation work; and

• low pressure injection with ‘A’ pump out-of-service

The inspectors selected these systems based on their risk significance

2011003

Additionally, the licensee determined that the “white spots” on the head were the result of boron staining, white mastic residue used to attach insulation to the head, or chromate water deposits from a previous component cooling water leak.

2010002

The inspectors evaluated degraded performance issues involving the following

risk-significant systems:

• component cooling water system; and

 

....risk during planned component cooling water pump outage;

Pilgrim's Malfunctioning Scram Discharge Valves?

I would have to ask what changed between the failure during testing at power and the non failure of the valve with the plant shutdown:

1) Same service air pressure at power and during shutdown ops?

2) Obviously there is a huge change in temperature in the area at power and shutdown?

3) Usually the dried lubricant excuse, right, they have to come up with some plausible reason for the how they corrected the problem The dried lubricant is just a generic canned made up excuse so they wouldn't have to totally rip open the valve and maybe find a generic issue forcing a shutdown.

4) This is a really expensive nuclear safety valve and it is an extremely mature design, why would there even be bum lubricant in there.

5) It is implausible it would be the wrong lubricant knowing it is so important of a valve

6) If it was bum lubricant, why isn't there a slew of sticking SDV valves throughout the industry. Cause it would have caused an information notice, everyone would have changed the type of lubricant.

And you can totally count on the daily event report and the first rendition of a licensed event report to be comic books...accepted by the NRC and totally fictitious.
 
Pilgrim scram valve fails again
Is this a sign of an aging plant past its prime?
PLYMOUTH —

The second “event” at Pilgrim in as many weeks – the failure of a “scram discharge valve” – is also the second time this particular valve has failed in the last two months.

The scram discharge volume valve – referred to in the event releases as CV-302-22B – failed Feb. 18, a week after the blizzard knocked out power to the plant. (In another case of twos, Pilgrim also lost power twice during the strom.). The valve failed again last Friday, March 1.

According to the Union of Concerned Scientists (UCS), the CV-302-22B is one of the valves on the drain line from the scram discharge volume, a metal tank that is supposed to contain all of the water vented during a scram (a sudden, rapid, shut down of the reactor).

“When a scram signal occurs,” the UCS reported, “this valve automatically closes, or is designed to do so. Whether it does so is another matter.”

For critics of the plant, including EcoLaw.org Founder Meg Sheehan, this is a sure sign that the plant is past its prime.

“Pilgrim is old and worn out,” Sheehan wrote on her blog this week. “It presents an unacceptable risk to our region, and this is just one more example of that.”

A 1975 report on reactor safety, widely known as the Rassmussen Report, argues against that conclusion.

That report specifically stated that the valves in question have only a “one in a million” chance of interfering with a reactor shut down.

But the UCS said the Brown’s Ferry Nuclear Power Plant in Alabama must have hit the lottery, because in 1980 a plugged scram discharge valve prevented plant operators from successfully removing all of its control rods, three times, before the reactor staff was able to complete a planned shut down of their reactor.

That event at Brown’s Ferry did not occur during an emergency, however, and the 15 minutes it took to withdraw all of the reactor’s control rods did not, therefore, result in a disaster.

This week’s failure of Pilgrim’s scram valve, the official event notice released by Pilgrim concluded, “has no impact on the health and safety of the public.”

Plant staff had actually been monitoring the valve since it first failed in mid-February.

“A similar event report was generated for the same valve on Feb. 18, 2013,” the event-notification report states. “Compensatory measures applicable to the original event report included a revised lubrication application and additional surveillance testing.”

In other words, Pilgrim has been testing this valve since it first failed.

According to the NRC, the valve was lubricated, retested and restored to operability soon after the issue was discovered.

But tests conducted March 1, Pilgrim stated, “did not meet opening stroke time operability requirements for the valve.”

According to the NRC, during the power outages that shut down the plant twice during the February blizzard, the valve worked properly to support the scram.

“That is, it closed within the timeframe necessary to support the scram,” NRC spokesman Neil Sheehan told the Old Colony.

“The problem resulting in the report on Feb. 18 was discovered,” Neil added, “during routine surveillance testing conducted on these valves in the ‘open’ direction and was unrelated to any of the shutdowns.”

The NRC spokesman acknowledged that this valve plays an important role in supporting the scram function.

“That said, nuclear power plants have numerous systems and components that are important to safety,” Neil said. “The ‘defense-in-depth’ approach for nuclear power plants is based on multiple layers of safety through redundant systems and equipment.”

Neil wouldn’t comment directly on the assertion that the problems with this valve were related to the plants overall age.

“The company (Entergy) is continuing to evaluate the exact cause of the slowness of the valve to operate in the open direction,” Neil concluded. “Our inspectors will review the results of that review.”






July 29, 2005 Scram Discharge Volume Valve License Amendment Request.

So this is the secret deregulation going on that over rides initial plant design. If this happened prior to July 2005 they would be required to shutdown in 12 hours...today they got 7 days. They have had an unrecognized defect in the valve for two weeks now...might be three weeks at the end.

In a real incident it would have to operate under reactor pressure....for this test its only at atmospheric.

  Old requirement
"...If one or more SDV vent and drain lines have a single valve that is inoperable, the existing required action (Action A) is for the plant to be in hot shutdown within 12 hours.

New
With one SDV vent or drain valve inoperable in one or more lines, the isolation function would be maintained since the redundant valve in the affected line would perform its safety function of isolating the SDV. The current ACTION statement requires the plant to be in hot shutdown within 12 hours if any SDV vent or drain valve is found or made inoperable. The proposed changes are to allow for the isolation of the affected line and continue operation. For a single inoperable valve, the revised Required Action A requires the affected line to be isolated within 7 days (or restore the inoperable valve), or the plant is required to proceed to MODE 3 in the next 12 hours. The 7-day completion time (CT) is acceptable because of the low probability of the concurrent events of a scram within the 7 days of the CT and a failure of the redundant

valves. Alternately, if the inoperable valve was initially closed, there would be ample time and warning available to drain the SDV before an automatic scram would occur due to SDV high level. The proposed addition of Required Action B to address both valves being inoperable in a vent or drain valve is likewise acceptable in that isolation of the affected line provides the safety function and the shorter completion time (8 hours versus 7 days) reflects the increased importance of addressing the problem when multiple valves are inoperable..."

July 29, 2005 Scram Discharge Volume Valve License Amendment Request.
So this is the secret deregulation going on that overrides initial plant design. If this happened prior to July 2005 they would be required to shutdown in 12 hours...today they got 7 days. They have had an unrecognized defect in the valve for three weeks now...might be three weeks in the end.

In a real incident it would have to operate under reactor pressure....for this test its only at atmospheric.

Old requirement

...If one or more SDV vent and drain lines have a single valve that is inoperable, the existing required action (Action A) is for the plant to be in hot shutdown within 12 hours.

New

With one SDV vent or drain valve inoperable in one or more lines, the isolation function would be maintained since the redundant valve in the affected line would perform its safety function of isolating the SDV. The current ACTION statement requires the plant to be in hot shutdown within 12 hours if any SDV vent or drain valve is found or made inoperable. The proposed changes are to allow for the isolation of the affected line and continue operation. For a single inoperable valve, the revised Required Action A requires the affected line to be isolated within 7 days (or restore the inoperable valve), or the plant is required to proceed to MODE 3 in the next 12 hours. The 7-day completion time (CT) is acceptable because of the low probability of the concurrent events of a scram within the 7 days of the CT and a failure of the redundant

valves. Alternately, if the inoperable valve was initially closed, there would be ample time and warning available to drain the SDV before an automatic scram would occur due to SDV high level. The proposed addition of Required Action B to address both valves being inoperable in a vent or drain valve is likewise acceptable in that isolation of the affected line provides the safety function and the shorter completion time (8 hours versus 7 days) reflects the increased importance of addressing the problem when multiple valves are inoperable.

Came out this morning...March 4...

Typical delaying tactic..two weeks...trying to buy time before they call it inop. Probably to order parts. It's been inop already for two weeks, but they can play the "we are analyzing it game" before they call it.

Power Reactor	Event Number: 48801
Facility: PILGRIM Region: 1 State: MA Unit: [1] [ ] [ ] RX Type: [1] GE-3 NRC Notified By: KENNETH GRACIA HQ OPS Officer: CHARLES TEAL	Notification Date: 03/01/2013 Notification Time: 17:37 [ET] Event Date: 03/01/2013 Event Time: 10:45 [EST] Last Update Date: 03/01/2013
Emergency Class: NON EMERGENCY 10 CFR Section: OTHER UNSPEC REQMNT	Person (Organization): ART BURRITT (R1DO)

Unit	SCRAM Code	RX CRIT	Initial PWR	Initial RX Mode	Current PWR	Current RX Mode
1	N	Y	94	Power Operation	94	Power Operation

Event Text

24 HOUR NOTIFICATION OF INOPERABLE SCRAM DISCHARGE VOLUME VALVE BASED ON NRC BULLETIN 80-14 "Scram Discharge Volume (SDV) Valve Declared Inoperable. "On March 1, 2013 at 1045 hours, with the reactor at 94% core thermal power (CTP), a scram discharge volume valve, CV-302-22B was declared inoperable as required by station procedural direction due to an observed degradation in opening stroke timing during performance of a compensatory surveillance test of the Scram Discharge Instrument Volume Vent and Drain Valve. This report is provided consistent with NRC IE Bulletin 80-14. "Currently, station engineering is evaluating the valve stroke time trend data of CV-302-22B and plans to address this issue will be developed as part of the Corrective Action Program (CAP). Pilgrim Technical Specification (TS) 3.3.G applies due to the inoperability of CV-302-22B. "This notification is being made in accordance with the NRC IE Bulletin 80-14, 'Degradation of BWR Scram Discharge Volume Capability,' Part A.3., which states, 'By procedures, require that the SDV vent and drain valve be normally operable, open and periodically tested. If these valves are not operable or are closed for more than 1 hour in any 24 hour period during operation, the reason shall be logged and the NRC notified within 24 hours (Prompt Notification).' "A similar event report was generated for the same valve on February 18, 2013. Compensatory measures applicable to the original event report included a revised lubrication application and additional surveillance testing. Although surveillance tests subsequent to the original February 18, 2013 tested demonstrated valve operability, the initial March 1, 2013 test did not meet opening stroke time operability requirements for the valve. Subsequent stroke time testing has met the opening stroke time operability requirements for the valve. "This event has no impact on the health and safety of the public. "The USNRC Senior Resident Inspector has been informed." See similar event EN #48766.

　

Unit	SCRAM Code	RX CRIT	Initial PWR	Initial RX Mode	Current PWR	Current RX Mode
2	N	N	0	Refueling	0	Refueling

Event Text

REACTOR PROTECTION SYSTEM SCRAM SIGNAL DUE TO SCRAM DISCHARGE VOLUME HIGH LEVEL "On 2/16/13, at 0310 EST, with the reactor shutdown for a refueling outage, a full RPS actuation was received on Hatch Unit 2 due to Scram Discharge Volume High level. The Operations crew placed the Unit 2 mode switch to the Start-up/Hot Standby position per approved procedure for the purpose of performing the U2 Refueling Interlock functional test. The cause of the Scram was due to a Scram Discharge Volume high level caused by a malfunctioning SDV drain valve. Hatch Condition Report 591279 has been generated to document the event." The NRC Resident Inspector has been informed.

　

Facility: PILGRIM Region: 1 State: MA Unit: [1] [ ] [ ] RX Type: [1] GE-3 NRC Notified By: MIKE HETTWER HQ OPS Officer: BILL HUFFMAN	Notification Date: 02/18/2013 Notification Time: 16:30 [ET] Event Date: 02/18/2013 Event Time: 05:15 [EST] Last Update Date: 02/18/2013
Emergency Class: NON EMERGENCY 10 CFR Section: OTHER UNSPEC REQMNT	Person (Organization): ANTHONY DIMITRIADIS (R1DO)

　

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

24 HOUR NOTIFICATION OF INOPERABLE SCRAM DISCHARGE VOLUME VALVE BASED ON NRC BULLETIN 80-14 "On February 18, 2013 at 0515 hours, with the reactor at 100% core thermal power, a scram discharge volume valve, CV-302-22B was declared inoperable as required by station procedural direction due to an observed degradation in opening stroke time during performance of quarterly surveillance testing of the Scram Discharge Instrument Volume Vent and Drain Valves. This action was taken consistent with NRC IE Bulletin 80-14. "Currently, station engineering is evaluating the valve stroke time trend data of CV-302-22B and a plan to address this issue will be developed as part of the Corrective Action Program. Pilgrim Technical Specification 3.3.G applies due to the inoperability of CV-302-22B. "This notification is being made in accordance with NRC IE Bulletin 80-14, 'Degradation of BWR Scram Discharge Volume Capability,' Part A.3, which states, 'By procedures, require that the SDV [scram discharge volume] vent and drain valves be normally operable, open and periodically tested. If these valves are not operable or are closed for more than 1 hour in any 24 hour period during operation, the reason shall be logged and the NRC notified within 24 hours (Prompt Notification). "This event has no impact on the health and safety of the public. "The NRC Senior Resident Inspector has been informed." The licensee will inform the State.

　
Hmm, I hope these aren't new valves?

You think this is a coincidence?

They are air operated valves I think?