Connecting the Dots on ANO and Recent Nuclear industry Issues

My theme is there was documented and known issues these plants were entering a abyss by the NRC...but the NRC was prevented to act by Congress. Prevented from seeing the big Picture. I really don't think the rank and file NRC inspector has the requisite education and experience to even be a NRC inspector.   

This all looks like jumping flees to me...Palisades, Vermont Yankee, ANO, Pilgrim and now River Bend and Waterford. 

So basically the function of the NRC is to stay away from a serious off site radiation event(meltdown)...their job is not to keep the industry palatable to the public and orderly. Risk perspectives does that for them. I think the demarcation of a serious accident like TMI and Fukushima is is blurry as hell to the agency and at the plant. More, the danger line is almost unquantifiable, as least through the component worth and isolated risk calculation of components and systems. Basically risk perspectives is worthless.It is grossly oversold as a protect scheme for our nation...

Why doesn't risk perspectives focus the agency to look at the right areas in the below plant events...anticipate these events. Why didn't the NRC informed by risk perspective, step in and knock heads before these events emerged from the bureaucracy of organizations. Really, the events below are seen months and years before the events occur. They are organization centric events, not components, systems and electronics centric events.

Really congress is regulating the plant inspectors and the NRC...limiting their interaction and field of view with the goings on in the plants. We strictly follow the rules, but are we really allowed to see everything and is the plants required to show everything. It more a child's peekaboo going on in the USA between a plant and the NRC.

Jan 2015 Pilgrim

March 2013 ANO

March 2012 San Onofre

June 2011 Fort Calhoun

As example, if the NRC can't anticipate and head off...being situationally aware... in the four plant events above, how do you expect them to head off a meltsown or other significant industry events.

Post findings on these plants for the events, they discovered years of known problems not openly confronted by the NRC. It is as if we got two regulatory policies, one declared and the other not seen by outsider until a big event makes transparent the agency negligence over many years. The truth is, congress never punishes the NRC for allowing a plant to operate outside regulation. The NRC is mostly on the day to day events in these plant a god unto themselves. The big problem is agency knows they are not constrained by higher levels of government. The giant electric utilities are just a too powerful political force unconstrained  political campaign contribution. Really not bounded by the ideals of our perfect constitution. The NRC acts like a totalitarian force for big business, unafraid of getting thrown out of office by the voters. Ultimately they are a power unto themselves and nobody is required to tell the complete truth.       

Why aren't we asking ourselves and NRC, is our NRC just as inflexible as the Japanese's Nuclear Regulatory Authority. Have we regulated the inspectors more than the plants? Is the NRC and the public only getting a very limited field of view...has Congress set up the system for that by campaign contribution. 

January 22, 2016 5:30 pm JST 

IAEA urges Japan to enhance technical competence for nuclear restarts 

TOKYO (Kyodo) -- The International Atomic Energy Agency said Friday that Japan should "strengthen its technical competence," after a team of experts of the U.N. nuclear watchdog concluded a 12-day mission the same day to assess the regulatory framework for nuclear and radiation safety in Japan. 

The country's Nuclear Regulation Authority "needs to further strengthen its technical competence in light of upcoming restarts of nuclear facilities" idled after the 2011 Fukushima nuclear disaster, the team said in its initial report. The final mission report will be released in about three months.

The latest Integrated Regulatory Review Service followed the first review in Japan in June 2007, marking the first assessment since the March 2011 earthquake and tsunami caused the Fukushima nuclear crisis. The NRA was established in 2012 to oversee stricter regulations. 

The team of 19 nuclear experts also found Japanese authorities need to amend relevant legislation to allow the NRA to conduct more effective inspections. 

"What we found is the system that is regulating or defining the framework for inspection is very complex and very rigid," Philippe Jamet, the head of the mission team, said at a joint press conference held by the team and the NRA.
"It doesn't give enough freedom for the inspectors to react immediately," Jamet said. 

Shunichi Tanaka, the chairman of the NRA, said the Japanese regulatory body will work more closely with power companies to improve its inspection operations. 

"We have to talk to operators more thoroughly to improve the inspection method," Tanaka said. 

The mission team also said the NRA should work to attract more experienced staff and strengthen staff skills through education, training and international cooperation...

 Briefing Notes for 95003 Inspection at Arkansas Nuclear One

2:00 pm EST/1:00 pm CST

January 20, 2015

Nuclear Regulatory Commission (NRC) Staff Participants:

• Neil O’Keefe, Branch Chief and 95003 Inspection Team Leader
• John Dixon, Assistant Team Leader
• Brian Tindell, Senior Resident Inspector

Purpose 

To provide a current status of performance regulatory oversight and performance improvement efforts to improve safety performance at the Arkansas Nuclear One nuclear power plant.

Background 

The NRC increased regulatory oversight of Entergy’s Arkansas Nuclear One (ANO) plant in the third quarter of 2014. ANO was placed into Column 4, “Multiple/Repetitive Degraded Cornerstone,” of the NRC’s Action Matrix as a result of having two Yellow findings affecting each of the two plants. The NRC’s color coding indicates that Yellow findings have substantial safety significance. These findings were identified as a result of the events surrounding the industrial accident that occurred at the plant on March 31, 2013, which resulted in one fatality and eight injured personnel. One Yellow finding involved performance deficiencies identified from the event associated with dropping a heavy component and causing significant damage to plant equipment. The other Yellow finding involved performance deficiencies associated with inadequate flood protection of safety equipment that was exposed as a result of plant damage from the heavy component drop.

Event Description 

On March 31, 2013, during a planned Unit 1 outage, the licensee was lifting the Unit 1 main generator stator out of the turbine building when an inadequately designed temporary lifting rig failed, causing the 525 ton stator to fall approximately 30 feet into the train bay. The train bay is shared between Unit 1 and Unit 2. The impact caused substantial damage to the Unit 1 side of the turbine building and power distribution systems, and parts of the lift rig impacted the Unit 2 side of the turbine building.

Yellow Finding Associated with the Heavy Component Drop

The temporary lifting rig collapsed because there were incorrect assumptions and errors in the design such that it could not safely complete the intended lift. A test to verify the capability of the lift rig was not performed due to further errors in communication and decision making. These failures were the result of inadequate oversight of the primary contractor and a subcontractor hired to perform the operation. As a result, there was a complete loss of offsite power to Unit 1 for six days, and Unit 2 partially lost offsite power. This increased risk to the plant because alternate means of providing electrical power to key safety-related systems was not available using installed plant equipment in the event the diesels failed. The NRC determined that this constituted a violation of substantial safety significance.

Yellow Finding for Degraded Flood Protection Features

Following the flooding that occurred during the heavy component drop event, the licensee conducted a comprehensive inspection and identified over 100 deficient flood protection features, including unsealed electrical cable conduits, and degraded hatches and floor plug seals in the auxiliary and emergency diesel fuel storage buildings. NRC inspections subsequently identified additional problems, necessitating further reviews. Both Unit 1 and Unit 2 Safety Analysis Reports (SARs) require that the auxiliary building and safety-related pump rooms be watertight.

The NRC concluded that the licensee had failed to design, construct, and maintain the flood protection features in both units in accordance with the approved design requirements. The finding included multiple violation examples and was determined to have substantial safety significance. The primary contributor to the safety significance was due to the potential safety impact of the theoretical maximum rainfall event, which could lead to core damage due to equipment damage from the degraded flood protection features.

NRC Actions

• The safe operation of the units is the NRC’s primary concern. We have three inspectors onsite that are continuously assessing day to day operation, and we are documenting our assessment that continued plant operation is acceptable in quarterly inspection reports.

• ANO is currently receiving one of the highest levels of NRC oversight designed to ensure that the plant continues to operate safely and performance does not further decline. If safety performance declines further, the NRC will promptly identify and address the decline with regulatory actions up to and including shutting the units down.

• Both the NRC and the licensee are in the process of evaluating the nature and extent of performance issues. We have reviewed the results of each of their evaluations and interim actions to avoid further performance decline.

• The NRC will begin a comprehensive inspection on January 25, 2016. The inspection will involve a team of about 25 inspectors who will spend about 3,600 hours on the effort. This inspection will be an independent evaluation of the extent of the performance problems at Arkansas Nuclear One. We will also assess the licensee’s evaluation of their problems and their proposed corrective actions to ensure they lead to timely and sustained performance improvements.

• We expect to issue an inspection report with the findings and assessments of the team in the spring of 2016. We have tentatively scheduled a public exit meeting for April 6, 201

• April 6, 2016, and will also present the results of the NRC’s annual assessment. Victor McCree, the NRC’s Executive Director for Operations, is expected to attend this meeting.

• The NRC will issue a Confirmatory Action Letter that documents commitments made by the licensee to implement the key corrective actions needed to improve safety performance. The NRC will then conduct inspections to verify the completion and effectiveness of those corrective actions as the actions are completed.

• Based on past experience with plants with similar performance problems, we expect it will take ANO 2 to 3 years to complete the actions needed to demonstrate a sustained improvement in safety performance. The NRC will not reduce the level of oversight until ANO has completed those key actions designated in the Confirmatory Action Letter and the NRC inspections confirm that those actions were effective.

ANO Actions

• ANO has been effective in running the units safely and not allowing the recovery efforts to detract from safe plant operation.

• ANO has completed an extensive series of evaluations to identify the causes for declining safety performance, and has developed, prioritized, and scheduled corrective action to address those causes. These evaluations were performed with the help of nuclear industry experts from outside the company to assist in recognizing areas where ANO and Entergy have not been following industry practices.

• ANO has recognized that their top issue affecting performance involves ensuring that the necessary resources are provided to accomplish station programs and processes in a safe and effective manner (for example, vendor/contractor oversight, increasing backlogs, and equipment maintenance). They have added more than 100 workers and have brought in consultants to assist with its performance improvement and recovery effort.

• The NRC will issue a Confirmatory Action Letter that documents commitments made by the licensee to implement the key corrective actions needed to improve safety performance. The NRC will then conduct inspections to verify the completion and effectiveness of those corrective actions as the actions are completed.

Who Wants River Bend’s Junk Capacity Factor?

Update 1/27

Is River Bend ever going to startup again? This is the big problem as far as the industry's financial problems.

What the Nuclear Energy Institute (NEI) Says About the Nuclear Industry's Death Spiral

 

Update 1/24

Still shutdown today? Have they made money in the last two years? 

***This shutdown must have caused a lot of damage? Eleven days and counting?  

Special Inspection in 2015 Didn't Fix a Thing at Crap Plant River Bend

Event Date: 01/09/2016

 

Junk Pilgrim Prepared For Storm, Operators Say

It would take at least 4 to 6 hours to bring about a orderly shutdown and cool down.

It would be so cool for the plant to trip today and LOOP? Would this be the last shutdown in the life Pilgrim plant. :)

None of this is based on real engineering, engineering assurance it could survive Blizzard. Although I believe Entergy is worried about if Gov Baker begins to turn on them. It is all a grand NRC experiment.  

 

Who cares if Entergy is going to permanently shutdown within a year. or so.

..."the Nuclear Regulatory Commission spokesman said Friday that procedures for addressing storms have been tightened since last year."

It is interesting the grid prices spiked up this early morning. Is it a result of normal winter condition approaching the coast or has the grid anticipated losing Pilgrim:)

 

Maybe Entergy wants the NRC to shutdown the plant...blame them for permanently shutdown the plant.   

NUCLEAR SAFETY

Pilgrim prepared for storm, operators say

The protocol has been tightened in the year since a blizzard-induced shutdown at the plant, a Nuclear Regulatory Commission spokesman says.

By Christine Legere

Posted Jan. 22, 2016 at 5:45 PM
Updated at 9:17 AM

PLYMOUTH — Operators at Pilgrim Nuclear Power Station say they are ready for whatever the fast-traveling snowstorm heading up the East Coast this weekend, with accompanying 60 mph winds, brings their way.

“We are monitoring the storm closely and have begun preparations under our coastal storm protocol,” Entergy Corp., the plant’s owner-operator, said Friday in a statement provided by spokesman Patrick O’Brien.

One provision in the newly beefed-up storm plan calls for a pre-emptive shutdown based on the severity of the storm. “It has to do with wind speeds and the rate of snowfall,” Neil Sheehan, spokesman for the Nuclear Regulatory Commission, wrote in an email Friday.

Entergy is holding off on that decision for now. “The currently projected storm path and weather conditions do not meet the criteria for a pre-emptive shutdown of the station,” the company statement said. “We will continue to monitor the storm closely and have appropriate staff and other resources available should conditions change.”

The Pilgrim plant's 220-foot primary meteorological tower is still out of service, awaiting a part expected to be installed in February, according to Sheehan. The smaller backup tower will provide plant operators with vital information on wind velocity and direction.

That second tower had been inoperable for several years and was just recently replaced. The plant must rely on the National Weather Service in Taunton whenever a single tower goes down and lacks backup.

Representatives of the Plymouth Fire Department were at the nuclear plant earlier this week to review storm preparations, according to the town’s emergency management director, Aaron Wallace.

It has been just about a year since a blizzard tore through the Northeast, knocking out power at Pilgrim. Problems began with electrical arcing in the switchyard, where power is brought to the plant and sent from the plant to the grid. Such switchyard problems date back as long as 30 years.

Operators shut down the reactor during that January storm, but problems persisted, with the failure of a diesel-driven air compressor, a leaking safety valve used to depressurize the reactor, failure of a manually operated safety relief valve and failure of the high-pressure coolant injection system, which then leaked an inch of water onto the floor.

Sump pumps could not clear it, since all nonvital functions at the plant had been shut down.

The series of malfunctions during that storm prompted a week of federal inspections and contributed to the downgrade of the Pilgrim plant by NRC officials in September to among the three worst performers in the country.

Entergy announced in October its plan to permanently shut down the Pilgrim reactor sometime before June 2019.

Although some plant watchdogs warn there is no longer any impetus for Entergy to stay on top of plant maintenance, the Nuclear Regulatory Commission spokesman said Friday that procedures for addressing storms have been tightened since last year.

“We have a resident inspector at Pilgrim who is continuing to closely track storm preparations,” Sheehan wrote. “For instance, site walkdowns were conducted yesterday to check for any loose debris that could be tossed by strong winds and impact the switchyard or plant infrastructure.

“Also, a change put in place since last winter’s storms is the installation of heat lamps in the switchyard to prevent the kinds of electrical arcing events that have occurred in the past,” Sheehan continued. “We will be paying attention to the heat lamps’ effectiveness should they be needed during this storm.”

David Lochbaum, director of the Nuclear Safety Project for the Union of Concerned Scientists, said the switchyard is always vulnerable to winds and icing. “The backup generators are the real safety net,” he said. “If they work, they effectively cool the reactor. Because of the problems in the past, (Pilgrim operators) may be more prepared and have a longer list of backups.”

Storm Jonas 2016: Is Junk Plant Pilgrim Shutting Down?

Update The day after 1/24

The definitive answer from the NRC tonight. Lots of nuke plants had lots of trouble with weather this storm.
 

…”there have been no significant impacts at the facility”: depends on what their definition of “no significant impacts at the plant” means. I'd like them to describe all storm related impacts at the plant.    

  NRC: Update: As the Blizzard Moves Out of the Mid-Atlantic
Just North of Pilgrim.

The Weather Service recorded a wind gust of 70 miles per hour at the municipal airport in Marshfield.

So far it looks like Pilgrim stayed up at power. Course Plymouth got only grazed by storm Jonas. But...

Update, 6 p.m.
PLYMOUTH MA — Eversource crews on Saturday night restored power to all but about 100 customers after a snowstorm knocked out power to over 1,000. 

Winter Storm Jonas brought blizzard conditions that knocked out power for more than 1,000 in Plymouth Saturday afternoon. 

Boston Globe:

"Boston can expect the snowflakes to start falling between noon and 2 p.m. Temperatures will hit a high of about 30 degrees and a low of about 20 at night, said Frank Nocera, a National Weather Service meteorologist.

Nocera said the highest snow totals from the storm would be in the southeastern part of the state, where 8 to 12 inches of snow can be expected. The storm will also feature high winds that may bring down power lines and the possibility of coastal flooding, forecasters said."

Remember Pilgrim last year didn't trip after many hours of brutal blizzard conditions. It wasn't a really bad blizzard and much snow accumulation. The plant tripped right at the beginning of the blizzard.

Accuweather says Plymouth is going to get more than two hours of heavy snowfall this afternoon.

The red outlined area is the National Weather Service's "Winter Storm Warning".  Storm Jonas has intensified much more than anticipated in the models. South Shore Massachusett just a few hours ago wasn't supposed to get any snow at all.

Winter Storm Warning remains in effect until 7 AM EST Sunday.

• Locations: Kent and Bristol counties in Rhode Island and coastal Plymouth County. Cities and towns in the warning include Plymouth, West Greenwich, Warwick. Bristol.
• Hazard types: Heavy snow.
• Accumulations: snow accumulation of 4 to 8 inches.
• Timing: snow will develop around mid morning and become heavy at times in this afternoon and evening. Snowfall rates up to one inch per hour will be possible at times. Gusty winds up to 45 mph combined with the snow will result in blowing snow and poor visibilities at times. The snow will begin to taper off after midnight.
• Impacts: hazardous travel with heavy snow and poor visibilities. Heavy snow combined with strong winds may result in isolated power outages.
• Winds: northeast 25 to 35 mph with gusts up to 55 mph.
• Temperatures: in the upper 20s.
• Visibilities: one quarter mile or less at times.

Junk Safety Culture Still At Arkansas Nuclear One

This guys are bad. Can you believe the violation level from the NRC??? The risk determination system is completely broken down by political intervention. This is Flint Michigan.   
Just to be clear, ANO and Pilgrim are the worst operating nuclear power plants in the USA. There are owned by Entergy.  Where is your dignity?  

ARKANSAS NUCLEAR ONE– NRC INSPECTION REPORT 05000313/2015003 and 05000368/2015003

Findings  

Introduction. The inspectors reviewed a Green self-revealing non-cited violation of 10 CFR Part 50, Appendix B, Criterion V, “Instructions, Procedures, & Drawings,” for failure to follow the instructions in the chemical volume control system charging pump pulsation dampener bladder charging procedure. Specifically, the licensee used a gas cylinder containing argon, carbon dioxide, and oxygen rather than a pure nitrogen cylinder to charge the dampener. The gas leaked into the reactor coolant system and was subsequently activated by neutrons. Reactor coolant system activity significantly increased, which elevated dose rates in the auxiliary building. 

Description. The Unit 2 chemical volume control system charging pumps have suction and discharge dampeners to reduce pressure pulsations caused by these positive displacement pumps. These dampeners are an accumulator tank with a nitrogen filled bladder. Nitrogen leakage through the bladder can result in the nitrogen entrainment in the water, which is pumped into the reactor coolant system. The licensee had been aware

It's the absence of a fix it quickly philosophy. The longer you got a mechanical defect in a system with degraded safety culture the greater the chances of a bigger problem popping up.

of leakage from the dampeners and had implemented quarterly preventative maintenance tasks to check the pressure and fill the dampeners with nitrogen, if necessary. 

On July 31, 2015, a reactor coolant sample indicated a rising trend in argon-41.  argon-41 is a radioactive isotope of argon that is created when argon-40 in reactor coolant passes through the reactor and becomes irradiated. It undergoes decay, giving off a high-energy beta particle, increasing dose rates in the plant. A failure mode analysis team investigated the possible causes and identified the most likely cause to be a leaking charging pump dampener bladder filled with the incorrect gas. 

On September 3, 2015, the licensee performed gas chromatograph sampling on the 2P-36C charging pump suction and discharge dampeners. Although the test equipment cannot test for percent argon content, the test determined that the suction dampener only had a 14.4 percent nitrogen content. The discharge dampener only had a 15.4 percent nitrogen content. If the dampeners were charged with nitrogen as expected, the content would be expected to be over 90 percent nitrogen. The licensee recharged the pulsation dampener with pure nitrogen, and dose rates in the plant returned to normal. 

The addition and subsequent activation of argon caused the reactor coolant activity to increase by a factor of three over a period of two months. This increased the dose rates in the vicinity of piping associated with the chemical and volume control system, increasing dose to operators and radwaste personnel. 

The licensee performed a cause analysis and determined that a human performance error caused the wrong gas to be used. Plant maintenance mechanics had performed pulsation dampener preventative maintenance on July 28, 2015. The mechanics retrieved a pressure gauge from the hot machine shop and went to the compressed gas cylinder storage rack. The mechanics measured pressure in the cylinders and chose the first cylinder that contained sufficient gas. The mechanics then proceeded to 2P-36C charging pump dampener fill connection, connected the cylinder to the charging header, and recharged the pulsation dampeners. 

All of the gas cylinders in this storage location were the same color, and the labelling appeared similar unless read carefully. The mechanics failed to check the label on the gas cylinder to ensure that they chose a nitrogen bottle, and they incorrectly chose the single cylinder that contained a mixture of carbon dioxide, oxygen, and argon. 

The licensee revised the procedure to require independent verification of the gas prior to charging pulsation dampeners. 

Chemistry samples confirmed there was no change in oxygen content in the reactor coolant. 

Analysis. The failure to follow the pulsation dampener charging procedure, which resulted in increased reactor coolant system activity and elevated dose rates in the auxiliary building, was a performance deficiency. The performance deficiency is more than minor because it was associated with the plant facilities/equipment attribute of the Occupational Radiation Safety Cornerstone and adversely affected the cornerstone objective to ensure the adequate protection of the worker health and safety from exposure to radiation from radioactive material during routine civilian nuclear reactor operation. Specifically, charging argon into a pulsation dampener with a known bladder leak resulted in an increase in reactor coolant activity, causing elevated dose rates in several plant areas. Using NRC Inspection Manual Chapter 0609 Appendix, C, “Occupational Radiation Safety Significance Determination Process,” issued August 19, 2008, the inspectors determined that the finding was of very low safety significance (Green) because it did not involve ALARA planning or work controls, did not involve an overexposure, did not have a substantial potential to be an overexposure, and the ability to assess dose was not compromised. The inspectors determined this finding had a cross-cutting aspect in the human performance area, Avoid Complacency, because the plant maintenance mechanics failed to implement appropriate error reduction tools such as self-checking and peer-checking. [H.12] 

Enforcement. Title 10 CFR Part 50, Appendix B, Criterion V, “Instruction, Procedures, & Drawings,” states that “Activities affecting quality shall be prescribed by documented instructions, procedures, or drawings, of a type appropriate to the circumstances and shall be accomplished in accordance with these instructions, procedures, or drawings. Instructions, procedures, or drawings shall include appropriate quantitative or qualitative acceptance criteria for determining that important activities have been satisfactorily accomplished.” Contrary to the above, on July 28, 2015, the licensee failed to accomplish an activity affecting quality in accordance with the procedure. Specifically, the licensee failed to charge a charging pump pulsation dampener, an activity affecting quality, with nitrogen as required by quality Procedure OP-2411.066, “Charging Pump Dampener Bladder 2M-115A, B, C and 2M-116A, B, C Charging, Checking and Depressurization,” Revision 5, Attachment 3, Supplement 1. Step 1.3 of this procedure required that nitrogen be connected to the charging pump pulsation dampener supply valve during the charging process, but a bottle with a mix of gases including argon was used instead. The error resulted in a significant increase in reactor coolant activity, with a resulting increase in dose rates in various areas of the plant. As corrective action, the licensee recharged the dampener with pure nitrogen and degassed the reactor coolant system to reduce dose rates in the plant. This violation is being treated as a non-cited violation (NCV), consistent with Section 2.3.2.a of the Enforcement Policy because it was of very low safety significance (Green) and it was entered into the licensee’s corrective action program as Condition Report ANO-2-CR-2015-02576: NCV 05000368/2015003-01, “Failure to Follow Procedure Results in Increased Reactor Coolant Activity.”

***"On August 18, 2015, the licensee identified an adverse trend in unsecured doors, as documented in Condition Report CR-ANO-C-2015-03229. Specifically, the condition report documented that 15 condition reports had been written since May 1, 2015, for fire or high energy line break doors found open and unattended. The licensee addressed this trend by conducting a personal interface campaign at the plant entry area. As persons entered the station, managers stopped them, discussed the importance of barriers, and handed them a one page document with further information on why barriers are important to safety. In addition, departmental managers were given an action to develop a plan to verify or improve employee behaviors. Following these actions, two more condition reports identified doors that had been left open. Station management held a stand down on September 28, 2015, with all station employees to ensure that they understood the importance of door design and configuration.'

The inspectors found that the station had appropriately identified the adverse trend in regards to station behaviors, but had failed to document an adverse trend in the number of documented door deficiencies. In the past year, 31 condition reports documented deficient conditions on doors required for security, fire, high energy line break or flooding. Although the licensee failed to identify the trend, the inspectors determined that the licensee was addressing the conditions appropriately in the work management system. The licensee documented the observation in Condition Reports CR-ANO-C-2015-03972 and CR-ANO-C-2015-03973.

This whole thing is frightening as hell below. Basically defective breakers and buses interacting with a roof leak....plus the issue gets lost in the bureaucratic document system. Instead of bureaucracies and documentation systems shining a light on problems early, it digs a big hole and buries the problems.  Roof leaks are  prime evidence of a severe safety culture problem. How long was the roof leak and why didn't the NRC step in before it damaged the bus and breaker?   

Another non sited violation to their buddies ...

***Introduction. The inspectors reviewed a self-revealing violation of 10 CFR Part 50, Appendix B, Criterion XVI, “Corrective Action,” for the failure to promptly identify and correct conditions adverse to quality. Specifically, the licensee failed to promptly replace short bus stabs with longer bus stabs in six safety-related motor control centers (MCCs) following a 2007 motor control center fault.

Description.

On April 21, 2015, non-safety MCC 2B-35 experienced a fault which melted bus bars and caused the feeder breaker to the MCC to open to isolate the fault, de-energizing multiple non-vital loads in the turbine building. Subsequent inspection and analysis determined that the fault was caused by a high resistance connection between the breaker for turbine building recirculation fan and the associated bus bars. Contributing to this condition, the licensee observed indications that water had dripped onto the bus bars from above from turbine building roof leaks. This event led the licensee to review a previous similar event and to assess the corrective actions for that event.

In October 2007, a fault had occurred in a Unit 2 motor control center when starting a charging pump, which tripped the motor control center feeder breaker and secured power to all the loads supplied by that motor control center. The licensee documented in Condition Report CR-ANO-2-2007-01512 that the cause of the fault was “limited physical stab engagement on bus”. The limited contact area between the breaker stabs and the bus bars was determined to be marginal for the current needed to run the charging

Seabrook at 60% and ISO Prices

Update1/22

Good job Seabrook with getting back to 100% yesterday. The NEISO is at around $39 per megawatt hour. The price is shockingly low for such a cold spell. When is the businesses and ratepayer going to get a break?

***So Seabrook has been at 60% for three days. What is up?

I continue to be amazed by how docile the price of electricity has been throughout the mild winter and now in a deep winter cold spell. It is amazingly cheap. No big spikes in prices as has been the last winters...

It is amazing how much media and print time is devoted to solar and wind. It is such a small percentage of net generation...

Industry News & Developments

Wholesale electricity prices and demand in New England

Friday, January 30, 2015 at 1:54PM

Year-over-year natural gas and wholesale power prices dropped in December on milder weather, lower demand

December’s average natural gas and wholesale power prices in New England were about half as much as the average monthly prices recorded during December 2013, due largely to milder weather that dampened demand. During December 2013, colder weather increased consumers’ use of natural gas for heating, resulting in natural pipeline constraints that drove natural gas prices higher. Those high fuel prices, in turn, pushed up wholesale power prices.
This past December, the average real-time price of wholesale power, at $42.47 per megawatt-hour (MWh)*, fell about 57% from the December 2013 average of $98.53/MWh. It was down by about 5% from November’s price of $44.86/MWh...

Cooper Junk SRVs: 63% Failed Technical Specification Safety Testing

***Update 1/19

Spoke to Cooper's "new" senior resident inspector and the seasoned resident on the phone this afternoon for about 20 minutes. I swear the women are taking over the world(good). She said she is evaluating the LER update as we speak...LER 2015-001-01. Basically the below was my talking points. I gave her this blog's address.... 

I asked how close Cooper is to their MAPI...the SRV piping stresses when outside Tech Specs.

Looking forward to the new inspection report.

***updated 1/17

"Or the fix could be as simple as cycling each SRV open and close once every month to disrupt the oxidize bonding"

The NRC are supposed to be sticklers for details and telling the truth...

Right, Hope Creek this testing period had a 71% failure rate and Cooper has a 63% failure rate...kind of in the ball park, you think each? 

The drastic increase in failures compared to the last four outages should should raise the hairs on the back of your head. Any ethical engineering report like this should openly question this drastic increase and vow to immediately fix it. Why didn't they mention this in the report...what else is Cooper habitually not confronting and fixing at the plant? How come in Mrs Bower's letter to me on Hope Creeks SRV problems he didn't discuss the increase in setpoint accuracy problems? I just saying he is not discussing the painful truth... It is like he is a advertising executive and not a federal regulator. How many SRVs would have failed testing if the limits were +/- 1% or didn't have a stellite coating the on seat and valve? The +/- 3% and Stellite coating is accommodating these defectively designed valves. It is just giving a illusion they fix the problem.  It is destructive "Normalization of Deviance" on steroids. It is a common organizational mental illness.  

On the second SRV going INOP Cooper needs to be shutdown in 24 hours. 

You get it, a ethical organization(s) would never preform an experiment on nuclear power plant safety equipment. They would put the stellite coated internals and valve on a test stand and exactly model the environment and length of duty as in the nuclear plant. They would put the valve in a much more harsh environment than the plant, so the problems would be exaggerated. Then they would test the valves just like they do when it comes out of the nuclear plant. They'd never put that stellite into a nuclear plant without being 1000% sure how the stellite would perform. It would fix the lift setpoint accuracy problems. I am telling you something stinks rotten here.      

LER 2015-001-01: 5 failed TS safety testing 

LER 2011-005-00: 1 failed TS safety testing  

LER 2010-001-00: 2 failed TS safety testing 

LER 2008-002-00: 1 failed TS safety testing  

LER 2008-002-00: 1 failed TS safety testing

Licensee Event Report No. 2015-001-01

***Read what this below sentence in the LER. This is Coopers title of the document. The NRC wants me to make believe these below 16 words don't matter.  Ask Cooper what they are required to do in this case if they find this specific "condition prohibited by technical specification while at power". They are required to emediately shutdown. This is all "Catch 22" crazy circular logic. Right, "a loss of safety function.

Right, it like your brake peddle goes almost down to the floor. It wasn't like that a day ago. Once you put your foot on the peddle it emediately began braking is what it was a day ago. You test your braking power by slamming on the brakes. The car quickly stops like it should. Come on, but are you safe by ignoring this new problem. Normal people's alarm horns would loudly be going on their heads. They would quickly take the car to a mechanic and drive much more slowly while getting it to them.      

Valve Test Failures Result in a Condition Prohibited by Technical Specifications and a Loss of Safety Function

PLANT STATUS

Cooper Nuclear Station (CNS) was in Mode 1, Power Operation, at 100 percent power, when the event was discovered; i.e., January 26, 2015.

BACKGROUND

The pressure relief system includes three American Society of Mechanical Engineers code safety valves (SV) [EllS: SB] and eight safety relief valves (SRV) [EllS: RV], all of which are located on the main steam lines [EIlS: SB] within the drywell [EllS: NH], between the reactor vessel [EllS: RPV] and the first main steam isolation valve [EllS: ISV]. The SVs provide protection against over pressurization of the nuclear system and discharge directly into the interior space of the drywell. The SRVs discharge to the suppression pool and provide three main functions: overpressure relief operation to limit the pressure rise and prevent safety valve opening, overpressure safety operation to prevent nuclear system over pressurization, and depressurization operation (opened automatically or manually) as part of the emergency core cooling system [EllS: B J, BM, BO].

Technical Specification (TS) Limiting Condition for Operation 3.4.3 requires the safety function of seven SRVs and three SVs to be operable. The nominal set pressure and tolerances for these valves are established in CNS TS Surveillance Requirements (SR) 3.4.3.1.

The SRVs installed at CNS are Target Rock Model 7567F, two-stage, pilot-actuated valves with pilot assemblies comprised of Stellite 21 pilot discs and Stellite 6B pilot body seats. The pilot assemblies had been in continuous service since installation in Refueling Outage (RE) 27.

Corrosion bonding occurs when the protective oxide layers of the seat and disc break down and allow a crevice corrosion process to develop between the seat and disc. The seat is machined and then lapped with the disc to create a tight fit with one another. During the material removal process (machining) on both the seat and disc, the protective oxide layer that provides corrosion protection is removed. Because the SRV pilot valves are then assembled, the oxide layer is not given sufficient time to reestablish itself naturally, and no external process, such as pickling, is done to ensure that the oxide layer is reestablished to its full extent without any breaks or discontinuities. When the SRV pilot valves are assembled, the seat and disc are jammed together and air cannot reach the surfaces, therefore the full benefits of the oxide layer of the anti-corrosion material is diminished.

EVENT DESCRIPTION

On January 26 and February 11, 2015, three complete SRVs and five SRV pilot assemblies, removed during RE28 in the Fall of 2014, were as-found tested at National Technical Systems Laboratories, formerly Wyle Laboratories.

The pressure setpoint for SRV pilot assembly serial number 385 is 1090 psig. The TS SR 3.4.3.1 as-found limit of acceptance is 1090 +/- 3%. The first actual lift pressure of this SRV pilot assembly was recorded as 1124 psig, 3.119% above the pressure setpoint. For informational purposes, the technicians performed a second and third lift. The results were 1087 psig and 1087 psig, both within 3% of the pressure setpoint.

The pressure setpoint for SRV pilot assembly serial number 386 is 1100 psig. The TS SR 3.4.3.1 as-found limit of acceptance is 1100 +/- 3%. The first actual lift pressure of SRV number 386 was 1192 psig, 8.36% above the pressure setpoint. A second and third lift was performed and the results were 1108 psig and 1112 psig, both within 3% of the pressure setpoint.

The pressure setpoint for SRV pilot assembly serial number 1242 is 1090 psig. The TS SR 3.4.3.1 as found limit of acceptance is 1090 +/- 3%. The first actual lift pressure of this SRV pilot assembly was recorded as 1267.7 psig, 16.24% above the pressure setpoint. The results of a second and third lift were 1091 psig and 1090 psig, both meeting the pressure setpoint.

After this failure, testing was halted in order to verify testing accuracy. Testing was found to be the same as used in years past, and testing resumed on February 10 and February 11 for the remaining five SRVs.

The TS SR 3.4.3.1 as-found limit of acceptance for SRV pilot assembly serial number 1243 is 1100 psig +/- 3%. The first actual lift pressure of this SRV pilot assembly was recorded as 1139 psig, 3.545% above the pressure point. For informational purposes, a second and third lift was performed. The results were 1112psig and 1105 psig, both meeting the pressure setpoint.

SRV pilot assembly serial number 1241 was tested. The TS SR 3.4.3.1 as-found limit of acceptance is 1090 psig +/- 3%. The first actual lift pressure of this SRV pilot assembly was recorded as 1138 psig, 4.404% above the pressure point. A second and third lift was performed. The results were 1106 and 1092 psig, both meeting the pressure setpoint.

BASIS FOR REPORT

CNS is reporting this event as an operation or condition prohibited by plant TS per 10 CFR

50.73(a)(2)(i)(B), and also as a condition that could have prevented the fulfillment of the safety function of structures or systems as defined under 10 CFR 50.73(a)(2)(v).

An existing engineering analysis demonstrated that the reactor vessel would not be challenged during an overpressure event. In addition, a new analysis determined that the existing Minimum Critical Power Ratio (MCPR) operating limit would have protected the MCPR safety limit in the event of an anticipated operational occurrence. As such, this event will not be counted as a Safety System Functional Failure for the Nuclear Regulatory Commission performance indicator since no loss of safety function occurred.

SAFETY SIGNIFICANCE

Although the TS related to the set point lift pressures of the SRV pilot valve assemblies were exceeded, an analysis of this event indicates that the design basis pressures to ensure safety of the reactor vessel and its pressure related appurtenances would not be challenged. Public safety was not at risk. Safety to plant personnel and plant equipment were not at risk.

CAUSE

The direct cause of five of eight SRV pilot valves failing their lift tests is corrosion bonding.

CORRECTIVE ACTIONS

The following corrective actions have been entered into CNS' corrective action program:

1. CNS shall inspect the SRVs during disassembly to ensure there are no indications of binding, vibration, or other mechanical problems that might cause effects similar to that of corrosion bonding.

2. Laboratory work, under the direction of CNS, shall be undertaken to confirm or deny corrosion bonding of the disc and seats as needed. A comparison with previous laboratory findings about SRV pilot valves will be performed to determine, if possible, the role time in-service played in the failures.

3. Based on the results of the inspection and laboratory work, specific findings and corrective action recommendations in the form of a revised root cause investigation report will be completed.

4. If no evidence to refute corrosion bonding is identified, ensure after machining and lapping processes have been completed, that the oxide, passive layer on the seat and disc are fully restored by pickling or an equivalent process.

5. Presuming that no technical reason is discovered to prevent the following, submit to the Nuclear Regulatory Commission a Technical Specification change that requests setpoint changes as noted in EE 10-053; NEDC-33 543P, Revision 0, Class Ill, DRF 0000-0103-4647, dated February 2010; GE-H NEDC-3362OP, Revision 0, May 2011; and GE-H, report 002N5242-R0, entitled, Cooper Cycle 28 SRV Set Point Study.

PREVIOUS EVENTS

Licensee Event Report (LER) 2011-005-00 - On June 22, 2011, one of eight Target Rock SRV pilot valve assemblies failed to lift within TS lift setpoint requirements. Wyle Laboratories performed this testing. The pressure setpoint of the failed pilot assembly was 1090 +/- 32.7 psig; it lifted at 1199 psig. Two subsequent informational lifts were performed for the SRV pilot assembly and were within the TS pressure setpoint tolerances. The mechanistic cause was the same as reported in previous LERs, pilot disc-to-seat corrosion bonding.

LER 2010-001-00 - On January 12, 2010, two of eight Target Rock SRV pilot valve assemblies failed to lift within TS lift setpoint requirements. Wyle Laboratories performed this testing. The pressure setpoint for the first pilot assembly is 1100 +1- 33.0 psig; the SRV pilot assembly lifted at 1166 psig. The pressure setpoint for the second pilot assembly is 1090 +1- 32.7 psig; it lifted at 1139 psig. Two subsequent informational lifts were performed for both SRV pilot assemblies and were within the TS pressure setpoint tolerances. The mechanistic cause was the same as reported in previous LERs, pilot disc-to-seat corrosion bounding.

LER 2008-002-00 - On July 7 through July 9, 2008, the results of Target Rock SRV test data performed at Wyle Laboratories identified that one of eight SRV pilot assemblies failed as-found pressure setpoint testing. The SRV pilot assembly lifted at 1165 psig, outside its TS setpoint tolerance of 1100 +/- 33.0 psig. The mechanistic cause was pilot disc-to-seat corrosion bounding between the Stellite 21 pilot disc and Stellite 6B pilot body seat to cause the SRV pilot assembly to lift outside its TS setpoint tolerance.

LER 2007-002-00 - On February 28 through March 2, 2007, the results of Target Rock SRV tests performed at Wyle Laboratories identified that one of eight SRV pilot valve assemblies failed to lift within its TS lift setpoint of 1090 +/- 32.7 psig. The failure was a result of sufficient corrosion bonding between the SRV pilot valve assembly Stellite 21 disc and the pilot valve Stellite 6B body seat to cause the SRV pilot valve to lift outside its TS setpoint tolerance.

NRC: Indian Point Is Obstinate With Safety Pipe leaks

So I believe outsiders and I have caused this audit. I am particularly irked with the recent fire water leak in Unit 1 wasn't made into LER. The NRC told me in Indian Point's fire water and service water re-licensing responses to them, it felt like Entergy was just babbling to them. They were giving the agency incomplete answers to the NRC questions. So the NRC was irked at Indian Point.

Ultimately what is wrong here, Indian Point put in improper and cheap fire water and service water pipe metal. They are accommodating this safety deficiency by replacing piping sections as leaks develop. They think it is the cheapest fix. They should have took a prolong shutdown decades ago to completely replace all fire water and service water piping with modern corrosion resistance piping. The piping leaks have gotten out of control. The accommodating strategy has taken resources away from other areas. This accommodation eats up employees and resources...it ultimately weakens the organization and the bureacrocy. They got runaway piping leaks at the plant plus bureaucracy problems. The best solution for the health of the bureaucracy, is you cut off the destructive complexity by replacing the piping. Are they systemically accommodating across many other areas? Then you got very few new problems with proper new pipes and little headaches with a regulator trying to jack up your complexity by pushing you into more employees, inspections and complexity caused by a improper accommodation strategy. You get what I talking about, the improper accommodation strategy slowly blinds a bureacrocy with excessive complexity. You just are juggling too many balls in the air. You are effectively stealing money from the future to support the past and the now.                 

"The corrective actions were to weld repair the affected piping followed by replacing piping with very corrosion resistant material(AL6XN)."

They had to shutdown units two's fire water for two hours. They discovered the beginning or the leak in 2008 and it got lost in their terrible work document system until a huge pipe blew out. At one point, they brought a crew into the plant to replace the weaken section of pipe with the small pin hole leak in it. They botched the replacement job, they neglected (screw-up) to replace the leaking section of pipe...it was scheduled to be replace and they replaced the wrong section of expensive pipe. 

NRC INTEGRATED INSPECTION REPORT 05000247/2015001 AND 05000286/2015001
(pg 27)The inspectors reviewed corrective action documents and WOs for identified degradation of the fire protection piping and conducted a walkdown to assess the material condition. In 2010, Entergy generated CR-IP2-2010-5187 due to the discovery of a through-wall leak in the fire protection piping downstream of valve FP-2. This leak was discovered during a UT conducted as extent of condition for a nearby through-wall leak documented in 2008 (CR-IP2-2008-0044). Entergy created WO 135106 to replace the corroded and corroding piping section. In November 2012, the WO was in a ready status and scheduled to be worked. Due to problems obtaining effective isolation for protective tagging due to valve leak-by, the repair was postponed and the work was not done. Entergy had planned a major maintenance outage for the fire protection system for May 2014 to repair leaking valves and sections of corroded piping. Despite being within the isolation boundary and ready to work, the section of piping containing the 2010 leak was not included in the scope of this work. WO 135106 was instead scheduled following Unit 3 3R18 RFO. The inspectors noted that Entergy did not consider the remaining service life of the degraded piping section when delaying the repair from 2012 to 2015. This issue was entered into Entergy’s CAP as CR-IP2-2014-6668.

That is the trouble with organizational bureaucrats...NRC and Entergy...they think the system is safe just if the paperwork is filled out and complete. The get a grade of "A+" for finding the leak, getting it in the document system and getting resources into the plant to replace the pipe...they got a "E -" for improperly executing the plant in excellence. The leak just got completely lost in the bureaucracy and their work document system. Basically the system is riddled with destructive and massive levels of priorities with too little resources. It is a too complex system with not enough funding. If they don't have enough money to properly run the facility, they just jack up the rules and procedure to compensate for what they don't have. Stick it in the beast slowly digesting facts and we won't have to spend money on the piping leaks for many years.        

We only get a terrible skimpy NRC inspection over this. We are overly dependent on the NRC disclosing these problema. What do they got, three or four NRC inspectors on the site. They got somewhat like a 1000 Entergy employees on the site. Who is likely to catch the problem first?  

December 21, 2015

Vice President, Operations

Entergy Nuclear Operations, Inc.

Indian Point Energy Center

450 Broadway, GSB

P.O. Box 249

Buchanan, NY 10511-0249

SUBJECT: PLAN FOR THE REGULATORY AUDIT OF THE SERVICE WATER INTEGRITY AND FIRE WATER SYSTEM AGING MANAGEMENT PROGRAMS PERTAINING TO THE INDIAN POINT NUCLEAR GENERATING UNIT NOS. 2 AND 3 LICENSE RENEWAL APPLICATION (CAC NOS. MD5407 AND MD5408)

Dear Sir or Madam:

By letter dated April 23, 2007, as supplemented by letters dated May 3, 2007, and June 21, 2007, Entergy Nuclear Operations, Inc. (Entergy), submitted an application pursuant to Title 10 of the Code of Federal Regulations Part 54, to the U.S. Nuclear Regulatory Commission

(NRC) for renewal of the operating licenses for Indian Point Nuclear Generating Unit Nos. 2 and 3 (IP2 and IP3). The NRC staff documented its findings in the Safety Evaluation Report (SER) related to the license renewal of IP2 and IP3, which was issued August 11, 2009 and supplemented August 30, 2011 (SER Supplement 1), and November 6, 2014 (SER Supplement 2). Subsequent the issuance of SER Supplement 1, the NRC staff identified additional operating experience at several nuclear power plants regarding recurring internal corrosion, corrosion occurring under insulation, and managing aging effects for fire water system components. To address this operating experience, on November 22, 2013, the NRC staff issued interim staff guidance document LR-ISG-2012-02, “Aging Management of Internal Surfaces, Fire Water Systems, Atmospheric Storage Tanks, and Corrosion Under Insulation.” In accordance with the enclosed audit plan, the NRC staff plans to conduct an onsite audit of the service water integrity and fire water system aging management programs during the week of February 22, 2016. If you have any questions, please contact me by telephone at 301-415- 6459, or by e-mail at michael.wentzel@nrc.gov.

Sincerely,

/RA/

Michael J. Wentzel, Project Manager

Projects Branch 2

Division of License Renewal

Office of Nuclear Reactor Regulation