The Popperville Town Hall

Tuesday, May 26, 2015

LER 2015-002-00: Main Steam Safety Relief Valves Determined to be Inoperable Following Evaluation

I called up the Pilgrim inspectors over this LER today. The NRC seems to be very disappointed with this LER and have a lot of questions over it. It is still under investigation, so I got very little comment about.

The inspector said the special inspection is coming out tomorrow. He said it is going to be big and make big news, whatever this means. My comment to him was, you should have had the big inspection right after the 2013 blizzard, plant trip and LOOP and when the first problems in the SRVs showed up in 2011. I told him I am disappointing with the NRC over this...he said the higher up make the decision not him. He was very polite and a good guy. I tried not to give him any grief, told him I don't hold you personally responsible. Said, I hold you inspector guys as heroes and you are in the front lines against or preventing chaotic condition at your plants.

Bottom line in this LER, the three stage safety relief valves were found to be unsafe for plant operation, they yanked the three stage out and replaced it with the troublesome 2 stage relief valve.

Is the plant really licensed now for the 2 stage reliefs...did they need a licensed amendment request?

I asked him to discuss my conversation to him with his boss, the inspector said he would. I requested a discussion with his boss, the project manager. We will see. They will probably let me digest the special inspection report...

Also the Pilgrim inspector yesterday said NRC inspectors were on site at the safety valve manufacturer Target Rock. It was similar to a special inspection as Pilgrim.

I said to the inspector, basically no matter what happens with the violation on the Juno LOOP and SRVs special inspection...all it is going to be is a paperwork violation. You went out of you way to let them start-up post Juno and all though these SRV inops, these guys never pay a big price for poor performance. It is all though the Entergy Nuke Plants.

You don't have the power to make these big guys tremble at the sound of your soft whisper!!!

Here is my commentary on the LER:

May 12, 2015

Licensee Event Report 2015-002-00, Main Steam Safety Relief Valves Determined to be Inoperable Following Evaluation EVENT DATE 03 12 2015

LER NUMBER2015 002 00

REPORT DATE05 12 2015

On March 12, 2015, after further evaluation of system

You get it, basically this report is required to come out in 60 days. The licencee get a period to decide if it is going to be a LER and evaluating. These guys are really smart about the timing of the LERs. They are looking ahead in the future...

Basically because they started up without a complete evaluation, they didn't understand the problem...they started up with two inop SRV valves. They illegally started up. Really, these new valves before they ever were put into the plant were inop.

It looks like Pilgrim knew prior to the Juno start up these valves were unsafe. But they didn't have a replacement. They would have waited for weeks and maybe a month before the new two stage SRVs could have been tested and brought to the plant. The whole documentation trail post Juno was engineered to allow Pilgrim to knowingly and illegally operate with defective and unsafe 3 stage SRV valves till replacement at the outage with 2 stage.

I talked a length about when I thought Pilgrim should have call the SRVs inop. Then they would have entered into Tech Specs. If one SRV was called inop, it would have been a required shutdown within 14 day. If two or more were inop, it would have been something like an immediate or within 6 hours shutdown. I asked the inspector why didn't the NRC enforce tech specs and force the shutdown, he said that was the decision of the gods much higher than me. I get the decision of the gods are not challengable by him.

I think the NRC are gods. They got a really a lot of policies and rules...it looks like the NRC makes decision solely based on rules, engineering and science. I think this is not the case. I think they secretly go behind closes doors, make the decisions on self interest...then wrap the policies and rules around the godly objective they choose. It just looks like the NRC is making decision on rules, engineering and science!!!

performance of SRV-3A and SRV-3C, along with results of valve internal conditions identified during physical inspection, the valves were determined to have been inoperable for an indeterminate period during the last operating cycle. Specifically, SRV-3C was determined to

Isn't that convenient they declare it in the outage with no price to pay. You get the system, they are incompetent at diagnosing the problems of the set of valve or keeping it properly maintained...but this stated incompetence gets them to the outage where they never pay a price. This is corruption and lying on a federal document..the so called incompetence just gives them a free ticket into the next outage. These guys are extremely smart and cagey.

be inoperable based on its on-demand performance at low reactor pressures, as well as the visual conditions that were identified during the inspection process. SRV-3A was

The NRC said the valves would have still have provided their licencing function. So what study are you using to support this? I asked him, what about in a prolonged station blackout. These valves would have needed to be cycled in this event between 200 to 400 times. It sounds like all these valves would have failed in a event like this. Doesn't this matter to the NRC?

considered inoperable based on it having similar internal indications as SRV-C when it was disassembled and inspected. SRV-3A was installed in May 2011 and SRV-3C was installed in October 2013.

Additionally, during an extent of condition review of historical SRV performance, the review identified on March 13, 2015 that SRV-3A had failed to open in response to three manual actuation demands on February 9,2013.

At the time the valves were declared inoperable the reactor was at 100% power. The valves had been replaced

I had issues with getting the Pilgrim inspector to tell me what the above sentence means. When did they declare the valves inoperable at 100% power and did they enter into tech specs. It would have been a quick shutdown because it was more than one valve. The NRC inspector deftly shifted the conversation to LER 2015-001-00 and he would anwser my question.

in February 2015 during the forced outage relating to winter storm Juno. This event posed no threat to public health and safety.

BACKGROUND

On January 27, 2015, during winter storm Juno, Pilgrim Nuclear Power Station (PNPS) experienced a generator load reject and automatic reactor scram. During the pressure vessel cool-down period, a Main Steam Safety Relief Valve (SRV) appeared to have not fully opened when manually operated to control reactor pressure. Reactor vessel pressure did not lower as expected, reactor water level did not increase (swell) as expected, and there was minimal change in tailpipe temperature, which was not consistent with changes observed when other SRVs were opened. Operations maintained control of reactor pressure by alternate openings of other SRVs during plant cool-down.

Specifically, at 1015 hours, the first opening of SRV-3C was initiated when reactor pressure was 220 psig. When

God intervened here. What condition would that valve be in if we didn't have the Juno plant trip and then the next voluntary plant blizzard shutdown. What condition would this be in just prior to the outage shutdown on April 19?

There is absolutely no evidence and testing on how this damaged valve in other situation(at operating pressure).

the operator placed the hand switch in the Open position there was no significant change in plant operating parameters. The operator initiated the second opening of SRV-3C at 1032 hours when reactor pressure was 262 psig, and again, there was no significant change in plant operating parameters, but a small torus water temperature increase was observed near the SRV-3C tailpipe outlet in the containment suppression pool. After the second attempt, Operations declared the valve SRV-3C, Serial Number (SN) 9, inoperable.

This is important, Entergy later says the valve could have preformed it function at full pressure. The operators don't have that knowledge in their heads as the engineers who studied it in their heads for hours. There was a anomaly in the operation of the valve that the operators seen, the operator is too busy and information of the condition inside the valve was unavailable to them...so the operator determined the valve was too dangerous to operate based on what they know. It only matters what the operator thinks in his head at the time, not the full picture of the components operability days and months after the engineers study the conditions of the valve.

The SRVs are dual function Target Rock Corporation Model 0867F valves that are designed to operate in both safety

Basically the engineers at Pilgrim are stove piping the operability of the SRVs in the automatic modes. The third mode of of these valves is the licensed operators manual mode. Thet open and close these valve for pressure control of the reactor. It unprofessional to allow a automatic function at a nuclear...humans are suppose to be operating these plants not automatic component. Maybe in the opening moments of a plant scram and isolation...it is ok to allowed the SRVs to cycle on their own. Then the people take control of the SRVs, watching very closely what the valves do to the rest of the plant.

Probably the most critical use of the SRVs valves is in a prolonged station blackout. These valves are use as the means to guild the plant through cold down. The cool-down might have stopped and restarted depending on component availability. The weak link in the emergency evolution with high probability of a core damage is a stuck open relief and a failure for a valve to open is very problematic. The quality of these valve need to be that the manual operations should be bullet proof with opening and shutting in a accident.

mode and relief mode. The safety mode is automatically actuated at 1155 psig and involves successive opening of a first stage pilot valve, second stage pilot valve, and the main stage. The relief mode can be automatically actuated by the Alternate Depressurization System (ADS) which opens all four valves. Relief mode can also be initiated manually by the operator using any of the four SRVs individually or together. The relief mode of operation requires Direct Current power to energize a solenoid valve mounted locally on each valve. When the solenoid is energized, locally stored nitrogen is admitted to an air operator mounted on the valve. Nitrogen provides the motive force to open the second stage pilot valve and cause the SRV main stage to open.

PNPS has four, three-stage SRVs installed on the Main Steam lines. Each three-stage SRV contains a pilot (also called the first stage), a second stage, a main stage, and an air-operator. The pilot has main steam constantly applied to a bellows spring via a pressure sensing tube extending through the valve body. As the set pressure is reached, the bellows expands, opening the pilot disc and allowing steam to pass to the second stage. Steam pressure behind the second stage piston pushes the second stage disc open allowing steam to vent from behind the main stage piston to the containment suppression pool. Main steam pressure is present in front of the main stage piston, therefore, venting behind the piston creates a large differential pressure across the main piston causing it to stroke; pulling open the main stage disc to discharge steam and relieve system pressure. The air-operator is used to manually operate (open) the SRV below its setpoint pressure. When the air operator is pressurized, the operator plunger pushes directly against the second stage piston, opening the disc.

Subsequent to the plant reaching cold shutdown, SRV-3C, and another valve, SRV-3A, SN 4, were removed from the Main Steam system for testiness, disassemble, inspection,

This description is almost complete. In the recent Oyster Creek yellow finding with the Electromagnetic Relief Valves( their SRVs valves) they basically yank the valves out of the plant and then let them sit on a bench for 1.5 years. It is at this point they do the as found testing and inspecting, then certify testing for insertion into the plant. So it is important the dates of all of the testing, which they don't have here. Again, you see the possibilities of "engineering" the discovery of defects in a safety valve with a agenda in mind. This is fraud and corruption. In Oyster Creek with valves taken out of the plant, it took them 1.5 years to discovered serious problems and defects in the valve. How hard is it to know, you yank a safety valve out of reactor...it is you duty to immediately do as found testing and inspections. You want to immediately discovered design defects in the valve.

and refurbishment. The valves met the Technical Specification required lift set-point acceptance criterion during testing. Based on the testing having demonstrated acceptable results within the Technical Specification acceptance criterion for valve opening and initial inspection results, an operability evaluation for each valve determined that the valves were operable and

This is like preparing you car for long trip. You go out and start your car, it starts up. Then you begin your trip with no oil in the engine, depending on the oil pressure warning light to work. How about dates on the pressure testing and then the disassembly inspection.

able to fulfill their intended safety function. However, after disassembly, during the inspection process, internal damage in the main stage piston section was observed that required further investigation.

EVENT DESCRIPTION

On March 12, 2015, after further engineering evaluation of performance of the valves and internal conditions identified during inspection, SRV-3A and SRV-3C were determined to have been inoperable for an indeterminate period during the last operating cycle. SRV-3C was determined to be inoperable based on its on-demand performance at low reactor pressures (first attempt at 220 psig; second attempt at 262 psig;), as well as the visual conditions that were identified during the inspection process. SRV-3A was considered inoperable based on it having similar internal indications as SRV-3C when it was disassembled and inspected. SRV-3A was installed in May 2011 and SRV-3C was installed in October 2013.

Additionally, during an extent of condition review of

These expensive employees are note for their attention to-detail...it is dangerous to operate a nuclear plant with employees who can't detect subtle defects. it just looks like like these employee are actively turning their heads away with problems with SRVS. It is not plausible these employee are so stupid.

historical SRV performance, the review identified on March 13, 2015 that SRV-3A had failed to open in response to three manual actuation demands on February 9, 2013 with reactor pressures of 114, 101, and 98 psig.

The condition of the SRVs did not cause adverse results during the plant cool-downs, since the other installed

Yea, but Entergy didn't know the internals of these valves were massively damaged...could detect it.

SRVs operated as expected to control reactor pressure. In both cases, the reactor was placed safely in a cold shutdown condition.

Also, all the SRV's responded properly when called upon to function at higher reactor pressures (approximately

So massive internal damage and future operatability problems doesn't matter.

1000 psig or pressures close to that). In addition, following high pressure operation, the SRV's functioned over their entire range of operations.

CAUSE OF THE EVENT

The degradation mechanism is believed to be fretting wear (repeated cyclical rubbing) between the main stage piston and liner, increasing the friction in the stroke of the valve. Fretting is a time-dependent wear mechanism which

Got any legitimate engineering studies and testing predicting the wear mechanism or is it all guess work. Can reliable predict the wear mechanism through the cycle.

develops while the valves are in-service in the plant.The fretting occurs because the piston-to-disk threaded connection loosens and the main steam line flow vibration drives the piston rings against the guide liner.

It is believed valve certification testing on a limited

I don't believe the limited steam flow test stand is the problem. Can you even imagine the noise of these valves popping open and shut on the test stand creating such loading and damage? Can you even imagine a professional nuclear safety service provider hearing this severe flow perturbation noise...how can you think he would not request to inspect the valve right after the test. These guys are probably testing as assortment SRV valves from different plants. How could such severe test stand flow noise not stand out from other plants' normal valves testing.

steam-flow test stand creates the conditions internal to the main body which allows the valve to develop a fretting wear condition while in-service. The gagged-

How come there is not not other plants with test stand damage to their SRVs and then vibration damage to the spring and components similar to Pilgrim? Now how loud in that "high impact loading"?

Honestly, "Main Spring relaxation was caused by "extreme dynamics encountered during limited flow testing""...the test stand technician could hear the "extreme dynamics" and wonder if something was broken in the valve. They didn't record the loud noise in a document.

Can Entergy artificially create...reenact... the same test stand damage and then create the same kind of vibrations on their steam line seen by the SRVs in a laboratory..can Entergy artificially create the same kind of damage on the SRVs seen in normal operation?

valve test stand operations on a limited steam capacity test stand subjects the valve main stage to high opening force and high impact load. The high impact load increases potential loosening of the threaded joint between the main stage piston and the main disc stem (as-manufactured condition). When the valve is installed in the plant, normal system operation (steam flow) can cause

I think Pilgrim has a big problem with excessive steam line vibration and it could lead to catastrophic break of a main steam line. Wonder if the special inspection will say anything about steam line vibration.

the loosened piston to move (continuous, long-term, low amplitude vibration) relative to its liner. This movement may cause the piston rings to rub (fret) against the liner. Continued fretting may cause the rings to wear a groove into the liner; increasing potential binding friction against the piston when the valve strokes open. If sufficient binding friction has developed then the SRV opening stroke may not exhibit the typical rapid popping action when the valve opens at low reactor pressure where less opening force is available.

Target Rock Corporation issued an interim 10 Code of Federal Regulations (CFR) Part 21 report to the U.S. Nuclear Regulatory Commission concerning a potential test induced defect in the SRVs on March 16, 2015 (NRC Event # 50900) to provide notification that a multi-faceted investigation is ongoing to identify the cause of internal damage that could go undetected during production of new valves and refurbishment of valves that have been in-service. Although a root cause has not been determined at this time, sufficient facts have been established to warrant investigation of changes to current testing practices. This 10 CFR Part 21 notification was issued as a result of the PNPS SRV failures.

ADDITIONAL CONDITIONS

The SRVs also exhibit a spring "shortening" (or relaxation) phenomenon. GE SIL-196, Supplement 17 determined that Main Spring relaxation was caused by "extreme dynamics encountered during limited flow testing.... Valve dynamics under full flow conditions (i.e., discharge not gagged) are much less severe than those under limited flow conditions.

The shortened spring is directly related to the overload

What did you say, the test stand noise made me hard of hearing?

condition created on the test stand that is potentially contributing to the loosened main stage piston connections. It is not unusual for a valve on the test stand to not fully close after a test stroke. Based on

A problem though the years in the industry, once you use a SRV, it has the high probability of leaking in the near future. Are we really talking about the SRVs are not sturdy and durable enough for the duty of plant operation.

evaluations to date, a shortened main stage spring does

Can I see than engineering and scientific report?

not impact the valve over-pressure set-point, automatic actuation, or manual operation. Thus, this phenomenon does not directly impact the functionality of the valves.

CORRECTIVE ACTIONS

Prior to restart from the forced outage related to winter

This is the point when Entergy realized these valves were not safe.

storm Juno, SRV-3A and 3C were replaced with certified spare valves.

All SRV body/bases were removed from the system during the current refueling outage. In place of the four SRV's

You got to give Entergy the credit to expertly engineer the replacement of the SRV valve at their convenience. Man, they know how to read the NRC to get away with this.

removed from the plant during the current refueling outage, PNPS has installed 2-stage SRV's. These will be used for Cycle 21.

Corrective actions will be captured in the PNPS corrective action program in Condition Report CR-PNP- 2015-0561 and appropriate engineering documents.

SAFETY CONSEQUENCES

The function of the safety relief valves is to limit peak vessel pressure during overpressure transients to satisfy the American Society of Mechanical Engineers Boiler and Pressure Vessel Code requirements for overpressure protection.

The Automatic Depressurization System (ADS) provides a means to rapidly depressurize the primary system to a pressure where low-pressure systems can provide makeup for core cooling. In the event of a small or medium break Loss of Coolant Accident, the ADS function would be required if the High Pressure Coolant Injection (HPCI) system is unable to maintain reactor water level. The postulated transients that require SRV actuation are described in Chapter 14 and Appendices R and Q of the Final Safety Analysis Report (FSAR). In accordance with plant Technical Specification 3.5.E.1 Limiting Condition for Operation, the ADS is required to be operable whenever there is irradiated fuel in the reactor vessel and the reactor pressure is greater than 104 psig and prior to a startup from a cold condition. In accordance with FSAR Section 4.4 Nuclear System Pressure Relief System sub-section 4.4.5 Description, "For depressurization operation, each relief valve is provided with a power actuated device capable of opening the valve at any steam pressure above 100 psig, and capable of holding the valve open until the steam pressure decreases to about 50 psig." Additionally, FSAR Table 6.3-1 Core Standby Cooling Systems Equipment Design Data Summary lists ADS valves as having a pressure range of 1,120 to 50 psig which spans from above normal operating pressure at rated core thermal power to below the pressure interlock for entry into Residual Heat Removal Shutdown Cooling.

During both cool-downs when SRV-A (February 2013) and SRV-C (January 2015) did not perform as expected, other SRVs were available to perform the necessary function of pressure control. During the event, both HPCI and the

You notice how Entergy failed to mention HPCI was inoped near the end of the cooled. They aren't scrupulously honestly in this document. The pattern of them selectively releasing information that reflect well on the plant. .

Reactor Core Isolation Cooling systems were used when needed to provide the functions of supplying makeup water to the vessel, providing adequate core cooling, and heat removal. Therefore, there was no adverse impact on the public health or safety.

REPORTABILITY

This report is submitted in accordance with:

* 10 CFR 50.73(a)(2)(v)(B) and 10 CFR 50.73(a)(2)(v)(D) - Event or Condition that Could Have Prevented Fulfillment of a Safety Function.

* 10 CFR 50.73(a)(2)(i)(B) - Operation or Condition Prohibited by Technical Specifications

LER: Pilgrim Juno Scram and LOOP

Originally posted on 4/24...reported. This is closely related to today's LER 2015-02-00...

Basically these are arbitrary points...why didn't they interact with pilgrim before this.

Should have had big violations seen in the 2013 LOOP:should have had special inspection over these.

Over the leaking Safety Relief Valves

the 2013 LOOP

The difference between the 2013 LOOP and 2015 LOOP is the magnitude of equipment problems(HPCI, core spray and the SRVs).

Remember I contend, as Vermont Yankee was collapsing into permanent shutdown, the agency was pulling their punches with Pilgrim. They were afraid Pilgrim would end up like Vermont Yankee...

"Based on the update of data following the third quarter of 2013, Pilgrim saw its performance indicator for Unplanned Scrams (shutdowns) with Complications shift from green to white. This indicator tracks unplanned scrams that require additional operator actions and that are more risk significant than uncomplicated shutdowns. Subsequently, when 2013 fourth-quarter data was finalized, another indicator for the single-reactor plant also transitioned to white. That indicator covers Unplanned Scrams per 7,000 Hours of Operation and becomes white if a plant experiences more than three unplanned shutdowns during that period of time."

Licensee Event Report 2015-001 -00

Loss of 345KV Power Resulting in Automatic Reactor Scram During Winter Storm Juno

1. FACILITY NAME 2. DOCKET NUMBER 3. PAGEPilgrim Nuclear Power Station 05000293 1 OF 64. TITLELoss of 345KV Power Resulting in Automatic Reactor Scram During Winter Storm Juno5. EVENT DATE 6. LER NUMBER 7. REPORT DATE 8. OTHER FACILITIES INVOLVEDMONTH DAY YEAR YEAR SEQUENTIAL REV DAY YEAR CITYNAME DOCKET NUMBERNUMBER NO. N/A N/A01 27 2015 1 20 1 ACIT NAME DOCKETN UMBER2015- 001 - 00 03 30 2 N/A9. OPERATING MODE 11. THIS REPORT IS SUBMITTED PURSUANT TO THE REQUIREMENTS OF 10 CFR §: (Check all that apply)H 20.2201(b) 20.2203(a)(3)(i) 50.73(a)(2)(i)(C) 50.73(a)(2)(vii)N H 20.2201(d) 20.2203(a)(3)(ii) 50.73(a)(2)(ii)(A) 50.73(a)(2)(viii)(A)H 20.2203(a)(1) E 20.2203(a)(4) 50.73(a)(2)(ii)(B) D 50.731a)(2)(viii)(g)20.2203(a)(2)(i) 50.36(c)(1)(i)(A) K 50.73(a)(2)(iii) [] 50.73(a)(2)(ix)(A)10. POWER LEVEL K 20.2203(a)(2)(ii) K] 50.36(c)(1)(ii)(A) [ 50.73(a)(2)(iv)(A) K] 50.73(a)(2)(x)K] 20.2203(a)(2)(iii) K 50.36(c)(2) K] 50.73(a)(2)(v)(A) E] 73.71(a)(4)52 E] 20.2203(a)(2)(iv) K] 50.46(a)(3)(ii) 50.73(a)(2)(v)(B) K] 73.71(a)(5)K] 20.2203(a)(2)(v) K] 50.73(a)(2)(i)(A) K 50.73(a)(2)(v)(C) K] OTHER20.2203(a)(2)(vi) Specify inA bstract betow or in 50.73(a)(2)(i)(B) 50.73(a)(2)(v)(D) NRC Form 366A12. LICENSEE CONTACT FOR THIS LERLICENSEE CONTACT TELEPHONE NUMBER (Include Area Code)Mr. Everett P. Perkins, Jr. - Regulatory Assurance Manager 508-830-832313. COMPLETE ONE LINE FOR EACH COMPONENT FAILURE DESCRIBED IN THIS REPORTMANU- REPORTABLE MANU- REPORTABLECAUSE SYSTEM COMPONENT FACTURER TO EPIX CAUSE SYSTEM COMPONENT FACTURER TO EPIXB FK BU M- YRT B SB RV T020 YLD CMP A544 Y14. SUPPLEMENTAL REPORT EXPECTED 15. EXPECTED MONTH DAY YEARSUBMISSION D YES (If yes, complete 15. EXPECTED SUBMISSION DATE) NO DATEABSTRACT (Limit to 1400 spaces, i.e., approximately 15 single-spaced typewritten lines)

On Tuesday January 27, 2015, at 0402 hours, while in the process of lowering reactor power, with the reactor in the RUN mode at 52 percent core thermal power, Pilgrim Nuclear Power Station (PNPS) experienced a loss of 345KV power resulting in a load reject and an automatic reactor scram. The loss of 345KV power was due to faults from flashovers in the PNPS switchyard. All control rods fully inserted. The Emergency Diesel Generators had been previously started and were powering safety-related buses A5 and A6. The plant stabilized in Hot Shutdown. At the time of the event a significant winter storm (Juno) was buffeting Southern New England.

I think the real root cause should be: we have plenty and multiple examples that of our switchyard wasn't designed for the climate, and we knowingly chose to ignore the great reduction in safety to the plant and surrounding people.

The root cause of the event is that the design of the PNPS switchyard does not prevent flashover when impacted by certain weather conditions experienced during severe winter storms. A modification of the switchyard is planned to address the susceptibility of the PNPS switchyard to flashovers during severe winter storms.

This event posed no threat to public health and safety.

BACKGROUND

Pilgrim Station Nuclear Power Station (PNPS) is connected to the transmission lines through a 345KV ring bus located within the station's switchyard. The 345KV ring bus connects the output of the main transformer (GSU), the startup transformer (SUT), Line 355, and Line 342. There are four gas circuit breakers connecting PNPS's 345KV ring bus sections: ACB-1 02, ACB-1 03, ACB-104 and ACB-1 05.

The Line 355 bus connects PNPS to NSTAR (Eversource) Carver Station and is connected to ACB-102 and ACB-1 05. The Line 342 bus connects PNPS to the Canal Power Plant's Switchyard in Sandwich, MA and to Auburn Street Station Switchyard in Whitman, MA. The Canal Switchyard is owned and operated by NSTAR and Auburn Street Station Switchyard is owned and operated by National Grid. ACB-103 and ACB-104 connect the Line 342 bus to the SUT and GSU bus. The 345KV system is the PNPS preferred off-site power source via the SUT.

The 345KV ring bus design locates the power transmission lines such that a failure of any one line will not result in the loss of the other line. Specifically, with both transmission lines in service, a failure of either 345KV line will not result in a main generator trip, a SUT trip, or a failure of the other 345KV line. Either of the two 345KV lines is capable of carrying full station output and supplying station loads via the SUT.

The 345KV protective relay system is designed and coordinated to isolate system faults and minimize the impact to the overall transmission system. The protective systems are comprised of a primary and secondary protection scheme and are divided into four zones of protection.

*The main transformer bus (isolated by ACB-104 and ACB-105)

*The SUT bus (isolated by ACB-102 and ACB-103)

*Line 355 bus (isolated by ACB-102 and ACB-105 and Carver Station)

*Line 342 bus (isolated by ACB-103 and ACB-104 and Auburn Street Station and Canal Station)

When ACB-104 and ACB-105 open, the main transformer is isolated from the 345KV transmission system thus resulting in a generator load reject event.

In addition to the preferred 345KV off-site power lines, PNPS has a secondary off-site power source, a 23KV line from NSTAR's Manomet Substation that provides power to a shutdown transformer (SDT).

During normal station start-ups and shutdowns, the station's 4160V demands are supplied by the SUT. Once the station main generator is synchronized to the 345KV transmission system, the station unit auxiliary transformer (UAT) supplies all station 4160V demands, with the SUT maintained in standby, ready to provide 4160V power if necessary.

In anticipation of a major snow storm impacting the site on January 26, 2015, Operations entered Procedure 2.1.37 (Coastal Storm Preparations). Procedure 2.1.42 (Operation During Severe Weather) and EN-FAP-EP- 010 (Severe Weather Response). During the storm on January 26-28, 2015, meteorological instruments at PNPS recorded sustained wind speeds between 37 and 61 mph with the wind direction predominantly from the ocean toward the switchyard.

EVENT DESCRIPTION:

On 1/25/15 with PNPS operating at 100 percent power, the National Weather Service (NWS) issued a blizzard warning for winter storm Juno. Wind speed of 40 mph sustained with 50 mph gusts and snow fall of more than two inches/hour were predicted. PNPS entered procedures 2.1.42, Operation During Severe Weather and 2.1.37, Coastal Storm Preparations and Actions, and started making preparations for storm arrival. Preparations were completed on 1/26/15. At 0132 hours on

First, they should have shutdown hours before this. But seeing they were not, they should have seen the light based on past events...they should have scrammed at this point. What didn't upper management advise this to the shift prior in the approach of the storm.

1/27/15, the 345 KV Line 355 bus faulted (for the first of five times) whereupon Operations personnel commenced a reactor shutdown at 0134. The Emergency Diesel Generators (EDGs) were started and loaded with the safety related buses. Reactor Protection System (RPS) bus "A" was placed on the backup power supply. At 0235 hours, the Line 355 bus faulted for the final time at which time the Line 355 breakers at both Carver and PNPS were left tripped open. This configuration left PNPS with one transmission line connected to the grid.

Honestly these guys are so dangerous, it took from 01:32 to 04:20 for the plant to auto trip. It is dangerous to take a scram because equipment could fail...you manually scram before the auto scram.

Was the Pilgrim CEO stationed at the plant during big blizzards like Millstones???

At 0402 hours with the reactor at 52 percent power, Line 342 faulted resulting in a trip of ACBs 103 and 104. This isolated PNPS from the grid causing a generator load reject and automatic reactor scram. All control rods were verified fully inserted. The non-safety related back-up diesel driven air compressor, K-1 17 failed to start on instrument air system low pressure. K-1 17 failure to

That is why I hate this non safety air compressors. They are not instrumented up. You ain't taking rounds and readings on the backup air compressors knowing the condition of the battery. If they would have been instrumented up, an alarm would have stayed lit in the control room. They didn't test the backup air compressor just before the storm arrived. They could have had it running just before the storm.

Pilgrim had issues with diesel smoke in the reactor building last Nor'easter...did it occur this time?

start was due to a battery low voltage condition. Primary Containment Isolation System (PCIS) Group II - Sampling Systems, Group VI - Reactor Water Cleanup (RWCU) System and Reactor Building Isolation System (RBIS) isolations occurred as expected. Reactor water level was maintained by the Reactor Core Isolation Cooling (RCIC) system and reactor pressure was maintained by the High Pressure Coolant Injection (HPCI) System. Once normal reactor level and pressure were restored, operators commenced a depressurization to the cold condition. At 0641 a Non- Emergency Notification to the NRC of the RPS and safety system actuations was made. (EN 50769).

During the reactor vessel depressurization, the High Pressure Coolant Injection (HPCI) System was removed from service prior to reaching the low pressure automatic isolation setpoint (Approx. 80 psig). Shortly after

There goes HPIC and one wonders how reliable HPCI is? But the reactor was almost cooled down.

system shutdown, the HPCI Gland Seal Condenser Blower Overload Alarm was received. The HPCI System was declared inoperable. At 1656 hours, a Non-Emergency Notification to the NRC of the HPCI System inoperability was made. (EN 50771) Subsequent analysis determined that the cause of the overload condition was due to the inability to remove water from the condenser with the HPCI pump discharge

Right, having in house supplied air compressors is the safest mode. It a big safety hole at many plants not having in house safety electricity for the air compressors. Lots of plant get into big troubles without air compressor and it creates damaged.

You get it don't you, the back up air compressor not working was the cause of losing HPCI. This reflect very poorly with Pilgrim's operation and engineering not being able to anticipate this. It is very dangerous with having many components failing in a plant accident.

How many other not working air valves didn't also work.

Was this not modeled in the computer simulators. I'd like to see how many LOOPs like this was thrown, practice in the simulator?

piping isolated, since the air operated valves that would normally open to remove water were unavailable due to the loss of instrument air when K-1 17 failed to start. The analysis also determined that HPCI would have been available to perform pressure control or restore reactor water level if required. Upon opening of a valve in the HPCI discharge piping flow path, the HPCI Gland Seal Condenser Hotwell Pump would restore the condenser level to normal. The depressurization continued using Main Steam Safety Relief Valves (SRVs) for pressure decrease and Core Spray Loop "B" to maintain reactor vessel water inventory. When

So we know from the Part 21 the 3C Safety Relief Valve under went severe perturbation due bad components and severely damaged the valve.

The question left opened, did the 3C SRV valve have indications of seat leakage and how long did they know it? How were the long term trends on the SRV tail piece temperatures? Did any other SRV have elevated temperatures?

Entergy says they don't put in the right resonance frequency to the purchase contract with these valves...some abnormal vibrations on the steam line destroyed the valve.The SRV valves weren't sturdy enough for the vibration duty. Many plant recently have come up with the same problem...

I think think the manufacturer is building these valves with poor quality components.

SRV RV-203-3C was manually opened, the SRV did not appear to open or failed to open fully. Part 21 Event Report 50900 documents this condition. Post-event removal and disassembly of the valve revealed damaged parts in the main stage assembly. Further investigation by the valve manufacturer is required to determine the cause. Core Spray Loop "A" discharge header low pressure alarm

Now we know another independent system was impaired...the A Core Spray was dead. It is implausible the B wasn't dead also.

was received due to the unavailability of the nonsafety related keep-fill system due to the loss of power to the non-safety related buses. Operators recognized the potential for voiding within the piping. To preclude the potential for damage of the piping due to water hammer pressure pulses, the Core Spray Loop "A" was not used during this event. At 1626 hours, Residual Heat Removal (RHR) Loop "B" was placed in service in the shutdown cooling mode. At 1658 hours, the reactor moderator temperature was less than 212 degrees F. Prior to restoration of offsite power to the switchyard, the switchyard bus insulators and bushings were cleaned of snow and salt contamination to prevent further flashovers.

Basically from 4 am to 5 pm the main lines wasn't available...13 hours LOOP.

On January 29, 2015 at 1643 hours, the loss of 345KV power condition was cleared when offsite power was restored to the switchyard and the startup transformer. CAUSE OF THE EVENT The design of the PNPS switchyard does not prevent flashover when impacted by certain weather conditions experienced during severe winter storms. CONTRIBUTING CAUSES: Previous corrective actions to preclude recurrence taken in response to LER 2008-006-00, Automatic Scram Resulting From Switchyard Breaker Fault During Winter Storm, LER 2008-007-00, Momentary Loss of all 345kv Off-Site Power to the Startup Transformer from Switchyard Breaker Fault, and LER 2013-001-00, Loss of Offsite Power and Reactor Scram, did not prevent recurrence. Previous cause analyses of loss of 345KV transmission lines failed to fully analyze all available weather related data to understand precisely what weather related attributes (and characteristics) were necessary to guide operators in making decisions to maneuver the plant to shutdown prior to or during snow storms with the potential for creating flashovers. As a result, Procedure 2.1.42 failed to guide operators to the correct actions necessary to preclude the automatic scram during winter storm Juno. Previous cause analyses did not effectively use repeat

Does anyone believe this. Like to have all the data on winter storms...how many alarms on the main lines don't cause line or plant trips? I bet they got a lot of alarms and no plant trips on winter storms Effectively they were intentionally betting there would be no plant trip. Double or nothing every blizzard.

2008 blizzard LOOP-Corrective actions planned include the following:

- Review of potential design changes to improve switchyard resistance to weather related flashovers.

- Modify and replace the input breakers on the X55 and X56 transformers.

- Complete vendor evaluation of transformer tap control board failure.

events to evaluate design aspects to effectively communicate the risk of the current design.

CORRECTIVE ACTIONS

The switchyard insulators and bushings were cleaned prior to return of the switchyard to service. The following corrective actions are planned to correct / preclude recurrence:

* Implement a switchyard design change to minimize switchyard flashovers during snow storms

* Revise procedure PNPS 2.1.42 to provide additional guidance including the requirement to place the reactor in cold shutdown prior to the anticipated arrival of certain severe winter storms

Additional corrective actions are captured in the corrective action program in Condition Report CR-PNP- 00558.

The Loss of Coolant Accident (LOCA) design basis accident (DBA) analyzed in the Updated Final Safety Analysis Report (UFSAR) assumes coincident loss of both 345 KV and 23 KV (preferred and secondary) sources (LOOP). The design imposes a 10 second delay in re-energizing the 4160V Emergency Buses required to mitigate the DBA to allow the EDG to start and reach voltage. This delay also allows the operating motors to coast down to a stop to prevent being repowered out of phase. In cases where coincident loss of an EDG presents a bounding condition, the affected safety bus is not assumed to be picked up by the shutdown transformer (SDT). The bounding condition in which all off-site power and onsite AC (EDGs) sources would be lost is a Station Blackout (SBO) transient event (10 CFR 50.63). PNPS is designed to recover from the SBO event by having a separate SBO diesel generator capable

What are the chances the standby SBO diesel generator would have had a dead battery just like the backup DG air compressors. They ain't just pushing a button on this guy like they would in the control room. That is why a real operator would think the whole flex philosophy in bankrupt. You think they would cleanly put the one diesel generator on the safety bus. I doubt it. Minimum certainty is all the crews in training actually starting up the DG and they putting it on the bus themselves repetitively like they know the back of their hand. How long would it take to get cooling to the core through a backup diesel generator?

You got any proof with ECCS automatic timing starts and the rest, the start-up DG could take this kind of sequence???

Think of the political and public ramifications locally and nationwide in a historic blizzard, if a nuclear plant didn't have any electricity for three or four hours. They bungled the start-up of the back up diesel generator or caused a fire in the plant over electrical shorts I doubt Pilgrim would ever start up again.

of providing power to the required safety buses to shutdown the plant and maintain it in a safe condition. Thus, the loss of 345KV power experienced by PNPS is within the analyzed conditions. During the event, the EDGs, RHR, Core Spray Loop "B",

How can they say this, the gland seal was dead because the back up compressor didn't start and no motive force to drain the HPCI gland exhauster to the condenser. Then one side of the CS wasn't pressurized.

HPCI, and RCIC were available. These systems provided capability to supply makeup water to the vessel and ensured adequate core cooling was maintained. During and following the storm, operators were able to maintain safe shutdown conditions (reactivity control, reactor water inventory, decay heat removal, etc.). While loss of power to non-safety related spent fuel pool

This is so unprofessional losing cooling to the Fuel Pool...

cooling was a key consideration, time-to-boil never became an overriding concern with respect to reenergizing buses and there was no recently irradiated spent fuel in the pool. The most recent recently irradiated fuel was almost 21 months old, and the time to boil was approximately seven days upon loss of fuel pool cooling. The spent fuel pool temperature remained less than 105 degrees F. The Emergency Diesel Generators were started and loaded with the safety related buses prior to the loss of 345KV power. The amount of fuel onsite initially was sufficient to operate the EDGs for 7 days (under LOCA conditions) and the SBO DG was always available. Throughout these events there was no adverse impact on the public health or safety. REPORTABILITY This report is submitted in accordance with: * 10CFR50.73(a)(2)(iv)(A)- System Actuation,
* 1OCFR50.73(a)(2)(v)(B) and 1OCFR50.73(a)(2)(v)(D) - Event or Condition that Could Have Prevented Fulfillment of a Safety Function.
The Reactor Protection System, Containment Isolation System, High Pressure Coolant Injection System, and Low Pressure Core Spray System are included in 10CFR50.73(a)(2)(iv)(B). The Reactor Protection System and Containment Isolation System automatically actuated. The High Pressure Coolant Injection System and Low Pressure Core Spray System were manually actuated. Since High Pressure Coolant Injection System is a single train system to fulfill a safety function, the inoperability was reported in accordance 1 OCFR50.73(a)(2)(v)(B) and 1 OCFR50.73(a)(2)(v)(D). PREVIOUS EVENTS The most recent loss of 345KV power events at PNPS reported as LERs are as follows:

The most recent loss, because the whole list of LOOPs over plant life would be so embarrassing. They were actively not looking events that would show the switchyard wasn't designed for the climate. No doubt you'd never get any pilgrim employee to admit that.

LER 2008-006-00, Automatic Scram Resulting from Switchyard Breaker Fault During Winter Storm, dated February 12, 2009. LER 2008-007-00, Momentary Loss of all 345KV Off-Site Power to the Startup Transformer from Switchyard Breaker Fault, dated February 12, 2009. LER 2013-001-00, Loss of Offsite Power and Reactor Scram due to Winter Storm Nemo, dated April 4, 2013. ENERGY INDUSTRY IDEBTIFICATION SYSTEM (EIIS) CODES COMPONENTS CODESSwitchyard Bus BURelief Valve RVCompressor CMP SYSTEMSSwitchyard System FKMain Steam System SBHigh Pressure Coolant Injection System BJ\Low Pressure Core Spray System BMInstrument Air System LDESF Actuations (RPS,PCIS, RBIS) JE
REFERENCES Condition Report CR-PNP-2015-0558, Loss of Offsite Power and Reactor Scram Condition Report CR-PNP-2015-0559 - K1 17 air compressor failed to start following unit scram. Condition Report CR-PNP-2015-0561 - SRV-3C appears to have not opened fully during manual operation.Condition Report CR-PNP-2015-0563, HPCI Overload alarm received during HPCI operation - Observed water emitting from P-223, Gland Seal Condenser Blower

Massive Texas Flooding: Are the Texas Nuclear plants OK?

June 16:

UPDATE3-Tropical Storm Bill pelts Texas coast

By Kristen Hays

HOUSTON, June 16 (Reuters) - Tropical Storm Bill punched the Texas coast with heavy rains and strong winds on Tuesday, the National Weather Service said, just three weeks after floods killed about 30 people in the state.

The second named tropical storm of the 2015 Atlantic hurricane season made landfall near Matagorda, a sportfishing town near the South Texas Nuclear Generating Station in Bay City, a coastal nuclear power plant.

Spokesman Buddy Eller said the plant had prepared for the storm and operations were normal with full staffing.

Companies said output from oil platforms in the Gulf of Mexico, which pumps about a fifth of all domestic crude, was unaffected.

But BP Plc shut its Mad Dog and Atlantis fields early on Tuesday after a pipeline outage that was expected to be fixed soon, a source said. It was unclear if the storm caused the outage.
Vessel traffic was halted in the Houston Ship Channel, the biggest U.S. petrochemical port, and ports in Galveston and Texas City, officials said...

Are the Texas Nuclear plants OK? I don't see any immediate issues yet...

There are two operating nuclear power plants in Texas. The South Texas Project (STP) is in Matagorda County near Bay City, about 90 miles southwest of Houston. Comanche Peak Nuclear Power Plant is in Somervell County near Glen Rose, TX, about 40 miles south of Fort Worth. Both have twin reactors.

~~Trinity River?~~

South Texas Project (Bay City): Has a cooling lake...about a mile from the Colorado River. It is close to the coast.

Let me get this straight, the cooling water reservoir sits at the 41 ft level, the plant itself is 28 ft level, while the Colorado River is about at sea level?

Comanche Peak (Glen Rose):On the Squaw Creek Reservoir...about one mile from the Brazos River. Not far from Fort Worth. Hmm, the reservoir has a river going into it. Squaw Creek is a tributary of the Brazos River?

Brazos River is flooding big time downstream in Waco...but this river has big water projects all through it and dams on the river.

I don't see any issues unless a dam fails.

Could the rainfall amounts overwhelm the roof or property drainage designs.

No NRC notices on Texas!!!

Sunday, May 24, 2015

Saturday, May 23, 2015

Entergy Loves The Clintons' To The Tune Of $250,000 For One Speech

See, with the politicians, you never know if any politician will be objective. Entergy and all the big utilities are doing the same thing to the rest of the Democrats.

NY has been a financial boon to Clintons

Entergy Corp., which owns the Indian Point nuclear power plant in Buchanan, paid the former president $250,000 for a June 5, 2014 speaking engagement.

The Clinton's NY home in Chappaqua is 13.43 miles from Indian Point nuclear plant. Just saying...

Friday, May 22, 2015

Part 21: Crappy Safety Relief Parts At Pilgrim

Bottom line, all the valves could have been degraded at once, and who knows how far that has gone on...

Remember the Hatch NRC inspector felt the cause of it was Pilgrim cycled their SRV valves much more than Hatch...

You think this statement is true: Appendix B stipulates extensive quality assurance requirements to ensure all key design, engineering, and production processes are sufficiently controlled in order to guarantee the performance of safety-related equipment?

It means you got a strict QA program nationwide in paper only...

INTERIM PART 21 REPORT - POTENTIAL TEST INDUCED DEFECT IN A 0867F MAIN STEAM SAFETY RELIEF VALVES

Sounds like they took out the SRV SN 9,4 and 3 of the Juno Blizzard plant trip. The talking about having three SRVs open at one time and not being able to shut them. You can't throttle these valves open...it either open or shut.

We are continuing the search for relevant Operating Experience (OE) and are currently aware of the following:

Pilgrim 0867F: Three (3) Pilgrim 0867F main assemblies, identified as S/N 9, 4 and 3, had main guide grooving and fretting wear, as well as damage to main disc threads, piston and piston rings. All of these valves opened under limited flow as-found testing at the set pressure. Additionally, S/N 9 and 4 were manually tested and successfully opened when low pressure (approximately 100 psig) was provided at the valve inlet.
None of these valves re-closed during the limited flow test.

During testing just before they installed the valve in the plant they were damaged?

At this time, TR believes the most likely root cause is excessive impact loads during limited flow
testing that relieves the torque applied to the piston/stem interface (de-torqueing) that may
subsequently lead to creation of a significant clearance between the piston and the main disc
(de-shouldering). If the excessive impact load also damages the locking tab, plant vibratory
loads can allow the piston to rotate creating/increasing the clearance between it and the stem. If
the clearance becomes significant, the piston tilts in its guide bore which can inhibit valve reclosing under certain conditions.

As far as the limited flow testing damaging the parts of the valve...it looks like cheap parts.

Best News For The Nuclear Industry In Forty Years!!!

Our Navy uses metallic fuel and it last for decades...sometimes the same fuel stays in the reactor for the life of the ship.

I would go for once every five year outages for a intense outage being 3 of 6 months long.

Now if a plant from day one was engineered for metallic fuel and four and five year operation periods...I'd be in heaven!

Four Utilities Request NRC Review Of Lightbridge Metallic Fuel Design
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Mon, May 18 2015 2:42 PM

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U.S. regulators said Monday that four U.S. electric utility companies, representing close to 50 percent of the country’s nuclear generation, have formally requested a review, by the Nuclear Regulatory Commission, of Lightbridge Corporation metallic fuel design, which might be available for testing in pressurized water reactors in five years.A joint letter to the NRC from nuclear fuel managers at Dominion Generation, Duke Energy, Exelon Generation and Southern Company, which comprise the Nuclear Utility Fuel Advisory Board (NUFAB), advised the regulator that it could expect an application from Lightbridge in 2017 for use of fuel lead test assemblies in a U.S. pressurized water reactor as early as 2020.
The Commission posted the utilities' expression of interest in Lightbridge's fuel and supporting documents on its official web site.
Lightbridge President and Chief Executive Officer Seth Grae expressed his confidence in the new metallic fuel design. In a statement, Lightbridge posted bullet points:

A 1,000°C reduction in average fuel operating temperature, compared to conventional uranium dioxide pellet fuel, resulting in dramatic safety improvements;

Improved heat transfer and fluid flow, increased structural strength, and improved performance during transients and accidents;

10% more power and longer fuel cycles or up to 17% more power with the same fuel cycle length for existing pressurized water reactors (PWRs);

Up to 30% more power with the same fuel cycle length for new build PWRs;

Increased revenue and improved profit margins for existing nuclear power units;

Lower total levelized cost per kilowatt-hour for new build reactors;

Increased competitiveness of nuclear power versus fossil or renewable energy sources;

The commercial nuclear energy industry is projected to grow rapidly at a time of rising global demand for reliable, carbon-free, base load electric power. There are currently 437 operable civil nuclear reactors in 30 countries around the world, with 65 reactors under construction and 481 on order, planned or proposed, according to the World Nuclear Association. By 2040, the International Energy Agency

How The NRC Values Human Life

They don't value human life in the same way with Risk Perspective with their phony assumption in the calculations.

Union of Concerned Scientists

Why Is the Nuclear Regulatory Commission Undervaluing American Lives?

Posted: 05/22/2015 9:00 am EDT Updated: 3 hours agoHow much is your life worth?

That's a key, but controversial, question for the federal government. Although it might seem distasteful to put a monetary value on a life, when federal agencies consider adopting new health and safety rules -- or strengthening old ones -- they often do just that and weigh the proposed rule's costs against its lifesaving benefits. The lower value they give to a life, the easier it is for them to reject a proposed safety measure as too costly.

Agencies determine what's called the "value of a statistical life" (VSL) based on a variety of economic and labor market studies that indicate what people are willing to pay to avoid certain risks or how much more employers pay workers to do a riskier job. For the most part, VSLs across agencies are in the same ballpark. For example, when estimating the benefits of a highway safety standard, the Department of Transportation calculates the value of a human life at $9.1 million. When the Environmental Protection Agency proposed strengthening the National Ambient Air Quality Standards for particulate matter last year, it pegged the VSL at $9.6 million. And when the Occupational Safety and Health Administration finalized its hazard communication rule in 2012, it used a value of $8.7 million.

Virtually all agencies periodically increase the VSL to reflect inflation and other factors. I say "virtually" all, because at least one agency -- the one responsible for ensuring the safety of commercial nuclear power plants -- is way behind the times. The Nuclear Regulatory Commission (NRC) has been using the same value -- $3 million -- for the past two decades. That's two to three times lower than other agencies' calculations.

"The $3 million amount used by the NRC is an outrageously low figure that is way out of line with other government agency practices and the economics literature," W. Kip Viscusi, the economist credited with developing the VSL concept, told me in a recent email. "I first got the government to use these numbers in 1982.... My estimate of VSL at that time was $3 million, which was in 1982 dollars.

"Inflation and the fact that society has gotten more affluent over time has boosted the VSL substantially over the past 33 years," added Viscusi, now a professor at Vanderbilt University. "My recent estimates using new Census of Fatal Occupational Injury data yield a VSL of around $9 million."

NRC Shortchanges Plant Safety

By maintaining a VSL more appropriate for 1982 than today, the NRC has been allowing nuclear plant owners to avoid making safety improvements that would better protect their workforce and the people who live within 50 miles of the plant.

"If the NRC increased that value to what other federal agencies use -- and made other long-overdue changes to the way it calculates the benefits of regulations -- it would have a major impact on nuclear plant license renewals and new reactor approvals," said Edwin Lyman, a physicist with the Union of Concerned Scientists. "Plant owners would have to add safety features that the NRC now considers to be too expensive because the agency lowballs the value of the lives that would be saved."

As it turns out, the NRC has been reconsidering its VSL formulation since August 2012, and the agency's staff is expected to soon recommend tripling the VSL to $9 million and tying it to the inflation rate going forward. Once that recommendation is officially proposed, which could happen any day now, the agency will open up a public comment period.

Undoubtedly, the nuclear power industry will object. It routinely complains about costly rules it finds burdensome.

"Resources are being spent complying with requirements that have little or no safety benefit," Anthony Pietrangelo, a senior vice president at the industry's premier trade association, the Nuclear Energy Institute, told Congress last December. "If the NRC more accurately estimated the cost of its regulatory requirements it would find that many of its requirements do not pass a simple cost-benefit test."

In fact, if the NRC more accurately estimated the cost and benefits of its regulatory requirements, plant owners might have to spend significantly more to ensure their facilities are safe. That would depend on reforming other NRC policies that favor the industry's bottom line at the expense of public and workplace safety, but it would be a good start.

Elliott Negin is a senior writer with the Union of Concerned Scientists.

Is the Indian Point Transformer Fire For Gov Cuomo His Vermont Yankee Moment?

The VY moment came when the plant official were asked in a Vermont legislative session if VY had pipes in the plant yard outside their buildings. The engineer said in technical language, no they didn't. Then they had a radioactive leak out in said yard. The word games then began. Basically the plant and the governor came under intense scrutiny. Republican Governor Douglas started getting weaselly words out of Entergy...Gov Douglas publicly said he couldn't trust anything out of Entergy. Governors are extremely vulnerable in nuclear plant crisis. They need a plant to be honest with them, because their job is on the line with the misbehaving plant. So if a nuclear company gets dishonest with the Gov, the Gov has to quickly disconnect themselves from the plant. Who really knows what is under the covers. It only makes it worst if the NRC plays it close to the vest. Remember just days ago the NRC gave IP good grades on the past year.

I think this was all about the water in the electrical supply room. The NRC and Entergy made the Gov look like an idiot, as he wasn't able to discuss or disclose the water in the supply room. This snubbed or disrespected the Gov. The NRC should have allowed the Gov to disclose the special inspection. The rumblings in the background is Entergy is a die heart right wing teabagger, basically a anti government corporation and Coumo has to be a liberal governor. Is politics going on behind the scenes?

This is how I explained the snub to Cuomo by Entergy and NRC on the NRC's blog page when I first perceived it. I thought this had the high likelihood of setting off a all out war between Cuomo versus Entergy and the NRC.

(May 19) "Did the NRC shame Gov. Cuomo by not telling him about supply room water on the floor or did the Governor intentionally withhold the water leak in the said electrical room from the public for some reason? Why didn’t the Governor disclose the water on the floor? The information was big deal heading into a special inspection.

I think you will see the governor and NY in the media a lot more discussing secret internal issues at the plant. The gov will try ti destroy the reputation of Entergy and the plant. I don't think Entergy realizes the power of a rich, giant and high population state as New York. Does Entergy think gov Cuomo is weak with the Albany scandals brewing all around?

Cuomo administration aiming to shutter Indian Point

May 22, 2015, 10:01am EDT

New York state energy czar Richard Kauffman acknowledged that Gov. Andrew Cuomo’s administration is pushing to close the Indian Point nuclear facility in Westchester County.

That’s an unusual departure from the administration’s previous communications strategy on Indian Point, Capital New York explained, which has been to express concerns about the plant while talking around the notion of closing it. Entergy (NYSE: ETR), the facility’s owner, is in the process of seeking a 20-year license from the federal government, but Kauffman’s comments indicate the state is exploring its options for how to prevent continued operation there, the report said, including, perhaps, limiting Indian Point’s use of river water.
Replacing Indian Point, which provides a significant amount of electricity for the New York metropolitan area, could cost nearly $1 billion, according to a 2013 estimate from the New York Power Authority and Consolidated Edison (NYSE: ED). Capital New York noted that Kauffman also said “there are lots of developers that are prepared to commit capital to provide replacement power” should the plant shut down.

Earlier this month, a transformer fire at Indian Point led to the automatic shutdown of one reactor, the Associated Press reported at the time. Cuomo took the opportunity to say there had been too many emergency situations at the plant recently, the AP reported.