The Popperville Town Hall

Tuesday, May 26, 2015

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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Nuclear Street News
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.

Thursday, May 21, 2015

Millstone: Response to Special Inspection

Originally posted on 10/27/14

OCT 31

I am confused on why the SLOD system wasn't in Tech specs? Why didn’t the information notice response get them to put the SLOT system into tech specs? As NRC Enforcement came out of these special inspections and declared the transmission system wasn't safety related according to the FSAR, why didn't the agency required them them to put the SLOD system in TS or find it as a flaw by Millstone with their FSAR?

I want to state here for the record, LOOPs never comes from a wrong switch movement or a short from an unexpected safety device. A LOOP takes many years of poor decisions and improper analysis…it always comes from a wounded and disease culture over years of sleeping on watch. A licensee can’t create a LOOP on there own…it takes a complicit regulator. A LOOP is always a pretty good indicator of the health of organizations. LOOPs are very hard to create!!!

In their response to IN 2012-03, why didn't that key Dominion and NU into the SLOD system wasn't properly characterized in the FSAR and controlled through tech specs?

If the SLOD system was in Tech Specs, there never would have been dual plant trip and loss of offsite power event. They would have been forced into getting a licensing amendment?

How are similar transmission system SLOD systems in the nuclear industry characterized in their FSARs and tech specs? This probably only has relevance in multi-unit sites.

NRC INFORMATION NOTICE 2012-03: DESIGN VULNERABILITY INELECTRIC POWER SYSTEM

MILLSTONE POWER STATION UNITS 2 AND 3 – NRC SPECIAL INSPECTION REPORT 05000336/2014011 AND 05000423/2014011

Inadequate Implementation of Dominion’s Design Change Process Enforcement: This finding does not involve enforcement action because no violation of regulatory requirements was identified, as SLOD was a non-safety related system, and therefore, not subject to 10 CFR Part 50, Appendix B requirements. Dominion entered this performance deficiency into their corrective action program (CR 553968). Because this finding does not involve a violation of regulatory requirements and is of very low safety significance (Green), it is identified as a finding. (FIN 05000336, 423/2014011-02,Inadequate Implementation of Dominion’s Design Change Process).

Oct 30 12:00 New: what does the mean?

Was the SAR seen by the NRC and is the SAR in Adams?

What is the extent of condition or cause with Dominion's declaring not needing a LAR and falsely saying these is no increase in risk or it is not a design change? Is their other missed Licence Amendment Requests?

Was the NRC informed of the UFAR update and why didn't that cue the NRC it was a improper plant design change?

These design change documents included a 10 CFR 50.59 screening and applicable safety analysis report (SAR) change notices for both the Millstone Unit 2 and 3 UFSARs.

Pilgrim plant is recent years had LOOPs out the ying yank…all sorts transmission and on property line shorts and trips. So how are the Pilgrim power line problems related Millstone?

I sure would like to understand why and the duration of this maintenance activity on the lines.

Prior to the event, one transmission line had been OOS for scheduled maintenance.

This is the guys who started the cascade accident called a dual plant trip and loss of all offsite power. I certainly would like to understand this short and then how it tripped the second line.

A suspected ground fault on the grid in the Northeast Utilities’ Card substation caused the loss of offsite line 383. (Seems it was caused insulator and some kind of trouble with the protection circuit.)

So the question remains, in a change to a facilities licence, why can't the NRC catch a wrong call in the screening and 50.59 on a design change. Why does it depend on the licensee declaring they are breaking the rules?

But everyone in the "systems" feels protected and secure in operating in silowing, cubbyholes and meaningless categorizations. Holistic thinking is hard work.

DOMINION NUCLEAR CONNECTICUT, INC. (DNC) MILLSTONE POWER STATION UNITS 2 AND 3 RESPONSE TO AN APPARENT VIOLATION IN NRC SPECIAL INSPECTION REPORT 05000336/2014011AND 05000423/2014011; EA-14-12

Apparent Violation

As stated in the summary section of NRC Special Inspection Report,05000336/2014011 and 05000423/2014011, during an NRC team inspection conducted between June 2 and July 15, 2014, "the NRC identified a Severity Level Ill Apparent Violation (A V) of Title 10 of the Code of Federal Regulations (10 CFR) 50.59, "Changes, Tests, and

So the NRC inspectors should have been in many outage and design change meetings and seen their documents. What didn't the NRC on their own see the Millstone design change on the transmission system and the circuit change, this was big, and it entailed an increase of risk. Is the bifurcation of nuclear safety responsibilities and ownerships between a on site transmission authority and near site transmission authorities a unreviewed safety issue.

Experiments," for Dominion's failure to complete a 10 CFR 50.59 evaluation and obtain a license amendment for a change made to the facility as described in the Updated Final Safety Analysis Report (UFSAR). Specifically, ... a

NRC OIG Inspection: On June 7, 2006, SCE notified NRC of its intent and timeline to replace Units 2 and 3 steam generators under 10 CFR 50.59. The SCE briefing document indicated there would be no associated power uprate and that associated technical specification changes were scheduled to be identified in 2007.

special protection system (SPS), known as severe line outage detection (SLOD), [was removed] which was described in the UFSAR. Dominion concluded in the 10 CFR 50.59 screening that a full 10 CFR 50.59 evaluation was

NRC OIG: An attachment to the inspection report listed, by number, the 15 screens, 8 evaluations, and 12 plant modifications the inspectors reviewed. Included within the list of eight evaluations reviewed was number 800071702, which OIG learned was the number SONGS assigned to its 10 CFR 50.59 screening and evaluation pertaining to its Unit 2 replacement steam generators.

not required and, therefore, prior NRC approval was not needed to implement this change. The team concluded that prior NRC approval likely was required because the removal of SLOD may have resulted in more than a minimal increase in the likelihood of occurrence of a malfunction of the offsite power system as described in the UFSAR."

Response to the Apparent Violation

Dominion Nuclear Connecticut, Inc. (DNC) submits the following information in response to NRC Special Inspection Report 05000336/2014011 and 05000423/2014011 which was issued by the NRC on August 28, 2014. DNC chooses to respond in writing to AV 05000336/2014011 and 05000423/2014011 and declined the opportunity for a Pre-decisional Enforcement Conference (PEC) and the opportunity to request Alternative Dispute Resolution (ADR) during a phone call on September 8, 2014, between Lori Armstrong of DNC and Raymond McKinley, Chief, Division of Reactor Projects Branch 5, NRC Region I.

1) The reason for the Apparent Violation (AV) or, if contested, the basis for disputing the violation DNC does not contest the apparent violation.

NRC's review and approval of the change to the Millstone Power Station Unit 2 (MPS2) and 3 (MPS3) licensing basis for the removal of SLOD was not requested by DNC because

Well, there is lots of Millstone's management levels who had to sign off on this?

of an inadequately prepared 10 CFR 50.59 screen. In the 10 CFR 50.59 screen, Engineering personnel failed to consider that the removal of SLOD was an adverse change

So why didn't Dominion send a notification to the the Plant NRC inspector of major work on our local transmission system potentially affecting safety, we find no increase in risk...please cover our backs with checking out our work???

Why does the licensee and NRC sounds more like enemies to each other, at a complete state of total war with each other relationship, instead of everyone covering each other's back(morally and ethically)? Do it the right way and no taking shortcuts?

Honestly, I can't imagine the NRC not nosing around the site on their own and finding the major work was going on in transmission system in the document and the list of potential and on going major work. Doesn't that say a lot they couldn't discover this on their own? How much else does the NRC miss with not being "intrusive".

According to the NRC OIG report on SONGs, the NRC is coming out with a major committee report on the agency's lessons learned on the SONGS SG debacle late this fall. I can't wait to see this guy?

relating to DNC's compliance with General Design Criteria (GDC) 17, and therefore did not conclude that a 10 CFR 50.59 evaluation was needed.

The root cause evaluation for this AV identified the direct cause as a lack in proficiency and skill in performing 10 CFR 50.59 screens. The root cause for this AV was determined to be that continuing training was not adequate to maintain the proficiency and skills for consistent, accurate screens. Corrective actions were needed to address the screening deficiency identified in the apparent violation.

The complexities associated with the technical issue, multiple responsible entities involved, and understanding of the MPS2 and MPS3 licensing basis are also relevant to understanding the contributing factors for the AV. During review of this AV, it was determined that DNC's error of not performing a 10 CFR 50.59 evaluation occurred during the design development for the removal of SLOD by the transmission owner, Northeast Utilities (NU). During the design development, DNC did not recognize that NU's removal of SLOD resulted in a change in the method of compliance with GDC 17 that required DNC to perform a 10 CFR 50.59 evaluation. This matter is further addressed in the Additional Information provided below.

2) The corrective steps that have been taken and the results achieved

With removal of SLOD, and as discussed in the Additional Information provided below, the station no longer met the method for compliance with GDC 17 approved by the NRC at the time of original licensing of MPS3. As documented in NRC Special Inspection Report 05000336/2014011 and 05000423/2014011, DNC implemented a compensatory measure by issuing an Operations standing order for interim guidance on future offsite line outages and plant generation output. In March 2014, prior to the NRC Special Inspection, DNC had separately implemented improvements in the procedural guidance for performing 10 CFR 50.59 screenings.

These improvements were the result of DNC identified gaps in performance of 10 CFR 50.59 screenings. Improvements included a major rewrite and expansion of the guidance for completing 10 CFR 50.59 screens using a more user-

NRC OIG:

"According to the former NRR Director, if there were problems with the 50.59 process, it would have manifested itself in many more issues than just the steam generator issue."

"Although these reviews are never 100 percent because they are done through sampling, his expectations are that the inspectors look hard and that they challenge."

"The Team Leader thought existing 10 CFR 50.59 guidance could be improved."

"She recalled that each region interpreted the inspection procedures differently."

"Additionally, the Team Leader said there was no specific training for 50.59."

"Team Member 1 also thought the 50.59 guidance available to inspectors is too vague."

"From his experience, the licensee and NRC routinely get into disagreements because of interpretation of the guidance."

"He said while there may be an opportunity - if an inspector reviews something while it is being worked on - to identify something that can change the course of the licensee's path, but typically the activities are already done in the field, or on their way to being done, before NRC starts looking."

"The challenge is that there are so many different types of components, structures, and systems and it is hard to write a procedure that captures all those different circumstances."

"Although these reviews are never 100 percent because they are done through sampling, his expectations are that the inspectors look hard and that they challenge."

"The former Regional Administrator wants them to be as thorough as they can be, but their time is limited."

"So they can never look at everything."

"However, he said that inspectors do not look at everything and are trained to sample."

"NRC does not have the resources, including time or manpower, to review everything and so inspectors sample."

"According to the former NRR Director, based on the information provided by OIG pertaining to methodology changes, it appeared that NRC may have done a bad job of reviewing the SONGS 50.59 during the 2009 inspection; however, one should be careful before concluding that this was a broader problem than SONGS."

"Nevertheless, as the NRR Director responsible for the operational safety of 100 nuclear power plants and research and test reactors, he has limited resources."

"Also, he said, "We're only going to be able to sample, and you always want to make sure that you're sampling the items with the highest likely safety significance input."

"The Deputy Executive Director commented that the high frequency with which licensees use the 50.59 process coupled with the relatively low frequency of issues identified by NRC suggests to him that training could be a factor."

"We had a lot of stuff to look at. ..We didn't look at everything."

"He said the AIT's determination was - based on review of the FSAR, the engineering change package describing the new design, the 50.59 screen and evaluation, and other items - there was no indication that the licensee needed a license amendment."

"He said that reviewing the 50.59 entails reviewing a sampling and based on his years of experience as an inspector, he said, "you don't expect 100 percent of everything, but you review it. . . and you dig deeper into things that don't sound right."

"He said that all inspections are done by sampling."

"However, if the region missed some of the methodology changes it was because inspections have always been no more than a sampling."

"He said to make a definitive decision on whether a license amendment request was required, the agency would have to talk about the resources needed to accomplish that. He said, "It comes down to a prudent use of resources to go back and accomplish that."

"The Project Manager said that the UFSAR reviews by project managers are a low priority and he was not sure if they could be given a higher priority because project managers have a lot of work already."

friendly format. The procedure now includes more detailed guidance for responses to each section of the screen form

NRC OIG: "In his opinion, the NEI 96-07 guidance is too vague, allows for too many judgment calls, and needs solidifying of definitions. From his experience, the licensee and NRC routinely get into disagreements because of interpretation of the guidance.

including direct references to NEI 96-07, Guidelines for 10 CFR 50.59 Implementation.

NRC OIG: “For example, he said "more than a minimal increase" should be defined by a specific value in 1O CFR 50.59. (OIG notes that "more than a minimal increase" is the terminology used in several of the 1O CFR 50.59(c)(2) screening criteria.” “Team Member 1 told OIG that training for 50.59 inspections could be improved. He said NRC needs to insure inspectors are fully trained and versed in the 50.59 process.”

“The Branch Chief also told OIG that training was an area that needed improvement and that the quality of a 10 CFR 50.59 inspection is dependent on the inspector's knowledge, experience, and background. He said the guidance is complex and there is a lot of judgment that is applied in using it.”

In August 2014, training was provided on an expedited basis to a select population (the majority) of 10 CFR 50.59 screeners. The training included discussion on the fundamentals of GDC compliance and the importance of identifying and reviewing the impacts of design changes upon the licensing basis, including the FSAR. Only personnel who have received the training are presently qualified to perform 10 CFR 50.59 screens.

Design changes scheduled for implementation in the remainder of 2014 have been reviewed by Design Engineering to determine whether adequate licensing basis reviews were conducted as part of the 10 CFR 50.59 screenings. No 10 CFR 50.59 screens were identified which should have concluded a 10 CFR 50.59 evaluation was required.

3) The corrective steps that will be taken

To become qualified to perform 10 CFR 50.59 screens, future training will include a discussion of the fundamentals of GDC compliance and the importance of identifying and reviewing the impacts of design changes upon the licensing basis, including the FSAR.

Why don't we need NRC national training on all licensing issues and qualification testing?

A review of the 10 CFR 50.59 screens for FSAR changes processed in the past three years will be conducted by April 1, 2015 to determine whether adequate licensing basis reviews were conducted.

DNC is evaluating options for addressing compliance with GDC 17. To complete this work, engineering analysis, including consideration of potential design modifications, is necessary. Upon completion, a License Amendment Request (LAR) will be submitted to the NRC requesting review and approval of a licensing basis change to the MPS2 and MPS3 FSAR that addresses the removal of SLOD. DNC will keep the senior resident inspector informed of the status and schedule for resolution.

4) The date when full compliance will be achieved

Full compliance was achieved when training was provided in August 2014. To ensure future continued compliance, the 10 CFR 50.59 training module will be updated to include a discussion of the fundamentals of GDC compliance and the importance of identifying and reviewing the impacts of design changes upon the licensing basis, including the FSAR.

Additional Information:

The SLOD system was owned by the transmission system owner, NU. Removal of SLOD was a result of a major transmission line upgrade project to improve grid reliability by separating lines and towers leaving the MPS switchyard. This separation allowed NU to eliminate SLOD, which they no longer considered reliable or secure.

So the instrumentation was getting unreliable and obsolete...just rip it out without telling the NRC.

The upgrade, as it was presented, reduced risk to MPS and improved grid reliability to MPS.

Why wasn't the NRC invited to a meeting?

Representatives of DNC and NU participated in multiple Nuclear Plant Interface Meetings (NPIMs) coordinated by ISO New England (the transmission system operator). These meetings, which began several years in advance of the actual physical modifications, included discussions of proposed changes to the transmission system.

The transmission upgrade project by NU involved rerouting the transmission lines from four lines on two towers to four lines on four separate towers. The removal of SLOD was presented in the aggregate as an improvement in grid reliability, conforming to present transmission system standards. According to the North American Electric Reliability Corporation standard on special protection systems (SPSs), SPSs such as SLOD carry with them unique risks including, risk of failure on demand and inadvertent activation, and risk of interacting with other SPSs in unintended ways. Thus, at the time, DNC,

I bet you the overarching ideal was to yank this gear out of the system before it caused an inadvertent trip on fault.

ISO New England, and NU believed that separation of the towers/lines removed the vulnerability which SLOD was installed to mitigate and represented an improvement in grid reliability. Therefore, following tower line separation, SLOD was disabled and eventually removed. DNC recognizes that during the design development for the modified transmission circuits, there were opportunities to understand that the Millstone licensing basis was impacted by the removal of SLOD and that a 10 CFR 50.59

What about worrying about the collapse of the Pennsylvania and New York grid on past LAR related(2000)documents?

evaluation would be required. DNC accepted the changes proposed and approved by NU, ISO New England, and the Northeast Power Coordinating Council without adequately considering the impact to the MPS licensing basis. The complexities associated with the specific technical issue, multiple responsible entities involved, and understanding of the licensing basis all played a part in the failure to recognize the impact of the change on the licensing basis.

The 10 CFR 50.59 screen failed to consider that the removal of SLOD was an adverse change relating to DNC's compliance with GDC 17, and therefore did not conclude that a 10 CFR 50.59 evaluation was needed. It was the belief that the tower and line separation project, including SLOD removal, was undertaken by NU for the sole reason to enhance grid stability and reliability, providing a more stable source of offsite power to MPS. That belief resulted in the DNC mindset that the removal of SLOD references from the FSARs did not require further evaluation. Following the May 25, 2014 event, DNC recognized that SLOD was credited for GDC 17 compliance and its removal should have been considered an adverse change requiring a 10 CFR 50.59 evaluation.

Extensive engineering analysis, including consideration of potential design modifications, is ongoing to address DNC's compliance with GDC 17. Upon completion of this work, a LAR will be submitted to the NRC requesting review and approval of licensing basis changes to the MPS2 and MPS3 FSARs for GDC 17.

As noted in the response to Question 3, improving sensitivity to the license basis and the 10 CFR 50.59 requirements is being addressed by training to prevent future similar situations.

Of Interest:

Lawsuit: Quake standards altered at California nuclear plant

Dr. Mike Peck Differing Professional Opinion

"After filing the motion, however, the group learned that the plant’s final safety analysis report, a document required by the plant’s license, had been changed last year, altering the methodology for measuring seismic safety and stating that the plant can withstand shaking up to .75 times the force of gravity. Such a fundamental change, the group argues, requires amending the operating license itself, a process in which the commission must give the public the opportunity to comment.

Report not public

Instead, the revised safety analysis report wasn’t available to the public on the commission’s website. When Friends of the Earth requested a copy, they received a redacted version.

Commission spokeswoman Uselding said information related to nuclear plant safety is often released to the public on a case-by-case basis, after a commission staff member has reviewed the request to address national security concerns."

They needed 50.59 for this in July 2001 and then to rip the whole thing out in 2012? Who cares if they screwed Pennsylvania and New York by 2012? If new grid conditions made this non applicable today, why not fix the FSAR documents with a updated grid analysis?

Millstone Nuclear Power Station, Unit Nos. 2 and 3 10 CFR50.59 and Commitment Change Report for 2000

"The Severe Line Outage Detection (SLOD) system is designed to prevent instability and loss of all generation at Millstone Station. Besides avoiding unit instability, a distribution system casualty with generation above 1300-1400 MW at Millstone Station could have severe, adverse consequences on Pennsylvania and/or New York grid reactive and thermal operating conditions. The SLOD system is continuously armed and avoids instability and loss of all generation at Millstone by tripping only pre-selected units when certain conditions exist. The tripping logic associated with the SLOD system was modified to remove all trips associated with Millstone Unit No. 1. The Double Line and Breaker Failure Detection Unit Rejection Special Protection System (DBURS), two more Special Protection Systems (SPS) used to trip pre-selected units at Millstone, were deleted and removed since their functions were no longer needed due to the loss of Millstone Unit No. 1 generation. CRP-909 was connected to the master supervisory panel in the 345-kV switchyard via a new fiber optic cable. Switches on CRP-909 for control of Millstone Unit No. 1 switchyard circuit breakers and motor operated disconnects were removed."

MILLSTONE POWER STATION – NRC INTEGRATED INSPECTION REPORT

05000336/2012003 AND 05000423/2012003

"Summer Readiness of Offsite and Alternate Alternating Current (AC) Power Systems

a. Inspection Scope

The inspectors performed a review of plant features and procedures for the operation and continued availability of the offsite and alternate AC power system to evaluate readiness of the systems prior to seasonal high grid loading. The inspectors reviewed Dominion’s procedures affecting these areas and the communications protocols between the transmission system operator and Dominion. This review focused on changes to the established program and material condition of the offsite and alternate AC power equipment. The inspectors assessed whether Dominion established and implemented appropriate procedures and protocols to monitor and maintain availability and reliability of both the offsite AC power system and the onsite alternate AC power system. The inspectors evaluated the material condition of the associated equipment by interviewing the responsible system manager, reviewing condition reports (CR) and open work orders, and walking down portions of the offsite and AC power systems including the 345 kilovolt (KV) switchyard and transformers. Documents reviewed for each section of this inspection report are listed in the Attachment."

t.