The Real Entergy Shows Its Ugly Head

Is this just training for Entergy? 

Entergy thinks we’re stupid

(Honestly, you are stupid.) 

Updated 7:28 AM; Posted 7:28 AM

 Entergy New Orleans CEO Charles Rice, at left in gray suit, listens as protesters oppose the $210 million gas-fired power plant that Entergy proposed for New Orleans East. The council approved the plant with a 6-1 vote after an hours-long hearing in March. (Kevin Litten, NOLA.com | The Times-Picayune) 

By Tim Morris, Columnist

timothy_morris@nola.com

Fining Entergy New Orleans just $5 million for seeking to subvert the democratic process, mislead the City Council and wage war on residents hardly seems adequate.

For starters, there is the question of whether a $5 million fine will get the attention, let alone change the behavior, of a company with annual revenues of $11 billion and literal power over 2.9 million utility customers in Arkansas, Louisiana, Mississippi and Texas.

And then there is the sheer hubris the company displayed in trying to rig a political process that was already so embarrassingly weighted in its favor that no self-respecting Las Vegas bookie would have taken odds against council approval of the company’s plans for a new gas-fired power plant in New Orleans East.

Taking council members at their word that the 6-1 vote for the plant last March was based on the testimony of “experts,” what advantage did Entergy gain by hiring actors to show up at hearings in matching orange T-shirts, carrying mass-produced signs and reading heartfelt pleas for jobs, power and an end to “cascading outages” from prepared scripts?

Was then-Entergy CEO Charles Rice really that obsessed with overwhelming and humiliating activists and concerned residents with a shock and awe campaign of paid protesters? Text messages and other previously private communications uncovered by an independent City Council investigation certainly suggest that.

"This is a war and we need all the foot shoulders [soldiers] we can muster," he says in a discussion of whether Entergy would be willing to pony up for more ersatz supporters.

It’s never a good look when the head of a major utility is caught equating what is supposed to be a fair and open democratic process with all-out warfare, especially when his side has actual nuclear power and the resistance is mostly worried about how a new plant will affect their property values, quality of life and their children’s health.

This is the worst use of political dirty tricks since Richard Nixon’s Committee to Re-Elect the President, CREEP, tried to bug the Democratic Party headquarters at the Watergate in the campaign against South Dakota Sen. George McGovern. The “third-rate burglary” eventually spawned an investigation that forced Nixon to resign from his second term in the face of impeachment.

Nixon, by the way, defeated McGovern in a historic landslide with the Democratic challenger winning only in Massachusetts and the District of Columbia while losing everywhere else, including his home state of South Dakota.

There has never been any evidence that any of Nixon’s subversive political knavery had much impact on the electoral outcome. But that’s what happens when the political process, which is supposed to be “war by other means,” is embraced as actual warfare.

Only in this case, the “foot shoulders” were more “Hogan’s Heroes” than “Saving Private Ryan.” Did anybody really think that hiring local actors to appear in public venues was going to escape detection?

At some point isn’t someone going to notice that a beer-drinking buddy who used to be laser-beam focused on playing a cadaver on “NCIS: New Orleans” was suddenly a rabid convert to extolling the virtues of a “safe, reliable gas-fired peaking power plant over the alternative of being 100 percent reliant on transmission during a storm."

They must have thought we were all that stupid.

And even as the City Council’s investigation uncovered damning communications between top Entergy executives, the company continued to claim it has been duped by the outside public relations firm it hired to sell the plant proposal. Investigators also complained that Entergy has been less than forthcoming in forking over information requested. Not exactly encouraging signs moving forward.

What we need is more lifetime voters, folks who make it habit to get to the polls — informed and engaged.

Rice abruptly stepped down as Entergy’s CEO in August to take on a new role in — I’m not making this up — the company’s legal department.

Perhaps he will get to review the resolutions passed last week by the City Council that could include that $5 million fine and other requirements meant to induce a “sea-change in the corporate culture” at Entergy New Orleans.

City Councilwoman Helena Moreno called the episode “just plain sad and disappointing" and lamented that Entergy had "lost sight of the company they’ve always claimed to be.”

NHDOT Are Scumbags

Update Nov 5

The Keene Sentinel and 99% of the mega rich newspapers owners are infected with the same philosophical mental model defect. Basically, me saying two plus two equals four. They would come back, I can't report that because you showed me no proof. The bankrupted black and white philosophy of them picking and choosing what is evidence and proof that is needed to report the truth to the best of their ability. They are too lazy to get off their fat asses to see something beyond the surface truth and their simpleton model of how the world in their heads works. Usually there is a agenda under this: I've got a keep my job and feed my family and the owners got to make the paper comport to their own monied ideology. More likely, I will never get advertising revenue if I tell what is really going on.    

***Why can't the Keene Sentinel connect the dots? I hear rumors they are shutting down. Most of their facility, including the front desk, are a shithole. 

I think this state wide NHDOT inspections on Truss bridges comes out of my activities with the Brattleboro/Hinsdale route 119 bridge. I have been accusing the state of doing fraudulent bridge inspection based on politics and favors beginning in 2011. I have been saying for many years now the conditions of the bridges are a lot worst than the bridge NHDOT inspections. This year it went from a perfectly safe bridge to a red listed bridge needing a special inspection every 6 months. From a normal five year bridge inspection schedule to a once every 6 months inspection. The next inspection grade down is a shutdown. For years now, I have been picturing up the horrible conditions of my bridges. The facts on the ground here is the state has no engineering mechanism to predict the decline with this ancient bridge. This is what was proven in Hinsdale this year.

(added)
The rub here, with the skimpy state inspections, they don't collect enough data points to truly understand the accurate condition of the bridge inspection and be able to anticipate the material degradations. Fixated on the black and white engineering philosophy of facts and evidence. Can't image what information is missing from your skimpy inspections process. As I've said for years, their inspection presses are made flawed for political considerations, but they think their processes are dead on accurate. Honestly, the only people allowed to inspect the bridges should be highly educated and trained state employees. The state should have total control of these employees and they not be loyal be loyal to any other interest. But this is the NH advantage? Hate governed and barely fund the NH agencies. I don't trust the  bridge inspection contractor. As I said before, the non government bridge inspection contractor is only answerable to money and profits...         

The new bridge's price is somewhere near $60 Million dollars...

There is a high probability 

Nov 4

Lane closures slated on Charlestown bridge

By Sentinel Staff

12 hrs ago

Top of Form

Bottom of Form

CHARLESTOWN — Motorists who travel the bridge that carries Route 11 across the Connecticut River between Charlestown and Springfield, Vt., can expect up to five days of lane closures starting Monday, the N.H. Department of Transportation has announced.

The closures are to allow for what the department describes in a news release as an “in-depth inspection” of the span. The inspection is part of a statewide effort to assess the condition of New Hampshire’s truss bridges, according to the state transportation department.

The closures will be in effect daily as needed, 7:30 a.m. to 4 p.m., as weather allows.

Drivers will be alerted to the lane closures by people with flags as well as by warning signs, and they’re encouraged to use other routes if possible due to the resulting delays.

Junk Plant Grand Gulf: Isn't It About Time For A Scram Or a Prolonged And Deep Downpower?

Update Nov 7

Well, River Bend and Grand Goof are back a 100%. I still feel Grand Gulf is heading to a big fall. This round of erratic ops was just a warning.

But ANO unit 2 is still in a huge unexpected feedwater leak outage...

Entergy plants.

Update Nov 6

Grand Gulf 85%

The good news, River Bend is back to 100% power and Entergy always had plentiful nuclear engineering positions.

Update Nov 5

Grand Gulf is down to 92% power today.

Nov 2 62 % power
Nov 3 62
Nov 4 93
Nov 5 92

I would consider this a pretty large down power event. There is a slight chance this a adjusting control roads.

River Bend has had pretty erratic power operations this past week or so too.

What is going in at Energy's in region 4?

***River Bend has been erratically up and down in power for the last 5 days. Big moves.

US Terrorism Against Leftist Top Leadeship

Update

See, took the Saudi story right off the air?

***I think we got it all wrong. This US terrorism is a distraction from the Saudi murder with the Washington Post reportor. Factions within the Trump administration or our Defense establishment wanted to buy time to come up with a acceptable coverup story. They might cave to profond troubles with defense contracts and the Saudis being isolaled from the world.

ANO 2: What The Hell Is Going On With Their 9/16 Feedwater Leak

So they immediately scrammed or shutdown. This is a drastic example of how much deregulation has been going on with the NRC. Where is the event report on feedwater leak or on the shutdown or scram. This would have been required in the Obama years.

They scrammed or shutdown on Sept 16, 2018 and it is now Oct 25...that is 39 days. I wonder where the leak was located?  The feedwater pressure is up to 1000 psi and around 600 degrees. If the leak was in the primary containment, it would be a more of a safety concern. It certainly is a employee safety concern.

This sounds like many feet of feedwater pipe is being replace...

A leak in the feedwater system can emediately fill up a room with steam. This kind of leak has killed 4 people I believe the Surry plant. It wrecks havoc with creating shorts and equipment problems throughout the plant.  

Dead Ender Palisades: Losing NRC Faith in Science and Engineering over CDRM Leaks

This is what a plant looks like at end of life, when they are starving funding to the plant. Lot of equipment troubles showing up and losing employees prodigiously. What do we have about 10 plants in this condition is the USA? A big accident waiting to happen killing the rest of the industry.

Didn't they put in new CDRMs due to continuous leaks in around 2015. Check out my comments on this. Check out my comments below the article? Once President Trump came into power the NRC shutdown the "NRC's Blog". So they replace all but eight CRDMs in 2015. A CRDM replacement job is tremendously expensive and the radiation dose for the employees. Don't get me talking about titanium gonads protection for this job. Is the leak in the eight not replaced CRDMs in 2015...the the titanium gonad outage...or the rest of the CRDMs that were replaced. Is it a new CRDM or a old CRDMs. Basically the design of the reactor and the associated CRDMs was defective from day one of plant operation. It is a very old reactor. Palisades has the worst CRDM leak rate in the industry.         

An Inspector’s Perspective On the Control Rod Drive Mechanism Housing Flaws At Palisades 

Palisades maintenance outage underway

· By JIM DALGLEISH - Assistant Local News Editor
· 2 hrs ago

COVERT — The Palisades nuclear power plant is starting its second week of a repair outage, which comes in advance of a planned refueling outage, the plant and federal regulators reported.

Plant spokesman Nick Culp said Friday that operators shut down the reactor Oct. 13 for planned work on a degrading control rod drive seal.

However, “during the scheduled maintenance, an internal transformer fault occurred, resulting in the loss of power supply to several components,” Culp said. “At all times, the plant remained in a safe and stable condition. Palisades employees are working to replace the transformer. (Nuclear Regulatory Commission) inspectors were made aware of the planned shutdown and have been kept informed throughout.”

The NRC on Friday reported that the step-down transformer failed as crews tried to restart the reactor after the drive seal repair.

For proprietary reasons, Culp said, plant owner Entergy does not divulge when the plant will restart or if managers will roll the current outage into the refuelling outage. It will not say when the refuelling outage was to start.

“This maintenance project comes after 198 days of continuous safe operation and is reflective of our ongoing commitment to running the plant well,” Culp said in a statement. “... During the coming outage, Entergy will invest tens of millions of dollars in the plant’s safe and reliable operations.”

The fall refueling outage will be one of the last two before the plant shuts down in 2022, Culp said. 

Flooding Upstream Of The South Texas Nuclear Project, What Rivers?

Update

The site is not under a threat. 

***Hmm, Llano River and Colorado River. Plant is just south west of Houston on the coast. Central Texas is being inundated with precipitation. 

Brunswick Still Has flooding Issues Post Fukushima Retrofit

This is what I sent the NRC on Sept 12. Remember hurricane Florence petered out to a below Cat 1 hurricane as it hit landfall. A true cat 4 or 5 would have been devastating. 

Again, was the Fukushima lessen learned comprehensive at Brunswick? Does this prove it wasn't. These are all really smart people, maybe there is fraud and corruption.

Usually this would flip into a special inspection. But now the new NRC has a intermediate step favoring the licensees and the industry...meaning less special inspection. There is no doubt in recent years the NRC has had a lot less special inspection...   

Wednesday, September 12, 2018

NOAA Says The Two Plant Brunswick Nuclear Plant Are Heading For a Meltdown in a Cat 4 Hurricane

Still working on this

Cat 4 Hurricane Hugo had a storm surge of 18 feet in North Carolina. I don't know if it was in the high or low end of a Cat 4 hurricane? Remember Florence is 21 feet about sea level. You know, what is your definition sea level? There is many of them. I got my measurement of Brunswick's above sea-level height of 21 feet from google earth. I kinda thought over topping the Brunswick's site was not probable in a Cat 4 or 5 hurricane. I did not believe these plants could be constructed so closes to sea-level. I figured these plants could easily survive high in the Cat 5 level. I now know it is probable ocean overtopping the site in a cat 4 or 5 is a certainty. I totally believe the NOAA's cat 4 or 5 storm surge calculations. Remember the hurricane ocean over topping is 3 feet at Brunswick per NOAA.

I am shocked at this latitude this plant is so poorly situated. I suspect more plants are in the same situation.

Now I consider it a high probability there will be a guaranteed of meltdown at Brunswick in a cat 4 or 5 hurricane. This is our Fukushima. Are the reactor building, turbine building, diesel generator rooms or the switchyard are not designed for a 6 feet or more ocean over-topping of their site. Can the flex system over come this kind of defect with a 6 feet or more over-topping of their site. In the best of any ones computer models, they is just too much uncertainty.

I think the turbine building and reactor building would quickly fill up with ocean water rendering all ECCS inoperable. I think the ECCS safety busses are on the ground floor. They would become inoperable. As far as the diesel generators, they are probrably on the ground floor. Certainly the diesel generator's local breakers are on the ground floor. There is your blackout where the flex system being useless too. You going to helicopter a flex system big DG or pump into 6 feet of water?

I make the case in climate change, these big hurricanes will be much more probable.

Questions

1) Is it in plant licensing all US are nuclear plant are supposed to survive all cat 4 and 5 Hurricanes without a meltdown?

2) Think about the movement and safety of operators on site in a over-topping conditions. There would be no movement.

3) Would the hardened vent be usable or accessible?

I request a emergency investigation on this Hurricane ocean surge issue on a Cat 4 and 5 levels at Brunswick. Can this plant survive a Cat 4 or 5 hurricane without a meltdown? Is there a extremely high likelihood these plants would not meltdown? Actually, if a plant can't survive a Cat 4 or 5 hurricane without meltdown, these plants should be emediately shutdown in the greater interest of the USA?

I am considering a 2,206?

Sincerely,

Mike Mulligan
Hinsdale, NH

Cell: 1603 209-4206
steamshovel2002@ yahoo.com         

I guess the NRC has flooding issues with Brunswick post Hurricane Michael? 

From: Guill, Paul F <Paul.Guill@duke-energy.com> Sent: Wednesday, September 26, 2018 1:13 PM To: Vega, Frankie Subject: [External_Sender] RE: Brunswick Flooding MSA review
Frankie;

The clarification information requested is provided below in red. Let me know if need any additional information to support your review. Again, thanks for your patience 

From: Vega, Frankie [mailto:Frankie.Vega@nrc.gov]  Sent: Monday, September 24, 2018 1:04 PM To: Guill, Paul F <Paul.Guill@duke-energy.com> Subject: RE: Brunswick Flooding MSA review

*** Exercise caution. This is an EXTERNAL email. DO NOT open attachments or click links from unknown senders or unexpected email. ***  Hello Mr. Guill;

Just a quick follow-up with my request below. I know that you guys are still dealing with the aftermath of the hurricane so I understand if the responses are not yet ready.

Thanks

Frankie 

From: Vega, Frankie  Sent: Wednesday, August 15, 2018 2:25 PM To: 'Guill, Paul F' <Paul.Guill@duke-energy.com> Subject: RE: Brunswick Flooding MSA review

Hello Mr. Guill;

In addition to the documents already provided I would need the following clarification information in order to complete my review:

Flooding MSA Section 3.5.1 states the following: While most safety-related structures have finished floor elevations above 22 feet NGVD29, the Reactor Building has two access openings at 20 feet NGVD29: the equipment access airlock (i.e., railroad airlock) and the personnel airlock. Leakage past these doors is intercepted by floor drains and routed to sump areas on the -17 feet level of the Reactor Building. The minimal water intrusion spread over the large area of the Reactor Building would not challenge any plant equipment relied upon for the FLEX strategy. In order to confirm that no key FLEX equipment is impacted by the LIP, can you please provide additional information regarding in-leakage water quantities and expected flood water depths at the -17 feet level.

DUKE RESPONSE: In-leakage is conservatively determined to be 30 gpm for 6.3 hours from Reactor Building Doors D-2 and D-3 (closed). This leakage would migrate to the -17 ft elevation and be distributed over an area of about 140 ft by 40 ft and would result in approximately 3.25 in. (0.3 ft) of water on the -17 ft elevation floor. The RCIC pump, located in the S. RHR Room, is relied upon for the FLEX strategy and is located on raised pedestal 2 ft-8 in above the floor. Instruments on the bottom row of instrument racks are located at least 12.9 in above the floor resulting an APM of 0.8 ft. 

Also, water levels are expected to reach 26 feet NGVD29 or above at the reactor building due to the combined effects storm surge. These levels are well above the access openings for the reactor building airlock doors referenced above. It appears that the MSA doesn’t address the potential water leakage through these doors due to storm surge water levels. In order to confirm that no key FLEX equipment is impacted by the storm surge, please provide additional information regarding expected in-leakage water quantities and expected flood water depths at the -17 feet level.

DUKE RESPONSE: In the Combined Effects Storm Surge event, temporary passive barriers are to be installed interior to the reactor airlock doors D-2 and D-3 with triggers for actions as per BSEP Administrative Instruction 0AI-68. There is no in-leakage past these barriers and therefore in-leakage calculations are not performed for these locations. Modifications to these barriers are required to raise the top elevation from 26 ft to 27.5 ft NGVD29, which presents a minimum of 0.8 ft of margin at these barriers.

No formal responses are needed at this moment so replying to this email or placing the information in the electronic reading room (ERR) would work for me. If you have questions or need clarification on the questions above, please let me know. 

I will be out of the office starting tomorrow until August 28 so no rush on this response. My replacement during my time-off would be Joe Sebrosky (Joseph.Sebrosky@nrc.gov). Joe is not familiar with Brunswick’s flooding MSA so no need to forward him the response to the questions.

Thanks

Frankie

From: Vega, Frankie  Sent: Wednesday, August 08, 2018 3:44 PM To: Guill, Paul F <Paul.Guill@duke-energy.com> Subject: Brunswick Flooding MSA review

Mr. Guill;

Hope you’re doing well. I’m currently reviewing the Brunswick MSA submittal and in order to complete the review I would need to have the following references from the MSA submittal available in the electronic reading room (ERR):

11. BSEP Procedure, Abnormal Operating Procedure 0AOP-13.0, Operation during Hurricane, Flood Conditions, Tornado, or Earthquake, Revision 67. 14. BSEP Calculation BNP-14-009, Combined Effects Flood Evaluation, Revision 1. 22. BSEP Engineering Change, EC 287907, Fukushima 2.3 Flooding Inspection Documentation – BNP, Attachment Z01, Flood Protection Walkdown Final Report for BNP Nuclear Plant Site, Revision 3. 30. BSEP Drawing F-02277, Diesel Generator Building Floor & Wall Sleeves, Revision 32.
3
33. BSEP Calculation BNP-17-001, Evaluation of Brunswick Plant Local Intense Precipitation along FLEX Deployment Path, Revision 0. 34. BSEP Drawing F-11018, Reactor Building – Unit 1 Equipment Foundations at El. (-)17’-4, Revision 3. 35. BSEP Drawing F-01118, Reactor Building – Unit 2 Equipment Foundations at El. (-)17’-4, Revision 5.

I have access to the CERTREC IMS ERR so if you are using that ERR we should be good. At this moment I’m the only NRC staff member that needs access to the documents referenced above.

Thanks 

Frankie G. Vega, P.E. Project Manager NRR/DLP/PBMB 301-415-1617 Location: O-12F0

This e-mail guy is the first one about hurricane flooding post Hurricane Florence. It is dated Oct 27, 2018. Hurricane Florence hit landfall on Sept 14 2018

September 27, 2018 Serial: RA-18-0144
 U.S. Nuclear Regulatory Commission Attention:  Document Control Desk Washington, DC 20555-0001
 Subject: Brunswick Steam Electric Plant (BSEP), Unit Nos. 1 and 2 Renewed Facility Operating License Nos. DPR-71 and DPR-62 NRC Docket Nos. 50-325 and 50-324 Response to March 12, 2012, Request for Information Enclosure 2, Recommendation 2.1, Flooding, Required Response 3, Flooding Focused Evaluation Summary Report References: 1. NRC Letter, Request for Information Pursuant to Title 10 of the Code of Federal Regulations 50.54(f) Regarding Recommendations 2.1, 2.3, and 9.3 of the Near-Term Task Force Review of Insights from the Fukushima Dai-ichi Accident, dated March 12, 2012, Agencywide Documents Access and Management System (ADAMS) Accession No. ML12053A340
 2. NRC Letter, Supplemental Information Related to Request for Information Pursuant to Title 10 of the Code of Federal Regulations 50.54(f) Regarding Flooding Hazard Reevaluations for Recommendation 2.1 of the Near Term Task Force Review of Insights from the Fukushima.Dai-ichi Accident, dated March 1, 2013, ADAMS Accession Number ML13044A561 3. BSEP Letter, Flood Hazard Reevaluation Report, Response to NRC 10 CFR 50.54(f) Request for Information Pursuant to Title 10 of the Code of Federal Regulations 50.54(f) Regarding Recommendations 2.1, 2.3 and 9.3 of the Near-Term Task Force Review of Insights from the Fukushima Dai-ichi Accident, dated March 11, 2015, ADAMS Accession Number ML15079A385
 4. NRC Staff Requirements Memoranda to COMSECY-14-0037, Integration of Mitigating Strategies for Beyond-Design-Basis External Events and the Reevaluation of Flooding Hazards, dated March 30, 2015, ADAMS Accession Number ML15089A236
 5. NRC Letter, Coordination of Requests for Information Regarding Flooding Hazard Reevaluations and Mitigating Strategies for Beyond-Design-Basis External Events, dated September 1, 2015, ADAMS Accession Number ML15174A257
 6. Nuclear Energy Institute (NEI) Report, NEI 16-05, Revision 1, External Flooding Assessment Guidelines, dated June 2016, ADAMS Accession Number ML16165A178
U.S. Nuclear Regulatory Commission Page 2 of 4

7. U.S. Nuclear Regulatory Commission, JLD-ISG-2016-01, Revision 0, Guidance for Activities Related to Near-Term Task Force Recommendation 2.1, Flood Hazard Reevaluation; Focused Evaluation and Integrated Assessment, dated July 11, 2016, ADAMS Accession Number ML16162A301
 8. NRC Letter, Brunswick Steam Electric Plant, Units 1 and 2 - Interim Staff Response to Reevaluated Flood Hazards Submitted In Response to 10 CFR 50.54(f) Information Request - Flood-Causing Mechanism Reevaluation (CAC Nos. MF6104 and MF6105), dated March 16, 2017, ADAMS Accession Number ML17072A364
 9. NRC Letter, Nuclear Regulatory Commission Report for the Audit of Duke Energy Progress Flood Hazard Reevaluation Report Submittal Related to the Near-Term Task Force Recommendation 2.1-Flooding for Brunswick Steam Electric Plant, Units 1 and 2, (CAC Nos. MF6104 and MF6105; EPID L-2015-JLD-007 and EPID L-2015-JLD-008), dated November 15, 2017, ADAMS Accession Number ML17271A248
 10. NRC Letter, Brunswick Steam Electric Plant Units 1 and 2 - Staff Assessment of Response to 10 CFR 50.54(f) Information Request Flood-Causing Mechanism Reevaluation (EPID Nos. 000495/05000325/L-2015-JLD-0007 and 000495/05000324/L2015-JLD-0008), dated April 16, 2018, ADAMS Accession No. ML18089A055

Ladies and Gentlemen:
On March 12, 2012, the Nuclear Regulatory Commission (NRC) issued Reference 1 to request information associated with Near-Term Task Force (NTTF) Recommendation 2.1 for Flooding. One of the required responses in Reference 1 directed licensees to submit a Flood Hazard Reevaluation Report (FHRR). On March 1, 2013, the NRC issued Reference 2 to provide supplemental information to the request. The FHRR for Brunswick Steam Electric Plant (BSEP), Units 1 and 2, was submitted on March 11, 2015 (i.e., Reference 3).
 Following the Commission's directive to NRC Staff (i.e., Reference 4), the NRC issued a letter to industry (i.e., Reference 5) indicating that guidance is being prepared to replace existing instructions and provide for a "graded approach to flooding reevaluations and provide for more focused evaluations of local intense precipitation and available physical margin in lieu of proceeding to an integrated assessment."
 Guidance for performing flooding reevaluations is contained in Reference 6, which has been endorsed by the NRC in Reference 7. Reference 6 indicates that each flood-causing mechanism that is not bounded by the design basis flood (i.e., using only stillwater and/or wind-wave run-up levels) shall follow one of the following five assessment paths:
 Path 1: Demonstrate Flood Mechanism is Bounded Path 2: Demonstrate Effective Flood Protection Path 3: Demonstrate a Feasible Response to Local Intense Precipitation (LIP) Path 4: Demonstrate Effective Mitigation Path 5: Scenario Based Approach

U.S. Nuclear Regulatory Commission Page 3 of 4
Non-bounded flood-causing mechanisms in Paths 1, 2, or 3 require a Focused Evaluation to complete the actions related to external flooding required by Reference 1. Mechanisms in Paths 4 or 5 require an Integrated Assessment. The enclosure to this letter provides the Flooding Focused Evaluation Summary for BSEP.
The flooding analysis described in References 8, 9 and 10 was utilized as an input to this Flooding Focused Evaluation. The Flooding Focused Evaluation reaffirms that BSEP has reliable, passive protection of key structures, systems, and components (SSCs) to maintain key safety functions (KSFs).
The Flooding Focused Evaluation follows Path 2 of Reference 6 and utilized Appendices B and C of Reference 6 for guidance on evaluating the site protection features. This submittal completes the actions related to external flooding required by Reference 1.
The purpose of this letter is to provide the BSEP, Unit Nos. 1 and 2, Flooding Focused Evaluation Summary Report. Enclosure 1 provides the report.
This letter contains new regulatory commitments. Enclosure 2 provides a list of these commitments.
If you have any questions regarding this submittal, please contact Mr. Lee Grzeck, Manager- Regulatory Affairs, at (910) 832-2487.
I declare under penalty of perjury that the foregoing is true and correct. Executed on September 27, 2018.
s~
William R. Gideon
Enclosure 1: Brunswick Steam Electric Plant (BSEP), Unit Nos. 1 and 2, Flooding Focused Evaluation Summary Report
Enclosure 2: Brunswick Steam Electric Plant (BSEP), Unit Nos. 1 and 2, Flooding Focused Evaluation Summary Report, Regulatory Commitments

Junk Plant Hatch Safety Relief Valves: Why Did They Cancel Extending The Testing Frequency?

Update Oct 16: (made wording better) 

???

Thinking of a 2.206. 

Technical Letter Report
 

Three-Stage Target Rock Safety Relief Valve Performance and Reliability in Long-Term Station Blackout Accident Scenario for State of the Art Reactor Consequence (SOARCA) Program 

As mentioned above, in a LTSBO for a BWR 4 with Mark I containment, SRVs are assumed operable at the start of the event to provide RCS over-pressure control.  Analyses have shown [1] that, in the first ten hours of this transient, the SRVs will cycle open and closed approximately 440 times.  During each cycle, the valves open approximately every 45 seconds, and remain open for approximately four to six seconds.  After ten hours of the LTSBO, thermal hydraulic calculations show that the heat removal capacity of the wetwell is effectively exhausted (since the residual heat removal system is unavailable), and RCS temperature will rise.  RCS pressure will also continue to increase, resulting in additional open demands on the SRVs with increasing steam temperature.

An alternative basis for the SRV stochastic failure probability is proposed.  An industry representative has stated that the valve manufacturer warrants the valves for hundreds o

cycles at operating temperature and pressure conditions.  Note that these conditions are to be expected throughout the initial time period of a LTSBO, up to approximately 10 hours during which the valve will be demanded to cycle approximately 400 times.  The valve manufacturer has stated that laboratory tests have been performed to substantiate the conditions included in the valve warranty, i.e. that the valve can reliably open and close for hundreds of cycles.  The industry representative also stated that fossil-fuel plant experience with the same types of valves can be used to validate these assertions.

*** It is ridiculous Hatch would even think of extending their SRV testing interval on their very troublesome and unreliable SRVs going back a decade or more. They switched back and forth between stage 2 and 3 so many times I can keep up. They are a lemon designed valve and they should be replaced.

What a "crock of shit" with the drywell ventilation air blowing on the SRVs. This is probrably the third roll out of the 3 stage SRVs. The first two they had withdraw the valves from the plant due to being defective. They replaced the 2 stage with the 3 stage because of set point drift and leakage. No LERs in the past indicating ventilation air damaging on the valves in both plants. These excuses are highly suspect. At best, with this kind of unexpected failure, you can make the case the 3 stage is a too delicate a valve for the normal and emergency operation of the plant.

On the positive side, setpoint drift failures are a lot less in both plants since they installed all the 3 stage valves. The rub is, these valves haven't been in the plant for very long time. Very little aging in these young valves. By the way, the 3 stage valves aren't new valves. They are refurbished and have so called updated components in the valves. I suspect when these valves have been in the plant for two or more cycle they will fail at much higher rates.  

This LER below is probably the reason for canceling the testing extension.

The new SRV LER on unit 1 troubles was caused by ventilation air on the SRV causing abutment issues.  

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

On June 20, 2018, Unit 1 was at 100 percent rated thermal power (RTP) when "as-found" testing results of the 3-stage main steam safety relief valves (SRVs) indicated two of the eleven Unit 1 SRVs had experienced a setpoint drift during the previous operating cycle which resulted in their failure to meet the Technical Specification (TS) opening setpoint pressure of 1150 +/34.5 psig as required by TS Surveillance Requirement (SR) 3.4.3.1. The test results showed that the two SRVs were slightly out of spec tow due to setpoint drift.
The SRV pilots were disassembled and inspected to investigate the reason for the setpoint drift. Based on inspection results, the drift in setpoint was due to low abutment gap and low abutment pressure. Due to their location, drywall ventilation blowing on these two safety relief valves caused them to undergo a cyclic heating and cooling every 12 hours during the Unit's 2-year operating cycle. These temperature gradients across the valve internals caused a relaxation of the setpoint spring and bellows assembly.
NRC...

The below LER is in unit 2. It came out last year...it is their newest LER on SRV issues. It is way suspicious abutment issues are in both plants. Abutment issues are happening all over the industry beginning at Pilgrim and so called test stand damage. So loose manufacturing tolerances are behind this plant's the SRV abutment problem, but different than unit 1. So the strategy is to come up with a new failure mechanism every time they have tech spec SRV drift point test failing. All the NRC cares about is if they find the cause of the failure and it isn't repeated in the future. That is way they come up with a new angle every time they fail a tech spec lift test in the abutment issues. The go shopping for a new failure mechanism every time they submit a LER. I doubt the NRC inspectors have the time to verify deeply the failure. I am sure management just tell the local inspectors to just trust the licensee. I am sure the licensee knows how to game the system of trust thus the shifting failure mechanism to minimize a deeper investigation.     

I am appalled Hatch and the NRC tolerate the "most likely" acceptable standard for failure mechanisms for Unit 2. The cause of the defect and its fix is suppose to be bullet proof. It should have gone though a comprehensive engineering evaluation on the cause and then put them on a testing stand to beat the crap out of the valves in its supposed environment. If new issues are discovered on the testing stand, then a redesign of the defective and poorly engineered component happens. Then back to the stand. And do this over and over again until the design is perfect. 

(Updated) Edwin I. Hatch Nuclear Plant license Event Report 2017-(){)4-()() Safety Relief Valves' As Found Settings Resulted in Not Meeting Tech Spec Surveillance Criteria

On June 30 2017, with Unit 2 at 100 percent rated thermal power {RTP), "as-found" testing of the 3-stage main steam safety relief valves (SRVs) (EBS Code RV) showed that two of the eleven main steam SRVs that were tested had experienced a drift in pressure lilt setpoint during the previous operating cycle such that the allowable technical specification (TS) surveillance requirement (SR) 3.4.3.1 limit of 1150 +/-34.5 psig had been exceeded. Below is a table illustrating the Unit 2 SRVs that failed as found testing results alter being removed tom service during the Spring 2017 refueling outage. 

MPL 2821-F013C 2821-F013E 
Event cause Analysis 
Drift -39 psig -49 psig 

The SRV pilots were disassembled and inspected while investigating the reason for the drift It was found that the abutment gap closed prematurely during testing using a linear variable differential transformer to measure pilot stroke distance. The pre-mature abutment gap closure is most likely due to loose manufacturing tolerances leading to SRV setpoint drift. 

Something to do with the BWR SRV owners group formed on investigating the poor quality of the SRVS?  

October 15, 2018

SUBJECT: EDWIN I. HATCH NUCLEAR PLANT, UNIT NOS. 1 AND 2 PROPOSED ALTERNATIVE RR-V-12 REGARDING MAIN STEAM SAFETY RELIEF VALVE TESTING (EPID L-2018-LLR-0054)

Dear Ms. Gayheart 

By letter dated April 9, 2018 (Agencywide Documents Access and Management System (ADAMS) Accession No. ML 18099A146), the Southern Nuclear Operating Company, Inc. (SNC or licensee) submitted an alternative request for the Edwin I. Hatch Nuclear Plant, Unit Nos. 1 and 2. The proposed alternative RR-V-12 would extend the frequency for testing all main steam safety relief valves for each unit from once every 5 years to once every 3 refueling cycles (i.e., 6 years), as allowed by American Society of Mechanical Engineers (ASME) Code Case OMN-17. Subsequently, by letter dated July 18, 2018 (ADAMS Accession No. ML 18199A588), SNC withdrew the alternative request. The U.S. Nuclear Regulatory Commission (NRC) staff had recently approved the code case for unconditional use in Regulatory Guide 1.192. 

The purpose of this letter is to advise you that the NRC has received your request to withdraw the application dated April 9, 2018, and upon receiving the withdrawal letter, the NRC staff ceased its review of the above-cited application. 

If you have any questions regarding this matter, I may be reached at 301-415-4032 or via email at Randy.Hall@nrc.gov.
Docket Nos.: 50-321 and... 

Vogtle 3 and 4: Indications Of Massive Nuclear Plant Design Screw-ups

The pressure operated relief valves are(PORV)very important safety components. The bad design made the noise problem. Now this system is in a massive redesign even when this plant never ran. Is this just the beginning.  

Draft Request for Additional Information on Vogtle LAR 18-021 Main Steam PORV Noise Mitigation October 10, 2018


RAI 1 - relates to the structural stress analysis of the PORV                           ASME Boiler & Pressure Vessel Code (BPV Code), Section III, incorporated by reference in 10 CFR 50.55a, requires that piping analysis consider combinations of various loadings, including deadweight, pressure, seismic, thermal expansion and transient loads.  Southern Nuclear Operating Company (SNC) submitted Vogtle Electric Generating Plant (VEGP) Units 3 and 4 License Amendment Request (LAR) 18-021 proposing changes to the main steam (MS) branch line containing the power-operated relief valve (PORV).  These changes include relocating the PORV branch line from the MS line, increasing the size of the PORV branch line, reducing the PORV branch line length, and changing the PORV block valve size and type.  LAR 18-021 does not provide information related to the effects of the proposed changes on the structural integrity of the applicable systems, structures and components (SSCs).  To demonstrate that the structural integrity of the applicable SSCs will be maintained within acceptable design-basis limits as a result of the proposed changes in Vogtle LAR 18-021, the NRC staff requests that SNC provide the following information: 

Question 1:

(a) The MS PORV branch line had been decoupled from the MS line for the pipe stress analysis. The branch line is proposed to be changed from 6-inches to 12-inches nominal pipe size (NPS).  Please provide the minimum wall thickness or schedule of the planned 12 NPS branch line.  If the PORV branch line remains decoupled in the revised calculations, demonstrate that the proposed 12-inch branch line remains justified to be decoupled from the MS line using the current design-basis decoupling criteria. 

(b)    Describe the effects of the proposed changes in LAR 18-021 on the structural integrity of the applicable SSCs.  For the MS line and the PORV branch line, provide a brief summary of the maximum pipe stresses compared to the design-basis ASME allowable values.  In addition, provide a brief summary of the results of the evaluation of the MS containment penetration, applicable existing supports, and any additional supports to be installed.  

(c) Provide a summary of the maximum pipe break stresses compared to the design-basis break exclusion criteria as described in the FSAR.  SNC should demonstrate that the proposed changes do not result in any new postulated break locations and, therefore, there is no impact to the conclusions of the Pipe Rupture Hazard Analysis.

SNC may make applicable proprietary information to address these concerns available in its electronic reading room for NRC staff audit review.  If SNC intends to direct the NRC to the electronic reading room, please provide the exact references to documents so that they may be mentioned in an audit plan.

RAI 2 - relates to vibration and valve performance for the PORV modification
Question 1:  

General Design Criterion (GDC) 1, “Quality standards and records,” in Appendix A, “General Design Criteria for Nuclear Power Plants,” to 10 CFR Part 50 states, in part,  that structures, systems, and components (SSCs) important to safety shall be designed, fabricated, erected, and tested to quality standards commensurate with the importance of the safety functions to be performed.  GDC 4, “Environmental and dynamic effects design bases,” in 10 CFR Part 50, Appendix A, states that SSCs important to safety shall be appropriately protected against dynamic effects.  Vogtle License Amendment Request (LAR) 18-021, “Power Operated Relief Valve (PORV) Noise Mitigation,”  in Section 2 of Enclosure 1 on page 5 states that the MCR noise levels will be verified as part of the AP1000 human factors engineering verification and validation program.  The NRC staff requests that SNC describe its acoustic resonance analysis (such as acoustic resonance evaluation and Strouhal analysis) to demonstrate that the planned modification for the PORV block valve and branch line will not result in vibration levels that exceed the allowable limits.  For example, SNC should determine the potential sources of acoustic resonance and the applicable plant conditions.  SNC should address the planned PORV branch line connection design and radii that could cause potential adverse flow effects.  SNC should consider any plant operating experience with the proposed PORV branch line modification.  

SNC may make applicable proprietary information to address these concerns available in its electronic reading room for NRC staff audit review.  If SNC intends to direct the NRC to the electronic reading room, please provide the exact references to documents so that they may be mentioned in an audit plan.

Question 2:  

GDC 1 in 10 CFR Part 50, Appendix A, states that SSCs important to safety shall be designed, fabricated, erected, and tested to quality standards commensurate with the importance of the safety functions to be performed.  GDC 1 states, in part, that appropriate records of the design, fabrication, erection, and testing of SSCs important to safety shall be maintained by or under the control of the nuclear power unit licensee throughout the life of the unit.  Vogtle LAR 18-021 states in Section 2 in Enclosure 1 on page 4 that the new globe valves to be used in the PORV block valves will be qualified for the same environmental and pressure/temperature conditions as the current PORV block valves.  The Vogtle Final Safety Analysis Report (FSAR) with reference to the plant-specific AP1000 Design Control Document, Tier 2, Section 3.9.3.2.2, “Valve Operability,” specifies that active valve assemblies will be qualified in accordance with ASME Standard QME-1-2007, “Qualification of Active Mechanical Equipment Used in Nuclear Power Plants,” which the NRC endorsed in RG 1.100 (Revision 3), “Seismic Qualification of Electrical and Active Mechanical Equipment and Functional Qualification of Active Mechanical Equipment for Nuclear Power Plants.”  The NRC staff requests that SNC describe its plans to satisfy the provisions in ASME QME-1-2007 for the dynamic, environmental, and functional qualification of the new PORV block valves.  

SNC may make applicable proprietary information to address these concerns available in its electronic reading room for NRC staff audit review.  If SNC intends to direct the NRC to the electronic reading room, please provide the exact references to documents so that they may be mentioned in an audit plan.

Question 3:  

The NRC staff requests that SNC clarify the statements in Vogtle LAR 18-021 in Section 2 of Enclosure 1 on page 11 that there will be “no change to the valve motor operator” and “no change to the valve stroke time” in light of the potential differences in stroke length and operating requirements between the original 6-inch gate valve and the new 12-inch globe valve.

Junk Plant Hope Creek: Not Worth It To Fix Safety Components (SRVs), Because We Might Permanently Shutdown

Licensee Event Report 2018-002-01 Safety Relief Valve (SRV) As-Found Setpoint Failure

On April 20, 2018, Hope Creek Generating Station (HCGS) received results that the 'as-found' set-point tests for safety relief valve (SRV) pilot stage assemblies had exceeded the lift setting tolerance prescribed in Technical Specification (TS) 3.4.2.1. The TS requires the SRV lift settings to be within +/- 3% of the nominal set-point value.
During the twenty-first refueling outage (H1 R21 ), all fourteen SRV pilot stage assemblies were removed for testing at an offsite facility. Between April 20 and May 11, 2018, HCGS received the test results for all fourteen of the SRV pilot valve assemblies. A total of eight of the fourteen SRV pilot stage assemblies experienced set-point drift outside of the TS 3.4.2.1 specified values. All of the valves failing to meet the limits were Target Rock Model 7567F two-stage SRVs. 

This is a condition reportable under 10 CFR 50.73(a)(2)(i)(B) as an Operation or Condition Prohibited by Technical Specifications.

This is the wording from above. They are suppose to be shutdown if they find more than one SRVs outside the  valve pressure testing lifting accuracy. They requiring 13 SRVs to be operable implies there is not much safety slack in the SRV. 57% of the valves were unacceptable. The magnitude of these kinds of failures have been going on for decades. The NRC got a industry group studying this failure, and after NRC prodding by me, Hope Creed has admitted this is unacceptable quality assurance. They have been promising to replace these valves for years.    

"Technical Specification (TS) 3.4.2.1 requires that the safety function of at least 13 of 14 SRVs be operable with a specified code safety valve function lift setting, within a tolerance of +/- 3%. Action (a) of TS 3.4.2.1 specifies "With the safety valve function of two or more of the above listed fourteen safety/relief valves inoperable, be in at least HOT SHUTDOWN within 12 hours and in COLD SHUTDOWN within the next 24 hours." Therefore, this is a condition reportable under 10 CFR 50.73(a)(2)(i)(B) as an Operation or Condition Prohibited by TS."

The cause of the set-point drift for the eight SRV pilot stage assemblies is attributed to corrosion bonding between the pilot disc and seating surfaces, which is consistent with industry experience. This conclusion is based on previous cause evaluations and the repetitive nature of this condition at HCGS and within the BWR industry.

CONDITIONS PRIOR TO OCCURRENCE When the reports of the 'as-found' results were received, Hope Creek was in Operational Condition (OPCON) 5, Refuel, at 0 percent rated thermal power. No other structures, systems or components that could have contributed to the event were inoperable at the time of the event.  

DESCRIPTION OF OCCURRENCE During the twenty-first refueling outage (H1 R21) at Hope Creek Generating Station (HCGS), all fourteen Main Steam safety relief valves (SRV) pilot stage assemblies {SB/RV} were removed and tested at NWS Technologies. The SRVs are Target Rock Model 7567F two-stage SRVs. During the period from April 20 through May 11, 2018, HCGS received the results of the 'as-found' set pressure testing required by Technical Specification (TS) Surveillance Requirement (SR) 4.4.2.2. A total of eight of the fourteen SRV pilot stage assemblies had set-point drift outside of the required TS 3.4.2.1 tolerance values of +/-3% of nominal value. 

The 'as-found' test results for the eight SRVs not meeting the TS requirements are as follows:
Valve ID As Found TS Lift Setting Acceptable Band % Difference (psig) (psi g) (psig) Actual F013B 1210 1130 1096.1-1163.9 7.10% F013D 1191 1130 1 096.1 - 1163.9 5.40% F013F 1146 1108 1074.8- 1141.2 3.40% F013G 1197 1120 1 086.4 - 1153.6 6.90% F013H 1200 1108 1074.8-1141.2 8.30% F013L 1155 1120 1086.4- 1153.6 3.10% F013M 1161 1108 1074.8-1141.2 4.80% F013P 1199 1120 1086.4- 1153.6 7.10%
Technical Specification (TS) 3.4.2.1 requires that the safety function of at least 13 of 14 SRVs be operable with a specified code safety valve function lift setting, within a tolerance of +/- 3%. Action (a) of TS 3.4.2.1 specifies "With the safety valve function of two or more of the above listed fourteen safety/relief valves inoperable, be in at least HOT SHUTDOWN within 12 hours and in COLD SHUTDOWN within the next 24 hours." Therefore, this is a condition reportable under 10 CFR 50.73(a)(2)(i)(B) as an Operation or Condition Prohibited by TS. 

DESCRIPTION OF OCCURRENCE (Continued)
YEAR
2018
SEQUENTIAL NUMBER
• 002
The extent of condition for this event is to expand the scope of the SRV Group 1 valve testing, per ASME OM Code Section 1-1320 for Class 1 Pressure Relief Valves. However, since all fourteen SRV pilot stage assemblies were removed and replaced with tested spares during the refueling outage (H1 R21), the extent of condition scope was satisfied. 

CAUSE OF EVENT
REV NO.
• 01
The cause of the set-point drift for the eight SRV pilot stage assemblies is attributed to corrosion bonding between the pilot disc and seating surfaces, which is consistent with industry experience. This conclusion is based on previous cause evaluations and the repetitive nature of this condition at HCGS and within the BWR industry.
One of the eight SRVs that experienced set point drift, F013H, was determined to have a second failure mechanism present. The H SRV was the only valve that failed its second (informational) lift test. Disassembly of the SRV pilot revealed steam-cutting of the pilot disc and valve seat, as well as a build-up of corrosion products on the seating surface of the pilot valve. Leak-by on the pilot disc resulted in damage to the pilot seat which affected the lift setpoint. This is the cause of the second test lift to remain outside of the acceptable tolerance. This steam leak also caused the corrosion products to be seen on the seat base material.  

SAFETY CONSEQUENCES AND IMPLICATIONS There were no instances during cycle 21 that resulted in any of the fourteen SRVs being declared inoperable and there were no events during that cycle that required operation of the SRVs. All SRVs lifted well below the Safety Limit, providing reasonable assurance that accident analysis conclusions would remain valid. The industry has recognized that corrosion bonding occurs during the operating cycle. Once an SRV lifts, the corrosion bond breaks and subsequent openings occur very close to the set point as demonstrated during testing, with the exception of the H SRV I as described above. 

Since the eight as-found setpoint SRVs are within their Maximum Allowable Percent Increase (MAPI) above SRV nominal setpoint criteria established in GE document NEDC-32511 P, "Safety Review for Hope Creek Generating Station Safety/Relief Valve Tolerance Analysis", the SRVs are bounded by their MAPI value and no formal Technical Evaluation is required.  

SAFETY SYSTEM FUNCTIONAL FAILURE A review of this condition and a previous technical evaluation documents this is not a functional failure, therefore it was determined that a Safety System Functional Failure (SSFF) as defined in Nuclear Energy Institute (NEI) 99-02, "Regulatory Assessment Performance Indicator Guideline," did not occur. 

PREVIOUS EVENTS Similar events occurred during the 2015 (H1 R19) and 2016 (H1 R20) Hope Creek refueling outages when multiple SRVs were found out of the TS required limits of +/- 3%. These events were reported as LER 354/2015-004-00 (ten inoperable SRVs) and LER 354/2016-003-00 (ten inoperable SRVs).  

CORRECTIVE ACTIONS 1. All 14 SRV pilot stage assemblies were removed and replaced with pre-tested, certified spare pilot valves (H1 R21 ). 2. Evaluate options for the replacement of the currently installed Target Rock two-stage SRVs with a design that eliminates setpoint drift events exceeding +/-3% and improve SRV reliability. The replacement schedule will be developed after a suitable valve is identified. 

Why can't they find suitable valves?

Junk Plant Grand Gulf: This Is How A bad Plant Looks

The long outage was from about April 7 to July 11, 2017.  

They are running equipment to failure. They aren't spending enough money to keep equipment reliable and upgrading obsolete components. 

Junk Plant Grand Gulf Restarted From 50 Day Outage...Lets Watch It Till 100% Power

So the outage started near the early May 2017? Look how bad the startup was? 

Reactor Shutdown Because Of A Condensate System Inventory depletion And A Manual Reactor Core Injection Core Cooling (RCIC) Initiation Because Of Feedwater isolation  

At 00:10 on April 4, 2017, the reactor was manually shutdown from a 75 percent thermal power. due to condensate storage tank level lowering to 24 feet. All control rods fully inserted and all systems actuated as operated as designed. No safety relief valves actuated. Reactor level and pressure were controlled within normal bands. Reactor core isolation cooling (RCICJ) was manually initiated for level controlled.  Decay heat was removed via steam discharge to the condenser, and t6•the suppression pool via RCIC. The electrical grid was stable and supplying plant loads. The cause of the condensate depletion was a condensate system leak. 

The condensate system leak was a failed pipe connection caused by cycling water injection valves that induced excessive: vibration on the: pipe flange. A failing Turbine Control Card caused the faulty signal which led to the water injection valve's cycling. The piping and flange connection were repaired, and the Turbine Control Card was replaced. In addition, the Turbine Control System is scheduled to be replaced in Refueling Outage 22 in 2020.

All other systems operated as designed, and there were no actual nuc1ear safety or radiological consequences during the event.