The NRC's Management Stiff Arm

Basically, it is the issues most of the outsiders have...it is hard to get the higher ups to explain their justifications down on the paperwork. They just stiff arm us.  

But you have to respect the Hell out of the NRC and Mr. Peck for allowing this to become a public disscussion.

These cultural traits are expressed perfectly by Dr Peck.

"As an insider, I’ve found that the industry culture sometimes operates with the assumption that NRC Rules and license requirements impose excessive margins and burdens. In the 1980s, I worked as a reactor engineer (in-core physics) for the Tennessee Valley Authority. The plant culture often viewed NRC design basis requirements as far exceeding those need to preserve safety. “We have systems that back-up systems, that back-up systems, that … ” This industry culture justified encroachment on the facility design basis."

"As I’ve worked thought these issues, I’ve heard agency personnel express over and over again that Diablo Canyon has “plenty of seismic margin.” “Just look at the HE.” These statements imply that no real safety issue exists with the new seismic information. I maintain that Diablo Canyon seismic safety is very complex. It took the DPO Panel almost year just to conclude that the new ground motions were within the bounds of the existing SSE safety analysis. And I’m still not 100 percent convinced that they got it right. While the NRC license review processes may seem cumbersome and stakeholder input can be frustrating at times, use of the established regulatory framework provides us the basis for our presumption of nuclear safety. History has repeatedly taught us that we sometimes get ourselves in trouble when we try working around these processes."

Mr. Peck doesn't address at the bottom of this all is the issue of budget pressures and financial priorities...insufficient resources.

This isn’t about safety…it about money and profits!

Diablo’s Former Inspector Explains

Summary of the Diablo Canyon Differing Professional Opinion

Friday, September 19, 2014

By Michael Peck

The Nuclear Regulatory Commission’s internal processes allow employees to raise issues and make recommendations that differ from the prevailing agency view. Michael Peck, a resident NRC inspector at Diablo Canyon nuclear plant, had a “differing professional opinion” (DPO) after new seismic information was developed. His DPO asserted that PG&E operated the reactors outside the bounds of the facility design basis as defined by its license to operate. Any operation outside of the design basis challenges plant safety due to an erosion of regulatory margins. No immediate or significant safety issues were noted, but Peck points out that operations outside the design basis have contributed to nuclear accidents in the past.

Beginning in 2012, I used the NRC non-concurrence and differing professional opinion (DPO) processes to raise nuclear safety issues affecting the Diablo Canyon Nuclear Facility. These internal processes allow employees to raise issues and make recommendations that differ from the prevailing agency view. These safety issues were related to how the NRC addressed design control, equipment evaluation, and Operating License fidelity after Pacific Gas and Electrical (PG&E) Company developed new seismic information affecting the Diablo Canyon site. The agency carefully considered my recommendations and dispositioned these concerns in September 2014. The NRC subsequently made my views and the agency’s conclusions publicly available in the Agencywide Documents Access and Management System (ADAMS Accession Number ML1425A743).

Diablo Canyon seismology is both highly complex and controversial. However, my DPO was not about seismology. My DPO addressed routine and generally well-understood inspection practices related to agency enforcement of existing design basis requirements at a power reactor facility. These requirements are equally applicable regardless if the issues involved seismic qualification, spent fuel, accident analysis, or any other aspect of the facility design basis. The DPO did not identify any “immediate or significant safety issues.” However, the DPO asserted that PG&E continues to operate the Diablo Canyon reactors outside of the bounds of the facility design basis as defined by the NRC Operating License. Any operation outside of the design basis challenges plant safety due to erosion of regulatory margins.

For example, in 2004 a seismologist identified that the Fukushima sea wall was too low. This was a condition outside of the facility design basis that required protection against the maximum creditable flood and demanded corrective action. But this was not an “immediate or significant safety issue” because the probability of a large tsunami was thought to be small. But as we saw in 2011, the low sea wall height did impact the capability of facility operators to mitigate a flood.

The license application (Final Safety Analysis Report or FSAR) for a nuclear power plant must include safety analyses demonstrating that regulatory design basis are satisfied. The design basis includes requirements that equipment important to safety remain functional following the safe shutdown earthquake (SSE). The NRC defines the SSE as largest credible earthquake that can affect the site.

The Diablo Canyon license application, as amended and approved by the NRC, stated that this design basis SSE was satisfied by the Double Design Earthquake (DDE) safety analysis. NRC Rules required PG&E to maintain the plant capable of meeting this design basis requirement, as specified in the license application (as amended), during reactor operation. The Diablo Canyon license application also discussed a second earthquake analysis, called the Hosgri Evaluation (HE).

Nuclear seismic qualification is not just about how much the ground will shake following an earthquake. Equally important are the methods used to analyze how seismic energy propagates through plant structures; the engineering assumptions and inputs used in the safety analysis; and the application of load combinations and acceptance limits. The larger HE earthquake (0.75 g peak ground acceleration) predicted less mechanical stress on plant equipment, including reactor components, than the smaller SSE/DDE (0.4 g). While this may sound counterintuitive, this result reflected the different analytical methods and assumptions used in the two analyses. The PG&E license application (as approved) explicitly stated that SSE design basis requirement was satisfied by the DDE. The application discussed the HE as a response to NRC questions raised during the original licensing process. The application also specifically stated that the HE did not meet NRC requirements for the SSE. In other words, the facility Operating License established the DDE/SSE as the maximum ground motion for the site, implementing NRC design basis Rules for protection against earthquakes. The HE demonstrated that PG&E could safety shutdown the plant (assuming no accident or fire) if a 7.5 magnitude earthquake occurred on the Hosgri fault. The reasons for excluding the larger HE ground motions from the SSE safety analysis are complex and reflect negotiated agreements made between the NRC and PG&E prior to original plant licensing.

In early 2011, PG&E placed a reevaluation of the local seismology on the NRC docket. This report concluded that three earthquake faults were capable of producing greater ground motion than SSE/DDE but less than the HE. NRC regulations required PG&E to evaluate this new information against the existing facility design basis and update any deficient FSAR safety analysis. PG&E could have updated the SSE safety analysis with the new ground motions. However, this approach would have required an amendment to the Operating License because the resulting stress would have exceeded established safety limits for equipment important to safety, including the reactor pressure boundary. The NRC typically doesn’t approve safety analysis changes that conclude safety limits have been exceeded.

As an alternative, PG&E chose to change the SSE safety analysis methodology from the DDE to the HE. At the time, this seemed to be a reasonable approach since the new ground motions were bound by the HE spectrum. PG&E was required to obtain NRC approval before incorporating this change. NRC Rules require an amendment to the Operating License if less conservative analytical methods are used to demonstrate that a design basis requirement is satisfied. In October 2011, PG&E submitted License Amendment Request 11-05 requesting NRC approval for this change. NRC Rules allowed continued reactor operation while the agency reviews the amendment request provided that PG&E demonstrates a “reasonable assurance” that equipment important to safety remains “operable.” In other words, PG&E would have to show by evaluation that accident mitigation equipment would still work and reactor piping would hold together (meet acceptance limits of the American Society of Mechanical Engineers, Boiler and Pressure Vessel Code) given the higher seismic inputs.

As a resident inspector, my job was to compare the Diablo Canyon facility and PG&E activities against the facility Operating License, NRC regulations, and industry guidance. When inspections identify gaps in the implementation of these requirements, then I was expected to draft violations consistent with the NRC Enforcement Policy. I was specifically tasked with reviewing between 19 and 25 PG&E operability evaluations each year.

In the summer of 2011, PG&E concluded that all safety equipment was “operable” given the higher ground motions. This evaluation relied on the HE as an alternate methodology. NRC operability policy allows use of “alternate analytical methods” provided certain conditions are met. For example, the alternate method cannot produce a result that “over-predicts” equipment performance when compared to the design bases method.

My inspection concluded that the PG&E evaluation failed to meet NRC operability standards. For a given ground motion, the HE method will always produce a less conservative result when compared to the SSE/DDE method. Gaining margin over the SSE/DDE was the sole reason PG&E used the HE as an alternate method. I also knew that very little margin to the Code limits existed from my experience with the replacement reactor head and steam generator inspections. Almost any increase in seismic loading would result in exceeding the Code acceptance limits, roughly 2/3 of the critical buckling strength for the material.

I included an inadequate operability evaluation violation with my 2011 third and fourth quarter Intergraded Inspection Reports. In both cases, NRC Region IV management removed the violation prior to issuing the report. The proposed violation addressed the decrease in nuclear safety because PG&E had encroached on design basis margins and safety limits.

NRC violations associated with inadequate operability evaluations are common. Typically, these violations address technical deficiencies in the analytical or regulatory approach used by the licensee. Corrective actions usually involve adding technical rigor or additional justification to the evaluation. However, for the seismic operability case, it was unlikely that PG&E would have been successful. The magnitude of the new ground motions combined with the lack of available margin in the existing SSE safety analysis would have made it all but impossible to conclude that plant equipment was operable. If this equipment was determined to be inoperable, then the Operating License required PG&E to immediately shut down both reactors.

A License mandated shutdown is not all that unusual. The NRC has and routinely uses statutory authority to grant regulatory dispensation in these types of cases. PG&E could have used the HE to support a safety argument justifying continued operation pending NRC approval of the license amendment. This path would have required the NRC to formally waive Diablo Canyon seismic design basis requirements and approve relief from the Code. This path would have also reversed the previously well-publicized agency position that PG&E had been operating within the bounds of the facility design basis.

To ensure NRC management fully understood the underlying technical and regulatory aspects of the proposed violation, I non-concurred on my own inspection report. To my surprise, the agency response stated that insufficient information was available to complete an operability evaluation. To the best of my knowledge, this position was completely unprecedented and contrary to written NRC policy. In my 30-plus years’ performing and inspecting operability evaluations, I had never once come across this view. The failure to clearly demonstrate operability has always resulted in a declaration of “inoperability,” requiring immediate application of the Technical Specification remedial actions. The agency’s response went on to state that NRC approval of the PG&E license amendment request was needed before operability could be fully assessed.

Apparently, I had misapplied NRC operability criteria during the inspection. However, the nonconcurrence response did not provide sufficient information for me to understand why or how I had missed the mark. The NRC response also appeared to establish new agency policy and precedent.

In 2012, NRC technical reviewers concluded that HE methodology was not suitable for the Diablo Canyon SSE design basis. In October 2012, PG&E withdrew the license amendment request at the NRC’s request. The NRC Diablo Canyon Project Manager subsequently requested PG&E to directly add the results of the Shoreline fault analysis to the facility FSAR, appearing to work around the failed license amendment process.

This action limited stakeholder input by bypassing statutory requirements for notice and hearing opportunity associated with a facility design basis change. NRC rejection of the license amendment also appeared to have voided the agency’s stated bases for the non-concurrence decision on operability.

I submitted the DPO in July 2013. My goal was to include sufficient technical detail and regulatory analysis to support a third-party review of the issues. I addressed the unresolved operability issue from 2011 and added the lack of appropriate corrective actions to restore the FSAR safety analysis to the facility design basis and regulatory requirements.

During the DPO deliberations, I did my best to reach a consensus on the technical and regulatory issues with the Panel. I offered to withdraw the DPO if the Panel could provide a technical resolution consistent with both agency Rules and the facility License. I also requested that the Panel obtain a legal opinion from the NRC Office of General Council since the DPO involved application of specific legal requirements established by the facility Operating License. My understanding was that the Panel did not accept either recommendation.

In May 2014, the Panel concluded that PG&E had satisfied all regulatory requirements. Apparently, I had misapplied the Diablo Canyon License requirements. The Panel’s conclusion was built on the assumption that the HE was a facility SSE. Because the HE was an SSE, then neither a license amendment nor an operability evaluation was required. To the best of my knowledge, this was the first time the agency had concluded that the HE was the Diablo Canyon SSE. Unfortunately, the Panel Report offered no explanation or the basis for this assumption. I found this partially frustrating since I went to great lengths in the DPO to provide a detailed description of the facility seismic licensing basis. I thought that if I had gotten it wrong, then the Panel should be able to point out were I made my error.

The assumption that the HE was a facility SSE appeared to be in direct conflict with the facility license application (FSAR). I followed up with the Panel Chairman to better understand the basis for their assumption and my error. He directed me to an FASR Section. Interestingly, this section was included in the September 2013 revision following the NRC Project Manager’s direction to add the Shoreline fault to the FSAR. NRC Rules state that FSAR changes that potentially affect how the facility design basis are met, are required to be screened to determine if a license amendment is required. These changes were flagged by PG&E as exempt from this screening requirement based on “correspondence from the NRC.” From my view, the Panel appeared to use circular logic as basis for their underlying assumption and then used this assumption to support their conclusion.

In June 2014, I submitted an appeal to the DPO decision. My appeal stated that the DPO conclusion appeared to be built on a misunderstanding of the Diablo Canyon license requirements and agency Rules. Also, the Panel appeared not to have fully addressed the statutory requirements associated with adding the new seismic information to the FSAR (10 CFR 50.59) and meeting ASME Code for the facility SSE (10 CFR 50.55a). Specifically, the Panel appeared not have compared the new seismic inputs against the FSAR safety analysis as explicitly required by agency Rules.

I included the actual original (license application, as approved) and current FSAR pages describing the seismic design and licensing basis in the Appeal. I included these pages to avoid any misunderstanding of the facility License requirements. I included the specific language of applicable agency Rules and approved guidance to avoid unsupported assumptions. I also added specific examples detailing past NRC enforcement action taken on similar issues at other facilities and formal agency guidance addressing expected actions following discovery of conditions outside of the seismic design basis.

In response to my Appeal, the agency again told me my conclusions were incorrect. Apparently, my regulatory analysis had inappropriately excluded the HE from the facility licensing basis. Again the agency response did not include sufficient detail to help me understand where I had made my error or which part of the license application I misinterpreted.

I have exhausted the NRC processes for raising nuclear safety concerns. At every turn, the agency reinforced that its original conclusions and actions had been correct. From my perspective, I applied the same NRC inspection standards and agency Rules to the Diablo Canyon seismic issues that I’ve used to disposition many other design bases issues during my twenty years as an inspector. Since the DPO was reviewed by the highest levels of agency management, I was left with the impression that the NRC may have applied a different standard to Diablo Canyon.

I’ve also encountered this culture as an inspector. For example, the NRC issued eight violations over five years associated with facility changes PG&E made without first obtaining the required NRC approval in the form of an amendment to the Operating License.

By studying major nuclear accidents, Three Mile Island, Chernobyl, and Fukushima, l found that these events were largely preventable. Encroachment of operating standards and the design basis contributed to each event. In some cases decision makers didn’t fully appreciate the complexity or consequence of the safety barriers they encroached upon. For example, an engineer directed reactor power be maneuvered outside of design basis limits at Chernobyl to support testing. The engineer didn’t realize that his actions had placed the reactor in an unstable region, leading to an uncontrolled power excursion. The results of his actions are now part of the nuclear legacy.

As I’ve worked thought these issues, I’ve heard agency personnel express over and over again that Diablo Canyon has “plenty of seismic margin.” “Just look at the HE.” These statements imply that no real safety issue exists with the new seismic information. I maintain that Diablo Canyon seismic safety is very complex. It took the DPO Panel almost year just to conclude that the new ground motions were within the bounds of the existing SSE safety analysis. And I’m still not 100 percent convinced that they got it right. While the NRC license review processes may seem cumbersome and stakeholder input can be frustrating at times, use of the established regulatory framework provides us the basis for our presumption of nuclear safety. History has repeatedly taught us that we sometimes get ourselves in trouble when we try working around these processes.

Michael Peck, PhD, is the former NRC senior resident inspector at Diablo Canyon Power Plant.

Fort Calhoun and Cooper Identical Twins Training Failures

Just so you get it:

1)      The Cooper plant just recently got a terrible NRC report about their training.

2)      Effectively a politician on a Nebraska state Power board improperly disclosed  that INPO had put Fort Calhoun training on probation as a campaign tactic.

3)      These guys are less than a hundred miles apart.

Nebraska Public Power District (NPPD, Cooper) and Omaha Public Power District,( OPPD, Fort Calhoun)

Are we really watching a plant death spiral?

It questions if these Fort Calhoun should have ever been operating. I seen it back in Jan 2014.

Did I call it right from Jan? 

There are more pre 2011 Fort Calhouns out there right now!

June 2014: Fort Calhoun going nuts on Us.

 Normally a plant gets 3 or 4 LERs per year, maybe less….

2014: 12

2013: 35

Once you get onto the north side of 2005 till today, it is amazing the escalation of the numbers of LERs. I wonder what has changed?

2005:3

2004:3

2003:5

April 2014: The Ongoing 2011 Accident at Fort Calhoun Nuclear Plant

 See, crap quality assurance and crap maintenance. This came out on the same date of the new scram.
Junk! Another plant scram! They fixed the stuff relevant to NRC rules...but neglected components support reliable plant operation
Three years and 200 million dollars...16 days of operation...and they already had two shutdowns.

Were the new sluice gates cheaply purchase at Walmart...

Would that be great, putting on this kind of debt for 10 years...then have to shutdown within a year.

Goes to show you, if the majority of the plant is obsolete and degraded gear...throwing 200 million is a waste of money! They just didn't go in big enough.

Jan 2014: The Ongoing 2011 Accident at Fort Calhoun Nuclear Plant

 Has INPO also put Cooper training program on probation?

SUBJECT: COOPER NUCLEAR STATION - NRC EXAMINATION REPORT 5000298/2014301 

"The examination included the evaluation of five applicants for reactor operator licenses, one applicant for instant senior reactor operator license, and three applicants for upgrade senior reactor operator licenses. The license examiners determined that two of the applicants satisfied the requirements of 10 CFR Part 55 and the appropriate licenses have been issued."

No findings were identified during this examination.

Can you imagine they would tolerate this post Fukushima?

"The licensee already has areas for improvement that include improved critical task development and scenario performance weaknesses on critical tasks, with Condition Report CR-CNS-2014-04683 written to address these issues."

Can you imagine how horrified the operators would be with their plant in this condition? I always thought the procedures and the component used should be at a much higher quality than if a plant was running in a normal state. A plant at normal operation is fault tolerant and has multiple back up systems…while a plant like this is mostly naked and has most of the safety systems stripped away from them. One operator error can screw the whole region. The industry thinks these procedure and component can be of a lesser quality because the chance of being here is slim to none...I think the quality needs to be at a much higher quality because the consequences of a error is so much higher.

You know, they could have caught Cooper on this five years ago? Why did they catch them on this at this inspection?

I am giving you an example where in the USA training might not be up to the quality advertised to prevent a serious accident or mitigate a bad accident.

Or because credibility issues, we do not the know the true condition of all the plants.

COOPER NUCLEAR STATION – NRC INTEGRATED INSPECTION REPORT05000298/2014003

You gotta know it is ten times more worse than the NRC reports it and employees admit it. Think about it, seven out of nine employees failed initial licensing testing.

Did they shorten initial licensing training…almost an instant license...in order to mitigate the crisis with not enough qualitied licenses at Cooper? Is this why the NRC made an example out of Cooper because initial licensing “lite” training?

How could they get this far behind the license eight ball?

Aug 12:

“Interviewees indicated that a lack of Senior Reactor Operators (SROs) has placed the station in a staffing crunch that could ultimately affect shift staffing options. Operators are concerned that if the number of operating crews is reduced, quality of life effects could add stress to the operators. Management is aware of these concerns. There are currently two initial license classes in progress to address this issue.

The inspection team concludes that staffing at Cooper Nuclear Station is adequate. Station management is taking steps to address potential future short comings, i.e. training more senior reactor operators, and planning a four crew rotation contingency. However, the inspection team recommends that increased monitoring of operation.”

Isn’t it interesting, two completely different corporate nuclear managers, (Entergy, Exelon) Cooper and Fort Calhoun having profound troubles with training…

90 miles from each other and lost deep in the Midwest.

Unbelievable current access to how INPO works…

“Fort Calhoun Nuclear Station on probation; 'Why didn’t the public know?' OPPD boardcandidate asks”

By Cody Winchester / World-Herald staff writer The Omaha World-Herald

Training and maintenance programs at Fort Calhoun Nuclear Station have been on accreditation probation since March, a candidate for the Omaha Public Power District board revealed Wednesday.

The National Nuclear Accrediting Board imposed the six-month probation in late March, citing “broad gaps” in training at the nuclear plant, which restarted in December after being shut down for nearly three years.

The accrediting board is an arm of the Institute of Nuclear Power Operations, a trade group that offers technical assistance and training to member utilities.

Candidate Jeff Lux, who is challenging 16-year incumbent Anne McGuire for the District 2 seat in South Omaha, called a press conference Wednesday outside OPPD’s headquarters to criticize the utility for not disclosing the problems.

“Why didn’t the public know about this?” Lux said.

Fort Calhoun Station sits on the banks of the Missouri River about 15 miles north of Omaha. The plant was taken offline in April 2011 for a scheduled refueling, but then flooding, a fire and the discovery of numerous safety violations led the U.S. Nuclear Regulatory Commission to place the plant under special oversight.

The trade group certifies training programs at nuclear plants every four years; Fort Calhoun’s accreditation review came shortly after restart.

OPPD spokesman Jeff Hanson said the nuclear power institute needed more time to review new processes as the plant transitions to new management. In 2012, the district hired an outside firm, Exelon, to run the plant.

The accrediting board will discuss lifting the probation when it convenes Thursday in Atlanta. OPPD is optimistic, Hanson said.

“All indications are that we will receive positive news,” he said.

If the board votes against reaccreditation, employees at the plant no longer would be allowed to get training.

The probation was a “critical issue” at Fort Calhoun that prompted weekly conference calls with accrediting managers, who later visited the plant on several inspection visits, according to internal OPPD newsletters.

“Without an accredited program, (Fort Calhoun) can’t properly train and qualify personnel to operate and maintain the station,” assistant plant manager Tim Uehling wrote in a July memo to employees.

Although the OPPD board was kept in the loop, the probation never was made public — another example of the district keeping ratepayers in the dark, Lux said.

The news comes after OPPD went to court, unsuccessfully, to fight the disclosure of seven employee severance agreements worth nearly $950,000.

Many of the issues identified in an analysis of training problems, including weak oversight by management, also were identified in a longer technical report that delved into why the plant was shut down in the first place, Lux said. The district “shelved” that report, too, said Lux, a felony prosecutor in the Douglas County Attorney’s Office.

“Two years later — this came out in 2012 — we’re still seeing the same problems,” he said.

Jan 28: The Terribly Uncertainty In The TDAFW Pump NOED At Millstone

(What they really knew but didn't tell and what they assumed they knew in the NOED)

The NRC and Millstone sets this document in utter certainty that they have a god's eye view...they perfectly have all the information associated with risk and the conditions (information) with the TDAFW pumps.

NOTICE OF ENFORCEMENT DISCRETION FOR DOMINION NUCLEAR CONNECTICUT,INC. REGARDING MILLSTONE POWER STATION UNIT 3

[TAC NO. MF3393, NOED NO. 14-1-01]

Dear Mr. Heacock:

By letter dated January 28, 2014, Dominion Nuclear Connecticut (DNC), Inc. requested that the U.S. Nuclear Regulatory Commission (NRC) exercise discretion to not enforce compliance with the actions required in Millstone Power Station (MPS) Unit 3 Technical Specification (TS) 3.7.1.2,“Auxiliary Feedwater (AFW) System,” Action C, to restore the Turbine Driven Auxiliary Feedwater (TDAFW) pump to operable status within 72 hours. This letter documented information

On January 23, 2014, at 1:50 p.m., during a planned surveillance test, the MPS Unit 3 TDAFW pump tripped on an over speed condition and was declared inoperable by plant operators. After review of the troubleshooting data, the most probable cause was identified by station personnel that insufficient force was being transferred via the linkage to the turbine steam supply control valve.

You stated that at 1:50 p.m. on January 23, 2014, MPS Unit 3 operators entered TS 3.7.1.2, Action C. Further, TS 3.7.1.2 requires that if 3.7.1.2, Action C, cannot be met within 72 hours, operators at Unit 3 are required to shutdown the reactor and place the unit in at least hot standby within 6 hours and in hot shutdown within the following 12 hours. You sought enforcement discretion to allow for continued operation in violation of TS 3.7.1.2 in order to permit additional time for station personnel to make repairs, perform testing activities, and restore the TDAFW pump to operable status. An additional 72 hours (NOED completion time) was requested beyond the TS completion time allowance to restore the TDAFW pump to an operable condition, such that the need for enforcement discretion would no longer be required at 1:50 p.m. on January 29, 2014. This letter documents the telephone conversation between DNC and NRC staff on January 26, 2014, which concluded at approximately 1:00 p.m., when the NRC staff verbally granted a NOED for 36 hours. Your written request reflected this 36 hour authorization. Subsequent to that call, station personnel restored the TDAFW pump to operable status, allowing operators at Unit 3 to exit TS 3.7.1.2, Action C, and terminate the NOED at 5:05a.m on January 27, 2014.

During the teleconference on January 26, 2014, and further elaborated in your January 28, 2014 letter, your staff indicated that from a risk perspective, it was unnecessary to place MPS Unit 3 into a plant shutdown in that MPS Unit 3 was operating in a stable configuration with offsite power and both MPS Unit 3 Emergency Diesel Generators available, along with the Station Blackout (SBO) Diesel Generator. Based on actual plant conditions on January 26, 2014, quantitatively your staff estimated the Incremental Conditional Core Damage Probability (ICCDP) to be approximately 2.97E-08, and the Incremental Conditional Large Early Release Probability (ICLERP) to be approximately 1.88E-09. Additionally, it was noted that the estimated ICCDP and ICLERP values did not take into account various additional conservatisms associated with compensatory actions which had been put in place. The results of your staff’s quantification were independently corroborated by NRC analysts and were determined to meet the guidance thresholds as articulated in Inspection Manual Chapter (IMC) 0410, “Notices of Enforcement Discretion,” (ADAMS Reference Number ML13071A487).

Your staff implemented compensatory risk management measures prior to entering the period of the enforcement discretion, which were to remain in effect throughout the proposed period of discretion and were independently verified by NRC inspectors. The compensatory measures included staging an operator continuously at the station blackout diesel generator, performing no planned switchyard maintenance, protecting the motor-driven auxiliary feedwater trains and condensate and main feedwater systems, and implementing fire risk management actions. The compensatory actions were intended to increase operator awareness of plant conditions, to reduce the likelihood of losing redundant trains, and to reduce the likelihood and consequences of initiating events. Your staff also stated that no severe weather was forecast, which could challenge offsite power availability during the proposed period of enforcement discretion, grid conditions were normal, and no maintenance would be performed on safety-related equipment.

Your staff stated that the proposed change did not involve a significant hazard based on the three standards set forth in 10 CFR 50.92(c), and did not involve adverse consequences to the environment such that the proposed change meets the categorical exclusion set forth in 10 CFR 51.22(c)(9). The MPS Facility Safety Review Committee reviewed and concurred with the NOED request. Because the request was a one-time extension of the required completion times for repairs, your staff stated that a follow-up license amendment request was not required.

Based on the NRC staff’s evaluation of your request, the NRC has concluded that granting this NOED is consistent with the NRC’s Enforcement Policy and staff guidance. In addition, it meets Section 3.0.3 (b) of IMC 410 in that compliance with the TS would result in an unnecessary down-power or a shutdown of the reactor without a corresponding health and safety benefit.

Therefore, as communicated to your staff at 12:44 p.m. on January 26, 2014, the NRC exercised discretion to not enforce compliance with TS 3.7.1.2, Action C, for an additional period of 36 hours, which expired at 1:50 a.m. January 28, 2014. In addition, as discussed on January 26, 2014, the NRC staff agreed with your determination that a follow-up TS amendment is not needed. The staff concluded that an amendment (either a temporary or permanent amendment) is not necessary because this NOED involves a nonrecurring noncompliance and only involves a single request to not enforce compliance for36 hours with TS 3.7.1.2, Action C, to restore the TDAFW pump to an operable status within 72 hours.

As stated in the Enforcement Policy, action will be taken, to the extent that violations were involved, for the root cause that led to the noncompliance for which this NOED was necessary.

There are more pre 2011 Fort Calhouns out there right now!

Originally published this on July 15, 2014

July 15: Where did I hear intrusiveness…that was in the Palisades red yellow finding?

Reoccurring themes:  lack of Executive intrusiveness and just meeting the minimum regulatory requirements.

Bill,

Fort Calhoun Corrective Action Program Root Cause Analysis Report.  

Organizational Ineffectiveness at Fort Calhoun.

There is a Root Cause Analysis for you?

Do you trust the NRC to tell us really what going on in a nuclear plant and make a plant correct themselves before they cause great economic harm to the parent company and ruin the reputation of the nuclear industry? What role does the NRC play in protecting the ratepayers and businesses? Can you imagine this was going on and they did not or could not report on it pre 2011? Would we be a better nation if we got these employees to talk about their problem before the Great Missouri River flood and their large electric breaker problems leading to a prolonged shutdown and the NRC red finding? Would we be a better nation if the NRC gave the red finding way before the July 11, 2011 breaker fire leading to the red finding and prolonged shutdown?

What if the Great Flood happened and there was no NRC flood findings or poorly operating new large breaker issues...what if the plant came out of the 2011 event with widespread NRC and community respect??? Could they have been our heroes?

Can you even imagine not one employee in the know didn't step out of the shaddows informing the public things are really bad at my plant and we have to change pre 2011. All nuclear plant employees are cowards and they are only out for the money!!!

Should have done a scathing RCA outside report on the regulatory ineffectiveness here?  

What if god didn’t throw the great Missouri River flood at us and the breaker fire…what would have been the end point of the Fort Calhoun decline? What is larger than a red finding?

What if the NRC oversight of our nuclear plants now tolerates twenty Fort Calhoun pre July 11, 2011 plant culture failures, remember the ROP had no inclination to put a floor on the dysfunction (it could have gotten much worst). What would have been the worst accident coming out of these twenty plants if the NRC kept uninvolved ? What would the size be of our national embarrassment be? 

Sept 16, 2014

Here is my example...I wrote this on July 15, 2014

ARKANSAS NUCLEAR ONE- NRCINSPECTION REPORT - PRELIMINARY YELLOW FINDING - September 09, 2014

By Bob Meyer

This report is a shot over the bow of the nuclear industry for each plant to review flood walkdowns and review plant specific flood analysis. Based on my experience, some of the conditions that resulted in NRC violations exist at other plants. The NRC concuded that all long-term core makeup and cooling could have failed during an external flood.

Read this very important, detailed NRC inspection report and compare it to the conditions at your plant. Here is the redacted report.

Apparent Violation. The inspectors identified a finding of preliminary substantial safety significance (Yellow) for the failure to design, construct, and maintain the Units 1 and 2 auxiliary and emergency diesel fuel storage buildings in accordance with the safety analysis reports' description of internal and external flood barriers so that they could protect safety-related equipment from flooding. Two apparent violations were associated with this finding:

In other words, it would have to be worst than a red finding…at what level will the NRC finally put a floor on bad behavior and dysfunctions.

How many mad man and unseen pre July 11, 2011 Fort Calhouns do we have out there right now! 

Organizational ineffectiveness at Fort Calhoun Station

Condition Report: 2012-03986
A. EXECUTIVE SUMMARY:
Event Date: May 11, 2012
Executive Sponsor: W. Gary Gates
Summary of Events:

Fort Calhoun Station has a history of organizational effectiveness weaknesses as indicated by The Nuclear Regulatory Commission has identified organizational effectiveness issues in Problem identification and Resolution (PI&R) inspections conducted in 2007, 2009 and 2011. A PI&R Root Cause Analysis (CR2011~10135) identified that flawed mental models, misguided beliefs, and misplaced values have driven, influenced and permitted the misalignment of organizational behaviors. The station has shown an adverse regulatory trend of violations beginning in 2007, entering action matrix column 3 (95003) in October 2010, then action matrix column 4 in July 2011, to eventually Inspection Manual Chapter 0350 in December 2011.

 A root cause analysis team was formed to evaluate the causes of this organizational ineffectiveness. The team conducted a root cause analysis on organizational effectiveness related events that occurred from 2007 through May 2012. The team also reviewed the! I Sand Strategic Talent Solutions (STS) Executive Leadership Assessment summary to validate their findings.

Condition Report 2012-03986 was initiated when a team of station management personnel and external consultants determined that the Fort Calhoun Station‘s organizational effectiveness is inadequate. The team characterized the issue as follows: "Senior leaders and managers are not providing the necessary leadership to improve organizational performance. Additionally, leadership has failed to be intrusive, set the right priorities, and holds personnel accountable and has not understood major processes or issues affecting morale. As a result, timeliness and thoroughness of resolution of important issues has been lacking and station performance has declined significantly.”

The RCA team subsequently developed a problem statement that, “The Fort Calhoun Station (FCS) organization has been ineffective in meeting regulatory and industry standards, resulting in untimely and ineffective resolution of issues contributing to a significant decline in station performance."

This organizational effectiveness weakness has had a direct negative impact on nuclear, radiological, and industrial safety and other business aspects. Examples include organizational effectiveness issues identified in the Yellow external finding, the FAQ contactor failure White NRC identified finding, and the 184A Bus fire NRC Red finding. industries! safety has been identified by ######### as lacking sufficient organizational oversight and ####### that station oversight did not perform adequate organizational challenging of radiological planning for outages.

The analysis identified that there has been inadequate direction, prioritization and oversight from the "board of directors” down to the station leaders. The team identified three root causes and three contributing causes. Less than adequate corporate and station governance and oversight; leaders functioning more in a tactical rather than strategic manner and not valuing accountability; and lack of thorough policy implementation as root causes. Three policies were determined to be contributing causes base on the fact that both the policy was weak and needed improving, as well as proper implementation. Those three policies included the stations Nuclear Safety policy, Change Management policy, and Communications policy. All three of these policies were identified in the #####.

The extent of condition was based on the problem statement, interviews conducted, documents reviewed and the analytical tools used to assess FCS performance in the area of Organizational Effectiveness. An extent of condition exists: The team concluded the organizational effectiveness deficiencies reviewed by this causal analysis extend to those programs, processes, and departments throughout the organization.

ANO: First Killing A Employee Yellow Finding, Now A flooding Yellow Finding

Right, the design bases flood would have distroyed all the cooling systems...

The repeated theme here across many plants…some seminal event happens usually a yellow or red finding, a broken RHR injections valve ignored for years, a dropped stator, a hole in the head, historic flooding and safety electrical problems like Fort Calhoun…then the NRC comes in with more intensive inspections finding many other hanging around not addressed safety issues for decades and not related violations finding at the plant.  Talking about the power of the gods, it is as if the NRC has a special secret process where some secret rule breaking is tolerated by the NRC. It might be against the rules, but everyone knows some violations are acceptable to the NRC and maintain secret from the public.

 

ARKANSAS NUCLEAR ONE- NRC INSPECTION REPORT - PRELIMINARY YELLOW FINDING - September 09, 2014

I am not that far off with picking on Entergy. These guys are the most dishonest fleet operators in the USA.

This is the intolerable theme with many sentinel issues in the US industry. The sentinel issue shows up, like TVA with the broken RHR injection…then in the intensified public scrutiny and NRC inspections they find a gaggle of non-related violations hanging around for decades that the NRC ignored. You have no idea how damaging this is to the safety culture of a nuclear when the NRC telegraphs they won’t act on well known violations in which all the plant staff knows. So this flooding issues comes out of the delayed NRC response to negligently dropping the 600 ton stator at the site, killing one and injuring eight.

Again, this flooding yellow violation was hanging around for decades and subsequent to Fort Calhoun and Fukushima…

You know, how much do we really know about any plant in the USA…

Why was the Killing of one employee a yellow finding based on nuclear risk, a year to see the light, and then another yellow finding about flooding? It sounds like absolutely no forward motion in a year at ANO-Entergy. Even if it was a yellow finding today, why wasn’t it bumped up to a red finding or shutdown, as for deterrence for not immediately correcting their attitude from the stator drop accident? I asked at Entergy-Palisades to be returned to the yellow oversight regime.

I got another swing at the Palisades RCP issue a few days ago. It was basically a speech about there is absolutely no deterrence with the ROP. I brought up many recent industry events that I thought are all connected to an ineffective regulator. Even from one event to another similar event at the same plant. I spent a lot of time getting transcribed, risked getting thrown out of this 2.206 for drawing outside the lines. Even the NRC has issues with me staying on subject. I tried explained waht the meaning of Fort Calhoun was to the all these NRC employees.

I’ll throw a link on the transcription of my speech…the NRC should be ashamed of themselves. I am sure you would wonder what I really knew, when I was on the phone to the NRC.

And by the way, I called the Cooper senior inspector today… Once the senior resident figured out what I was asking, he threw me to the NRC PR spokesman.

Again, you should read my 2011 2.206 excepts I submitted recently here…it is as relevant today as it was in 201, predicting the future at Palisades and all the rest of the plants in the USA…

ARKANSAS NUCLEAR ONE- NRC INSPECTION REPORT PRELIMINARY YELLOW FINDING -September 09, 2014 

Submitted by NUCBIZ on September 11, 2014 - 18:20

By Bob Meyer

This report is a shot over the bow of the nuclear industry for each plant to review flood walkdowns and review plant specific flood analysis. Based on my experience, some of the conditions that resulted in NRC violations exist at other plants. The NRC concuded that all long-term core makeup and cooling could have failed during an external flood.

Read this very important, detailed NRC inspection report and compare it to the conditions at your plant. Here is the redacted report.

Apparent Violation. The inspectors identified a finding of preliminary substantial safety significance (Yellow) for the failure to design, construct, and maintain the Units 1 and 2 auxiliary and emergency diesel fuel storage buildings in accordance with the safety analysis reports' description of internal and external flood barriers so that they could protect safety-related equipment from flooding. Two apparent violations were associated with this finding:

• Contrary to 10 CFR Part 50, Appendix B, Criterion Ill, "Design Control," the licensee failed to assure that regulatory requirements and the design basis were correctly translated into specifications, drawings, procedures, and instructions, and that design changes were subjected to design control measures commensurate with those applied to the original design.

• Contrary to 10 CFR Part 50, Appendix B, Criterion V, "Instructions, Procedures, and Drawings," the licensee failed to prescribe documented instructions for activities affecting quality and accomplish activities affecting quality in accordance with drawings.

The inspectors determined that the finding was more than minor because it was associated with the protection against external factors attribute of the mitigating systems cornerstone and adversely affected the cornerstone objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. Specifically, the performance deficiency resulted in the vulnerability to flooding of safety-related equipment necessary to maintain core cooling in the auxiliary and emergency diesel fuel storage buildings.

The following were the dominant considerations in reaching a preliminary risk determination conclusion:

• With respect to the auxiliary and emergency diesel fuel storage buildings, there were more than 100 unknown ingress pathways for a flooding event, therefore if an external flood above grade level were to occur, the buildings would flood.

• The unexpected rate of flooding would likely be beyond the licensee's capability to prevent or mitigate as equipment and connections associated with alternative mitigating strategies, could be submerged.

• All reactor core cooling and makeup could fail due to significant flooding of the auxiliary and emergency diesel fuel storage buildings.

• The change in core damage frequency was quantitatively bounded below 2 x 10-3 and qualitatively determined to likely be less than 1 x 10-4 . The bounding and qualitative results are based on the frequency of the probable maximum flood event and a loss of all equipment needed for core cooling and makeup.

This finding was preliminarily determined to be of substantial safety significance (Yellow) for Unit 1 and Unit 2, as determined by a Significance and Enforcement Review Panel.

This finding had a cross-cutting aspect in the area of human performance related to maintaining design margins. Specifically, the licensee did not design, construct, and/or maintain over 100 flood barriers to ensure design margins were sustained [H.6].

Unit 1, Safety Analysis Report, Amendment 26, Section 5.1.6, "Flooding," defined the design basis for external flooding and stated, in part, that the seismic class 1 structures are designed for the maximum probable flood level at elevation 361 feet above mean sea level (MSL). All seismic class 1 systems and equipment are either located on floors above elevation 361 feet MSL or protected. Sections 5.3.2 and 5.3.5.2 identified the auxiliary and emergency diesel fuel storage buildings as seismic class 1 structures.

Unit 2, Safety Analysis Report, Amendment 25, Section 3.4.4, "Flood Protection," defined the design basis for external flooding and stated, in part, that seismic category 1 structures were designed for the probable maximum flood . All category 1 systems and equipment were either located on floors above elevation 369 feet MSL, or are protected. Table 3.2-2, "Seismic Categories of Systems, Components, and Structures," identified the auxiliary and emergency diesel fuel storage buildings as seismic class 1 structures.

At the end of the inspection period, the following deficient flood protection features had been identified:

1. Unsealed Conduits

Over 100 unsealed conduits that penetrated flood barriers for the Unit 1 and Unit 2 auxiliary and emergency diesel fuel storage buildings between 335 feet MSL and 361 feet MSL.

2. Degraded Seals

The March 31, 2013, stator drop event revealed degraded hatch seals that allowed fire water in the turbine building to leak into the Unit 1 auxiliary building. During extent of condition reviews, the licensee identified 13 degraded hatches for Unit 1 and Unit 2 at 354 feet MSL (site grade elevation). The licensee determined that some hatch seals were degraded from age and some hatch seals were rolled out of place upon installation. From its extent of condition review, the licensee also identified that the building expansion joint between the auxiliary building and containment buildings was significantly degraded and could be subjected to external floodwater by backflooding through un-isolable floor drains.

The inspectors determined that the degraded hatch seals failed to protect safety-related systems from flooding, and that the licensee failed to establish instructions that prescribed how to adequately inspect, replace, and test the seals. The licensee corrected the hatch seal deficiencies by establishing adequate instructions, replacing the seals, and smoke testing the hatches or seal welding the hatches shut. The licensee implemented compensatory measures to plug the floor drains upon notification of a flood to prevent external floodwater from impacting the auxiliary building to containment building expansion joint.

3. Ventilation Penetration

...during construction, the ductwork blind flange was not fabricated and procedural instructions to isolate this flooding pathway were never developed.

The inspectors determined that the licensee failed to stage the blind flange and translate the design for flange installation into Procedure OP-1203.025, "Natural Emergencies," Revision 37.

4. Floor Drains

During extent of condition reviews for the degraded hatches, the licensee identified that floor drains at 354 feet MSL from the turbine building and old radwaste building sump were routed to the Unit 1 auxiliary building and the lines did not contain isolation valves in case of flooding. The inspector determined that the licensee failed to translate the design requirement to have isolation capability into specifications and drawings for the floor drain system . The licensee corrected the condition by installing a blind flange on the old radwaste building sump drain line and implemented compensatory measures to plug the drain line from the turbine building upon notification of a flood.

5. Auxiliary Building Extension

During extent of condition reviews for the degraded hatches, the licensee identified that some Unit 2 auxiliary building extension pipe penetrations between 335 feet MSL and 354 feet MSL were not sealed between the turbine building and auxiliary building extension. Unit 2 Drawing A-2002, "Architectural Schematic, Fire and Flood Protection Plans and Sections," Revision 10, referenced which walls, ceilings, and floors are flood barriers that required seals. Unit 2 Drawing Series A-2600, "Fire Barrier Penetration Seal Details," Revision 5, showed seal installation details that met flood barrier requirements.

The inspectors determined that the licensee failed to install seals for pipe penetrations that could be subjected to floodwater. The licensee designed the auxiliary building extension to be watertight in order to protect the auxiliary building because the buildings were connected by a non-watertight door below the design flood elevation. The unsealed pipe penetrations combined with the non-watertight door could lead to flooding of the Unit 2 auxiliary building. The licensee corrected the condition by modifying the non-watertight door connecting the auxiliary building and the extension, so that if the Unit 2 auxiliary building extension flooded, the Unit 2 auxiliary building would not flood.

6. Non-Watertight Door and Hatch

During extent of condition reviews for the degraded hatches, the licensee identified non-watertight Unit 1 Hatch 522 and Unit 2 Door 253 that could be subjected to floodwater at 358 feet MSL. The licensee found that the door and hatch in the area between the Unit 1 and Unit 2 auxiliary building and containments could be subject to external floodwater because the area was below the design flood level, and the area floor drains were connected to Lake Dardanelle without backwater (check) valves. The inspectors determined that the licensee failed to translate design requirements into specifications and drawings for the Hatch 522 and Door 253. The licensee implemented compensatory measures to plug the floor drains upon notification of a flood.

7. Abandoned Equipment

During a flooding walkdown, the inspectors identified unsealed abandoned pipes that penetrated the Unit 1 auxiliary building flood barrier at 354 feet MSL. The inspectors discovered two pipes that penetrated the auxiliary building from the turbine building that were open on both ends. The licensee cut the pipes as part of a modification to abandon the waste solidification system. However, the design change failed to protect the Unit 1 auxiliary building from floodwater, a design requirement. The licensee corrected the condition by installing a blind flange and a pipe cap to seal the pipes.

8. Decay Heat Vault Drain Valves

The March 31, 2013, stator drop event revealed an open decay heat vault drain valve that allowed fire water internal to the auxiliary building to leak into Unit 1 decay heat vault B at 317 feet MSL. Unit 1, Safety Analysis Report, Amendment 26, Section 5.3.2, "Auxiliary Building," stated, in part, that the floor area at elevation 317 feet containing engineered safeguards equipment was partitioned into separate rooms to provide protection in the event of flooding due to a pipe rupture. In addition, the auxiliary building, which contains the decay heat removal vaults, is classified as seismic category 1 and is a safety-related structure; thereby the decay heat removal vaults are also safety-related. Each decay heat vault room contains a decay heat removal pump (low head safety injection) that is needed for accident mitigation.

The licensee determined that the reach rod for the valve was loose, so that the position indication was inaccurate, and that the condition applied to both Unit 1 decay heat vaults' drain valves. The inspectors identified that valve position indicated that the valve was closed for approximately 36 degrees of valve rotation. Consequently, when the valve indicated closed, it could actually be open. As stated above, the Unit 1 Safety Analysis Report indicated that the decay heat vaults were designed to be watertight, and the auxiliary building was designated seismic category 1 (safety-related), which includes the decay heat vaults; however, the inspectors determined that the vault drain valves were classified as non-safety-related components.

The inspectors determined that the licensee failed to identify the loose reach rods during daily operation or surveillance testing, correct the inaccurate position indication, and properly classify the vault drain valves as safety-related. The licensee corrected the deficiencies by replacing the reach rods and ensuring the position indication was accurate. In addition, the licensee initiated Condition Report CR-ANO-C-2014-01477 to document the inspectors concerns with maintenance and classification of the vault drain valves.

9. Startup transformer 2 Buswork

The inspectors identified that startup transformer 2 buswork was installed at 360.5 feet MSL. The licensee credited offsite power for Unit 1 and Unit 2 through startup transformer 2 up to the design flood level of 361 feet MSL, as an alternating current power source for vital and non-vital loads. The licensee implemented compensatory actions to seal the buswork upon notification of a flood.

Due to the number and relatively large area of unsealed penetrations affecting both Unit 1 and Unit 2 auxiliary buildings at plant grade or below, an external flood could cause an inflow of approximately 2,000 gallons per minute and overwhelm the total sump pump capacity of 300 gallons per minute. For unsealed penetrations, the inspectors calculated the inflow by creating a matrix of the penetrations, with a static head of water at the penetration given a flood height of 354 feet , 1 inch MSL. The inspectors calculated the potential flow through those unsealed penetrations using the Bernoulli and Darcy Weisbach equations, with the penetration lengths, number of elbows and other restrictions, as indicated on plant drawings, being included in the calculations. The inspectors estimated the flow through hatches by calculating the flowrate through the hatches during the stator drop event based on water volume and time and applying that potential flowrate to the remainder of hatches and doors. The static head of water on the hatches during the stator drop could approximate a flood height of 354 feet, 1 inch MSL. The Unit 1 and Unit 2 emergency diesel fuel storage building had 14 unsealed conduits that penetrated the flood barrier, and the inflow could overwhelm the sump pump capacity of 15 gallons per minute. The inspectors determined that the auxiliary and emergency diesel fuel storage buildings could flood if water level exceeded site grade elevation.

The inspectors conclude d that, for Unit 1 and Unit 2, the licensee failed to protect safety-related systems below the design flood level from external floodwater, including equipment inside of vaults. Most importantly, all long-term core makeup and cooling could have failed during an external flood.

The emergency diesel fuel storage building could have flooded, submerging the Unit 1 and Unit 2 diesel fuel oil transfer pumps, which could have starved the emergency diesel generators of fuel. Unit 1 and Unit 2 spent fuel pool cooling could have been lost because both units' pumps are in the auxiliary building below flood elevation and are not flood protected. Unit 2 outside containment isolation valves were affected because breakers for the valves could be submerged, however the valves were accessible for manual operation and the inside containment isolation valves would be available. Unit 1 and Unit 2 containment spray systems could be submerged. Unit 1 and Unit 2 portable recovery equipment, connections, and other recovery strategies, such as gravity feeding tanks, could be unavailable due to submergence from flooding.

The NRC and licensee identified multiple floodwater paths into the auxiliary building after the licensee had performed flooding walkdowns, as directed by the March 12, 2012, 50.54(f) letter, concerning actions to be taken by licensees that resulted from the Fukushima Dai-ichi nuclear power plant event. The licensee failed to properly identify all flood protection features, as specified in NEI 12-07, "Guidelines for Performing Walkdowns of Plant Flood Protection Features," Revision 0.

Licensee Personnel

J. Browning, Site Vice President

D. James, Director, Regulatory and Performance Department

S. Pyle, Manager, Regulatory Assurance

NRC ADAMS: ML14253A122

Oconee Turned Into Junk

My bad, I assumed this happened yesturday... I guess leaking SRVs are normal??? At least I self check myself...I was looking for if Oconee had repeated issues with SRVs. If I paid attention to the date of the event on 10/24/2013 I wouldn't have put it up.

LER-287/2013-01

It is bad when two broken components show up in one plant trip (broken feedwater thing and a leaking relief)...but four misoperating reliefs???

I am certain they reduced pressure by 30 psig by the nature of the trip on their own without going into the procedure...

MANUAL REACTOR TRIP FROM FULL POWER DUE TO FEEDWATER SYSTEM OSCILLATIONS

"At 0553 EDT on 10/24/2013, Oconee Unit 3 was manually tripped due to oscillations in the feedwater system in anticipation of an automatic reactor trip. At 0549 EDT, Unit 3 began experiencing small feedwater oscillations. The feedwater control system was placed in manual in an attempt to stabilize feedwater flows. Feedwater oscillations continued to grow in magnitude and at 0553 EDT, a manual trip was directed to prevent an automatic reactor trip.

"Due to an RPS actuation, this event is being reported as a 4 and 8 hour Non-Emergency per 10 CFR 50.72 (b)(2)(iv)(B) and 10 CFR 50.72 (b)(3)

"Following the reactor trip, four main steam relief valves failed to reseat. Procedure guidance was utilized to reduce main steam system pressure by approximately 30 psig to reseat the main steam relief valves. All main stream relief valves are now reseated. All other post trip conditions were normal and all other systems performed as expected. Unit 3 is currently in Mode 3 and stable.

"Operations have been stabilized on Unit 3. A post-trip investigation is in progress, per site procedures and directives."

The licensee has notified the NRC Resident Inspector.


* * * UPDATE FROM BOB MEIXELL TO DONALD NORWOOD AT 1439 ON 9/10/14 * * *

"Duke Energy reviewed NRC Event Number 49471 against NUREG 1022, Rev 3, section 3.2.6, "System Actuation" and determined this event should have been reported only per 10 CFR 50.72 (b)(2)(iv)(B), RPS Actuation (while critical). Thus, Duke Energy is revising NRC Event Number 49471 to remove the 8-hour report criteria 10 CFR 50.72 (b)(2)(iv)(A). The NRC Resident Inspector was notified of this revised report.

"This update has no effect on safety significance."

Notified R2DO (Shaeffer).