Cover-up And OK'd Falsification of Documents At Seabook

Straight from Seabrook's union President Ted Jenis today about why they are still using that carbon steel crap pipe in the service water system.

November 26. 2013 9:53PM

Seabrook plant close to lockout in union dispute

SEABROOK — A federal mediator arrives at the Seabrook Station nuclear power plant today, hoping to break a contract impasse that could lead to a lockout of plant operators represented by the Utility Workers Union of America, AFL-CIO, as early as Dec. 2.

“Their battle cry is‘natural gas is killing us. We are not making the money we were making five years ago,’ ” said Jenis. “But it’s hard for us to sit here and see these raises go out to management.”

"This is a workplace that has been beaten down over the last few years," he said.

 “There seems to be a total attitude change toward the workers from the corporate level.”

...This comes from a discussion I had with the senior resident NRC inspector in Seabrook.

So basically they put in a new 10 foot section of service water pipe in 2011. It had a plastic coating where they bragged it would last 20 years. It’s carbon steel pipe in a seawater system.
 

According to the Senior Resident inspector there is a lot of leaks in the service water system, one now in the cooling tower piping...he said carbon steel piping for seawater is “crap”. Him and me are brothers as we both served in nuclear submarines. He was talking about all the leaks and the chlorides in the seawater...I interrupted his happyland with that carbon steel is nothing but junk. I said you know that. Then he said, “yep, its crap”.

So it began leaking this Aug 7^th or so. It is the summer and everyone worries about grid load if you know what I mean. Who pays for the replacement power if Seabrook had to shut down?

So Seabrook filled out per procedure “prompt operability determination” (POD) document. They did ultrasonic testing (UT)...the NRC report says they first filled out a UT report which is a falsification. There was no report in the most important moment of the NRC’s investigation when the inspector was first investigating the leaks. And the NRC’s managers don’t give a shit if Dominion puts up a ton of barriers making it difficult and timely...eat up the precious inspector time... for the inspectors to investigate safety problems at a operating reactor.

As the senior inspector complained to me...we got only a very limited amount of paid time in a day, week or monthly pay period. We are incentivized to spend very little time at the plant. We don’t get paid after 40 hours. I believe the manager don’t want them to put in extra time. Political Campaign contributions stuff these rule down the inspector throats. The nuclear plant executives fears the more hours an inspector spends at a plant the more violation they will get.   

“No” so says the senior resident inspector. The POD referencing the UT basically said the leak was insignificant and there are no long term risks. This resident inspector in a prior life was a welder and he read many UT results. Dominion didn’t think the NRC would go in farther than the POD. But the resident asked to see the UT report. Seabrook himmed and hawed looking for the document...the resident finally decided to hunt it down by foot. He went into a few offices...finally an Dominion employee finding it in the UT machine. He had start up the actual device. Dominion was making it difficult for the inspectors to see the documents.

The UT reading was obscenely worse than the POD. Dominion falsified the POD.

I asked the resident, well then it’s a falsification and you can’t trust the integrity of the staff at the plant. He said he agreed with that...but we called it just gross incompetence. What is the difference I said, if you are so grossly incompetent you can’t accurately assess the leaking hole in a pipe in an unbelievable important plant and reactor cooling pipe. The UT said a rather large area had a zero thickness.   

I mean, how can you trust Seabrook to assess anything in the plant.

I asked, once you learned Seabrook lost the bubble and played games in hiding safety testing results why didn’t the agency declare the side INOP and make them shutdown in 24 hours like the rules demand. He remained silent on this. But I pushed him about Dominion falsifying safety documents the NRC depends on. He thought for a moment, “saying they didn’t see it like that, they were just grossly incompetent.

The leak eventually got much worst...the NRC said the sized of the hole and leak in the plant was larger than any of there safety analysis.

He said the Dominion was basically obstinate throughout this, that the plant was safe through the next month...they didn’t even need to put a Band-Aid on it. 

The resident indicated he couldn’t believe how reckless Dominion was and how disrespectful Seabrook was to the role he played at the plant  He advocated Seabrook should be severely sited with a violation for their behavior...but his bosses above him prevented him from siting the plant. So how is the plant going to respect him now.

Dominion stock price is doing extremely well compare to the other utilities. Their stock price has been on a steep increase for many years. We have seen how utilities get big headed over high stock prices. They basically think their stock price proves they are safe. A high price stock price is very unsafe...it leads to arrogance and overconfidence.

1)    Dominion falsified the POD saying the leak was insignificant when they had indications there was zero pipe wall metal left and the geometry of the hole could lead to a very large increase in leak rate. The NRC allows Dominion to get away with inaccurate and falsified documents to a Federal regulator.

2)    Dominion gave falsified information on the new "piping material and Belzona" on its service water system. So they had evidence this Belzona crap could fail very early and it still did. Seabrook promised in their license renewal they would get service water leaks and degradation and it is only gotten more out of control and worsening with new piping failing in two years.

     April 26, 2012

      Seabrook Station Response to Request for Additional Information 
NextEra Energy Seabrook License Renewal Application Supplemental Response - RAI B.2.1.11-2 and B.2.1.12-6 

      Belzona® products are polymeric materials commonly used for lining and liner repairs at Seabrook Station. An engineering evaluation performed in 1993 indicates that Belzona lined pipe has an expected service life of 15 years. However, review of the NextEra Energy OE database has not indicated failures of the Belzona lining due to exceeding its service life. The condition of all Service Water pipe linings is monitored via periodic internal pipe inspections in accordance with the "Service Water Inspection and Repair Trending Program"' Preventive maintenance activities have been initiated to insure inspections are scheduled and are being tracked. The extent of use of the Belzona and polyurethane coatings in Service Water piping has been identified and is being tracked in the Service Water Inspection and Repair Trending Program.

3)   The NRC managers place improper pressure on a senior resident inspector to downplay the severity of safety piping leak into a non sited violation.

 

I wish the inspectors and their managers had more attention to detail. There is two renditon with how they charactoize the leaking hole. Which one is right?

I been through the rounds, made a safety complaint to region I. Talked to the region I public relation department and got Senator Shaheen office to begin asking questions to the NRC. Called Seabrook plant security and asked them to pass on a message to their PR department or engineering for comment.
 

November 19, 2013

Mr. Kevin Walsh

Site Vice President

Seabrook Nuclear Power Plant

NextEra Energy Seabrook, LLC

c/o Mr. Michael Ossing

P.O. Box 300

Seabrook, NH 03874

SUBJECT: SEABROOK STATION, UNIT NO. 1 - NRC INTEGRATED INSPECTION REPORT 05000443/2013004 AND INDEPENDENT SPENT FUEL STORAGE INSTALLATION (ISFSI) REPORT NO. 07200063/2013001

Introduction. The inspectors identified a Green NCV of 10 CFR Part 50, Appendix B, Criterion V, “Instructions, Procedures, and Drawings,” and an associated violation of TS 3.7.4, because NextEra did not follow the requirements of station procedure EN-AA-203-1001, “Operability Determinations/ Functionality Assessments.” Specifically, NextEra did not properly evaluate and document an adequate basis for operability, when relevant information was available that would have challenged the “reasonable assurance for operability” threshold for a SW through-wall leak that degraded incrementally from weepage on August 7, 2013, to a significantly larger leak on August 28, 2013.

Description. On August 7, 2013, NextEra personnel discovered a through-wall leak on  a section of 24-inch bypass piping associated with the “B” train SW system strainer No. 11. In accordance with EN-AA-203-1001, “Operability Determinations/ Functionality Assessments,” an immediate operability determination was performed that concluded the SW system was operable but degraded, with an estimated leak rate of 10 drops per minute (dpm), and within the CAP under action request (AR) No. 01895334. NextEra subsequently completed a prompt operability determination (POD), on August 8, 2013, which utilized American Society of Mechanical Engineers (ASME) Boiler and Pressure Vessel Code case N-513-3, “Evaluation Criteria for Temporary Acceptance of Flaws in Moderate Energy Class 2 or 3 Piping,” Section XI, Division 1, consistent with site procedures and NRC regulations. The POD documented the piping section had adequate structural integrity to meet code requirements, following the performance of volumetric examination of the flaw, through the use of ultrasonic testing (UT), performed in accordance with procedure ES1807.012, “Ultrasonic Thickness Measurements.”

Additionally, the UT report was reviewed by Engineering based on the results of the flaw evaluation and concluded the flaw was stable and acceptable for continued service. The UT evaluation documented and characterized the flaw as exhibiting an “abrupt change in thickness from nominal…absent the normal intermittent thickness readings that are seen within flawed areas of SW piping.” Because of this atypical result, the flaw was “conservatively bounded” by the inside piping surface UT signal loss, resulting in a flaw size of “…2.327-inches circumferentially by 1.50-inches axially with a remaining wall thickness of 0.00-inches…” The POD also concluded the observed leak rate was within design and licensing basis flow and leakage requirements, which supported the operable but degraded conclusion.

On August 20, 2013, NextEra personnel identified that the leak had degraded to an approximate leak rate of 90 dpm. The basis of operability, which was documented in AR report No. 01898318, referred back to the August 8 POD, (performed under AR 01895334) and concluded the 90 dpm leakage value continued to be within the bounding design and licensing basis flow and leakage requirements. The operability basis was supported by a follow-up UT of the affected area, performed on August 21, which revealed essentially similar UT results. The evaluation summarized the flaw examination as follows:

“Based on the PAUT examination the flaws axial and circumferential dimensions are unchanged with no reportable thickness. However, the rapid change in the OD surface coupled with the lack of UT thickness data in the flawed area suggests that there is little remaining wall at this location. It is likely that the size of the through wall hole will rapidly increase to the full 1.5-inch by 2.367-inch dimension.”

On August 28, 2013, during a planned performance of surveillance testing of a CT SW pump, NextEra identified that the leak had progressively worsened to an estimated 25 gallons per minute (gpm). Subsequent evaluations postulated that the additional SW header pressure during CT SW pump operation (66 psig versus nominal 48 psig) contributed to the degrading condition of the leak at the identified flaw location. NextEra installed a housekeeping patch to limit the impact of water spray, and instituted several corrective actions under AR No. 01900249, as well as the originating AR No. 01895334 and its associated POD, which had continued to govern the basis and continued reasonable assurance for operability, which included, for example, the formation of an Operational Decision-Making (ODM) team, and planning extent-of-condition piping inspections to meet Code Case N513-3 requirements.

Also, TS 3.7.4.d requires, in part, that with two loops (except two CT loops) inoperable, return at least one of the affected loops to OPERABLE status within 24 hours, or be in at least HOT STANDBY within 6 hours and in COLD SHUTDOWN within the following 30 hours. Contrary to the above, between August 7, 2013, and September 1, 2013, when the weldolet repair was completed on the “B” SW header piping, one CT SW loop and one ocean SW loop were inoperable for greater than TS requirements, and therefore,  is considered a TS-prohibited condition. Corrective actions included apparent cause evaluations to determine the cause of (1) the flaw on the “B” SW strainer bypass header and (2) the missed opportunities to identify the significance of the UT data, as well as the NRC-approved code relief that resulted in the temporary weldolet installed over the flaw area on the “B” SW strainer bypass header. NextEra entered these issues into their CAP as AR 01904703.

The inspectors assessed NextEra performance regarding the evaluation of the degrading and non-conforming condition, and concluded that all available information should have resulted in a determination by NextEra that the leak could propagate to the bounding geometry discussed in the UT reports to 1.5-inches circumferentially and 2.3-inches axially. Moreover, since flow through this 1.5-inch by 2.3-inch defect would result in leakage outside the current licensing and design bases of the plant, reasonable assurance of operability was no longer appropriate for the circumstances, and should have resulted in the “B” SW ocean and CT headers being declared inoperable.

As a result, the inspectors determined that the reasonable expectation of operability was no longer credibly assured based on the following factors:

 1. The subject carbon steel (belzona-lined) piping was newly-installed on or about April 2011, with a nominal thickness of 0.375-inches. The leak in August 2013, directly indicates an average loss over the approximate 28 months of 0.160-inches/year, which far exceeded the corrosion rates of 0.030-inches/year utilized in the POD to justify continued operability;

2. The actual, rapid leak propagation that occurred from 10 dpm on August 7, to 90 dpm on August 20, to 25 gpm (while running CT SW pumps) on August 28, and ultimately, the estimated 15 gpm with normal ocean SW pressures, indicated a flaw degradation that appeared to be consistent with the flaw evaluation conducted following the volumetric examinations;

3. The physical condition of the piping at the flaw location was characterized initially as “weepage,” on August 7, followed by a “concavity” that appeared at the flaw location on August 20, and ultimately as a through-wall hole on August 28 with a resultant estimated leak rate of 25 gpm. This rapid deterioration of ASME Class 3 piping wall was also consistent with the flaw evaluation and volumetric examinations that predicted very little remaining material of a specific geometry;

4. Information regarding the leak-rate from a hole characterized in the flaw evaluation, i.e., bounded by “…2.327-inches circumferentially by 1.50-inches axially with a remaining wall thickness of 0.00-inches…” was not integrated into the evaluation under the POD regarding the reasonable expectation of operability. Moreover, when the bounding flaw size was used to determine potential leak rates using standard engineering equations, an approximate 570 gpm leak rate was calculated. This resultant leak rate was outside the Operability criteria established in the POD of (1) 137.25 gpm (excluding SW boundary valve leak-by) based on leakage criteria associated with UFSAR design basis values of CT inventory for a 7-day mission time without makeup, (2) 130 gpm available margin from calculations that address SW cooling the primary component cooling heat exchanger, and (3) 250 gpm available margin from calculations that address SW cooling the diesel generator heat exchanger; and

5. It was known that the rapid leak propagation occurred from 90 dpm to 25 gpm on August 28, during surveillance testing of CT pumps, which directly indicated that a 20 psig increase in fluid system pressures caused the rapid leak propagation. Coupled with the volumetric flow information that was also known, a direct challenge to the reasonable expectation of operability should have been identified, or, more directly, a recognition that for all specified safety functions and design basis mission times, further operability of the “B” SW header with a rapidly degrading pipe wall and increased leak rates, was not assured.

Subsequently, through discussions between the NRC and NextEra, on August 31, NextEra was granted relief to perform a temporary, non-ASME code repair to the SW piping through the installation of a weldolet assembly over the affected flaw area, in compliance with 10 CFR 50.55a(a)(3)(ii), and completed the repair efforts on September 1, 2013. Current NextEra planning includes replacement of the flaw area in the next refueling outage, and completion of corrective actions associated with a number of apparent cause evaluations and other associated activities.

Analysis. The inspectors identified that NextEra did not follow the requirements of station procedure EN-AA-203-1001, “Operability Determinations/ Functionality Assessments.” Specifically, NextEra did not properly evaluate and document an adequate basis for operability, when relevant information was available in the form of atypical UT data and assessment, and more importantly, the propagation of a SW leak from a flaw that occurred between August 7 and August 28, 2013. The characterization and assessment of the flaw through UT methods was consistent with the leak propagation that was subsequently observed. This information was available for utilization during the prompt operability determination process, and directly challenges the “reasonable expectation for operability” threshold for a SW through-wall leak. Specifically, EN-AA-203-1001 stipulates that determination of operability be based on “the licensee’s reasonable expectation,” from the evidence collected, that SSCs are operable and that the operability determination will support the expectation. This failure to consider all relevant information was reasonably within NextEra’s ability to foresee and correct, and their failure to appropriately assess operability when a degrading or non-conforming condition was identified was a performance deficiency. This performance deficiency is more than minor, and considered a finding, because it is associated with the equipment performance attribute of the Mitigating Systems Cornerstone, and affected its objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. Specifically, the prompt operability determination incorrectly concluded the “B” CT SW header and the “B” SW (ocean) pumps were operable, but degraded, because they did not utilize appropriate rigor to determine that given the (1) UT information and assessment, (2) identified flaw size, and (3) actual leak propagation, the resultant information translated into potential leakage values would have yielded leak rates in excess of the operability limits established in NextEra’s current licensing basis, and in some cases, inconsistent with design basis required boundary leakage values.

The inspectors and Region I Senior Reactor Analyst (SRA) used IMC 0609, “Significance Determination Process,” Attachment 04, to perform the initial safety significance characterization of this finding. The inspectors assumed that functionality of the SW system, based upon the as-found wall thinning, would only be challenged when aligned to the cooling tower basin (higher suction pressure) and the SW piping is subjected to a higher overall system pressure. This system configuration is used to mitigate a seismic event following the loss of the normal SW intake structure. Accordingly, the inspectors used IMC 0609, Appendix A, Exhibit 2, “Mitigating Systems Screening Questions,” and Exhibit 4, “External Events Screening Questions,” to assess this issue and conclude a detailed risk evaluation was warranted.

The SRA used insights from the Seabrook Updated FSAR and Seabrook Individual Plant Examination of External Events (IPEEE), as well as, the Risk Assessment Standardization Project (RASP) Handbook, Volume 2, to perform a qualitative assessment. The operating basis earthquake (OBE) and the safe shutdown earthquake (SSE) peak horizontal ground acceleration values are 0.125g and 0.25g, respectively. From IPEEE Table 3.2, “Seabrook Fragility Analysis: Seismic Capacity of Structures,” and Table 3.3, “Seabrook Fragility Analysis: Equipment Fragilities,” the seismic design capacities of the Service Water (SW) Pumphouse, SW Intake Structure, SW Cooling Tower, and SW piping are all built to withstand seismic events that exceed 2.0g. Based upon IPEEE, Figure 3-1, “Family of Seismic Hazard Curves for the Seabrook Site,” the annual exceedance probability of an earthquake producing ground accelerations greater than 2.0g (of a magnitude sufficient to challenge the seismic capacity of the SW Intake Structure) is approximately 1.0E-07. Assuming an earthquake of this magnitude and the failure of the SW intake structure, it is likely the unit will be manually shutdown, if not automatically tripped, from the event. In conjunction with plant walkdowns to identify and assess SSC damage, operators would be tasked with aligning the service water suction to the cooling tower basin. Assuming worst case operator performance due to high stress and limited time available to restore service water cooling for decay heat removal and RCP seal cooling, the SRA assumed a one in ten probability of failure (to realign the SW system suction to the cooling tower basin). Lastly, the probability of a service water piping failure (rupture) due to the observed wall thinning cannot be accurately quantified, but under a worst case condition can assume to be 1.0. Therefore, the estimated increase in core damage probability associated with this performance deficiency is in the low 1.0E-08 range or very low safety significance (Green).

The finding has a cross-cutting aspect in the area of human performance associated with the decision making component because NextEra failed to use conservative assumptions in decision-making and adopt a requirement to demonstrate that the proposed action is safe in order to proceed rather than a requirement to demonstrate it is unsafe in order to disapprove the action. Specifically, NextEra personnel had not considered relevant information in the form of UT data and actual leak propagation to conclude that they no longer had “reasonable assurance of operability” and did not declare the “B” header of ocean and CT SW systems inoperable [H.1(b)].

Enforcement. 10 CFR Part 50, Appendix B, Criterion V, “Instructions, Procedures, and Drawings,” requires, in part, that activities affecting quality shall be prescribed by documented instructions or procedures, and shall be accomplished accordingly. NextEra’s procedure EN-AA-203-1001, “Operability Determinations/ Functionality Assessments,” requires in part, that a SSC remains operable until reasonable expectation of operability cannot be demonstrated, with specific focus on the ability of the SSC to perform its specified safety function. Contrary to the above, NextEra did not properly evaluate and document an adequate basis for operability, when relevant information from volumetric UT data was available that would have challenged the “reasonable assurance for operability” threshold for a SW through-wall leak that degraded incrementally from weepage on August 7, 2013, to a significantly larger leak on August 28, 2013. In addition, between August 7, 2013 and September 1, 2013, when the weldolet repair was completed on the “B” SW header piping, one CT SW loop and one ocean SW loop were inoperable for greater than TS 3.7.4.b. requirements, and therefore, is a TS-prohibited condition. NextEra entered this issue regarding the TS violation in the CAP, to evaluate the cause and to determine actions to prevent recurrence, as AR No. 01916618 and 01904703. Because this finding is of very low safety significance and was entered into NextEra’s CAP, this violation is being treated as an NCV consistent with Section 2.3.2 of the NRC Enforcement Policy.

(NCV 05000443/2013004-01, Inadequate Operability Determination Regarding Service Water Leakage and Associated TS Violation)