ML12276A301

Summary of October 25, November 8, and November 10, 2011, Conference Calls Related to Fall 2011 Refueling Outage Steam Generator Tube Inspections

ML12276A301
Person / Time
Site:	Arkansas Nuclear
Issue date:	10/12/2012
From:	Kalyanam N Plant Licensing Branch IV
To:	Entergy Operations
Kalyanam N NRR/DORL/LPLIV 301-415-1480
References
TAC ME7368
Download: ML12276A301 (6)

Text

UNITED STATES NUCLEAR REGULATORY COMMISSION WASHINGTON, D.C. 20555*0001 October 12, 2012 Vice President, Operations Arkansas Nuclear One Entergy Operations. Inc.

1448 SR. 333 Russellville, AR 72802

SUBJECT:

ARKANSAS NUCLEAR ONE. UNIT NO.1 -

SUMMARY

OF OCTOBER 25, NOVEMBER 8, AND NOVEMBER 10, 2011, CONFERENCE CALLS REGARDING THE FALL 2011 STEAM GENERATOR TUBE INSPECTIONS (TAC NO. ME7368)

Dear Sir or Madam:

On October 25, November 8, and November 10,2011, the U.S. Nuclear Regulatory Commission (NRC) staff participated in conference calls with representatives of Entergy Operations, Inc. (the licensee), regarding its ongoing steam generator tube in$pection activities at Arkansas Nuclear One, Unit 1. A summary of the conference calls is enclosed. Information provided by the licensee in support of and subsequent to the conference call on October 25, 2011, is located in the Agencywide Documents Access and Management System (ADAMS) at Accession No. ML112990340. The NRC staff did not identify any issues that would warrant preventing the plant from starting up following its 17th refueling outage (RFO).

The NRC staff indicated that it might be interested in reviewing some of the eddy current data associated with the absolute drift indications. The NRC staff is evaluating the need for further discussion on this issue.

If you have any questions, please contact me at (301) 415-1480 or bye-mall at kaly.kalyanam@nrc.gov.

Sincerely,

~~

N. Kaly Kalyanam, Project Manager Plant Licensing Branch IV Division of Operating Reactor licensing Office of Nuclear Reactor Regulation Docket No. 50-313

Enclosure:

As stated cc w/encl: Distribution via Listserv

SUMMARY

OF CONFERENCE CALLS WITH ENTERGY OPERATIONS, INC .. REGARDING THE FALL 2011 STEAM GENERATOR TUBE INSPECTION RESULTS AT ARKANSAS NUCLEAR ONE, UNIT 1 DOCKET NO. 50-313 On October 25, November 8, and November 10, 2011, the U.S. Nuclear Regulatory Commission (NRC) staff participated in conference calls with representatives of Entergy Operations, Inc. (Entergy, the licensee), regarding its ongoing steam generator (SG) tube inspection activities at Arkansas Nuclear One, Unit 1 (ANO-1).

Information provided by the licensee in support of and subsequent to the conference call on October 25, 2011, is located in the Agencywide Documents Access and Management System (ADAMS) at Accession No. ML112990340. The replacement steam generators (RSGs) for ANO-1 are Enhanced Once-Through Steam Generators (EOTSG) manufactured by AREVA.

The EOTSG is a straight shell and tube-type heat exchanger installed in a vertical position. The Alloy 690 thermally treated tubing has a nominal diameter of 0.625 inches and a nominal wall thickness of 0.037 inches. The tubes were expanded hydraulically for the full depth of the tubesheet. There are 15 tube support plates (TSPs) that are constructed of Type 410 stainless steel. These supports have a trefoil-shaped hole design.

Conference call held on October 25. 2011 During the conference call on October 25, 2011, the licensee stated that this is the fourth inspection of the RSGs since installation and the first time that tie-rod bowing was found in SG B. Tie-rod bowing has been noted in SG A since the first inspection outage after replacement. The tie-rod bowing found in SG B is different from that found in SG A inasmuch as while the tie rods in SG A all bend towards the center of SG A, in SG B, the tie-rod bowing is in different directions.

The worst-case tie-rod bowing in SG B is approximately 0.5 inches, while the worst-case tie-rod bowing in SG A is approximately 1.3 inches. When bowing of the tie rods was initially observed in SG A (Le., during the first refueling outage following SG installation), the maximum extent of bowing was 0.9 inches, which is more than the 0.5 inches observed in SG B. The current acceptance criterion for the extent of tie-rod bowing is approximately 1.6 inches (this limit is periodically re-evaluated). Based on thermal cycling fatigue analysis, the tie-rod bowing in SG A is expected to increase for the first 12 thermal cycles, and then the bowing should level out at approximately 2 inches. SG A has currently experienced six thermal cycles. The amount of acceptable bowing in the SGs is calculated from a low-cycle fatigue analysiS. Some of the bowing in the upper spans of SG A was slightly higher than predicted by the modeling, but still met the acceptance criteria. The bowing in the upper span is in the shape of an "S." As a result of the tie-rod bowing, the licensee decided to stabilize and plug several tubes.

Enclosure

-2 The direction that the tie rod bows appears to be a function of (1) which TSPs are no longer free to move and (2) the locations around the SG circumference where the TSPs are locked. The licensee is continuing to analyze exactly how these two mechanisms influence bowing of the tie rods. The licensee has concluded that bowing occurs in the cold condition (i.e., when the plant is shut down) because no wear indications due to tube-to-tube (or tie-rod) contact have been found on the tubes affected by the bowed tie rods.

The acceptance criteria for the extent of allowable tie-rod bowing is updated every outage. The rate of increase in the amounVextent of bowing in SG A has slowed down. The most limiting consideration is the fatigue of the tie rods (lateral bow verses number of thermal cycles). Tie rod bowing is occurring in the 1st, 10th, 14th, and 15th spans in SG B and in the 1st, 2nd, and 13th through 15th spans in SG A. The magnitude of bowing in the spans 2 and higher spans is relatively small.

The licensee stated it found some small dents (approximately 0.3 volts) at TSP 1 in SG A.

These dents are near the tie rods experiencing the largest amount of bowing. Two in-service tubes that are next to the tie rod with the largest deflection (maximum amount of bowing) had four surface indications that the licensee described as "wrinkles." However, there was no wall loss associated with these indications. These same two tubes had dents and bulges. The bulges were at the tube-to-tubesheet interface on the secondary side of the SG. The licensee stated that both tubes were stabilized and plugged during this outage.

The licensee found approximately 300 new-wear indications on the tubes at the TSP elevations this outage. All of the new-wear indications were relatively small and the new 95th percentile bounding growth rate is lower than the 95th percentile growth rate calculated during the last inspection outage. Approximately seven tubes were plugged this outage for wear at TSPs. The licensee plugged all tubes with wear greater than or equal to 35 percent of the wall thickness.

While the NRC staff did not identify any issues that warranted follow-up action at this time, the NRC staff asked to be notified in the event that any in-situ pressure testing was performed or if any unusual conditions were detected during the remainder of the outage.

Conference call held on November 8, 2011 On November 8, 2011, the NRC staff participated in a follow-up call with the licensee. Entergy informed the NRC staff that the SG tube bobbin coil inspections at Three Mile Island Nuclear Station, Unit 1 (TMI), had detected absolute drift indications (ADI) between the 8th and 9th TSPs. Further examination with a +PoinFM probe and an X-probe confirmed the indications as tapered wear scars that ranged from 4-9 inches long. The wear scars were attributed to tube to-tube contact. The TMI staff informed the ANO-1 staff of the tube-to-tube wear findings because the two nuclear plants have the same model SGs.

Based on the TMI findings, the ANO-1 staff reviewed its inspection records and determined that there were three areas in SG A with ADls (paired or triplet ADls) similar to those observed at TMI. All of these ADls were approximately 17 inches above the 8th TSP. One of these areas of ADls affected three tubes, and the other two areas affected two tubes each. In SG B, there were two areas of paired ADls (both areas affected two tubes).

- 3 The licensee had identified these ADls in previous outages (e.g., the first inservice inspection of the SGs). When the ADls were detected with a bobbin probe, they were inspected with an X-probe, but they were classified as "no degradation found." There is no recent X-probe data for these ADls. Based on the TMI findings and a review of the bobbin voltages, the licensee concluded that these ADls were tapered wear scars with the deepest indication estimated to be 28 percent through-wall (TW). At the time of the call, the licensee did not have the voltages for these indications as a function of outage (Le., to assess the progression of these indications with time).

Given the TMI findings, Entergy has decided to send its eddy current data to AREVA to re-evaluate the data for ADls with an automated eddy current analysis software package referred to as AIDA. AREVA thinks that more ADls will be identified as a result of this data re-evaJuation. Prior to the re-evaluation, the licensee had identified approximately 18 ADls in SG A and 9 in SG B. The data re-evaluation is scheduled to be completed by the close-of business on November 9, 2011.

The TMllicensee has a voltage versus depth correlation that is used to size the indications.

The largest indication at ANO-1 has a bobbin voltage amplitude of 1.2 volts, which is consistent with the largest voltage amplitude at TMI.

During the conference call, the NRC staff asked Entergy several questions, including (1) whether the eddy current calibration at TMI and ANO-1 were similar (to ensure the voltage measurements were comparable between the two sites), (2) how many of the ADls were called by the primary analyst, secondary analyst, or both, and (3) the history associated with these ADls including how they were dispositioned. Given that these findings were relatively recent, the licensee did not have sufficient information to provide definitive answers.

Industry personnel on the conference call indicated that the industry's Steam Generator Management Program was issuing a letter to all domestic pressurized-water reactor owners of the findings at TMI.

Conference call held on November 10, 2011 On November 10,2011, a follow-up conference call was held with Entergy to discuss the results of its data re-evaluation with the AIDA software. At the time of the call, the data re-evaluation was complete. Approximately 53 tubes in SG A and 74 tubes in SG B were identified as having ADls. The largest indication in SG A, assuming it was a tapered wear scar, measured 18 percent TW. The largest indication in SG B measured 26 percent TW. The average depth of these ADls (wear scars) was 10 percent TW.

In SG A, most of the ADls were new (Le., just present in the 2011 outage data) or have only been present in the last two outages. In SG B, however, most of the ADls were traceable to the first inservice inspection. In addition, most of these ADls had wear indications at the TSPs.

Almost all of the ADls are in the 8th span, a few in the 9th span, and one ADI in the 6th span.

Similar to TMI, the wear scars associated with these ADls are located in a donut shape on a tubesheet map. Most ADls (wear scars) are approximately 20 tubes into the tube bundle from the periphery, and the pattern of ADls (wear scars) is similar to the wear at the 8th TSP.

-4 The tubes at ANO-1 and TMI are in compression during operation. Based on. the analysis to date, it appears that the typical wear scars form and approach a depth of 8-10 percent TW and then stay at this level with little change.

The eddy current calibrations at TMI and ANO-1 are identical except for the voltage level for one of the frequencies. The 95th percentile growth rate for these ADls (wear scars) is approximately 4 percent per effective full power year. As a result, no plugging of these indications was deemed necessary by the licensee. Given these growth rates, the licensee believes that these indications could remain inservice for at least three cycles without re-inspection (but that the next inspection may be controlled by the tie-rod bowing issue rather than the ADI (wear scar) issue).

No tube proximity signals were identified during the data review. None of the ADls (wear scars) are associated with the tie rods that are bowed. The length of the ADls (wear scars) is not known, but it was assumed that they were 9 inches long in the structural integrity assessments for these indications.

The number of ADls identified during the data re-review was approximately three times the number of ADls initially identified. As a result, AREVA initiated a condition report to determine the apparent cause for the increase in the number of ADls. The results should be complete in approximately 30 days. It was speculated that since these ADls were believed to be non-flaw like, the analysts were not reporting them. In addition, the increase in ADls may be attributed to using a lower voltage threshold for reporting them. Many of the ADls are not paired.

The NRC staff indicated that it might be interested in reviewing some of the eddy current data associated with these ADls. The NRC staff is evaluating the need for further discussion on this issue.

Principal Contributor: A Johnson

ML12276A301 *via memo OFFICE NRRlDORULPL4/PM NRRlDORULPL4/LA NRRlDE/ESGB/BC (A) NRRlDORULPL4/BC NRRlDORULPL4/PM NAME NKalyanam JBurkhardt VCusumano PKlein for' MMarkley NKalyanam DATE 10/12/12 10/4/12 12/7/11 10/12/12 10/12/12