ML102371214

Riverkeeper Opposition to Entergy'S Motion for Summary Disposition of Riverkeeper Technical Contention 2 (Flow-Accelerated Corrosion)

ML102371214
Person / Time
Site:	Indian Point
Issue date:	08/16/2010
From:	Brancato D Riverkeeper
To:	Atomic Safety and Licensing Board Panel
SECY RAS
References
50-247-LR, 50-286-LR, RAS E-388, RAS E-389, & RAS E-390
Download: ML102371214 (144)

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UNITED STATES OF AMERICA NUCLEAR REGULATORY COMMISSION ATOMIC SAFETY AND LICENSING BOARD

))

In the Matter of

)

Entergy Nuclear Operations, Inc.

(Indian Point )) Docket Nos.

Nuclear Generating 50-247-LR Units 2 and 3) ) and 50-286-LR RIVERKEEPER OPPOSITION TO ENTERGY'S MOTION FOR

SUMMARY

DISPOSITION OF RIVERKEEPER TECHNICAL CONTENTION 2 (FLOW-ACCELERATED CORROSION)

August 16, 2010 DOCKETED USNRC August 17, 2010 (8:30a.m.)

OFFICE OF SECRETARY RULEMAKINGS AND ADJUDICATIONS STAFF 7A'74Lfv7-e-- ý-YCýo3

TABLE OF CONTENTS BA CK G R OU ND .............................................................. 1 STANDARD OF REVIEW ..................................................... 2 ARGUMENT................................ .......................... 4 POINT I: GENUINE MATERIAL FACTS ARE IN DISPUTE CONCERNING ENTERGY'S RELIANCE ON CHECWORKS.. ... ........... 4 A. The CHECWORKS Computer Code Lacks Adequate Benchmarking to Assure Reliable PredictiveResults Under Post- Stretch Power Uprate

("SPU") Operating Conditions at Indian Point During the Period of Extended Operation ...................... .......... 4 B. CHECWORKS Patently Lacks a "Track Record of Performance" at the Uprated Power Levels at Indian Point ................................... 11 C. Entergy's FAC Program Relies Largely on the CHECWORKS Computer C ode...... ........................................................ 12 POINT I1: GENUINE MATERIAL FACTS ARE IN DISPUTE CONCERNING THE SUFFICIENCY OF THE FAC PROGRAM AT INDIAN POINT.. 16 A. Entergy's FAC Program Fails to Adequately Address all Required .

Elements Identified in the GALL Report and SRP-LR..................16 B. Entergy's FAC Program Lacks Sufficient Detail to Demonstrate that Relevant Components will be Adequately Inspected and Maintained During the Period of Extended Operation ........................... 17 CO N C L U SIO N .......................... .................................... 18

LIST OF ATTACHMENTS Attachment Description 1 Riverkeeper Counter-Statement of Material Facts 2 Declaration of Dr. Joram Hopenfeld 3 Curriculum Vitae of Dr. Joram Hopenfeld 4 Excerpt from Entergy Operating Experience Review Report, Engineering Report No. IP-RPT-06-LRDO5, Rev. 1 (June 2007) 5 Entergy FAC related Condition Reports: CR-IP2-2001-10525; CR-IP3-2006-02270 6 Excerpt of Transcript of Meeting of Advisory Committee on Reactor Safeguards (Sept. 10,2009) 7 Graphs excerpted from Entergy CHECWORKS Modeling Reports, internal index included 8 Excerpt from Indian Point Unit 2 CHECWORKS FAC Model, Calculation No. 050714b-01, Rev. 1 (Sept. 12, 2006)

August 16, 2010 UNITED STATES OF AMERICA NUCLEAR REGULATORY COMMISSION ATOMIC SAFETY AND LICENSING BOARD

)

In the Matter of )

)

Entergy Nuclear Operations, Inc. ) Docket Nos.

(Indian Point Nuclear Generating 50-247-LR Units 2 and 3) ) and 50-286-LR RIVERKEEPER OPPOSITION TO ENTERGY'S MOTION FOR

SUMMARY

DISPOSITION OF RIVERKEEPER TECHNICAL CONTENTION 2 (FLOW-ACCELERATED CORROSION)

Pursuant to 10 C.F.R. § 2.1205(b) and the Atomic Safety and Licensing Board's

("ASLB") Scheduling Order dated July 1, 2010,1 Riverkeeper, Inc. ("Riverkeeper") hereby submits this answer in opposition to Entergy Nuclear Operations, Inc.'s ("Entergy") Motion for Summary Disposition of Riverkeeper Technical Contention 2 (Flow-Accelerated Corrosion).

For the reasons set forth below, summary disposition is inappropriate and Entergy's motion must be denied. Riverkeeper's answer in opposition to the instant motion is supported by the attached Counter-Statement of Material Facts (Attachment 1), the Declaration of Dr. Joram Hopenfeld (Attachment 2), and numerous other supporting attachments (Attachments 3-8).

BACKGROUND The instant proceeding stems from the license renewal application Entergy filed with the Nuclear Regulatory Commission ("NRC") in April 2007 seeking to extend the operating licenses of Indian Point Units 2 & 3 for an additional 20 years. On November 30, 2007, Riverkeeper filed a Request for Hearing and Petition to Intervene in the proceeding, asserting, inter alia, a See Entergy Nuclear Operations, Inc. (Indian Point Nuclear Generating Units 2 and 3), Docket Nos. 50-0247-LR and 50-286-LR, ASLBP No. 07-858-03-LR-BD01, Scheduling Order (July 1, 2010) atl 1, ADAMS Accession No. ML101820387.

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technical safety contention, RK-TC-2, challenging the sufficiency of Entergy's plan to adequately manage an aging phenomenon known as "flow accelerated corrosion" (hereinafter "FAC"). 2 The ASLB's ruling on contention admissibility dated July 31, 2008, admitted RK-TC-3 2 for an adjudicatory hearing.

The ASLB determined that RK-TC-2 raised material "questions regarding the sufficiency of Entergy's AMP to demonstrate that a specific class of components subject to FAC will be managed so that their intended functions will be maintained during the period of extended operations." 4 In particular, as characterized by the ASLB, RK-TC-2, contends that (1) Entergy's AMP for components affected by FAC is deficient because it does not provide sufficient details (e.g.,

inspection method and frequency, criteria for component repair or replacement) to demonstrate that the intended functions of the applicable components will be maintained during the extended period of operation; and (2) Entergy's program relies on the results from CHECWORKS without benchmarking5 or a track record of performance at IPEC's power uprate levels.

Entergy's has now made a motion to summarily dismiss RK-TC-2 claiming that no genuine dispute of material fact exists to litigate. The following amply demonstrates that numerous factual issues remain, warranting complete dismissal of the instant motion.

STANDARD OF REVIEW The regulations at 10 C.F.R. § 2.1205 governmsummary disposition motions and direct 6

Licensing Boards to "apply the standards for summary disposition set forth in Subpart G.',

2 See Riverkeeper, Inc.'s Request for Hearing and Petition to Intervene in Indian Point License Renewal Proceeding (November 30, 2007), at 15-23, ADAMS Accession No. ML073410093.

3 Entergy Nuclear Operations, Inc. (Indian Point Nuclear Generating Units 2 and 3), Docket Nos. 50-247-LR, 50-286-LR, ASLBP No. 07-858-03-LR-BD01, LBP-08-13, Memorandum and Order (Ruling on Petitions to Intervene and Requests for Hearing (July 31, 2008), ADAMS Accession No. ML082130436, at 162-69 (hereinafter "ASLB Contention Admissibility Order").

4 ASLB Contention Admissibility Order, -supranote 3, at 167.

5Id. at 169. The power uprates at occurred at Indian Point Unit 2 and Unit 3 in 2004 and 2005, respectively. See id at 167.

6 10 C.F.R. § 2.1205(c).

2

Under Subpart G, summary disposition is appropriate if the filings in the proceedings, statements of the parties and affidavits, if any, "show that there is no genuine issue as to any material fact and that the moving party is entitled to a decision as a matter of law." 7 In a motion. for summary disposition, the moving party bears the burden to demonstrate the absence of a genuine issue as to any material fact. 8 Any doubt as to the existence of a genuine issue of material fact is resolved against the moving party. 9 "Because the burden is on the moving party, the Board must examine the record in the light most favorable to the non-moving party and give the non-moving party the benefit of all favorable inferences that can be drawn from the evidence."'1 A party opposing a motion for summary disposition need not show a likelihood of success on the merits, but rather, only that there is a genuine .issue of fact to be evaluated at the evidentiary hearing. 11 Indeed, summary disposition "is not a tool for*trying to convince a Licensing Board to decide, on written submissions, genuine issues of material fact that warrant resolution at a hearing."'12 As the Commission recently elaborated upon, "a licensing board (or presiding officer) should not.., conduct a 'trial on affidavits.' At this stage, 'the judge's function is not himself to weigh the evidence and determine the truth of the matter but to 7Id. § 2.710(d)(2).

8 Id. § 2.325; AdvancedMed Sys., Inc. (One Factory Row, Geneva, Ohio, 44041), CLI-93-22, 38 NRC 98, 102 (1993); Entergy Nuclear Vermont Yankee LLC (Vermont Yankee Nuclear Power Station), LBP-06-5, 63 NRC 116, 121 (2006) (quoting PrivateFuel Storage, LLC (Independent Spent Fuel Storage Installation), LBP-01-39, 54 NRC 497 (2001).

9 Entergy Nuclear Vermont Yankee LLC (Vermont Yankee Nuclear Power Station), LBP-06-5, 63 NRC 116, 121 (2006) (citing Advanced Med. Sys., Inc. (One Factory Row, Geneva, Ohio, 44041), CLI-93-22, 38 NRC 98, 102 (1993)).

1oId.

1 Advanced Med Sys., Inc. (One Factory Row, Geneva, Ohio, 44041), CLI-93-22, 38 NRC 98, 102 (1993) 12 Entergy Nuclear Vermont Yankee LLC (Vermont Yankee Nuclear Power Station), LBP-06-5, 63 NRC 116, 121 (2006) (quoting PrivateFuel Storage, L.L.C. (Independent Spent Fuel Storage Installation), LBP-01-39, 54 N.R.C.

497, 509 (2001)).

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determine whether there is a genuine issue for [hearing].' 13 Accordingly, "[i]f 'reasonable minds 14 could differ as to the import of the evidence,' summary disposition is not appropriate."'

As the ASLB has already recognized in this proceeding, when conflicting expert opinions are involved, summary disposition is unsuitable.' 5 Indeed, "competing expert opinions present the 'classic battle of the experts' and it [is] up to [the finder of fact] to evaluate what weight and credibility each expert opinion deserves."' 16 At the summary disposition stage, "[r]egardless of the level of the dispute. . . it is not proper for a Board" to choose which expert has the better of the argument. 17 ARGUMENT POINT I: GENUINE MATERIAL FACTS ARE IN DISPUTE CONCERNING ENTERGY'S RELIANCE ON CHECWORKS A. The CHECWORKS Computer Code Lacks Adequate Benchmarking to Assure Reliable Predictive Results Under Post-Stretch Power Uprate ("SPU") Operating Conditions at Indian Point During the Period of Extended Operation A genuine dispute exists concerning whether CHECWORKS is adequately benchmarked so as to assure reliable predictive results under post power uprate conditions at Indian Point during the period of extended operation.18 Notwithstanding Entergy's various claims that the CHECWORKS model can handle a wide range of operating parameters and that the model has been appropriately "updated" with changed plant parameters as well as actual measured wear 13Entergy Nuclear Generation Co. and Entergy Nuclear Operations, Inc. (Pilgrim Nuclear Power Station), CLI 11, 4

71 NRC ,__ (slip op. at 13) (Mar. 26, 2010).

1 1d.

isLicensing Board Memorandum and Order (Ruling on Motions for Summary Disposition) ýNov. 3, 2009), at 1-2, ADAMS Accession No. ML093070521.

16 See Entergy Nuclear Vermont Yankee LLC (Vermont Yankee Nuclear Power Station), LBP-06-5, 63 NRC 116, 121 17 (2006) (citing Phillips v. Cohen, 400 F.3d 388, 399 (6th Cir. 2005)).

Entergy Nuclear Vermont Yankee LLC (Vermont Yankee Nuclear Power Station), LBP-06-5, 63 NRC 116, 121 (2006) (citing Private Fuel Storage, L.L.C. (Independent Spent Fuel Storage Installation), LBP-0.1 -39, 54 NRC 497, 510 (2001)).

18 ASLB Contention Admissibility Order, supra note 3, at 167 (ASLB finding that "Riverkeeper has presented sufficient facts and expert opinion to raise a genuine dispute regarding a material. issue").

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rates, the actual performance of CHECWORKS demonstrates that it is not a reliable tool for predicting wall thinning at Indian Point.

CHECWORKS modeling reports generated on behalf of Entergy subsequent to the power uprates reveal that CH-ECWORKS predictions of wall thinning are highly unreliable. Graphs plotting CHECWORKS predictions of wall thickness versus actual measurements for selected plant components, for at least seven different outages at Units 2 and 3 after the power uprates, show an unacceptably large margin of error in CHECWORKS predictions. 19 The wide scatter of data points on such graphs, examples of which are appended hereto as Attachment 7, show that CHECWORKS predictions are far from accurate. 20 Indeed, one could draw almost any line through the data on such graphs, indicating a complete lack of correlation. 21 A straight line parallel to the abscissa would indicate that actual plant observations and computer model predictions are independent of each other.22 Arbitrary lines are drawn on these graphs to show that some, but not all of the data, can be bound with +/- a factor of two. 23 In fact, a review of such graphs shows that predictions can deviate by as much as factor of +/- 10.24 Accordingly CHECWORKS can either under-predict or over-predict FAC by 1000%.

It is, thus, apparent that the CHECWORKS model employed at Indian Point cannot predict FAC to any degree of accuracy. 25 A margin of error high as +/- 1000% exhibited by a significant number of components, is not a demonstration of precise and accurate results, as Entergy asserts. 2 6 On the contrary, CHECWORKS can only predict an overall range of

'9 See Hopenfeld Declaration (Attach. 2), ¶¶ 12-14; Attach. 7.

20 See Hopenfeld Declaration (Attach. 2), ¶ 13; Attach. 7.

21 See Hopenfeld Declaration (Attach. 2), ¶T 13, 17; Attach. 7.

22 See Hopenfeld Declaration.(Attach. 2), ¶ 13; Attach. 7.

23 See Hopenfeld Declaration (Attach. 2), ¶ 13; Attach. 7.

24 See Hopenfeld Declaration (Attach. 2), ¶ 13; Attach. 7.

25 See Hopenfeld Declaration (Attach. 2), ¶ 14.

26 See id.

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corrosion rates for a given a component or a group of components. 27 This range is too wide for practical applications, especially when the consequences of component failure are safety related.28 As such, Entergy's apparent position that the level of correlation between the CHECWORKS model predicted wear and the measured wear following implementation of the stretch power uprates at Indian Point is acceptable, is untenable.29 Such conclusions are further bolstered by Entergy's arbitrary reliance on a "line 30 correction factor" to "compare and adjust CHECWORKS predictions to match inspection data.

As Entergy documentation explains, "[t]he LCF indicates the degree to which CHECWORKS over or under-predicts wear. A reasonable LCF should be between 0.5 and 2.5.31 Entergy's own documentation reveals numerous instances where the LCF was outside of this range, indicating that CHECWORKS is unreasonably failing to predict wear rates.32 Moreov'er, Entergy has provided no justification to support the conclusion that the LCF range of 0.5 to 2.5 is acceptable, or, in particular, how this LCF range would be an indication that CHECWORKS can be used to accurately predict inspection locations. 33 Furthermore, Entergy has failed to show how "adjusting" CHECWORKS predictions using an LCF has made, or will make, the model more accurate, as claimed, since years of modeling reports show consistently inaccurate results, 34 as discussed above.

Based on the foregoing, Riverkeeper disputes Entergy's claim that CHECWORKS is "a viable and effective tool for selecting and prioritizing IPEC piping and piping component 27 See id ¶ 12.

28 See id 29 See id. 17. Notably, Entergy's experts say that the level of correlation meets their "expectations" without defining what that means. This only serves as further doubt that CHECWORKS results are acceptable, since subjective 30 "expectations" do not necessarily correspond to an acceptable level of performance.

See Entergy Motion for Summary Disposition, Attach. 2 at ¶ 48.

.31 See Attach. 8; see also Entergy Motion for Summary Disposition, Attach. 9 at 4-1.

32 See, e.g., Attach. 7, Figures 12-15, 17-18.

33 See Hopenfeld Declaration (Attach. 2), ¶¶ 15-16.

34 See id. 77 12-14.

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35 locations for inspection to detect and mitigate FAC during the period of extended operation."

This raises a material and genuine issue of fact regarding whether the CHECWORKS model is adequately calibrated or benchmarked at Indian Point to assure reliable predictions during the period of extended operation.36 Entergy attempts to argue that findings of a different Atomic Safety and Licensing Board in the Vermont Yankee license renewal proceeding ("VY ASLB") should be dispositive in the instant proceeding. 37 Generally speaking, the conclusions of the VY ASLB are specific to the continued operation of VY and, therefore, cannot be generically applied in the instant proceeding. No where did the VY ASLB state that their conclusions were universal. In~fact, that board's decision referenced the role of plant specific inputs and data in the FAC program at VY numerous times, leaving no doubt that the conclusions reached by the VY ASLB are restricted to 38 the VY plant.

Notwithstanding the obvious inappropriateness of relying upon the findings of a licensing board in a wholly separate and distinct proceeding, Entergy points to the VY ASLB's finding that 10 to 15 years of additional benchmarking of the CHECWORKS model at VY was not necessary because Entergy would have three sets of data at the uprated power levels before that -

plant entered into its period of extended operation.3 9 However, in coming to this conclusion, the VY ASLB did not have the benefit of any data for the VY plant at the uprated power levels. The 35 See Entergy Motion for Summary Disposition, Att. 2 at 28-29; Hopenfeld Declaration (Attach. 2), ¶ 8.

36 The ASLB has already recognized that "neither Entergy nor the NRC Staff [] provided any support for the claim that the inspection data that will be collected during refueling outages prior to the license renewal period will be sufficient to benchmark the model." ASLB Contention Admissibility Order, supra note 3 at 168. Entergy now attempts to claim that no factual dispute exists, but still has no support to demonstrate that CHECWORKS is adequately benchmarked. In light of the substantial evidence presented herein questioning the accuracy of the model, it is patently obvious that a material factual dispute remains.

37 See Entergy Motion for Summary Disposition at 20-21.

38 See Entergy Nuclear Vermont Yankee (Vermont Yankee Nuclear Power Station), LBP-08-25, 68 NRC 763, 871-72 (Nov. 24, 2008) ("To address the adequacy of Entergy's FAC AMP, we [the VY ASLB] reviewed.. . Entergy's updates to CHECWORKS with plant-specific data").

39 See Entergy Motion for Summary Disposition at 20.

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circumstances present in the instant proceeding are clearly different: three sets of data at power uprate levels for IP3, and four sets of data at power uprate levels for IP2 have already been collected, and, as discussed above, clearly demonstrate that the CHECWORKS model is not sufficiently benchmarked to account for the new plant conditions. 40 This necessarily renders the conclusions of the VY ASLB regarding the benchmarking of CHECWORKS inapplicable in the instant proceeding.41 In coming to the conclusion that 10 to 15 years of benchmarking of CHECWORKS was not necessary at VY, the VY ASLB further reasoned that "data collected at VYNPS since 1989" had assisted in calibrating the model.42 To the contrary, in the instant proceeding, Entergy maintains that data and CHECWORKS modeling at Indian Point prior to the power uprates of 2004 and 2005 are irrelevant, as evidenced by their position in response to Riverkeeper's Motion to Compel disclosure of such information. 43 Entergy has refused to provide any CHECWORKS related information dating prior to 2000 for IP2 and 2001 for IP3.44 Such information would be necessary in order to assess the adequacy of benchmarking/calibration of the CHECWORKS model and/or its predecessor codes since the owners of the plants started using it (ostensibly since the 1980s). In light of Entergy's unwillingness to admit the relevancy of, or provide such information, Entergy certainly cannot rely upon an assertion that the CHECWORKS model at Indian Point has been calibrated with decades of data, as the VY ASLB found in the VY license renewal proceeding.

40 See Hopenfeld Declaration (Attach. 2), ¶ 29.

41 See id.

42 Entergy Nuclear Vermont Yankee (Vermont Yankee Nuclear Power Station), LBP-08-25, 68 NRC 763, 894 (Nov.

24, 2008).

43 See Entergy's Answer to Riverkeeper's Motion to Compel Disclosure of Documents (Aug. 13, 2010), at 4-5 (Explaining Entergy's objection "to Riverkeeper's request for additional CHECWORKS documents related to modeling for IP2 prior to outage 2R16 (2004) and for IP3 prior to outage 3R13 (2005) as not relevant to the admitted contention and beyond the scope of this proceeding .... FAC reports prepared prior to 1999 are not relevant to the admitted contention.").

44 id.

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Entergy further argues that the power uprates that occurred at Indian Point are bounded by the larger power uprate that occurred at VY, somehow rendering the CHECWORKS model automatically benchmarked for Indian Point plant specific conditions. Such reasoning is utterly, misplaced. To begin with, in the VY proceeding, Entergy did not demonstrate that the CHECWORKS model had adequately -accounted for changed plant conditions from the 20%

power uprate; rather the VY ASLB, in part, deferred to future inspection data which it assumed would calibrate the CHECWORKS model sufficiently prior to the period of extended operation. Thus, the magnitude of the power uprate at VY should have no bearing on the instant proceeding whatsoever.

In any event, CHECWORKS must be evaluated at each plant separately to account for the unique differences in changed plant conditions, including materials, local flow velocities, temperatures, and water chemistry. 46 Notably, Indian Point is a much larger facility than VY, and the impact of a power uprate on plant conditions is necessarily relative to the size of the particular plant. 47 Indian Point is also a different kind of reactor than VY, i.e., a pressurized water reactor and not a boiling water reactor, the former of which are known to be significantly more prone to failures from wall thinning due to FAC than the latter.48 Thus, simply because the percent change in power increase at VY was larger than the uprate that occurred at Indian Point does not mean that the impacts on plant conditions would be bounded by what took place at VY 45 See Entergy Nuclear Vermont Yankee (Vermont Yankee Nuclear Power Station), LBP-08-25, 68 NRC 763, 894 (Nov. 24, 2008); see also Hopenfeld Declaration (Attach. 2), ¶ 29 ("[T]he VY ASLB did not have the benefit of any data-to assess the ability of CHECWORKS to accurately detect wall thinning in light of changed plant operating conditions).

46 See Hopenfeld Declaration (Attach. 2), ¶ 28.

47 See id. ¶ 27.*

41 See id (citing See e.g., Entergy Motion for Summary Disposition, Attach. 15 at 5.25).

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or that the VY power uprate would automatically account for all changed conditions at Indian 49 Point.

Moreover, accessibility for inspections, past history with respect to the number of components and frequency of wall measurements that were used in the calibration of CHEC WORKS, the quality of the correlation of predictions with measurements, and the number of component failures from wall thinning, will necessarily vary depending on the facility, further warranting an individual assessment of the use of CHECWORKS at Indian Point. 50 Indeed, Entergy produces Indian Point specific CHECWORKS modeling reports, which Entergy repeatedly touts use actual inspection data gathered at the plant and which account for plant specific conditions, such as new conditions due to replaced components. Entergy relies on these plant specific reports for its conclusion that CHECWORKS is an appropriate tool to be used as part of the FAC program at Indian Point. It is, therefore, counterintuitive and downright contradictory to assert that a generic assessment of CHECWORKS, without regard for how it is implemented at a specific plant, is appropriate.

Based on the foregoing, it would be incorrect for the ASLB in this proceeding to simply defer to the findings of a licensing'board relating to a plant specific determination at VY, especially in light of the clearly inadequate benchmarking of the CHECWORKS code at Indian Point, as discussed herein.

49 Thus, the ASLB's questioning of what percent change in plant operating parameters would have a material effect on CHECWORKS results, when it ruled on the admissibility of Riverkeeper Contention TC-2 was completely appropriate. See ASLB Contention Admissibility Order, supra note 3 at 168. Entergy cannot simply dismiss this inquiry, saying that it is not necessary to answer this question because the Indian Point power uprate is bounded by the uprate at VY. See Entergy Motion for Summary Disposition at 21.

50 See Hopenfeld Declaration (Attach. 2), ¶ 28.

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B. CHECWORKS Patently Lacks a "Track Record of Performance" at the Uprated Power Levels at Indian Point A genuine dispute exists-concerning whether Entergy has established that CHECWORKS has a "track record of performance at IPEC's power uprate levels," as characterized by the ASLB.51 Establishing such a track record is essential since CHECWORKS is entirely based on empirical modeling, meaning that it is solely based on a collection of selective data which represents only a fraction of the total flow area. 52 As such, CHECWORKS requires considerable benchmarking to be used as a reliable predictive tool. 53 Thus, a demonstrated record of performance is necessary to be sure that the model is sufficiently calibrated or benchmarked so as to be an effective predictive tool.

Entergy's claim that "CHECWORKS has a demonstrated record of successfully predicting wall thinning -at IPEC and other nuclear power plants" is completely unfounded. As the discussion in the foregoing section clearly demonstrates, CHECWORKS results have been highly unreliable at Indian Point since plant conditions changed after the power uprates. 54 This alone undeniably establishes a dispute of fact regarding the track record of CHECWORKS results at Indian Point.

Additionally, various instances of wall thinning and leaking components at nuclear power plants suggests that, generally speaking, the success of CHECWORKS at detecting FAC related wall thinning has been questionable.55 At Indian Point in particular, numerous leaks and reports of excessive wall thinning in mechanical systems tend to indicate that CHECWORKS has not been successful at preventing FAC related occurrences. For example, Entergy's 2007 Operating 5' ASLB Contention Admissibility Order, supra note 3, at 169.

52 See Hopenfeld Declaration (Attach. 2), ¶ 9.

" See id. ¶ 8.

14 See id. ¶¶ 12-18.

55

.See id. ¶ 11.

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Experience Review Report documents many unacceptable wall thinning events and pipe leaks which occurred between 2001 and 2005.56 Entergy condition reports document occurrences of leaks from components that resulted from undetected FAC, where subsequent inspections revealed wall thickness measurements that were-below acceptable levels. 7 The NRC Staff in this license renewal proceeding has also questioned Entergy regarding incidences of

-unacceptable wall thinning. 58 Considering that typically, wall thinning rates in pressurized water reactors range from 5 to 50 mills per year, and the wall thickness of the components ranges between 300 to 1000 mills, one would expect that more and more components would become prone to failures after 40 years of service, i.e., during the proposed period of extended 59 operation.

Entergy further implies that the implementation and use of CHECWORKS has resulted in no fatalities and no "major FAC-caused pipe ruptures in a U.S. nuclear unit for more than 10 years." 60 However, this information by itself is purely circumstantial, and cannot lead one to conclude that CHECWORKS had been a success. It is, thus, far from clear that CHECWORKS has been successful at predicting FAC at Indian Point. The foregoing undoubtedly demonstrates that a material and genuine issue of a fact regarding whether CHECWORKS has an adequate "track record of performance."

C. Entergy's FAC Program Relies Largely on the CHECWORKS Computer Code A genuine dispute exists concerning Entergy's assertion that the FAC program at Indian Point will be effective in managing FAC-related aging effects because "CHECWORKS is only one of several, bases used by Entergy to select and schedule in-scope components for 56 See Hopenfeld Declaration (Attach. 2), ¶ 11; See Attach. 4.

51 See Hopenfeld Declaration (Attach. 2), ¶ 11; See Attach. 5.

51 See Hopenfeld Declaration (Attach. 2), ¶ 11; See Attach. 6.

59 See Hopenfeld Declaration (Attach. 2), ¶ 13.

60 See Entergy Motion for Summary Disposition at 23.

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inspection." 61 In particular, Entergy maintains that assuming Riverkeeper is correct that CHECWORKS is an ineffective tool for predicting FAC, the FAC program at Indian Point would still be effective, since inspection scope is also based on (1) actual pipe wall thickness measurements from past outages, (2) industry experience related to FAC, (3) results from other plant inspection programs, and (4) engineering judgment.62 Riverkeeper wholly disagrees that Entergy's identification of these "additional" tools for inspection scope selection demonstrates 63 the effectiveness of Entergy's FAC aging management program.

Riverkeeper disputes Entergy's assertion that these additional criteria can be viewed as independent tools sufficient to establish an accurate FAC inspection scope.. A close examination reveals that these additional criteria largely depend upon the use of CHECWORKS. For example, actual pipe wall thickness measurements from past outages are only useful when used in combination with a predictive tool which would prevent the wall thickness of a given 64 component from being reduced to below the minimum design thickness while in service.

Accordingly, this is a required input for the use of CHECWORKS and not a stand-alone "tool" for component selection.65 Moreover, for components initially selected for inspection by CHECWORKS, any decisions regarding future inspection scope based on actual pipe wall thickness measurements and wear ratetrending of the actual inspection results, necessarily depends upon use of the CHECWORKS computer model. 66 Likewise, knowledge of pipe wall thinning events, changed plant parameters, etc., at Indian Point and other plants (i.e., industry and plant experience) are also types of information that feed into the CHECWORKS model.67 61 Id. at 17.

62 See id. at 17; Entergy's Motion for Summary Disposition, Attach. 2, ¶¶ 39.

63 See Hopenfeld Declaration (Attach. 2), ¶ 19.

64See 65 id. ¶ 20.

See id.

66 See id.

67 See id. ¶ 21.

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Thus, the usefulness of such information in determining future inspections rests in part on how the CHECWORKS model processes the inputs.

To the extent actual pipe wall thickness, plant and industry experience do not rely upon CHECWORKS in order to meaningfully contribute to inspection scope selection, they can only be properly categorized as inputs which assist in the formulation of an "engineering judgment,"

and not three independent tools. 68 However, Entergy has completely failed to demonstrate that engineering judgment alone will safely manage FAC at Indian Point. Generally speaking, it is commonly recognized in all major industrial plants that engineering judgment alone is not sufficiently reliable to prevent component failures from wall thinning.69 The development of the CHECWORKS computer model itself stemmed from the realization by the nuclear industry that engineering judgment alone wasno longer enough to be able to detect unacceptable and unsafe wall thinning occurrences.70 When engineering judgment is identified as an independent predictive tool, a very high degree of knowledge is required by those who conduct the assessment and specify the required steps for the prevention of component failures. 71 Even with the same input data, different assessments could lead to different results because each assessment would depend heavily on the individual skill and judgment of the responsible engineer. 72 Accordingly, in order to assess the validity of the use of engineering judgment, it is imperative to fully understand how it is used

/

and all relevant underlying assumptions informing any judgment related determinations. 73 To the contrary, Entergy has failed to clearly describe what exactly "engineering judgment" even 68 See id. ¶¶ 20-21; see Entergy Motion for Summary Disposition, Attach. 9 at 2-4 (EPRI guidance document explaining that engineering judgment requires awareness of operating experience, and input from plant operations, and also that "engineering judgment cannot substitute for other factors").

69 See Hopenfeld Declaration (Attach. 2), ¶ 22.

70 See id ¶¶ 9, 22.

71 See id ¶ 23.

.72 See id.

71 See id 14

means in relation to FAC inspections at Indian Point, and what role it actually plays in inspection scope selection.74 Entergy has not identified any kind of systematic methodology which demonstrates that engineering judgment is a separate predictive tool that would adequately manage FAC related component degradation during the period of extended operation.75 It is, thus, apparent that Entergy does not employ any meaningful tools that, separate and apart from CHECWORKS, would sufficiently manage the aging effects of FAC at Indian Point.

Rather, Entergy's program for managing FAC relies heavily on the unreliable CHECWORKS code. This clearly disputes Entergy's assertions to the contrary, raising a material and genuine issue of a fact.

Entergy once again improperly relies upon findings of the VY ASLB in the VY license renewal proceeding to bolster its position here. In particular, Entergy points to the VY ASLB's 76 observation that at VY, CHECWORKS played a limited role in the overall FAC program.

Entergy attempts to demonstrate that CHECWORKS is employed in the same manner as in VY, and that, likewise, it is only one of many tools used to determine locations for FAC inspections.

However, as the above discussion demonstrates, it is disputed whether Entergy has adequately 77 demonstrated any other means by which it meaningfully selects inspection points.

Moreover, it would simply be inappropriate to rely upon the conclusions drawn during a completely separate proceeding, and essentially assume that Entergy implements its FAC program at Indian Point in an effective manner, simply because a different licensing board found it did so at a different facility. The implementation of the FAC program at Indian Point necessarily involves site specific considerations, and, as such, the question of the adequacy of the 74 See id.

" See id 76 Entergy Motion for Summary Disposition at 17-18.

77 See Hopenfeld Declaration (Attach. 2), ¶ 30.

15

FAC program is not conducive to a generic determination. Notably, Entergy's attempt to summarily dispose of this issue in the VY proceeding was unsuccessful, and the VY ASLB only reached a determination after a full adjudicatory hearing. In the instant proceeding, at this stage, Riverkeeper need only establish a dispute of fact, which the foregoing, supported by the expert opinion of Dr. Hopenfeld, amply does.

POINT II: GENUINE MATERIAL-FACTS ARE IN DISPUTE. CONCERNING THE SUFFICIENCY OF THE FAC PROGRAM AT INDIAN POINT A. Entergy's FAC Program Fails to Adequately Address all Required Elements Identified in the GALL Report and SRP-LR A genuine dispute exists concerning whether, in light of the inadequacy of CHECWORKS as a tool for managing FAC at Indian Point during the period of extended operation, Entergy had sufficiently addressed all required elements identified in the SRP-LR. In particular, because Entergy's FAC program relies primarily on a method which does not accurately. detect FAC, i.e., CHECWORKS, and Entergy has not otherwise demonstrated that it employs other methods sufficient to manage the aging effects of FAC at Indian Point, it is necessary for Entergy to provide detailed information regarding the method and frequency of component inspections and attendant criteria for component repair and replacement.

In contrast, Entergy merely states that its FAC program is consistent with the SRP-LR and GALL report guidance documents. 78 However, these generic guidance documents focus on the use of a properly calibrated CHECWORKS model. The GALL Report implies that when one uses computer codes to predict wall thinning, the codes must be properly benchmarked at each plant before they can be used as a management tool to control FAC. 79 Because Entergy has 78 See Entergy Motion for Summary Disposition at 15.

79 See Hopenfeld Declaration (Attach. 2), ¶ 10; Entergy's Motion for Summary Disposition, Attach. 7 at XI M-61, Xl M-62 ("CHECWORKS is acceptable because it provides a bounding analysis for FAC. CHECWORKS was developed and benchmarked by using data obtained from many plants").

16

failed to show that CHECWORKS is properly benchmarked to be an effective tool at Indian Point, as discussed above, Entergy has not been successful in implementing a critical aspect of these documents. 80 Moreover, as discussed above, Entergy has failed to properly define how it 81 employs other tools to adequately address FAC in accordance with such guidance.

Accordingly, Entergy cannot generically claim consistency with these guidance documents, and instead must "provide a reasonably thorough description of its AMP to show conclusively how this program will ensure that the effects of aging will be managed."82 It is, therefore, clear that Entergy's FAC program at Indian Point does not adequately addresses the elements outlined in the SRP-LR and GALL Report.

B. Entergy's FAC Program Lacks Sufficient Detail to Demonstrate that Relevant Components will be Adequately Inspected and Maintained During the Period of Extended Operation Entergy further claims that the FAC program at Indian Point includes sufficient detail "to demonstrate that the intended functions of the applicable components will be maintained during the PEO," because it implements a fleet-wide procedure, EN-DC-315 and EPRI guidance document (NSAC-202L-R3).8 3 Once again, these procedures are focused heavily on the appropriate use of CHECWORKS, and further indicate CHECWORKS should be benchmarked or calibrated.84 Due to the inadequacy of CHECWORKS as a tool for managing FAC at Indian Point,85 it is disputable whether Entergy is actually implementing such guidance.8 6 Thus, instead 80 See Hopenfeld Declaration (Attach. 2), ¶ 25.

81 See id ¶¶ 19-24.

82 Entergy Nuclear Vermont Yankee (Vermont Yankee Nuclear Power Station), LBP-08-25, 68 NRC 763, 870 (Nov.

24, 2008); see id. at 871 ("an applicant... merely stating that its AMP meets NUREG-1801 without any specificity falls short of the required demonstration [of 10 C.F.R. § 54.21], since section XI.M17 of NUREG-1801 consists of less than two pages of narrative evaluating EPRI's guidelines presented in NSAC-202L-R3 with an absence of plant-specific details.").

83 Entergy Motion for Summary Disposition at 16.

84 See Hopenfeld Declaration (Attach. 2), ¶ 25; Entergy Motion for Summary Disposition, Attach. 9, Attach. 11 85 See Hopenfeld Declaration (Attach. 2), ¶¶ 8-18.

17

of simply referring to procedural documents which depend upon the proper use of CHECWORKS, Entergy must provide sufficient details regarding inspection scope, frequency, etc, such that FAC will be adequately managed during the period of extended operation.

Entergy argues that this is a "settled" issue because the VY ASLB found that EN-DC-315 contained sufficient specificity to show that Entergy had implemented the GALL Report guidelines. 87 However, the VY ASLB only found that the relevant guidelines "have been implemented at VYNPS." 8 8 This finding does not have general applicability. Indeed, as Entergy even acknowledges, the VY ASLB reached-this determination only after thoroughly examining the FAC program at VY.89 In contrast, at this stage of the Indian Point license renewal proceeding, Riverkeeper has highlighted numerous deficiencies with Entergy's FAC program to question whether a similar conclusion can be drawn here.

Based on the foregoing, there remains a material issue of factual dispute regarding whether Entergy's program for managing FAC at Indian Point during the period of extended operation contains sufficient specificity to demonstrate that relevant components will be adequately inspected and maintained during the period of extended operation.

CONCLUSION The foregoing demonstrates that significant disputes of fact exist regarding the sufficiency of Entergy's program for managing the aging effects of FAC at Indian Point during the period of extended operation. In particular, Riverkeeper, supported by the expert opinion of 8

6 See Entergy Nuclear Vermont Yankee (Vermont Yankee Nuclear Power Station), LBP-08-25, 68 NRC 763, 870 (Nov. 24, 2008) ("For an applicant to just illustrate how its proposed program will, or promises to, follow the same generic program recommendations provided to all plants does not clear the bar required by the regulations.").

87 Entergy Motion for Summary Disposition at 16-17.

88See Entergy Nuclear Vermont Yankee (Vermont Yankee Nuclear Power Station), LBP-08-25, 68 NRC 763, 871 (Nov. 24, 2008) (emphasis added).

89 Entergy Motion for Summary Disposition at 16.

18

Dr. Joram Hopenfeld, has raised the following issues, which directly controvert Entergy's position that the aging management program to address FAC at Indian Point is adequate:

" Entergy's failure to demonstrate that CHECWORKS is adequately benchmarked so as to be an effective tool for predicting FAC at Indian Point during an extended period of operation;

" Entergy's failure to demonstrate that CHECWORKS has an adequate "track record of performance at Indian Point";

" Entergy's primary reliance upon the use of CHECWORKS, since Entergy has failed to identify any tools that are meaningfully independent of CHECWORKS that would sufficiently address FAC at Indian Point;

" Entergy's failure to demonstrate compliance with applicable regulatory guidance since, given the inadequacy of CHECWORKS, Entergy has failed to provide enough detailed information regarding the method and frequency of component inspections and attendant criteria for component repair and replacement, to assure adequate management of FAC.

In light of numerous material factual disputes, this case boils down to the classic "battle of the experts" for which summary disposition is utterly inappropriate. Accordingly, Entergy's Motion for Summary Disposition must be dismissed in its entirety.

Respectfully submitted, Deborah Brancato, Esq.

Phillip Musegaas, Esq.

Riverkeeper, Inc.

828 South Broadway Tarrytown, NY 10591 914-478-4501 dbrancatonriverkeeper.org phillip(kriverkeeper.org Dated: August 16, 2010 Tarrytown, NY 19

Riverkeeper Opposition to Entergy's Motion For Summary Disposition of Riverkeeper Technical Contention 2 (Flow-Accelerated Corrosion)

Riverkeeper TC-2: Attachment 1

August 16, 2010 UNITED STATES OF AMERICA NUCLEAR REGULATORY COMMISSION ATOMIC SAFETY AND LICENSING BOARD

)

In the Matter of )

)

Entergy Nuclear Operations, Inc. ) Docket Nos.

(Indian Point Nuclear Generating ) 50-247-LR Units 2 and 3) ) and 50-286-LR RIVERKEEPER COUNTER-STATEMENT OF MATERIAL FACTS Riverkeeper respectfully submits the following counter-statement of material facts in response to Entergy's July 26, 2010 Statement of Material Facts. Riverkeeper responds as follows:

GENERAL OBJECTIONS

1. A large portion of what Entergy has submitted as statements of material facts consists of summaries of the contents of documents, statements of law, or legal argument. The referenced documents, law, and arguments, are the best evidence of their content and speak for themselves. Riverkeeper has below disputed only facts; it has largely reserved its counterarguments, including interpretation of documents,. for its accompanying memorandum of law.

SPECIFIC RESPONSES AND COUNTERSTATEMENTS' A. Backzround ConcerningFAC, CHECWORKS, and Related Industry Guidance

1. Flow acceleratedcorrosion ("FA C") is a degradationprocess that attacks carbon steel piping and vessels exposed to moving water or wet steam. This attack occurs under specific water chemistry conditions. If FA C is not detected, then the piping or vessel walls will become progressively thinner until they can no longer withstand internalpressure and other applied loads. Joint Declarationof Jeffrey Horowitz, Ian Mew, andAlan Cox in Support of Entergy's Motionfor Summary Dispositionof Riverkeeper Contention TC-2 (Flow-Accelerated Corrosion)¶ 4 (Attach. 2); EPRI, Recommendationsfor an Effective Flow-Accelerated CorrosionProgram (NSAC-202L-R3) at 1-1 (Aug. 2007 (Attach.9). Undisputed that this a general definition of FAC. Disputed to the extent that FAC as used by Entergy in CHECWORKS is limited only to a very specific wall thinning degradation mechanism i.e.

due to dissolution of metal in water only. The degradation process also includes wall Entergy's alleged Undisputed Material Facts are reproduced below in Italics, followed by Riverkeeper's responses in bold.

I

thinning by electrochemical corrosion, erosion-corrosion and cavitation- erosion. See Riverkeeper, Inc.'s Request for Hearing and Petition to Intervene in the License Renewal Proceeding for the Indian Point Nuclear Power Plant (November 30, 2007), ADAMS Accession No. ML073410093 at 17 (hereinafter "RK Hearing Request"). Moreover, although the main causes of FAC (turbulence intensity, steam quality, material compositions, oxygen content and coolant pH) have been identified, the behavior of FAC is not completely understood. See id.

2. In December 1986, an elbow in the condensatesystem at the Surry Unit 2 nuclear plantfailed catastrophically,causingsteam and hot water to be releasedinto the turbine building. Post accident investigations revealed that FAC was the cause of the degradationto the elbow. At that time, the U.S. nuclearfleet did not have programs in place to deal with single-phase (i.e., water only) piping degradationcaused by FAC. Attach. 2, T 5. Undisputed.

3. In response to the pipe rupture at Surry in 1986, the Electric Power Research Institute ("EPRI") committed to developing a computer program that would assist utilities in determining the most likely placesfor FAC damage, and thus key locations to inspectfor pipe wall thinning. Attach. 2 ¶ 6,;Attach. 9, at 1-1 to 1-2. Undisputed.

4. EPRI releasedthe computerprogram CHEC (Chexal-HorowitzErosion Corrosion)to U.S. utilities in 1987. In 1989, EPRI replaced CHEC with CHECA TE (Chexal-Horowitz Methodologyfor Analyzing Two-Phase Environments). In 1993, EPRI replaced CHECMATE with CHECWORKS (Chexal-HorowitzEngineeringCorrosion Workstation) in 1993. Each new version of the code built on the previous program and incorporateduser feedback, improvements in software technology, and availablelaboratoryandplant data into the algorithms used in the programs. Attach. 2, ¶ 6; Attach. 9, at 1-1 to 1-2. Undisputed.

5. In 1993, to help utilities improve and standardizetheir FAC programs, EPRI's Nuclear Safety Analysis Center ("NSAC") publishedNSAC-202L, Recommendationsfor an Effective Flow-Accelerated CorrosionProgram. Attach. 2, ¶ 9. Undisputed.

6. EPRI issued Revision 3 of NSAC-202L in August 2007. NSAC-202L-R3 describes the elements of an effective FAC program, identifies the needfor andsuggested scope of program implementationprocedures and documentation, recommends specific FA C program tasks, and explains how to develop a long-term strategyfor reducingplant FAC susceptibility (e.g., through the use of FA C-resistantmaterials, improvements in water chemistry, andsystem design changes). Attach. 2, ¶¶ 31 & 34, Attach. 9. Undisputed that this is an accurate description of the content of NSAC-202L-R3, as characterized by that document.

7. Since the release of CHEC and its successorprogram more than 20 years ago, and the associateddevelopment of technology andprogrammaticguidance on FA C control, there has never been a fatality at any plant using CHEC or its successors. There has not been a major FAC-causedpipe rupture in a nuclear Unit in the United States for more than 10 years. At nuclearplants in countries where CHECWORKS is not used, there is approximately one major ruptureperyear. Attach. 2, ¶ 66. Agree, however dispute implication that FAC has never been an issue at nuclear power plants that have employed CHECWORKS or its 2

predecessor programs. For example, in 1997, an extraction steam piping ruptured at the Fort Calhoun Station. See RK Hearing Request at 18; see also Attach. 2, T 11. Moreover, dispute implication that the use of CHECWORKS and its predecessor programs have been effective at adequately managing FAC, or that the fact that no fatalities at plants using these programs has occurred can be directly linked to such use. See id. TT 8-17. This statement seeks to establish cause and effect by an unsupported correlation.

8. CHECWORKS is now used in more than 150 nuclearpower plant units worldwide, including all US. nuclear units, all Canadiannuclear units, and nuclear units in Belgium, the Czech Republic, England,Japan,Korea, Mexico, Romania, Slovenia, Spain, and Taiwan. Attach. 2, ¶¶ 7 & 66. Undisputed.

9. Since 2001, the NRC has approved numerous EP Us exceeding 15 percent. Duane Arnold (15.3%), Dresden Unit 2 (17%1o), Dresden Unit 3 (17%), QuadCities Unit 1 (17.8%lo),

Quad Cities Unit 2 (17.8%), Clinton (20%), Vermont Yankee (20%), and Ginna (16.8%). There have been no reportedfailures in any major steam andfeedwater system piping components at any of these plants, each of which has continuedto use CHECWORKS since implementation of their respective EPUs. Attach. 2, ¶ 67; see, also Approved Applicationsfor Power Uprates (Oct.

28, 2009), http://www.nrc.gov/reactors/operating/licensing/power-uprates/statius-power-apps/approved-applications. html (Attach. 14). Agree, however, dispute implication that CHECWORKS has fully accounted for changed plant parameters at referenced facilities; such an implication is speculative in light of the information available in this proceeding, and, in any event, not relevant to the instant proceeding which relates specifically to Indian Point. Riverkeeper further disputes the implication that FAC has never been a problem at such facilities; the fact that these facilities have not reported system failures does not preclude the possibility that unacceptable wall thinning may have occurred. Again, the limited information available in this proceeding confines our understanding of whether FAC has occurred at the listed plants since power uprates occurred. Lastly, the level of a power uprate is relative to the size of the particular facility, and the mentioned power uprates do not necessarily have any relevance to power uprates which have occurred at Indian Point. See Attach. 2, TT 26-27.

B. ARplicable NRC Regulations and Guidance

10. 10 C.F.R. § 54.21(d)(3) requiresa license renewal applicantto demonstrate that the effects of agingon structures and components subject to an aging management review

("AMR ") will be adequately managed, so that there is "reasonableassurance" that their intendedfunctions will be maintained consistent with the currentlicensing basis ("CLB ")forthe period of extended operation ("PEO"). Agree that 10 C.F.R. § 54.21(a)(3) read in conjunction with 10 C.F.R. § 54.29 requires such a demonstration.

11. 10 C.F.R. § 54.21(d) requiresthat the final safety analysis report ("FSAR ")

supplementfor thefacility contain a summary descriptionof the programs and activitiesfor managing the effects of aging. Undisputed.

3

12. In reviewing a license renewal application ("LRA "), the NRC Staff uses guidance in NUREG-1800, Rev. 1, StandardReview Planfor Review of License Renewal Applicationsfor Nuclear Power Plants (Sept. 2005) ("NUREG-1800" or "SRP-LR) (Attach. 6), and NUREG-1801, Vol. 2, Rev. 1, Generic Aging Lessons Learned (GALL) Report - Tabulation of Results,"

(Sep. 2005) ("NUREG-1801" or "GALL Report") (Attach. 7). Undisputed, and agree that these reports constitute guidance and not binding regulations. See Entergy Nuclear Vermont Yankee (Vermont Yankee Nuclear Power Station), LBP-08-25, 68 NRC 763, 869 (Nov. 24, 2008).

13. The GALL Report provides the technical basisfor the SRP-LR and identifies generic aging managementprogram ("AMPs ") that the Staff hasfound acceptable based on the experiences and evaluations of existing programs at operatingplants during the initiallicense period Attach. 6, at 3.0-2 & App. A at A. 1-3 to A. 1-8. Undisputed that this is NRC Staff's characterization of the GALL Report as stated in the SRP-LR.

14. The GALL Report describes each AMP with respect to the ten program elements defined in the SRP-LR: (1) Scope of the Program, (2) Preventative Actions, (3) Parameters Monitored or Inspected, (4) Detection ofAging Effects, (5) Monitoringand Trending, (6)

Acceptance Criteria,(7) CorrectiveActions, (8) ConfirmationProcess, (9) Administrative Controls, and (10) OperatingExperience. Attach. 2, ¶ 33; Attach. 7, at XI M-61 to XIM-62.

Disputed because the GALL report only generally describes what an AMP should contain.

See Entergy Nuclear Vermont Yankee (Vermont Yankee Nuclear Power Station), LBP 25, 68 NRC 763, 869 (Nov. 24, 2008) ("The simple fact is that NUREG-1801 does not contain an AMP, since it merely consists of two pages briefly describing the characteristics of a FAC AMP and specifies ten "evaluation and technical basis" criteria to be used in evaluating a FAC AMP... An enumeration of the criteria to be used in evaluating a program, is not itself a program.").

15. The Commission has stated that a "license renewal applicant's use of an aging managementprogram identified in the GALL Report constitutes reasonable assurancethat it will manage the targetedaging effect during license renewalperiod " AmerGen Energy Co., LLC (Oyster Creek Nuclear GeneratingStation), CLI-08-23, 68 NRC 641, 468 (2008). Dispute this characterization of the law. See Entergy Nuclear Vermont Yankee (Vermont Yankee Nuclear Power Station), LBP-08-25, 68 NRC 763, 871 (Nov. 24, 2008) ("merely stating that its AMP meets NUREG-1801 without any specificity falls short of the required demonstration ... a bald reference to NUREG-1801 fails to show how the recommendations of NUREG-1801 are proposed to be implemented ... and does not demonstrate that the effects of aging are adequate managed").

16. Section XIMJ 7 of the GALL Report describes the NRC-approvedAMP forflow-acceleratedcorrosion. Disputed for the reasons stated in ¶ 14. Moreover, the GALL Report is merely a guidance document generated and used by NRC Staff. See ¶ 12. It states that an acceptable FAC programrelies on implementation of the EPRIguidelines in NSA C-202L-R2 for an effective FACprogram. Attach. 2, ¶ 3,1; Attach. 7, at XI M-61.

Undisputed that this is an accurate description of what the GALL Report states.

4

17. The purpose of a program implemented in accordancewith GALL Report Section XTM1 7 and EPRIguidelines is to predict, detect, and monitor FAC in plantpiping andpiping components, such as tees, elbows and reducers. Attach. 2, ¶ 32; Attach. 7, at XI M-61.

Undisputed.

18. The programdescribedin GALL Report Section XI.M1 7 includes performing (1) an analysis to determine criticallocations, (2) limited baseline inspections to determine the extent of thinning at these locations; and (3) follow-up inspections to confirm the predictions, or repairingor replacingcomponents as necessary. The program also may include the use of CHECWORKS or similarpredictive code that uses the implementation guidance ofNSAC-202L to predict component degradation in the systems susceptible to FAC. Attach. 2, ¶ 32; Attach. 7, at XI M-61. Agree that the description of the FAC AMP in the GALL Report is accurately referenced here, but dispute any implication that Entergy's FAC program, including use of CHECWORKS, is implemented in accordance with the referenced guidance or that Entergy's program will adequately manage the aging effects of FAC at Indian Point. See Attach. 2, ¶ 25.

C. Overview of the Indian Point Energy Center ("IPEC") FAC Program

19. Chapter 3 of the IPECLRA summarizes Entergy's detailed assessment, conducted at a structure and component level, to identify those structures and components that require aging management review. Chapter 3 identifies FAC as an applicable aging mechanism for certainplant systems. Attach. 2, ¶ 29; LRA at 3.3-32 & 3.4-3 to 3.4-6, available at ADAMS Accession No. ML071210517. Undisputed.

20. The appendices to the LRA contain a description of Entergy's FA C Program.

Appendix A presents information.requiredby 10 C.FR. § 54.21(d) relatingto the AMP for FAC that supplements the updated FSAR (" UFSAR ')for IPEC. The supplement to the UFSAR, presented in section A.2 of Appendix A, contains a summary descriptionof the program and activitiesfor managing the effects of FAC during the PEO. Appendix A states that this information will be incorporatedinto the UFSAR following issuance of the renewed operating licenses. Attach. 2, ¶ 29; LRA, App. A at A-1 & A-24, available at ADAMS Accession No. ML071210520. Undisputed that this is an accurate description of the content of the referenced appendix of the LRA.

21. Appendix B to the LRA describes those AMPs credited in the integratedplant assessmentfor managing aging effects. Section B. 1.15 describes the IPEC FAC Program and indicates that it is consistent with, and takes no exceptions to, the program describedin GALL Section XI.MJ 7. Attach. 2, ¶ 30; LRA, App. B at B-1 & B-54, availableat ADAMS Accession No. ML071210523. Undisputed that this is an accurate description of the content of the referenced appendix of the LRA. Dispute that the IPEC FAC program is actually implemented in accordance with NRC and industry guidance. See Attach. 2, ¶ 25.

22. LRA Section B. 1.15 states that the IPECFAC Program is based on EPRI guidelinesfor an effective FACprogram containedin NSAC-202L-R2. Attach. 2, ¶ 30; LRA, 5

App. B at B-54. Undisputed that these EPRI guidelines apply. Dispute that the IPEC FAC program is actually implemented in accordance with EPRI guidance. See Attach. 2, ¶ 25.

23. Entergy comparedthe IPECFAC Program to GALL Report Section XI.M1 7 with respect to each of the ten program elements. The results of this comparison are documented in the LRA and Entergy's June 2008 AMP Evaluation Reportfor non-Class] mechanical components and show that the IPEC FAC Program elements are consistent with all ten program elements identified in the SRP-LR and the GALL Report. Attach. 2, 7¶ 33 & 56; LRA, App. B at B-54 to B-55; Entergy Eng 'gReport No. IP-RPT-06-LRDO7,Rev. 5, Aging Management ProgramEvaluation Results - Non-Class ] Mechanical, (Mar.18, 2009) (Attach. 8) ("AMP Evaluation Report'). Disputed. Riverkeeper disagrees that the IPEC FAC program elements are consistent with those elements identified in SRP-LR and the GALL Report.

See Attach. 2, ¶ 25.

.24. On December 18, 2007, in response to NRC Audit Item 156, Entergy amended the "scope ofprogram" and "detection of aging effects "program elements to identify its use of Revision 3 of NSAC-202L (NSA C-202L-R3) as an "exception" to GALL Report Section XIM1 7, which references the prior Revision 2 ofNSAC-202L. Attach. 2, ¶ 34; NL-07-153, Letterfrom FredR. Dacimo, Entergy, to NRC Document Control Desk, "Amendment 1 to License Renewal Application (LRA), "Attach. 1, at 46-48 (Dec. 18, 2007) (Attach. 10). Undisputed.

25. NSA C-202L-R3 incorporateslessons learned and improvements to detection, modeling, and mitigation technologies that arose after the publication of Revision 2. Attach. 2, TT 34 and 5 7. It states that the updated recommendations "are intended to refine and enhance those of the earlierversions, without contradiction,so as to ensure the continuity of existing plant FAC programs." Attach. 9, at v. Undisputed. Entergy did not take an exception to the GALL Report in its April 2007 LRA because implementing NSA C-202L-R3 does not create program deviationsfrom NSAC-202L-R2. Attach. 2, TT 34 & 57. Dispute to the extent this statement implies that that Entergy implements the IPEC FAC Program in accordance with the EPRI guidance. See Attach. 2, ¶ 25.

26. The NRC Staff's Safety Evaluation Report concludes that the IPECFAC program elements, including Entergy's use ofNSAC-202L-R3, are acceptable and consistent with all ten program elements in GALL Section XIM1 7. Attach. 2, ¶ 35; NUREG-1930, Vol. 2, Safety EvaluationReport Related to the License Renewal of Indian Point Nuclear Generating Unit Nos.

2 and 3, Docket Nos. 50-24 7 and 50-286, Entergy Nuclear Operations,Inc. at 3-22 to 3-30 (Nov.

2009), available at ADAMS Accession No. ML093170671 ("SER"). Undisputed that this is an accurate description of the content of the referenced NRC Staff SER. Dispute to the extent Entergy is characterizing the substance of NRC Staff's finding as undisputed facts; Riverkeeper disagrees that the IPEC FAC program elements are consistent with those elements identified -in SRP-LR and the GALL Report. See Attach. 2, ¶ 25.

D. IPECProgramfor ManagingFAC Duringthe Periodof Extended Operation

27. Entergy has maintaineda formal FAC inspectionprogram at IPEC based on EPRI and industry guidelines since 1990. The IPEC FAC Programis an existing IPECprogram 6

that will continue during the PEO. Although the IPECFACProgrampredatesEPRI guidelines in NSA C-202L, the program documents have been revisedto conform to the recommendations containedin NSA C-202L guidelines. Attach. 2, ¶ 36. Disputed that Entergy's IPEC FAC Program has been consistent with the referenced EPRI and industry guidelines. See Attach. 2, ¶ 25.-.

28. The IPEC FAC Programdrawsfrom industry andIPEC operating experience, including NRC information notices, bulletins, and generic letters,; inspection datafrom recent refueling outage inspections andpower uprate-relatedchanges in operatingparameters;and audits/self-assessmentsof the IPEC FAC Program. Attach. 2, ¶ 36; LRA, App. B at B-54 to B-55; SER Vol. 2, at 3-29 to 3-30. Dispute that Entergy's IPEC FAC Program "draws from" such mechanisms in a manner which effectively addresses FAC at Indian Point. See Attach. 2, ¶¶ 19-24.

29. Entergy has implemented the IPECFAC Program in accordance with its fleet-wide procedureEN-DC-315, "Flow Accelerated CorrosionProgram,Rev. 3 (Mar. 1, 2010)

(Attach. 11), which governs the FAC programsat all of Entergy's nuclearpower plants. EN-DC-315 implements the recommendations of the GALL Report and the more detailed EPRI NSAC-202L-R3 guidelines. In developing EN-DC-315, Entergy reviewed best practicesfor the FAC Programat all Entergy sites and includedguidancefrom the EPRI CHECWORKS Users Group ("CHUG"). Attach. 2, ¶ 37. Disputed. Whether Entergy has implemented the IPEC FAC Program in accordance with its fleet-wide procedure is a subjective assessment and statement of opinion at best, not a fact. Further disagree that the IPEC FAC program is actually implemented in accordance with the GALL Report and EPRI NSAC-202L-R3 guidelines. See Attach. 2, ¶ 25.

30. The IPECFAC Program applies to carbon and low-alloy steel piping systems and includesfeedwater heater and moisture separatorre-heater ("MSR ") shells susceptible to FAC.

It includes inspections of single-phaseand two-phase piping componentsfor both safety-related and nonsafety relatedsystems. Attach. 2, ¶ 38; LRA, App. B at B-54. Undisputed that this accurately reflects the language describing the IPEC FAC Program in the LRA.

31. Ultrasonic testing (" UT") thickness measurementsperformed in accordancewith approvedprocedures are the primarymethod used to determinepipe wall thickness. Attach. 2, T 38; Attach. 1], at 19-23. Undisputed.

32. EN-DC-315 states that FAC inspectionsare to be conducted during scheduled refueling and maintenance outages. Attach. 2, TT 38 & 59; Attach. 11 at 3 & 10. Undisputed that this accurately reflects the language in Entergy's procedural document, EN-DC-315.

33. The IPECFAC Programincludes specific criteriaor guidancefor selecting componentsfor inspections,performing the inspections, evaluating inspection data, dispositioningcomponent inspection results, conducting re-inspections,addressingcomponents thatfail to meet initial screening criteria,expanding the sample to other components similar to those failing to meet acceptance criteria,repairingor replacingdegradedcomponents. Attach.

2, T 59; Attach. 9, at 4-1 to 4-28; Attach. 11, at 15-26 & 34. Disputed to the extent this 7

statement implies that the IPEC FAC Program "criteria" and "guidance" for the above activities is adequate to effectively manage FAC atfIndian Point. See Attach. 2, ¶4 19-24.

34. The IPEC criteriafor component selectionfor FAC inspection during outages are consistentwith those citied in NSAC-202L-R3, with the selection being basedpiincipallyon: (1) pipe wall thickness measurementsfrom past outages, (2) predictive evaluationsperformedwusing the CHECWORKS code, (3) industry experience related to FAC, (4) resultsfrom other plant inspectionprograms, and (5) engineeringjudgment. The planningprocessforfuture inspections at IPEC also considers the consequences offailure of a particularcomponent with respect to personnel safety andplant availability,and the margin of nominal wall thickness versus code minimum wall thickness. EN-DC-315provides additionalguidance on component selection.

Attach. 2, ¶¶ 39-40,; Attach. 1], at 16-17. Disputed. Generally, this alleged undisputed fact merely states a subjective judgment regarding the consistency of Entergy's FAC program with EPRI guidance. Disagree that Entergy's IPEC FAC Program-is consistent with EPRI guidance. See, Attach. 2, ¶ 19-25. Criteria for component selection during outages and the scope of inspection in the IPEC FAC program are inadequate because they are based on questionable CHECWORKS predictions and rely on "engineering judgment" that Entergy has failed to describe with sufficient specificity. Id. 44 8-24.

35. The IPEC FAC Programalso includes specific criteriafor the disposition of inspection results, including the criteriafor component repairand replacement. Using the inspection results, the wear r ate andpredictedthickness at a future inspection date (usually the next refueling outage) is calculatedand compared to the component nominal thickness (t,,r,)

(i. e., wall thickness equal to the ANSI standardthickness). Specific actions are taken based on the results of this comparison. The component may be found acceptablefor continuedservice, subjected to a structuralevaluation in accordancewith pipe code stress requirements, or immediately repairedand replaced(in accordancewith Section 5.13 ofEN-DC-315). Attach. 2,

¶ 41; Attach. 9, at 4-17 to 4-2,7; Attach. 11, at 23-26 & 35. Disputed. "Specific" is ambiguous and subject to varying interpretation by different experts. No conclusion can be reasonably drawn or legitimately inferred from this statement; dispute to the extent this statement implies that the IPEC FAC Program criteria-cited is adequate to effectively manage FAC at Indian Point. See Attach. 2, ¶4 18-24.

36. If a component isfound that has a currentorprojected wall thickness less than the minimum acceptable wall thickness, then Entergy will perform additionalinspections of identical or similarpiping components in a parallelor alternate train,as necessary, to bound the extent of thinning. Section 5.12 of EN-DC-315 describes the sample expansion protocol.

Attach. 2, ¶ 42; Attach. 1], at 25-26. Undisputed that this accurately reflects the language in Entergy's procedural document, EN-DC-315. But disputed to the extent this statement implies that the IPEC FAC Program section referenced is adequate to effectively manage FAC at Indian Point. See Attach. 2, 44 18-24.

37. Entergy has replacedcertain IPECpipingcomponents susceptible to FAC previously with FA C-resistantmaterials (e.g., stainless steel, chromium-molybdenum steel).

Sufficient concentrationsof certain alloying elements, particularlychromium, make steels immune to FAC. Undisputed, however, Entergy has not specified the extent to which FAC-8

resistant materials have replaced FAC-susceptible materials. Therefore, no conclusion can heir.easonablv drawn or legitimately inferred from this statement.

38. Entergy also maintains water chemistry to inhibit corrosion of FAC-susceptible pipingandpiping components. In accordancewith the Secondary Water Chemistry Program, IPEG utilizes an all volatile treatment ("A VT") that includes the addition of monoethanolamine

("ETA ") and hydrazine to the condensate to control pH control [sic] and oxygen levels. Under the Secondary Water Chemistry Program,corrosionproducts of iron and copper typically are reduced to less than I partper billion ("ppb "') and 0. 01 ppb, respectively. These concentrations are below the industry recommended limits specified in EPRI's PWR secondary water chemistry guidelinesfor feedwater iron (5 ppb).andfeedwater copper (I ppb) duringfull power operation.

Attach. 2, ¶ 44. Undisputed, however, Entergy has not provided analyses of the performance of the FAC inhibiting water chemistry program. Therefore, no conclusion can-be reasonably drawn or legitimately inferred from this statement.

E. Use and Updatingof CHECWORKS Models at IPEC

39. The decision to repair or replacepiping or components at IPEC is based on actual inspections ofplantpiping andpiping componentsfor wall thinning. Attach. 2, ¶ 49,;

Attach. 11, at 21-26; SER Vol. 2, at 3-27 to 3-29. Undisputed, however object to the extent this statement attempts to minimize the role CHECWORKS plays in this process, since actual inspection point locations are chosen in the first instance in large part because of CHECWORKS. See Attach. 2, T 20.

40. CHECWORKS is a multi-purpose computer program designed to assist FAC engineers in identifyingpotential locations of FAC vulnerability. It is designedfor use by plant engineersas a tool for identifyingpiping locations susceptible to FAC, predictingFAC wear rates,planning inspections, evaluatinginspection data, and managing inspection data. Attach.

2, ¶ 45; Attach. 9, at 1-1. Undisputed to the extent this is a general description of CHECWORKS and its intended use, but disputed that CHECWORKS is an effective tool for identifying appropriate inspection locations. See Attach. 2, 44 8-18.

41. At JPECCHECWORKS is used in conjunction with trend datafrom actual inspections, relevant informationfrom otherplantprograms, industry or plant operating experience, and engineeringjudgment. Attach. 2, ¶ 49; Attach. 1], at 16-17; SER Vol. 2, at 3-

29. Disputed to the extent this statement implies that such measures, as implemented by Entergy, sufficiently manage the effects of FAC at Indian Point. See Attach. 2, IM 19-24.

42. The CHECWORKS user constructs a mathematicalmodel of the FAC-susceptible piping systems, similar in concept to a piping stress model orflow model. The input to the CHECWORKS modelingprogram includesplant operatingparameterssuch asflow rates,pipe material,operatingtemperaturesandpiping configuration, as well as measured wall thicknesses from FAC Programcomponents. Based on this input, CHECWORKS predicts the rate of wall thinning and remainingservice life on a component-by-component basis. Attach. 2, ¶ 46.

Undisputed to the extent this is a general description of CHECWORKS and its intended 9

use, but disputed that CHECWORKS is an effective tool for predicting "the rate of wall thinnitgand.remaining service life" ofplant components. S Attach. 2, ¶8-18.

43. CHECWORKS uses two types of evaluations in determining the susceptible locationsfor FAC and predictingwear rates. The first evaluation,called a "PASS-] Analysis,"

is performed to reportpredicted wear rates based on plant operatingcharacteristicsthat do not incorporateactualpipe thicknessesfrom plant inspections. This evaluation is normally used to generate a list of componentsfor inspections when plant data are not available. Attach: 2, ¶ 47; Attach. 9, at 4-1 to 4-2;'Attach. 1], at 8 & 11. Undisputed to the extent this is a general description of how CHECWORKS is run and its intended use, but disputed that CHECWORKS is an effective tool for "determining the susceptible locations for FAC and predicting wear rates." See Attach. 2, ¶¶ 8-18.

44. The second evaluation, called a "PASS-2 Analysis, *' incorporatesmeasurements from actual inspections ofplant piping and components. The model then compares the results to the initialpredictedvalues and adjusts the FAC calculations to accountfor actual wall thickness through the use of a "line correctionfactor" ("LCF"). If the model-predictedwear rate is less than the actualwear rate, then the predictedwear rates are increased(multiplied by the LCF)to match the inspection data. Attach. 2, ¶ 48; Attach. 9, at 4-1 to 4-2;,Attach. 11 at 8 & 1]; Attach.

12, at 15. Undisputed to the extent this is a general description of how CHECWORKS is used, but disputed that CHECWORKS is an effective predictive tool, or that Entergy's use of LCF's render CHECWORKS predictions accurate. See Attach. 2, ¶¶ 8-18.

45. The piping system locations at IPEC with areas of highflow velocity and high turbulence are expected to be most susceptible to FAC. These locations have been confirmed through two decades of inspectionsperformed under the FAC program. Attach. 2, ¶ 50; SER Vol. 2, at 3-26 to 3-27; see also NL-08-004, Letterfrom FredR. Dacimo, Entergy, to NRC Document ControlDesk, "Reply to Requestfor Additional Information Regarding License Renewal Application (Steam GeneratorTube Integrity and Chemistry), "Attach. 1, at 3 (Jan.4, 2008) (Attach. 13). Disputed. Whether the IPEC FAC Program has been appropriately implemented so as to accurately identify locations most susceptible to FAC is subject to varying interpretation by different experts.

46. The CHECWORKS~model is updatedafter every outage with the latest chemistry, operating,and inspection data. Through thisprocess, changes due to replacementor repairof piping andpiping components, adjustments in water chemistry, andpost-power uprate operationsare incorporatedinto the IPEC CHECWORKS models. Attach. 2 ¶ 5]1; Attach. 11, at 15-16, Attach. 12, at 15-17; SER Vol. 2, at 3-27 to 3-28. Disputed that the CHECWORKS model has been sufficiently calibrated or benchmarked to account for the changed operating parameters at Indian Point following the power uprates. See Attach. 2, ¶¶ 8-18.

47. The NRC approved stretchpower uprates ("SPUs") of 3.26% and 4.85%for1IP2 and 1P3 in October 2004 and March 2005, respectively. Attach. 2, ¶ 52,; Attach. 14, at *3.

Undisputed.

10

48. Entergy updated the IPEC CHECWORKS models to accountfor changes to plant operattigparametersresuldhgfrbm the SPUs. Spec-ially before the SPUs were performed, Eniergy entered the new operatingparameters(e g., flow rates, temperatures,pressures,and steam quality) into the IP2 and IP3 CHECWORKS databases and ran the CHECWORKS models to calculate new wear rates. These evaluations were complete in March 2005. The results of the updated CHECWORKS results were used in the inspection planningfor the subsequent outages.

Attach. 2, T¶ 52 & 62; Attach. 12, at 15; SER Vol. 2, at 3-26. Disputed that the CHECWORKS model has been sufficiently calibrated or benchmarked to account for the changed operating parameters at Indian Point following the power uprates. See Attach, 2,

¶¶ 8-18.

'49. Consistent with EN-DC-315, Rev. 3 and NSA C-202L-R3, Entergy uses UT inspection results obtained duringplant outages to assess the accuracy of the CHECWORKS wear predictionsand to perform re-baselined CHECWORKS analyses. Attach. 2, ¶ 53; Attach.

11, at 15-16 & 27; SER Vol. 2, at 3-28 to 3-29. Disputed that the IPEC FAC program is "consistent with" with referenced guidance. See Attach. 2, T 25. Further disputed that Entergy's use of inspection results adequately calibrates the CHECWORKS model to produce accurate predictions. See id. ¶4 8-18.

50. Under the current IPECoutage schedule, Entergy expects that at leastfour IP2 refueling outages andfive 1P3 refueling outages will have occurred between implementation of the SPU and expiration of the respectiveplant operatinglicenses. Attach. 2, IT 53 & 63.

Undisputed, however, dispute implication that collection of data during these outages will adequately benchmark/calibrate CHECWORKS for effective use under the power uprate conditions at Indian Point during the period of extended operation. See Attach. 2, 44 8-18.

51. Entergy has updated the IP2 CHECWORKS model to incorporateinspection data from the 2R16 (2005), 2R17 (2006), 2R18 (2008) and 2R19 (2010) outages. Attach. 2, ¶ 54.

Dispute that such updates have adequately benchmarked/calibrated CHECWORKS for effective use under the power uprate conditions at Indian Point during the period of extended operation. See Attach. 2, 44 8-18.

52. Entergy has updated the IP3 CHECWORKS model to incorporateinspection data from the 3R13 (2005), 3R14 (2007), 3R15 (2009) outages. Attach. 2, ¶ 54. Dispute that such updates have adequately benchmarked/calibrated CHECWORKS for effective use under the power uprate conditions at Indian Point during the period of extended operation. See Attach. 2, ¶¶ 8-18.

53. Comparison of measuredwear and CHECWORKS model-predictedwear indicates a level of correlationfollowing SPU implementation that is consistent with industry andplant expectations relative to the performance,of CHECWORKS. Attach. 2, TT 55, 63 & 76.

Disputed. Comparison of measured wear and CHECWORKS predicted wear indicates a level of correlation that is unacceptable, and which demonstrates CHECWORKS is not sufficiently calibrated/benchmarked to post power uprate conditions at Indian Point. See Attach. 2, ¶ 13.

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54. The NRC Staffs SER concludes that the IPEC FAC Program is adequate to manage FAC during the PEO because: (1) the CHECWORKS code is consideredto be a self-benchmarking code that is capable of modeling,predicting,and-trackingthe results of the ultrasonic inspections that areperformed in accordancewith the applicant'sFAC Program;(2) the self-benchmarkingfeature of CHECWORKS makes prolongedbenchmarking of CHECWORKS unnecessary; (3) the applicant uses the actual UT inspection results to confirm the predictive modeling of the CHECWORKS analyses and to perform re-baselined CHECWORKS analyses; (4) the applicantdoes not use the CHECWORKS computer code as the sole basisfor establishingwhich steel piping,piping components, or piping elements at IP2 and IP3 will be inspected; and (5) the program includes acceptableprogram elements for managing flow-acceleratedcorrosionthat are consistent with the program element criteriain GALL AMP XI.M1 7 or with the acceptable alternative to use EPRIReport NSAC-202L-R3 as the implementationguidelinefor this program. SER Vol. 2, at 3-29. Undisputed that this is an accurate description of the content of the referenced NRC Staff SER. Disputed to the extent Entergy is characterizing the substance of NRC Staff's finding as undisputed facts.

Riverkeeper does not agree with the NRC's Staff s findings or conclusions in the SER in regards to Entergy's program for managing FAC at Indian Point, consistent with the specific disputes already identified herein.

55. The NRC Staff's SER also concludes that Entergy's LRA, including the FAC Program,satisfies the applicable requirements of 10 C.F.R. Part54, including those contained in 10 C.F.R. § 54.21 (a)(3), 10 C.F.R. § 54.21(d). SER Vol. 2, at 3-31. Undisputed that this is an accurate description of the content of the referenced NRC Staff SER. Disputed to the extent Entergy is characterizing the substance of NRC Staff's finding as undisputed facts.

Riverkeeper does not agree with the NRC's Staff's findings or conclusions in the SER that Entergy's LRA satisfies the requirements of Part 54 in regard to Entergy's program for managing FAC at Indian Point, as discussed in Riverkeeper's accompanying Memorandum of Law.

Respectfully submitted, Deborah Brancato, Esq.

Phillip Musegaas, Esq.

Riverkeeper, Inc.

828 South Broadway Tarrytown, NY 10591 914-478-4501 dbrancato(*.riverkeeper.org Dated: August 16, 2010 Tarrytown, NY 12

Riverkeeper Opposition to Entergy's Motion For Summary Disposition of Riverkeeper Technical Contention 2 (Flow-Accelerated Corrosion)

Riverkeeper TC-2: Attachment 2

August 16, 2010 UNITED STATES OF AMERICA NUCLEAR REGULATORY COMMISSION

.ATOMIC SAFETY AND LICENSING BOARD

)

In the Matter of )

)

Entergy Nuclear Operations, Inc. Docket Nos.

(Indian Point Nuclear Generating ) 50-247-LR Units 2 and 3) ) and 50-286-LR

)

DECLARATION OF DR. JORAM HOPENFELD Joram Hopenfeld, hereby declares under penalty of perjury that the following is true and correct:.

1. I have been retained by Riverkeeper, Inc. as an expert witness in proceedings concerning the application by Entergy Nuclear Operations, Inc. ("Entergy") for a renewal of the two separate operating licenses for the nuclear power generating facilities located at Indian Point on the east bank of the Hudson River in the Village of Buchanan, Westchester County, New York, for twenty years beyond their current expiration dates.

2. I submit this declaration in opposition to Entergy's July 26, 2010 Motion for Summary Disposition that seeks the dismissal of Riverkeeper Technical Contention 2 concerning Flow-Accelerated Corrosion (hereinafter "Entergy's Motion for Summary Disposition").

3. My professional and educational qualifications are described in the curriculum vitae appended as Attachment 3. Briefly summarized, I am an expert in the field relating to nuclear power plant aging management. I am a mechanical engineer and hold a doctorate in mechanical engineering. I have 45 years of professional experience in the fields of thermal-hydraulics, 1

material/environment interaction instrumentation, design, project management, and nuclear safety regulation, including 18 years in the employ of the U.S. Nuclear Regulatory Commission.

4. My extensive professional experience has afforded me with knowledge and expertise regarding the material degradation phenomenon known as "flow-accelerated corrosion" (hereinafter referred to as "FAC"). I have published numerous peer-reviewed papers in the area of corrosion, and hold patents related to monitoring of wall thinning of piping components. I have knowledge and expertise regarding the use of the CHECWORKS computer code dating back to 1988, when it was known as CHEC. Most recently, I was a technical consultant and expert witness for theNew England Coalition in theVermont Yankee license renewal proceeding, where I testified at an adjudicatory hearing concerning FAC and CHECWORKS.

5. I reviewed the April 30, 2001 License Renewal Application submitted by Entergy to renew the operating licenses for Indian Point Units 2 and 3, and assisted Riverkeeper with the preparation of Contention TC-2, which articulates Entergy's failure to provide for adequate aging management of FAC.

6. I have reviewed the pertinent sections of the NRC Staff s August 12, 2009 Safety Evaluation Report, numerous documents provided byEntergy pursuant to mandatory disclosure obligations of 10 C.F.R. § 2.336, and Entergy's Motion for Summary Disposition together with its attendant declarations and attachments. After a review of these documents, for the reasons explained more fully below, it remains my professional opinion that Entergy's proposed aging management program for FAC fails to provide reasonable assurance that Indian Point Units 2 and 3 will operate safely through their proposed license renewal periods.

2

7. A discussion of various assertions in Entergy's filing, sufficient to establish that Entergy's arguments are by no means dispositive and that technically credible and substantial disputes of fact remain, follows below:

Entergy's Misplaced Reliance on CHECWORKS

8. I disagree with Entergy's assertion that CHECWORKS is "a viable and effective tool for selecting and ptioritizing IPEC piping and piping component locations for inspection to detect and mitigate FAC during the period of extended operation." See Entergy Motion for Summary Disposition, Attach. 2 at 28-29. In particular, I continue to maintain that CHECWORKS is not a mechanistic model, and therefore it requires considerable benchmarking to be used as a reliable predictive tool.

9. Following the 1987 catastrophic pipe rupture accident at the Surry nuclear power plant, the nuclear industry funded the development of a computer program, today known as CHECWORKS, to predict wall thinning rates of critical reactor components that are exposed to high velocity single phase water. Wall thinning by wet steam, cavitation, or by abrasion are not included in the model. CHECWORKS is entirely based on empirical modeling, meaning that it is solely based on 'acollection of selective data which represents only a fraction of the total flow area. Accordingly, CHECWORKS must be calibrated or benchmarked separately at each individual power plant and recalibrated when plant conditions change.

10. NRC's guidance report, NUREG-1801, Generic Aging Lessons Learned (GALL)

Report, further implies that when one uses computer codes to predict wall thinning, the codes must be properly benchmarked at each plant before they can be used as a management tool to control FAC. See Entergy Motion for Summary Disposition, Attach. 7 (GALL Report at XI.M17).

3

11. It is difficult to quantify the overall success of CHECWORKS since no formal comparison of data from nuclear power plants that use CHECWORKS and those that do not, is available. Generally speaking,- given the numerous leaks and pipe ruptures from wall thinning which have occurred at nuclear power plants since its introduction in the late 1980s, the success of CHECWORKS has been questionable at best. See generally Riverkeeper, Inc.'s Request for Hearing and Petition to Intervene in the License Renewal Proceeding for the Indian Point Nuclear Power Plant (November 30, 2007), ADAMS Accession No. ML073410093 at 21-23. At Indian Point in particular, numerous leaks and reports of excessive wall thinning in mechanical systems tend to indicate that CHECWORKS has not been successful at preventing FAC related occurrences. For example, Entergy's 2007 Operating Experience Review Report (relevant excerpts appended as Attachment 4) documents various unacceptable wall thinning events which occurred between 2001 and 2005. See Attach. 4. Also by way of example, Entergy condition reports appended as Attachment 5, document occurrences of leaks from components that resulted from undetected FAC, where subsequent inspections revealed wall thinning was below minimum acceptable levels. See Attach. 5. The NRC Staff in this license renewal proceeding has also I

questioned Entergy regarding incidences of component wall thinning that were below minimum acceptable levels, as memorialized during a meeting of the Advisory Committee on Reactor Safeguards regarding Entergy's LRA, the relevant excerpt of which is appended as Attachment

6. See Attach. 6.

12. My review of numerous reports generated on behalf of Entergy in relation to CHECWORKS modeling at Indian Point has revealed that CHECWORKS predictions of wall thinning are highly unreliable. CHECWORKS can only predict the overall range of corrosion 4

rates for a given a component or a group of components. This range is too wide for practical applications, especially when the consequences of component failure are safety related.

13. For the purposes of demonstrating the highly unreliable predicative capability of CHECWORKS, I have collected graphs excerpted from seven individual CHECWORKS modeling reports, which plot CHECWORKS predictions of wall thickness versus actual measurements for selected plant components. Riverkeeper has labeled these graphs Figures 1 through 18 and, they are appended together as Attachment 7. These graphs were generated based on CHECWORKS/FAC data from Indian Point Unit 2 refueling outages 16 (2005), 17 (2006), 18 (2008), and 19 (2010), and from Indian Point Unit 3 refueling outages 13 (2005), 14 (2007), and 15 (2009), as indicated by cover sheets in Attachment 7. All of these outages occurred after the operating conditions at the Units 2 and 3 changed due to power uprates in 2004 and 2005, respectively.

If CHECWORKS predictions were completely accurate, all data points in Figures 1 through 18 would fall on a 45 degree line, i.e., the center line in the graphs. To the contrary, the wide scatters of the plotted points on the example graphs demonstrate that this is not the case.

See Att. 7. Indeed, one can draw almost any line through the data in these graphs, indicating a complete lack of correlation. See iq. A straight line parallel to the abscissa would indicate that actual plant observations and computer model predictions are independent of each other. See id The two lines drawn on these graphs above and below the center line were drawn completely arbitrarily to show that most, but not all of the data, can be bound with +/- a factor of two from the straight 45 degree line. See id Many of these graphs show that points outside these two lines can deviate by as much as a factor of +/- 10. See Attach. 7. For example, the data point furthest to the left in Figure 4 5

represents an actual measured wall thickness of a given component of about 20 mills (abscissa) while the corresponding CHECWORKS prediction was over 200 mills. On the other hand, Figure 7 shows that the predicted wall thickness of the data point furthest to the right in the figure was about 10 mills while the corresponding measured value was over 100 mills. Thus, CHECWORKS can either under-predict or over-predict FAC by a factor of 10 or 1000%. It is, thus, apparent, and my expert opinion, that CHECWORKS cannot predict FAC to any degree of accuracy. Considering that typically, wall thinning rates in pressurized water reactors range from 5 to 50 mills per year, and the wall thickness of the components ranges between 300 to 1000 mills, one would expect that more and more components would become prone to failures after 40 years of service. In my professional opinion, the margin of error in CHECWORKS predictions is too large and, therefore, CHECWORKS is not a reliable tool for identifying locations for inspections.

14. In discussing the alleged success of CHECWORKS in predicting wall thinning, Entergy maintains that "while CHECKWORKS sometime underestimates wear rates, it also yields precise and accurate results." See Answer ofEntergy Nuclear Operations, Inc. Opposing Riverkeeper Inc.'s Request for Hearing and Petition to Intervene (Jan. 22, 2008), at 54, ADAMS Accession No. ML080300149. I did not find any data that would support this conclusion. In my opinion, a margin of error high as +/- 1000% exhibited by a significant number of components is not a demonstration of precise and accurate results.

15. Entergy uses a "line correction factor" ("LCF") to compare and adjust CHECWORKS predictions to match inspection data. See Entergy Motion for Summary Disposition, Attach. 2 at ¶ 48. According to Entergy documentation related to CHECWORKS, the relevant excerpt of which is appended as Attachment 8, "[t]he LCF indicates the degree to 6

which CHECWORKS over or under-predicts wear. A reasonable LCF should be between 0.5 and 2.5." See Attach. 8. My review of Entergy's reports related to CHECWORKS for the above referenced outages has revealed numerous instances where the LCF was outside of this range.

See, e.g., Attach. 7, Figures 12-15, 17-18. Thus, Entergy's own data indicates that CHECWORKS is unreasonably failing to predict wear rates.

16. Moreover, I am unaware of a justification to support the conclusion that the LCF range of 0.5 to 2.5 is acceptable. I attended a tutorial on CHECWORKS where Entergy witness Dr. Jeffrey Horowitz explained that the LCF is obtained by comparing the predicted amount of wall thinning with the measured results for each component and then using proprietary statistical methods to determine the LCF, which is applied to all components in a given pipe line. Based on this explanation and my review of relevant documents provided by Entergy, it is evident that Entergy has failed to demonstrate how the stated LCF range would be an indication that CHECWORKS can be used to predict inspection locations. In my opinion, one acceptance criteria for the LCF must be the consequences of component failure.

17. The foregoing directly, controverts Entergy's apparent position that the level of correlation between the CHECWORKS model predicted wear and the measured wear following implementation of the stretch power uprates at Indian Point is acceptable. See Entergy Motion for Summary Disposition, Att. 2 at ¶¶ 55, 63, 75. The foregoing further contradicts Entergy's conclusion that CHECWORKS is adequately benchmarked under post power uprate operating conditions, and that it "is a suitable tool for informing predictions of where potential pipe failures due to FAC might occur." See id at ¶¶ 74, 75.

18. Entergy claims that the CHECWORKS model is updated after every plant refueling outage, and takes into account inspection data, as well as changed parameters, thus allowing for 7

more accurate predictions over time. See Entergy Motion for Summary Disposition, Attach. 2. at

¶¶ 48, 51-54, 61-65, 75. My review of Indian Point related CHECWORKS modeling reports encompassing the previous five years of refueling outages at Units 2 and 3, as discussed above, demonstrates the such claims are highly disputable.

Entergy's Other Inspection Point Selection Criteria

19. Entergy's Motion for Summary Disposition vaguely, identifies other "tools" or criteria Entergy allegedly relies upon in addition to CHECWORKS for selecting components for FAC inspections. Specifically, Entergy states that, in addition to the use of CHECWORKS, component section is "based principally on" (1) actual pipe wall thickness measuremerts from past outages, (2) industry experience related to FAC, (3) results from other plant inspection programs, and (4) engineering judgment. See Entergy's Motion for Summary Disposition at Attach. 2 ¶ 39. I disagree with Entergy's characterization of these "additional" criteria as independent tools that demonstrate the effectiveness of Entergy's FAC aging management program irrespective of the use of CHECWORKS. See Entergy's Motion for Summary Disposition at 17-18.

20. Actual pipe wall thickness measurements from past outages are only useful when used in combination with a predictive tool which would prevent the wall thickness of a given component from being reduced to below the minimum design thickness while in service.

Accordingly, this is a required input for the use of CHECWORKS or for the formulation of an engineering judgment, and not a stand alone "tool" for component selection. Moreover, obviously, for components initially selected for inspection by CHECWORKS, any decisions regarding future inspection scope based on actual pipe wall thickness measurements and wear 8

rate trending of the actual inspection results, necessarily depends upon use of the CHECWORKS computer model.

21. Industry and plant experience also cannot be properly categorized as independent "tools" for component selection. Rather, knowledge of pipe wall thinning events at Indian Point and other plants are simply types of information that feed into the CHECWORKS model, and/or contribute to ones ability to formulate a judgment regarding proper inspection scope. In other words, they are merely inputs into engineering judgment and/or CHECWORKS.

22. To the extent engineering judgment can be considered an independent tool for selecting components for FAC inspections, Entergy has failed to demonstrate that this alone will safely manage FAC at Indian Point. It is commonly recognized in all major industrial plants, (power, chemical, oil) that engineering judgment alone is not sufficiently reliable to prevent component failures from wall thinning. For this reason, many plants supplement that judgment with either computer modeling and/or direct or indirect continuous on line wall thinning measurements. The development of the CHECWORKS computer model itself stemmed from the realization by the nuclear industry that engineering judgment alone was no longer enough to be able to detect unacceptable and unsafe wall thinning occurrences.

23. When engineering judgment is identified as an independent predictive tool, a very high degree of knowledge is required by those who conduct the assessment and specify the required steps for the prevention of component failures. Engineering judgment is intrinsically subjective. Even with the same input data, different assessments could lead to different results because each assessment would depend heavily on the individual skill and judgment of the responsible engineer. Accordingly, in order to assess the validity of the use of engineering judgment, it is imperative to fully understand how it is used and all relevant underlying 9

assumptions informing any judgment relateddeterminations. To the contrary, Entergy has failed to clearly describe what exactly "engineering judgment" even means in relation to FAC inspections at Indian Point, and what role it actually plays in inspection scope selection. Entergy has not identified any kind of systematic methodology which demonstrates that engineering judgment is a separate predictive tool that adequately manages FAC related component degradation.

24. Based on the foregoing, and in direct contradiction to Entergy's assertions otherwise, it is apparent that Entergy does not employ any meaningful tools that, separate and apart from CHECWORKS, would sufficiently manage the aging effects of FAC at Indian Point.

Rather, Entergy's program for managing FAC relies heavily on the unreliable CHECWORKS code.

Entergy's Improper Reliance on Guidance Documents

25. Because Entergy has failed to show that CHECWORKS will be an effective tool for adequately managing the effects of FAC at Indian Point during the period of extended operation, or that it has other methods sufficient to manage such aging effects, it is necessary for Entergy to provide detailed information regarding the method and frequency of component inspections and attendant criteria for component repair and replacement. In contrast, Entergy merely states that its FAC program relies on and is consistent with various guidance documents. See Entergy Motion for Summary Disposition, Attach. 2 ¶¶ 56-59. However, these generic guidance documents and fleet wide procedure focus heavily on the use of a properly calibrated CHECWORKS model. See, e.g. id. at Attach. 9. Because Entergy has failed to show that CHECWORKS is properly benchmarked so as to be an effective tool at Indian Point, as discussed above, Entergy has not been successful in implementing the essential elements of the 10

referenced documents. Moreover, as discussed above, Entergy has failed to properly define how it employs "engineering judgment" or other "tools" to adequately address FAC in accordance with such guidance. Accordingly, mere reference to guidance and fleet wide procedure is not a demonstration that Entergy had developed an effective program for safely managing FAC at Indian Point.

Entergy's Improper Comparison to the Vermont Yankee License Renewal Proceeding.

26. Entergy's Motion for Summary Disposition references various findings of a different Atomic Safety and Licensing Board ("ASLB") in a different license renewal proceeding concerning the Vermont Yankee nuclear power plant ("VY"), in order to demonstrate compliance with applicable regulatory requirements. For example, Entergy relies upon the VY ASLB's findings relating to the need to benchmark CHECWORKS for use at VY, and the overall sufficiency of Entergy's "other tools" for managing FAC at VY. I have reviewed the decision made by the Atomic Safety and Licensing Board in the Vermont Yankee license renewal proceeding ("VY ASLB"). Based on this review, as well as my participation in the VY license renewal proceeding as an expert witness, I disagree that any of the specific findings in the VY proceeding can be generically applied to the instant license renewal proceeding involving Indian Point. The VY ASLB's conclusions are restricted to the VY plant.

27. Generally speaking, major differences between VY and the Indian Point plants underscore the need to perform an independent assessment of the efficacy of Entergy's program for managing FAC at Indian Point. This includes the very small size of the VY plant (with a gross thermal output of 1912 MWth) in comparison to the large Indian Pointrplants (with gross thermal output on the order of 3200 MWth). Moreover, VY is a boiling water reactor, while the Indian Point plants are pressurized water reactors. The latter are known to be significantly more 11

prone to failures from'wall thinning due to FAC than the former. See e.g., Entergy Motion for Summary Disposition, Attach. 15 at 5.25.

28. The VY ASLB's findings regarding the adequacy of the benchmarking of the CHECWORKS computer code at VY cannot be applied here. The use of CHECWORKS must be evaluated at each plant separately to account for the .unique differences in materials, local flow velocities, temperatures, water chemistry, accessibility for inspection, past history with respect to the number of components and frequency of wall measurements that were used in the calibration of CHECWORKS, the quality of the correlation of predictions with measurements, and the number of component failures from wall thinning at the specific plant.

29. Moreover, in the VY license renewal proceeding, hearings were held shortly after the VY plant changed its operating power. Therefore, theVY ASLB did not have the benefit of any data to assess the ability of CHECWORKS to accurately detect wall thinning in light of changed plant operating conditions (including changed velocities, temperatures, and coolant chemistry). Rather, the VY ASLB relied upon the fact that data would be collected prior to the VY license extension period which it assumed would adequately calibrate the CHECWORKS model. In contrast, data from seven post power uprate outages at Indian Point Units 2 and 3 is already available to assess the ability of CHECWORKS to account for changed plant conditions.

As discussed above, this data shows almost a complete failure of CHECWORKS to predict wall thinning in light of new plant operating parameters. This necessarily renders the conclusions of the VY ASLB regarding the benchmarking of CHECWORKS inapplicable in the instant proceeding.

30. The VY ASLB's findings in relation to the minimal role CHECWORKS plays in Entergy's FAC program at VY, and the attendant sufficiency of the detail of Entergy's FAC 12

program at VY are likewise inapplicable in the instant license renewal proceeding, since, as the discussion above demonstrates, Entergy relies primarily on CHECWORKS in order to address FAC at Indian Point.,

Conclusion

31. The foregoing demonstrates that significant disputes of fact exist regarding the sufficiency of Entergy's program for managing the aging effects of FAC at Indian Point during the period of extended operation. In particular, my testimony herein supports the following findings and conclusions:

• Entergy has failed to demonstrate that CHECWORKS is adequately benchmarked so as to be an effective tool for predicting FAC at Indian Point during an extended period of operation; 0 Entergy's program for managing FAC is largely reliant upon the use of CHECWORKS, since Entergy has failed to identify any tools that are meaningfully independent of CHECWORKS that would sufficiently address FAC at Indian Point; In the absence of CHECWORKS, Entergy has failed to provide detailed information regarding the method and frequency of component inspections and attendant criteria for component repair and replacement, sufficient to assure adequate, safe management of FAC; The findings of the VY ASLB are not applicable to the instant proceeding.

13

In accordance with 28 U.S.C. §1746, 1 declare under penalty of perjury that the foregoing is true and correct Executed onA .. / 2010.

References Entergy Condition Reports CR-IP2-2001-10525, CR-IP3-2006-02270 Entergy Fleet Procedure, EN-DC-315, Rev. 3, Flow Accelerated CorrosionProgram (March 1, 2010)

Entergy Nuclear Vermont Yankee (Vermont Yankee Nuclear Power Station), LBP-08-25, 68 NRC 763 (Nov. 24, 2008)

Entergy Operating Experience Review Report, Engineering Report No. IP-RPT-06-LRD05, Rev. 1 (June 2007)

Indian Point Unit 2 CHECWORKS FAC Model, Calculation No. 050714b-01, Rev. 0 (July 5, 2005)

Indian Point Unit 2 CHECWORKS FAC Model, Calculation No. 050714b-01, Rev. 1 (Sept. 12, 2006)

Indian Point Unit 2 CHECWORKS SFA Model, Calculation No. 0705.10 1-01, Rev. A (Nov. 17, 2008)

Indian Point Unit 2 CHECWORKS SFA Model, Calculation No. 0705.101-01, Rev. 1 (Feb. 26, 2010)

Indian Point Unit 3 CHECWORKS FAC Model, Calculation No. 050714c-01, Rev. 0 (Oct. 25, 2005)

Indian Point Unit 3 CHECWORKS SFA Model, Calculation No. 0705.100-0 1, Rev. 0 (Nov. 14,.2007)-

Indian Point Unit 3 CHECWORKS SFA Model, Calculation No. 0705.1 00-01, Rev. 1 (Feb. 12, 2010)

NL-08-004, Letter from Fred Dacimo, Entergy, to NRC Document Control Desk, "Reply to Request for Additional Information Regarding License Renewal Application (Jan. 4 2008) (ADAMS Accession No. ML080160123)

Nuclear Safety Analysis Center (NSAC)-202L-R2, Rev. 2, Recommendationsfor an Effective Flow Accelerated Corrosion Program Nuclear Safety Analysis Center (NSAC)-202L-R3, Rev. 3, Recommendationsfor an Effective Flow Accelerated Corrosion Program NUREG- 1801, GenericAging Lessons Learned (GALL) Report (Sept. 2005),Section XI.M 17 NUREG-l1800, StandardReview Planfor Review of License Renewal Applicationsfor Nuclear Power Plants (Sept. 2005).

Safety Evaluation Report Related to the License Renewal of Indian Point Nuclear Generating Unit Nos. 2 and 3, Docket Nos. 50-247 and 50-286, Entergy Nuclear Operations, Inc. (Nov. 2009), NUREG-1930 (ADAMS Accession No. ML093170671.

Transcript of Meeting of Advisory Committee on Reactor Safeguards (Sept. 10, 2009)

Riverkeeper Opposition to Entergy's Motion For Summary Disposition of Riverkeeper Technical Contention 2 (Flow-Accelerated Corrosion)

Riverkeeper TC-2; Attachment 3

Curriculum Vitae for Dr. Joram (Joe) Hopenfeld 1724 Yale P1., Rockville, MD 20850 Tel: 301 340 1625 A. Professional Expertise:

a. Nuclear Safety and Licensing (design basis/severe accidents)

b. Thermal/Hydraulics (Transient Boiling, Jet Mixing, Reentry Heat transfer, molten metal/coolant interactions, pool fires, computer code developments) c.. Materials/Environment Interaction (corrosion, erosion, stress corrosion, fatigue,.

cavitation, fouling)

d. Radioactivity Transport (10 CFR Part 100)

e. Industrial Instrumentation and Environmental Monitoring.

B. Current Position - CEO, Noverflo, Inc C. Education - Engineering- University of California at Los Angeles: BS 1960, MS 1962, Ph.D 1967.

D. Summary of Work Experience

1. Nuclear Plant Related Experience I have 45 years of experience in industry and government primarily in the areas of thermal hydraulics, materials, corrosion, radioactivity transport, instrumentation, PWR steam generator transient testing and accident analysis. I have managed major international programs on steam generator performance during steam generator tube ruptures, steam line and feed line breaks. Following a decade of studies and several Advisory Committee on Reactor Safety hearings, the Nuclear Regulatory Commission, ("NRC")

adopted my position regarding the safety consequences of operating with degraded steam generator

tubes. In 2001 the NRC initiated a major program on the effects of steam generator tube degradation on plant safety see NRC website). I have consulted to law firms and citizen groups regarding Steam Generators, Thermal Hydraulics, Corrosion, and Material Fatigue in connection with license renewals and a power upgrades.

2. Non Nuclear Related Experience I am the owner and the CEO of a small Maryland company, Noverflo, Noverflo is developing advanced fiber optic sensors for the oil & gas and the environmental monitoring industries. In 2004 Noverflo has completed a three year program which was sponsored by the U.S. Department of Energy. The program produced a new system for automatic tank gauging, which will be presented at the 2006 National Petrochemicals and Refiners Association Maintenance Conference.

In 1994-1996 Noverflo has developed and commercialized a shutoff valve for fuel tanks to comply with new EPA regulations.

E. Brief Employment History A. Recent Consulting

1. Winston & Strawn, 1400 L St. Washington D.C 2001 Provided assistance in connection with the February 2000 steam generator event at Indian Point.

2. C-10 Research and Education Foundation, Inc. 44Merrimac St. Newburyport, MA 2002-2003 Provided assistance in the preparation of a .2.206 petition to the NRC and other matters in connection with steam generator problems at the Seabrook Station

3. California Earth Corps (Sabrina D. Venskus, Attorney at Law, Santa Monica, CA) 2005

Provided testimony to the Public Utility Commission of the State of California on behalf of California Earth Corps in connection with-the San Onofre steam generator replacement project.

4. New England Coalition (Raymond Shadis, Edgecomb, Maine 04556) 2005-2006 Technical consultant and expert witness in connection with Vermont Yankee power uprate and life extension hearings before the Atomics Safety and Licensing Board. Prepare contentions and testify before the Board.

B. Industryand Government Employment 1962- 1971 -Corrosion testing of materials for the design and operation of liquid metal cooled nuclear reactors. Modeling Transient Boiling in water and sodium. Modeling Sodium Fires. Modeling destruction of SNAP fuel rods on reentry into the earth atmosphere. Atomics International, Canoga Park, Calif.

1971- 1973- Participated-in the resolution of design issues as related to material behavior in the Breeder reactor environment. Atomic Energy Commission 1973 - 1978 Project Manager for the safety evaluation and testing of steam generators for liquid metal reactors. Managed the development of thermal -hydraulic computer codes such as COBRA.

ERDA/Department of Energy. Responsible for testing material compatibility and cavitation damage in sodium. Development of acoustic leak detection systems for sodium/water reactions.

1978 - 1982 Project Manager-for the development of materials and instrumentation for high temperature steam generators for fossil plants. Responsible for the resolution of issues relating to corrosion/erosion and NOx /SOx emissions, Department of Energy.

1982 - 2001 Program manager for the resolution of various, thermal hydraulics, material corrosion and safety issues primarily in relation to PWR steam generators. Nuclear Regulatory Commission.

Publications

In addition to numerous reports, I have published 15 papers in peer-reviewed technical journals in the areas of thermal-hydraulics, corrosion/ erosion, steam generator dose releases during accidents, steam explosions, sensors and ECM machining.

Peer Reviewed I "New Fiber Optic Based Technology for Automatic Tank Gauging", Sensors ,December 2006

2. "Distributed Fiber Optic Sensors for Leak Detection In Landfills", Proceeding of SPIE Vol 3541 (1998)

3. "Continuous Automatic Detection of Pipe Wall Thinning", ASME Proceedings of the 9th, International Conference on Offshore Mechanics and Arctic Engineering. Feb. 1990 4 "Iodine Speciation and Partitioning in PWR Steam Generators", Nuclear Technology, March 1990'

5. Comments on "Assessment of Steam Explosion Induced Containment Failures" Letter to the Editor, Nuclear Science and Engineering, Vol. 103, Sept. 1989

6. "Experience and Modeling of Radioactivity Transport, Following Steam Generator Tube Rupture', Nuclear Safety, 26,286, 1985

7. "Simplified Correlations for the Predictions of Nox Emissions from Power Plants". AIAA Journal of Energy, Nov.-Dec., 1979

8. "Grain Boundary Grooving of Type 304 Stainless Steel in Armco Iron Due to Liquid Sodium Corrosion", Corrosion, 27, No. 11, 428, 1971

9. "Corrosion of Type 316 Stainless Steel with Surface Heat Flux in 1200 Flowing Sodium",

Nuclear Engineering and Design, 12; 167-169, 1970

10. "Prediction of the One Dimensional Cutting Gap in Electrochemical Machining", ASME Transaction, J. of Engineering for Industry, p100 (1969)

11. "Electrochemical Machining- Prediction and Correlation of Process Variables", ASME Transactions, J. of Engineering for Industry, 88:455-461, (1966)

12. "Laminar Two-Phase Boundary Layers in Subcooled Liquids", J. of Applied Mathematics and Physics (ZAMP), 15, 388-399 (1964)

13. "Onset of Stable Film Boiling and the Foam Limit", International j. of Heat Transfer and Mass Transfer, 6; 987-989 (1963) ) (co-author) 14 "Operating Conditions of Bubble Chamber Liquids", The Review of Scientific Instruments, 34, 308-309. (1963); co-author

15. "Similar Solutions of the Turbulent Free Convention Boundary Layer for an Electrically Conducting Fluid in the Presence of a Magnetic Field," AIAA J. 1:718-719 (1965)

Not Peer Reviewed (Recent Publications Only)

I. New Fiber Optic Based Technology for Automatic Tank Gauging (ATG), NPRA - 2006 Reliability and Maintenance Conference, May 23-26, San Antonio, TX

2. Automatic Tank Gauging: A New Level of Accuracy; A New Device Promises Greater Accuracy for Custody Transfer by Combining Fiber- Optic Sensing with a Pressure.

Sensors Magazine, 12/01/06

3. PlasticOptical Fibers Sensors for Industrial Process Controls and Environmental Monitoring, POF World West 2007, June 25-27. 2007 List of Patents

1. Automatic Shut-Off Valve for Liquid Storage Tanks, 5,522,415

2. Method and Apparatus for Detecting the Presence of Fluids, 5,200,615

3. Sensors For Detecting Leaks, 5,187,366

4. Method for Monitoring Thinning of Walls and Piping Components 4,922,74

5. Method for Monitoring Thinning of Pipe Walls, 4,779,453

6. Looped Fiber Optic Sensor for the Detection of Substances (5,828,798)

7. Coated Fiber Optic Sensor for The Detection of Substances (5,982,959)

8. Method and Apparatus for Analyzing Information of Sensors Provided Over Multiple Waveguides (6,870,607)

Honors

i. Engineer of Distinction - Published by Engineers Joint Council

2. American men and Women in Science

3. The Blackwall Award for Machine Tools

4. Member Sigma-Xi Professional Activities I. Reviewed papers for the ASME Journal and the Journal of Sensors and Actuators

2. Taught a class on Diesel Engines at Montgomery College, Rockville, MD.

3. Served as a member of a Railroad Committee that development a standard for locomotive Fueling

4. Funded and sponsored research and development work at the Engineering Department of the University of Virginia. The research produced a novel method of measuring pipe wall thinning from erosion/corrosion

Riverkeeper Opposition to Entergy's Motion For Summary Disposition of Riverkeeper Technical Contention 2 (Flow-Accelerated Corrosion)

Riverkeeper TC-2: Attachment 4

l.m-inecrimg Report No.I.-1I-0LRD Rc Pie I of 105 Arfeg ENTERGY NUCLEAR E~ngineering Report Cover Sheet Engineering Report'

Title:

0,,vrtinu ELx perience Revijew Reporl Engineering Report Type:,

Ne~ E Revision 2 Catncelled C3 Superseded Applicable Site(S) rrI E iP2 IP3 JAF E I'Nm'S VY El wo El0

\\OI E A\ 02 FCH E GCI; N; E RL3S El WF3 1RN, N.. rElN/A:E.

Report Origin: Enter,, Elvetidor Vendor D~ocumntii Xo.

Quality-Related: E] Ncs ZNo Prepilred [by .rkrtijc% C, Taylor -.

r2':sPc"(ish e Fl niner (PI hil Nott te Sig~n fDesitrt \erifidl -

Daw:

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.. For ASME Section XI Code Program plans per ENN-DC- 20. if recuired

IP-RPT-06-LRD05 IPEC License Renewal Project IRevision 1 Operating Experience Review Report Page 10 of 105 Table 3.1.1 Operating Experience Applicable to Non-Class I Mechanical Systems Item Issue Evaluation CR-IP2- 200101924 - UHT-10-248 (auxiliary steam Loss of material is an aging effect 2001-01924 trap) is a bucket trap that has a plug on the identified inthe mechanical tools for top with an allen wrench center that has a carbon steel intreated water or steam, leak. The leak appears to be a through wall leak in the middle of the plug.

CR-IP2- 200101994 - Discovered excessive steam Loss of material is an aging effect 2001-01994 leaks on Dock Steam line, 5' section of identified inthe mechanical tools for Utility Tunnel. The area of one leak was a carbon steel intreated water or steam.

one foot section corroded almost completely through.

CR-IP2- 200102051 - Location: 15' south side of Loss of material is an aging effect 2001-02051 loading well by janitor supply cage. identified in the mechanical tools for carbon steel in treated water or steam.

Elbow in aux steam line leaking.

CR-IP2- 200102140 - Through wall piping leak on Loss of material is an aging effect 2001-02140 Main Steam line from 22A Moisture identified in the mechanical tools for Separator Reheater Vent Chamberto 26A carbon steel in treated water or steam.

Feedwater Heater approximately 1 foot from tie to MS line from 21A MSR Vent Chamber (leak located close to 26A FWH, near valve MS-645).

CR-1P2- 200102187 - The 2" City Water supply Loss of material is an aging effect 2001-02187 piping from the 12" City Water Header, in identified in the mechanical tools for the Unit 1 Water Factory, to the retired carbon steel in treated water.

Resin Storage Tank is CORRODED &

HAS 2 CLAMPS AND BLACK ELECTRICAL TAPE HOLDING IT TOGETHER.

CR-IP2- 200102451 - Through wall leak between Loss of material is an aging effect 2001-02451 valves 387 and 310 inside valve gallery identified in the mechanical tools for PAB. Noted fresh boron buildup on top of stainless steel in treated water.

piping in between 310and 387. Found no other source of leakage above the piping that could have dripped on the pipe.

.CR-IP2- 200102482 - The 1/2 pipe downstream of Loss of material is an aging effect 2001-02482 CT-843 connected to 3EX-10-1, route stop identified in the mechanical tools for 23b feed water heater drain. The pipe is carbon steel in treated water or steam.

welded to 3EX-10-1 and is leaking condensate around the weld.

LI _ _ _ _ _ _ _ _ _

IPEC License Renewal Project P i-RPT-o6-LRD05 Operating Experience Review Report Pagev12 of 105 Table 3.1.1 Operating Experience Applicable to Non-Class 1 Mechanical Systems Item Issue Evaluation CR-IP2- 200103046 - 21 Emergency Diesel Loss of material is an aging effect 2001-03046 Generator Fuel Oil Storage tank fill valve identified in the mechanical tools for cover iron frame is no longer attached to carbon steel in indoor air.

the concrete pad, repair as required, The iron frame is bent and rusted and should be replaced with new material.

CR-IP2- 200103608- While performing daily Loss of material is an aging effect 2001-03608 rounds found on 21 House service boiler, identified in the mechanical tools for soot blower drain line upstream of valve carbon steel in treated water and steam.

AS-1408 dripping. Could not pinpoint exact location of leak due to insulation/lagging on the pipe.

CR-IP2- 200103681 - Steam leak on the Loss of material is an aging effect 2001-03681.... crossunder inlet pipe to 21A Moisture identified in the mechanical tools for Separator Reheater has evidence of steam carbon steel in treated water and steam.

condensate dripping on the floor coming off the lagging. The leak is located at 53' turbine hall building, north of 21A MSR.

CR-IP2- 200103734 - While walking down up- Loss of material is an aging effect 2001-03734 coming jobs I noticed a steam leak on a identified in the mechanical tools for one inch line leaking from the one inch. carbon steel in treated water and steam.

union located between valve tag number, (HD&V 5EX-512 HDT LC-5004s root stop) and (HDTLC LC-5004s)

CR-IP2- 200103887 - There is aleak of several Loss of material is an aging effect 2001-03887 drops per second that appears to be identified in the mechanical tools for coming from the pipe cap on the down carbon steel in treated water and steam.

stream side of valve 5EX-35-15. The valve is located on the underside of Moisture Separator Drain Tank 21A's level controller (LC-1105S).

CR-IP2- 200104083 - Air leak from AOM-9. Found Loss of material is an aging effect 2001-04083 EDG building louvers open. Air leak may identified in the mechanical tools for be enough to keep these louvers open. No stainless steel in treated air.

tag found on air motor.

CR-IP2- 200104232 - 24A FWHTR outlet Loss of material and cracking are aging 2001-04232 temperature indicator thermowell has small effects identified in the mechanical tools leak. Repair/replace thermowelf as for stainless steel in treated water.

required.

[ ~

Operating

~~IPEC

~Page License Renewal Project Experience Review Report IP-RPT-06-LRD05 Rvso 1 Pev13iof 13 of 105 Table 31.1 Operating Experience Applicable to Non-Class 1 Mechanical Systems Item Issue Evaluation CR-IP2- 200104776 - While performing Pi-M2 VC Loss of material and cracking are aging 2001-04776 inspection found boron encrustation on effects identified in the mechanical tools the packing gland needs to be cleaned for for stainless steel in treated water.

valve 955D.

CR-IP2- 200104959 - The Auxiliary Condensate Loss of material and cracking are aging 2001-04959 return header just upstream of valve UW- effects identified inthe mechanical tools 88 near the Toolroom on 15 foot elevation for carbon steel or stainless steel in has a through the wall leak at the twelve treated water.

o'clock position. Please repair.

CR-IP2- 200105054 - On 5118/01, while attempting Loss of material is an aging effect 2001-05054 to perform a soot blow of 21 HSB, it was identified in the mechanical tools for noted that there was a through wall leak in carbon steel in treated water.

the piping upstream of AS-1408 condensate drain for the front soot lance on 21 HSB.

CR-IP2- 200105904 - Seal Oil Vacuum Pump Loss of material is an aging effect 2001-05904 identified in the mechanical tools for Oil sampled on the Seal Oil Vacuum Pump carbon steel or stainless steel in Gear Box indicating large amount of built lubricating oil.

up oxidized sludge. Oxidized sludge promotes corrosion and deterioration of the oil. The gearbox oil is changed every three months.

CR-IP2- 200105968 - While.doing a survey in the Loss of material is an aging effect 2001-05968 utility tunnel I noticed that the discharge identified in the mechanical tools for pipe to the river is scaled with rust in one carbon steel or stainless steel in treated section. This is the pipe that contaminated water.

the tunnel in the past.

CR-IP2- 200106470 - LCV-1127D has a through Loss of material is an aging effect 2001-06470 .wall leak. This is a large Heater Drain identified in the mechanical tools for Tank dump to 23 condenser. This valve is carbon steel in treated water, being isolated. 'Initiate work order to repair.

cR'-lP2- 200106476 - Hydrogen cooler #22 south Loss of material is an aging effect 2001-06476 section inlet relief valve SWT-62 located identified in the mechanical tools for on the east side of 36' near the Service stainless steel in raw water.

Water manual throttle valves has a service water through wall leak at elbow weld. f

IPEC License Renewal Project Operating Experience Review Report IPRP-0-LDO IPeRPi-06-LRD05 Revision I Page 14 of 105 Table 3.1.1 Operating Experience Applicable to Non-Class I Mechanical Systems Item Issue Evaluation CR-IP2- 200106740- 24 Service Water Pump Loss of material is an aging effect 2001-06740 Vacuum Breaker SWN-9-3 Failed its PMT identified in the mechanical tools for due to leak at threaded fitting at top of stainless steel in raw water.

valve body.

Reference CR# 200100463.

CR-IP2- 200107107- Following performing Loss of material is an aging effect 2001-07107 chlorination on Circulating Water Pump identified in the mechanical tools for bays 21,22, & 23, it was discovered that plastic in raw water.

PCV-7979 has evidence of leakage (residue on side of valve, residue stalagtite forming on bottom of valve, and residue on pump casing).

CR-IP2- 200107232 - LCV-1 127C Heater Drain Loss of material is an aging effect 2001-07232 Tank Large Dump Valve to 22 Condenser identified in the mechanical tools for has a through wall leak on the east side of carbon steel in treated water.

the valve body. This is the second of the three large dump valves to have a leak.

(LCV-1 127D is already isolated CR#01-06470)

CR-IP2- 200107951 - LCV-1 127D Heater Drain Loss of material is an aging effect 2001-07951 Tank Large Dump to 23 Condenser, has identified in the mechanical tools for through wall leak on piping located directly carbon steel in treated water.

below the valve.

CR-IP2- 200108270 - GT-3, # 4 basket fuel oil Loss of material is an aging effect 2001-08270 supply line coupling closest to the nozzle is identified in the mechanical tools for leaking atI drip/minute during Gas carbon steel in fuel oil.

Turbine operation, investigate and repair.

CR-IP2- 200109058 - While performing an Loss of material is an aging effect 2001-09058 Environmental/Safety tour of the Utility identified in the mechanical tools for Tunnel, it was discovered that the 20" Fuel carbon steel with outside air on external Oil Fill Line is being severely eroded by in surfaces, which is presumed to include leakage of "sweet" water. moisture.

CR-lP2- 200109241 - During the Annual Walkdown Loss of material is an aging effect 2001-09241 on the Gas Turbines it was found on the identified in the mechanical tools for I GT3 Blackstart diesel that its exhaust stack carbon steel in exhaust gas, indoor air or has a minor exhaust leak located at the Outdoor air.

joint between the expansion joint and the lower end of the muffler

IP-RPT-06-LRD05 IPEC License Renewal Project Revision I Revision 1

~Page Experience Review Report Operating 15 of 105 Table 3.1.1 Operating Experience Applicable to Non-Class 1 Mechanical Systems Item Issue Evaluation CR-IP2- 200109482 - #12 ignition oil pump is . Loss of material is an aging effect 2001-09482 leaking from the bottom of the pump identified in the mechanical tools for casing. carbon steel in fuel oil.

CR-IP2- 200109593 - DPI-5000S, 21 Service Loss of material is an aging effect 2001-09593 Water Strainer Differential Pressure low identified in the mechanical tools for side impulse line has a minor leak .at the carbon steel or stainless steel in raw threaded connection on the housing, this is water.

causing corrosion of surrounding components, repair same.

CR-IP2- 200109653'- There is a thru wall pipe leak Loss of material is an aging effect 2001-09653 downstream of AS-1076. Pipe is severely identified in the mechanical tools for corroded and needs to be changed from carbon steel in steam and treated water.

the steam tralp and to include the check valve and AS-1076.

CR-IP2- 200109659 - RW-132 heat exchanger 12 Loss of material is an aging effect 2001-09659 tube side drain and RW-126 heat identified in the mechanical tools for exchanger 1 tube side drain have both carbon steel or stainless steel in raw broken off the heat exchangers. The water.

threaded nipples corrode and rot away.

CR-IP2- 200109743 - Leaks exist at three locations Loss of material is an aging effect 2001-09743 on 22 House Service Boiler (22 HSB) at identified in the mechanical tools for the interface of the mud drum and Firebox carbon steel in steam and treated water.

outer casing. Each leak is approximately two drops per second.

CR-IP2- 200109797.- Hot water return inlet stop Loss of material is an aging effect 2001-09797 UH-344 to heat exchanger HE-1 in MOB identified in the mechanical tools for HVAC room is severely corroded and has carbon steel in treated water.

a packing leak.

CR-IP2- 200109821 - The 10" piping just below Loss of material is an aging effect 2001-09821 LCV-1 127C has a thru wall steam leak. identified in the mechanical tools for This leak is in addition to the thru wall body carbon-steel in treated water.

leak on the valve.

NOTE: This condition is the same as the steam leak on LCV-1 127D which is to be worked under 0 1-22963, CR-IP2- 200110925 - Request a more immediate Loss of material and cracking are aging 2001-10925 response to repair of Dock Steam. The effects identified in the mechanical tools condensate return line associated with this for stainless steel or carbon steel in steam is corroded and leaks badly. This is and treated water.

rendering Dock Steam out of service.

IPEC License Renewal Project IP-RPT-06..LRD05 RevisioRD0 Operating Experience Review Report Pagev16iof 1

• * *Page 16 of 105 Table 3.1.1 Operating Experience Applicable to Non-Class 1 Mechanical Systems Item Issue Evaluation CR-IP2- 200111779- In an effort to reduce the Loss of material is an aging effect' 2001-11779 effect of Flow Accelerated Corrosion in the identified in the mechanical tools for secondary piping, the Wet Steam Piping carbon steel in steam and treated water.

Replacement Project was created as part of the IP2 Flow Accelerated Corrosion (FAC) Program.

CR-IP2- 200111861 - The inside fish spray header. Loss of material is an aging effect 2001-11861 on #22 TSC has a thru wall leak at the identified in the mechanical tools for elbow just down stream of the stop valve stainless steel in raw water.

WW-103.

CR-IP2- 200200013 - The 2 inch Trough drain Loss of material is an aging effect 2002-00013 waste water line threaded fitting on 23 identified in the mechanical tools for Charging pump is leaking at a rate of 1 stainless steel or carbon steel in treated drip/I10 seconds at the 90 degree elbow water.

before the vertical section of piping causing a housekeeping issue in the cell.

CR-IP2- 200200818 - While performing Corrective Loss of material is an aging effect 2002-00818 Maintenance (NP-98-05617 Replace identified in the mechanical tools for Piping upstream of FP-2) there was stainless steel or carbon steel in treated excessive corrosion observed on the water.

inside of the fire piping. The wall thickness of the piping is heavily degraded.

CR-IP2- 200201055 The welded elbow Loss of material and cracking are aging 2002-01055 downstream of AS-1075 has a significant effects identified in the mechanical tools steam leak as well as a union downstream for stainless steel or carbon steel in of this elbow. There exists a deficiency-tag treated Water or steam.

on or around AS-1 075 however I was unable to read it due to steam impinging on the tag.

CR-IP2- 200201199 - Leak at end bell on CCC side Loss of material is an aging effect 2002-01199 of Heat Exchanger. Leak appeared during identified in the mechanical tools for isolation of heat exchanger to change out carbon steel in raw water.

zinc plugs.

CR-IP2- 200201457 - Drain plug for BFD-4-2 (26C Loss of material and cracking are aging 2002-01457 Feedwater Heater outlet stop) has a small effects identified in the mechanical tools drain plug leak. for stainless steel or carbon steel in treated water or steam.

IPEC License Renewal Project IP-RPT06-LRD05 Operating Experience Review Report page 17 of 105I Table 3.1.1 Operating Experience Applicable to Non-Class I Mechanical Systems Item Issue - Evaluation CR-IP2- 200201628- This condition was found Loss of material and cracking are aging 2002-01628 during SAO-141 Walkdown. Water is effects identified, in the mechanical tools leaking from a threaded cap connection for stainless steel or carbon steel in downstream of valve 5EX-23 onto floor. treated water or steam.

Valve 5EX-23 is a Heater Drain & Vent dump line header drain stop valve located on the 5' elevation of the turbine building.

CR-1P2- 200201820 - MSR-22A Vent Chamber line Loss of material and cracking are aging 2002-01820 drain stop leaks- by. It is located on the 15' effects identified in the mechanical tools el. by moisture pre-separator tank. for stainless steel or carbon steel in treated water or steam.

CR-IP2- 200202368 - The steam supplied wall Loss of material and cracking are aging 2002-02368 heater on the South wall of the Ignition Oil effects identified in the mechanical tools Tank Room has an elbow leak at the outlet for stainless steel or carbon steel in of the heater. Condensate was leaking treated water or steam.

onto the floor and under thetanks.

CR-1P2- 200202864 - During field inspections Loss of material is an aging effect 2002-02864 noted 21 Main Boiler Feed Pump suction identified ,inthe mechanical tools for piping had water dripping out of the carbon steel in treated water.

insulation about three feet above the pump casing. Possible through the wall leak on the suction piping of 21 MBFP.

CR-iP2- 200204664 - Insulation. needs to be, Loss of material and cracking are aging 2002-04664 removed from in between 5EX-4 and 5EX- effects identified in the mechanical tools 3 in order to identify possible thru wall leak for stainless steel or carbon steel in on extraction steam line. treated water or steam.

CR-IP2- 200204951 - Small steam leak located at Loss of material and cracking are aging 2002-04951 23B MSR inlet inspection/access port at effects identified in the mechanical tools north end of MSR 53' Turbine Hall. Leak is for stainless steel or carbon steel in located under lagging. Maximo work order treated water or steam.

1. 02-02851.

CR-1P2- 200205463 - SWN 77-6 has a thru wall Loss of material is an aging effect 2002-05463 leak at the vent valve. identified in the mechahical tools for stainless steel or carbon steel in raw water.

CR-tP2- 200205472 - There is a thru wall leak on Loss of material is an aging effect 2002-05472 the piping approx. 3 feet to the west FW- identified in the mechanical tools for 226. stainless steel or carbon steel in raw water.

- IPEC License Renewal Project IP-RPT-06-LRD05 Operating Experience Review Report 18 of 1 TagOperating Ee 18Aof 105 Table 3.1.1 Operating Experience Applicable to Non-Class I Mechanical Systems Item Issue Evaluation CR-IP2- 200205524 - A through wall leak has Loss of material is an aging effect 2002-05524 developed on 12 house tank fill pump identified in the mechanical tools for suction piping immediately downstream of stainless steel or carbon steel in treated suction valve FP-68.12 house tank fill water.

pump was already out of service via tagout 2000N-14395, which isolated the pump discharge.

CR-IP2- 200206004- The piping between WW-178 Loss of material is an aging effect 2002-06004 and PI-6987 has a 0,5 gpm leak when 28 identified in the mechanical tools for traveling screen is washing. The insulation stainless steel in raw water, needs to be removed to determine the location of the leak. Most likely the elbow weld is leaking.

CR-IP2- 200206358 - Noted during field Loss of material is an aging effect 2002-06358 inspections small leak (2-3 drops/minute) identified in the mechanical tools for on the suction piping going to #23 stainless steel in treated water.

Charging pump. Thru wall leak is down stream of valve 284 (suction stop) on weld just upstream of C-7 drain valve.

CR-IP2- 200207210 - During PM of R-46 four of Loss of material is an aging effect 2002-07210 the casing studs and nuts were found identified in the mechanical tools for unacceptable due to corrosion. Couplings carbon steel in condensation and indoor for the upper and lower manifolds are air.

unacceptable due to damaged threads.

CR-lP2- Found 22 HZFP (22 Hydrazine Feed Pump Loss of material is an aging effect 2002-07731 leaking at pump casing onto floor. About identified in the mechanical tools for 500 cc of dilute Hydrazine from Chemical carbon steel or stainless steel in steam addition tank has leaked onto floor. Pump and treated water.

was taken out of service and valves isolated, chemical spill tape was placed around tank.

CR-lP2- FAC (Flow Accelerated Corrosion) Loss of materialis an aging effect 2002-08136 component FAC-1B-VCD17 has wall identified in the mechanical toois for thickness readings below allowable limits carbon steel in steam and treated water.

per FAC procedure SE-SQ-12.318 (Tmin =

0.135", Tmeas = 0.110"). Component is a 3" 90-degree elbow directly downstream of valve HCV-5068B on the MSR.

IPEC License Renewal Project IP-RPT-06-LRDevision Page 19 of I05 Operating Experience Review Report "Table3.1.1 Operating Experience Applicable to Non-Class I Mechanical Systems Item Issue Evaluation CR-IP2- FAC (Flow Accelerated Corrosion) Loss of material is an aging effect 2002-08370 component FAC-2B-VCD39 has wall identified in-the mechanical tools for thickness readings below allowable limits carbon steel in steam and treated water.

per FAC procedure SE-SQ-12.318 (Trmin =

0.135", Tmeas = 0.134). Component is a 3" elbow directly downstream of valve MS-618.

CR-1P2- PI-M9 aboveground petroleum tanks Loss of material is an aging effect 2002-08676 inspection failed due to oil leaks. Main identified in the mechanical tools for boiler feed pump wrt IP2-02-02798, Main carbon steel in fuel oil.

turbine oil conditioner wrt IP2-02-02713, IP2-02-02714, 1P2-02-02794, IP2-.02-00349, AND CR200203880, 200201990, 200202090, AND 006360.

CR-IP2- Piping downstream of steam trap AST-20 Loss of material is an aging effect 2002-08823 is leaking. Leak seems to be coming from identified in the mechanical tools for coupling downstream of steam trap. carbon steel in treated water or steam.

Steam trap is located in front of 15' elev Tool Room.

CR-IP2- 22 Containment Spray Pump continues to Loss of material is an aging effect 2002-08858 show evidence of large amounts of copper identified inthe mechanical tools for in the oil from the pump reservoir. copper in lube oil.

Inspection was performed in July with no visible anomalies identified. Copper is still being generated from an unknown source.

CR-IP2- While examining the zinc anodes on #21 Loss of material is an aging effect 2002-09024 EDG JWC & LOC it was observed that the identified in the mechanical tools for recently replaced expansion joint SWN-66 stainless steel in raw water.

has a thru wall leak of less than one drop per min.

CR-1P2- Found 24 SWP Zurn strainer blowdown Loss of material is an aging effect 2002-09073 piping flange bolts badly rusted during identified in the mechanical tools for performance of PI-3Y13. This is the 3"-150 carbonmsteel or stainless steel in raw psig pressure boundary flange water.

downstream of the strainer and upstream of SWN-594. All the other strainers have stainless steel bolting.

IP-RPT-06-LRD05 IPEC License Renewal Project Revision I Operating Experience Review Report

• Page 20 of 105 Table 3.1.1 Operating Experience Applicable to Non-Class 1 Mechanical Systems Item Issue Evaluation CR-IP2- During performance of PI-3Y1 3 for 24 Loss of material is an aging effect 2002-09074 SWP epoxy delamination was found identified in the mechanical tools for downstream of SWN 3 along the entire carbonsteel or stainless steel in indoor spool piece from flange to flange. The air air.

pocket created by delamination is causing the discharge piping to corrode at an accelerated rate.

CR-IP2- Corrosion and evidence of thru wall Loss of material is an aging effect 2002-09076 leakage was observed on EDG 21 SW identified inthe mechanical tools for stainless steel expansion sleeve SWN stainless steel in raw water.

3. This examination was performed as part of the Extent of Condition response for CR 20002-09024 to inspect the lower SW expansion sleeves.

CR-IP2- Calculated wear rate(see EVAL# 15P- Loss of material is an aging effect 2002-09115 MST-24(b)) indicated the predicted identified in the mechanical tools for thickness (Tp) for component MST-24 will carbon steel in steam and treated water.

reach the component's minimum required thickness (Tmin).within the next operating cycle. It is recommended that the component be replaced.

CR-IP2- Valve 8978 has at least one stud that has Loss of material is an aging effect.

2002-09781 some amount of degradation found during identified in the mechanical tools for the Section Xl bolted Connection stainless steel in treated water.

-Inspection Program. The back side of the valve is inaccessible and therefore has not been inspected.

CR-IP2- 16" Flange face that mates to FCV-1 112 Loss of material is an aging effect 2002-09869 has an area of degradation approximately identified in the mechanical tools for 1/8" depth, 4-1/2" long around inner carbon steel, stainless steel, and nickel circumference at 8 o'clock position, and 1" alloy in raw water.

wide. This is on the west side flange of the valve.

CR-IP2- 18" lower flange that mates to SWN-39 has Loss of material is an aging effect 2002-09949 an area of concrete lining that is missing identified in the mechanical tools for I on the interior. The missing area of carbon steel in raw-water.

concrete is about a 3 inch width right near the flange face and extends about half way around the circumference of the pipe.

IP-RPT-06-LRD05 IPEC License Renewal Project Revision 1 Operating Experience Review Report Page 21 of 105 Table 3.1.1 Operating Experience Applicable to Non-Class I Mechanical Systems Item Issue Evaluation CR-IP2- Visual inspection performed of piping at Loss of material is an aging effect 2002-10043 location of SWN-2 which was removed for identified in the mechanical tools for a valve PM. This inspection revealed a carbon steel in raw water.

cement lining defect on the upstream flange at 7 o'clock position.

CR-1P2- There is a crack in the air line leadingto Cracking is an aging effect identified in 2002-10920 MPS-758 (MPS Tank B Non Return Inlet the mechanical tools for stainless steel in check valve). The crack is in the first treated air.

elbow upstream of the valve. MPS-758 is located in the 32' elev mezzanine of the Turbine Bldg on the north side under the HP Turbine.

CR-IP2- Today while conducting a test on the fire Loss of material is an aging effect 2002-10965 supply to the Service Center the pre test identified in the mechanical tools for flush discharged significant amounts of carbon steel in raw water.

rust and other debris. Such debris could potentially clog fire nozzles and damage equipment.

CR-IP2- #2 Fuel Oil Header in the utility tunnel is Loss of material is an aging effect 2002-11024 degraded. The lagging and flashing were identified in the mechanical tools for removed from the carbon steel fuel oil carbon steel with outside air on external header in the utility tunnel. surfaces, which is presumed to include moisture.

CR-IP2- The CPD sample cooler for the sodium Loss of materal is an aging effect 2002-11154 and hydrazine analyzer has a shell leak. identified in the mechanical tools for This cooler has a service water cooling stainless steel or copper alloys in treated supply. water.

CR-IP2- The Boric Acid Building Make-up Air Unit Loss of material and cracking are aging 2002-11159 Heater Coil is leaking. UH-684 is closed effects identified in the mechanical tools and water is still coming out of the base of for stainless steel or copper alloys in the fan and forming a puddle on the floor. treated water, or steam.

The water then seeps through the floor and puddles on the lower elevation.

CR-IP2- - Extraction Steam line to EST-18 down Loss of material is an aging effect 2002-11169 stream of 3EX-37-4 is leaking from under identified in the mechanical tools for the insulation and has increased from the carbon steel in treated water or steam.

original report (see WRT-IP2-02-01676, 10/4/02). There is steam and water coming from the insulation at one end and water dripping from the other.

IPEC License Renewal Project IRePTv0isnLR0 Operating Experience Review Report aev22iof 1 Page 22 of 105 Table 3.1.1 Operating Experience Applicable to Non-Class 1 Mechanical Systems Item Issue Evaluation CR-IP2- At the union to 26B Feedwater Heater low Loss of material is an aging effect 2002-11194 level column there is a pinhole leak in the identified in the mechanical tools for weld. carbon steel in treated water or steam.

CR-IP2- Found pin hole leak thru a weld on valve Loss of material is an aging effect 2002-11229 5EX-48-1, HDT Dump To Cond. 22 Drain identified in the mechanical tools for Stop, on 5ft. of the Turbine Hall. This carbon steel in treated water or steam.

condition could have possible dissolved oxygen level increase.

CR-IP2- Drain valve 5EX-48-1, the drain on LCV- Loss of material is an aging effect 2002-11266 1127C (HDT large condenser dump to 22 identified in the mechanical tools for condenser) was reported in CR carbon steel in treated water or steam.

200211229 to have a pin hole leak in the weld.

CR-1P2- There is approximately a 1 drop per Loss of material is an aging effect 2002-11594 second leak upstream of SWT-47-10 (22 identified in the mechanical tools for Hydrogen Cooler North Section Vent stainless steel in raw water.

Stop). The leak is dripping from the first elbow Out of the 22AHC hydrogen cooler.

CR-IP2- LW-828 Sphere Foundation pump Loss of material is an aging effect 2003-00003 discharge drain valve upstream piping is identified in the mechanical tools for corroded. Failure of this pipe will cause carbon steel or stainless steel in raw CSB 14' to be flooded. LW-828 is where water.

the-back-up Air Driven pump discharge is connected.

CR-IP2- Attempted to flush 21 Condenser Vacuum Loss of material and cracking are aging 2003-00088 Pump moisture separator tank. First flush effects identified in the mechanical tools brought down the sodium to 9 PPB from 40 for stainless steel in steam and water.

PPB.

CR-1P2- Strainer downstream of AS-1261, Cracking is an aging effect identified in 2003-00341 atomizing steam to 22 HSB, failed due to a the mechanical tools for carbon steel in through wall crack from the bottom threads steam and treated water.

to middle of body. This failure caused the room to fill with steam while I &C personnel were in room troubleshooting 21 HSB.

CR-1P2- During the restoration of the unit 1 dock Loss of material and cracking are aging 2003-00587 steam header the following leaks were effects identified in the mechanical tools identified in the utility tunnel AS-27 had a for carbon steel or stainless steel in steam leak on a welded union. The dock steam and treated water.

aux condensate header in the utility tunnel had a pinhole leak.

IP-RPT-06-LRDO5 IPEC License Renewal Project Revision 1 Operating Experience Review Report Page 23 of 105 Table 3.1.1 Operating Experience Applicable to Non-Class 1 Mechanical Systems Item Issue Evaluation CR-IP2- 24 inch service water lines 405 and 409 Loss of material is an aging effect 2003-00941 have corrosion buildup near the tops of the identified in the mechanical tools for pipes. The ceiling of the steam generator carbon steel with condensation on blowdown tank room shows no evidence of extemal surfaces.

leakage directly above the pipes. -

CR-iP2- A through-wall leak Was found on the Loss of material is an aging effect 2003-02016 stator winding cooling water system. The identified in the mechanical tools for leak is on line 2'YRCF at 45 degree elbow stainless steel in treated water.

just North of the staircase near the weir.

Presently about one drop per second is leaking and appears to be increasing.

CR-IP2- Lube oil valve, LO-1, outlet flange leaks. Loss of material is an aging effect 2003-02020 Documented under PI-M9 (DEC tank identified in the mechanical tools for inspection), carbon steel in lube oil, CR-IP2- 21 House Service Boiler steam drum Loss of material is an aging effect 2003-02310 leaking slightly. The water is evaporating identified in the mechanical tools for before it teaches the floor. carbon steel in steam and treated water.

CR-IP2- Stearn Generator. Blowdown Tank outlet Loss of material is an aging effect 2003-02794 pipe down stream of SWN-53 has a small identified in the mechanical tools for through wall leak at the weld where the carbon steel in steam and treated water.

pipe is connected to the Service Water Outlet. Leak is a couple of drops per minute.'

CR-IP2- Noted through wall leak at elbow Loss of material is an aging effect 2003-02798 downstream of MS-102-63 (MST-45 inlet identified in the mechanical tools for stop). Insulation has been removed carbon steel in steam and treated water.

previously due to water accumulation in area of MS-102-63.

CR-IP2- Request for carbon steel bolt inspection. Loss of material is an aging effect 2003-02870 identified in the mechanical tools for During the performance of a safety carbon steel.in outdoor air.

injection pump surveillance, we observed that the carbon steel flange bolts for FE-950 (Recirculation to refueling water storage tank) are rusted.

CR-IP2- During tours noted a thru wall steam leak- Loss of material and cracking are aging 2003-03384 just up stream of MS-20B on 22 Main effects identified in the mechanical tools Steam lead 36' elevation north end of for carbon steel in steam and treated Turbine Hall in overhead, (PT-1t34-3 root water.

stop)

IPEC License Renewal Project IPRPTe0viLi0o 5 Operating Experience Review Report PaRe 24 of 105 Table 3.1.1 Operating Experience Applicable to Non-Class I Mechanical Systems Item Issue Evaluation

__ L CR-IP2- An epoxy coating defect was found on Loss of material is an aging effect 2003-03849 21 EDLC when performing the 6 month identified in the mechanical tools for clean/inspect PM per work order IP2 carbon steel in raw water.

42966. The defect is approximately a 1 inch long by 1/16 inch wide chip in the epoxy at the under side of the channel end divider plate.

CR-IP2- There is a minor steam leak just upstream Loss of material is an aging effect 2003-04031 of MSR-29 (21A MSR LP Inlet Press Root. identified in the mechanical tools for Stop) at a flanged connection. The leak is carbon steel in steam and treated water.

evident from the top -and bottom of the flange (east side) through the insulation.

CR-P2- WO IP202461 and CR 200304031 written Loss of material is an aging effect 2003-04633 on 6/22/03 press describes turbine exhaust)the to LP 21Asteam MSR inlet (hi identified in the mechanical tools for flange carbon steel in steam and treated water.

leak. The leak appears to have worsened.

CR-IP2- A rusty nipple was found to be leaking on Loss of material is an aging effect.

2003-05306 the bottom of the 10-inch Service Water identified in the mechanical tools for Return line for the station EDG's just carbon steel in raw water.

upstream of the 1176 valves. It is believed that the nipple used to belong to SWN 1.

CR-IP2- During the tagout of 11 fresh water cooling--. Loss of material and cracking are aging 2003-06224 heat exchanger to replace drain-valve RW- effects identified in the mechanical tools 127 under work order IP2-02-04630, it was for stainless steel or copper in raw water discovered that 11 fresh water heat or treated water, exchanger has tube leakage.

CR-IP2- During the performance of,changing out Cracking is an aging effect identified in 2003-06567 the zincs and endbell gasket on 23SIP the mechanical tools for carbon steel or lube oil cooler under work order 03-19020, stainless steel in treated water.

a small crack was found in the lower zinc hole. The crack was thru wall and down the length of the threads.

CR-IP2- Ultrasonic thickness reading taken on line Loss of material is an aging effect 2004-00213 405, outiet piping from #21 CCWHT ETX identified in the mechanicat tools for was found to be below 87.5% (.328") of carbon steel in raw water or treated water.

the nominal wall. Reading as low as .250" were observed on the first elbow downstream from SWN-35.

_ _ ,, _ _ __ J __ ___

IPEC License Renewal Project IP-RPT-06-LRDv05 Operating Experience Review Report Pae 25 of 105I Table 3.1.1. Operating Experience Applicable to Non-Class 1 Mechanical Systems Item Issue Evaluation CR-IP2- Replacement piping and Victualic coupling Loss of material is an aging effect 2004-01401 on city water line, 43' Unit 1 Utility Tunnel identified in the mechanical tools for is extremely corroded. This is due to the carbon steel with outside air on external same ground water action that surfaces, which is presumed to include necessitated the original piping moisture.

replacement.

CR-IP2- Section of pipe upstream of valve SWN- Loss of material is an aging effect 2004-01738 62-4 is coated with rust. Location is the identified in the mechanical tools for bottom of the pipe between the 15' & 2nd carbon steel with condensation on elbow downstream of the service water external surfaces.

header.

CR-IP2- There is a pin hole leak on 21 SJE-C first Loss'of material is an aging effect 2004-02281 stage ejector for 21 SJAE located about 6 identified in the mechanical tools for inches below the elbow going to SJAE carbon steel in steam and treated water.

condenser.: The leak is a steady stream and has created a 2 scfm air leak.-.

CR-IP2- - During Flow Accelerated Corrosion (FAC) Loss of material is an aging effect 2004-02954 examination (WO IP2-03-26606) FAC point identified in the mechanical tools for 214-25P, wall thinning was noted. carbon steel in steam and treated water.

CR-IP2- Air In-Leakage is elevated at Unit 2. Latest Loss of material is an aging effect 2004-04010 air in-leakage results from 8/29/04 indicate identified in the mechanical tools for a total of 9.85 scfmý (21 Condenser air in- carbon steel in steam and treated water.

leakage - 7.5 scfm, 22 Condenser air in-

.leakage - .65 scfm and 23 Condenser air*

in-leakage - 1.7 scfm)

CR-IP2- While flushing 22 BATP prior to hanging Loss of material is an aging effect 2004-04011 PTO 2-CVCS-22BATP identified in the mechanical tools for REBUILDNARIOUS WORK REV 0-0, stainless steel in treated water.

water was noted coming out of the insulation under valve 355B.

CR-IP2- During the Service Water Radiography of Loss of material is an aging effect 2004-04446 Line 410, Weld F-1574, one area of identified in the mechanical tools for degradation in the form of erosion was carbon steel in raw water.

identified. The area of erosion measured approx. 1"wide by 2" long.

CR-IP2- Service water is leaking from the nipple Loss of material is an aging effect 2004-04556 downstream of valve SWT 823 which is on identified in the mechanical tools for the outlet side of HPFW sample cooler at carbon steel or stainless steel in raw the SWAP. water.

IP-RPT-06-LRDO5 IPEC License Renewal Project Revision I Operating Experience Review Report Page 26 of 105 Table 3.1.1 Operating Experience Applicable to Non-Class I Mechanical Systems Item Issue Evaluation CR-IP2- Main steam thru wall leak downstream of Loss of material is an aging effect 2004-04565 valve MS-667-X1 Inlet Isolation Valve on identifiedin the mechanical tools for FT-5058 on 23A MSR. This is located on 'carbon steel in steam and treated water.'

the south end of 23A MSR on the Main Steam Inlet piping.

CR-IP2- While performing 2Y inspection of the CCR From the CR description, it does not 2004-04691 HVAC UNIT21 MTR under WO IP2 appear that either of the known cracking 64800 it was discovered that the flare nut mechanisms for bolting (stress corrosion on the TXV equalizing line has a crack its cracking and fatigue) was present. Since entire length and thru wall, no other examples of cracking of non-Class 1 bolting materials was found, this isolated case is judged to reflect a manufacturing defect in this flare nut.

CR-IP2- During UT inspection.of component.MS- Loss of material .is an aging effect 2004-05358 1B26 (90 ELBOW) in the main steam line identified in the mechanical tools for wall thinning was detected below the - carbon steel in steam and treated water.

administrative screening criteria of 70% of nominal wall thickness. The nominal thickness and the screening criteria of the component !is.0.432.

CR-IP2- CR written to document results of Loss of material is an aging effect 2004-05794 evaluation performed on piping between identified in the mechanical tools for valves 6EX-3 and 6EX-4, Extraction steam -carbon steel in steam and treated water.

non-return check valves for 26FWHR When the valves were opened up for inspection, a rust bloom was found in bottom of pipe between the two valves.

CR-IP2- During performance of PWT# IP2 Loss of material is an aging effect 2004-06150 15373, Inservice inspection for leakage of identified in the mechanical tools for various service water system piping, carbon steel with condensation on valves, and components, identified the external surfaces.

following; On 22 EDG Service Water Supply from the 1-2-3 header, located on a horizontal piping run upstream of SWN 4, there is a considerable build up of rust on the underside of the pipe.

CR-IP2- Chemical trends indicate an active Loss of material is an aging effect 2004-06162 corrosion mechanism in the Unit 2 CCW. identified in the mechanical tools for Copper and iron concentrations have carbon steel and copper in treated water.

increased significantly.

IPC e R a PIP-RPT-06-LRD05 IPEC License Operating Renewal Experience ReviewProject Report Revision Page I 27 of 105 Table 3.1.1 Operating Experience Applicable to Non-Class 1 Mechanical Systems

.....Item Issue Evaluation CR-1P2- This is to record and track the as-found *Loss of material is an aging effect 2004-06238 condition of the main boiler feed water identified in the mechanical tools for pump lube oil coolers 22FPLOC and carbon steel in raw water, lube oil and 21FPLOC. There was some corrosion indoor air.

damage on the channel heads of both of

' them.

CR-IP2- During the Extent Of Condition inspection Loss of material is an aging effect 2004-06741 of the Service water line welds to the identified in the mechanical tools for EDGs today, it was determined that the 6" carbon steel in raw water.

line from the 1-2-3 header to 21 EDG has a weld below minimum thickness that will need to be removed and replaced.

CR-IP2- Flange below LC-5206-2S is leaking. Loss of material and cracking are aging 2004-06830 effects identified in the mechanical tools for carbon or stainless steel in treated water.

CR-1P2- The preliminary UT reports for the 9 welds Loss of material is an aging effect 2004-06776 upstream of valve SWN-62-6 on the 1-2-3 identified in the mechanical tools for header of the 23 EDG has indications carbon steel in raw waer.

below the minimum wall calculated.

CR-IP2- Unit Heater 246 has a steam leak in the Loss of material and cracking are aging 2004-06796 coil area. effects identified in the mechanical tools for copper or stainless steel in steam and treated water.

CR-IP2- During a routine PM of Vacuum Breaker Loss of material on bolting is an aging 2004-06847 SWN-9-3 (IP2-02-32450) the nuts and effect identified in the mechanical tools for studs attaching the Stainless Steel elbow carbon steel or stainless steel bolting with to the 24 Service Water discharge header condensation on external surfaces.

was found to be severely corroded. No leakage is present.

CR-1P2- Through Wall leak on weld for CD-98-1. Loss of material is an aging effect 2005-00162 21 MBFP suction line vent valve. Leak can identified in the mechanical tools for be isolated by removing 21 MBFP from carbon steel in steam and treated water, service and applying PTO.

CR-IP2- Flange upstream of MS-1064 has a steam Loss of material is an aging effect 2005-00294 leak. identified in the mechanical tools for carbon steel in steam and treated water.

IPEC License Renewal Project IP.RPT-06-LRD05 Revision 105 Operating Experience

... ... Report Review Page 30 of 105 Table 3.1.1 Operating.Experience Applicable to Non-Class I Mechanical Systems Item Issue Evaluation CR-IP3- Durng an erosion/corrosion examination Loss of material is an aging effect 2001-01045 wall thinning was noted on piping identified in the mechanical tools for downstream of HD-LCV-7003. This carbon.steel in steam and treated water.

inspection was required as the valve is leaking and was noted by performance test personnel via PFM-59.

CR-IP3- During an erosion/corrosion examination Loss of material is an aging effect 2001-01096 (WR 00-04379-07), wall thinning was identified in the mechanical tools for noted on MSR Vent Chamber Drain piping carbon steel in steam and treated water.

downstream of MSR 32B, located 2'6" south and 11'6" west of F/20, approx. el.

45'.

CR-IP3- During an erosion/corrosion examination, Loss of material is an aging effect

.2001-01285 (WR 00-04379-09, 01-PT-08), wall thinning identified in the mechanical tools for was, noted on piping downstream of valve carbon steel or stainless steel in steam MS-HCV-146-2. The inspection was and treated water.

required as a pinhole leak was discovered at a weld in upstream piping, and similar valves are cur CR-IP3- During an erosion/corrosion examination, Loss of material is an aging effect 2001-01322 (WR 00-04523-02, 01-PT-24) wall thinning identified in the mechanical tools for was noted on piping downstream of Main carbon steel in steam and treated water.

Steam Trap MST-80 (Main Steam Balancing Line).

CR-1P3- During R09, R10, and pre-R 11 NRC GL Loss of material is an aging effect 2001-01514 89-13 NDE inspections of insulated carbon identified in the mechanical tools for steel Service Water piping in the VC, a carbon steel in indoor air.

condition has routinely been found of heavy metal exfoliation on the exterior of the 10" FCU supply and return lines.

CR-IP3- During the Generic Letter 89-13 Loss of material is an aging effect 2001-01593 inspections, location EOC-26, on the 24" identified in the mechanical tools for line 408 in the room with the rock area, carbon steel or stainless steel in raw was found to have wall thinning. Minimum water.

code thickness was. 151"' while a 1" length was found to be 0.132".

CR-IP3- During inspections of the fan cooler units, Loss of material is an aging effect 2001-01749 pin hole leakage or evidence of pin hole identified in the mechanical tools for leakage was found on six of the ten valves carbon steel or stainless steel in raw

'that serve as isolation valves to the fan water.

cooler unit motor coolers. The valves in question are: SWN-520; SWN-521; SWN- i 523.

IPEC License Renewal Project IP-RPT-06-LRDO5 Revision Operating Experience Review Report Page 31 of 105 Table 3.1.1 Operating Experience Applicable to Non-Class I Mechanical Systems Item Issue Evaluation CR-IP3- A forced plant outage was necessary in Loss of material is an aging effect 2001-01887 Jan. 1997 due to feedwater heater tube identified in the mechanical tools for leaks in the #31 FWH's. Most of the tube copper alloy or carbon: steel in steam and damage found was in the form of OD treated water.

thinning at the bottom of the inlet passes.

CR-IP3- No piping replacement is required. Loss of material is an aging effect 2001-01921 identified in the mechanical tools for During an erosion/corrosion examination, carbon steel in steam and treated water.

(WR 00-04521-01, 01-PT-5), wall thinning was noted on three (3) piping segments downstream of MS-PCV-1 152 and MS-196.

CR-IP3- No piping replacement required. Loss of material is an aging effect 2001-01985 identified in the mechanical tools for During an erosion/corrosion examination, carbon steel in steam and treated water.

(WR 00-05234-09, RHD-02.6B.-OIE), wall thinning was noted on an 8" elbow downstream of RHD-LCV-1 105B.

CR-1P3- At the 5/15 day to night SW (Service Loss'of material is an aging effect 2001-02124 Water) turnover, dayshift reported that identified in the mechanical tools for during the extent of condition flange face nickel alloy or stainless steel in raw water.

inspection the engineer noticed a missing piece of concrete liner on the pipe near the.

flange.

CR-IP3- During the Service Water ISLT the Loss of material is an aging effect 2001-02319 following items were noted: identified in the mechanical tools for carbon steel or stainless steel in raw PID 01065 - SWT-238 Blowdown Hx 4 water.

relief valve inlet piping leak.

PID 01067 - SWT-80 31 Exciter Air Cooler Inlet Isol. pipe leak.

PID 01068 - 31 MBFP Oil Cooler head has small leak.

CR-IP3- A'pin-hofe type leak was discovered just Loss of material is an aging effect 2001-02320 downstream of the downstream flange-to- identified in the mechanical tools for pipe weld at valve SWT-24. Leak rate is carbon steel or stainless steel in raw approx. 2-3 drops/sec. Leak is in a non- water.

safety-related, non-ISI section of the

,service water system.

IPEC License Renewal Project IP-RPT-06-LRD05 Operating Experience Review Report-PRev32iof Revision'lI 1 TPage 32 of 105 Table 3.1.1 Operating Experience Applicabl e to Non-Class I Mechanical Systems Item Issue Evaluation CR-0P3- PID 03521 stated: Loss of material is an aging effect 2001-02324 identified in the mechanical tools for Boron buildup / leak on Swagelok between carbon steel or stainless steel in treated SP-AOV- 956c and SP-AOV-956d, where water.

IVSWS ties on PZR liquid space sample line.

CR-IP3- Main Generator H2 leakage is above the Loss of material is an aging effect 2001-02419 action limit of 500 SCFD. Based on the identified in the mechanical tools for last 3 days the trend is up, with leakage carbon steel, stainless steel or copper increasing from 600 CFD to 900 CFD. alloys in raw water.

CR-lP3- Plant personnel discovered that an elbow Loss of material is an aging effect 2001-02489 on a 2" drain line from the 1A (northeast) identifiedin the mechanical tools for moisture preseparator to the heater drain carbon steel in steam and treated water.

tank is leaking steam.. Elbow is located about halfway between the line isolation valve MS-125-3 and the check valve MS-126-3.

CR-IP3- While measuring air in leakage on 32 Loss of material is an aging effect 2001-02534 condenser, it was observed that on 32 Air identified inthe mechanical tools for Ejector Loop Seal Check Valve CV-49 had carbon steel in steam and treated water.

a thru wall leak. Leakage thru the valve was approx. one (1) drop every 4 seconds.

CR-IP3- 112" to 1 thick buildup of corrosion " Loss of material is an aging effect 2001-02567 products was found on the inside of valve identified in the mechanical tools for bodies removedfrom MW-337 and MW- carbon steel in treated water.

338 under corrective maintenance WRs 00-02670-00 and 00-02672-00.

CR-1P3- While performing RE-CCI-030 "Electrical Loss of material is an aging effect 2001-02620 Generator Hydrogen Survey" the chemistry identified in the mechanical tools for technician found a significant leak around carbon steel, stainless steel and copper the bottom of 32 hydrogen cooler, alloy in raw water.

CR-IP3- During a routine Shift Manager tour 5HD Loss of material is an aging effect 2001-02710 5 was found leaking. The valve, '33A identified in the mechanicaltools.for Moisture Separator Drain Tank to HDT" carbon steel in steam and treated water.

check valve has a through wall leak on the side of the valve.

IPEC License Renewal Project IP-RPT-06-LRD05 Operating ExperienceReview Report .. Revision I OPage 33 of 105 Table 3.1.1 Operating Experience Applicable to Non-Class I Mechanical Systems Item Issue -. - Evaluation CR-IP3- During rounds, NPO discovered a small Loss of material is an aging effect 2001-02751 pinhole, through-wall leak in the service .. identified in the mechanical tools for water pipe header to the CCW heat carbon steel or stainless steel in raw exchangers. This hole appears to be at water.

the toe of the weld on the cross-tie tee connection.(between valves SWN-31 and SWN-33-2.

CR-lP3- During routine rounds the conventional Loss of material is an aging effect 2001-02817 NPO identified a small leak on the MST-64 identified in the mechanical tools for strainer. carbon steel in steam and treated water.

CR-IP3- While replacing 31 Potable Water Booster Loss of material is an aging effect 2001-03181 pump which had a through wall leak on identified in the mechanical tools for the casing, the mechanics bumped into the carbon steel or stainless in steam and adjacent 32 Potable Water Booster pump. treated water.

The discharge line on the pump completely sheared off probably due to corrosion.

CR-lP3- During removal of a PTO, an NPO Loss of material is an aging effect 2001-03440 discovered small service water leaks on identified in the mechanical tools for 32A and 32B condenser heads at the carbon steel in raw water.

piping welds. The leaks were approximately 2 to 6 drops/minute.

CR-IP3- Pinhole service water leak discovered on Loss of material is an aging effect 2001-04148 outlet of piping from 33 FCU. identified in the mechanical tools for carbon steel or stainless steel in raw The leak is approx. 1 drop per minute water.

between the containment wall and the Containment isolation valve.

CR-IP3- Eddy current inspections were performed Loss of material is an aging effect 2001-04449 on the tube side (Service Water side) of identified in the mechanical tools for the #31 &#32 CCW heat exchangers as copper alloy in raw water.

part of scheduled PMs under WRs 99-04460-01 &99-04461-01. In both. heat exchangers, ID corrosion pitting was found resulting in the plugging of 2 tubes in #31 HTX and 5 tubes in # 32 HTX, CR-lP3- During a walkdown, the pipe sleeve for Loss of material is an aging effect 2002-00068 Weld Channel Zone 4A was found identified in the mechanical tools for corroding in the drain trench. The sleeve carbon steel or stainless steel in raw for this flow-thru test station protects the water.

embedded weld channel and piping as shown on dwg. 9321-F-70333, Detail No.

3.

IPEC License Renewal Project Revision IP-RPT'06"LRDo 15 Operating Experience Review Report Page 35 of 105 Table 3.1.1 Operating Experience Applicable to Non-Class I Mechanical Systems Item Issue Evaluation, CR-IP3- The CityWater Line that leads to the.EDG Loss of material is an aging effect 2002-02254 Expansion Tanks is corroded on the identified in the mechanical tools for outside. The corroded section is just as it carbon steel with outside air on external leaves the wall in the valve pit in the EDG surfaces, which is presumed to include Valve Room. The corrosion has been moisture.

caused by occasional discharges from a vacuum breaker.

CR-IP3- One through wall pin hole leak and one Loss of material and cracking are aging 2002-02751 through wall 2" circumferential crack on the effects identified in the mechanical tools body weld were found on the CT-LCV- for carbon steel in treated water.

1158-2. This Valve is CAT I and Seismic Class I.

CR-IP3- The following conditions were found during Loss of material is an aging effect 2002-02793 replacement of 36 CWP Motor cooling coil identified in the mechanical tools for under WO# 13-020087100: stainless steel in raw water.

• Numerous corrosion-induced pinhole leaks were noted during as-found testing of the installed stainless steel cooling coil.

CR-IP3- Steam trap EST-4 downstream piping "T" Loss of material is an aging effect 2002-02886 has pinhole steam leak, identified in the mechanical tools for carbon steel in steam and treated water.

CR-IP3- Service Water leakage discovered at Loss of material is an aging effect 2002-03132 threads where SWT-63-1, 3, -4, -5, and -6 identified in the mechanical tools for (Carbon Steel) threads onto the Bus-Duct - carbon steel and stainless steel in raw Cooling piping (Stainless Steel). water.

CR-IP3- A steam leak was identified on the 16" Loss of material is.an aging effect 2002-03263 drain line from the moisture pre-separators identified in the mechanical tools for to the heater drain tank. carbon steel in steam and treated water.

CR-IP3- Found pinhole leak on weld upstream of Loss of material is an aging effect 2002-03622 SWN-34-1 (inlet to 31 CCW heat identified in the mechanical tools for exchanger). carbon steel in raw water.

I..

CR-IP3- A leak was identified on the 31 sparging Loss of material is an aging effect 2002-03811 pump at the seal water connection tap. identified in the mechanical tools for carbon steel or stainless steel in raw

[water.

IP-RPT-06-LRD05 IPEC License Renewal Project Revision 1 Operating Experience Review Report Page 37 of 105 Table 3.1.1 Operating Experie.nce Applicable to Non-Class I Mechanical Systems Item Issue Evaluation CR-IP3- Engineering area for improvement Loss of material and cracking are aging 2002-05086 identified by WANO team: Long term effects identified in the mechanical tools degradation of the service water system for carbon steel and stainless steel in raw and of the Circulating Water Pump LCI water.

drives has challenged operators. This has been caused, in part, by the lack of comprehensive and aggressive CR-IP3- .34 MSIV Flange is leaking water/steam Loss of material, is an aging effect 2003-00409 from its west side and leaking steam (2 identified in the mechanical tools for feet steam plume) from its east side. The carbon steel in steam and treated water.

top 2 most west bolts are also leaking water/steam slightly, CR-IP3- During FIN investigation of WRT IP3 Loss of material is an aging effect 2003-00423 01697 City Water line 001-JND-6" was identified in the mechanical tools for found to have a slight leak. After further carbon steel in treated water.

investigation it was determined that an approx.. 30' section of this pipe should be replaced.

CR-IP3- . The 31 PAB Heating Coil has developed a Loss of material and cracking are aging 2003-00508 leak and was removed'from service. The effects identified in the mechanical tools leak Was a 3 foot steam plume and filled for stainless steel or copper alloys in the area with approximately 3: inches of steam and treated water.

standing water.

CR-IP3-, Brass plug between SWN"123 and PCV- Loss of material is an aging effect 2003-00556 1271-2 galvanically corroded to SS identified in the mechanical tools for bushing. Problem discovered during stainless steel or copper alloys in raw performance of 3PT-R1 85B. Plug needs water.

to be removed and replaced with like sized plug of SS material.

CR-IP3- During a FAC examination (WO 13- Loss'of material is an aging effect 2003-01071 ,010447602, 03-PT-03), wall thinning was identified in the mechanical tools for noted on an elbow downstream of VCD- carbon steel in steam.

PCV-7009 (32A MSR); specifically the elbow downstream of the Westinghouse control section at the entrance to the 31 condenser.

CR-IP3- Continuous Chlorination tank appears to Loss of material is an aging effect 2003-01176 be degrading. Pieces of fiberglass coating identified in the mechanical tools for found floating in tank. Within the last week carbon. steel, stainless steel or plastic in the continuous chlorination system ' treated water.

became plugged with material.

IPEC License Renewal Project IP-RPT-06-LRDe O Operating Experience Review Report RPage3vof 105 Table 3.1.1 Operating Experience Applicable to Non-Class I Mechanical Systems.

Item Issue Evaluation CR-IP3- During inspection of the Sodium Loss of material is an aging effect 2003-01186 Hypochlorite (NaOCI) tank, it was noted identified in the mechanical tools for that bits of whatappeared to be pieces of carbon-steel, stainless steel or plastic in fiberglass resin was found floating in the treated water.

tank. It appears that the tank may be degrading and is likely related to the recent clogging.

CR-IP3- During a FAC examination (WO IP3 Loss of material is an aging effect 2003-01327 23675,,03-PT-25), wall thinning was noted identified in the mechanical tools for on piping downstream of valve 5HD-LCV- carbon steel in steam and treated water.

1107 (31B MS Drain Tank drain)at the Drains Collecting Tank.

CR-IP3- During inspection of 31 EDG east and west Loss of material is an aging effect 2003-01346 air start systems i.e. air start motor, carbon identified in the mechanical tools for steel pipe, pressure regulators and carbon steel or stainless steel in treated strainers, rust particles were found in the air.

east strainer cap and a small amountof water was found in the west air regulator.

CR-iP3- Nondestructive examination of Service Loss of material is an aging effect 2003-01362 Water erosion corrosion location IS-19 identified in the mechanical tools for (line # 1086) identified wall thickness carbon steel or stainless steel in raw readings below the acceptance criteria water.

(0.135") of work order IP3-02-21094. Two localized areas of degradation below the criteria were identified.

orCR-IP3- The sodium hypochlorite tank was Loss of material is an aging effect 2003-01366 inspected and a three and a half ft crack identified in the mechanical tools for was found on the interior wall. In addition carbon steel, stainless steel or plastic in the fiberglass is delaminating inthe area of treated water.

the crack. A four inch portion of the crack appears to be almost through wall, CR-IP3- During a FAC examination (WO IP3 'Loss of material is an aging effect 2003-01927 24847, EX-02.9-02P), wall thinning was identified in the mechanical tools for noted on an elbow on the line from the carbon steel steam and treated water.

Moisture Separator lB to the extraction steam header.

CR-IP3- Visual inspection of the #35 &#36 main Loss of material is an aging effect 2003-02161 condenser inlet waterbox tubesheets identified in the mechanical tools for revealed that several of the existing tube copper alloys-in raw water.

plugs were either missing the brass expanding screws or the screws showed signs of corrosion degradation.

IP-RPT-06-LRD05 IPEC License Renewal Project Revision I Operating Experience Review Report Page 39 of 105 Table 3.1.1 Operating Experience Applicable to Non-Class I Mechanical Systems Item Issue - Evaluation CR-IP3- It appears that there is corrosion on Loss of material is an aging effect 2003-02298 feedwater line #7 at the whip restraint just identified in the mechanical tools for inside the containment wall, at elevation carbon steel in indoor air.

57'-6" near column line 10.

CR-IP3- During a FAC examination, (WO IP3 Loss of material is an aging effect 2003-02319 10074, EX-02.2-02T) wall thinning was identified in themechanical tools for found on a 10" X 18" tee in the line from carbon steel in steam and treated water.

the 2A preseparator to the extraction steam header.

CR-IP3- While adjusting Batching Tank Aux Steam Loss of material and cracking are aging 2003-03812 flow via the PCV Bypass a large spout of effects identified in the mechanical tools water gushed through the wall of the outlet for carbon steel or stainless steel in steam line for Batch Tank Aux. Steam Relief and treated water.

valve. I immediately shut the valve and inspected the area of the leak.

CR-IP3- During heat trace trouble shooting on line Loss of matenal is an aging effect 2003-04048 DF-1055 (fuel oil supply line to 31 EDG identified in the mechanical tools for day tank) a pinhole leak was found in the carbon steel in fuel oil.

pipe wall approximately 10 inches from check valve DF-15-1.

CR-IP3- When removing the PTO for 31 EDG oil Loss of material is an aging effect 2003-04266 lines the cap for the drain valve DF-10-1 identified in the mechanical tools for could not be put back. The nipple on DF- carbon steel in fuel oil.

10-1 is corroded and has to be cut out and a new one welded in.

CR-IP3- During the internal tank inspections of #31 Loss of material and cracking are aging 2003-04873 Fire Water Storage Tank (FWST) effects identified in the mechanical tools performed on 8/26 and 8/27103, several for carbon steel in treated water.

areas of localized coating failure and iron nodules with underlying pitting were identified on the tank floor. Many nodules were removed.

CR-IP3- On rounds the nuclear NPO found a Loss of material and cracking are aging 2003-05443 through wall hole in the aux steam to boric effects identified in the mechanical tools acid batch tank relief line. The hole is for carbon steel or stainless steel in steam about 1.5 inches long and .5 inch wide and and treated water.

is located directly behind P1-1370.

IPCLicense Renewal ProjectIPRT0LDO Operating Experience Review Report Page 40 of 105 Table 3.1.1 Operating-Experience Applicable to Non-Class I Mechanical Systems Item Issue Evaluation CR-IP3- During the performance of the 5 year-, Loss of material and cracking are aging 2003-05491 inspection (WO IP3-03-14198) of the 32 effects identified in the mechanical tools FWST (FP-T-2), the tank interior was for carbon steel in treated water.

found to exhibit general coatings deterioration and localized failures.

CR-IP3- UH-T-599-8, Condensate Return from Unit Loss of material and cracking are aging 2004-00179 Htr HSB-UH-9 Aux. Steam Trap, has a effects identified in the mechanical tools through-wall steam leak with a 7" plume. for carbon steel or stainless steel in treated water.

CR-IP3- Itwas reported following inspection that Cracking is an aging effect identified in 2004-01448 leak rate on S1-733B, 31 Residual Heat the mechanical tools for stainless steel in Removal Heat Exchanger Discharge Line treated water.

Relief Valve was 8 mil/min. This leakage is due to a cracked bellows is water from RWST and not RCS. Operability Evaluation 04-09 germane.

CR-IP3- During the replacement of 5EX-SOV- Loss of material and cracking are~aging 2004-01579 1252C found removed valve had excessive effects identified in the mechanical tools erosion and steam cuts to body and seat for carbon steel or stainless steel in steam areas. and treated water.

CR-IP3- Ecolochem watch noticed a crack on the 6" Loss of material is an aging effect 2004-02902 PVC inlet flange to the carbon bed. identified in the mechanical tools for plastic in treated water.

CR-IP3- MW-473, City Water to north loading well Loss of material is an aging effect 2004-03378 hose connection isolation, has a body leak identified in the mechanical tools for of about one drop per minute and has carbon steel or stainless steel in treated significant rust and corrosion at the sight of water.

the leakage.

CR-IP3- During the 33 CCW pump PTO removal Loss of material is an aging effect 2004-03540 the pump casing was noted to be leaking. identified in the mechanical tools for gray cast iron in treated water.

CR-IP3- There is an Aux. Steam leak downstream Loss of material and cracking are aging 2005-00163 of UH-516 within the confines of Air effects identified in the mechanical tools Handing Unit RS-AH-1 at the far side the for carbon steel, stainless steel or copper heating coils near the floor. The leak is alloys in steam and treated water.

causing multi-level flooding on the 73', 55',

and 41' RAMS bldg.

IP-RPT-06-LRD05 IPEC License Renewal Project RevisionD0 Operating Experience Review Report Revision I Page 41 of 105 Table 3.1.1 Operating Experience Applicable to Non-Class I Mechanical Systems Item Issue Evaluation CR-IP3- During the installation of temp indication Loss of material is an aging effect 2005-00235 for the power uprate, found the threads on identified in the mechanical tools for MS-287, Moisture Preseperator .1B Test carbon steel in steam and treated water.

Connection severelycorroded with the last two threads on the pipe connection completely gone..

CR-IP3- During 3R13P FAC UT inspection of the Loss of material is an aging effect 2005-00613 10" X 14" expander downstream of valve identified in the mechanical tools for 5HD-LCV-1127B, (Heater Drain Tank carbon steel in steam and treated water.

Bypass to Condenser 33 LCV), wall

,thinning was detected below the administrative scr'eening criteria of 70% of the nominal wall thickness (0.175").

CR-IP3- During inspection of 31 main turbine lube Loss of material is an aging effect 2005-01101 oil cooler. The outlet pipe flange facehas 4 identified in the mechanical tools for areas of crevice corrosion.

• carbon steel, stainless steel or copper alloys in lube oil, raw water or treated water.

CR-IP3- The tube bundlein the Main Boiler Feed Loss of material is an aging effect 2005-01366 Pump Lube Oil Cooler #32 is severely identified in the mechanical tools for degraded due to corrosion pitting per eddy carbon steel, stainless steel or copper current inspection (see iTi Report No. PR alloys in lube oil, raw water or treated No.32-134, dated 3-21-05). The vendor water.

recommended tube bundle replacement.

CR-IP3- During inspection of the fuel oil supply pipe Loss of material is an aging effect 2005-03088 to 32 EDG it was discovered that line 1053 identified in the mechanical tools for had wall thickness loss in multiple areas of carbon steel in fuel oil.

up to 0.056" due to corrosion.

CR-IP3- Inspection of the 31 FCU HXwaterbox Loss of material is an aging effect 2005-05466 shows that the previously identified identified in the mechanical tools for deterioration of the cover plates by crevice carbon steel in raw water or treated water.

corrosion has progressed to the point that repairs are necessary to seal the waterboxes.

CR-IP3- Inspection of the 32 FCU HX waterbox Loss of material is an aging effect 2005-05558 shows widespread pitting corrosion of identified in the mechanical tools for cover plates to the point that repairs are carbon steel in raw water or treated water.

necessary to seal the waterboxes.

CR-IP3- Steam leak fromflange on SW side of Loss of material and cracking are aging 2005-05832 Magnatrol, leak is audible, and visually effects identified in the mechanical tools verified, hi level alarm is not in. for carbon steel and stainless steel in steam or treated water.

Riverkeeper Opposition to Entergy's Motion For Summar6 Disposition of Riverkeeper Technical Contention 2 (Flow-Accelerated Corrosion)

Riverkeeper- TC-2: Attachment 5

Entegy S CONDITION REPORT " CR-IP2-2001-10525 Originator: MALONE, HAZEL Originator Phone: 0 Originator Site Group: IP2 ENG P&C-Code Programs Staff Operability Required: Y Supervisor Name: SCHWARTZ,- GEOFFREY Reportability Required: N Discovered Date: 10/31./2001 00:00 Initiated Date: 10/31/2001 00:00 Condition

Description:

CR Date: 10/31/2001 12:33 CR Entered Date: 10/31/2001 14:21 UT inspections were performed on sections of Crossunder piping as the result of a pinhole leak found on the MSR2 IA inlet piping during the cycle (see CR# 200103681). Areas on the expansion joints and piping upstream of MSR2 IA show measured thickness below or close to allowable minimum wall (0.247") based on UT results taken during the mid-cycle outage. The cause of these thinned areas is believed to be Flow Accelerated Corrosion (FAC). It is recommended that these areas be repaired at this time. Design Engineering has been notified and temporary repair of thinned areas are being performed. See-drawings attached for location of thinned area and the mearsured thickness readings of these areas.

Immediate Action

Description:

Evaluated thinned areas and worked with Design Engineering to develop temporary repair for degraded areas.

Suggested Action

Description:

EQUIPMENT:

Tae Name Tae Suffix Name Component Code Process System Code 21AMSR IMS REFERENCE ITEMS:

Tyne Code Item Desc CR 200103681 CR 200103681 CR 200110521 CR 200110526 DETECTION SI LOCATION. Turbine WON 01-23886 WON 01-23886 Y WON 01-24370 WON 01-24370 Y TRENDING (For.Reference Purposes Only):

Trend Tvye Trend Code PR PR-CORROSION & EROSION (ALL WALL-THINNING PROCESSE OR OR-DESIGN ENGINEERING EQ EQ-AH KA KA-IN IPEC00092616

Entergy CORRECTIVE ACTION CR-IP2-2001-10525 CA Number: I Site Group S .. Name

• Assigned By: IP2 CA&A Staff E-CAPTAIN, CRS Assigned To: iP2 ENG P&C-Code Programs Mgmt *Azevedo,Nelson F Subassigned To: IP2 ENG P&C-Code Programs Staff MALONE, HAZEL Originated By: E-CAPTAIN, CRS 11/1/2001 00:00:00 Performed By: Azevedo,Nelson F 11/29/2001 00:00:00 Subperformed By: MALONE, HAZEL . 1/26/2001 00:00:00 Approved By:

Closed By: E-CAPTAIN, CRS 11/29/2001 00:00:00 Current Due Date: 12/01/2001 Initial Due Date: 12/01/2001 CA Type: DISP - CORR ACTION Plant Constraint:. NONE CA

Description:

Please evaluate to determine apparent cause and recommend corrective actions. (cbh)

CA REFERENCE ITEMS:

Type Code Description CRS ID 254719

Response

IPEC00092617

Entergy CORRECTIVE ACTION CR-IP2-200 1-10525 Subresponse:

111/09/2001 Assigned to: MALONE, HAZEL Status: Closed + Approved Action Requsted: Hazel, please evaluate this SL2 and provide corrective actions as required. Nelson Assignee Response: See SL Report Reviewer Comment:

Although this CR was classified as an SL2, the wall thinning detected during the mid-cycle inspection was a result of Flow Accelerated Corrosion (FAC).,Nhich is a well understood degradation mechanism and it iswell modeled.in industry and in IP2 FAC analysis. No causal factors or any other evaluation was performed on this CR because it was considered provide no additional value to this already, well understood phenomena. Based on this, it is requested that this CR be downgraded to an SL3 and closed as such.

Nelson Azevedo 11/29/01 Significance Level 3 Report UT inspections were performed on the 26.5" ID vertical riser section of crossunder piping leading to MSR21A as the result of a pinhole leak which occurred in this section during thecycle (See CR# 200103681). Results of the UT inspections performed found an additional thinned area on the same expansion joint containing the pinhole leak and a thinned area on a pup piece adjacent to that expansion joint (See attachment for locations of thinned areas). The thinned areas found measured below or close to allowable minimum wall thickness (See wear rate/structural evaluation for each component inspected for

.details).

Cause of wear is believed to be the result of Flow Accelerated Corrosion (FAC). FAC is the process whereby the protective oxide layer on carbon steel piping is dissolved by flowing water or wet steam which results in the wearing away of the, underlying metal. Main Steam exhausted from the High Pressure Turbine enters the Crossunder piping as a wet steam, that.

can contain as much as 20% moisture. This wet-steam mixture combined with the high fluid velocity and high temperature of this piping system can result in extremely high wear rates and establishes Crossunder piping as one of the most susceptible systems to FAC...Though the IP2 FAC program history shows that all crossunder piping was completely weld overlaid with Stainless Steel to prevent wear, certain areas near expansion joints were not weld overlaid due to restrictions on welding near the expansion joints links (dogbones). Certain areas near these expansion joint dogbones may have been consequently left as Carbon Steel due to these restrictions and are still vulnerable to the effects of FAC. The leak that occurred during the cycle 15, as well as the thinned areas found during the mid-cycle outage were all located in the vicinity of the expansion joints.

Thinned areas located during the mid cycle inspection will be temporarily repaired externally per WO# 01-23886 until they

• can be visually inspected internally during the 2002 refueling outage and permanently repaired. Internal inspections are recommended to determine the location of the expansion dogbones and also to locate areas not weld overlayed that may need repair. Internal inspections of crossunder piping will be added to the scope of the 2002 refueling outage as part of the FAC outage inspection scope (see FAC Master Inspection List for details) and may include inspection of parallel trains or similar expansion joint areas.

Permanent repair of thinned areas will be performed under work order 01-24370. Methods of permanent repair as well as expansion joint replacement options should be researched and planned for accordingly prior to the outage to ensure proper scheduling.

Thinned areas located during the mid cycle inspection will be temporarily repaired externally per WO# 01-23886 until they can be visually inspected internally during the 2002 refueling outage and permanently repaired. Internal inspections are recommended to determine the location of the --- see attachment for rest Closure Comments:

reject per CAG quality review Attachments:

Subresp Description 1i1/09/2001 Assigned to: MA IPEC00092618

SEntergy CORRECTIVE ACTION CR-IP2-2001-10525 CA Number: 2 Site [ -Group JName Assigned By: IP2 CA& Cdotaff E-CAPTAIN, CRS Assigned To: IP2 ENG P&C-Code Programs Mgmt Azevedo.Nelson F

,.. .--..L *- hrv_

uuasslgneu o; Originated By: E-CAPTAIN, CRS, 12/4/2001 00:00:00 Performed By: Azevedo,Nelson F 12/4/2001 00:00:00 Subperformed By:

Approved By:.

Closed By: Azevedo,Nelson F 12/4/2001 00:00:00 Current Due Date: 12/06/2001 Initial Due Date: 12/06/2001 CA Type: DISP - CORR ACTION Plant.Constraint:.. NONE CA

Description:

reject per CAG quality review Downgraded from SL2 to SL3 per Joe Barlok. Due date changed to 12/6/01 ... 12/4/01 MK CA REFERENCE ITEMS:

Type-Code

• Description CRs ID 260983 IPEC00092619

Entergy CORRECTIVE ACTION I.CR-iP2-2001-10525

Response

Significance Level 3 Report UT inspections were performed on the 26.5" ID vertical riser section of crossunder piping leading to MSR2 IA as the result of a pinhole leak which occurred in this section during the cycle (See CR# 200103681). Results of the UT inspections performed found an additional thinned area on the same expansion joint containing the pinhole leak and a thinned area on a pup piece adjacent to that expansion joint (See attachment for locationsofthinnedareas). The thinned areas found measured below or close to allowable minimum wall thickness (See wear rate/structural evaluation for each component inspected for details).

Cause of wear is believed to be the result of*Flow Accelerated Corrosion (FAC). FAC is the process whereby the protective oxide layer on carbon steel piping is dissolved by flowing water or wet steam which results in the wearing away of the underlying metal., Main Steam exhausted'from the High Pressure Turbine enters the Ciossunder piping as a wet steam, that can contain as much as 20% moisture: This wet steam mixture combined with the high fluid velocity and high temperature of

• this piping system can result in extremely high wear, rates and establishes Crossunder piping as *one of the most susceptible systems to FAC. Though the IP2 FAC program history shows that all crossunder piping was completely weld overlaid with Stainless Steel to0prevent wear, certain areas near expansion joints were not weld overlaid due to restrictions on welding near the expansion joints links (dogbones). Certain areas near these expansion joint dogbones may have been consequently left as Carbon Steel due to these restrictionsand are still vulnerable to the effects of FAC. The leak that occurred during the cycle 15, as well as the thinned areas found during the mid-cycle outage were all located in the vicinity of the expansion joints.

Thinned areas located during the mid cycle inspection will be temporarily repaired externally per WO# 01-23886 until they can be visually inspected internally during the 2002 refueling outage and permanently repaired. Internal inspections are recommended to. determine the location"of the expansion dogbones and also to locate areas not weld overlayed that may need repair. Internal inspections of crossunder piping will be added to the scope of the 2002 refueling outage as part of the FAC outage inspection scope (see FAC Master Inspection List for details) and may include inspection of parallel trains or similar expansion joint areas.

Permanent repair of thinned areas will-be performed under work-order 0 1-24370. Methods of permanent repair as well as.,

expansion joint replacement options should be researched and planned for accordingly prior to the outage to ensure proper scheduling.

Thinned areas located-during the mid cycle inspection will be temporarily repaired externally per WO# 01-23886 until they can be visually inspected internally during the 2002 refueling outage and permanently repaired. Internal inspections are recommended to determine the location of the expansion dogbones and also to locate areas not weld overlayed that may need repair. Internal inspections of crossunder piping will be added to the. scope of the 2002 refueling outage aspart of the FAC outage inspection scope (see FAC Master Inspection List for details) and may include inspection of parallel trains or similar expansion joint areas.

Permanent repair of thinned areas will be performed-under work order 01-24370. Methods of permanent repair as well as expansion joint replacement options should be researched and planned for accordingly prior to the outage to ensure proper scheduling.

- Subresponse:

Closure Comments:

N/A IPEC00092620

Entergy CORRECTIVE ACTION CR-IP2-2001-10525 CA Number: 3 Site Group -. Name Assigned By: IP2 -CA&A Staff E-CAPTAIN, CRS Assigned To: IP2 ENG SYS-Balance of Plant Staff RayBryan J Subassigned To:

Originated By: E-CAPTAIN, CRS 11/1/2001 00:00:00 Performed By: Ray,Bryan J 11/3/2001 00:00:00 Subperformed By:

Approved By:

Closed By: RayBryan J 11/3/2001 00:00:00 Current Due Date: 11/08/2001 Initial Due Date: 11/08/2001 CA Type: CRS - FYI Plant Constraint: NONE CA

Description:

For your information on equipment with your system.

CA REFERENCE ITEMS:

Type Code Description CRS ID 254720

Response

Subresponse:

Closure Comments:

N/A -

IPEC00092621

Entergy CORRECTIVE ACTION. CR-IP2-2001-10525 CA Number: 4 Site Group JName Assigned By: IP2 CA&A Staff E-CAPTAIN, CRS Assigned To: IP2 ENG P&C-Code Programs Mgmt Azevedo,Nelson F Subassigned To:

Originated By: E-CAPTAIN, CRS 12/4/2001 00:00:00 Performed By:, Azevedo,Nelson F 2/1/2002 00:00:00 Subperformed By:

Approved By:

Closed By: Azevedo,Nelson F 2/1/2002 00:00;00 Current Due Date: 02/17/2002 Initial Due Date: 02/17/2002 CA Type: CR CLOSURE REVIEW Plant Constraint: NONE CA

Description:

Follow up on corrective action assignments CA REFERENCE ITEMS:

Type Code D4~scription CRS ID 26 1193

. Response:..

Since the corresponding ICAs have been adequately implemented, this CR is ready for closure.

Subresponse:

Closure Comments:

N/A IPEC00092622

. Entergy CORRECTIVE ACTION CR-IP2-2001-10525 CA Number: 5 Site Group I Name I Assigned By: IP2 ENG P&C-Code Programs Mgmt Azevedo,Nelson F Assigned To: IP2, ENG P&C-Code Programs Staff MALONE, HAZEL Subassigned To:

OriginatedrBy: Azevedo,Nelson F 12/4/2001 00:00:00 Performed By: MALONE, HAZEL 1/18/2002 00:00:00 Subperformed By:

Approved By:

Closed By: Azevedo,Nelson F 1/18/2002 00:00:00 CurrentDue Date: 01/18/2002 Initial Due Date: 01/18/2002 CA Type: PERFORM CA Plant Constraint: NONE CA

Description:

Add internal inspection of MSR vertical risers to FAC Master Inspection List (MIL) for 2002 refueling outage.

CA REFERENCE ITEMS:

Type Code Description CRS CLASS I CRS ID 261191 Response: -

Internal inspectionof 21 A&B, 22A&B and 23A&B. MSR vertical risers will be added to FAC Master Inspection List (MIL) for 2002 refueling outage. Final MIL is due for release 1/31/2002 Subresponse: -

Closure Comments:

Please reflect the fact that the inspection locations have been added to the inspection list even though the final list will not be

. issued until 1/31/02.

IPEC00092623

• Entergy CORRECTIVE ACTION CR-IP2-2001-10525 CA Number: 6 Site Group Name I Assigned By: IP2 ENG P&C-Code Programs Mgmt Azevedo,Nelson F Assigned To: IP2 ENG P&C-Code Programs Staff MALONE. HAZEL Subassigned To:

Originated By:- AzevedoNelson F 12/4/2001 00:00:00.

Performed By: MALONE, HAZEL 1/18/2002 00:00:00 Subperformed By:

Approved By: ,

Closed By: Azevedo,Nelson F 1/18/,2002 00:00:00 Current Due Date: 01/18/2002 Initial Due Date: 01/18/2002 CA Type: PERFORM CA Plant Constraint: NONE CA

Description:

Research methods of permanent repairs for previously temporary repaired areas of crossunder piping. Also, research the cost and resource information for the replacement of crossunder expansion joints to determine if this option is practicable.

CA REFERENCE ITEMS:

Type Code Description CRS CLASS 1 CRS ID 261192

[PE000092624

Entergy CORRECTIVE ACTION CR-IP2-2001-10525

Response

There have been many differentmethods used to permanently repair these areas of crossunder piping. The following are descriptions of these methods: ,

1. Welding under expansion dogbones One option of repair that has been performed at plants such as Surry is to remove the expansion dogbones, perform Stainless steel cladding to.expose piping underneath and replace dogbones. Advantages to this repair method are. that the entire area would be protected (including area under dogbones) and thinned areas of piping can be brought back up to nominal thickness by the overlay. Disadvantages, to this repair is that it is not a recommended repair method of Westinghouse because it may jeopardize the flexibility of the expansion joint and that extra time will be needed to perform the engineering to analyze this concern.

2. Stainless Steel Tubing Repair This repair option was used at St. Lucie Unit i & 2 to repair eroded area under dogbones. A stainless steel piece of tubing was placed next to the dogbones and welded in place. The tubing was then deformed to ensure a secure fit up to the dogbone (see attachment for details). Advantages to this repair are that there is no welding to the dogbone and no arc strikes on the dogbone as recommended by Westinghouse. Disadvantage to this repair is that if there is not a consistent bond between the tubing and the dogbone, steam can still get into that area and erode the piping underneath.

3. Stainless Steel Covering over dogbones During the last CHECWORKs Users Group (CHUG) meeting (January 14& 15, 2002), it was mentioned the Point Beach has welded stainless steel covers over the dogbones in their crossunder piping. At this time, Point Beach FAC engineer has provided no additional information.

4. Welding on Outside of crossunder piping A 1995 letter to Westinghouse on the subject of repairing eroded areas of crossunder piping from the outside yield the following response:

These eroded areas beneath the expansion joint link (dogbones) can be repaired from the outside of the pipe. The eroded area beneath the link should be ground out and weld repaired using 309 stainless as per PS 600374 for the first few passes to provide an erosion resistant inner surface. The remaining cavity should be built-up with carbon steel weld material as per PS 600945 Part 1-1-1I-B.. Post weld heat treatment should not be performed for any of the above welding processes.

The expansion joint link should not be subjected to any arc strikes during the welding process. It is recommended that a copper backing plate be placed between the link and the area of repair to protect the link during welding.

A carbon steel backing plate can be welded over the repaired area on the outside diameter of the pipe, if desired. This welding should be performed to PS 600945 1-I-I-B. No PWHT is to be performed.

Advantages0f this repair are that it is a recommended repair from, the expansion joint vendor (Westinghouse) and that it would restore original pipe thickness. Would need to obtain welding procedure from Westinghouse if similar procedure is not available.

Replacement:of Expansion Joint sections (21A & 21B Vertical Risers) was also investigated for this RES.. At the time of this

-response. Westinghouse (Siemens) had not replied with an estimate for replacing both 21A and 21B-vertical risers. The following information was provided from proposals of IP3 .1997 Crossunder replacement of their 3 1 A and 31 B vertical risers and IP2 1995 Crossunder replacement of 32"expansion joints under the HP turbine.

IP2 32" Expansion Joints under HP Turbine (1995) o Material cost - $24,160 (8, 32" Plates of 1-1/4 Chrome) o Heat Treatment of 32" Expansion Joints - $17,086.76 (15 days to perform)

IP3 31 A & 31 B Vertical Riser Replacement (1997) o Lump sum quote for design/engineering of all MSR vertical risers and --- see attachment for rest Subresponse:

Closure Comments:

N/A 1PE000092625

Enterigy CORRECTIVE ACTION CR-IP2-2001-10525 Attachments:

Resp Description There have been many different IPEC00092626

Er E tcgy CORRECTIVE ACTION CR-IP2-2001-10525 CA Number: 7 Site I Group I Name Assigned By: IP2 ENG P&C-Code Programs Mgmt Azevedo.Nelson F Assigned To: IP2 ENG P&C-Code Programs Staff MALONE, HAZEL Subassigned To:

Originated By: Azevedo,Nelson F 1/18/2002 00:00:00 Performed, By: MALONE,'HAZEL "1/18/2002 00:00:00 Subperformed By:

Approved By:

Closed By: Azevedo,Nelson F 1/18/2002 00:00:00 Current Due Date: 01,/18/2002 Initial Due Date: 01/18/2002 CA Type: PERFORM CA Plant Constraint: NONE.

CA

Description:

Please reflect the fact that the inspection locations have been added to the inspection list even though the final list will not be issued until 1/31/02.

CA REFERENCE ITEMS:

Type Code Description CRS CLASS 1 CRS ID 270378 Response:.

Internal inspections of 21A&B, 22A&B and 23A&B MSR vertical risers have been added to FAC Master Inspection List (MIL) for the 2002 refueling outage. The final MIL is due for release 1/31/2002 Subresponse:

Closure Comments:

N/A IPEC00092627

S .Entergy CONDITION REPORT CR-1P3-2006-02270,,

I . Originator:. Lizzo,Nicholas

)riginator Group: Operations Watch Mgmt Originator Phone: 8277 Operability Required: N Reportability Required: N Supervisor Name: CramerThomas A Discovered Date: 07/23/2006 04:49 Initiated Date: 07/23/2006 04:58 Condition

Description:

The line downstream of the 1104 valves ("A" reheaters) -to 36 FWH shell side is leaking approximately 1/2 gpm. WRT

[P3-06-18192. Rapid Response activated.

Immediate ActionDescription-SM notified - rapid response activated Suggested Action

Description:

Repair.

EQUIPMENT:

Tae Name Tat Suffix Name Component Code Process System Code 1104 . HD REFERENCE ITEMS:

Truve Code Description

1. LEVEL OF DEFENSE Observation KEYWORDS leak TEAM 3C tt WON .IP3-06-18192 TRENDING (For Reference Purposes Only):

Trend Type Trend Code REPORT WEIGHT 4 EM MAMM KEYWORDS KW-LEAKS-WATER EFII

[PE000025699

Ety r CORRECTIVE ACTION CR-IP3-2006-02270 CA Number: I Group I Name I Assigned By: CRG/CARB/OSRC Harrison,Christine B Assigned To: P&C Eng Codes Mgmt Azevedo,Nelson F Subassigned To: P&C Eng Codes Staff Hartjen,Harry G Originated By: Harrison,Christine B 7/25/2006 11:27:08, Performed By: AzevedoNelson F 8/15/2006 14:22:53 Subperformed By: Hartjen,Harry G 8/10/2006 09:27:02 Approved By:

Closed By: AzevedoNelson F 8/15/2006 14:22:53 Current Due Date: 08/16/2006 Initial Due Date: 08/16/2006 CA Type: .DISP - CA Plant Constraint: #NONE CA

Description:

Please review and assign further corrective actions as required.

Response

UT thickness measurements were taken around the leaking area on this pipe (UT Report 06UT 171). The thinned area was -.

found to be localized on one side of the pipe which is downsstream of a tee. A pipe clamp (Team Inc.) was installed over the leak and thinned area under work order IP3-06-18192. Leak repair was successful and the leak has stopped. CA 00002 has been issued to review the FAC program and determine if additional inspections are warrented as a result of this leak.

"-bresponse:

- Issued CA#2 Closure Comments:

I PEC00025700

Entergy CORRECTIVE ACTION CR-IP3-2006-02270 CA Number: 2

ýýGrbup .I ,Name I Assigned By: P&C Eng 'Codes Staff HartjenHarry

'Hartjen,Hanry G HartjenHarry Assigned To: P&C Eng Codes Staff Hartjen,Harry G Subassigned To:

-Originated By: Hartjen,Harry.G 8410/2006 09:24:00 Performed By: ..Hartjen,Harry G .10/30/2006 11:28:34 Subperformed By:

Approved By:

Closed By: Hartjen,Harry G 10/30/2006 11:28:34 Current Due Date: 10/31/2006 Initial Due Date: 10531/2006 CA Type: ACTION Plant Constraint: #NONE CA

Description:

Review both Unit 2 and Unit 3 FAC Programs and determine if similar locations to this leak have been inspected for wall thinning. Also determineif and when additional inspections are required to determine if wall thinning is occuring at these similar locations. If additional inspections are required, incorporate inspections into work week schedule, or FAC Program outage scopes.

Response

A review of both Unit 2 and Unit 3 FAC programs was performed.to determine if similar locations to the current Reheater Drain line leak have been inspected for wall thinning and determine if and when additional inspections are required to determine if wall thinning is occurring at these similar locations.

Review of the Unit 2 FAC inspection history found that all similar locations have been recently inspected or replaced. No additional inspections are recommended for Unit 2 at this time.

Review of the Unit 3 FAC inspection history found that some similar locations do not have recent inspections and should-be inspected. A total of 9 additional inspections were identified.

Details of this review, along with the recommended additional inspections are attached.

No on-line exams are recommended due to the high temperature (385 degrees F) of these components, and the congestion of piping in these areas. Therefore the 9 additional inspections are to be performed during the 3R14 refuel outage.

CA 3 is issued to generate work orders and 3R14 scope add forms for these inspections.

Subresponse:

Closure Comments:

Attachments:

Resp Description Review of FAC Inspections due to leak in U3 RHD IPEC00025701

'P Riverkeeper Opposition to Enthigy's Motion For Summary Disposition of Riverkeeper Technical Contention 2 (Flow-Accelerated Corrosion)

Riverkeeper TC-2: Attachment 6

1 1 UNITED STATES OF AMERICA 2 NUCLEAR REGULATORY COMMISSION 3+++'+.+

4 565TH MEETING 5 ADVISORY COMMITTEE ON REACTOR SAFEGUARDS 6 (ACRS) 7+++++

8 THURSDAY, 9 SEPTEMBER 10, 2009 10 11 ROCKVILLE, MARYLAND 12 The Advisory Committee met at the Nuclear

.13 Regulatory Commission, One White Flint North, 14 Commissioner's Conference Room, 11555 Rockville Pike, 15 at 8:30 a.m., Dr.. Mario V. Bonaca, -Chairman, 16 presiding.

17 COMMITTEE MEMBERS:

18 MARIO V. BONACA, Chairman 19 SAID ABDEL-KHALIK, Vice Chairman 20 GEORGE E. APOSTOLAKIS, Member 21 J. SAM ARMIJO, Member-at-Large 22 SANJOY BANERJEE, Member 23 CHARLES H. BROWN, Member 24 MICHAEL L. CORRADINI, Member 25 OTTO L. MAYNARD, Member NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

(202) 234-4433 WASHINGTON, D.C. 20005-3701' www.neairgross.com

2 COMMITTEE MEMBERS (Continued):

DANA A. POWERS, Member 4 HAROLD B. RAY, Member MICHAEL T. RYAN, Member E

WILLIAMJ.JSHACK, Member E JOHN D. SIEBER, Member JOHN W. STETKAR, Member C

s 1

1E 14 1

16 17 18 20 22 23 24 25 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., NW.

(202) 234-4433 WASHINGTON, D.C. 20005-3701 www.nealrgross.com

3 1 C-O-N-T-E-N-T-S 2 Call to Order and Welcome ............................ 4 3 Indian Point, License Renewal ......................... 7 4 Briefing/Discussion with NRC Staff... ............ 83 5 Entergy Response to Questions ...................... 94 6 Public Comments ............ ........ ............... 113 7 License Renewal Application ....................... 117 8 and Final SER for the Three Mile' Island 9 Nuclear*Station Unit 1 10 Briefing/Discussion with NRC Staff.............. 118 1 Fire Protection for Nuclear Powerplants .......... 175 12 Draft Digital Instrumentation and 13 Control Research Plan for 14 Fiscal Years 2010 to 2014 .......................... 211 1.5 Adjourn 16 17, 18 19 20 21 22 23 24 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., NW.

(202) 234-4433 WASHINGTON, D.C. 20005-3701 www.nealrgross.com

90 1 Thank you.

2 MS. GREEN: I would like to move on to the 3 flow-accelerated corrosion program and the operating 4 experience.

5 During the ACRS Subcommittee meeting in 6 March, an ACRS member questioned why the inspection 7 frequency, did not change for instances where the 8 minimum measured wall thickness was near or below 9 minimum acceptable wall thickness. At that time, the 10 staff did not answer the ACRS member's question. So I 11 would like to try to address that now.

12 During the audit, the staff questioned the 13 applicant about the incidences of wall thinning that 14 were reported in the license renewal application.

15 Specifically, 'there' was an iP3 vent chamber drain 16 piping, IP3 high-pressure turbine drain piping. There 17 is a 2-inch diameter line and a three-quarter-inch 18 diameter line, and the IP2 steam trap piping. These 19 were, I think, the four cases that the ACRS member was 20 referring to in the staff's audit report..

21 In response to the audit question, as well 22 as a few others that were related, to the flow-23 accelerated corrosion program, the applicant stated 24 that the piping and affected components were included 25 in the flow-accelerated corrosion program prior to the NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., NW.

(202) 234-4433 WASHINGTON, D.C. 20005-3701 www.nealrgross.com

91 1 *inspections. As the wall thinning of these components 2 was discovered, the applicant replaced the components 3 with like-for-like materials or FAC-resistant 4 materials.

5 The applicant also stated that, if a 6 component is discovered that has a current or 7 projected wall thickness less than the minimum 8 acceptable wall thickness, then additional inspections 9 of identical or similar piping components in a 10 parallel or alternate train is performed to bound the 11 extent of thinning. When the inspections of 12 -components detects significant wall thinning, then the 13 sample size for that line is increased.

14 One of the examples I would like to talk 15 about to explain this is the IP3 vent chamber 16 drainpipe thinning. During the refueling outage '13, 17 Entergy did an inspection of an elbow immediately 18 downstream of the moisture separator reheater and 19 found wall thinning, less than the minimum acceptable 20 wall thinness, requiring replacement of the elbow.

21 Based on the results of that inspection, 22 the applicant performed a sample expansion to 23 determine the extent of condition for this pipe 24 thinning. The expansion included corresponding 25 components on the other moisture separator reheaters NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

(202) 234-4433 WASHINGTON, D.C. 20005-3701 www.nealrgross.com

92 1 with a configuration similar' to that of the elbow 2 displaying the thinning.

3 Entergy then performed four additional 4 inspections. These inspections also found wall 5 thinning less' than the minimum acceptable thickness 6 requiring replacement of the components.

7 The sample expansion was continued until 8 no additional components were detected with 9 significant wear. Entergy performed four additional 10 inspections downstream of the worn elbows. The 11 results of this expansion did not find significant 12 wear, and the sample expansion was then terminated by 13 - Entergy. The -applicant updated and, adjusted the 14 Checkworks model to incorporate the inspection data.

15 MEMBER BROWN: Before you go on, I guess I 16 asked that question. So I will ask it again.

17 .I'm trying to draw a conclusion from your

-18 answer that, No. 1, they replaced them with more 19 erosion-resistant or flow-accelerated, corrosion-20 resistant materials when they did the replacements.

21 Is that correct?

22 MS. GREEN: For that particular line, they 23 were planning to replace with Chrome-Moly, but for 24 other lines --

25 ' MEMBER BROWN: That doesn't mean anything; NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

(202) 234-4433 WASHINGTON, D.C. 20005-3701 www.nealrgross.com

93 I 1 I'm not a metallurgist. Is it better or worse?

2 MS. GREEN: It's better.

3 MEMBER BROWN: Okay. Thank you.

4 MS. GREEN: Sorry.

5 That is, more FAC-resistant. For other 6 lines, they did a replacement of like-for-like 7 material.

8 MEMBER BROWN: Okay. The second question 9 was they had found, the wall thicknesses considerably 10 less. There were a number of other locations also 11 that had less than the minimum acceptable wall 12 thickness.

13 So the second part of the question about, 14 if they just did it like-for-like, what do you do to 15 your inspection process to make sure you don't 16 -encounter a circumstance that you now find you've got 17 less than minimum wall thickness again, which means 18 increased frequency? That part I didn't understand 19 the answer. Or was there an answer?

20 MS. GREEN: I am not a flow-accelerated 21 corrosion program expert. So I would have to ask Matt 22 Yoder from the staff to address your question.

23 MEMBER MAYNARD: I believe we have 24 somebody coming to answer that.

25 We need a portable microphone, I believe.

NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

(202) 234-4433 WASHINGTON, D.C. 20005-3701 www.nealrgross.com

94 1 MR. YODER: Okay, Matt Yoder, NRR staff.

2 So, *when these instances were found, the 3 data is then fed back into your Checkworks model. So 4 that, for future planning of inspections and UT, your 5 model is going to predict a greater wear rate at those 6 *locations, and it should then be scheduled for more 7 frequent UT inspection.

8 MEMBER BROWN: Okay. So there was an 9 explanation of the Checkworks thing in, I think, the 10 applicant's answer back, which I read, not being a 11 Checkworks expert.

12 So the point being that the information of 13 the increased wear rate is then fed back into- this 14 model, so that it gets into a periodic inspection that 15 is more frequent than before? It is not like you go 16 change a chart somewhere, but you do it based on the 17 predictions {of the model?

18 MR. YODER: That is correct. The model is 19 continuously updated with actual field data.

20 MEMBER BROWN: Okay. All right, thank 21 you.

22 MEMBER SHACK: How long has the Checkworks 23 program been in place at Indian Point?

24 MR. YODER: I will have to defer to 25 Entergy.

NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

(202) 234-4433 WASHINGTON, D.C. 20005-3701 www.nealrgrosscom

95 1 MR. AZEVEDO: My name is Nelson Azevedo.

2 I'm the Supervisor of Programs at Indian Point.

3 We first started using the Checkworks 4 models when it was first issued by EPRI, which I 5 believe was the .early nineties. I don't know the 6 exact-date.

7 MEMBER SHACK: It hasn't, reached steady-8 state yet?.

9 .MEMBER MAYNARD: Okay, let's go.

10 MS. GREEN: Okay. I would just -like to 11 cover briefly the, staff's evaluation of the 12 applicant's flow-accelerated corrosion program.

13 In the license renewal application, -the 14 applicant stated that its flow-accelerated corrosion 15 program is consistent with the GALL AMP XI.M17 with 16 one exception, that exception being the use of EPRI 17 NSAC-202L, Revision 3, in lieu of Revision 2, which is 18 recommended in the GALL report. The staff reviewed 19 the exception and found that the use of Revision 3 is 20 acceptable.

21 Based on the staff's audit and review, it 22 determined. that all other program elements are 23 consistent with the GALL report AMP.

24 The applicant's program includes updated 25 inputs for the power operating parameter changes with NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W (202) 234-4433 WASHINGTON, D.C. 20005-3701 www.nealrgross.com

96 1 steam flow rates and temperatures and such. It also 2 identified piping systems and components that are 3 currently the most susceptible to the loss of material 4 due to FAC.

5 Corrective actions that are in place 6 include re-evaluation, repair, or replacement. Based 7 on the review of the applicant's program, the staff 8 concluded that it is adequate to manage the effects of 9 aging, and therefore, acceptable.

10 During the March ACRS Subcommittee, ACRS 11 Member Brown asked the- staff to explain the various 12 criteria for Charpy upper-shelf energy. At the time, 13 the staff did not provide a full explanation, and 14 therefore, Chairman Maynard asked us- to provide an 15 explanation of the criteria, which I will attempt to 16 do now.

17 10 CFR 50, Appendix G, requires that 18 reactor vessels must maintain Charpy upper-shelf 19 energy values of no less than 50-foot pounds, unless 20 it can be demonstrated that lower values of upper-21 shelf energy will provide margins of safety against 22 fracture equivalent to those required by Appendix G of 23 Section 11 of the ASME Code.

24 Appendix K of the ASME Code, Section 11, 25 and ASME Code Case N-512 provide criteria for NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

(202) 234-4433 WASHINGTON, D.C. 20005-3701 www.nealrgross.com

Riverkeeper Opposition to Entergy's Motion For Summary Disposition of Riverkeeper Technical Contention 2 (Flow-Accelerated Corrosion)

Riverkeeper TC-2: Attachment 7

INDEX Cover Page Refueling Outage Excerpted Graphs Indian Point Unit 2 CHECWORKS IP2 R016 (2005) Figure 1 FAC Model, Calculation No. Figure 2 050714b701, Rev. 0 (July 5, 2005).. Figure 3 Indian Point Unit 2 CHECWORKS IP2 RO 17 (2006) Figure 4 FAC Model, Calculation No. Figure 5 050714b-01, Rev. 1 (Sept. 12, 2006)

Indian Point Unit 2 CHECWORKS IP2 RO18 (2008) Figure 6 SFA Model, Calculation No. Figure 7 0705.101-01, Rev. A (Nov. 17, 2008)

Indian Point Unit 2 CHECWORKS IP2 R019 (2010) Figure 8 SFA Model, Calculation No. Figure 9 0705.101-01, Rev. 1 (Feb. 26, 2010)

Indian Point Unit 3 CHECWORKS IP3 R013 (2005) Figure 10 FAC Model, Calculation No. Figure 11 050714c-01, Rev. 0 (Oct. 25, 2005) Figure 12 Indian Point Unit 3 CHECWORKS IP3 R014 (2007) Figure 13 SFA Model, Calculation No. Figure 14 0705.100-01., Rev. 0 (Nov. 14, 2007) Figure 15 Indian Point Unit 3 CHECWORKS IP3 RO15 (2009) Figure 16 SFA Model, Calculation No. Figure 17 0705.100-01, Rev. 1 (Feb. 12, 2010) Figure 18

Indian Point Unit 2 CHECWORKS FAC Model Calculation No. 050714b-01 Revision 0 Issued For-Use July 5, 2005 preparedfor:

Entergy Nuclear Northeast 295 Broadway Suite 3 PO Box 308 Buchanan,-NY 10511-0308 preparedby:

CSI TECHNOLOGIES, INC.

1051 E. Main St., Suite 215 East Dundee, IL 60118 IPECO0024459

FIGURE 3 CS, Technologies, Inc. IP2 CHECWORKS FAC Model Comparison of Wear Predictions

.)UUr RHTR DTK B DRN DSCV LCF = 1.808 2501

+50 _

C4) 1- 1:

14 - -

50 13 50, O. . . .

10016 . . . .

150Ii . . . .

20026 2i0 300 Measured Wear (mils)

• Curre.nt Component S Replaced Component 0 1 b0 e ii n ,A p n i IP g -5 of. 356 Cac lto N .0 Calculation No. 050714b-01, Revision 0, Appendix I Page 1-350 of 356

Indian Point Unit 2 CHECWORKS FAC Model Calculation No. 050714b-01 Revision I Issued For-Use September 12, 2006 preparedfor:

Entergy Nuclear Northeast 295 Broadway Suite 3

'PO Box 308 Buchanan, NY 10511-0308 preparedby:

CS, TECHNOLOGIES, INC.

1051 E. Main St., Suite 215 East Dundee, IL 60118 IPECO0168838

FIGURE 4 CS, Technologies,Inc. IP2 CHECWORKS FAC Model Comparison of Wear Predictions 4U Measured Wear (mils)

• Cunent Component Replaced Component IPECO0168480

FIGURE 5 CS, Technologies, Inc. IP2 CHECWORKS FAC Model Comparison of Wear Predictions 10 FWH 23 DRNS USCV LCF = 2.464 9 0. - - - - - - -7 - - r-_ -

70-_ - - -- _ __

60° -- ---

-o T

40

" T:$30---- -*

(U

-4~-

1 I 40 50 60 Measured.Wear (mils)

Current Component IPEC00168646

Indian Point Unit 2 CHECWORKS SFA Model CSI Calculation No. 0705.101-01 Revision A Issued For-Use November 17, 2008 preparedfor:

Indian Point Unit 2 295 Broadway Suite 3 PO Box 308 Buchanan, NY 10511-0308 preparedby:

CS, TECHNOLOGIES, INC.

One Douglas Avenue, Suite 300 Elgin, IL 60120

CSI TECHNOLOGIES, INC. 1P2 CHECWORKS SFA Model Plot J.27: RHTR DRN TK 21A USCV Compaoison of Wern Predictions - RHTR DRN TK 21A USCV fCYCLE 19 LCF = 1.03313 100-C~)

C w m (711 a

Measured Wear (mils)

• Replaced Component A CUrrent Component - +1- 50 %

Page J-28 of 36 Calculation Calculation No. 0705.101-01, Appendix No. 0705.101-01, Appendix J, Revision 0 J, Revision 0 Page J-28 of 36

CS, TECHNOLOGIES, INC. IP2 CHECWORKS SFA Model Plot J.32: RHTR DRN TK 23B USCV Comparison of Weal Piedictions - RHTR DRN TK 23B USCV @,CYCLE 19 LCF = 0.950476 100-C A

A m

A *4 9D -A A A A A: lA* A*

A A

A

& j*A ~- A

, &tA. A A ....-

A A 0 100 Measured Wear (mils)

• Replaced Component A Current Component +1-50 %

Page J-33 of 36 Calculation No. 0705.101-01, Appendix No. 0705.101-01, Revision 00 J, Revision Appendix J, 'Page J-33 of 36

Indian Point Unit 2 CHECWORKS SFA Model CSI Calculation No. 0705.101-01 Revision 1 Issued For-Use February 26, 2010 preparedfor:

Indian Point Unit 2 295 Broadway Suite 3 PO Box 308 Buchanan, NY 10511-0308 preparedby:

CS, TECHNOLOGIES, INC.

One Douglas Avenue, Suite 300 Elgin, IL 60120 IPECO0216834

FIGURE 8 CSI TECHNOLOGIES, INC. IP2 CHECWORKS SFA Model Plot J.35: RHTR DRN TK-23A USCV S -.. .:C.n:i.

.: i pariSon of Weal Predictions - RHTR DRN K .23A USCVýWREFUEL 19  : . :.  :. .: :.

.LCF.=1,03313<

A

................... ........... ..... I0..........

.Measured Wear (mils)

• R~plced Componrt A Ctto-rl Co-,ronw *.-50l%

Plot J.36: RHTR DRN TK 23B USCV Comparison of Wear Predictions - RIITR URNTN 2313USCV 4-REFUEL V~

LCF =0 989746 1Z.

. . . .. . . . . . . . . Measured

. . Wear (mils)  :

.:REPI.Ced Compnof- A Curret .Camp-"re~ .

Calculation No. 0705.101-01, Appendix J, Revision 1 Page J-19 of 21 IPECO0218028

FIGURE 9 CS, TECHNOLOGIES, INC. IP2 CHECWORKS SFA Model Plot J.37: RHTR DTK A DRN DSCV

• ...... . .. Co.nparis.ii. of W a . Piedictens.

.K .S. R.R A ORN - '4. ....L 1 .. X: "1.

... LCF =11016 IL Measured Wear (mils): . .

0 Repl*ced C-p.onrr .A current C

..o*fr nent Plot J.38: RHTR DTK B DRN DSCV Comparlson of Wear Predictions" -RHTR DTKB ORN DSCV :@REFUEL 19 LCF = 1 19272 21CO 0 100 200 300

................ ..... Measured Wear (niis).

...0 Rep]iled Cn orrt ..A CuerenComrr tnt.r .-. soa%

Calculation No. 0705.101-01, Appendix J, Revision 1 Page J-20 of 21 IPECO0218029

Indian Point Unit 3 CHECWORKS FAC Model Calculation No. 050714c-01 Revision 0 Issued For-Use October 25, 2005 preparedfor.

Entergy Nuclear Northeast 295 Broadway Suite 3 PO Box 308 Buchanan, NY 10511-0308 prepared by:

CSI TECHNOLOGIES, INC.

1051 E. Main St., Suite 215 East Dundee, IL 60118 IPEC00028935

FIGURE 10 CSI Technologies, Inc. IP3 CHECWORKS FAC Model Comparison of Wear Predictions 0D Measured Wear (mils)

• Current Component Calculation No. 050714c-01, Revision 0, Appendix I Page 1-29 of 349 IPEC00029580

FIGURE 11 CSI Technologies, Inc. 1P3 CHECWORKS FAC Model Comparison of Wear Predictions GO N

Measured Wear (mils)

• Current Component Calculation No. 050714c-01, Revision 0, Appendix I Page 1-187 of 349 IPEC00029738

FIGURE 12 CSi Technologies, Inc. 1P3 CHECWORKS FAC Model

.Comparison of Wear Predictions MSD: MS 32 TO MSDT LCF 4.136 160 -- --

120 -___ +50%9 __

80- - _

60t _ __50%

-' 40 -_ __

60 80 100 120 Measured Wear (mils)

• Current Component Calculation No. 050714c-01, Revision 0, Appendix I Page 1-259 of 349 IPEC0002981 0

Indian Point Unit 3 CHECWORKS SFA Model Calculation No. 0705.100-01 Revision 0 Issued. For-Use November 14, 2007 Preparedfor:

Entergy Nuclear- Northeast 295 Broadway Suite 3

.... PO Box 308 Buchanan, NY 10511-0308 Prepared by:

CSi TECHNOLOGIES, INC.

1051 E. Main St., Suite 215 East Dundee, IL 60118

CSI TECHNOLOGIES, INC. IP3 CHECWORKS SFA Model CS! TECHNOLOGIES, INC. 1P3 CHECWORICS SFA Model Comparison of Wear Predictions - FW: SG HEADERS @!Cycle 15 LCF = 3.42342 C.2

-a a,

IL 0 100 200 300 Measured Wear (mils) 0 Replaced Component A Current Component -- +/-50%

m 0

0 C) 00 O Calculation No. 0705.100-01, Revision 0, Appendix I Page 1-306 of 590

CSI TEcHNoLoGIE'S, INc. IP3 CHECWORKS SFA Model CSI TECHNOLOGIES, INC. 1P3 CHECWORKS SFA Model Comparison of Wear Predictions -MSD: MS 32 TO MSDT @jiycle 15 LCF = 13.9913 a)

U.

IL 0 100 Measured Wear (mils) 0 Replaced Component A Current Component - +1-50 %

m 00 K) Calculation No. 0705.100-01, Revision 0, Appendix I Page 1-435 of 590 0

CSI TEcHNoLOGIES, INC. IP3 CHECWORKS SFA Mod6l CSi TECHNOLOGIES, INC. 1P3 CHECWORJCS SFA Mod~I Conhlharlsol of Weai Predictions- MSD: MSDT 33 TO HDT *'CycIe 15 LCF = 3.76998 (n

0)

(a C 0) 0~ m F"

A Measured Wear (mils)

• Replaced Component & Current Component - +1-50 %

m 0

0 0

0 00 N)3 Calculation No. 0705.100-01, Revision 0, Appendix I Page 1-476 of 590 0

Indian Point Unit 3 CHECWORKS SFA Model Calculation No. 0705.100-01 Revision 1 Issued For-Use February 12, 2010 preparedfor:

Entergy Nuclear Northeast Indian Point Unit 3 295 Broadway Suite 3 P.O Box 308 Buchanan, NY 10511-0308 preparedby:

CSI TECHNOLOGIES, INC.

1 Douglas Ave, Suite 300 Elgin, IL 60120

FIGURE 16 CSI TECHNOLOGIES, INC. IP3 CHECWORKS SFA Model Plot J.19: ES: PRESEP TO 35 HDR Comparison of Wear Predictions -ES: PRESEP TO 35 HDR @iCycle 16 LCF =2.06052 600-

.- r 500 i "

w 400 Ce a,

a, 300 -- - --

0. A A.

a, a

200 - A A--~

A h AY*  :. V

• ------. 9 1o0.

- 9

-~ 7~ 9 ---.------- ..- - A V - 9 0 100 .2 *300 400 Measured Wear (mils) 9 Replaced Component A Current Component +1.50 %

1 Page J-20 of 46 Calculation No.

Calculation Appendix J, 0705.100-01, Appendix No. 0705.100-01, J, Revision Revision I Page J-20 of 46

FIGURE .17 CSI TECHNOLOGIES, INC. IP3 CHECWORKS SFA Model Plot J.23: FW: SG HEADERS Comparison of Wear Piedictions - FW: SG HEADERS @Cycle 16 LCF =3.42342 700-600 500 U) 400-300o 200-

• A, 100 0 .. 100 200 300 400 Measured Wear (mils)

• Replaced Component A Current Component - +1-50%

Page J-24 of 46 Calculation No. Appendix J, 0705.100-01, Appendix No. 0705.100-01, Revision 11 J, Revision Page J-24 of 46

FIGURE18 CS, TECHNOLOGIES, INC. IP3 CHECWORKS SFA Model Plot J.41: RHD: RH 32B TO HDR Comiparison of Weat Pedictions - RHO: RH 32B TO HDR 4Ccide 16 LCF =2.93,243 200-A AA '

V ~ A 100 n A, A A k

.Z iA A

Uf, I I 100 Measured Wear (mils)

• Replaced Component A Current Couponent 4.50%

Page J-44 of 46 Calculation No. 0705.100-01, Calculation No. Appendix J, 0705.100-01, Appendix Revision 1 J, Revision I Page J-44 of 46

Riverkeeper Opposition to Entergy's Motion For Summary Disposition of Riverkeeper Technical Contention 2 (Flow-Accelerated Corrosion)

Riverkeeper TC-2: Attachment 8

Indian Point Unit 2 CHECWORKS FAC Model Calculation No. 050714b-01 Revision I Issued For-Use September 12, 2006 preparedfor:.

Entergy Nuclear Northeast 295 Broadway Suite 3 PO Box 308 Buchanan, NY 10511-0308 preparedby:

CSI TECHNOLOGIES, INC.

1051 E. Main St., Suite 215 East Dundee, IL 60118

CSI TECHNOLOGIES, INC. 1P2 CHECWORKS FAC Model CHECWORKS FAC allows a number of options to determine the value of the minimum measured thickness (T...) of an inspected component.

"Min. Meas Thickness from Region of Max. Wear" (GW)-uses the smallest thickness value from the region that has the highest wear. This option is selected by default if the wear calculation uses the band, blanket, or area methods. The second option used, "Minimum-Measured Thickness" (MT), uses the smallest thickness value from any region. MT was chosen for subcomponents that had counterbore, for baseline inspections, when wear was calculated using the point-to-point method, and when the MT value was over 0.040" less than the GW value.

Since the MT method uses the minimum reading from the entire UT inspection grid and the GW method uses the minimum reading from the region where wear is maximum, the T..e, value calculated by MT will be less than or equal to the value calculated by GW in all cases. Thus MT is the more conservative method. However, conservatism is not always ther best option in the CHECWORKS model. Because the CHECWORKS model contains many components, using an overly conservative method to calculate the remaining life of one component may cause that component to be selected for inspection at the expense of another. Therefore, the method used was to model components as realistically as possible. See Section 4.1.1 for further discussion on conservatism in the CHECWORKS model.

For inspected components, the Tmeas value listed in the "Wear Rate Analysis: Wear Predictions Report" in the Pass 2 Analysis, Appendix I, may not match the measured minimum thickness from the UT readings.

In all cases, the Tea, values should not conflict by more than 0.040". Note that the "Wear Rate Analysis: Wear Predictions Report" in Appendix I lists the T.e.s method, MT or GW, that was used.

5.4.6. Pass 2 Wear Rate Analyses (WRA) and Line Correction Factor (LCF)

Pass 2 Wear Rate Analysis was performed on the Wear Rate Analysis Runs as defined with one change: the Analysis Option, "Do Not Use Measured Wear" was deselected. As in Pass 1 WRA, Pass 2 WRA will generate for each component a predicted wear rate, and a predicted remaining service life. During Pass 2 WRA, CHECWORKS also generates a Line Correction Factor (LCF) for each WRA Run in the following way. For each inspected component in the run where the option "Do Not Use for LCF" is not chosen, CHECWORKS generates a ratio of the calculated wear to the predicted wear. The LCF for a run is defined as the median value of these ratios. CHECWORKS multiplies the Pass 1 wear predictions by the LCF to generate the Pass 2 wear predictions.

The LCF indicates the degree to which CHECWORKS over or under-predicts wear. A reasonable LCF should be between 0.5 and 2.5 [7.8]. An LCF outside this range may be the result of inaccuracies in the model (e.g., incomplete chemistry history) or non-representative inspection data.

Calculation No. 050710-01, Revision I Page 19 of 30

August 16, 2010 UNITED STATES OF AMERICA NUCLEAR REGULATORY COMMISSION ATOMIC SAFETY AND LICENSING BOARD In the Matter of

)

Entergy Nuclear Operations, Inc. ) Docket Nos.

(Indian Point Nuclear Generating ) 50-247-LR Units 2 and 3) ) and 50-286-LR CERTIFICATE OF SERVICE I certify that on August 16, 2010, copies of the foregoing "Riverkeeper Opposition to Entergy's Motion for Summary Disposition of Riverkeeper Technical Contention 2 (Flow Accelerated Corrosion)" along with eight (8) accompanying attachments, were served on the following by first-class mail and e-mail:

Lawrence G. McDade, Chair Judge Kaye D. Lathrop Atomic Safety and Licensing Board Panel 190 Cedar Lane East Atomic Safety and Licensing Board Ridgeway, CO 81432 U.S. Nuclear Regulatory Commission E-mail: Kave.Lathropwnrc.gov Washington, D.C. 20555 E-mail: 'Lawrence.McDade(ihnrc.gov Richard E. Wardwell Michael J. Delaney, V.P. - Energy Atomic Safety and Licensing Board New York City Econ. Development Corp.

U.S. Nuclear Regulatory Commission 110 William Street Washington, D.C., 20555 New York, NY 10038 E-mail: Richard.Wardwellnanrc.gov E-mail: mdelaney.(nvcedc.com John J. Sipos, Esq. Kathryn M. Sutton, Esq.

Assistant Attorney General Paul M. Bessette, Esq.

Office of the New York Attorney General Jonathan M.-Rund, Esq.

for the State of New York Morgan, Lewis & Bockius, LLP The Capitol 1111 Pennsylvania Ave. N.W.

Albany, NY 12224 Washington, D.C. 20004 E-mail: John. Sipos~c-oag. state. ny.us E-mail:

pbessetteamorganlewis.com ksutton~i~morganlewis.comn irund(gmorganlewis.com

Robert D. Snook, Esq. John L. Parker, Esq.

Assistant Attorney General Regional Attorney,,Region 3 55 Elm Street, P.O. Box 120 New York State Department of Hartford, CT 06141-0120 Environmental Conservation E-mail: Robert. Snook((tpo. state.ct.us 21 South Putt Comers New Paltz, NY 12561 E-mail: ilparker(2iýgw.dec.state.nv.us Elise N. Zoli, Esq. Mylan L. Denerstein, Esq.

Goodwin Procter, LLP Executive Deputy Attorney General 53 State Street 120 Broadway, 2 5th Floor Boston, MA 02109 New York, NY 10271 E-mail: ezoli Cd)goodwinprocter.com E-mail: mylan.denerstein(dAoag.state.ny .us Sherwin E. Turk Sean Murray, Mayor Beth N. Mizuno Village of Buchanan Brian G. Harris Municipal Building David E. Roth 236 Tate Avenue Andrea Z. Jones Buchanan, NY 10511-1298 Office of General Counsel E-mail: vob abestweb.net, Mail Stop: 0-15D21 SMurray(?i)villageotbuchanan.com, U.S. Nuclear Regulatory Commission Administratoravillageofbuchanan.com Washington, D.C. 20555-!0001 E-mail: Sherwin.Turk(anrc. gov; Beth.Mizuno(cnrc. gov. brian.han-is(,i)nrc. gov.

David.Roth.Wnrc.gov; andrea.jonesLnrc.gov; Deborah Brancato August 16, 2010 3