ML061440245

Entergy'S Initial Statement of Position on New England Coalition Contention 3; Testimony and Affidavits of Craig J. Nichols and Jose L. Casillas on NEC Contention 3 - Large Transient Testing, with Exhibits 1 - 22

ML061440245
Person / Time
Site:	Vermont Yankee
Issue date:	05/17/2006
From:	Travieso-Diaz M Entergy Nuclear Operations, Entergy Nuclear Vermont Yankee, Pillsbury, Winthrop, Shaw, Pittman, LLP
To:	Atomic Safety and Licensing Board Panel
Byrdsong A T
References
50-271-OLA, ASLBP 04-832-02-A, RAS 11673
Download: ML061440245 (230)

Text

IRA5 4 73 May 17, 2006 UNITED STATES OF AMERICA DOCKETED USNRC NUCLEAR REGULATORY COMMISSION May 17, 2006 (4:02pm)

Before the Atomic Safety and Licensing Board OFFICE OF SECRETARY RULEMAKINGS AND

) -ADJUDICATIONS STAFF In the Matter of )

) Docket No. 50-271 ENTERGY NUCLEAR VERMONT )

YANKEE, LLC and ENTERGY ) ASLBP No. 04-832-02-OLA NUCLEAR OPERATIONS, INC. ) (Operating License Amendment)

(Vermont Yankee Nuclear Power Station) )

)

ENTERGY'S INITIAL STATEMENT OF POSITION ON NEW ENGLAND COALITION CONTENTION 3 Pursuant to 10 C.F.R. § 2.1207(a)(1) and the Atomic Safety and Licensing Board's

("Board") Revised Scheduling Order dated April 13, 2006 ("Revised Scheduling Order"), 'Appli-cants Entergy Nuclear Vermont Yankee, LLC and Entergy Nuclear Operations, Inc. (collectively "Entergy") hereby submit their Initial Statement of Position ("Statement") on New England Coali-tion Contention 3 ("NEC Contention 3"). This Statement is supported by the "Testimony of Craig J. Nichols and Jose L. Casillas on NEC Contention 3 - Large Transient Testing" ("Entergy Dir.")

and exhibits thereto, being filed simultaneously herewith.

I. INTRODUCTION One of the contentions originally proposed by NEC was Contention 3,2 which asserts that Entergy's application for an extended power uprate ("EPU") for the Vermont Yankee Nuclear As directed by the Board, "[t]he initial written statement should be in the nature of a trial brief that pro-vides a precise road map of the party's case, setting out affirmative arguments and applicable legal stan-dards, identifying witnesses and evidence, and specifying the purpose of witnesses and evidence (ie.

stating with particularity how the witness or evidence supports a factual or legal position)." Revised Scheduling Order at 3.

2 New England Coalition's Request For Hearing, Demonstration of Standing, Discussion of Scope of Proceeding and Contentions, dated August 30, 2004, at 11 ( NEC Hearing Request").

ieon plate Sey.. 037 6jCY.- O_

Power Station ("VY") ("EPU Application") should not be approved unless performance of Large Transient Testing ("LTT") is a made a condition of the uprate.3 The scope of NEC Contention 3 has been recently clarified by the Board, which has ruled that "the 'Large Transient Testing' at is-sue in NEC Contention 3, and the testimony and other evidence to be submitted concerning it, are limited to the main steam isolation valve closure test and the turbine generator load rejection test."

Memorandum and Order (Clarifying the Scope of NEC Contention 3) (April 17, 2006), slip op. at 3.

NRC's Review Standard RS-001, "Review Standard for Extended Power Uprates," Revi-sion 0 (December 2003) refers to Standard Review Plan (SRP) 14.2.1, "Generic Guidelines for Extended Power Uprate Testing Programs," ("SRP 14.2.1") for the testing related to extended power uprates.' Entergy Dir. at A18. SRP 14.2.1 in turn specifies that LTT is to be performed as part of the extended power uprate, and that the tests are to be performed in a similar manner to the testing that was performed during initial startup testing of the plant. Id. and Entergy Dir. Exhibit 4 at 14.2.1-5. The SRP also provides guidance on how to justify a request for deletion of testing re-quirements. Entergy Dir. at A19 and Entergy Dir. Exhibit 4 at 14.2.1 14.2.1-10.

The LTT that the SRP seeks to have performed for an EPU are the main steam isolation valve closure test and the generator load rejection test. Entergy Dir. at A17 and Entergy Dir. Ex-hibit 4 at 14.2.1-9. The main steam isolation valve ("MSIV") test is performed by rapidly closing all eight MSIVs from full rated power. Entergy Dir. at A20. Sudden closure of all MSIVs at power is an "Abnormal Operational Transient" as described in Chapter 14 of the VY Updated Fi-nal Safety Analysis Report ("UFSAR"). Id.

3 As admitted by the Board, NEC Contention 3 reads: "The license amendment should not be approved unless Large Transient Testing is a condition of the Extended Power Uprate." Memorandum and Order, LBP-04-28, 60 NRC 548,580, Appendix 1 (2004).

4RS-01 is available in the ADAMS system under accession number ML033640024. The cited provision appears on Section 2.12.1 at 255.

2

A generator load rejection (also known as a "turbine generator load rejection") is initiated by a rapid closure of the turbine control valves after a load rejection. Entergy Dir. at A23. A gen-erator load rejection is an Abnormal Operational Transient as described in Chapter 14 of the UFSAR. Id.

In its EPU Application, Entergy sought an exception to performing LTT as part of the test-ing program for the EPU. Entergy Dir. at Al 0; see also Entergy Dir. Exhibits 5 and 6. In seeking that exception, Entergy addressed the factors outlined in SRP 14.2.1 as justifying not performing the LTT, including: (1) VY's general response to unplanned transients;(2) analyses of specific events; (3) the impact of EPU modifications; and (4) relevant industry experience. Entergy Dir. at A26.

In its Final Safety Evaluation Report for the VY EPU, the NRC Staff agreed that the ex-ception from LITT requested by Entergy should be granted. Entergy Dir. at A28 and Entergy Dir.

Exhibit 7 (Final SER) at 267-271.5 The Staff reached the following conclusion:

Based on its review of the information provided by the licensee, as described above, the NRC staff concludes that in justifying test eliminations or deviations, other than the condensate and feedwater system testing discussed in SE Section 2.5.4.4, the licensee ade-quately addressed factors which included previous industry operat-ing experience at recently uprated BWRs, plant response to actual turbine and generator trip tests at other plants, and experience gained from actual plant transients experienced in 1991 at the VYNPS.

From the EPU experience referenced by the licensee, it can be con-cluded that large transients, either planned or unplanned, have not provided any significant new information about transient modeling or actual plant response. As such, the staff concludes that there is reasonable assurance that the VYNPS SSCs will perform satisfacto-rily in service under EPU conditions. The staff also noted that the 5 The SER is available in ADAMS under accession number ML060050028. Pages 267-271 are included as Entergy Dir. Exhibit 7.

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licensee followed the NRC staff approved GE topical report guid-ance which was developed for the VYNPS licensing application.

Final SER at 271.

Likewise, in its letter to the NRC Chairman following its review of the EPU Application, the Advisory Committee on Reactor Safeguards concluded:

3. Load rejection and main steam isolation valve closure transient tests are not warranted. The planned transient testing program ade-quately addresses the performance of the modified systems.

Letter from Graham B. Wallis to NRC Chairman Nils Diaz dated January 4, 2006 Entergy Dir.,

Exhibit 22.

II. APPLICABLE LEGAL STANDARDS In propounding NEC Contention 3, NEC did not specify what legal standards would be contravened by the granting of the exception from LTT at VY, nor was the issue addressed in the Board's discussion of the issue when the contention was admitted. See NEC Heating Request at 1; 'LBP-04-28, 60 NRC at 571-72. Section 2.12 of the SER for the VY EPU, on the other hand, states that the acceptance criteria for the VY EPU test program "are based on 10 CFR Part 50, Ap-pendix B, Criterion XI, which requires establishment of a test program to demonstrate that SSCs

[structures, systems and components] will perform satisfactorily in service." SER at 261. Crite-rion XI of Appendix B to 10 C.F.R. Part 50 states:

XI. Test Control A test program shall be established to assure that all testing required to demonstrate that structures, systems, and components will per-form satisfactorily in service is identified and performed in accor-dance with written test procedures which incorporate the require-ments and acceptance limits contained in applicable design docu-ments. The test program shall include, as appropriate, proof tests prior to installation, preoperational tests, and operational tests during nuclear power plant or fuel reprocessing plant operation, of struc-tures, systems, and components. Test procedures shall include provi-sions for assuring that all prerequisites for the given test have been met, that adequate test instrumentation is available and used, and 4

that the test is performed under suitable environmental conditions.

Test results shall be documented and evaluated to assure that test re-quirements have been satisfied.

10 C.F.R. 50, Appendix B, Criterion XI.

Entergy agrees that the legal standard for determining whether the EPU should be ap-proved without the performance of LTT is whether, in the absence of LiT, the test program im-plemented by Entergy for the EPU complies with Criterion XI by demonstrating that structures, systems, and components will perform satisfactorily in service at the proposed EPU power level.

III. APPLICANTS' STATEMENT OF POSITION ON FACTUAL ISSUES A. Entergy's witnesses and evidence Entergy's testimony on NEC Contention 3 will be presented by a panel of two experts, each with extensive experience in boiling water reactor ("BWR") operation and the response of BWRs like VY to large transients. The first of Entergy's witnesses, Mr. Craig J. Nichols, is the EPU Project Manager for VY and, in that capacity, he is the manager for the implementation of EPU at VY. Entergy Dir. at A2. As manager for the VY EPU project, Mr. Nichols has been re-sponsible for overseeing the plant modifications needed to implement the upgrade and the per-formance of the technical evaluations and analyses required to demonstrate VY's ability to operate safely under uprate conditions. Id. and Entergy Dir. Exhibit 1. With twenty years of work experi-ence at VY, Mr. Nichols is familiar with VY's operating history, current plant operations, and the anticipated operating conditions after the uprate. Entergy Dir. at A3 and A5.

The other witness in Entergy's panel is Mr. Jose L. Casillas, the Plant Performance Con-sulting Engineer in the Nuclear Analysis group of the Engineering organization of General Elec-tric ("GE") Nuclear Energy. Mr. Casillas is responsible for BWR plant performance design and analyses, including evaluations in support of EPU applications. Entergy Dir. at A7. He has over thirty-three years of direct technical experience working in all aspects of plant performance at GE Nuclear Energy, including transient analysis. He is familiar with the analytical codes used to pre-5

dict BWR plant response to operational transients and with the industry experience regarding the response of BWRs to large transients. Id. at A7 - A9 and Entergy Dir. Exhibit 2.

The testimony and opinions of the Entergy witnesses on NEC Contention 3 are based on both their technical expertise and experience and their first hand knowledge of the issues raised in NEC Contention 3. By contrast, NEC's witness on this contention, Dr. Joram Hopenfeld, has pro-vided no indication that he has any experience or expertise in the analysis or evaluation of large operational transients at BWRs, nor does he profess to have any familiarity with the operational experience at either VY or other comparable plants with large transients. See "Curriculum Vitae for Dr. Joram (Joe) Hopenfeld," Exhibit A to NEC's Answer to Entergy's Motion for Summary Dis-position of New England Coalition Contention 3 (Dec. 22, 2005).

The evidence provided by the Entergy witnesses demonstrates that there is no support for the claims made in NEC Contention 3. The extensive and conservative engineering analyses, his-torical test and actual transient data, individual component testing, and observed performance at other plants experiencing large transients provide reasonable assurance and confidence that VY systems will function as designed in mitigation of large transients from EPU conditions. The po-tential benefits, if any, from LTT at VY are significantly outweighed by the adverse effect on plant systems and components from the tests themselves. VY's request for an exception to LTT, there-fore, is reasonable and poses no threat to public health and safety. Entergy Dir. at A61.

B. The analytical tools used by Entergy provide transient response predic-tions that bound plant performance in large transient events under EPU conditions

1. In advance of implementation of the EPU, GE performed analyses of the performance of VY under EPU conditions. These analyses included, among others, the results of licensing basis large transient simulations conducted using GE's ODYN code. Entergy Dir. at A40 and Entergy Dir. Exhibit 8.

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2. The results of these simulations verified that: (1) these transients remain the limiting tran-sients from the perspective of the selected parameters, and (2) the results remain within the design and license limits, and show significant margin to the limits. Id.

3. The large transient analyses for VY predict the behavior of the safety- and non-safety-related systems in the plant during operational transients. These large transient analyses model both the performance of the secondary side of the plant and any relevant potential interactions between primary and secondary systems in a transient to evaluate the parame-ters of interest. Id. at A29.

4. ODYN is a proprietary code developed by GE and approved by the NRC in 1981 for use in the analysis of GE BWR plant response to pressurization transients. A description of the ODYN model and the qualification as well as the NRC Safety Evaluation Report can be found in NEDO 24154-A (proprietary) dated August 1986. The ODYN model has been upgraded over the last 20 years to include greater modeling detail such as increased nodes, advanced physics correlations, and more representative control systems. These changes have consistently improved the accuracy of the ODYN code and reduced the uncertainty in its predictions compared against the qualification tests. Recently, the ODYN model has been approved by the NRC for application to all GE BWR plant transients. Id. at A30.

5. The ODYN code models BWR vessel physical components, mechanical equipment func-tions, control systems and nuclear/thermal-hydraulic phenomena. The simulation involves describing the physical plant in the model (i.e., volumes, flow paths, resistances), estab-fishing the desired operating conditions (i.e., water level, power, pressure) and introducing a disturbance (i.e., valve closure, pump trip, control action). The ODYN model predicts the plant response behavior based on its physical model correlations. The ODYN code has 7

been assessed against actual MSIV closure transients and load rejection transients at an oper-ating facility. [d. at A3 1.

6. The ODYN analyses assume operational configurations and component/system failures that bound (i.e., represent more severe conditions than) the transients that would occur dur-ing normal plant operations or design basis events, including large transients. Id.

7. The ODYN code is accepted as a best estimate code, though it includes some conservative biases due to simplified aspects of the model. GE has qualified the ODYN code against all significant plant transients and the NRC has accepted that the ODYN code is a dependable best estimate code. Id. at A34. As a best estimate code benchmarked against all signifi-cant transients, ODYN is capable of predicting accurately the plant behavior during tran-sients occurring at higher EPU power levels. Id. at A35.

8. The ODYN code has been benchmarked against all significant plant transients including turbine trip (equivalent in its effects to a generator load rejection test) and MSIV closure events. Id. at 36. The turbine trip data were obtained from the Peach Bottom and KKM -

Muhlenberg plants; the MSIV closure data were obtained from the Hatch plant. Id. at A37.

9. The results of ODYN's benchmark assessments demonstrate the ability of the code to accu-rately predict plant performance during large transients. All versions of the ODYN code have been assessed against the benchmark tests and continue to form the basis for the code's accuracy. The current version of the ODYN code continues to accurately predict the overpower magnitude and slightly overpredict the overpressure magnitude. Id.

10. It is reasonable to conclude that the ODYN simulations of VY's behavior in large tran-sients during EPU operation accurately predicts the actual plant response to those tran-sients because the ODYN model is qualified for the analysis of this type of transient and 8

the resulting parameters are within the applicable physical correlations of the model for the bounding licensing analysis. Also, a VY LTT at the increased power condition at constant pressure would be significantly milder than the ODYN analyses. Several plant transients have been compared against ODYN predictions over the years to assess the specific BWR licensing basis. All of these comparisons have determined that the licensing predictions are bounding and that the plant equipment response is consistent with its design basis. Id at A41.

C. The behavior of BWRs that have undergone EPUs under large tran-sients has been satisfactory and within the bounds of analytical predic-tions, thus confirming the validity of the transient analysis methodology

11. The VY EPU was implemented following the guidelines contained in the NRC-approved document "General Electric Company Licensing Topical Report (CLTR) for Constant Pressure Power Uprate Safety Analysis: NEDC-33004P-A Rev. 4, July 2003" ("NEDC-33004P-A"). Implementation of the guidance in NEDC-33004P-A results in an increase in reactor power without an increase in reactor operating pressure (i.e., a "constant pressure power uprate" or "CPPU"). Id. at Al 3.

12. Thirteen BWRs similar to VY have implemented EPUs without increasing reactor operat-ing pressure, including eleven plants in the United States and two in Switzerland (KKL -

Leibstadt and KKM - Muhlenberg). Id. at A15. None ofthe eleven domestic BWR plants similar to VY that have implemented EPUs without increasing reactor operating pressure has been required to perform LTT at EPU power levels. Id.

13. Those thirteen plants are similar to VY in all significant respects that bear on large tran-sient performance. Id. at A16. For example, the Brunswick units are both BWR/4 plants with Mark 1 containments, like VY. Comparison of the designs of important parameters 9

for the Brunswick and VY plants shows their striking similarities in areas such as power density, steam relief and bypass capacities that would affect the large transient perform-ance of the plants. Such similarity supports the prediction that the performance of both plants in the event of a large transient would be substantially the same. Id. and Entergy Dir.

Exhibit 3.

14. Of the thirteen BWR plants that have implemented EPUs without increased reactor operat-ing pressure, four (Hatch I and 2, Brunswick 2, and Dresden 3) have experienced one or more unplanned large transients from uprated power levels. Entergy Dir. at A44 and En-tergy Dir. Exhibits 9-16.

15. Hatch Unit 2, which like VY has a BWR/4 Mark I reactor, experienced a post-EPU un-planned event that resulted in a generator load rejection from approximately 111% original rated thermal power ("OLTP") (98% of uprated power) in May 1999. All systems at Hatch Unit 2 functioned as expected and no anomalies were seen in the plant's response to this event. Entergy Dir. at A44 and Entergy Dir. Exhibit 9.

16. Hatch 2 also experienced a post-EPU reactor trip on high reactor pressure as a result of MSIV closure (from 113% OLTP (100% of uprated power)) in 2001. All systems func-tioned as expected and designed, given the conditions experienced during the event. En-tergy Dir. at A44 and Entergy Dir. Exhibit 10.

17. Hatch Unit 1, which like VY has a BWR/4 Mark I containment, has experienced two post-EPU turbine trips from 112.6% and 113% of OLTP (99.7% and 100% of uprated power).

Again, the behavior of the primary safety systems was as expected. No new plant behav-iors for either plant were observed. Entergy Dir. at A44 and Entergy Dir. Exhibits 11 and 12.

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18. The performance of the Hatch units during transients was bounded by the ODYN code predictions for those units. Entergy Dir. at A44.

19. The Hatch operating experience shows that the analytical models being used at VY are ca-pable of modeling plant behavior at EPU conditions. Id.

20. Progress Energy's Brunswick Unit 2, which is a BWRI4 with a Mark I containment very similar to VY, experienced a post-EPU unplanned event that resulted in a generator/turbine trip due to loss of generator excitation from 115.2% OLTP (96% ofuprated thermal power) in the fall of 2003. No anomalies were experienced in the plant's response to this event, and no unanticipated plant behavior was observed. Entergy Dir. at A44 and Entergy Dir. Exhibit 13.

21. The Brunswick Unit 2 operational experience shows that the analytical models being used at Brunswick (which are the same as those used at VY) are capable of modeling primary and secondary plant behavior at EPU conditions. Entergy Dir. at A44.

22. Exelon Generating Company LLC's Dresden Unit 3, like VY a BWR/4 with a Mark I con-tainment, experienced in January 2004 two turbine trips from 112.3% and 113.5% of OLTP (96% and 97% of uprated power). The plant response was as predicted in the tran-sient analyses, which use the same methodology as those performed at VY. Entergy Dir.

at A44 and Entergy Dir. Exhibits 14 and 15.

23. In May 2004, Dresden 3 also experienced a loss of offsite power which resulted in a tur-bine trip on Generator Load Rejection from 117% of OLTP (100% of uprated power). The plant response was again as predicted in the transient analyses. Entergy Dir. at A44 and Entergy Dir. Exhibit 16.

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24. The Dresden 3 response to these transients indicates that the analytical models used for transient analyses (which are the same as those used at VY) are capable of accurately pre-dicting transient plant behavior at EPU conditions. Entergy Dir. at A44.

25. In all cases, the plants experienced no anomalous response to large transients from EPU operating levels and the plant response was as predicted in the transient analyses, which use the same methodology as those performed at VY. Id.

26. In every instance in which unplanned large transients from EPU power levels were experi-enced at these plants and an analysis of the scenario involved in the transients existed, the plant's response was bounded by the analyses performed using ODYN and no new phe-nomena were exhibited in the response. Id. at A45.

27. The response of these plants to operational transients indicates that the analytical models used for transient analyses are capable of accurately predicting transient plant behavior at EPU conditions and supports the conclusion that VY should also respond as predicted to large transients during EPU operation. Id. at A44.

D. Industry experience with Large Transient Testing Confirms the Ana-lytical Predictions

28. LTT has been performed after an EPU at one plant similar to VY. The KKL (Leibstadt) power uprate implementation program was performed during the period from 1995 to 2000. Power was raised in steps from its previous operating power level of 104.2% OLTP to 119.7% OLTP. Uprate testing was performed at I 10.4% OLTP in 1998, 113.4% OLTP in 1999, 116.7% OLTP in 2000 and 119.7% OLTP in 2002. KKL testing for major tran-sients involved turbine trips at 113.4% OLTP and 116.7% OLTP, and a generator load re-jection test at 104.2% OLTP. Id. at A46.

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29. The transient tests at KKL showed that the uprate analyses performed by KKL (which were performed using the ODYN code, as were VY's) consistently reflected the behavior of the plant. Id.

30. A comparison of the KKL turbine test transient performance against the ODYN predic-tions shows consistency between the test results and those predicted in the model's qualifi-cation, as well as in other comparisons between ODYN runs and plant operating data. In all cases, the ODYN model slightly overpredicts vessel peak pressure. Id. at A47.

31. The KKL turbine trip test is an excellent prediction of what a test at VY would show be-cause KKL has a 2% higher power density than VY and both plants are of a full turbine bypass capacity design. Id.

32. The fact that the Hatch, Brunswick and Dresden plants, all of which are similar in design to VY, experienced no anomalous response to large transients from EPU operating levels supports the conclusion that VY should also respond as predicted to large transients during EPU operation. Id. at A44.

E. The VY Operational Experience Justifies the LTT Exception

33. Between 1991 and 2005, VY experienced five large transient while operating at full pre-EPU power levels. Id. at A49 and Entergy Dir. Exhibits 17-21.

34. No significant anomalies were seen in the plant's response to those five events. The per-formance of VY in the transients it experienced at pre-EPU power levels was well within the bounds of the ODYN analyses. Entergy Dir. at A50.

35. VY's historical response to large transients provides a basis for an exception to LTT. In particular, the transients in 2004 and 2005 occurred after most of the modifications associ-ated with EPU were already implemented, including the new HP turbine rotor, Main Gen-13

erator Stator rewind, the new high pressure feedwater heaters, condenser tube staking, an upgraded isophase bus duct cooling system, and condensate demineralizer filtered bypass.

In each instance, the modified or added equipment functioned normally during the tran-sient. The plant's performance during these recent transients, including that of the modi-fied components, demonstrates that the EPU modifications do not significantly affect the plant's response during transient conditions. Id. at A51.

F. System and component testing during normal operations provide a ba-sis for an exception to LTT

36. Technical Specification-required surveillance testing (S.g., component testing, trip logic system testing, simulated actuation testing) is routinely performed during plant operations.

Such testing demonstrates that the structures, systems and components ("SSCs") required for appropriate transient performance will perform their functions, including integrated performance for transient mitigation as assumed in the transient analysis. Id. at A52.

37. The main components involved in LTT are tested frequently. The MSIVs are tested quar-terly. The safety relief valves and spring safety valves are tested once every operating cy-cle. These valves are required to perform in accordance with the design during large tran-sients; their periodic testing assures that their performance during large transients will be acceptable. Likewise, the reactor protection system instrumentation that is relied on to mitigate large transients is tested quarterly, assuring that it will carry out its design func-tion in the event of a large transient. Id. at A53.

38. Because the characteristics and functions of SSCs are tested periodically during plant op-erations, they do not need to be demonstrated further in a large transient test. In addition, limiting transient analyses (i.e., those that affect core operating and safety limits) are re-14

performed for each operating cycle and are included as part of the reload licensing analy-sis. Id. at A54.

G. Similarities in pre- and post-EPU plant design and physical configura-tion suggest that EPU implementation should have no effect on the plant's response to large transients

39. There are great similarities in design and system function between the pre- and the post-EPU VY plant configuration Id. at A55. While some operating parameters (e.g.. core power distribution) have been modified to accommodate EPU operation and some setpoint changes were made, these changes do not measurably contribute to response to large tran-sient s. None of the modifications that have been made will introduce new thermal-hydraulic phenomena as a result of power uprate, nor are any new system interactions dur-ing or as the result of analyzed transients introduced. No systems have been added or changed at VY that are required to mitigate the consequences of the large transients that would be the subject of the LTT. Id.

40. Operationally, the EPU modifications have no significant effect on plant transient analysis because, since the uprate is a constant pressure uprate, most of the plant's systems will op-erate in the same manner as before the uprate. Also, the VY EPU is performed without a change in operating reactor dome pressure from current plant operation. Id.

41. There have been no major equipment modifications or new hardware installations at VY that could result in different large transient performance than that predicted by the analyses and the plant's prior operating history. Id. at 56. Most of the EPU modifications were made to non-safety related components, which are not credited in licensing basis transient analyses. Incidental modifications associated with EPU, such as alarms, indications, and scaling changes also do not impact transient response. Id. at A56.

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42. Not only are the number of equipment modifications and additions relatively small but none of these modifications will introduce any new thermal-hydraulic phenomena as a re-sult of the power uprate. Nor are any new system interactions during or as the result of analyzed transients introduced. Id. at A57.

43. VY's performance during the 2004 and 2005 transients, which occurred after most of the modifications associated with EPU were already implemented, demonstrates that the EPU modifications do not significantly affect the plant's response during transient conditions.

Id. at A51.

H. LTT would have an adverse impact on VY without compensating safety benefits

44. The performance of a SCRAM from high power, such as those that take place during LTT, results in an undesirable transient cycle on the primary system. The occurrence of primary system transient cycles should be minimized, since they introduce unnecessary stresses on the primary system components. Id. at A58.

45. An MSIV closure test performed as part of LTT would not result in an appreciable tran-sient because the SCRAM signals would issue from the MSIV position switches and a SCRAM would immediately take place. Id. at A22.

46. A generator load rejection test performed as part of LTT would result in bypass valve opening and would in effect be the same as any plant trip at full power and thus provide no comparable information to that resulting from an actual GLRWB transient. Id. at A25.

47. If performed, the MSIV closure and generator load rejection tests would not confirm any new or significant aspect of performance that is not routinely demonstrated by component level testing and demonstrated through analyses. Id. at A27.

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48. The undesirable effects of performing the tests outweigh the benefits of any limited addi-tional information that may be gained from them. Id. at A58.

49. In addition, performance of each LTr causes a plant shutdown. Any plant shutdown re-sults in a generation outage for a period of time (typically 2-3 days) for the plant. Since there are no measurable safety benefits to be derived from the performance of the tests, the loss of generation revenue and other costs associated with the performance of the tests cannot be economically justified. Id.

IV. CONCLUSION The extensive and conservative engineering analyses, historical test and actual transient data, individual component testing, and observed performance at other plants experiencing large transients provide reasonable assurance and confidence that VY systems will function as designed in mitigation of large transients from EPU conditions. The potential benefits, if any, from LTT at VY are significantly outweighed by the adverse effect on plant systems and components from the tests themselves. VY's request for an exception to LTT, therefore, is reasonable and poses no threat to public health and safety. Id. at A61.

Consequently, the test program implemented by Entergy for the EPU, which excludes the performance of LIT, complies with Criterion XI of Appendix B to 10 C.F.R. Part 50 by 17

demonstrating that structures, systems, and components will perform satisfactorily in service at the proposed EPU power level.

Respectfully submitted, a1k F JayE. Silberg Matias F. Travieso-Diaz PILLSBURY WINTHROP SHAW PITTMAN LLP 2300 N Street, N.W.

Washington, DC 20037-1128 Tel. (202) 663-8063 Counsel for Entergy Nuclear Vermont Yankee, LLC and Entergy Nuclear Operations, Inc.

Dated: May 17, 2006 18

UNITED STATES OF AMERICA NUCLEAR REGULATORY COMMISSION Before the Atomic Safety and Licensing Board In the Matter of )

Docket No. 50-271 ENTERGY NUCLEAR VERMONT )

YANKEE, LLC and ENTERGY ) ASLBP No. 04-832-02-OLA NUCLEAR OPERATIONS, INC. ) (Operating License Amendment)

(Vermont Yankee Nuclear Power Station) )

)

CERTIFICATE OF SERVICE I hereby certify that copies of "Entergy's Initial Statement of Position on New England Coalition Contention 3," Testimony of Craig J. Nichols and Jose L. Casillas On NEC Contention 3 - Large Transient Testing," "Affidavit of Craig J. Nichols," and "Affida-vit of Jose L. Casillas" were served on the persons listed below by deposit in the U.S. mail, first class, postage prepaid, and where indicated by an asterisk by electronic mail, this 17th day of May, 2006.

• Administrative Judge *Administrative Judge Alex S. Karlin, Chair Lester S. Rubenstein Atomic Safety and Licensing Board Panel 4760 East Country Villa Drive Mail Stop T-3 F23 Tucson AZ 85718 U.S. Nuclear Regulatory Commission lesmrr(comcast.net Washington, D.C. 20555-0001 ask2(@nrc.gov

• Administrative Judge Atomic Safety and Licensing Board Dr. Anthony J. Baratta Mail Stop T-3 F23 Atomic Safety and Licensing Board Panel U.S. Nuclear Regulatory Commission Mail Stop T-3 F23 Washington, D.C. 20555-0001 U.S. Nuclear Regulatory Commission Washington, D.C. 20555-0001 aib5(anrc.Rov

• Secretary Office of Commission Appellate Adjudica-Att'n: Rulemakings and Adjudications Staff tion Mail Stop 0-16 Cl Mail Stop 0-16 Cl U.S. Nuclear Regulatory Commission U.S. Nuclear Regulatory Commission Washington, D.C. 20555-0001 Washington, D.C. 20555-0001 secynrc.gov, hearingdocket(anrc.gov

• Raymond Shadis *Sherwin E. Turk, Esq.

New England Coalition *Steven C. Hamrick, Esq.

P.O. Box 98 Office of the General Counsel Shadis Road Mail Stop 0-15 D21 Edgecomb ME 04556 U.S. Nuclear Regulatory Commission shadis(lprexar.com Washington, D.C. 20555-0001 set(inrcjgov, schl (dnrc.gov

• Jered Lindsay *Jonathan Rund Atomic Safety and Licensing Board Panel Atomic Safety and Licensing Board Panel Mail Stop T-3 F23 Mail Stop T-3 F23 U.S. Nuclear Regulatory Commission U.S. Nuclear Regulatory Commission Washington, D.C. 20555-0001 Washington, D.C. 20555-0001 JJL5(flrc. Qov imr3awnrc.gov Matias F. Travieso-Diaz 2

May 17, 2006 UNITED STATES OF AMERICA NUCLEAR REGULATORY COMMISSION Before the Atomic Safety and Licensing Board

)

In the Matter of )

) Docket No. 50-271 ENTERGY NUCLEAR VERMONT YANKEE, LLC and ENTERGY ) ASLBP No. 04-832-02-OLA NUCLEAR OPERATIONS, INC. ) (Operating License Amendment)

(Vermont Yankee Nuclear Power Station) )

)

TESTIMONY OF CRAIG J. NICHOLS AND JOSE L. CASILLAS ON NEC CONTENTION 3 - LARGE TRANSIENT TESTING

May 17, 2006 UNITED STATES OF AMERICA NUCLEAR REGULATORY COMMISSION Before the Atomic Safety and Licensing Board

: )

In the Matter of )

) Docket No. 50-271 ENTERGY NUCLEAR VERMONT )

YANKEE, LLC and ENTERGY ) ASLBP No. 04-832-02-OLA NUCLEAR OPERATIONS, INC. ) (Operating License Amendment)

(Vermont Yankee Nuclear Power Station) )

)

TESTIMONY OF CRAIG J. NICHOLS AND JOSE L. CASILLAS ON NEC CONTENTION 3 - LARGE TRANSIENT TESTING I. WITNESS BACKGROUND Craig J. Nichols (CJN")

Ql. Please state your full name.

Al. (CJN) My name is Craig J. Nichols.

Q2. By whom are you employed and what is your position?

A2. (CJN) I am the Extended Power Uprate Project Manager for En-tergy Nuclear Operations, Inc. ("Entergy"). In that capacity, I am the manager for the implementation of the extended power uprate

("EPU") at the Vermont Yankee Nuclear Power Station ("VY").

Q3. Please summarize your educational and professional qualifications.

A3. (CJN) My professional and educational experience is summarized in the curriculum vitae attached to this testimony as Exhibit 1.

Briefly summarized, I have over twenty years of professional ex-perience working in various technical and managerial capacities at

VY. For the last four years, I have managed all activities relating to the implementation of the EPU at VY. I received a B.S. De-gree in Electrical Engineering from Northeastern University.

Q4. What is the purpose of your testimony?

A4. (CJN) The purpose of my testimony is to address, on behalf of Entergy Nuclear Vermont Yankee, LLC and Entergy Nuclear Op-erations, Inc. (collectively "Entergy"), Contention 3 submitted by the New England Coalition ("NEC") in this proceeding. As ad-mitted by the Atomic Safety and Licensing Board ("Board"),

NEC Contention 3 reads:

The license amendment should not be approved unless Large Transient Testing is a condition of the Extended Power Uprate.

Memorandum and Order, LBP-04-28, 60 NRC 548, 580, App. 1 (Nov. 22, 2004).

In addition, the scope of NEC Contention 3 has been clarified re-cently by the Board, which has ruled that "the 'Large Transient Testing' at issue in NEC Contention 3, and the testimony and other evidence to be submitted concerning it, are limited to the main steam isolation valve closure test and the turbine generator load re-jection test." Memorandum and Order (Clarifying the Scope of NEC Contention 3) (April 17, 2006), slip op. at 3.

Q5. What has been your role in the VY EPU project as it relates to NEC Contention 3?

A5. (CJN) In my capacity as manager for the VY EPU project, I have been responsible for overseeing the plant modifications needed to implement the upgrade and the performance of the technical evaluations and analyses required to demonstrate VY's ability to operate safely under uprate conditions. I am familiar with VY's 2

operating history, current plant operations, and the anticipated op-erating conditions after the uprate.

Jose L. Casillas ("JLC")

Q6. Please state your full name.

A6. (JLC) My name is Jose L. Casillas.

Q7. By whom are you employed and what is your position?

A7. (JLC) I am the Plant Performance Consulting Engineer in the Nu-clear Analysis group of the Engineering organization of General Electric ("GE") Nuclear Energy. In that capacity, I am responsi-ble for boiling water reactor ("BWR") plant performance design and analyses, including evaluations in support of EPU applica-tions and the development and application of computer codes used to predict BWR plant performance.

Q8. Please summarize your educational and professional qualifications.

A8. (JLC) My professional and educational experience is summarized in the curriculum vitae attached to this testimony as Exhibit 2.

Briefly summarized, I have over thirty-two years of direct techni-cal experience working in all aspects of plant performance at GE Nuclear Energy, including transient analysis. I received a B.S.

Degree in Mechanical Engineering from the University of Cali-fornia, Davis.

Q9. What is the purpose of your testimony?

A9. (JLC) The purpose of my testimony is to address those aspects of NEC Contention 3 that relate to the industry experience regarding the response of BWRs to large transients.

3

II. OVERVIEW A. Issues Raised By Contention Q10. What is your understanding of the technical issues raised by NEC Contention 3?

A1O. (CJN) In its license amendment application ("EPU Application")

to increase the authorized power level of VY from 1593 mega-watts thermal ("MWt") to 1912 MWt, Entergy sought, in accor-dance with the guidance in Standard Review Plan ("SRP") 14.2.1, to be excused from performing Large Transient Testing ("LTP').

NEC Contention 3 asserts that LTT must be conducted to assure that the public health and safety is protected during EPU opera-tions, and that the EPU should not be approved unless LTT is re-quired to be performed.

Qll. Do you agree with the assertion in NEC Contention 3 that the EPU Application should not be approved unless LTT is a condition to the approval of the license amendment?

All. (CJN, JLC) No.

Q12. What is the basis for your disagreement?

A12. (CJN, JLC) The effects of large transients at EPU conditions can be predicted analytically, on a plant-specific basis, without the need for actual transient testing. This conclusion is supported by:

(a) the similarity of the pre-EPU and post-EPU VY design con-figuration and system functions; (b) results of past transient test-ing at VY and other BWRs and the plants' responses to unplanned transients; (c) confirmation that the transient safety analysis re-suits bound the experience from actual transients; and (d) the ex-perience with unplanned transients at other post-EPU plants.

The transient analyses performed for the VY EPU demonstrate that all safety criteria are met under uprate operating conditions.

On the other hand, a reactor SCRAM from EPU power levels -

4

such as would occur during LTT - would provide no meaningful new information and would cause an undesirable transient cycle on the station's systems.

III. DISCUSSION A. EPU General Description Q13. Please describe the analytical bases for the VY EPU Application.

A13. (CJN) The VY EPU request was prepared following the guide-lines contained in the NRC-approved document "General Electric Company Licensing Topical Report (CLTR) for Constant Pres-sure Power Uprate Safety Analysis: NEDC-33004P-A Rev. 4, July 2003" ("NEDC-33004P-A"). Implementation of the guid-ance in NEDC-33004P-A results in an increase in reactor power without an increase in reactor operating pressure (i.e., a "constant pressure power uprate" or "CPPU").

Q14. Why is a CPPU advantageous?

A14. (JLC) The CPPU methodology, which maintains the same reactor operating pressure as originally licensed, greatly simplifies the engineering analyses and equipment and procedural changes re-quired to achieve uprated conditions. It also assures that the plant's perfornance during transients will be analogous to that be-fore the uprate.

Q15. Have any other plants uprated their thermal power using the CPPU approach?

A15. (JLC) Yes. Thirteen BWRs similar to VY have implemented EPUs without increasing reactor operating pressure:

• Hatch Units l and 2 (1998) (105% to 113% of Original Licensed Thermal Power ("OLTP")) (The Hatch units previously had 5% "stretch" uprates, from 100% to 105% OLTP)

• Monticello (1998) (106% OLTP) 5

• Muehleberg (i.e., KKM) (1993) (105% to 116% OLTP)

• Leibstadt (i.e., KKL) (2000) (104% to 119.7% OLTP)

• Duane Arnold (2001) (104.1% to 119.4% OLTP) (The Duane Arnold unit previously had a 4.1% "stretch" uprate, from 100% to 104.1% OLTP)

• Dresden Units 2 and 3 (2001) (100% to 117% OLTP)

• Quad Cities Units 1 and 2 (2001) (100% to 117.8%

OLTP)

• Clinton (2002) (100% to 120% OLTP)

• Brunswick Units 1 and 2 (2002) (105% to 120% OLTP)

(The Brunswick units previously had 5% "stretch" uprates, from 100% to 105% OLTP).

None of the domestic BWR plants similar to VY that have imple-mented EPUs without increasing reactor operating pressure has been required to perform LTT at EPU power levels.

Q16. How similar are these plants to VY?

A16. (JLC) They are similar to VY in all significant respects that bear on large transient performance. For example, the Brunswick units are both BWR/4 plants with Mark 1 containments, like VY.

Comparison of the designs of important parameters for the Brunswick and VY plants shows their striking similarities in areas such as power density, steam relief and bypass capacities that would affect the large transient performance of the plants. This information has been extracted from UFSAR Tables 1.7.1 through 1.7.4 of the VY and Brunswick plants (attached as Exhibit 3) and supports the prediction that the performance of both plants in the event of a large transient would be substantially the same.

6

Parameter VY Brunswick Comment Power Density, 5.2 5.2 Equivalent MW/assembly Number of 368 560 VY has 34% less fuel and cor-Fuel Assem- respondingly lower steam blies flow than Brunswick.

Steam Line 331 391 VY has 15% smaller length, Length, ft. though the stem flow is corre-spondingly less than Bruns-wick.

Safety and Re- 60 56 Equivalent lief Capacity,

% of Steam Bypass capac- 86 69 VY has 25% greater capacity ity, % of Steam resulting in milder pressure rise following a tur-bine/generator trip.

Turbine Valve </= 0.1 </= 0.1 Equivalent Closure Time, sec.

Main Steam </= 5.0 <1= 5.0 Equivalent Valve Closure Time, sec SCRAM Inser- </= 3.5 <1= 3.5 Equivalent tion Time, sec.

7

B. Large Transient Testing Q17. Which are the tests that are classified as LTTs?

A17. (JLC) NEDC-33004P-A defines two LTTs applicable to EPU op-erations: the Main Steam Isolation Valve ("MSIV") Closure and the Generator Load Rejection tests. These tests, when conducted during plant operation, are similar to counterpart tests performed during initial plant startup testing. The NRC Staff has accepted these two LTTs as verifying that plant performance after EPU will be as predicted. See Exhibit 4, SRP 14.2.1, "Generic Guidelines for Extended Power Uprate Testing Programs" (Draft, 2002)

("SRP 14.2.1"),Section III.C.2.f.

Q18. Does NRC guidance call for the performance of LTT at plants undergoing an EPU?

A18. (JLC) NRC's Review Standard RS-001, "Review Standard for Extended Power Uprates," Revision 0 (December 2003) refers to SRP 14.2.1 for the testing related to extended power uprates. The SRP specifies that LTT is to be performed in a similar manner to the testing that was performed during initial startup testing of the plant. SRP 14.2.1,Section III.A.l.

Q19. Does the SRP make provisions for licensees to take exception to the performance of the LTT?

A19. (CJN) Yes. The SRP provides guidance on how to justify a re-quest for elimination of the LTT requirement. Id,Section III.C.2.

Entergy has followed the SRP guidance in taking exception to performing the large transient tests (i.e., MSIV closure and gen-erator load rejection tests) during EPU operations at VY.

Q20. Please describe the MSIV closure transient.

A20. (CJN) Sudden closure of all MSIVs at power is an "Abnormal Operational Transient" as described in Chapter 14 of the VY Up-8

dated Final Safety Analysis Report ("UFSAR"). The MSIV clo-sure test requires the fast closure (within 3.0 to 5.0 seconds) of all eight MSIVs from full rated power.

Q21. What is the purpose of the MSIV closure test?

A21. (CJN) The MSIV closure test is intended to (1) demonstrate that reactor transient behavior during and following simultaneous full closure of all MSIVs is as expected; (2) check the MSIVs for proper operation; and (3) determine or confirm MSIV closure time at full power.

Q22. What limiting aspect of plant operations is challenged during a Main Steam Isola-tion Valve closure transient?

A22. (CJN) The transient produced by an MSIV closure ("with Flux SCRAM") is the most severe abnormal operational transient from the standpoint of increase in nuclear system pressure. However, for the full licensing basis transient to take place it is necessary that the direct SCRAM signals from the valve position switches that would cause a reactor trip do not occur and that the SCRAM be delayed until the high flux signal is received. For that reason, an MSIV closure test performed as part of LTT would not result in an appreciable transient because the SCRAM signals would is-sue from the MSIV position switches and cause a SCRAM. The prompt SCRAM would significantly reduce the pressure transient that would otherwise occur.

Q23. Please describe a generator load rejection transient.

A23. (CJN) A Generator Load Rejection From High Power Without Bypass ("GLRWB") (commonly referred to as a "turbine genera-tor load rejection" or a "generator load rejection") is an Abnormal Operational Transient as described in Chapter 14 of the UFSAR.

The GLRWB -transient is initiated by a rapid closure of the turbine 9

control valves after a load rejection. For the full licensing basis transient to take place, however, it is necessary that all bypass valves fail to open. (The bypass valves open following a control valve closure to provide a path for steam to the condenser for plant cooldown and to maintain reactor pressure control.)

Q24. What aspect of plant operations is challenged in a GLRWB transient?

A24. (CJN) A GLRWB provides a bounding challenge to the fuel thermal limits, assuming none of the bypass valves open.

Q25. What is the purpose of a generator load rejection test?

A25. (CJN) The purpose of this test is to determine and demonstrate re-actor response to a generator trip, with particular attention to the rates of change and peak values of power level, reactor steam pressure and turbine speed. In reality, however, a generator load rejection test performed as part of LTT would result in bypass valve opening and would in effect be the same as any plant trip at full power and thus provide no comparable information to that re-suiting from an actual GLRWB transient.

Q26. How did Entergy document its request for an exception to the LTT provisions in SRP 14.2.1?

A26. (CJN) Entergy included with its EPU Application as Attachment 7, "Justification for Exception to Large Transient Testing Ex-hibit 5 hereto. Entergy subsequently supplemented its justifica-tion for the requested exception by submitting additional informa-tion. EPU Application, Supplement 3, Att. 2 (Oct. 28, 2003), at-tached as Exhibit 6. In those submittals, Entergy addressed the factors outlined in SRP 14.2.1 as justifying not performing the LTT, including: (1) VY's general response to unplanned tran-sients; (2) analyses of specific transients; (3) the impact of EPU modifications; and (4) relevant industry experience. Entergy ad-10

dressed the justification for not performing LTT in subsequent li-censing submittals, including EPU Application Supplements 19 (October 2004) and 32 (September 2005).

Q27. Why did VY take exception to performing these LTTs for its EPU?

A27. (CJN) If performed, the MSIV closure and generator load rejec-tion tests would not confirm any new or significant aspect of per-formance that is not routinely demonstrated by component level testing and demonstrated through analyses. It is important to note that the EPU transient analyses for VY were performed assuming operational configurations and component/system failures that are impractical to replicate during a testing program and are unlikely to be seen during actual plant operations, and therefore bound (i.e., represent more severe conditions than) the transients that would occur during actual plant operations or during LTTs.

Q28. Has Entergy's request for an exception from LTT been approved by the NRC Staff?

A28. Yes. In its Final Safety Evaluation Report for the VY EPU, the NRC Staff agreed that the exception from L'IT requested by En-tergy should be granted. SER at 267-270, attached as Exhibit 7.

The Staff reached the following conclusion:

Based on its review of the information provided by the licensee, as described above, the NRC staff con-cludes that in justifying test eliminations or devia-tions, other than the condensate and feedwater sys-tem testing discussed in SE Section 2.5.4.4, the li-censee adequately addressed factors which included previous industry operating experience at recently uprated BWRs, plant response to actual turbine and generator trip tests at other plants, and experience gained from actual plant transients experienced in 1991 at the VYNPS. From the EPU experience ref-erenced by the licensee, it can be concluded that large transients, either planned or unplanned, have not provided any significant new information about 11

transient modeling or actual plant response. As such, the staff concludes that there is reasonable as-surance that the VYNPS SSCs will perform satis-factorily in service under EPU conditions. The staff also noted that the licensee followed the NRC staff approved GE topical report guidance which was de-veloped for the VYNPS licensing application.

Q29. Can the behavior of the VY plant during a large transient be bounded analyti-cally?

A29. (CJN) Yes. The large transient analyses for VY, which were per-formed using the NRC-approved code ODYN, predict the behav-ior of the safety- and non-safety-related systems in the plant dur-ing operational transients. These large transient analyses model both the performance of the secondary side of the plant and any relevant potential interactions between primary and secondary systems in a transient to evaluate the parameters of interest.

Q30. Please provide a summary description of the ODYN code.

A30. (JLC) ODYN is a proprietary code developed by GE and ap-proved by the NRC in 1981 for use in the analysis of GE BWR plant response to pressurization transients. A description of the ODYN model and the qualification as well as the USNRC Safety Evaluation Report can be found in NEDO 24154-A (proprietary) dated August 1986. The ODYN model has been upgraded over the last 20 years to include greater modeling detail such as in-creased nodes, advanced physics correlations, and more represen-tative control systems. These changes have consistently improved the accuracy of the ODYN code and reduced the uncertainty in its predictions compared against the qualification tests. Recently, the ODYN model has been approved by the NRC for application to all GE BWR plant transients.

Q31. How does the ODYN code model the behavior of BWRs such as VY during large transients?

12

A31. (JLC) The ODYN code models BWR vessel physical compo-nents, mechanical equipment functions, control systems and nu-clear/thermal-hydraulic phenomena. The simulation involves de-scribing the physical plant in the model (i.e., volumes, flow paths, resistances), establishing the desired operating conditions (i.e.,

water level, power, pressure) and introducing a disturbance (i.e.,

valve closure, pump trip, control action). The ODYN model pre-dicts the plant response behavior based on its physical model cor-relations.

The ODYN analyses assume operational configurations and com-ponent/system failures that bound (i.e., represent more severe con-ditions than) the transients that would occur during normal plant operations or design basis events, including large transients.

Q32. What is your understanding of the term "design codes"?

A32. (JLC) Design codes are the computer simulation models applied in analyses to ensure that the structures, systems and components in a nuclear power plant discharge their intended function during normal, transient and accident conditions. As such, design codes incorporate appropriate margins of conservatism.

Q33. What is your understanding of the term "best estimate codes"?

A33. (JLC) Best estimate codes are computer simulation models ap-plied in analyses intended to accurately predict the actual behavior of a nuclear power plant (or portions thereof) during normal opera-tions, transients, or design basis accidents.

Q34. Which of the two terms, "design code" or "best estimate code", more accurately describes the operation of the ODYN -code?

A34. (JLC) The ODYN code is accepted as a best estimate code, though it includes some conservative biases due to simplified as-13

pects of the model. GE has qualified the ODYN code against all significant plant transients and the NRC has accepted that the ODYN code is a dependable best estimate code.

Q35. What is the impact of the nature of the ODYN code on the ability to obtain realistic predictions of plant behavior during the two large transients that are the subject of this contention?

A35. (JLC) As a best estimate code benchmarked against all significant transients, ODYN is capable of predicting accurately the plant be-havior during transients occurring at higher EPU power levels.

Q36. Has the ODYN code been assessed against actual MSIV closure transients or load rejection transients at an operating facility?

A36. (JLC) Yes, the ODYN code has been benchmarked against all significant plant transients including turbine trips (equivalent in its effects to a generator load rejection test) and main steam valve isolation events. The turbine trip data were obtained from the Peach Bottom and KKM plants; the MSIV closure data were ob-tained from the Hatch plant.

The qualification of ODYN against the plant pressurization tran-sients involved modeling each plant description and simulation of the transient. The ODYN code-predicted parameters are com-pared against the measured data, and the results of the comparison are used to determine the application basis of the ODYN results to licensing analyses.

Q37. Do the results of these benchmark assessments demonstrate the ability of the code to accurately predict plant performance during large transients?

A37. (JLC) Yes. The Peach Bottom turbine trip tests date back to the late 1970s and form the initial benchmark for pressurization tran-sients and uncertainty margins for the ODYN code. All subse-quent advanced versions of the ODYN code have been assessed 14

against these tests and continue to form the basis for the code's ac-curacy. The current version of the ODYN code continues to accu-rately predict the overpower magnitude and slightly overpredict the overpressure magnitude vis-a-vis the Peach Bottom tests. The ODYN model was later also qualified against MSIV transient data and determined to also predict the peak pressure results conserva-tively, consistent with its approved application basis.

Q38. What other assessments have been made of the performance of the ODYN code and its ability to predict the behavior of BWRs such as Vermont Yankee during large plant transients?

A38. (JLC) The ODYN model was initially developed exclusively for the prediction of, and benchmarked against, fast pressure tran-sients such as MSIV closure, turbine trips or GLRWBs. How-ever, since that time, GE has expanded its qualification and appli-cation to include all other significant transients, such as recircula-tion flow and coolant temperature disturbances. The code has been determined to accurately predict plant behavior in those tran-sients.

Q39. Do the large transient analyses compute the stresses that are imparted on mechanical components during the transients under uprate conditions?

A39. (JLC) The best estimate ODYN model is applied using bounding equipment performance and limiting initial conditions to predict the plant behavior. The resulting predicted parameters - princi-pally pressure histories - are used to confirm that the reactor com-ponents and vessel meet the loads used in their design. With re-spect to large transients, the parameter of interest is the peak ves-sel pressure, whose design value is 1375 psig. The overpressure transient analysis is performed to confirm that the predicted peak pressure remains below this design value. No other loads on the vessel or its components are derived from the overpressure tran-15

sient analyses. Therefore, stresses on components are not direct outputs of the ODYN simulations.

Q40. Have transient analyses been performed for MSIV closure and generator load re-jection transients at VY occurring under EPU operation that bound the plant's be-havior during those transients?

A40. (CJN) Yes. In advance of implementation of the EPU, GE pre-pared in December 2005 an updated Supplemental Reload Licens-ing Report ("SRLP") containing analyses of the performance of VY under EPU conditions. The SRLP contained, among others analyses, the results of licensing basis GLRWB and MSIV closure simulations conducted using the ODYN code. Copies of the pages of the SRLP that summarize the results of these simulations are included as Exhibit 8. The results of these simulations veri-fied that: (1) these transients remain the limiting transients from the perspective of the selected parameters, and (2) the results re-main within the design and license limits. Based on the bench-mark results, the peak pressures calculated by ODYN would be overpredicted (conservatively high). These analyses still show significant margin to the limits. This type of analysis is per-formed as part of the core design for each operating cycle.

Q41. Why is it reasonable to conclude that the ODYN simulations of VY's behavior in large transients during EPU operation accurately predicts the actual plant response to those transients?

A41. (JLC) The ODYN model is qualified for the analysis of this type of transient and the resulting parameters are within the applicable physical correlations of the model for the bounding licensing analysis. Also, a VY LTT at the increased power condition at constant pressure would be significantly milder than the ODYN analyses. Several plant transients have been compared against ODYN predictions over the years to assess the specific BWR li-censing basis. All of these comparisons have determined that the 16

licensing predictions are bounding and that the plant equipment response is consistent with its design basis. Furthermore, GE has simulated in detail some of the transients for the purpose of revis-ing the equipment response or setpoints in order to improve the plant response. None of these simulations has shown any ODYN model deficiency with respect to its licensing and qualification basis. Therefore, GE does not expect any model qualification benefit from the VY tests.

C. Technical Bases for Not Performing LTT at VY under EPU Operation Q42. Besides the results of the ODYN analyses that you just described, is there a tech-nical justification for excusing VY from performing LTT under EPU operations?

A42. (CJN, JLC) Yes. There are several sound technical bases that support Entergy's request for an exception from performing LTT at VY under uprate operations.

Q43. What are these bases?

A43. (CJN, JLC) They include: (1) the behavior of other plants that have experienced large transients during EPU operations; (2) the results of LTT conducted at an European plant similar to VY; (3)

V's responses to unplanned transients; (4) the regime of periodic component and system testing at VY; and (5) the similarity in VY's pre- and post- EPU design configuration and system func-tions. From these technical bases, it is reasonable and justifiable to conclude that the effects at EPU conditions can be analytically determined on a plant-specific basis without the need for actual transient testing. The transient analyses performed for the VY EPU demonstrate that all safety criteria are met and the uprate does not cause any previously non-limiting transient to become limiting.

17

D. Industry Experience Confirming the Transient Analysis Meth-odology Q44. What industry experience confirms the basic transient analysis methodology used by Entergy at VY?

A44. (JLC) Of the thirteen BWR plants that have implemented EPUs without increased reactor operating pressure, four (Hatch 1 and 2, Brunswick 2, and Dresden 3) have experienced one or more un-planned large transients from uprated power levels. Specifically:

• Southern Nuclear Operating Company's ("SNOC") application for EPU of Hatch Units 1 and 2 was granted without a re-quirement to perform large transient testing. VY and Hatch are both BWR/4 plants with Mark I containments. Hatch Unit 2 experienced a post-EPU unplanned transient that resulted in a generator load rejection from approximately 111% OLTP (98% of uprated power) in May 1999. As noted in SNOC's LER 1999-005-00 (attached as Exhibit 9), all systems func-tioned as expected and no anomalies were seen in the plant's response to this transient.

• Hatch 2 also experienced a post-EPU reactor trip on high reac-tor pressure as a result of MSIV closure (from 113% OLTP (100% of uprated power)) in 2001. As noted in SNOC's LER 2001-003-00 (attached as Exhibit 10), all systems functioned as expected and designed, given the conditions experienced dur-ing the transient.

• In addition, Hatch Unit 1 has experienced two post-EPU tur-bine trips from 112.6% and 113% of OLTP (99.7% and 100%

of uprated power) as reported in SNOC LERs 2000-004-00 and 2001-002-00, respectively (copies attached as Exhibits 11 and 12). Again, the behavior of the primary safety systems was as 18

expected. No new plant behaviors for either plant were ob-served. The Hatch operating experience shows that the analyti-cal models being used (which are the same as those in use at VY) are capable of modeling plant behavior at EPU conditions.

• As discussed earlier, Progress Energy's Brunswick Units I and 2 - which are very similar in design to VY - were licensed to uprate their power output to 120% of OLTP. Brunswick Unit 2 experienced a post-EPU unplanned transient that resulted in a generator/turbine trip due to loss of generator excitation from 115.2% OLTP (96% of uprated thermal power) in the fall of 2003. As noted in Progress Energy's LER 2003-004-00 (at-tached as Exhibit 13), no anomalies were experienced in the plant's response to this transient, and no unanticipated plant behavior was observed. The Brunswick operational experience shows that the analytical models being used (which are the same as those used at VY) are capable of modeling primary and secondary plant behavior at EPU conditions.

• Exelon Generating Company LLC's applications for EPU for Quad Cities Units 1 and 2, and Dresden Units 2 and 3 were granted without requiring the performance of LTT. The Quad Cities and Dresden units are plants similar to VY, featuring Mark I containments. Dresden 3 has experienced several tur-bine trips and a generator load rejection from high uprated power conditions. In January 2004, Dresden 3 experienced two turbine trips from 112.3% and 113.5% of OLTP (96% and 97% of uprated power) as reported in Exelon LERs 2004-001-00 and 2004-002-00, respectively (attached as Exhibits 14 and 15). The plant response was as predicted in the transient analy-ses, which used the same methodology as those performed at VY. The plant response indicates that the analytical models 19

used for transient analyses are capable of accurately predicting transient plant behavior at EPU conditions.

• Similar plant response was observed in May 2004, when Dres-den 3 also experienced a loss of offsite power which resulted in a turbine trip on Generator Load Rejection from 117% of OLTP (100% of uprated power). See Exelon LER 2004-003-00 (attached as Exhibit 16).

The fact that the Hatch, Brunswick, and Dresden plants, all of which are similar in design to VY, experienced no anomalous re-sponse to large transients from EPU operating levels supports the conclusion that VY should also respond as predicted to large tran-sients during EPU operation.

Q45. Was the ODYN code used to provide the bounding transient analyses for all of these plants?

A45. (JLC) Yes. In every instance in which unplanned large transients from EPU power levels have been experienced at these plants and an analysis of the scenario involved in the transients existed, the plant's response was bounded by the analyses performed using ODYN and no new phenomena were exhibited in the response.

E. Industry experience with Large Transient Testing Q46. Has LUT been performed on any plant after an EPU, and if so what were the test results?

fA46. (JLC) Yes. The KKL (Leibstadt) power uprate implementation

program was performed during the period from 1995 to 2000.

Power was raised in steps from its previous operating power level of 104.2% OLTP to 119.7% OLTP. KKL testing for major tran-sients involved turbine trips at 113.4% OLTP and 116.7% OLTP, and a generator load rejection test at 104.2% OLTP.

20

The response of the KKL reactor and other plant equipment dur-ing those large transient tests was satisfactory and was bounded by the ODYN code predictions for that plant.

Q47. How did the response of the KKL plant to a turbine trip transient compare to the analytical predictions made by the ODYN code?

A47. (JLC) A comparison of the KKL turbine test transient perform-ance against the ODYN predictions shows consistency between the test results and those predicted in the model's qualification, as well as in other comparisons between ODYN runs and plant oper-ating data. In all cases, the ODYN model slightly overpredicts vessel peak pressure. The KKL turbine trip test is an excellent prediction of what a test at VY would show because KKL has a 2% higher power density than VY and both plants are of a full turbine bypass capacity design.

Q48. NEC alleges (December 22, 2005 Answer to Entergy's Statement of Material Facts Regarding NEC Contention 3, para. 20) that since KKL is a foreign reactor not subject to NRC regulation, the KKL test results are irrelevant to the VY EPU, and that even if relevant, there is no ready means of reconciling regulatory data to those applicable to VY. Are these allegations valid?

A48. (JLC) No. Plant test performance is a physically observable phe-nomenon, which can be objectively measured and is independent of the regulatory regime. Furthermore, the same ODYN analyti-cal model as used for VY was applied to simulate this test.

F. VY Operating Experience Q49. Has VY experienced large transients during its operating lifetime?

A49. (CJN) Yes. VY has previously experienced the following un-planned large transients:

• On 3/13/1991, with the reactor at full power, a reactor SCRAM occurred as a result of Turbine/Generator Trip on Generator 21

Load Rejection due to a 345 kV Switchyard Tie Line Differen-tial Fault. This transient was reported to the NRC in LER 1991-005-00, dated 4/12/91 (attached as Exhibit 17).

• On 4/23/1991, with the reactor at full power, a reactor SCRAM occurred as a result of a turbine/generator trip on generator load rejection due to the receipt of a 345 kV breaker failure signal. The transient included a loss of offsite power. This was reported to the NRC in LER 1991-009-00, dated 05/23/91 (attached as Exhibit 18).

• On 6/15/1991, during normal operation with reactor-at full power, a reactor SCRAM occurred due to a Turbine Control Valve Fast Closure on Generator Load Rejection resulting from a loss of the 345 kV North Switchyard bus. This transient was reported to the NRC in LER 1991-014-00, dated 7/15/91 (at-tached as Exhibit 19).

• On 6/18/2004, during normal operation with the reactor at full power, a two phase electrical fault-to-ground caused the main generator protective relaying to isolate the main generator from the grid and resulted in a Generator Load Rejection reactor SCRAM. This transient was reported to the NRC in LER 2004-003-00, dated 8/16/2004 (attached as Exhibit 20).

• On 7/25/2005, during normal operation with the reactor at full power, a generator load rejection SCRAM occurred due to an electrical transient in the 345 kV Switchyard. This transient was reported to the NRC in LER 2005-001-00 (attached as Ex-hibit 21).

Q50. Did VY perform as expected in response to these transients?

22

A50. (CJN) Yes. No significant anomalies were seen in the plant's re-sponse to these transients. The performance of VY in the tran-sients it experienced at pre-EPU power levels was well within the bounds of the ODYN analyses.

Q51. Does VY's historical response to large transients provide a basis for an exception to LTT?

A51. (CJN) Yes. In particular, the transients in 2004 and 2005 oc-curred after most of the modifications associated with EPU were already implemented, including the new HP turbine rotor, Main Generator Stator rewind, the new high pressure feedwater heaters, condenser tube staking, an upgraded isophase bus duct cooling system, and condensate demineralizer filtered bypass. In each in-stance, the modified or added equipment functioned normally dur-ing the transient. The plant's performance during these recent transients, including that of the modified components, demon-strates that the EPU modifications do not significantly affect the plant's response during transient conditions.

G. System and component testing Q52. Does system and component testing during normal operations provide a basis for an exception to LIT?

A52. (CJN) Yes. Technical Specification-required surveillance testing (Lg., component testing, trip logic system testing, simulated ac-tuation testing) is routinely performed during plant operations.

Such testing demonstrates that the structures, systems and compo-nents ("SSSCs") required for appropriate transient performance will perform their functions, including integrated performance for transient mitigation as assumed in the transient analysis.

Q53. How often are the main components involved in large transients tested?

23

A53. (CJN) The MSIVs are tested quarterly. The safety relief valves and spring safety valves are tested once every operating cycle.

These valves are required to perform in accordance with the de-sign during large transients; their periodic testing assures that their performance during large transients will be acceptable. Likewise, the reactor protection system instrumentation that is relied on to mitigate large transients is tested quarterly, assuring that it will carry out its design function in the event of a large transient.

Q54. What is the significance of the system and component testing program?

A54. (CJN) Because the characteristics and functions of SSCs are tested periodically during plant operations, they do not need to be demonstrated further in a large transient test. In addition, limiting transient analyses (i.e., those that affect core operating and safety limits) are re-performed for each operating cycle and are included as part of the reload licensing analysis.

H. Similarities in pre- and post-EPU plant design and physical configuration Q55. Are there similarities in design and system function between the pre- and the post-EPU VY plant configuration?

A55. (CJN) There are great similarities. While some operating pa-rameters (eg., core power distribution) have been modified to ac-con-modate EPU operation and some setpoint changes were made, these changes do not measurably contribute to response to large transients. None of the modifications that have been made will introduce new thermal-hydraulic phenomena as a result of power uprate, nor are any new system interactions during or as the result of analyzed transients introduced. No systems have been added or changed at VY that are required to mitigate the consequences of the large transients that would be the subject of the LTT.

24

Operationally, the EPU modifications have no significant effect on plant transient analysis because, since the uprate is a constant pressure uprate, most of the plant's systems will operate in the same manner as before the uprate. Also, the VY EPU is per-formed without a change in operating reactor dome pressure from current plant operation.

Q56. Have there been major equipment modifications or new hardware installations at VY that could result in different large transient performance than that predicted by the analyses and the plant's prior operating history?

A56. (CJN) No. Table 1 (attached) provides: (a) a listing of EPU plant modifications, all of which were implemented during VY's last two Refueling Outages (RFO 24 and RFO 25, in Spring 2004 and Fall 2005, respectively); (b) a determination of whether the modi-fications have an effect on the plant transient analysis; (c) a de-termination of whether the modifications are modeled in the tran-sient analyses; (d) an indication of completed post modification testing; (e) an indication of subsequent power ascension and/or power operation confirmatory testing and monitoring; and (f) a determination of whether the modified function would be tested/verified during large transient testing.

Most of the EPU modifications were made to non-safety-related components, which are not credited in licensing basis transient analyses. Incidental modifications associated with EPU, such as alarms, indications, and scaling changes, also do not impact tran-sient response.

Q57. How does the number of modifications and new equipment installations included in the VY EPU provide a basis for an exception to LTT?

A57. (CJN) Not only are the equipment modifications and additions relatively few but none of these modifications will introduce any new thermal-hydraulic phenomena as a result of the power uprate.

25

Nor are any new system interactions during or as the result of ana-lyzed transients introduced.

I. Impact of LTT on plant systems and components Q58. Would performance of LTT have an adverse impact on the plant?

A58. (CJN, JLC) The performance of a SCRAM from high power, such as those that take place during LTT, results in an undesirable tran-sient cycle on the primary system. The occurrence of primary system transient cycles should be minimized, since they introduce unnecessary stresses on the primary system components. The un-desirable effects of performing the tests outweigh the benefits of any limited additional information that may be gained from them.

In addition, performance of each LTT causes a plant shutdown.

Any plant shutdown results in a generation outage for a period of time (typically 2-3 days) for the plant. Since there are no meas-urable safety benefits to be derived from the performance of the tests, the loss of generation revenue and other costs associated with the performance of the tests cannot be economically justi-fied.

J. Endorsement of LTT exception by ACRS.

• Q59. Has the Advisory Committee on Reactor Safeguards examined the LTT exception sought by Entergy for the VY EPU?

A59. (CJN)Yes. In its letter to the NRC Chairman following its review of the VY EPU, the Advisory Committee on Reactor Safeguards concluded:

3. Load rejection and main steam isolation valve closure transient tests are not war-ranted. The planned transient testing pro-

-gram adequately addresses the performance of the modified systems.

26

Letter from Graham B. Wallis to NRC Chairman Nils Diaz dated January 4, 2006, attached as Exhibit 22.

IV.

SUMMARY

AND CONCLUSIONS Q60. Please summarize your testimony.

A60. (CJN, JLC) Our testimony can be summarized as follows:

• Previous industry operating and LTT experience Operating experience at other plants that have implemented a con-stant pressure power uprate such as that implemented by Entergy at VY has shown that the transient analysis results bound the per-formance observed during actual operational transients. This in-dustry operating experience is applicable to VY because of the similarity in its design to that of those plants. The results of LIT at one plant similar to VY also confirm the validity of the analyti-cal predictions of VY's response to LTT under EPU operating conditions.

• Previous VY operating experience Previous operating experience at VY for large transients has shown that the plant has performed as expected, and that its performance during transients is bounded by the transient analyses of record for the facility. This operating experience includes transients in 2004 and 2005, which occurred after the completion of many of the plant modifications being implemented in preparation for the EPU.

The plant's performance during the 2004 and 2005 transients dem-onstrates that the EPU modifications do not significantly affect the plants response during transient conditions.

27

• Absence of new thermal-hydraulic phenomena or sys-tem interactions The operation of VY after the EPU will result in different operat-ing parameters (g., feedwater flow, moisture carryover) but will not result in any new thermal-hydraulic phenomena in the event of a plant transient. The modifications already implemented have no significant effect on plant transient analysis because, since the uprate is a constant pressure uprate, most of the plant's systems will operate in the same manner as before the uprate.

• No net benefits from LTT The benefits from conducting LTT would be minimal and would be outweighed by the potential adverse impact of LTT on the plant's systems and components.

• Significant costs associated with performance of LTT Performance of LT' causes a plant shutdown. Any plant shut-down results in a generation outage for a period of time (typically 2-3 days) for the plant. Since there are no measurable safety bene-fits to be derived from the performance of the tests, the loss of generation revenue and other costs associated with the perform-ance of the tests cannot be justified.

Q61. What are your conclusions regarding the assertions in NEC Contention 3?

A61. (CJN, JLC) We conclude that there is no support for the claims made in NEC Contention 3. The extensive and conservative en-gineering analyses, historical test and actual transient data, indi-vidual component testing, and observed performance at other plants experiencing large transients provide reasonable assurance and confidence that VY systems will function as designed in miti-gation of large transients from EPU conditions. The potential 28

benefits, if any, from LTT at VY are significantly outweighed by the adverse effect on plant systems and components from the tests themselves. VY's request for an exception to LTT, therefore, is reasonable and poses no threat to public health and safety.

Q62. Does that conclude your testimony?

A62. (CJN, JLC) Yes, it does.

29

Table 1: VY Equipment Modifications Implemented for EPU Potential Post Mod Testing EPU Startup Testing Further Tested Impat onby Load Reject Modification Description Transient Without Bypass TRaspnsient Main Steam Rs Isolation Valve

_Closure Main turbine Replace 8' stage dia- No Vibration baseline Vibration monitoring. NA

- LP dia- phragm of LP tur- measurements phragm bine replacement Main turbine Install higher capacity No In-service Leak Monitor temperature No cross-around relief valves check downstream of relief valves CARVs (CARVs) and Dis-charge Pip-Main genera- Rewind/upgrade main No

• Perfonnance test

• Monitor generator

• No tor -rewind generator for CPPU

• AC Hi-Pot test and cooling conditions, each phase Replace generator by- .Pressure and vac-drogen coolers with uum testing upgraded coolers

• Winding resis-tance

• Meggenng Main con-

• Stake main con- No

• Leak check tubes

• Monitor chemistry

• No denser denser tubing to re- *Monitor chemistry duce the effects of flow induced vibra-tion Feedwater

• Replace relief valves No

• Bench test valves NA

• No heater 4A/B with larger capacity

• Leak test installa-shell side relief valve to ac- tion relief valve commodate in-creased feedwater flow Steam dryer

• Replace lower cover No

• Inspection

• Vibration and mois-

• No cover plate plates with thicker ture canyover moni-strengthening plates toting during power

• Add reinforcing ascension per power stiffeners at lower ascension test plan cover plates and ver- (PATP) tical hood sides

• Remove internal brackets in top in-side comers of outer hoods

• Replace vertical hood and hood top plates with thicker plates

• Replace/Upgrade tie bars -

Isolated

• Install a new isolated No

• Monitor bus duct

• Performance moni-

• No phase bus phase bus duct cool- cooling toting duct cooling ing system to re- *Flow tests move bus duct heat under CPPU condi-tions 30

Potential Post Mod Testing EPU Startup Testing Further Tested Impact on by Load Reject Modification Description Transient Without Bypass R e / Main Steam Isolation Valve Closure HP feedwater * #IA, #IB, #2A, and No

• Pressure test

• Perfonnance mod-

• No heater re- #2B feedwater *Visual inspection toring placement heater replacement

• Magnetic particle testing

• Radiography

• In-service inspec-tion

• Thermal perform-ance demonstra-tion.

Residual heat oModify RHRSW No

• Visual Inspection NA

• No removal pumps (Train A and

• Particle Testing service water B) Motor Bearing

• Ultrasonic Flow (RHRSW) Oil Coolers piping to Testing system recover Service Wa- *In-Service Inspec-ter flow from the tion coolers  :

NSSS/torus

• Upgrade particular No

• Welds to be ex- NA

• No attached NSSS and tonus at- amined by visual, piping tached piping sup- liquid penetrant, ports magnetic particle, as applicable Flow induced

• Install FIV instru- No

• Verify installation

• Collect EPU data

• No vibration mentation and analyze (FIV) ._.

Reactor

• Provide rapid run- No

• Channel Calibra- NA

• No recirculation back of RR pump tion (RR) system from high power on

• Test with breakers runback trip of condensate or in "test' and RR feedwater pump system not operat-ing Condensate

• Install condensate No

• Monitor chemistry

• With filtered bypass

• No demineralizer demineralizer fil- *Establish flow in service, monitor tered bypass strainer baseline meas- flows under various to permit one urements EPU conditions demineralizer to be

• Monitor reactor wa-removed under ter chemistry CPPU conditions Feedwater . Protect feed pumps No . Channel calibra- NA . No system suc- (RIP) with two se-. tion tion pressure quential levels of

• Test with breakers trip low suction pressure in "Test" position trips at various time delays to ensure only one pump trips at a time and for high power RR pump runback to -60% on loss of a Feed Pump

• Modify trip logic to prevent common mode failure due to loss of RFP low flow circuits L X __ X _i _Gun Cooling

• Replace fan blades No

• Cooling tower NA

• No I tower/fan with more efficient performance motors blades and drive mo- monitoring tors with upgraded higher performance motors 31

Potential Post Mod Testing EPU Startup Testing F;rther Tested Modification Description Impact on Without Bypass Trespnsient I Main Steam Isolation Valve Response?

._ Closure

• Reroute feed to SRV No

• Voltage check and NA

• No EQ Upgrades monitor to new megger breaker -  :

Increase the rating No

• Voltage checks

• In-service testing of

• No Grid Stability *

(million volt-ampere

• Logic checks the 345kV and 115 (MVA)) of the Ver-

• Relay calibration kV primary/ secon-mont Yankee- dary protective relay, Northfield 345kV line carrier system line from 896 MVA (Monthly) to a minimum rating of 1075 MVA

• Increase MVA rating on the Ascutney-Coolidge 115 kV line from 205 MVA to 240 MVA

• Addition of 60 MVAr of shunt ca-pacitors at the Ver-mont Yankee 115 kV bus

• Modification to pro-vide a second pri-.

mary protection scheme on the Ver-mont Yankee north bus

• Addition to provide a second primary protection scheme on the Vermont Yankee main gen-erator

• Independent pole tripping on the Ver-mont Yankee 381 breaker

• Addition of out of step protection for the Vermont Yankee generator Main turbine

• Replace HP Turbine No

• Factory 120% trip

• Overspeed testing

• No

- HP flow steam path (new HP test

• Vibration monitoring path diaphragms and ro-

• Overspeed testing

• EPR and MPR Test-tor),

• Control and stop ing per Power As-

• New control cams, valve response cension Test Plan camshafts and hy- testing (PATP) draulics

• Vibration baseline Control and stop New control valve set- measurements valve testing tings

• EPR and MPR

• Modify control valve tuning operating mocha-nism with 5% mar-gin above CPPU

• Modify turbine con-trol and overspeed setpoint for CPPU conditions

• New Hydrogen Coolers .

32

Further Potential Modeled in Post Mod Testing EPU Startup Tested by Ipcon Transient Testing Turbine Description Transientrip / Main Modification Response Steam Iso-lation Valve Closure Changein Yes Yes

• Wire continuity

• EPR and

• No Electronic pres-sure EPR setpoint checks MPR test-regulator (EPR) control range

• PLC calibration ing per setpoint change and zero

• EPR and MPR PATP power setpoint tuning based on higher steam line differen-tial pressure (dp)

• Rescale by-pass relay to account for bypass valve capability of 89% oftotal steam flow

• Expand EPR control band from current range of 900 to lO00psiga new range of 850to 1000 psig

• Install signal isolators to minimize EPR output test wiring fault from nega-tively affect-ing EPR op-eration

• Add second notch filter function to programmable logic control-ler (PLC) software and tune to remove an 8.8 Hz sig-nal _  :

33

Further Potential Modeled in Post Mod Testing EPU Startup Tested by on Tansient rImpact Testing Turbine Modification Description Transient Analysis Trip / Main Responsesteam ISO-Response lation Valve Closure Main steam line

• Respan trans- Yes Yes

• Channel calibra-

• TS re-

• No high flow set- mitters to en- tion quired point compass new

• Test circuit logic channel 140% steam check and flow values calibration Replace the 4 transmitters used to pro-vide 40% set-point forMSL high flow re-duced function with more ac-curate trans-mitters

• Setpoint changes for 140% isolation at new steam flows

• Install new in-dicators on master trip units Neutron monitor-

• APRM flow Yes Yes

• Channel calibra-

• TS re-

• No ing setpoints - biased tion quired APRM and RBM SCRAM set-

• Test circuit logic channel points and rod check and block limits calibration require changes due CPPU

• APRMs re-quire recali-bration reflect-ing CPPU rated power operation

• RBMs require recalibration reflecting CPPU rated power opera-tion__

Rodworthmini-

• Setpoint Yes Yes

• Channelcalibra- *TSre-

• No mizer (RWM) - change to: tion quired setpoint maintain the

• Test circuit logic channel setpoint at the check and same absolute calibration value of steam flow due to the range changes of the associ-ated instru-ments_

Turbine first

• Setpoint Yes Yes

• Channel calibra-

• No. (TS

• No stage pressure changes for tion required the SCRAM

• Test circuit logic channel bypass check and

_calibration) _

34

Further Modeled in Post Mod Testing EPU Startup Tested by Potential Transient Testing Turbine Impact on Trip / Main Modification Description Trant Analysis Steam Iso-Response SemI Valve Responselation

____ ____Closure Feedwater Isoki-

• Replace Sam- No No

• Leak Check

• No

• No netic Probes ple Probes process bound-Feedwater Pump

• Trip Feedwa- No No

• Circuit/Logic

• Yes - Con-

• No Automatic Trip ter Pump on Tests densate Loss of Con- Pump Trip densate Pump Test 35

UNITED STATES OF AMERICA NUCLEAR REGULATORY COMMISSION Before the Atomic Safety and Licensing Board

.)

In the Matter of )

-) Docket No. 50-271 ENTERGY NUCLEAR VERMONT )

YANKEE, LLC and ENTERGY ) ASLBP No. 04-832-02-OLA NUCLEAR OPERATIONS, INC. ) (Operating License Amendment)

(Vermont Yankee Nuclear Power Station) )

- )

AFFIDAVIT OF JOSE L. CASILLAS RE NEC CONTENTION 3 TESTIMONY County of Santa Clara )

)

State of California )

I, Jose L. Casillas, being duly sworn according to law, depose and state the following:

1. I am the Plant Performance Consulting Engineer in the Nuclear Analysis group of the Engineering organization of GE Nuclear Energy. My business address is 1989 Little Orchard Street, San Jose, California, 95125.

2. I am providing testimony, dated May 17, 2006, on behalf of Entergy Nuclear Vermont Yankee, LLC and Entergy Nuclear Operations, Inc. in the above captioned proceeding, entitled "Testimony of Craig J. Nichols and Jose L. Casillas on NEC Contention 3 - Large Transient Testing."

3. The factual statements and opinions I express in the cited testimony are true and correct to the best of my personal knowledge and belief

4. I declare under penalty of perjury that the foregoing is true and correct.

i

- I Further, the affiant sayeth not.

I 6UZ 4v f-. Jose L. Casillas Subscribed and sworn to before me this /6; day of May, 2006 -

_awwo I _

CHMMAK14 CW~t N1CMh j-# -

Wk 'h ONMM Notary Public My commission expires UNITED STATES OF AMERICA' NUCLEAR REGULATORY COMMISSION Before ihe Atomic Safety and Licensing Board In the Matter of )

f ;) Docket No. 50-271 ENTERGY NUCLEAR VERMONT )

YANKEE, LLC and ENTERGY ) ASLBP No. 04-832-02-OLA NUCLEAR OPERATIONS, INC. ) (Operating License Amendment)

(Vermont Yankee Nuclear Power Station) )

AFFIDAVIT OF CRAIG J.-NICHOLS RE NEC CONTENTION 3 TESTIMONY County of Windham )

):

State of Vermont )

I, Craig J. Nichols, being duly sworn according to law, depose and state the following:

1. I am the Extended Power Uprate Project Manager for Entergy Nuclear Operations, Inc. My business address is 320 Governor Hunt Road, P.O. Box 250, Vernon, VT 05354.

X2. 'I am providing testimony, dated May 17, 2006, on behalf of Entergy Nuclear Vermont Yankee, LLC and Entergy Nuclear Operations, Inc. in the above captioned proceeding, entitled "Testimony of Craig J. Nichols and Jose L. Casillas on NEC Contention 3- Large Transient Testing.';

3; The factual statements and opinions I express in the cited testimony are true and correct to the best of my personal knowledge and belief.

4. I declare under penalty of perjury that the foregoing is true and correct.

Further, the affiant sayeth not.

Craig J. Nichols Subscribed and sworn to before me this JSŽ day of May, 2006 Public My commission expires Resume of Craig Joseph Nichols 178 Forest Avenue West Swanzey, NH 03446 (603) 358-6452 EMPLOYMENT Entergy Nuclear Operations, Inc. - Vermont Yankee July 2002 to Present Change in employment due to sale of Vermont Yankee.

Project Manager - Power Uprate July 2002 to Present

• Provide overall project management for an Extended Power Uprate at Vermont Yankee.

- Includes all engineering, analyses, modifications, implementation, fiscal and project management for the most comprehensive site project since original plant startup.

• BWR Owners Group Maintenance Committee Chairman.

Key Management Role as Station Duty Call Officer

-*: Refuel Outage Support - Emergent Issues (MSIVs) and Outage Execution Vermont Yankee Nuclear Power Corporation 1989 to July 2002 Various positions of increasing responsibility in production, project management, and support in the areas of Electrical, I&C, Planning and Scheduling, and Engineering. Responsibilities have included management of large projects and personnel groups, interaction of newly created organization, and leadership of maintenance and site efforts to identify constraints and improve economic viability.

Manager - Power Uprate December 2001 to Present

• Newly created position to provide overall project management for an Extended Power Uprate at Vermont Yankee. Includes all engineering, analyses, modifications, implementation, fiscal and project management for the most comprehensive site project since original plant startup Maintenance Support Manager April 2000 to December 2001

• Newly created position responsible to oversee and integrate all Maintenance Division support functions including project planning and implementation, component engineering and program management.

• 4Achieved Plant Certification for BWR I&C Manager. January 1999 to April 2000

• Lead effort to improve human performance and training programs for I&C technicians.

• Implement and modernize all engineering programs and projects.

Electrical and Controls Maintenance Manager January 1997 to January 1999 4 New position created during reorganization of Maintenance Departments.

• Initial.task to integrate operations of electrical and I&C groups within E&CM and the three Maintenance Departments.

• Management of E&CM projects and budget in support of company goals.

4 Acting Maintenance Manager October 1996 to January 1997

• Successful completion of 1996 Refuel Outage including recovery from MS1V PCLRT failures.

• Development and pursuit of Maintenance Department reorganization to address areas for improvement and create organization for long-term performance.

Planning and Scheduling Supervisor - April 1996 to September 1996

• Assigned responsibility to improve Department Planning and Scheduling activities.

• Developed draft for 12-week schedule preparation guideline.

• Initiated efforts to reduce backlogs of CMs and PMs, unplanned work orders, and unscheduled activities.

Electrical Maintenance Production Supervisor 1991 to March 1996 Senior Maintenance Engineer - Electrical 1989 to 1991 Yankee Atomic Electric Company 1983 to 1989 Electrical Engineer for design modification and project implementation for Vermont Yankee and Seabrook Stations.

Cooperative Education Student Assignments 1981 to 1983 Engineering Assistant and Draftsman at Stone & Webster Engineering Corporation EDUCATION BSEE (Power Systems) 1985 NORTHEASTERN UNIVERSITY BOSTON, MASSACHUSETTS Magna Cum Laude and Cooperative Education Award REFERENCES Available upon request 2

JOSE L CASILLAS Current Title Consulting Engineer in BWR Plant Performance, Nuclear Analysis, Engineering, GE Nuclear Energy.

Nuclear Experience BWR Simulator Training.

BWR System Fundamentals.

Education BS Mechanical Engineering 1973, University Of California, Davis.

Advanced Training and Certification None.

Qualifications Summary Areas of Expertise:

• BWR Plant System Performance Evaluation.

• BWR Transient and Loss-of Coolant Accident Analysis.

• Design, Licensing and Operation of BWR Cores.

• Thermal Hydraulic Design and Evaluation of BWR Fuel.

Experience GENERAL ELECTRIC COMPANY - 33 YEARS

• Plant Performance Consulting Engineer/Engineering Fellow, 2002-present.

• Analysis Consultant, Nuclear & Safety Analysis, 1998-2002.

• Technical Account Manager, Engineering & Licensing Consulting Services, 1995-1997.

• Project Manager, Shroud Cracking Safety Evaluations, 1994-1995.

• Technical Leader, Reload Nuclear Engineering, 1984-1994.

• Technical Leader, Plant Performance Engineering, 1980-1984.

• Senior Engineer, ECCS/Containment Performance Engineering, 1977-1980.

• Engineer, Core Thermal Hydraulic Analysis, 1973-1977.

May 2006.

3 TABLE 1-3 Nuclear Plant Principal Plant Design Features Comparison [Historical]

Brunswick Brown's Ferry Cooper Edwin I.

Units 1 & 2 Units 1, 2 & 3 Hatch Nuclear Plant Unit-1 A. SITE

1. Location Brunswick Limestone Co., Nemaha Co., Appling Co.,

County, North Alabama Nebraska Georgia Carolina

2. Size of Site (Acres) 1,200 840 1,090 2,100

3. Site Ownership CP&L U.S. Government CPPD GPC

4. Plant Ownership CP&L TVA CPPD GPC

5. Number of Units on Site 2 3 1 2 B. PLANT-REACTOR WARRANTED CONDITIONS

1. Net Electrical Output 821 1,075/unit 770 786 (Mwe)

2. Gross Electrical Output 849 1,098/unit 801 813 (Mwe)

3. Turbine Heat Rate 10,120 10,243 10,187 10,227

4. Gross Plant Heat Rate 9,816 10,231 10,142 10,218 (Btu/kW-hr) ____ _ _ _ _

5. Feedwater Temperature 420 376.1 367 387.4 C. REACTOR PRIMARY VESSEL

1. Inside Diameter (ft-in.) 18-2 20-11 18-2 18-2

2. Overall Length Inside (ft- 69-4 72-0 69-4 694 in.) _ _ _ _ _ _ _ _ _ _ _ _ _ _ _

3. Design Pressure (psig) 1,250 1,250 1,250 1,250

4. Wall Thickness (in.) 5-17/32 6-5/16 5-17/32 5-17/32 (including clad)  : .

E .

TABLE 1-3 Nuclear Plant Principal Plant Design Features Comparison [Historical]

Brunswick Brown's Ferry Cooper Edwin I.

Units 1 & 2 Units 1, 2 & 3 Hatch Nuclear Plant

. I Unit-I D. REACTOR COOLANT - RECIRCULATION LOOPS

1. Location of Recirculation Primary Primary Primary Primary Loops Containment Containment Containment Containment System Drywell System Drywell System Drywell System Structure Structure Structure Drywell Structure

2. Number of Recirculation 2 2 2 2 Loops

3. Pipe Size (in.) 28 28 28 28

4. Pump Capacity, each 45,200 45,000 45,200 45,200

_ (gpm )_ _ _ _ _ _ _ _ _ _ __ _ _ _

5. Number of Jet Pumps 20 20 20 20

6. Location of Jet Pumps Inside Reactor Inside Reactor Inside Reactor Inside Reactor Primary Vessel Primary Vessel Primary Vessel Primary Vessel E. REACTOR

1. Reactor Warranted Conditions

a. Thermal Output (Mwt) 2,436 3,293 2,381 2,436

b. Reactor Operating 1,005 1,005 1,005 1,005 Pressure (psig)

c. Total Reactor Core 77.0 x 106 102.5 x 106 74.5 x 106 78.5 x 106 Flow Rate (lb/hr)

d. Main Steam Flow 10.47 x 106 13.38 x 106 9.81 x 106 10.03 x 106 Rate (lb/hr)

2. Reactor Core Description

a. Lattice 7x7 7x7 7x7 7x7

b. Pitch of Movable 12.0 12.0 12.0 12.0 Control Rods (in.) X _ __ _

c. Number of Fuel 560 764 548 560 Assemblies

TABLE 1-3 Nuclear Plant Principal Plant Design Features Comparison [Historical]

Brunswick Brown's Ferry Cooper Edwin I.

Units 1 & 2 Units 1, 2 & 3 Hatch Nuclear Plant Unit-1

d. Number ot Movable 137 185 137 137 Control Rods

e. Effective Active Fuel 144 144 144 144 Length (in.)

f. Equivalent Reactor 160.2 178.1 158.5 160.2 Core Diameter (in.)

g. Circumscribed 170.5 198.6 170.5 170.5 Reactor Core Diameter (in.)

h. Total Weight U0 2 272,850 372,373 267,095 272,850

3. Reactor Fuel Description _

a. Fuel Material U0 2 U0 2 U0 2 U0 2

b. Fuel Density % of 93 93 93 93 Theoretical

c. Fuel Pellet Diameter 0.487 0.487 0.487 0.487 (in.) X

d. Fuel Rod Cladding Zircaloy-2 Zircaloy-2 Zircaloy-2 Zircaloy-2 Material

e. Fuel Rod Cladding 0.032 0.032 0.032 - 0.032 Thickness (in.) -

f. Fuel Rod Cladding Free Standing Free Standing Free Standing Free Standing Process Loaded Tubes Loaded Tubes Loaded Tubes Loaded Tubes

g. Fuel Rod Outside 0.563 0.563 0.563 0.563 Diameter (in.)

h. Length of Gas Plenum 16.0 16.0 16.0 16.0 (in.) .

i. Fuel Rod Pitch (in.) 0.738 0.738 0.738 0.738

j. Fuel Assembly Zircaloy4 Zircaloy-4 Zircaloy-4 Zircaloy-4 Channel Material

TABLE 1-3 Nuclear Plant Principal Plant Design Features Comparison [Historical]

Brunswick Brown's Ferry Cooper Edwin l.

Units 1 & 2 Units 1,2 & 3 Hatch Nuclear Plant

-Unit-1

4. l Reactor Control Control Rods

a. Number 137 185 137 137

b. Shape. Cruciform Cruciform Cruciform Cruciform

c. Material B4C Granules B4 C Granules B4 C Granules B4 C Granules Compacted in SS Compacted in SS Compacted in SS Compacted in Tubes Tubes Tubes SS Tubes

d. Pitch (in.) 12.0 12.0 12.0 12.0

e. Poison Length (in.) 143.0 143.0 143.0 143.0

f. Blade Span (in.) 9.75 9.75 9.75 9.75

g. Number of Control 84 84 84 84 Material Tubes for Rod

h. Tube Dimensions (in.) 0.188 0.188 0.188 0.188 ODxO.025-wall ODxO.025-wall ODxO.025-wall ODxO.025-wall

i. Stroke (in.) 144.0 144.0 144.0 144.0

5. Thermal Hydraulic Data

a. Heat Transfer Area 86.513. 86.513 86.513 86.513 per Assembly (fA2) -_ __

b. Reactor Core Heat 48,451 66,098 47,409 48,451 Transfer Area (ft2 )

c. Maximum Heat Flux 428,100 425,000 427,820 428,308 2)

(Btu,/r fA

d. Average Heat Flux 164,410 163,200 164,500 164,740 2)

(Btu/hr fA

e. Maximum Power per 18.5 '18.4 18.5 18.5 Fuel Rod Unit Length (kW/ft)

' These items are shown at design limits ratherthan design point.

UPDA TED FSAR 1Revision:8 A INTRODUCTIONAND

SUMMARY

Table: 1-3 CHAPTER I TABLES Page: 5 of 11 TABLE 1-3 Nuclear Plant Principal Plant Design Features ComParison [Historical]

Brunswick Brown's Ferry Cooper Edwin I.

Units1&2 Units1,2&3 Hatch Nuclear Plant UnIt-1

f. Average Power per 7.10 7.049 7.079 7.11 Fuel, Rod Unit Length

_ (kW/ft) _________

g. Maximum Fuel 4,380 4,380 4,380 4,380 Temperature (OF)

h. Minimum Critical 1.9 1.9 1.9 1.9 Heat Flux Ratio

i. Total Heat Generated 95.0 95.0 95.0 95.0 in Fuel (% )  ; - -l----_______

j. Core Average Exit 13.6 13.2 13.2 13.0 QQuality _______

6. Power Distribution -

Peaking Factors (Peak/Average) _ ____ _

a. Axial 1.50 1.50 1.50 1.50

b. Relative Assembly 1.40 1.40 1.40 1.40

c. Local (within 1.24 1.24 .1.24 1.24 assembly) _ _ _ __ _

d. Total Peaking Factor 2.6 2.6 2.6 2.6

7. Nuclear Design Data l_1_T___1

a. Average Discharge l19,000 MWD/ 19,000 MWD/ 19,000 MWD/ 19,000 MWD/

Exposure - 1" core short ton U short ton U short ton U short ton U

b. Moderator to Fuel 2.41 2.41 2.41 2.41 Volume Ratio at Total Core H2 0/U0 2 cold

8. In-Core Neutron Instrumentation

a. Numberofln-Core 124 172 124 124 Neutron Detectors

'These items areshown at design limits ratherthan design point.

TABLE 1-3 Nuclear Plant Principal Plant Desian Features Comparison [Historical]

Brunswick Brown's Ferry Cooper Edwin I.

Units 1 & 2 Units 1, 2 & 3 Hatch Nuclear Plant Unit-l

b. Number of In-Core 31 43 31 31 Detector Strings

c. Number of Detectors 4 4 4 4 per String

d. Number of Flux 4 5 4 4 Mapping Neutron Detectors

e. Range (and Number) of Detectors

1) Source Range Source to 10-3% Source to 10-3% Source to 10'3% Source to Monitor power (4) power (4) power (4) 10-3% power

__ __ __ X(4)

2) Intermediate lO 4 to 10% 104to 10% power lO 4 to 10% 10 4 to 10%

Range Monitor power (8) (8) power (8) - power (8)

3) Local Power 2.5% to 125% 2.5% to 125% 2.5% to 125% 2.5% to 125%

Range monitor power (124) power (172) power (124) power (124)

4) Average Power 5% to 125% 5% to 125% 5% to 125% 5% to 125%

Range Monitor power (4A power (4)- power (4) power (4)

f. Number and Type of 5-Sb-Be 7-Sb-Be 5-Sb-Be 5-Sb-Be In-Core Neutron Sources

9. Reactivity Control

a. Approximate Effective 0.96k 0.96k 0.96k 0.96k Reactivity of Core with all Control Rods in (cold)

b. Effective Reactivity of <0.99k <0.99k <0.99k <0.99k Core with Strongest Control Rod out (cold)

c. Typical Moderator Temperature Coefficient ( 0k/k F) _

- Brown's Ferry Units 2 and 3. I

'Beginning of core life

TABLE 1-3 Nuclear Plant Principal Plant Design Features Comparison [Historical]

Brunswick Brown's Ferry Cooper Edwin L.

Units 1 & 2 Units 1, 2 & 3 Hatch Nuclear Plant IUnit-l

1) Cold (at 68 0F) -5.0 x I0' -5.0 x 10-5 -5.0 x 10 5 -5.0 x 10-5

2) Hot (no voids) -16.0 x 10- -16.0 x i1-5 -16.0 x I0- -16.0 x I0-5

d.Typical Moderator Void Coefficient (k/kvoid)- _

1) Hot (no voids) 0 100 -0.9 x

2) At rated output -1.05 x 10-3 -1.0 X 10-3 -1.05 x 10-3 -1.05 x 10-3

e. Typical Fuel Temperature

_ (Doppler) Coefficienr

1) Cold (at 68 0F) -0.94 x 10-5 -0.94 x 10-5 -0.94 x I0-' -0.94 x 10-5

2) Hot (no voids) -0.97 x 10' -0.97 x 10-5 -0.97 x 10-5 -0.97 x 10-5

3) At rated output S -0.83 x I0-5 *-0.83 x 10-5 -0.83 x 10-5 *-0.83 x IOd F. CONTAINMENT SYSTEMS

1. Primary Containment l___l______

a. Type Pressure Pressure Pressure Pressure Suppression Suppression Suppression Suppression

b. Construction

1) Drywell Light Bulb/ Light Bulb/ Light Bulb/ Light Bulb/

Reinforced Steel Vessel Steel Vessel Steel Vessel Concrete with steel liner

2) Pressure Torus/Reinforced Torus/Steel Torus/Steel Torus/Steel Suppression Concrete with Vessel Vessel Vessel Chamber steel liner

c. Pressure Suppression +62 +56 +56 +56 Chamber-Internal Design Pressure (psig) -

'Beginning of core life

TABLE 1-3 Nuclear Plant Principal Plant Design Features Comparison [Historical]

Brunswick Brown's Ferry Cooper Edwin I.

Units 1 & 2 Units 1, 2 & 3 Hatch Nuclear Plant

-Unit-l

-d. Pressure Suppression +2 +1 +2 +2 Chamber-External Design Pressure (psi)

e. Drywell-Internal +62 +56 +56 +56 Design Pressure (psig) f_ Drywell-External +2 +1 +2 +2 Design Pressure (psi)

g. Drywell Free Volume 164,100 159,000 145,430 146,240

h. Pressure Suppression 124,000 119,000 109,810 110,950 Chamber Free Volume (ft)

i. Pressure Suppression 87,600 85,000 87,660 87,660 Pool Water Volume

- ( &) - _ _ _ _X

j. Submergence of Vent 4 4 4 3 ft - 8 in.

Pipe Below Pressure Pool Surface (ft)

k. Design Temperature 300 281 281 281 of Drywell (IF)

_. Design Temperature 220 281 281 281 of Pressure Suppression Chamber (F)

m. Downcomer Vent 6.21 6.21 6.21 6.21 Pressure Loss Factor

n. Break Area/Gross 0.02 0.019 0.019 0.019 Vent Area

o. Drywell Free 1.32 1.33 1.4 1.3 Volume/Pressure Suppression Chamber Free Volume

p. Calculated Maximum 49.4 40 46 46.5 Drywell Pressure after blowdown with no prepurge (psig)

UPDATED FSAR Revision: 18A INTRODUCTION AND

SUMMARY

Table: 1-3 APrem CHAPTER I TABLES Page: 9 of 11 TABLE 1-3 Nuclear Plant Principal Plant Design Features Comparison [Historical]

Brunswick Brown's Ferry Cooper Edwin '.

Units 1 & 2 Units 1, 2 & 3 Hatch Nuclear Plant Unit-i

q. Leakage Rate (Percent 0.5 0.5 0.5 1.2 Free Volume per Day) l

2. Secondary Containment

a. Type Controlled Controlled Controlled Controlled Leakage, Leakage, Elevated Leakage, Leakage, Elevated Release Release Elevated Release Elevated l l Release

b. Construction

1) Lower Levels Reinforced Reinforced Reinforced Reinforced Concrete Concrete Concrete Concrete

2) Upper Levels Steel Steel Steel Steel Superstructure Superstructure Superstructure Superstructure and Siding and Siding and Siding and Siding

3) Roof Metal Decking Steel Sheeting Steel Sheeting Steel Sheeting with Built-up Roofing

c. Internal Design 0.25 0.25 0.25 0.25 Pressure (psig)

b. Design nleakage Rate 100 100 100 100 (Percent free volume/day at 0.25 in.

H20

3. Elevated Release Point

a. Type Stack Stack Stack Stack

b. Construction Reinforced Steel Steel Reinforced Concrete Concrete

c. Height (above ground) I100 Meters 200 Meters 100 Meters 150 Meters G. PLANT AUXILIARY SYSTEMS

1. Emergency Core Cooling - 1 l Systems (number) l I _

a. Reactor Core Spray 2 Loops 2 Loops 2 Loops 2 Loops

_ I Cooling System

TABLE 1-3 Nuclear Plant Principal Plant Design Features Comparison [Historical]

Brunswick Brown's Ferry Cooper Edwin L.

Units 1 & 2 Units 1, 2 & 3 Hatch Nuclear Plant Unit-l

b. Reactor Core High I pump I pump I pump I pump Pressure Coolant Injection System

c. Auto-Relief System) I 1 1 1

d. Reactor Core Residual Heat Removal System:

1) Low Pressure 4 pumps 4 pumps 4 pumps 4 pumps Coolant Injection Subsystem

2) Primary 1 1 1 1 Containment Spray/Cooling Subsystem

3) Reactor Shutdown 1 1 1 1 Cooling Subsystem

2. Reactor Auxiliary System (number)

a. Spent Fuel Pool 1 1 1 1 Cooling and Demineralizing System

b. Reactor Cleanup 1 1 1 1 Demineralizer System

c. Reactor Core Isolation I 1 1 1 Cooling System _ _ _

H. PLANT ELECTRICAL POWER SYSTEMS

1. Transmission System _ _ _ _

Outgoing Lines 8-230 kV 4-500 kV 4-345 kV 5-230 kV (number-rating)

2. Auxiliary Power Systems

a. Incoming Lines 8-230 kV 2-161 kV 1-69 kV 5-230 kV (number-rating) 1-115 kV

UPDATED FSAR Revision: 18A INTRODUCTIONAND

SUMMARY

Table: 1-3 CHAPTER I TABLES Page: 11 of 11 TABLE 1-3 Nuclear Plant Principal Plant Design Features Comparison [Historical]

Brunswick Brown's Ferry Cooper Edwin I.

Units 1 & 2 Units 1, 2 & 3 Hatch Nuclear Plant Unit-1 Onsite lso resll

1) Auxiliary 2 2 1 2 Transformers

2) Startup 2 2 1 2 Transformers

3) Shutdown 0 0 1 0 Transformers

3. Standby Diesel Generator System Number of Diesel 4 3 of 4 4 3 Generators

Table 1.7.1 Comparison of Nuclear System Design Characteristics (Parameters are related to rated power output for a single unit unless otherwise noted.

Values given apply to the originally licensed design).

Browns Ferry Thermal and Hydraulic Design Vermont Yankee Each Unit Hatch Station Monticello Rated Power, MWt 1593 3293 2436 1670 Design power, MWt 1665 3440 2537 1670 Steam flow rate, lb/hr 6.43 x 106 13.38 x 106 10.03 x 10' 6.77 x 10' Core coolant flow rate, lb/hr 48.0 x 10' 102.5 x 10' 75.5 x 106 57.6 x 106 Feedwater flow rate, lb/hr 6.40 x 10l 13.33 x 10' 10.445 x 106 6.77 x Feedwater temperature, OF 372 376.1 387.4 376.3 System pressure, nominal in steam dome, psia 1020 1020 1020 1020 Average power density, kw/liter 50.94 50.8 51.2 40.6 Maximum thermal output, kw/ft 18.37 18.35 18.3 17.5 Average thermal output, kw/ft 7.079 7.049 7.114 5.7 Maximum heat flux, Btu/hr-ft 2 425,500 425,048 428,308 405, 000 Average heat flux, Btu/hr-ft2 163,926 163,230 164,734 131,350 Maximum U02 temperature, OF 4380 4380 4380 2750 Average volumetric fuel temperature, OF 1100 1100 1100 900 Average fuel rod surface temperature, OF 558 558 558 558 Minimum critical heat flux ratio (MCHFR) >1.9 >1.9 >1.9 >1.9 Coolant enthalpy at core inlet, Btu/lb 519.8 521.3 526.2 523 .0 Core maximum exit voids within assemblies 74.7 79 79 Core average exit quality, % steam 13.3 13.2 13.9 12.1 Design Power Peaking Factor Maximum relative assembly power 1.4 1.4 1.4 1.58 Local peaking factor 1.24 1.24 1.24 1.24 Axial peaking factor 1.5 1.5 1.5 1.57 Total peaking factor 2.60 2.6 2.6 3 .08 Nuclear Design (First Core)

Water/U02 volume ratio (cold) 2.47 2.41 2.41 2.42 Thermal and Hydraulic Design Reactivity with strongest control I rod out, kif <0.99 cO .99 <0.99 .O0.99 Moderator temperature coefficient At 68OF, Ak/k - OF water -5.0 x 105 -5.0 x 105 -5.0 x 10 5 -8.9 x 10-'

Hot, no voids, Ak/k - OF water -39.0 x 10 5 -39.0 x 10-5 -39.0 x 10-5 -17.0 x 10-5 VYNPS UFSAR Revision 17 1.7-5 of 22

Table 1.7.1 (Continued)

Browns Ferry Vermont Yankee Each Unit Hatch Station Monticello Moderator void coefficient

-1.0 X 10-3 Hot, no voids, Ak/k - % void -1.0 X 1O03 -1.0 X 10-3 -1.0 X 10-3 At rated output, Ak/k - % void -1.6 x 10-3 -1.6 x 10-3 -1.6 x 10-3 -1.4 x 10-3 Fuel temperature doppler coefficient At 68OF, Ak/k - OF fuel -1.3 x 10-5 -1.3 x 10-5 -1.3 x 10-5 -1.2 x 10 5 .

Hot, no voids, Ak/k - OF fuel -1.2 x 10-5 -1.2 x 10-5 -1.2 x lo0- -1.2 x 10-l At rated output, Ak/k - OF fuel -1.3 x 10-5 -1.3 x 10-5 -1.3 x io-5 <-1.2 x 10-5 Initial average U-235 enrichment, W/O 2.50% 2.19% 2.23% 2.25%

Fuel average discharge exposure, MWD/ton 19, 085 19, 000 19,000 19, 000 Core Mechancial Design Fuel Assembly Number of fuel assemblies 368 764 560 484 Fuel rod array 7 x 7 7 x 7 7 x 7 7 x 7 Overall dimensions, inches 175.83 175.88 175.88 175.88 Weight of U02 per assembly, pounds Undished - Undished - Undished - Undished -

490.53 490.35 490.35 492.5 Dished (3%) Dished (3%) Dished - Dished -

479.35 483.42 483.42 481.7 Weight of fuel assembly, pounds Undished - Undished - Undished - Undished -

682.33 681.48 681.48 678.9 Dished (3%) Dished (3%) Dished - Dished -

671.05 674.55 674.55 668 Fuel Rods Number per fuel assembly 49 49 49 49 Outside diameter, inch 0.563 0.563 0.562 0.563 Clad thickness, inch 0. 032 0.032 0.032 0.032 Gap - pellet to clad, inch 0.006 0.0055 0.005 0.005 Length of gas plenum, inches 16 16 16 11.24 Clad material Zircaloy-2 Zircaloy-2 Zircaloy-2 Zircaloy-2 and/or -4 Cladding process Free standing Free standing Free standing Free standing loaded tubes loaded tubes loaded tubes loaded tubes Fuel Pellets Material Uranium dioxide Uranium dioxide Uranium dioxide Uranium dioxide Density, % of theoretical 95% 93%- 93% 93%

Diameter, inch 0.487 0.488 0.488 0.488 Length, inch 0.5 0.5 0.5 0.5 VYNPS UFSAR Revision 17 1.7-6 of 22

Table 1.7.1 (Continued)

Browns Ferry Vermont Yankee Each Unit Hatch Station Monticello Fuel Channel Overall dimension, inches (length) 166.875 166.875 166.875 166.875 Thickness, inch 0 .08 0.08 0.08 0.08 Cross section dimensions, inches 5.438 x 5.438 5.438 x 5.438 5.438 x 5.438 5.438 x 5.438 Material Zircaloy-4 Zircaloy-4 Zircaloy-4 Zircaloy-4 Core Assembly Fuel weight as U0 2, pounds 178,145 370,933 272,849 238,370 Zirconium weight, pounds 63,539 131, 000 96,370 80, 990 (Z-2 + Z-4 Spacers)

Core diameter (equivalent), inches 129.9 187.1 160.2 149 Core height (active fuel), inches 144 144 144 144 Core Mechanical Design Reactor Control System Number of movable control rods 89 185 137 121 Shape of movable control rods Cruciform Cruciform Cruciform Cruciform Pitch of movable control rods 12.0 12.0 12.0 12.0 Control material in movable rods B4 C granules B4 C granules B4 C granules B4C granules compacted in compacted in compacted in compacted in SS tubes SS tubes SS tubes SS tubes Type of control rod drives Bottom entry, Bottom entry, Bottom entry, Bottom entry, locking piston locking piston locking piston locking piston Number of temporary control curtains 156 372 248 216 Curtain material Flat, boron-- Flat, boron-- Flat, boron-- Flat, boron--

stainless steel stainless steel stainless steel stainless steel Method of variation of reactor power Movable control Movable control Movable control Movable control rods and variable rods and variable rods and variable rods and variable coolant pumping coolant pumping coolant pumping coolant pumping Reactor Vessel Design Material Carbon steel-clad Design pressure, psia 1265 1265 1265 1265 Design temperature, 4F 575 575 575 575 Inside diameter ft-in. 17 - 2 20 - 11 18 - 2 17 - 2 Inside height, ft-in. 63 - 1.5 72 - 11 1/8 69 - 4 63 - 2 Side thickness (including clad) 5.187 6.313 5.531 5.187 Minimum clad thickness, inches 1/8 1/8 1/8 1/8 VYNPS UFSAR Revision 17 1.7-7 of 22

Table 1.7.1 (Continued)

Browns Ferry.

Vermont Yankee Each Unit Hatch Station Monticello Reactor Coolant Recirculation Design Number of recirculation loops 2 2 2 2 Design pressure Inlet leg, psig 1175 1148 1148 1148 Outlet leg, psig 1274 1326 1274 1248 Design temperature, 'F 562 562 562 562 Pipe diameter, inches 28 28 28 28 Pipe material 304/316 304/316 304/316 304 Recirculation pump flow rate, GPM 32,500 45,200 45,200 32,500 Number of jet pumps in reactor 20 20 20 20 Main Steam Lines Number of steam lines 4 4 4 4 Design pressure, psig 1146 1146 1146 1146 Design temperature, OF 563 563 563 563 Pipe diameter, inches 18 26 24 18 Pipe material Carbon Steel (ASTM A155 KC70 or ASTM A106 Grade B)

In-Core Neutron Instrumentation Number of in-core neutron detectors (fixed) 80 172 124 96 Number of in-core detector assemblies 20 43 31 24 Number of detectors per assembly 4 4 4 4 Number of traversing-incore-probe neutron 3 5 4 3 detectors Range (and number) of detectors Source range monitoring subsystem Source to Source to Source to Source to

.001% power (4) .001* power (4) .001% power (4) .001% power (4)

Intermediate range monitoring .0002% to 20% .0001% to 10% .0001% to 10% .0001% to 10%

.subsystem power (6) power (8) power (8) power (8)

Local power range monitoring 0.1% to 125% 5% to 125* 5% to 125% 5 to 125%

subsystem power (80) power (172) power (124) power (96)

Average power range monitoring 2.5% to 125% 2.5% to 125% 2.5% to 125% 5% to 125%

subsystem power (6) power (6) power (6) power (6)

Number and type of in-core neutron sources 4 Sb-Be 7 Sb-Be 5 Sb-Be 5 Sb-Be Core Standby Cooling System (These systems are sized on design power.)

Core Spray System Number of loops 2 2 2 2 Flow rate (gpm) 3000 at 120 psid 625.0 at 122 psid 4625 at 120 paid 3020 at 307 psid VYNPS UPSAR Revision 17 1.7-8 of 22

Table 1.7.1 (Continued)

Browns Ferry Vermont Yankee Each Unit Hatch Station Monticello High Pressure Coolant Injection System (No.) 1 1 1 1 Number of loops 1 1 1 1 Flow rate (gpm) 4250 5000 4250 3000 Automatic Depressurization System (No.) 1 1 1 1 Low Pressure Coolant Injection (No.) 1 1 1 1 Number of pumps 4 4 4 4 Flow rate (gpm/pump) 7,200 at 20 psid 10,000 at 20 psid 7,700 at 20 psid 4,000 at 20 psid Auxiliary Systems Residual Heat Removal System Reactor shutdown cooling (number of pumps) 4 4 4 4 Flow rate (gpm/pump)') 7,200 10, 000 7,700 4,000 Capacity (Btu/hr/heat exchanger) (2) 57.5 x 106 70 x 106 32 x 106 24.5 x 106 Number of heat exchangers 2 4 2 2 Primary containment cooling Flow rate (gpm) 28,000 40,000 30,800 16,000 RHR Service Water System Flow rate (gpm/pump) 2,700 4,500 8,000 3,500 Number of pumps 4 8 4 4 Reactor Core Isolation Cooling System Flow rate (gpm/pump) 400 616 at 1120 psid 400 at 1120 psid 400 Fuel Pool Cooling and Cleanup System Capacity (Btu/hr) 2.37 x 106 8.8 x 130 3.3 x 10O 2.87 x 106 (1) Capacity during reactor flooding made with 3 of 4 pumps running.

(2) Capacity during post-accident cooling mode with 165°F shell side inlet temperature, maximum service water temperature, and 1 RHR pump and 1 RHR service water pump in operation.

VYNPS UFSAR Revision 17 1.7-9 of 22

TABLE 1.7.2 Comparison of Power Conversion System Design Characteristics (Values given apply to the originally licensed design.)

Browns Ferry Turbine-Generator Vermont Yankee Each Unit Hatch Station Monticello Design power, MWt 1665 3440 2537 1670 Design power, MWe 564 1152 849 543 Generator speed, RPM 1800 1800 1800 1800 Design steam flow, lb/hr 6.721 x 10' 14.049 x 106 10.48 x 10' Turbine inlet pressure, psig 950 965 970 950 Turbine Bypass System Capacity, percent of turbine design steam flow 105 25 25 15 Main Condenser Heat removal capacity, Btu/hr 3605 x 106 7770 x 10' 5800 x 106 3750 x 106 Circulating Water System Number of pumps 3 3 3 2 Flow rate, gpm/pump 122, 000 200,000 185, 000 140, 000 Condensate and Feedwater Systems Design flow rate, lb/hr 6.4 x 106 13.999 x 10' 10.096 x 106 6.77 x 106 Number of condensate pumps 3 3 3 2 Number of condensate booster pumps 3 Number feedwater pumps 3 3 2 2 Condensate pump drive ac power ac power ac power ac power Condensate booster pump drive ac power Feedwater pump drive ac power turbine turbine ac power VYNPS UFSAR Revision 17 1.7-10 of 22

TABLE 1.7.3 Comparison of Electrical Power Systems Design Characteristics (Values given apply to the originally licensed design.)

Browns Ferry Transmission System Vermont Yankee Each Unit Hatch Station Monticello Outgoing lines (number-rating) 2-345 kV 6-500 kV 2-230 kV 2-345 kV I 2-115 kV 3-115 kV 2-230 kV Normal Auxiliary AC Power Incoming lines (number-rating) 2-345 kV 2-161 kV 2-30 kV 1-345 kV 2-115 kV 1-115 kV 1-4160 V Auxiliary transformers 1 3 1 2 Startup. transformers .1 2 2 1 Standby AC Power Supply Number diesel generators 2 4 3 2 Number of 4160 V standby busses 2 4 3 4 Number of 480 V standby busses 2 8 4 (600 V) 4 DC Power Supply Number of 125 V or 250 V batteries 2 4 2 2-125 V 1-250 V Number of 125 V or 250 V busses 3 4 4 2-125 V 1-250 V VYNPS I UFSAR Revision 17 1.7-11 of 22

TABLE 1.7.4 Comparison of Containment Design Characteristics (Values given apply to the original licensed design.)

Browns Ferry Primary Containment* Vermont Yankee Each Unit Hatch Station Monticello Type Pressure Pressure Pressure Pressure suppression suppression suppression suppression Construction Drywell Light bulb shape; Light bulb shape; Light bulb shape; Light bulb shape; steel vessel steel vessel steel vessel steel vessel Pressure suppression chamber Torus; steel Torus; steel Torus; steel Torus; steel vessel vessel vessel vessel Pressure Suppression Chamber Internal design pressure (psig) 56 56 56 56 External design pressure (psi) 2 2 2 2 Drywell-internal design pressure (psig) 56 56 56 56 Drywell-external design3 pressure (psi) 2 2 2 2 Drywell free volume (ft ) 134,200 159,000 146,400 134,200 Pressure suppression chamber free volume (ft3) 108,250 119,000 101,410 108,250 Pressure suppression pool water volume (ft3 ) 77, 970 135,000 86,660 77,970 Submergence of vent pipe below pressure 4 4 4 4 pool surface (ft)

Design temperature of drywell (OF) 281 281 281 281 Design temperature of pressure suppression chamber (OF) 281 281 281 281

• Where applicable, containment parameters are based on design power.

VYNPS UFSAR Revision 17 1.7-12 of 22

TABLE 1.7.4.

(Continued)

Browns Ferry Primary Containment* Vermont Yankee Each Unit Hatch Station Monticello Downcomer vent pressure loss factor 6.21 6.21 6.21 6.21 Break area/Total vent area 0.019 0.019 0.019 0.019 Calculated maximum pressure after blowdown 35 46.6 45 41 Drywell (psig)

Pressure suppression chamber (psig) 22 27 28 26 Initial pressure suppression pool temperature rise (OF) 35 50 50 50 Leakage rate (W free volume/day at 56 psig 0.5 0.5 0.5 0.5 and 281OF)

Secondary Containment Type Controlled leak- Controlled leak- Controlled leak- Controlled leak-age, elevated age, elevated age, elevated age, elevated release release release release Construction Lower levels Reinforced con- Reinforced con- Reinforced con- Reinforced con-crete crete crete crete Upper levels Steel super- Steel super- Steel super- Steel super-structure and structure and structure and structure and siding siding siding siding Roof Steel sheeting Steel sheeting Steel sheeting Built up on steel decking Internal design pressure (psig) 0.25 0.25 0.25 0.25 Design in leakage rate (% free volume/day 100 100 100 100 at 0.25 inches H20)

Elevated Release Point Type Stack Stack Stack Stack Construction . Reinforced con- Reinforced con- Reinforced con- Reinforced con-crete crete crete crete Height (above ground) 318 feet 600 feet 100 meters 238 feet

• Where applicable, containment parameters are based on design power.

VYNPS UFSAR Revision 17 1.7-13 of 22

TABLE 1.7.5 Comparison of Structural Design Characteristics (Values given apply to the original licensed design.)

Browns Ferry Seismic Design Vermont Yankee Nuclear Plant Hatch Station Monticello Design earthquate (horizontal g) 0.07 0.10 0.08 0.06 Maximum earthquake (horizontal g) 0.14 0.20 0.15 0.12 Wind Design Maximum sustained (mph) 80 100 105 100 Tornadoes (mph) 300 300 300 300 VYNPS UFSAR Revision 17 1.7-14 of 22

i TABLE 1.7.6 Comparison of Systems Design Characteristics (Parameters are related to rated power output for a single unit unless otherwise noted.) (Values given apply to the originally licensed design.)

Vermont Yankee Dresden 2 Thermal and Hydraulic Design Rated power, MWt 1593 2255 Design power, MWt 1665 2527 Steam flow rate, lb/hr 6.43 x 106 9.945 x 106 Core coolant flow rate, lb/hr 48.0 x 106 98 x 106 Feedwater flow rate, lb/hr 6.40 x 106 9.94 x 106 Feedwater temperature, OF 372 348 System pressure, nominal in steam dome, psia 1020 1020 Average power density, kw/liter 50.94 41.08 Maximum thermal output, kw/ft 18.37 17.5 Average thermal output, kw/ft 7.079 5.7 2

Maximum heat flux, Btu/hr-ft 425,500 405, 000 Average heat flux, Btu/hr-ft 2 163,926 131,860 Maximum U02 temperature, OF 4380 3470 Average volumetric fuel temperature, OF 1100 1050 Average fuel rod surface temperature, OF 558 558 Minimum critical heat flux ratio (MCHFR) >1.9 >1. 9 Coolant enthalpy at core inlet, Btu/lb 519.8 522.3 Core maximum exit voids within assemblies 74.7 76 Core average exit quality, % steam 13.3 10.1 Design Power Peak Factor Maximum relative assembly power 1.4 1.47 Local peaking factor 1.24 1.30 Axial peaking factor 1.5 1.57 Total peaking factor 2.60 3 .60 Nuclear Design (First Core)

Water/UO2 volume ratio (cold) 2.47 2.41 Reactivity with strongest control rod out, <0.99 <0.99 Moderator temperature coefficient At 68OF, Ak/k - OF water -5.0 x 10 5 -8.0 x 105 Hot, no voids, Ak/k - OF water -39.0 x 10-5 -17.0 x 10-5 Moderator void coefficient

-1.0 x 10-3 -1.0 X 103 Hot, no voids, Ak/k -  % void VYNPS UFSAR Revision 17 1.7-15 of 22

TABLE 1.7.6 (Continued)

Vermont Yankee Dresden 2 At rated output, Ak/k - t void -1.6 x 10-3 -1.4 x 10-3 Fuel temperature doppler coefficient At 68OF, Ak/k - OF fuel -1.3 x 10-5 -1.2 x 10-5 I

Hot, no voids, Ak/k - OF fuel -1.2 x 10-5 -1.2 x 10-5 At rated output, Ak/k - % fuel -1.3 x 10-5 -1.2 x 10i5 Initial average U-235 enrichment, W/O 2.50% 2.12%

Fuel average discharge exposure, MWD/ton 19, 085 19, 000 Core Mechanical Design Fuel Assembly Number of fuel assemblies 368 724 Fuel rod array 7 x 7 7 x 7 Overall dimensions, inches 175.88 175. 88 Weight of U02 per assembly, pounds Undished-490.53 Undished-492.5 Dished Dished-481.7 (3%)-479.35 Weight of fuel assembly, pounds Undished-682.23 Undished-678.9 Dished Dished-668.0 (3%)-671.05 Fuel Rods Number per fuel assembly 49 49 Outside diameter, inch 0.563 0.563 Clad thickness, inch 0.032 0.032 Gap - pellet to clad, inch 0.005 0.005 Length of gas plenum, inches 16 11.24 Clad material Zircaloy-2 Zircaloy-2 Cladding process Free standing Free standing loaded tubes loaded tubes Fuel Pellets Material Uranium dioxide Uranium dioxide Density, % of theoretical 95% 93%

Diameter, inch 0.487 0.488 Length, inch 0.5 0.5 Fuel Channel Overall dimension, inches (length) 166.875 166.875 VYNPS UFSAR Revision 17 1.7-16 of 22

TABLE 1.7.6 (Continued)

Vermont Yankee Dresden 2 Thickness, inch 0.080 0.080 Cross section dimensions, inches 5.438 x 5.438 5.438 x 5.438 Material Zircaloy-4 Zircaloy-4 Core Assembly Fuel weight as U02 , pounds 178, 145 351,258 Zirconium weight, pounds (Z-2 + Z-4 Spacers) 63,539 121, 154 Core diameter (equivalent), inches 129.9 182.2 Core height (active fuel), inches 144 144 Reactor Control System Method of variation of reactor power Movable control Moveable control rods and various rods and various coolant pumping coolant pumping Number of movable control rods 89 177 Shape of movable control rods Cruciform Cruciform Pitch of movable control rods 12.0 12.0 Control material in movable rods B4 C granules B 4C granules compacted in SS compacted in SS tubes tubes Type of control rod drives Bottom entry, Bottom entry, locking piston locking piston Number of temporary control curtains 156 340 Curtain material Flat, boron-- Flat, boron--

stainless steel stainless steel Reactor Vessel Design Material Carbon steel- Carbon steel-clad clad Design pressure, psia 1265 1265 Design temperature, OF 575 575 Inside diameter ft-in. 17 - 2 20 - 11 Inside height ft-in. 63 - 1.5 68 - 7 5/8 Side thickness (including clad) 5.187 6.125 Minimum clad thickness, inches 1/8 1/8 Reactor Coolant Recirculation Design Number of recirculation loops 2 2 Design pressure Inlet leg, psig 1175 1175 VYNPS UFSAR Revision 17 1.7-17 of 22

TABLE 1.7.6 (Continued)

Vermont Yankee Dresden 2 Outlet leg, psig 1274 1325

• Design temperature, OF 562 565 Pipe diameter, inches. 28 28 Pipe material 304/316 304/316 Recirculation pump flow rate, GPM 32,500 45,000 Number of jet pumps in reactor 20 20 Main Steam Lines Number of steam lines 4 4 Design pressure, psig 1146 1146 Design temperature, OF 563 563 Pipe diameter, inches 18 20 Pipe material Carbon steel Carbon steel Core Standby Cooling Systems

• (These systems are sized on design power.)

Core Spray System Number of loops 2 2 Flow rate (gpm) 3000 at 120 psid 4500 at 90 psid Core Mechanical Design In-Core Neutron Instrumentation Number of in-core neutron detectors (fixed) 80 164 Number of in-core detector assemblies 20 41 Number of detectors per assembly 4 4 Number of traversing-incore-probe neutron 3 3 detectors Range (and number) of detectors Source range Source to 0.001% Source to 0.001%

monitoring subsystem power (4) power (4)

Intermediate range monitoring subsystem 0.0002% to 20% 0.0003% to 10%

power (6) power (8)

Local power range monitoring subsystem 0.01% to 125% 5% to 125% power power (80) (164)

Average power range monitoring subsystem 2.5% to 125% 5% to 125% power power (6) (6)

Number and type of in-core neutron sources 4 Sb-Be 7 Sb-Be Core Standby Cooling Systems High pressure coolant injection system (No.) 1 1 VYNPS UFSAR Revision 17 1.7-18 of 22

TABLE 1.7.6 (Continued)

Vermont Yankee Dresden 2 Number of loops 1 1 Flow rate (gpm) 4250 5600 Automatic depressurization system (No.) 1 1 Low pressure coolant injection (No.) 1 1 Number of pumps 4 4 Flow rate (gpm/pump) 7200 at 20 psid 4833 at 20 psid Auxiliary Systems Residual Heat Removal System Reactor shutdown cooling (number of pumps) 4 3(3)

Flow rate (gpm/pump)( " 7,200 5, 350 (3)

Capacity (btu/hr/heat exchanger) (2) 57.5 x 106 27 x 10613)

Number of heat exchangers 2 3 (3)

Primary containment cooling Flow rate (gpm) 28,000 RHR Service Water System Flow rate (gpm/pump) 2,700 3,500 Number of pumps 4 4 Reactor Core Isolation Cooling System Flow rate (gpm) 400 None Fuel Pool Cooling and Cleanup System Capacity (Btu/hr) 2.37 x 106 3.65 x 106 Turbine-Generator Design power, MWt 1665 2527 Design power, MWe 564 809 Generator speed, RPM 1800 1800 Design steam flow, lb/hr 6.721 x 10' 9.945 x 106 Turbine inlet pressure, psig 950 950 Turbine Bypass System WCapacity during reactor cooling mode with three of four pumps running.

2

( )Capacity during post-accident.cooling mode with 165 0F shell side inlet temperature, maximum service water temperature, and one RHR pump and one RHR service water pump in operation.

l3) Separate shutdown cooling system.

VYNPS UFSAR Revision 17 1.7-19 of 22

TABLE 1.7.6 (Continued)

Vermont Yankee Dresden 2 Capacity, percent. of turbine design steam 105 40 flow Main Condenser Heat removal capacity, Btu/hr 3605 X 106 Circulating Water System Number of pumps 3 3 Flow rate, gpm/pump 122,000 Condensate and Feedwater Systems Design flow rate, lb/hr 6.4 x 106 9.725 x l06 Number of condensate pumps 3 4 Number of condensate booster pumps 4 Number feedwater pumps 3 3 Condensate pump drive ac power ac power Condensate booster pump drive ac power Feedwater pump drive ac power ac power Transmission System Outgoing lines (number-rating) 2-345 kV 5-345 kV 2-115 kV Normal Auxiliary AC Power Incoming lines (number-rating) 2-345 kV 5-345 kV 2-115 kV 6-138 kV 1-4160 v Auxiliary transformers 1 1 Startup transformers 1 I Standby AC Power Supply Number diesel generators 2 3 (for 2 units)

Number of 4160V standby busses 2 2 Number of 480V standby busses 2 2 DC Power Supply Number of 125 V or 250 V batteries 2 1-125 V 1-250 V Number of 125 V or 250 V busses 3 2-125 V 2-250 V VYNPS . UFSAR Revision 17 1.7-20 of 22

TABLE 1.7.6 (Continued)

Vermont Yankee Dresden 2 Primary Containment Type Pressure Pressure suppression suppression Construction Light bulb shape; Light bulb shape; Drywell. steel vessel steel vessel Pressure suppression chamber Torus; steel Torus; steel vessel vessel Pressure Suppression Chamber Internal design pressure (psig) 56 62 External design pressure (psi) 2 1 Drywell-internal design pressure (psig) 56 62 Drywell-external design pressure (psi) 2 2 Drywell free volume (ft3 ) 134,200 158,236 Pressure suppression chamber free volume 108,250 117,245 3

(ft )

Pressure .suppression pool water volume (ft3) 77,970 Submergence of vent pipe below pressure pool 4 4 surface (ft)

Design temperature of drywell (OF) 281 281 Design temperature of pressure suppression 281 281 chamber (OF)

Downcomer vent pressure loss factor 6.21 6.21 Break area total vent area (ft2 ) 0.019 0.019 Calculated maximum pressure after blowdown 35 48 drywell (psig)

Pressure suppression chamber (psig) 22 28 Initial pressure suppression pool temperature 35 so rise (OF)

Leakage rate (% free volume/day at 56 psig 0.5 0.5 (at 62 psig and 281 0F) and 2810F)

Where applicable, containment parameters are based on design power.

VYNPS . UFSAR Revision 17 1.7-21 of 22

TABLE 1.7.6 (Continued)

Vermont Yankee Dresden 2 Secondary Containment Type Controlled Controlled leakage elevated leakage elevated release release Construction Lower levels Reinforced Reinforced concrete concrete Upper levels Steel super- Steel super-structure and structure and siding siding Roof Steel sheeting Concrete slabs Initial design pressure (psig) 0.25 0..25 Design in leakage rate (% free volume/day at 100 100 0.25 inches H2 0)

Elevated Release Point Type Stack Stack Construction Reinforced Reinforced concrete concrete Height (above ground) 318 feet 310 feet Seismic Design Design earthquake (horizontal g) 0.07 0.10 Maximum earthquake (horizontal g) 0.14 0.20 Wind Design Maximum sustained (mph) so 110 Tornadoes (mph) 300 300 VYNPS UFSAR Revision 17 1.7-22 of 22

4 (Fornne Jy UREG-7-61087 4c'<"' 't'%o U.S. NUCLEAR REGULATORY COMMISSION

STANDARD REVIEW PLAN Nn I OFFICE OF NUCLEAR REACTOR REGULATION 14.2.1 GENERIC GUIDELINES FOR EXTENDED POWER UPRATE TESTING PROGRAMS This Standard Review Plan (SRP) section provides general guidelines for reviewing proposed extended power uprate (EPU) testing programs. This review ensures that the proposed testing program adequately verifies that the plant can be operated safely at the proposed uprated power level.

Power uprates can be classified In three categories. Measurement uncertainty recapture power uprates are less than 2 percent and are achieved by Implementing enhanced techniques for calculating reactor power. Stretch power uprates are typically up to 7 percent and do not generally Involve major plant modifications. EPUs are greater than stretch power uprates and have been approved for Increases as high as 20 percent.

EPUs usually require significant modifications to major balance-of-plant equipment. A power uprate Is classified as an EPU based on a combination of the proposed power increase and the plant modifications necessary to support the requested uprate. This SRP applies only to EPU license amendment requests.

REVIEW RESPONSIBILITIES Primary - Equipment and Human Performance Branch (IEHB)

Secondary - Reactor Systems Branch (SRXB)

Plant Systems Branch (SPLB)

Probabilistic Safety Assessment Branch (SPSB)

Materials and Chemical Engineering Branch (EMCB)

Electrical and Instrumentation & Controls Branch (EEIB)

Mechanical &-Civil Engineering Branch (EMEB)

DRAFT Rev. 0 - Debember 2002 USNRC STANDARD REVIEW PLAN Standard review plans are prepared for the guidance of the Office of Nuclear Reactor Regulation staff responsible for the review of oplilcations to construct and operate nuclear power plants. These documents are made avallable to the public as cart of the Commission's policy to Inform the nuclear Industry and the general public of regulatory procedures and ponles. Standard review plans are not substitutes for regulatory guides or the Commisslon's regulations and complance with them is not required. The standard review plan sections are keyed to the Standard Format and Content of Safety Analysis Reports for Nuclear Power Plants. Not all sections of the Standard Format have a corresponding review plan.-

Published standard review plans will be revised periodically, as appropriate, to accommodate comments and to reflect new Information and experience.

Comments and suggestions for Improvement will be considered and should be sent to the U.S. Nuclear Regulatory Commission, Office of Nuclear Reactor Regulation, Washington, D.C. 20555.

I I

1. AREAS OF REVIEW The Equipment and Human Performance Branch coordinates the review of the overall power uprate testing program. Secondaryreview branches are responsible for reviewing

<2 EPU applications to ensure that the licensee has proposed an EPU testing program that demonstrates that structures, systems, and components (SSCs) will perform satisfactorily in service at the requested increased plant power level. Secondary review branches will assist IEHB In the review of proposed testing plans and acceptance criteria, as needed.

The review of EPU testing programs should be performed In conjunction with staff reviews of other aspects of the EPU license amendment request Paperwork Reduction Act Statemement The information collections contained in this NUREG are covered by the requirements of 10 CFR Part 50 which were approved by the Office of Management and Budget, approval number 3150-0011.

Public Protection Notification If a means used to Impose an information collection does not display a currenty valid OMB control number, the NRC may not conduct or sponsor, and a person Is not required to respond to, the information collection.

DRAFT Rev. 0 - December 2002 14.2.1-2

11. 'ACCEPTANCE CRITERIA-Extended power uprate test program acceptance criteria.are based on meeting the relevant requirements of the following regulations:

Appendix A, 'General Design Criteria for Nuclear Power Plants,3 to 10 CFR Part 60, establishes In Criterion 1, 'Quality Standards and Records," as it relates to establishing the necessary testing requirements for SSCs important to safety, such that there Is reasonable assurance that the facility can be operated without undue risk to the health and safety of the public. However, as discussed in Section 2.1.5.6 of LIC-100, 'Control of Licensing Basis for Operating Reactors,' the General Design Criteria (GDC) are not applicable to plants with construction permits issued before Mai 21, 1971. Each plant licensed before the GDC were formally adopted was evaluated on a plant-specific basis, determined to be safe, and licensed by the Commission. -

Criterion Xl, 'Test Control," of Appendix B tolD CFR Part 50, as It relates to establishment of a test program to assure that testing required to demonstrate that SSCs will perform satisfactorily In service Is Identified and performed in accordance with written test procedures which Incorporate the requirements and acceptance limits contained Inapplicable design documents.

• 10 CFR 50.90, 'Application for Amendment of Ucense or Construction Permit,' as it relates to an application for an amendment following as far as applicable the form prescribed fororiginal applications- Section 50.34, Contents of Applications:

- Technical Information, which specifies requirements for the original operating licbnse application, requires that the Final Safety Analysis Report (FSAR) include plans for preoperational testing and initial operations.

Technical Rationale -

This review ensures that the proposed EPU testing program adequately demonstrates that SSCs will perform satisfactorily at EPU conditions. In particular, the EPU test program provides assurance that (1) any powver-uprate related modifications to the facility have been adequately constructed and implemented; and (2) the facility can be operated at the proposed EPU conditions in accordance with design requirements and in a manner that will not endanger the health and safety of the public.

The following paragraphs describe the technical rationale for application of the above acceptance criteria to the review of EPU test programs:

• Criterion I of Appendix A to 10 CFR Part 50, establishes the necessary testing requirements for SSCs Important to safety; that Is, SSCs that provide reasonable assurance that the facility can be operated without undue risk to the health and safety of the public: Also, SSCs important to safety shall be designed, fabricated,

&ected bhd tested to quality standards commensurate with the importance of the safety functi6ns to be performed. Where generally recognized codes and standards are used, they shall be identified and evaluated to determine their applicability. Additionally, a&ciuality assurance program shall be established to ensure that SSCs will satisfactorily perform their safety functions.

14.2.1-3 DRAFT Rev. 0 - December 2002

Application of Criterion I of 10 CFR 50, Appendix A, to the EPU test program ensures that the requested power uprate does not invalidate original testing requirements contained in the original licensing basis. This ensures that SSCs continue to meet their original design specifications. Testing is performed, as necessary to provide assurance that SSCs continue to meet their design capabilities. For example, testing could be performed to demonstrate that SSCs functions, as expected, actuate in the Intended time period and produce the expected flow rate within the expected time period. Original quality assurance standards and applicable codes and standards would be satisfied. The quality assurance program ensures proper documentation and traceability that applicable testing was accomplished, and codes and standards satisfied.

Criterion Xl of Appendix B to 10 CFR Part 50 requires that a test program be established to assure that all testing required to demonstrate that SSCs will perform satisfactorily in service is identified and performed in accordance with written test procedures which Incorporate the requirements and acceptance limits contained in applicable design documents. The test program requirements include, as appropriate, proof tests prior to installation, preoperational tests, and operational tests of SSCs. Test procedures are required to include provisions for assuring that all prerequisites for the given test have been met, that adequate test instrumentation is available and used, and that the test Is performed under suitable environmental conditions. Test results are required to be documented and evaluated to assure that test requirements have been satisfied.

Application of Criterion Xl of 10 CFR Part 50, Appendix B. to the EPU test program ensures that SSC capabilities to perform specified functions are not adversely Impacted by increasing the maximum allowed power level. This also ensures that deficiencies are identified and corrected, and that testing activities are conducted in a manner which minimizes operational reliance on untested safety functions. This K>

provides a high degree of assurance of SSC and overall plant readiness for safe operation within the bounds of the design and safety analyses, assurance against unexpected or unanalyzed plant behavior, and assurance against early safety function failures in service. Regulatory Guide (RG) 1.68, Initial Test Programs for Water-Cooled Nuclear Power Plants," Revision 2, describes the general scope and depth of Initial test programs that the NRC staff found acceptable during the review of original operating license applications. The SSCs subject to Initial testing performed safety functions that included fission product containment; reactivity monitoring and control; reactor safe shutdown (including maintaining safe shutdown); core cooling; accident prevention; and consequence mitigation as specified in the design and credited in safety analyses.

• 10 CFR 50.90, *Application for Amendment of License or Construction Permit,"

requires that each licensee submitting a license amendment request fully describe the changes desired and follow, as far as practicable, the form prescribed for the original application. Section 50.34, Contents of Applications: Technical Information," specifies requirements for the original operating license application.

In particular, 10 CFR 50.34(b)(6)(iii) requires that each application for a license to operate a facility include in the FSAR plans for preoperational testing and initial operations. The initial test program (which includes preoperational testing and testing during Initial operation) verifies that SSCs are capable of performing their safety functions as specified In the design and credited In safety analyses.

DRAFT Rev. 0 - December 2002 14.2.1-4

Application of 10 CFR 50.90 and 10 CFR 50.34(b)(6)i)R to the EPU test program ensures that the licensee submits adequate Information, commitments, and plans K... demonstrating that operation at the requested higher power level will be within the bounds of the design and safety analyses and that EPU testing activities will be conducted in a sequence and manner which minimizes operational reliance on untested SSCs or safety functions. This also ensures that preoperational and initial startup testing Invalidated by the requested Increase In power level are evaluated and reperformed as necessary to demonstrate safe operation'of the plant.

11. REVIEW PROCEDURES The purpose of this review Is to ensure that the proposed EPU testing program adequately controls the initial power ascension to the requested EPU power level. The EPU test program shall Include suflicient steady-state and transient performance testing to demonstrate that SSCs will perform satisfactorily at the requested power level. The proposed EPU test program should be based on a systematic review of the initial plant test program to Identify initial licensing power-ascension testing that may be invalidated by the requested EPU. Additionally, the EPU test program should Include sufficient testing to demonstrate that EPU-related plant modifications have been adequately Implemented.

A. Comparison of Pronosed EPU Test Program to the Initial Plant Test Proaram

1. General Discussion The licensee should provide a comparison of the proposed EPU testing program to the original power-ascension test program performed during Initial plant licensing. The scope of this comparison shall include (1) all power-ascension tests Initially performed at a power level of equal to or greater than 80 percent of the original licensed thermal power level; and (2) Initial power-ascension tests performed at lower power levels If the EPU would invalidate the test results. The licensee shall either reperform Initial power-ascension tests within the scope of this comparison or adequately justify proposed deviations.

2. - Specific Acceptance Criteria Within its associated technical discipline, each secondary branch reviewer will determine If the licensee has adequately Identified the following In the EPU license amendment request:

-* All power-ascension tests Initially performed at a power level of equal to or greater than 80 percent of the original licensed thermal power level.

• All Initial power-ascension tests performed at power levels lower than 80 percent of the original licensed thermal power level that would be Invalidated by the EPU.

• Differences between the proposed EPU power-ascension test program and the portions of the Initial power-ascension program Included within the scope of this comparison.

14.2.1-5 DRAFT Rev. 0 - December 2002

The reviewer should refer to the plant-specific testing identified In FSAR Chapter 14.2, OInitial Plant Test Program' (or the equivalent FSAR section for non standard format plants), and startup test reports, if available, to verify that the licensee has adequately identified the scope of the Initial plant test program. Additionally, Attachment 1, 'Steady-State Power Ascension Testing Applicable to Extended Power Uprates," and Attachment 2, 'Transient Testing Applicable to Extended Power Uprates,'

to this SRP section provide a generic summary of power-ascension tests performed at or near full power.

If the licensee's proposed EPU test program does not include performance of testing originally performed during the initial plant test program, the reviewer shall ensure that the licensee adequately justifies all differences. The reviewer should refer to Section IIL.C, below, for guidance on assessing the adequacy of justifications for proposed

- differences.-

B. Post Modification Testing Reguirements for Functions Imoortant to Safetv Impacted by EPU-Related Plant Modifications

1. General Discussion EPUs usually require significant modifications to major balance-of-plant equipment, in addition to setpoint and operating parameter changes.

Therefore, within its respective technical area, each secondary review branch will assess if the licensee adequately evaluated the aggregate impact of EPU plant modifications, setpoint adjustments, and parameter changes that could adversely impact the dynamic response of the plant to anticipated initiating events. The objective of this review is to verify that the licensee has proposed a testing program which demonstrates that EPU-related modifications to the facility have been adequately implemented.

The reviewer Is not expected to evaluate the specific component- and system-level testing requirements for each plant modification, parameter change, or setpoint adjustment. Based on previous experience, testing required by Technical Specifications and existing 10 CFR Part 50.

Appendix B, quality assurance programs have been adequate to demonstrate Individual system or component performance characteristics. Therefore, this review Is intended to ensure that functions Important to safety that rely on the Integrated operation of multiple SSCs following an anticipated operational occurrence are adequately demonstrated prior to extended operation at the requested EPU power level.

2. Snecific Acceptance Criteria Based on review of the licensee's EPU license amendment request, the reviewer will determine if the licensee has adequately identified the following:

DRAFT Rev. 0 - December 2002 14.2.1-6

• plant modifications and setpoint adjustments necessary to support operation at power uprate conditions, and

• changes In plant operating parameters (such as reactor coolant temperature, pressure, T.,,, reactor pressure, flow, etc.) resulting from operation at EPU conditions.

The reviewer should assess if the licensee adequately identified functions important to safety that are affected by EPU-related modifications, setpolnt adjustments, and changes in plant operating parameters. In particular, the licensee should have considered the safety Impact of first-of-a-kind plant modifications, the Introduction of new system dependencies or Interactions, and changes in system response to initiating events. The review scope can be limited to those functions Important to safety associated with the anticipated operational

-occurrences described in Attachment 2 to this SRP, "Transient Testing Applicable to Extended Power Uprates! To assist in this review, Attachment 2 also includes typical transient testing acceptance criteria and functions Important to-safety associated with these anticipated events.

The reviewer should verify that the proposed EPU test program adequately demonstrates each function Important to safety that meets all of the following criteria: (1) Is Impacted by EPU-related modifications, (2) is required to mitigate a plant transient listed In Attachment2, and (3)

Involves the integrated response of multiple SSCs. If a function Important to safety cannot be adequately tested by overlapping Individual component- or system-level tests, the licensee should propose suitable system functionaLtesting.

C. Use of Evaluation To Justify Elimination of Power-Ascension Tests

1. General Discussion In certain cases, the licensee may propose an EPU test program that does not Include all of the power-ascension testing that would normally be required by the review criteria of Sections IlA and Ill.B above. The

• licensee shall provide an adequate just fication for each of these normally required power-ascension tests that are not Included in the EPU test program. For each proposed test exception within lts technical area, each secondary review branch will verify the adequacy of the licensee's Justification.-

2. Specific Accentance Criteria If the licensee proposes to not perform a power-ascension test that would normally be required by the review criteria contained In Sections lIl.A and 111.B, above, the reviewer should ensure that the licensee provides an adequate justification. The proposed EPU test program shall be sufficient to adequately demonstrate that SSCs will perform satisfactorily In service. The reviewer should consider the following factors when assessing the adequacy of the licensee's justification:

14.2.1-7 - DRAFT Rev. 0 - December 2002

a. Previous Operating ExDerience If the licensee proposes not to'perform a required transient test based on operating experience, a review should be conducted to determine the applicability of the operating experience to the specific plant configuration and test requirements. If the licensee references industry operating experience, the reviewer should consider similarity In plant design and equipment; operating power level; and operating and emergency operating procedures.

b. Introduction of New Thermal-Hydraulic Phenomena or Identified System Interactions The reviewer should ensure that the licensee adequately addressed the effects of any new therrnal-hydraulic phenomena

__--- rsysteminteractions-thatmaybe introduced as-a result of the EPU.

c. Facility Conformance to Limitations Associated With Analytical Analysis Methods The licensee's justification for not performing specific power-ascension testing should include consideration of the facility conformance to limitations associated with analytical analysis methods. These limitations may include, but are not limited to, plant operating parameters, system configuration, and power level.

d. Plant Staff Familiarization With Facility Ooeration and Trial Use of Operatina and Emeraency Operating Procedures Plant modifications and parameter changes, in conjunction with increased decay heat generation associated with higher power operation, can Impact the execution of abnormal and emergency operating procedures. For example, the EPU may change the timing and sequence of significant operator actions used in abnormal and emergency operating procedures, or could impact accident mitigation strategies In abnormal or emergency operating procedures.

For each EPU license amendment request, IEHB reviews the Impact of the requested power uprate on operator training and human factors in accordance with separate EPU review standard guidance. These reviews Include an evaluation of the changes In operator actions, procedures, and training (including necessary changes to the control room simulator) resulting from the EPU.

Although the initial power-ascension test program objectives, as described in Reference 8, included plant staff familiarization with facility operation and trial use of plant abnormal and emergency operating procedures, the EPU review standard adequately addresses the operator training and human factors aspects of the EPU. Therefore, it is not expected that power-ascension testing DRAFT Rev. 0 - December 2002 14.2.1-8

.4 would normally be required for the purposes of procedure verification or operator familiarization.

e. Margin Reduction in Safety Analysis Results for Anticiated Operational Occurrences The licensee's justification for not performing a particular power-ascension test should include a consideration of the change in the associated safety analysis results due to the proposed EPU. To aid in this review, the Information provided in Attachment 2 to this SRP section includes a reference to the safety analysis SRP sections related to each transient test, if applicable. For safety analysis acceptance criteria that can be quantitatively measured (e.g. peak reactor coolant system pressure), a reduction In available riiargin by less than approximately 10 percent would normally be considered to be a minimal change In consequences.

The available margin Is the difference between the standard review plan accident analysis acceptance criterion of Interest and the plant-specific value calculated at EPU conditions. For larger reductions In available margin, the licensee may consider such factors as the amount of remaining margin; the sensitivity of the results to changes In analysis assumptions; and the capability of transient testing to provide useful confirmatory data.

Although the initial power-ascension test program objectives, as described In Reference 8, Included validation of analytical models and verification of assumptions used for predicting plant response to anticipated transients and postulated accidents, transient testing Is not required for the purposes of analytical code validation for EPU license amendment reviews. The applicability and validation of accident analysis analytical codes is reviewed by the staff in accordance with separate EPU review standard guidance.

f. Guidance Contained in Vendor Toolcal Reports The NRC previously reviewed and accepted General Electric (GE)

Company Licensing Topical Report, 'Generic Guidelines for General Electric Boiling Water Reactor Extended Power Uprate' (referred to as ELTR-1), NEDC,32424P-A, Class III, February 1999, as an acceptable basis for BWR EPU amendment requests. This topical report provided specific guidance for the performance of Integrated system transient testing at EPU conditions. As described In Section 5.11.9.d and Appendix L.2A of ELTR-1, the generator load rejection and the main steam isolation valve (MSIV) tests verify that the plant performance Is as predicted and projected from previous test data.

• For PWRs, Westinghouse Report WCAP-10263, 'A Review Plan for Uprating the Licensed Power of a Pressurized Water Reactor Plant," provides limited guidance for power uprate testing.

Specifically, the document states that the recommended test 14.2.1-9 - DRAFT Rev. 0 - December-2002

program for the nuclear steam supply system and interfacing.

balance-of-plant systems be developed on a plant-specific basis depending on the magnitude of hardware modifications and the magnitude of the power uprat.

Although the NRC has previously approved certain exceptions to power-ascension testing requirements, the reviewer should assess the licensee's proposed Justifications on a plant-specific basis.

g. Risk 'mplications For cases where the licensee proposes a risk-Informed basis for not perfnoring certain transient tests, SPSB should be consulted to assist In the review. Risk-informed justifications for not perormung transient-tests-shousl be-arefully-weighedr against the potential benefits of performing the testing. In addition to the risks Inherent in initiating a plant transient, the review should also consider the benefit of Identifying potential latent equipment deficiencies or other plant problems under controlled I circumstances during transient testing. In any case, a risk-Informed justification should not be used as the sole basis for not performing transient testing.

Ifthe licensee provides adequate justification for not performing certain power-ascension tests, the staff may conclude that the EPU test program is acceptable without the performance of these tests.

D. Evaluate the AeouacvofProoosed Transient Testing Plans a I. General Discussion The EPU amendment request should Include plans for the initial approach to the increased EPU power level and steady-state testing that will be used to verify that the reactor plant operates within design parameters.

2. Specific Acceiotance Criteria For each EPU power-ascension test proposed by the licensee to demonstrate that the plant can be safely operated at EPU conditions, the staff will review the test objectives, summary of prerequisites and test methods, and specific acceptance criteria for each test to establish that the functional adequacy of SSCs Is verified. This review assures that the test objectives, test methods, and the acceptance criteria are acceptable and consistent with the licensing basis for the facility.

Each secondary review branch Vill review the licensee's plans for the EPU test program within its respective technical area. The licensee's EPU test program should include the following:

DRAFT Rev. 0 - December 2002 14.2.1-10

• The initial approach to the uprated EPU power level should be performed In an Incremental manner and Include steady-state power hold points to evaluate plant performance above the original full-power level. _

• The licensee should propose appropriate testing and acceptance criteria that ensure that the plant responds within design predictions. The predicted responses should be developed using real or expected values of Items such as beginning-of-life core reactivity coefficients, flow rates, pressures, temperatures, and response times of equipment and the actual status of the plant, and not the values or plant conditions used for conservative evaluations of postulated accidents.

• Contingency plans should be Implemented If the predicted plant

--- response-is -not obtained----

• The test program should be scheduled and sequenced to minimize the time untested functions Important to safety are relied upon during operation above the original licensed full-power level.

Safety-related functions relied upon during operation shall be verified to be operable In accordance with existing Technical Specification and Quality Assurance Program requirements.

To assist this review, Attachments I and 2 to this SRP section provide a generic listing of full power steady-state and transient tests and related acceptance criteria that are potentially applicable to an EPU test program.

If a power-ascension test is required to demonstrate that the plant can be operated safely at EPU conditions, the reviewer shall determine If a license condition should be imposed to ensure that this testing Is performed Ina timely and controlled manner.

IV. EVALUATION FINDINGS When the review of the Information in the EPU amendment application is complete and the reviewer has determined that it is satisfactory and In accordance with the -

acceptance criteria in Section II above, a statement similar to the following should be provided in the staffs Safety Evaluation Report (SER):

wThe staff has reviewed the EPU test program information provided In the license amendment request in accordance with SRP Section 14.2.1 and relevant guidance provided in the EPU Review Standard.'This review included an evaluation of (1) plans for the initial approach to the proposed maximum licensed thermal power level, including verification of adequate plant performance, (2) transient testing requirements necessary to demonstrate that the plant can be operated safely at the proposed increased maximum licensed thermal power level, and (3) the test program's conformance with applicable regulations. The staff finds that there is reasonable assurance that the applicant's EPU testing prograrnmsatisfies the requirements of Criterion Xi. 'Test Control,'of 10 CFR Part 50, Appendix B. and is therefore acceptable.'

I' 14.2.1-1 1 DRAFT Rev. 0 - December 2002

V. IMPLEMENTATION This SRP section will be used by the staff when performing safety evaluations of EPU license amendment applications submitted pursuant to 10 CFR 50.90. This SRP is not intended to be used In place of plant-specific licensing bases to assess the acceptability of an EPU application. Applicability of this SRP is determined on a plant-specific basis consistent with the licensing basis of the plant.

In addition, where the NRC has approved a specific methodology (e.g., topical report) for the type of power uprate being requested, licensees should follow the format prescribed for that specific methodology and provide the Information called for in that methodology and the NRC's letter and safety evaluation approving the methodology.

Except in those cases in which the applicant proposes an acceptable alternative method for complying with specified portions of the Commission's regulations, the method described herein will be used by the staff in its evaluation of conformance with Commission regulations.

VI. REFERENCES

1. 10 CFR Part 52, §52A7 'Contents of Applications.'

2. 10 CFR Part 50, Appendix B. Criterion XI, "Test Control.'

3. NUREG-1 503, 'Final Safety Evaluation Report Related to the Certification of the Advanced Boiling Water Reactor,* Volumes 1 and 2, July 1994.

4. SECY-01-0124, 'Power Uprate Application Reviews,' dated July 9, 2001. The related Staff Requirements Memorandum is dated May 24,2001.

5. General Electric Company Licensing Topical Report, "Generic Guidelines for General Electric Boiling Water Reactor Extended Power Uprate' (ELTR-1), NEDC-32424P-A, Class III, February 1999.

6. General Electric Company Licensing Topical Report, "Generic Evaluations of General Electric Boiling Water Reactor Extended Power Uprate," (ELTR-2), NEDC-32523P-A, Class 1II,February 2000, and Supplement 1, Volumes I and 11.

7. General Electric Company Licensing Topical Report, 'Constant Pressure Power Uprate,'

NEDC-33004P, RevisIon 1, July 2001.

8. NRC Regulatory Guide 1.68, "Initial Test Programs for Water-Cooled Nuclear Power Plants,' Revision 2, August 1978.

9. NRR Office Instruction LIC-100, 'Control of Licensing Basis for Operating Reactors.'

10. NRR Office Instruction LIC-101, "Ucense Amendment Review Procedures."

11. NRR Office Instruction LIC-500, "Processing Requests for Reviews of Topical Reports.'

12. Westinghouse WCAP-10263, "A Review Plan for Uprating the Licensed Power of a Pressurized Water Reactor Power Plant,' January 1983.

DRAFT Rev. 0 - December 2002 14.2.1 -12

.13. NRC inspection Manual, Part 9900, 10 CFR Part 50.59, Changes, Tests and

• Experiments, Change Notice Number 01-008.

14. NRC Information Notice 2002-26, "Failure of Steam Dryer Cover Plate After a Recent Power Uprate," September 11, 2002.

142.1-13 DRAFT Rev. 0- December 2002

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Pwer Ascenslon Test Reference Recommended InRbal Condiions Typical Test Acceptanee COflera PdimeyTedhlet Revlew Branch RadatIon sutveys RG 1.68. App A 100% o RTP shielding adequacy nd IdentIfy 10 CFR Part 20 IEH8 Sbb hIghradition zones Venolaton systems RO I K8.AP A 100% of RTP mnilnlan service ewes WhIn desbgn Imts SPt.B (Indud ngpitmaiy 4aend5ff contaInmet and tsnM MIne Acceptab~lly of reector RO 18 8, App A* Lowest pradical power level paraneters within design vahm EMEB ntemals. pmg% and l.a.1,1. 3. 1e and 5 o o component novermn vbrations, and epanslons DRAFT Rev. 0 - December 2002 14.2.1-15 . ATTACHMENT I

Transient Testin- Anilicable to Extended Power Uprates Transient Test Reference Typical Reactor Plant Initial Typical Transient Test Acceptance Cnteria and Applicable Accident Analyses Conditions Associated Functions Important to Safety (SRP Section)

Reetf valve testing RG 168. AppA Reactor power level at predetermined Reflef valve rating at a specified pressure setting 15.12 Inadvertent Opening of a 4p end51 power lve plateaus Steam Generator Relief or Delay time between the signal Initiating relief valve opening and Safety Valve Inspection Al relief valves set i auto the start of motion Procedure (IP) 156.1 Inadvertent Opening of a PWR 72510 Individual valve functional tests at Opening stroke time of Mhe main valve disc and distance Pressurizer Pressure Relief prescribed power vel plateaus Valve or a BWR Pressure Closing stroke tIme of the main valve piston following release of Relief Vale" indivdual valve capacity telsb at low power the pneumatically operated mechanical push rod (25% of RTP) using bypass valve movement or turbine generator output as a mneasurement variable Dynamic response of plant RG 1 68. App A 100% o RTP Performance Inaccordance with design to design bad swings 5.h h Reactor core Isolation IP 72512 Steady-state reactor operations at rated Startup fromhot standby conditions and discharge of rated fow cooling functional test temperature and pressure into the reactor vessel at rated pressure and temperature within a speclfed time RCIC alined for standby operation Verification of maxImum rated flow Isolation trip Reactor power at approximalety 25% of RTP Verification of overspeed trip Turbine gland seal condenser system shall prevent steam leak to atmosphere Dynamic response of plant RG 168, App A 100% of RTP Performance In accordance with design 15 3 1 (BWR) & 15 3 2 (PWR) to Imiing reactor coolant 511 pump tnips or closure of Trip from steady-state power operallon Instrumentation Isadjustedlo provide an accurate conversion of Loss of Forced Reactor teactor coolant system flow IP72512 individual let pump Ap values to a summed core flow over the Coolant Flow Includijn Trip of control valves Recording of transients following trip and rangs of topu operations Pump Motor during pump estart (Reactor coolant Reciculation pump instrumentation Iscalibrated recircutatlon pump trip est) Recording of limiting heat transfer parameters Loop fow from single-tap and double-tap pumps agrees within 3%

Return to two-pump operation Inaccord with facility operating procedures Core flow from single-tap and double-ap pumps agrees within 2%

Trip of a single pump and of both pumps simultaneously. Individual Jet pump flow variation from average pump. flow Is limited Dynamic response of the RG 1.65. App A 90% of RTP performance Inaccordance with design 15.1.1 Decrease InFeedwater plant to loss of feedwater 5kk Temperature heaters that results In most severe feedwater temperature reduction -

DRAFT Rev. 0 - December 2002 14.2.1-16 ATTACHMENT 2

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Transient Test Reference Typical Reactor Plant Initial Typical Translent Test Acceptance Critera and Applicable Accident Analyses Conditions Associated Functions Important to Safety (SRP Section)

Dynamic response of plant RO I e8, Appendlk plant perfomance In accordance with desIgn 152.7 Loss of Normal Feedweler to loss of eedweler flo A, SectIon 5 Flow (Introductlon)

Dynamo response of PlAn RO 1.U8, App A 100% of RRP vwh electIcel system a"iged Performance In acordance with design. Includinh 15.2.8 Loss of NonemergencAC for ful oad rejection 5 n for normal full-power operation and bad Powerto thaeStaton rejection method should subetd tine to Automalt transfer of plant loads as desgned, auoati start of Auxiliaries (Loss of Olme Power IP 72517 maftun eredbl overspeed condition dlesel generators. automatic lad of diesel generators In te Testig) speid sequence IP72582 stead s plant operations with gresbar than 10% generato output QIP72517 & Reactor pressure remains below the fstsafety valve setting 72582). Pressurier safety valves do not ti-trip of the plantwh breakers in specified Al safety yem such as RPSS HPCI. diesel generatos, and positions so that plant bads wm be RCIC function without manual assistance tferd direcyto he diesel generators los o house p po r Normal rctor cooling systems should mintaIn adequate core temperatures, and prevent acthtion of the Automatic recrchultn systern flw cont mode Depnessuttzetlon Syse howeer selected rellef valves may speciled function to control pressure Turbine bypass system operates to maintain specified pressure Value Steam system powerectulted pressue relIef vves open and cose at specified vaue Pressurifer spay valves open and close t spealied values.

Reactor coolant epr elationship remains rempeu within prescribed vaes Pressurizer level Ismaintained within prscribed limits Steam generator level remais within prescrbed limits DRAFT Rev. 0 - December 2002 14.2.1-17 ATTACHMENT 2

Transient Test Reference Typical Reactor Plant Initial Typical Transient Test Acceptance Cnteria and Applicable Accident Analyses Conditions Associated Functions Important to Safety (SRP Section)

Dynamic response of plant RG 168 App A tip from steady slate operation et greater Performance In accordance with design, Including 15 Z1 Turbine Trip to turbine tnp 511 than °5% of RTP reactor coolant pumps do not trop (Turbine trip or generator IP72580 iitiation of the test by trip of the main trip) IP72514 generator output breaker pressurizer spray valve opens and closes at the speafied values recIrculatOn system flow control Mode must reactor pressure remains below the setpoint of the first safety be specified valves, pressurimer safety valves do not lif or weep pressurzer leve withtn prescibed limits steam system power actuated pressure relief valve opens and closes at specred values reactor coolant pressureflemperature relationship remains withn defined values steam generator level remains wdhin prescribed lmIMts no flooding of the steam Ines dunrig the transient no initiation of ECCS and MSIV IsolatIon during the transient turbine bypass system operates to mainain speafic prerssur (plants with 100% bypass capability sal1 remain at power without scram durIng the transIent) plants with selecrod-nsertion shall maintain power without scram from recirculatlon pump overspeed or cold feedwater effect reactor protection system fnci0ons should be verified alt safety and ECCS systems such as RPS. HPCI. diesel generators. and RCIC function without manul assistance d called upon normal reactor coolng systems should maintain adeqate cooling and prevent acuation of auomeatIc depressurization ystem even though relief vales may function to control plant electrical loads (transferred as designed) turbine overspeed criteria met Dynambl response of plant RG 168. App A Initial power level of 100% of RTP perforiance in accordance with design 15.2.4 Main Steam IsolatIon Valve to automatic osure of al 5 mm Closure (BWR) main steatn Isolabon valves acepane criteria Include MSIV closing time IP72510 DRAFT Rev. 0 - December 2002 14.2.1-18 ATTACHMENT 2

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2 TTlEANDsuBlLE . NUREG0800 NUREG-0800, Standard Review Plan 3 DATE REPORT PUBUSHED 142.1, Generic Guidelines For Extended Power Uprate Testing Programs MM oH I YE December 2002

4. FIN OR GRN NUMER S AHORS 61TYPE OFflEPORT Robert Pettis Kevin Coyne Paid Prescott 7.PERuOD COVERED p=LwwDxs)

• PERFORMING ORGANIZATION - NAME AND ADDRESS , pmvdewAu o% Mm ofiewpo U& adesc=s vauow.

Division of Inspection Program Management Office of Nuclear Reactor Regulation U.S. Nuclear Regulatory Commission Washington, DC 2055-0001 S.SP5ONSORING ORGANIZTION -NffME AND ADDRESS {YNFBC > Saasabtwtecazr. pmnde IMCm OvMfficrftV* US Ahr-1arR#uby~msv endWqgedd=ss Same as above tO. SuPPLEMENTARY NOTES 11.ABSTRACT :?OO .es awrn This Standard Review Plan (SRP) section provides general guidelines for reviewi ng proposed extended power uprate (EPU) testing programs. This review ensures that the proposed testing program adequa tely verifies that the plant can be operated safely at the proposed uprated power level.

12. KEY WORDSMDESCRIPTORS gt Ai e ormph scs aass stewsrs m catnpo") 13 AVABIU;Y STAEENT Extended Power Uptate, EPU, testing, test program, power ascension testing, tra nsient testing unimited 4r4 ._: - 14 SECIWYCLASSIFICA1ON.

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I-Docket No. 50-271 BVY 03-80 Atgcbmient 7 Vermont Yankee Nuclear Power Station Proposed Technical Specificaticm Change No. 263 Extended Power Upraft Justification for Exception to Ire Transient Testing

• . BVY 03-80 /Aachment 7/Page 1

• JUSTCATION FOR EXCEPTION TO LARGE TRANET TESTING

Background

Tle basis for the Constant Pressure Power Uprate (CPPU) request was prepared following the guidelines contained in the NRC approved. General Electric (GE Company Licensing Topical Report for Constant Pzessure Power Upsate (CLTR) Safety Analysis: NDC33004P-A Rev. 4, July 2003. Thc NRC staff did not accept GEs proposal for the generic eliminatio of large trnsieat testing (e., Main Steam IsolWi=n Valve (MS1V) closure and turbine generator load rejection) presented in NEDC-33004P Rev. 3. herefore, on a plant specific basis, Vermont Yankee Nuclear Power Station (VYPS) is taking exception to the large transient tests; MSIV closr and turbine generatr load rejection.

The CPPU methodology, maintaining a constant pressure, simplifies the analyses and plant changes required to achieve uprated conditions. Although no plants have implemented an Extended Power Uprate (EnJ) using the C(lM. thirteen plants have implemented EPus without increasing reactor pressure.

• Hatch Units I and 2 (105%to 113% of Original Licensed hermal Power (OLTP))

• Monticello (106% OLTP)

• Muehleberg (.e, KKM) (105% to 116%/ OLTP)

• Lebstadt (Le., KIL) (105% to 117% OLTP)

Duane Arnold (105% to 120%Xe OLTF)

• Brunswick Units I and 2 (IOSY to 1200% OLTP)

• Quad Cities Units I and 2 (100% to ll7% OLTP)

• Drsden Units 2 and 3 (1000%a to 117ye OLTP)

• Clinton (100% to 1203%)

Data collected from testing responses to unplanned transients for Hatch Units I and 2 and KKL plants has shown that plant response has consistently been within expected parameters.

EnteVr believes that additional MSIV closure and generato load rejecton test are nd

~r mese tests would not confirm any new or significant hspect of IW.j 9fiaK..

performance that is not routinely demonstrated by component level testing. Th is futher supported by industry experience which has demonstrated plant perfolrmance, as predicted; under EPU conditions. VYNPS has experienced generator load rejections from 100% current licensed thermal power (see VYNPS Licensee Event Reports (LER)91-005, 91-009, and 91-014). No significant anomalies were seen in the plant's response to these events. Fwther testing is not necessary to demonstrate safe opation of the plant at CPPU conditions. A Scram from high power level relt in an unnecessary and udeirable transient cycle on the pr r system. In addition, the risk posed by intentionally initiating a MSIV closue transient or a generator load rejection, although small, should not be incurred unnecessarily.

VYNPS Response to Unplanned TranslentsL VYNPS experienced an unplanned Genertor Load Rejection finm 100% power on 04M23)91.

The event included a loss of off site power. A reactor scram occurred as a result of a Genentortfurbine trip on generator load reject due to the receipt of a 345 KV breaker failure

BVY 03-80 /AttacInet 7/Page 2 signal. This was reported to the NRC in LER 91-009, dated 05M/91. No significant anomalies were seen in the plant's response to this event. VYNPS also cprienced the following unplamned generatorload rection eveots:

• Oa 3/13/91 with reactor power at. 100°h a reactor scram occurred as a result of turbine trip on generator load reject due to a 345KV Switchyard Tie Line Diff al Fault This event was reported to the NRC in LER 91-05, dated 4/1291.

• Oa 6/15191 during normal operation with reactor power at 100°% a reactor scram occurred due to a Turbine Control Valve Fast Closure On Genrtor Load ject resltng from a loss of the 345KV North Switchyard bus. -ibis event was reported to the NRC in LER 91-014, dated 7/15/91.

No significant anomalies were seen in the plaat's response to these events. Trnnsint c~tienoe.

at high powers and for a wide range of power levels at opexating 3WR plant as hown a close conrelation of the plant tnsient data to the predicated response.

Based on the similarity of plants, past transient testings past analyses, and the evaluatio of test resuits, the effects of the CPPU RIP level can be analytically determined on a plant specific basis. The transient analysis performed for the VYNPS 'CPPU demostrates that all safdy criteria are met and that this tpate does not cause uy previous non-limiting events to become limiting. No safety related systems were significantly modified for the CPU, bowever some instrument seoints wae changecL The instument sepints that were changed do not contribute to the response to large trAnsient events. No physical modificatio or setpoint changes were made to the SRVs. No new ystems or featres were installed for mitigatin of rpid pressmmritn anticipated operationil occrrences for this CPPU. A Scram fiom high power level ults in an unnecessary and undesirable transient cycle on the primary system. Ther, additonal trasient testing involvimg sra frx high power levhes is not justiable. should any firtre large t ients ocu, VYWS procedures require vesification that the actual plant response is in accordance with the predicted response. Existing plant event data rcoorders are capable of acqiing the necessary data to confirm the actual versus expected response.

Further, the ikqrt= nuclear characteristics required for transient analysis are confirmed by the steady state physics testing. Transient mitigation capability is demonstated by otlnr oqipment surveillance tests required by the Tedmical Specifications. hn addition, the lmtig tasient

- anaiyses are in~cln as pan oxtre rroad licensing analysis.

MSIV Closure Event Closure of all MSMVs is an Abnormal Operational Transint as described in Chapter 14 of the VYNPS Updated Final Safety Analysis Report (UFSAR). The transient produced by the fast closure (3.0 seconds) of aU main steam line isolation valves represents the most severe abnormal operational asient resulting in a nuclear system pressure rise when direct scrams am lgnoe&

The Code overpressure protection analysis assumes the failure of the direct isolation valve position sm The MS1V closure transient. assuming the backup flux scram verses the valve position scram, is more significant. This case has been rel ted for CGPU with accetable results.

The CLTR states that: 'The same performance titeia will be used as in the original power ascension tests, unless fty have been replaced by updated criteria since the initial test program.

• . The original MSIV closure test allowed the scram to be initiated by the MSIV position switches.

BVY 03-80 / Attachment 7/Page 3 As such, if the orgial MSIV closure test were reiperformed, the results would be much less significant than the MSIV dosure analyis performed by GE br CPPU.

The original MSW closure test was intended to demonshate the following:

1. Detenninereactor transientbehavior duing andfollowingsimzdtaneousfsdl dsure of allMei~~.

itwria:

a) Reactorprssureshagbe maintainedbelow 1230psi&

b) Mamm reacorpressureshouddbe 35psi below theJilrtsafet valve setpoint (ThLs s mazinforsafet valve weeing).

2. Fwcimaly check theMSIVsforproperoperationanddete uneM Vclare tme a) ClMge me between 3 and5secofds.

Item 1: Reactor Tranient Behavior For this event, the closure of the MSIVs cause a vessel pressure increase and an increase in reactivity. The negive reacivity of the scram from MSIV postion switches should offset the positive m iity of the pressure increase slch that there is a minimal increase in hea fhLu fore, the thenmal performance dung the proposed MSIVclosure test is much less limiting than any of the transients routinely reevaluated C:PU will have minimal impact on the components important to achieving the desired thral perfaanance.Peactor Protection ystcau (RPS) logic is unffeted and with no steam dome pressure increase, oval contol rod insertxcm times will not be significantly affected. MSV closure speed is controlled by adjustments to the actuato and is considered voy reliable as indicated below.

Reactor Pressure Dae to the minimal mature of the flux btensient, the cpected reactor press ise, Item I above, is largely dependent an SRV setpoint perfrmance. At VYNPS all four Skys are rplaced with

- - tsfiiztedd cach va oimage Afem me outage, tM removed valves are sent out for testing d recahlon for instllatin in the following outage. Over the past ten years there have been twenty five SRV tests perfored in those twenty five tests buly one test found the as-found setting outside the Technical Specification (TS) curnt allowable tolemance of *3%. This valve was found to deviate by 3A% of its nomina lift setpoint. Note that this is bounded by the VYNPS design analysis for peak vessel pressure which assumes one of the four SRVs does not open at aul (one SRV out of service). Given the historical perf ac of the VYNPS SRVs along with the design inargins perfonmance of an actual MSIV closure test would provide little benefit for demonstrating vessel ovopressure protection that is not already accomplished by the component level testing t&at Is otily perfarmed, in accordance with the VYNPS TSs Because rated ves steam dome pressure is not being increased and SRV setpoints are no being c there is no increase in the probability of leakage after a SRV lifL Since SRV leakage per e is considered accetable at the curt conditions, which match CPPU conditions with respect to steam dome pressure and SRV setpoints, SRV leakage perfma should continue to be acceptable at CPPU conditions. An MSIV closure test would provide no

BVY 03-80 / Attacment 7 / Page 4 significant additional confirmation of kmr1 performance criteria than the routine component testingpeformed every cycle, in accordance wi the VYNPS TS&

Item 2: MSIV Closure Tnme Since steam flow assist MSIV closure, the fous of kern 2 was to vegrifr that the steam flow from the rea was not shut off faster than assumed (ie, 3 seconds). Daring maintenance and survIlance, MSV actuators are evaluated and adjusted as necessary to control closure speed, and VYNPS test performne has been good. To account for minor variations In stroke times, the caliratiaon test procedure for MSIV closure (OP 5303) requires an as left fast closure time of 4.0 402 seconds. The MSMV were evaluated for CPPU. The evaluation included MSTV

• losure time and deternined that the MSI ar acceptable for CPPU operati. n y expe-ience, including VYNPS, has shown that there are no significant gncric prcrmns with actuator design. Confiden is very high that steam line closure would aot be less than assumed by the anaysis.

Other Plant Systems and Components Response The MSIV limit switches that provide the scram signal are highly reliable devices that arm suitable for all aspects of this application including environmental requirements. There is no udiect effect by any (WU changes on these switcibes. There may be an indirect impact caused by sligty bigher ambient temperatures, but. the mcreased tenpde res will still be below the qualification temperature. These switches are pected to be equaly reliable before and after CPPU.

The Reactor Protection System (RPS) and Control Rod Drive (CRD) components that convert the scram signals into CRD motion are not directly affected by any CPPU cianges. Minor changes in pressure drops across vessel components may result m very diht changes in control blade insertin rates. These changes have been evaluated and determined to be insignificant. The ability to meet the scram performance requirement is not affected by CPPU. Technical Specificatien CM requirements for these con =ents will continue to be met CPPU Medifications Feedwater System operation will require operation of all three feed pumWs at CPPUJconditions (unlilm CLIP conditions). Operation of the additional Reactor Feed Pump (RFP) will not affect plant response to an MSIV closure transent. A feedwater pumps recsive a trip signal prior to level reaching 177 inches. Overfill of the vessel after a trip would only occur if level ceeded a mately 235. inches Since the feedwater pumps, the High Ptessare Coolant Injection (HPCI) turbine, and the RCIC turbine all receive trip signals prior to level reachin 177 inches, a substantial ma exists. VYNPS operating history has demonstrated that this margin greatly exceeds vessel level overshoot during transient events. Based on this, there is adeqate confidnce that the vessel level will remain well below the main steam lines unde CPFU conditions. he HPCI and RCIC pump trip functions are rouinely verified as required by TSs and are considered very reliable.'

The modification adding a recirclation pump runback following a RFP trip will not affect the plant response to this tnent. The reactor scram signal from the MSNV limit switches will result in control rod insertion prior to any manmal or automntic operation of the FPs. Since

BVY03-80 /I/ttachment7/PgS control rods will alrea be inserted, a subsequent runback of the recirulation pumps will not affect the plant response.

The modification (BVY 03-23 "ARTSMEIILA") to add an additional uwppd Spring Safety Valve (SSV) will not affect the plant response to this transient. The new third SSV will have the same lift sdtpint as the two edsting SSVs. This transict does not result in an opening of a SSV, nor is credit taken for SSV actuation.

Generator Load Reject Testing

'x ator Load Rejection From High Power W out Bypass (GLRWB) is an Abnormal Operational 1hisient as described miCapter 14 of the VYNPS Updated Final Safety Analysis Report (UFSAR). Ihis transient competes with the tu:bie trip witlout bypass as the most limiting ovegressurization tansient that challenges temal limits for each cycle. The GLRWB analysis assumes that the tiansift is midated by a rapid closure of the turbine'conrol aves. It also assumes that all bypass valves fail to open.

The CLTR states.tbat: "he same performance criteria will be used as in thc oiginal power asce oion tests, unless they have been replaced by updated criteria smce the iniial test program" The startup test for generator load reect allowed the select rod Insert feature to reduce the reactor power level and, in counction with bypass valve opning control the transiet sudh that the reactor does not sBam. Current VYNS. design does not incde the select rod insmt featur.

Ibe plant was also modified to include a scram firm the acceleration relay of the turbine control system Under current plant design the original generator load reect test can not be re-perf If a generator load reect with bypass test *ere performed, the results would be much less significant tn the generator load reject.without bypass closurc analysis perfoned by GE for CPPU.

The original generator load roect test was intended to demonstrate the following

1. Detennine and demt-ate reactor response to a generator t1p, with particular attention to the rates of changes andpeak values ofpower 1ev4 reactorsteam presswre and tubine speed

a. All testpresre transients mu have maxwm pressurevalies elow 1230 pg

b. Mxamun reactorpressre should be 35 psi beow the fiast safet Vwlve seapoint (Tis is marginfor sqlety valve weepn).

c The select rod insertfeahireshall operate and In conjunction with proper bypass valve opening, shall control the transientsuch that the reactor does not scram Due to plant modification discussed above, Crterion c. above would no longer be applicable for a generator load reect test. The generator load reject startup test was perfoe at 93.7% power, however, a reactor scram occurred during testing and invalidated the test A design change to initiate an immediate scram on generator load rject was implemented and this startup test was subseupently cancelled since it was no longe applicable.

BVY 03480. Attachment 7/Page 6 Item 1 Reictor Response For a generator load rlect with bypass event, gv curent plant design, the fast closure of the Turbine Control Valves (Vs) cause a tdp of the acceleration reay in the turbine control syste.nL Te acceleration relay trip initiates a full reactor scram The bypass valves oe, however sinc: the capacity of the bypass vaves at CPPU is 87?%, vessel pressure ixreasm Ths results in an incrase in retvity. The negative reactivity of the TCV fast closure scram from, the acceleration relay should offiet the positive reativity of the pressure Increase such ftfa there is a minimal crease in heat flkm Thercfore, the themal perfom3ance daoing a genertor load rejection test would be much less limiting than any of the transient routinely re-eval CPpU will have minimai impact on the components important to achieving the desired thnmal permac Reactor Protection system (MPS) logic is unaffected and nih no steam dome pressure increase, overall control rod inserdon times will not be significantly affected. A trip cannd and alarm functional test of the turbine contrl valve fast closure scramnis pefomed, every three months in accordane with plant technical specifications. This trip fnction. is conide vedry reliable.

Reactor Pressure Due to the minima nature of the fux transient, the exPected reacto pressure rise, Criteria a. and

b. above, are largely depedlet on SRV setpoint palforance Refer to the MSIV closure Reactor Pressure section above for discussion of SRV setpot perfoxmance.

Because rated vessel steam dome pressure is not being increased and SRV seipxns are not being changed, there is no increase in the probability of leakage afler a SRV lift Since SRV leakage pr e is considered acceptable at the cunt conditions, which match -PU conditions with respect to steam dome pressure and SRV setpoints, SRV leakage pefonnace will continu to be accptable at CPPU conditions. A g ator load rejection test would Pvidno significnt additona confimation of performance criteria a. and b. than the routine component testing performed every cycle, in accordance with the VYNPS s.

Other Plant Systems and Components Response I turbine control sstem acceleration relay hydraulic fluid 're switches tbat scram signal we mgmy rel ab1c devices that are suitable for all aspects of this kppliction g environmental reqirmts.- There is no direct effect by any CPPU chang;e on these pressure switches. These swivtches are expected to be equaLy reliable before and after CPPU.

Ten Reactor Protection Syste (RPS) and Control Rod Drive (CRD) compone1s that convert the scram signals mto CRD motion are not directly affected by any C{PU changes. Minor changes in pressure drops across vessel components may result in very Sliht changes in control blade insertion rates. These changes have been evaluated and determined to be insignificant Ihe ability to meet the scram perfommance reqqiremet is not affected by CPPU. TS requirements for these components will continue to be met CPPU Modifications As previously described, Feedwater System operation will require all three feed pumps at CPPU conditions, Operation of the additional Reactor Feed Pump (RFP) will not affect plant resonse to this trasient All feedwat pumps receive a tip signal prior to level readhing 177 inches.

BVY 03-80/ Attachment 7 / Page 7 Ove:i of the vessel after a trip would oly occu if level exceeded appxim 235,5 inch Since the feedwa pmps, the ih Presivre Coolant Injection C) turbine, and the RCIC tUrbine all receive trip signals prior to level reaching 171 inches, a substantial margin eists.

VYNPS oerzth* histmy has demonstrated that this mrgi greatly exceeds vessel level overshoot during transient events. Based on this, there is adequate confiden that-the vessel level will remai well below the ma stem lines under CPPU conditions. The PCI and RCIC pump trip functions are rotiy verified as reuird by TSs and are considered very relible.

The modification adding a reciruation pump rmback following a RFP trip will not affict the plant response to this transient. The reator sCram Sigl fiom tUbie control Naive fast closure will reult in control blade insertion prior to any Tmaual or automatic operton of the UPS.

Since control blades will alrdy be inserted, a subsequent nback of the recirculation pmps will not affect the plant response.

The modification (BVY 03-23) "ARTS&MELA') to add an additional unpiped SSV will not affect the plant respos to this tansient. he new third SSV will have the same lift saepoit of the two ecisting SSVs. This tasilent does not result in an opening of a SSV mnr is credit take for SSV actuation.

HP Turbine modification replaces the steam flow path but will not affect the turbine control system hydraulic prssure switches that prvide the turbine control valv fast closure saam signSl to tfie RPS system.

Industry Boiling Water Reactor (BWR) Power Uprate Experience Southern Nuclear OPeratinS Company's (SNOC) application for EPU of BHtch Units 1 and 2 was

- gated without requirements to perfom larI transient testing. VYNPS and atch are both BWR/4 with Mark I 1ontainment Although Hiatch was not requred to perform large transent testn Hatch Unit 2 eperieced an unplanned event that rsulted in a generator load rejct from 98% of uprated powerin the summer of 1999. As noted in SNOC's LER 1999-005, no s were seen in the plant's resp c to this event In addtion, Hatch Unit 1 has experienced one tubeie trip and one geneto load rject event subsequent to its prate (ie.. LERs 2000-004 jd 2001-002). Again, the behavior of the primary safety systems was as expeted. No new plant

-ehavliai5 ic obsirvi dl wuld indicaw 1iar whe analyrcal moes eg used arenot capable of modeling plant bebavior at EPJ conditions.

Te KKL power UPate imrplem opgram was perfarmed during the period from 1995 to 2000. Power was raised in steps fiom its previous operating power level of 3138 MWt (L.,

104.20% of OLTP) to 3515 MWt (ie, 116.7% OLTF). Uprate testing was performed at 3327 MWt (i.e., 110.5% OLTP) in 1998, 3420 MWt (i.e., 113.5% OLIP) in 1999 and 3515 MWt in 2000.

KKtesting formaortransients involved trbinetrips at 110.5% OLTP and 113.5% OLTP and a geerato load rejection test at 104.2% OLT. The KKL turbine and geetor trip testing de ed the performance of equipmen that was modified in pF aation for the higher power lvels. Equipment that was not modified performed as befor Th reactor vessel pressur was controlled at the same opeting point for all of the vprated power conditions. No mnepected performance was observed except in the fine-tuting of the turbine bypass opening that was done as the series of tests progressed. These large trnmsient tests at KKL demonstated the response of the equipment and the reactor response. The close matches observed with

.BVY 03-S /Attacbment/Page8 predicted response provide additional confidence that the prate licensing analyses consistently reflected the behavior of the plant.

Plant Modeling. Data Collection and Anases From the power upate exprience discussed above, it can be concluded tat lage transients, either planned or unplanne have not povided any ignificant nW ifmation about tranient modeling or actual plani response. Since the VYNPS uprate does not involve reactor pressure this exporience is considered applicable.

The safety analyses performed for VYNPS used the NRC-aroved ODYN ftansient modeling code. The NRC accepts this code for GE BWRs with a range ofpower levels andpower densities that bound the requested power uate for VYNPS. The ODYN code has been bencldrked against BWR test data and has icorxorated idastiy expnence gamed from iu tansiet modelg codes. ODYN uscs plant spepific inputs and modds all the essential phsical em ea for predicting integratd plant response to the analyed transients. Ihus, the ODYN code will acwaately an&or conseratively predict the integrated plant respone to these Use at CPFU power leves and no new information about transient modeling is expected to be gained fromperforraing these large transient tests.

CONCLUSION VYNPS believes that sufficient justification has been proided to demonstrate that an: MSIV transient test and a generator load rejection test is not necessry or pruden Also, the risk imposed by intentionally initiating large bansient testing should not be incutred unnecearly.

As suh, Enter does not plan to perform additional large transient testing fobowing the VYNPS CPPU.

. , I

.1 0

Docket No. 50-271 3VY 03-98 Attachment Vermont Yankee Nuclear Power Station Technical Specification Proposed Change No. 263 Supplement No. 3 Extended Power Uprate - Updated Information Justification for Exception to Large Transient Testing

BVY 03-98 / Attachment 7/ Page I 0 JUSTlFICATION FOR EXCEPTION TO LARGE TRANSIENT TESTING

Background

The basis for the Constant Pressure Power Uprate (CPPU) request was prepared following the guidelines contained in the NRC approved, General Electric (GE) Company Licensing Topical Report for Constant Pressure Power Uprate (CLTR) Safety Analysis: NEDC-33004P-A Rev. 4, July 2003. The NRC staff did not accept GEs proposal for the generic elimination of large transient testing (i0e, Main Steam Isolation Valve (MSIV) closure and turbine generator load rejection) presented in NEDC-33004P Rev. 3. Therefore, on a plant specific basis, Vermont Yankee Nuclear Power Station (VYNPS) is taking exception to performing the large transient tests; MSIV closure, turbine trip, and generator load rejection.

The CPPU methodology, maintaining a constant pressure, simplifies the analyses and plant changes required to achieve uprated conditions. Although no plants have implemented an

- Extended Power Uprate (EPU) using the CLTR, thirteen plants have implemented EPUs without increasing reactor pressure.

• HatchUnits I and2(105%to 113% ofOriginalLicensedThermalPower(OLTP))

• Monticello (106% OLTP)

• Muehleberg (i.e., KKM) (105% to 116% QLTP)

• Leibstadt (i.e., KKL) (105% to 117% OLTP)

• Duane Arnold (105% to 120% OLTP)

• BrunswickUnits I and 2 (l05% to 120% OLTP)

• Quad Cities Units 1 and 2 (I100% to'117% OLTP)

• Dresden Units 2 and 3 (100%.to 117% OLTP)

• Clinton (100% to 120%/)

Data collected from testing responses to unplanned transients for Hatch. Units I and 2 and KKL plants has shown that plant response has consistently been within expected parameters.

Entergy believes that additional MSIV closure, turbine trip, and generator load rejection tests are not necessary. If performed, these tests would not confirm any new or significant aspect of performnnce that is not routinely demonstrated by component level testing. This is further supported by industry experience which has demonstrated plant performance, as predicted, under EPU conditions. VYNPS has experienced generator load rejections from 100% current licensed thermal power (see VYNPS Licensee Event Reports (LER)91-005, 91-009, and 91-014). No significant anomalies were seen in the plant's response to these events. Further testing is not necessary to demonstrate safe operation of the plant at CPPU conditions. A Scram fiom high power level results in an unnecessary and undesirable transient cycle on the primary system. In addition, the risk posed by intentionally initiating a MSIV closure transient, a turbine trip, or a generator load rejection, although small, should not be ncurred unnecessarily.

VYNPS Response to Unplahned Transients:

VYNPS experienced an unplanned Generator Load Rejection from 100% power on 04/23/91.

The event included a loss of off site power. A reactor scram occurred as a result of a turbinelgenerator trip on generator load rejection due to the receipt of a 345 KV breaker failure signal. This was reported to the NRC in LER 91-009, dated 05/23/91. No significant anomalies

BVY 03-98 / Attachment 71 Page 2 were seen in the plant's response to this event. VYNPS also experienced the following unplanned generator load rejection events:

• On 3/13/91 with reactor power at 100%/a a reactor scram occurred as a result of turbine/generator trip on generator load rejection due to a 345KV Switchyard Tie Line Differential Faults This event was reported to the NRC in LER 91-005, dated 4112/91.

• On 6/15/91 during normal operation with reactor power at 100%/6 a reactor scram occurred due to a Turbine Control Valve Fast Closure on Generator Load Rejection resulting from a loss of the 345KV North Switchyard bus. This event was reported to the NRC in LER 91-014, dated 7/15/91.

No significant'anomalies were seen in the plant's response to these events. Transient experience at high powers and for a wide range of power levelsat operating BWR plants has shown a close correlation of the plant transient data to the predicated response.

Based on the similarity of plants, past transient testing, past analyses, and the evaluation of test results, the effects of the CPPU RTP level can be analytically determined on a plant specific basis. The transient analysis performed for the VYNPS CPPU demonstrates that all safety criteria are met and that this uprate does not cause any previous non-limiting events to become limiting. No safety related systems were significantly modified for the CPPU, however some instrument setpoints were changed. The instrument setpoints that were changed do not contribute to the response to large transient events. No physical modification or setpoint changes were made to the SRVs. No new systems or features were installed for mitigation of rapid pressurization anticipated operational occurrences for this CPPU. A Scram from high power level results in an unnecessary and undesirable transient cycle on the primary system. Therefore, additional transient testing involving scram from high power levels is not justifiable. Should any -future large transients occur, VYNPS procedures require verification that the actual plant response is in accordance with the predicted response. Existing plant event data recorders are capable of acquiring the necessary data to confirm the actual versus expected response.

Further, the important nuclear characteristics required for transient analysis are confirmed by the steady state physics testing. Transient mitigation capability is demonstrated by other equipment surveillance tests required by the Technical Specifications. In addition, the limiting transient analyses are included as part of the reload licensing analysis.

-MSIV C~luz e Event Closure of all MSIVs is an Abnormal Operational Transient as described in Chapter 14 of the VYNPS Updated Final Safety Analysis Report (UFSAR). The transient produced by the fast closure (3.0 seconds) of all main steam line isolation valves represents5the most severe. abnormal operational transient resulting in a nuclear system pressure rise when direct scrams are ignored.

The Code overpressure protection analysis assumes the failure of the direct isolation valve position scram. The MSIV closure transient, assuming the backup flux scram verses the valve position scram, is more significant. This case has -been re-evaluated for CPPU with acceptable results.

The CLTR states that: 'Me same performauce criteria will be used as in the original power ascension tests, unless they have been replaced by updated criteria since the initial test program."

The original MSIV closure test allowed the scram to be initiated by the MSIV position switches.

As such, if the original MSIV closure test were re-performed, the results would be much less 0 significant than the MSIV closure analysis performed by GE for CPPU.

BVY03-98 Attachment 7/Page 3 The original MSIV closure test was intended to demonstrate the following:

1. Determine reactor transientbehavior during andfollowing simzdtaneousfuzl closure of allMSeIVs.

Criteria:

a) Reactorpressureshall be maintainedbelow'1230psig.

b) Maximum reactorpressure should,be 35 psi below the first safety valve setpoint.

(This is marginforsafety valve weeping).

2. Functionallycheck the MS Vis for properoperationand determine ASJVclosure time.

Criteria:

a) Closure time between 3 and S seconds.

Item 1: Reactor Transient Behavior For this event, the closure of the MSIVs cause a vessel pressure increase and an increase in reactivity. The negative reactivity of the scram from MSIV position switches should offset the positive reactivity of the pressure increase such that there is a minimal increase in heat flux.

Therefore, the thermal performance during the proposed MS1V closure test is much less limiting than any of the transients routinely re-evaluated. CPPU will have minimal impact on the components important to achieving the desired thermal performance. Reactor Protection system (RPS) logic is unaffected and with no steam dome pressure increase, overall control rod insertion times will not be significantly affected. MS1V closure speed is controlled by adjustments to the-actuator and is considered very reliable as indicated below.

Reactor Pressure Due to the minimal nature of the flux transient, the expected reactor pressure rise, Item 1 above, is largely dependent on SRV setpoint performance. At VYNPS all four SRVs are replaced with re-furbished and pre-tested valves each outage. After the outage, the removed valves are sent out for testing and recalibration for intallation in the following-outage. Over the past ten years there have been twenty five SRV tests performed. In those twenty five tests only one test found the as-found setting outsidre IM echnicaI Specificaion (TS) current allowable tolerance of 23%. This valve was found to deviate by 3.4% of its nominal lifi setpoint Note that this is bounded by the VYNPS design analysis for peak vessel pressure which assumes one of the four SRVs does not open at all (one SRV out of service). Given the historical performance of the VYNPS SRVs along with the design margins, performance of an actual MS1V closure test would provide little benefit for demonstrating vessel overpressure protection that is not already accomplished by the component level testing that is routinely performed, in accordance with the VYNPS TSs.

Because rated vessel steam dome pressure is not beingincreased and SRV setpoints are not being changed, there is no increase in the probability of leakage after a SRV lift Since SRV leakage performance is considered acceptable at the current conditions, which match CPPU conditions with respect to steam dome pressure and SRV setpoints, SRV leakage performance should continue to be acceptable at CPPU conditions. An MSIV closure test would provide no significant additional confirmation of Item 1 performance criteria than the routine component testing performed every cycle, in accordance with the VYNPS TSs.

BVY 03-98 / Attachment 7/Page 4 Item 2: MSIV Closure Time Since steam flow assists MSTV closure, the focus of Item 2 was to verify that the steam flow from the reactor was not shut off faster than assumed (i.e., 3 seconds). During maintenance and surveillance, MSIV actuators are evaluated and adjusted as necessary to control closure speed, and VYNPS test performance has been good. To account for minor variations in stroke times, the calibration test procedure for MSIV closure (OP 5303) requires an as left fast closure time of 4.0 +/-0.2 seconds. The MSIVs were evaluated for CPPU. The evaluation included MSIV closure time and determined that the MSIVs are acceptable for CPPU operation. Industry experience, including VYNPS, has shown that there are no significant generic problems with actuator design. Confidence is very high that steam line closure would not be less than assumed by the analysis.

Other Plant Systems and Compoinents Response The MSIV limit switches that provide the scram signal are highly reliable devices that are suitable for all aspects of this application including environmental requirements. There is no direct effect by any CPPU changes on these switches. There may be an indirect impact caused by slightly higher ambient temperatures, but the increased temperatures will still be below the qualification temperature. These switches are expected to be equally reliable before and after CPPU.

The Reactor Protection System (RPS) and Control Rod Drive (CRD) components that convert the scram signals into CRD motion are not directly affected by any CPPU changes. Minor changes in pressure drops across vessel components may result in very slight changes in control blade insertion rates. These changes have been evaluated and determined to be insignificant. The ability to meet the scram performance requirement is not affected by CPPU. Technical Specification (rS) requirements for these components will continue to be met.

CPPU Modifications Feedwater System operation will require operation of all three feed pumps at CPPU conditions (unlike CLTP conditions). Operation of the additional Reactor Feed Pump (RFP) will not affect plant responF au MSV'-I closuel transi=-_ewte-p -receive-a-bip-signalaporierto level reaching 177 inches. Overfill of the vessel after a.trip would only occur if level exceeded approximately 235.5 inches. Since the feedwater pumps, the High Pressure Coolant Injection (HPCI) turbine, and the Reactor Core Isolation Cooling (RCIC) turbine all receive trip signals prior to level reaching 177 inches, a substantial margin exists. VYNPS operating history has demonstrated that this margin greatly exceeds vessel level overshoot during transient events.

Based on this, there is adequate confidence that the vessel level will remain well below the main steam lines under CPPU conditions. The HPCI and RCIC pump trip functions are routinely verified as required by TSs and are considered very reliable.

The modification adding a recirculation pump runback following a RFP trip will not affect the plant response to this transient The reactor scram signal from the MSIV limit switches will result in control rod insertion prior to any manual or automatic operation of the RFPs. Since control rods will already be inserted, a subsequent runback of the recirculation pumps will not affect the plant response.

BVY 03-98 / Attachment 7 / Page S

_ The modification (BVY 03-23 "ARTS/MELLLA") to add an additional unpiped Spring Safety Valve (SSV) will not affect the plant response to this transient. The new third SSV will have the same lift setpoint as the two existing SSVs. This transient does not result in an opening of a SSV,.

nor is credit taken for SSV actuation.

Generator Load Reject and Turbine Trip Testing "Generator Load Rejection From High Power Without Bypass" (GLRWB) is an Abnormal Operational Transient as described in Chapter 14 of the VYNPS Updated Final Safety Analysis Report (UFSAR). This transient competes with the turbine trip without bypass as the most limiting overpressurization transient that challenges thermal limits for each cycle. The turbine trip and generator load reject are essentially interchangeable. The only differences are l) whether the RPS signal originates from the acceleration relay (GLRWB) or from the main turbine stop valves (turbine trip), and 2) whether the control valves close shutting off steam to the turbine or the stop valves close to isolate steam to the turbine. Both tests would verify the same analytical model for plant response. Therefore, the GLRWB is considered bounding or equivalent to the Turbine Trip.

The GLRWB analysis assumes that the transient is initiated by a rapid closure of the turbine control valves. It also assumes that all bypass valves fail to open. The CLTR states that: -he same performance criteria will be used as in the original power ascension tests, unless they have been replaced by updated criteria since the initial test program." The startup test for generator load reject allowed the select rod insert feature to reduce the reactor power level and, in conjunction with bypass valve opening, control the transient such that the reactor does not scram.

Current VYNPS design does not include the select rod insert feature. The plant was also modified to include a scram from the acceleration relay of the turbine control system. Under cunent plant design, the original generator load reject test can not be re-performed. If a generator load reject with bypass test were performed, the results would be much less significant than the generator load reject without bypass closure analysis performed for CPPU.

The original generator load reject test was intended to demonstrate the following:

1. Determine and demonstrate reactor response to a generator trip, with particular attention to the rates of changes and peak values ofpower level reactorsteam pressure and turbinespeed Criteria:

a. All rest pressure transients must have maximum pressure values below 1230 psig

b. Maximum reactor pressure should be 35 psi below the first safety valve setpoint. (ars is marginfor safety valve weeping).

c. The select rod insertfeature shall operate and in conjunction with proper bypass valve opening, shall control the transientsuch that the reactor does not scram Due to plant modification discussed above, criterion c. above, would no longer be applicable for a generator load reject test The generator load reject startup test was performed at 93.7% power, however, a reactor scram occurred during testing and invalidated the test. A design change to initiate an immediate scram on generator load reject was implemented and this startup test was subsequently cancelled since it was no longer applicable.

BVY 03-98 / Attachment 7 / Page 6 Item I Reactor Response.

For a generator load reject with bypass event, given current plant design, the fast closure of the Turbine Control Valves (TCVs) cause a trip of the acceleration relay in the turbine control system. The acceleration relay trip initiates a full reactor scram. The bypass valves open, however, since the capacity of the bypass valves at CPPU is 87%, vessel pressure increases. This results in an increase in reactivity. The negative reactivity of the TCV fast closure scram from the acceleration relay should offset the positive reactivity of the pressure increase such that there is a minimal increase in heat flux. Therefore, the thermal performance during a generator load rejection test would be much less limiting than any of the transients routinely re-evaluated.

CPPU will have minimal impact on the components important to achieving the desired thermal performance. Reactor Protection system (RPS) logic is unaffected and with no steam dome pressure increase, overall control rod insertion times will not be significantly affected. A trip channel and alarm functional test of the turbine control valve fast closure scram is performed every three months in accordance with plant technical specifications. This trip function is considered very reliable.

Reactor Pressure Due to the minimal nature of the flux transient, the expected reactor pressure rise, Criteria a. and

b. above, are largely dependent on SRV setpoint performance. Refer to the MS1V closure Reactor Pressure section above for discussion of SRV setpoint performance.

Because rated vessel steam dome pressure is not being increased and SRV setpoints are not being changed, there is no increase in the probability of leakage after a SRV lift Since SRV leakage performance is considered acceptable at the current conditions, which match CPPU conditions with respect to steam dome pressure and SRV setpoints, SRV leakage performance will continue to be acceptable at CPPU conditions. A generator load rejection test would provide no significant additional confirmation of performance criteria a.. and b. than the routine component testing performed every cycle, in accordance with the VYNPS TSs.

Other Plant Systems and Components Response The turbine control system acceleration relay hydraulic fluid pressure switches that provide the scram signal are highly reliable devices that are suitable lor all aspects of tmis application including environmental requirements. There is no direct effect by any CPPU changes on these pressure switches. These switches are expected to be equally reliable before and after CPPU.

The Reactor Protection System (RPS) and Control Rod Drive (CRD) cdmponents that convert the scram signals into CRD motion are not directly affected by any CPPU changes. Minor changes in pressure drops across vessel components may result in very slight changes in control blade insertion rates. These changes have been evaluated and determined to be insignificant The ability to meet the scram performance requirement is not affected by CPPUL TS requirements for these components will continue to be met.

BVY 03-98 / Attachment 7 / Page 7 CPPU Modifications As previously described, Feedwater System operation will require all three feed pumps at CPPU conditions. Operation of the additional Reactor Feed Pump PUP) will not affect plant response to this transient All feedwater pumps receive a trip signal prior to level reaching 177 inches.

Overfill of the vessel after a trip would only occur if level exceeded approximately 235.5 inches.

Since the feedwater pumps, the High Pressure Coolant Injection (HPCI) turbine, and the RCIC turbine all receive trip signals prior to level reaching 177 inches, a substantial margin exists.

VYNPS operating history has demonstrated that this margin greatly exceeds vessel level overshoot during transient events. Based on this, there is adequate confidence that the vessel level will remain well below the main steam lines under CPPU conditions. The HFCI and RCIC pump trip functions are routinely verified as required by TSs and are considered very reliable.

The modification adding a recirculation pump runback following a RFP trip will not affect the plant response to this transient. The reactor scram signal from turbine control valve fast closure will result in control blade insertion prior to any manual or automatic operation of the RFPs.

Since control blades will almrad be inserted, a subsequent runback of the recirculation pumps will not affect the plant response.

The ARTS/MMELLLA modification (BVY 03-23) to add an additional unpiped SSV will not affect the plant response to this transient. The new third SSV will have the same lift setpoint of the two existing SSVs. This transient does not result in an opening of a SSV nor is credit taken for SSV actuation.

HP Turbine modification replaces the steam flow path but will not affect the turbine control system hydraulic pressure switches that provide the turbine control valve fast closure scram signal to the RPS system.

Industry Boiling Water Reactor (BWR) Power Uprate Experience Southern Nuclear Operating Company's (SNC) application for. EPU of Hatch Units I and 2 was granted without requirements to perform large transient testing. VYNPS and Hatch are both BWR/4 with Mark I containments. Although Hatch was not required to perform large transient testing, Hatch Unit 2 experienced an unplanned event that resulted in a generator load reject from 98%of 0uprateW power in the summer uf-1999. Ax noted in SNOC s LER l999-005, ino uie-were seen in the plant's response to this event In addition, Hatch Unit I has experienced one turbine trip and one generator load reject event subsequent to its uprate (i.e., LERs 2000-004 and 2001-002). Again, the behavior of the primary safety systems was as expected. No new plant behaviors were observed that would indicate that the analytical models being used are not capable

• ofmodeling plant behavior at EPU conditions.

The KKL power uprate implementation program was performed during the period from 1995 to 2000. Power was raised in steps from its previous operating power level of 3138 MWt (i.Le, 104.2% of OLTP) to 3515 MWt (i.e., 116.7% OLTP). Uprate testing was performed at 3327 MWt (i.e., 110.5% OLTP) in 1998, 3420 MWt (i.e., 113.5% OLTP) in 1999 and 3515 MWt in 2000.

KKL testing for major transients involved turbine trips at 110.5% OLTP and 113.5% OLTP and a generator load rejection test at 104.2% OLTP. The KKL turbine and generator trip testing

BVY 03-98 / Attachment 7 /Page 8 demonstrated the performance of equipment that was modified in preparation for the higher power levels. Equipment that was not modified performed as before. The reactor vessel pressure was controlled at the same operating point for all of the uprated power conditions. No unexpected performance was observed except in the fine-tuning of the turbine bypass opening that was done as the series of tests progressed. These large transient tests at KKL demonstrated the response of the equipment and the reactor response. The close matches observed with predicted response provide additional confidence that the uprate licensing analyses consistently reflected the behavior of the plant.

Plant Modelin-. Data Collection and Analyses From the power uprate experience discussed above, it can be concluded that large transients, either planned or unplanned, have not provided any significant new information about transient modeling or actual plant response. Since the VYNPS uprate does not involve reactor pressure changes, this experience is considered applicable.

The safety analyses performed for VYNPS used the NRC-approved ODYN transient modeling code. The NRC accepts this code for GE BWRs with a range of power levels and power densities that bound the requested power uprate for VYNPS. The ODYN code has been benchmarked against BWR test data and has incorporated industry experience gained from previous transient modeling codes. ODYN uses plant specific inputs and models all the essential physical phenomena for predicting integrated plant response to the analyzed transients. Thus, the ODYN code will accurately and/or conservatively predict the integrated plant response to these transients at CPPU power levels and no new information about transient modeling is expected to be gained from performing these large transient tests.

CONCLUSION VYNPS believes that sufficient justification has been provided to demonstrate that an MSIV closure test, turbine trip test, and generator load rejection test is not necessary or prudent. Also, the risk imposed by intentionally initiating large transient testing should not be incurred unnecessarily. As such, Entergy does not plan to perform additional large transient testing following the VYNPS CPPU.

W 7

-I'o, UNITED STATES p NUCLEAR REGULATORY COMMISSION WASHINGTON, D.C. 205554001 SAFETY EVALUATION BY THE OFFICE OF NUCLEAR REACTOR REGULATION RELATED TO AMENDMENT NO. 229 TO FACILITY OPERATING LICENSE NO. DPR-28 ENTERGY NUCLEAR VERMONT YANKEE. LLC AND ENTERGY NUCLEAR OPERATIONS. INC.

VERMONT YANKEE NUCLEAR POWER STATION DOCKET NO. 50-271 Proprietary information pursuant to Title 10 of the Code of Federal Regulations Section 2.390 has been redacted from this document.

Redacted information is identified by blank space enclosed within double braces

M

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• Core spray and RHR pump seals were evaluated for possible replacement. As discussed in SE Section 2.2.4.2, the seals were requalified for EPU conditions and did not need to be replaced. Leak check testing to be performed at pump-rated conditions.

• Feedwater system pump modifications to include the addition of two sequential levels of low suction pressure trips at various time delays to ensure only one pump trips at a time.

Normal modification testing, with breakers in "test" position, to be performed.

The licensee stated that evaluations of the actual test results may identify the need for additional tests or the revision of the tests planned and therefore, the final test plan may be revised. The NRC staff also reviewed the EPU modification aggregate impact analysis, submitted by the licensee in Reference 4, which concluded that there is no adverse impact to the dynamic response of the plant to anticipated initiating events as a result of the proposed plant modifications.

The NRC staff concludes, based on review of each identified modification, the associated post-maintenance test, and the basis for determining the appropriate test, that the EPU test program will adequately demonstrate the performance of SSCs important to safety and included those SSCs: (1) impacted by EPU-related modifications; (2)used to mitigate an AOO described in the plant design basis; and (3)supported a function that relied on integrated operation of multiple systems and components. Additionally, the staff concludes that the proposed test program adequately identified plant modifications necessary to support operation at the EPU power level, and that there were no unacceptable system interactions because of proposed modifications to the plant.

SRP 14.2.1 Section Ill.C Use of Evaluation To Justify Elimination of Power-Ascension Tests Draft SRP 14.2.1,Section III.C, specifies the guidance and acceptance criteria that the licensee should use to provide justification for a test program that does not include all of the power-ascension testing that would normally be considered for inclusion in the EPU test program pursuant to the review criteria of SRP 14.2.1, Sections 11l.A and lll.B. The proposed EPU test program shall be sufficient to demonstrate that SSCs will perform satisfactorily in service. The following factors should be considered, as applicable, when justifying elimination of power-ascension tests:

• previous operating experience;

• introduction of new thermal-hydraulic phenomena or identified system interactions;

• facility conformance to limitations associated with analytical analysis methods;

• plant staff familiarization with facility operation and trial use of operating and emergency operating procedures;

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• margin reduction in safety analysis results for AOOs;

• guidance contained in vendor topical reports; and

• risk implications.

The NRC staff reviewed the licensee's justification, in Attachment 2 of Reference 20, for not re-performing certain original startup tests. The attachment provides summaries from historical startup testing records and further justifies not performing certain startup tests during EPU power ascension testing. This information supplemented the bases for the proposed testing program provided in Reference 4. The EPU power ascension test plan does not include all of the power ascension testing that would typically be performed during initial startup of a new plant. The following factors were applied by the licensee in determining which tests may be excluded from EPU power ascension testing:

• Previous operating experience has demonstrated acceptable performance of SSCs under a variety of steady state and transient conditions.

• The effects of the VYNPS EPU are in conformance with the criteria of the NRC-approved GE CPPU Licensing Topical Report NEDC-33004P-A (Reference 51). Because the EPU is a constant pressure power uprate, the effects on SSCs due to changes in thermal-hydraulic phenomena are limited.

• Most of the plant modifications associated with the EPU were installed and tested during the spring 2004 refueling outage and subsequent restart. Therefore, modified plant equipment has been in service since that time and plant staff familiarization with changes in plant operation as a result of the modifications has occurred.

The following is a brief justification provided by the licensee with respect to the startup tests that will not be re-performed as part of the EPU power ascension program:

STP-1 1. LPRM Calibration. The test is not required to be re-performed since calibration of LPRMs, which is maintained by TSs, is not affected by the EPU,

• STP-13. Process Computer. The test is not required to be re-performed since operation of the process computer is not affected by the EPU. Plant procedures maintain the accuracy of the process computer.

• STP-20. Steam Production. The test is not required to be re-performed since it was only applicable for initial plant startup to demonstrate warranted capabilities.

i STP-21. Response to Control Rod Motion. The test is not required to be re-performed since operation at EPU power increases the upper end of the power-operating domain, which does not significantly or directly affect the manner of operating or response of the reactor at lower power levels.

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• STP-25, Main Steam Isolation Valves (MSIVs). Inaccordance with VYNPS TS 4.7.D, each MSIV is tested at least once per quarter by tripping each valve and verifying the closure time. As discussed in Attachment 7 of Reference 1, one of the licensee's justifications for not performing large transient testing isthat the initial startup test involving simultaneous closure of all MSIVs would result in an unnecessary and undesirable transient cycle on the primary system which will not likely reveal unforeseen equipment issues related to operation at EPU conditions.

• STP-27. Turbine TriD. and STP-28. Generator Trip. These large transient tests were evaluated by the licensee for exception from EPU power ascension testing in accordance with Attachment 7 of Reference 1. A discussion of the NRC staffs review of the licensee's justification is provided below.

• STP-29. Recirculation Flow Control. Section 3.6 of the VYNPS PUSAR documents that the plant-specific system evaluation of the reactor recirculation system performance at CPPU power determined that adequate core flow can be maintained without requiring any changes to the recirculation system and with only a small increase in pump speed for the same core flow. Because the response to flow changes will be similar to that demonstrated during initial startup testing, this test is not required.

• STP-30. Recirculation System. For a one or two pump trip test at 100% power, Section 3.6 of the PUSAR indicates a CPPU that increases voids inthe core during normal EPU operations requires a slight increase in recirculation drive flow to achieve the same core flow. Section 3.6 documents that the plant-specific evaluation of the reactor recirculation system performance at CPPU power determines that adequate core flow can be maintained without requiring any changes to the system or pumps and with only a small increase in their speed for the same core flow. The response to a one or two pump trip will be similar to that of original startup testing, therefore the test is not required.

• STP X-5 (90). Vibration Testing. This test obtains vibration measurements on various reactor pressure vessel internals to demonstrate the mechanical integrity of the system under conditions of FIV and to check the validity of the analytical vibration model. The licensee stated in a previous submittal associated with the steam dryer and other plant systems and components (Reference 16) that the analysis of the vessel internals at the EPU power level was performed to ensure that the design continues to comply with the existing structural requirements. Section 3.4.2 of the PUSAR states that calculations indicate that vibrations of all safety-related reactor internal components under EPU conditions are within GE acceptance criteria.

As mentioned previously in the discussion of startup tests STP-27 and STP-28, the NRC staff also reviewed Attachment 7,"Justification for Exception to Large Transient Testing," contained in Reference 1. The licensee cited industry experience at ten other domestic BWRs (EPUs up to 120% OLTP) in which the EPU demonstrated that plant performance was adequately predicted under EPU conditions. The licensee stated that one such plant, Hatch Units I and 2, was granted an EPU by the NRC without the requirement to perform large transient testing and

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that the VYNPS and Hatch are both BWR/4 designs with Mark I containments. Hatch Unit 2 experienced an unplanned event that resulted in a generator load reject from 98% of uprated power in the summer of 1999. As noted in Southem Nuclear Operating Company's licensee event report (LER) 1999-005, no anomalies were seen in the plant's response to this event. In addition, Hatch Unit 1 has experienced a turbine trip and a generator load reject event subsequent to its uprate, as reported in LERs 2000-004 and 2001-002. Again, the behavior of the primary safety systems was as expected indicating that the analytical models being used are capable of modeling plant behavior at EPU conditions.

The licensee also provided information regarding transient testing for the Leibstadt (i.e., KKL) plant which was performed during the period from 1995 to 2000. Uprate testing was performed at 3327 MWt (i.e., 110.5% OLTP) in 1998, 3420 MWt (i.e., 113.5% OLTP) in 1999, and 3515 MWt in 2000. Testing for major transients involved turbine trips at 110.5% OLTP and 113.5% OLTP and a generator load rejection test at 104.2% OLTP. The testing demonstrated the performance of the equipment that was modified in preparation for the higher power levels.

These transient tests also provided additional confidence that the uprate analyses consistently reflected the behavior of the plant. Another factor used by the licensee to evaluate the need to conduct large transient testing for the EPU were actual plant transients experienced at the VYNPS. Generator load rejections from 100% current licensed thermal power, as discussed in VYNPS LERs91-005, 91-009, and 91-014, produced no significant anomalies in the plant's response to these events. Additionally, the licensee indicated that transient experience for a wide range of power levels at operating BWRs has shown a close correlation of the plant transient data to the predicted response.

The NRC staff also reviewed the licensee's technical justification for not performing a loss of turbine generator and offsite power test, which was originally performed at approximately 20%

of CLTP. The licensee stated that under emergency operations/distribution (emergency diesel generator) conditions, the AC power supply and distribution components are considered adequate and their evaluation assures an adequate AC power supply to safety-related systems. The TSs and approved plant procedures govern the testing of the safety-related AC distribution system, including loss of offsite power tests.

The power ascension test program is relied upon as a quality check to: (a)confirm that analyses and any modifications and adjustments that are necessary for proposed EPUs have been properly implemented, and (b) benchmark the analyses against the actual integrated performance of the plant thereby assuring conservative results. This is consistent with 10 CFR Part 50, Appendix B, which states that design control measures shall provide for verifying or checking the adequacy of design, such as by the performance of design reviews, by the use of alternate calculational methods, or by the performance of a suitable testing program; and requires that design changes be subject to design control measures commensurate with those applied to the original plant design (which includes power ascension testing).

SRP 14.2.1 specifies that the EPU test program should include steady-state and transient performance testing sufficient to demonstrate that SSCs will perform satisfactorily at the requested power level and that EPU-related modifications have been properly implemented.

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The SRP provides guidance to the staff in assessing the adequacy of the licensee's evaluation of the aggregate impact of EPU plant modifications, setpoint adjustments, and parameter changes that could adversely impact the dynamic response of the plant to anticipated operational occurrences.

The NRC staff's review is intended to ensure that the performance of plant equipment important to safety that could be affected by integrated plant operation or transient conditions is adequately demonstrated prior to extended operation at the requested EPU power level.

Licensees may propose a test program that does not include all of the power-ascension testing that would normally be included in accordance with the guidance provided in the SRP provided each proposed test exception is adequately justified. If a licensee proposes to omit a specified transient test from the EPU testing program based on favorable operating experience, the applicability of the operating experience to the specific plant must be demonstrated. Plant design details (such as configuration, modifications, and relative changes in setpoints and parameters), equipment specifications, operating power level, test specifications and methods, operating and emergency operating procedures; and adverse operating experience from previous EPUs must be considered and addressed.

Entergy's test program primarily includes steady-state testing with some minor load changes, and no large-scale transient testing is proposed. In a letter dated December 21, 2004 (Reference 60), the NRC staff requested that Entergy provide additional information (including performance of transient testing that will be included in the power ascension test program) that explains in detail how the proposed EPU test program, in conjunction with the original VYNPS test results and applicable industry experience, adequately demonstrates how the plant will respond during postulated transient conditions following implementation of the proposed EPU given the revised operating conditions that will exist and plant changes that are being, made. In letters dated July 27, and September 7, 2005 (Reference 60 and 61), the NRC staff requested that the licensee provide additional information regarding the need for condensate and feedwater system transient testing. The results of the staffs review of this issue and the need for a license condition is discussed in SE Section 2.5.4.4.

Based on its review of the information provided by the licensee, as described above, the NRC staff concludes that in justifying test eliminations or deviations, other than the condensate and feedwater system testing discussed in SE Section 2.5A.4, the licensee adequately addressed factors which included previous industry operating experience at recently uprated BWRs, plant response to actual turbine and generator trip tests at other plants, and experience gained from actual plant transients experienced in 1991 at the VYNPS. From the EPU experience referenced by the licensee, it can be concluded that large transients, either planned or unplanned, have not provided any significant new information about transient modeling or actual 'plant response. As such, the staff concludes that there is reasonable assurance that the VYNPS SSCs will perform satisfactorily in service under EPU conditions. The staff also noted that the licensee followed the NRC staff approved GE topical report guidance which was developed for the VYNPS EPU licensing application.

e GNr Global Nuclear Fuel.

AJoint Venture of GE, Toshiba., & iach 0000-0035-6443-SRLR Revision 0 Class I December 2005 Supplemental Reload Licensing Report for Vermont Yankee Nuclear Power Station Reload 24 Cycle 25 (with Extended Power Uprate)

i VERMONT YANKEE 0000-0035-6443-SRLR R^1iD-I

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RPpinin'n A V

8. Operating Flexibility Options 4 The following information presents the operational domains and flexibility options which are supported by the reload licensing analysis. Inclusion of these results in this report is not meant to imply that these domains and options have been fully licensed and approved for operation.

Extended Operating Domain (EOD): Yes EOD type: Maximum Extended Load Line Limit (MELLLA)

Minimum core flow at rated power: 99.0%

Increased Core Flow: Yes Flow point analyzed throughout cycle: 107.0 %

Feedwater Temperature Reduction: No ARTS Program: Yes Single Loop Operation: Yes Equipment Out of Service:

Safety/relief valves Out of Service: Yes (credit taken for 3 of 4 relief valves (I RV OOS))

9. Core-wide AOO Analysis Results 5 Methods used: GEMINI, GEXL-PLUS Operating domain: ICF (HBB)

Exposure range : BOC to MOC (Application Condition: I)

Uncorrected ACPR Flux Q/A Event (%rated) (%rated) GEI4C Fig.

FW Controller Failure 354 121 0.26 2 Load Rejection w/o Bypass 382 119 0.28 3 Turbine Trip w/o Bypass 372 118 0.27 4 inadvertent HPCI /L8 347 123 0.27 4 Refer to GESTAR for those operating flexibility options that are referenced and supported within GESTAR.

5Exposure range designation is defined in Table 7-1. Application condition number is defined in Section 11.

Page 8

VERMONT YANKEE 0000-0035-6443-SRLR D17rlasA ')A -c n Operating domain: ICF (HBB)

Exposure range : MOC to EOC (Application Condition: I)

Uncorrected ACPR EetFlux QIA Event (%rated) (%rated) GE14C Fig.

FW Controller Failure 379 123 0.26 6 Load Rejection w/o Bypass 400 120 0.27 7 Turbine Trip w/o Bypass 395 120 0.27 8 Inadvertent HPCI /L8 372 125 0.27 9 Operating domain: MELLLA (HBB)

Exposure range : BOC to MOC (Application Condition: I)

Uncorrected ACPR Event Flux Q/A GE14C Fig.

(%rated) (%rated)

FW Controller Failure 314 119 0.25 10 Load Rejection w/o Bypass 328 116 0.26 11 Turbine Trip w/o Bypass 331 116 0.25 12 Inadvertent HPCI /L8 306 121 0.25 13 Operating domain: MELLLA (HBB)

Exposure range : MOC to EOC (Application Condition: I)

Uncorrected ACPR Event Flux Q/A GE14C Fig.

(%rated) (%rated)

FW Controller Failure 328 120 0.25 14 Load Rejection w/o Bypass 337 117- 0.26 15 Turbine Trip w/o Bypass 340 117 0.25 16 Inadvertent HPCI /L8 324 122 0.26 17 Page 9

VERMONT YANKEE 0000-0035-6443-SRLR Reload 24 Revision 0 Operating domain: ICF (UB)

Exposure range MOC to EOC (Application Condition: 1)

Uncorrected ACPR Flux. QIA Event (%rated) (%rated) GEI4CFig.

FW Controller Failure 250 115 0.25 18 Load Rejection w/o Bypass 301 114 0.27 19 Turbine Trip w/o Bypass 278 114 0.26 20 Inadvertent HPCI /L8 247 118 0.26 21 Operating domain: MELLLA (UB)

Exposure range : MOC to EOC (Application Condition: I)

Uncorrected ACPR EventFx (%r ted) GE14C Fig.

FW Controller Failure 213 113 0.22 22 Load Rejection w/o Bypass 260 111 0.24 23 Turbine Trip w/o Bypass 238 112 0.24 24 Inadvertent HPCI /L8 207 115 0.23 25

10. Local Rod Withdrawal Error (With Limiting Instrument Failure) AOO Summary Rod withdrawal error (RWE) limits with ARTS are reported in Vermont Yankee Nuclear Power Station APRM/RBM/Technical Specifications / Maximum Extended Load Line Limit Analysis (ARTS/MELLLA),

NEDC-33089P, March 2003. A statistically based RWE limit of 1.40 is established in the Statistically Based Rod Withdrawal ErrorAnalysis for Vermont Yankee Nuclear Power Station, GE-NE-0000-0016-3451 -R0, July 2003.

A cycle specific analysis was performed for Vermont Yankee Cycle 25 to determine the MCPR corresponding to full withdrawal. (RBM was not credited in this analysis.) For the exposure range from BOC25 to EOC25, it is concluded that the statistically based RWE analysis value of 1.40 bounds the Cycle 25 specific analysis-value. Therefore, it is the statistically based value that is reported in Section 11 of the SRLR.

The RBM operability requirements specified in Section 3.4 of ARTS Report NEDC-33089P have been evaluated and shown to be sufficient to ensure that the Safety Limit MCPR and cladding 1%plastic strain criteria will not be exceeded in the event of an unblocked RWE event.

Page 10

VERMONT YANKEE 0000-0035-6443-SRLR Reload 24 Revision 0 Operating domain: MELLLA (HBB)

Exposure range : MOC to EOC (Application Condition: I )

Option A Option B GE14C GE14C FW Controller Failure 1.54 1.37 Load Rejection w/o Bypass 1.55 1.38 Turbine Trip w/o Bypass 1.55 1.38 Inadvertent HPCI tL8 1.55 1.38 Operating domain: ICF (UB)

Exposure range: MOC to EOC (Application Condition: I)

Opt i .A Option B FW Controller Failure 1.54 1.37 LaReeton w/o Bypass 1.57 1.40 Tubn rpw/o Bypass 1.56 1.139 Inadvertent HPC1 /L8 1.55 1.138 Operating domain: MELLLA (UB)

Exposure range : MOC to EOC (Application Condition: I)

Option A Option B GE14C GEl 4C FW Controller Failure 1.51 1.34 Load Rejection w/o Bypass 1.53 1.36 Turbine Trip w/o Bypass 1.53 1.36 Inadvertent HPCI /L8 1.52 1.35

12. Overpressurization Analysis Summary PsI Pdome Pv Plant (psig) (psig) (psig) Response MSIV Closure (Flux Scram) - ICF (HBB) 1302 1303 .1328 Figure 26 MSIV Closure (Flux Scram) - MELLLA 1299 1300 1324 Figure 27 (HBB) 1299__ ______ 132_Fiure27_

Page 13

ACCESSION #: 9906040026 LICENSEE EVENT REPORT (LER)

FACILITY NAME: Edwin I. Hatch Nuclear Plant - Unit 2 PAGE: 1 OF 5 DOCKET NUMBER: 05000366 TITLE: Generator Ground Fault Causes Turbine Trip and Reactor Scram EVENT DATE: 05/05/1999 LER #: 1999-005-00 REPORT DATE: 05/27/1999 OTHER FACILITIES INVOLVED: DOCKET NO: 05000 OPERATING MODE: 1 POWER LEVEL: 98.3 THIS REPORT IS SUBMITTED PURSUANT TO THE REQUIREMENTS OF 10 CFR SECTION:

50.73 (a)(2)(iv)

LICENSEE CONTACT FOR THIS LER:

NAME: Steven B. Tipps TELEPHONE: (912) 367-7851 Nuclear Safety and Compliance Manager, Hatch COMPONENT FAILURE DESCRIPTION:

CAUSE: B SYSTEM: EL COMPONENT: DUCT MANUFACTURER: N/A REPORTABLE NPRDS: Yes SUPPLEMENTAL REPORT EXPECTED: NO ABSTRACT:

On 05/05/1999 at 0747 EDT, Unit 2-was in the Run mode at a power level. of 2716 CMWT (98.3 percent rated thermal power). At that time, the reactor scrammed and the reactor recirculation pumps tripped automatically on turbine control valve fast closure caused by a turbine trip. The turbine tripped when the main generator tripped on a ground fault. Following the reactor scram, water level decreased due to void collapse from the rapid reduction in power. However, the reactor feedwater pumps maintained water level higher than eight inches above instrument, zero..

Consequently, no safety system actuations on low level were received nor were any required'. Pressure reached a maximum value of 1124 psig; nine of eleven safety/relief valves lifted toreduce reactor pressure.

Pres'sure did not reach the nominal actuation setpoints for the remaining two safety/relief valves.: The temperature in the vessel bottom head region decreased by more than the Technical Specification-allowed 100 degrees F in' one hour before a recirculation pump could be restarted.

This event was caused by a manufacturer error. Some of the turning vanes located in the discharge duct for the "B" isophase bus duct cooling fan broke loose, shorting a generator phase to ground.. The manufacturer installed turning vanes that were not the proper thickness for this' application thus resulting in some of their connection points'failing.

Pieces of the broken vanes were retrieved from the isophase bus duct and the remaining turning vanes were removed from the isophase bus duct cooling system.

END OF ABSTRACT DISCLAIMER FOR SCANNED DOCUMENTS

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TEXT PAGE 2 OF 5 PLANT AND SYSTEM IDENTIFICATION General Electric - Boiling Water Reactor Energy Industry Identification System codes appear in the text as (EIIS Code XX).

DESCRIPTION OF EVENT On 05/05/1999 .at 0747 EDT, Unit. 2 was in the Run mode at a power level of 2716 CMWT (98.3 percent rated thermal power). At that time, the reactor automatically scrammed and the reactor recirculation pumps (EIIS Code AD) automatically tripped on turbine control valve (EIIS Code TA) fast closure caused by a main turbine (EIIS Code TA) trip. The main turbine tripped when the main generator (EIIS Code TB) tripped on a ground fault detected simultaneously by generator neutral ground relays (EIIS Code EL) 2S32-R003A, 2S32-R003B, and 2S32-RO03C. A recorded ground fault current of 467 amps energized the neutral ground relays; contacts in the energized relays closed causing the generator output breakers (EIIS Code EL) to open.

Opening the generator output breakers energized the main turbine trip relays resulting in fast closure of the turbine control valves. Turbine control valve fast closure is a direct input to the reactor protection system (EIIS Code JC). logic system.

Following the automatic reactor scram, vessel water level decreased due to void collapse from the rapid reduction in power. However, the reactor

-feedwater pumps (EIIS Code SJ) continued to operate limiting the drop in water level. The minimum water level reached during this event was 8.9 inches above instrument zero (167.34 inches above the'top of the active fuel), a decrease of approximately 28 inches from a normal level of 37 inches above instrument zero. Vessel water level did not decrease to the actuation setpoint of three inches above instrument zero. Thus, no safety system, including emergency core cooling system, actuations on low (Level

3) water level were received nor were any required.

Vessel pressure reached a maximum value of 1124 psig three seconds after receipt of the scram. Nine of the eleven safety/relief valves actuated to reduce reactor pressure. Vessel pressure did-not reach the nominal actuation setpoint of 1140 psig for safety/relief valves 2B21-FO13E and 2B21-F013H; therefore, they. did not actuate nor were they required to actuate. (Although safety/relief valve 2B21-FO13L has a nominal setpoint of 1140 psig, it actuated during this event. The maximum vessel pressure of 1124 psig was within its Technical Specification-allowed setpoint tolerance of 1115.5 psig to 1184.5 psig. Therefore, the-safety/relief valve functioned properly during the event.) Vessel pressure was below its.

pre-event value of 1033 psig within six seconds of the receipt of the scram. All but the four low-low set safety/relief valves closed within nine seconds. of the scram; the low-low set safety/relief valves closed as vessel pressure decreased to their nominal closure setpoints of 890 psig, 881 psig, 866 psig, and 851 psig, respectively.

The temperature in the vessel bottom head region, as measured by the vessel

bottom head drain line temperature, decreased by 107 degrees F in less'than 22 minutes. Unit 2 Technical Specification Limiting Condition for Operation 3.4.9 limits the'reactor coolant system cooldown rate to a maximum of 100 degrees F in one hour. At 0810 EDT, Operations personnel restarted one of the reactor recirculation pumps thereby TEXT PAGE 3 OF 5 increasing the bottom head temperature and reducing the bottom head region.

temperature drop to less than 100 degrees F.

CAUSE OF EVENT

• This event was caused by a manufacturer error. Some of the turning vanes located in the discharge duct. for isophase bus duct (EIIS Code EL) 'cooling fan 2R13-C008B broke loose. One or more of the loose pieces'shorted a generator phase to the wall of the isophase bus duct, which is grounded'.

The manufacturer installed turning vanes that were not the proper thickness (gage) for this application thus resulting in some of the vanes failing at their connection points.

The licensed-power level and generator output of Unit 2 were increased during the Fall 1998 refueling outage. Larger fans and their associated duct work were installed in the isophase bus duct cooling system during-the outage to remove the increased amount of heat generated in the isophase bus resulting. from the increased generator output. The discharge ductwork for cooling fan.2R13-C008B included a 90-degree elbow; the elbow was necessary to connect the "B" fan discharge duct to the common header in the isophase bus duct cooling system. (Due to the location of the "A" cooling fan, no elbow was necessary to connect its' discharge duct to the cooling system header.) In order to reduce backpressure resulting from the air hitting the side of the 90-degree elbow opposite the fan discharge, and therefore increase the cooling air flow rate, the ductwork manufacturer installed turning vanes in the elbow. This is a standard practice in designing and constructing ductwork.' However, the sheet metal used to construct the vanes and the rails used to connect the vanes to the sides of the elbow was too thin for this application.

Twenty-two gage (0.0336") turning vanes were mounted on 24 gage (0.0276")

vane rails and tack welded to the rails at two points on two sides.

However, it is difficult to weld sheet metal thinner than 18 gauge.

Indeed, a visual check revealed that the vanes broke. off near the weld points likely due to metal "burn-out" resulting from welding the thin sheet metal. Additionally, portions of the rail also broke loose from the side of the duct at 'or near the weld points. Visual'examination revealed these points likewise had experienced metal burn-out. Although the gage thickness of the turning vanes was in agreement with the Duct Contraction Standard of the Sheet Metal and Air-Conditioning Contractor National Association,, the manufacturer should have used thicker sheet metal since welding was used to secure the vanes and rails. Moreover, the required duct specific pressure'rating of 17.1 inches water (air velocity of 4400 fpm) should have indicated a thicker sheet metal had to be used to manufacturer the turning vanes and rails." Therefore, the-manufacturer erred in using thinner than 18 gage sheet metal for the turning vanes and rails.

REPORTABILITY ANALYSIS AND SAFETY ASSESSMENT This report is required by 10 CFR 50.73 (a)(2)(iv) because of the unplanned actuation of Engineered Safety Feature systems. .The reactor protection system, an Engineered Safety Feature system, actuated on turbine control

. t valve fast closure when the main turbine tripped following a trip of the main generator from a ground fault. Both reactor recirculation pumps tripped also on turbine control valve fast closure. Nine of eleven TEXT PAGE 4 OF 5 safety/relief valves opened on high vessel pressure; four of the valves continued to operate in the low-low set mode until pressure decreased to their respective closure setpoints.

Fast closure of the turbine control valves is-initiated whenever.the main generator trips. The turbine control valves close as rapidly as possible to prevent overspeed of the turbine-generator rotor. Valve closing causes a sudden. reduction in steam flow that, in turn, results in a reactor vessel pressure increase. If the pressure increases to the pressure relief setpoints, some or all of the safety/relief valves will briefly discharge steam to the suppression pool (EIIS Code BL).

Reactor scram and recirculation.pump trip initiation by turbine control valve fast closure prevent the core from exceeding thermal hydraulic safety limits following a main generator or main turbine trip. Closure of the turbine control valves results in the loss of the normal heat sink (main condenser) thereby producing reactor pressure, neutron flux, and heat flux transients that must be limited. A reactor scram is initiated on turbine control valve fast closure in anticipation of these transients. The scram, along with the reactor recirculation pump trip system, ensures that the minimum critical power ratio safety limit is not exceeded.

The recirculation pump trip system, upon sensing a turbine control valve fast closure, trips the reactor recirculation pumps, resulting in a decrease in core flow. The rapid core flow reduction increases void content and reduces reactivity in conjunction with the reactor scram to reduce the severity of the transients caused by the turbine trip.

In this event, the main generator tripped from a ground fault in the isophase bus duct. The main turbine tripped as designed in response to the generator trip. The turbine trip actuated the reactor protection system and scrammed the reactor. All systems functioned as expected and'per their design given the water level and pressure transients caused by the turbine trip and reactor scram. Vessel water level was maintained well above the top of the active fuel throughout' the transient and indeed never decreased to the Level 3 actuation setpoint. Because the water level decrease was X mild, no safety system, including emergency core cooling system, actuations on low water level were received nor were any required.

Typically, the bottom head region of the pressure vessel experiences rapid cooling following a scram coincident with a trip of the reactor recirculation pumps. This cooling is the result of the loss of effective

-water mixing due to the trip of the recirculation pumps and increased cold water flow from the control rod drive (EIIS Code AA) system following a scram. In this event, the temperature in the vessel bottom head region decreased by 107 degrees F in one hour. However, a bounding analysis indicated'cooldown up to 165 degrees F in-one hour will not place unacceptable stress on components of the reactor coolant system.

Based upon the preceding analysis, it is concluded this event had no adverse impact on nuclear safety. The analysis is applicable to all power levels.

TEXT PAGE 5 OF 5

CORRECTIVE ACTIONS Pieces of the broken vanes and rails were retrieved from the isophase bus duct.

The remaining turning vanes were removed from the 90-degree elbow in the "B" cooling fan discharge duct. An evaluation by Southern Company Services ensured that the bus cooling flow requirements remain adequate without the turning vanes. The evaluation also ensured no deleterious effects result with respect to the structural integrity of the ductwork and the increased duty on the fan. The "A" cooling fan discharge ductwork does not contain any turning vanes; therefore, no further modification to its ductwork was necessary or performed.

The licensed power level of Unit 1 was increased during the Spring'1999 refueling outage. However, its existing isophase bus duct cooling system was determined previously to be adequate to handle the increased heat load.

Therefore, no modifications were performed on this system during the outage and thus no similar problems are expected and no additional work on the system is required.

Personnel assessed the effects of the excessive cooldown rate on the reactor coolant system as required by Unit 2 Technical Specifications Limiting..Condition for Operation 3.4.9, Required Action A.2. An evaluation performed by General Electric in May 1994 (NEDC-32319P) was used in assessing the effects of this event. The May 1994 evaluation, intended to eliminate the need to perform an evaluation for each specific event, demonstrated that reactor pressure vessel and recirculation piping heatup and cooldown rates up to 165 degrees F per hour were acceptable provided certain bounding conditions were met. General Electric and Southern Nuclear personnel reviewed the May 1994 evaluation and concluded that the cooldown of 107 degrees F in one hour experienced during this event was bounded by the generic evaluation. Therefore,, personnel determined that the Unit 2 reactor coolant system was acceptable for continued operation.

ADDITIONAL INFORMATION No systems other than those already mentioned in this report were affected by this event.

This LER does not contain any permanent licensing commitments.

Failed Component Information:

Master Parts List Number: 2R13 EIIS System Code: EL Manufacturer: Ernest D. Menold, Inc Reportable to EPIX: Yes Model Number: N/A Root Cause Code: B Type:-Turning Vanes

• EIIS Component Code: DUCT Manufacturer Code: None There have been no previous similar events in the last two years in which the reactor scrammed while critical.

ATTACHMENT TO 9906040026 PAGE 1 OF 1 Lewis Sumner Southern Nuclear Vice President Operating Company, Inc.

Hatch Project Support 40 Inverness' Parkway Post. Office Box 1295 Birmingham, Alabama 35201

'Vz Tel 205.992.7279 Fax 205.992.0341 SOUTHERN COMPANY Energy to Serve Your World**[Servicemark]

May 27, 1999 Docket No. 50-366 HL-5792 U.S. Nuclear Regulatory Commission ATTN: Document Control Desk Washington, D.C. 20555 Edwin I. Hatch Nuclear Plant - Unit 2 Licensee Event Report Generator Ground Fault Causes Turbine Trip and Reactor Scram Ladies and Gentlemen:

In accordance with the requirements of 10 CFR 50.73(a)(2)(iv), Southern Nuclear Operating Company is submitting the enclosed Licensee Event Report (LER) concerning a generator ground fault which caused a turbine trip followed by a reactor scram.

Respectfully submitted, H.L. Sumner, Jr.

OCV/eb

Enclosure:

LER 50-366/1999-005 cc: Southern Nuclear Operating Company Mr. P.H. Wells, Nuclear Plant General Manager SNC Document Management (R-Type A02.001)

U.S. Nuclear Regulatory Commission, Washington, D.C.

Mr. L.N. Olshan, Project Manager - Hatch U.S. Nuclear Regulatory Commission, Region II Mr. L.A. Reyes, Regional Administrator .

Mr. J.T. Munday, Senior Resident Inspector - Hatch

E

~./0 Lewis Sumner Southern Nuclear ViWC Presidednt Operating Company, Inc.

Hatch Prqect Support 40 Inverness Parkway Post 01f ke b 1295 Birmngiham, Alabama 35201 Tel 205.992.7279 Fax 205.992.0341 SOUTHERA COMPANY EnegD to Saw Your Worul February 14, 2002 Docket No. 50-366 HL-6184 U.S. Nuclear Regulatory Commission ATIN: Document Control Desk Washington, D.C. 20555 Edwin I. Hatch Nuclear Plant Unit 2 Licensee Event Report Sudden Closure of Main Steam Line Isolation Valve Causes Pressure Increase and Reactor Scram on APRM High Flux Ladies and Gentlemen:

In accordance with the requirements of 10 CFR 50.73(aX2XivXA), Southern Nuclear Operating Company is submitting the enclosed Licensee Event Report (LER) concerning a sudden closure of a main steamline isolation valve which caused a pressure increase and reactor scram on APRM high fl.

Respectfiuly submitted, H. L. Sumner, Jr.

CLT/eb

Enclosure:

LER 50-366=2001-03 cc: Southern Nuclear Operating Company Mr. P. H. Wells, Nuclear Plant General Manager SNC Document Management (R-Type A02.001)

U.S. Nuclear Regulatory Commission. Washington. D.C.

Mr. L. N. Olshan, Project Manager - Hatch U.S. Nuclear Regulator Commission. Region 1I Mr. L. A. Reyes, Regional Administrator Mr. J. T. Munday, Senior Resident Inspector - Hatch r\}

Institute of Nuclear Power Operations LEREventsginpo.org

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_(Seereverse for required number of bbsi(@nrcgov, and to the Desk Officer, Office of Information and Regulatory digIts/charecters for each block) Affairs. NEOB-10202 (3180.0104. Office of Management and Budget, Washington, DC 20503. f a means used to Impose Information. collection does not display a currently vAldd0MB control number, the NRC may not conduct or L -sponsor, and a person Is hot required to respond to, the Information colection.

1. FACILTY NANE 2. DOCKET NUMBER PAGE Edwin I. Hatch Nuclear Plant

• Unit 2 05000-366

.4.TITLE, Sudden Closure of Main Steam Line Isolation Valve Causes Pressure Increase and Reactor Scram on APRM High Flux.

i. EVENT DATE . LER NUMBER 7. REPORT DATE S. OTHER FACILUTIES INVOLVED I i I T FACIUTY NAME DOCKET NUMBER(S) j IFACIUTY 05000 MONTH AYMYER .H DAY_ _YEAR_ _

25 l2001.1 25 200120120 003. 0 002 14 2002 F.ln NAME AE05000 DOCKET NUMBER(S)

OPE ATIN 11. THIS REPORT IS UBM TED PURSUANT TO THE REQUIREMENTS OF 10 CFR  : C ec a th5at0pply)

MODE I 20.2201(b) 20.2203(aX3XU) 50.73(aX2X11XB) 50.73(aX2XIxXA)

10. POWER 20 22D1(d) 202205(aX4)- 50.73(aX2XUII) _ 50.73(aX2Xx)

LEVEL 1 _ 20.2203(aXl) 50.36cXlXixA) X 50.73(aX2)(vxA) 73.71(aX4) 20.22D3(aX2XI) 5DM3(cXIXIIXA) -50.73(a 2vA) . 73.7i(aS)(5 20-2203(CX2XII) 50.36(cX2) 50.73(aX2XvXB) - _OTHER I 20-22D3(aX2XiI) _5A6(aX3X1) _ 50.73(aX2XvXC) SpcIfy hIAbstract below AMC

_ 202203(aX2XIY) 50.73(aX2XIXA) SO.73(aX2XvXD) or in NRC FOrm 366A 20220X(X2XV) 50.73(aX2XIXC) _ 50.73(aX2XVIWXA)

I2D.2203(&X2XvI) 50.73(aX2)XCIX) 507_ XXfIA 491 IMENISFF MFTA"T Fg VPTICIU1L P~~~~~~EIEPHONE-UBRICd-e~e Steven B. Tipps, Nuclear Safety and Compliance Manager, Hatch (912) 367-785 1 TPY

13. COMPLETE ONE UNE FOR EACH COMPONENT FAILURE DESCRI ED IN THIS REPORT CAUSE SYSTEM COMPONENT MANUFACTURER A TO__

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14. SUPPLEMENTAL REPORT EXPECTED - 15. EXPECTED MONTH DAY YR YES. NO SUBMISSION

• (if Yes, Complete EXPECTED SUBMISSION DATE) X DATE

.i. Ab IFKAL {Limit tO 14UUSpace, .. ,appwroimately 1i snogle4paced typewriteeneIs}DEl On 12001 at 18 19 EST, Unit 2 was in the Run mode. At that time, the reactor scranumed on Average Power Range Monitor high neutron flux caused by- a rapid increase in reactor pressure vessel pressure. Pressure increased quickly as a result of the unexpected and sudden closure of main steam line isolation valve 2B214-F2SB. The closure of the main steam line isolation valve isolated one of the four main steam lines. Although the flow rates in the remaining three steam lines increased to compensate partially for the isolated line, the sudden isolation of one line was sufficient to cause reactor. vessel pressure to increase from a nominal value of 1035 psig to 1041.2 psig within 0.3 seconds. This rapid rate of change in pressure caused reactor power to increase to 120.5 percent rated thermal power and the reactor to scram on high neutron flux level. Following the scram, water level decreased due to void collapse fron the rapid reduction in power resulting in closure of Group 2 primary containment isolation valves. Level reached a minimum of 33.5 inches below instrument zero, a level not low enough to initiate other protective actions. .Therefore, no systems other than the Group 2 primary containment isolation valves actuated or were required to actuate. The Reactor Feedwater Pumps restored level to its pre-event value of approximately 36

-inches above instrument zero within 30 seconds of the scram. Reactor pressure reached its maximum value of 1048.2 psig less than one second after the scram. It decreased thereafter and was maintained below 975 psig by the main turbine bypass valves. No safety/relief valves lifted nor were any required to lift to reduce pressure.

This event was the result of component failure caused by high-cycle fatigue. The stem in valve 2B21-F B fiailed completely, causing the valve to close and reactor vessel pressure to increase. Corrective actions include replacing the stem and determining the feasibility and cost of options to reduce or eliminate stem vibration.

NRC FORM 366A (12001)

NRC FORM 366A - U.S. NUCLEAR REGULATORY COMMISSION LICENSEE EVENT REPORT (LER)

TEXT CONTINUATION FACILITY NAME (1) DOCKET LER NUMBER (6) PAGE (31

.YEAR I SEQUENTIAL IREVISION YEAR INUMBER Edwin L HatdiNuckw Piit t-Unit2 05000-366 112001 - 003 - 00 OF 4 TEXT (it MM space is tquired, use additonal copies of NRC Fob 366A) (17)

PLANT AND SYSTEM IDENTIFICATION General Electric - Boiling Water Reactor Energy Industry Identification System codes appear in the text as (EUS Code ).

DESCRIPTION OF EVENT On 12/25/200 1 at 18 19 EST, Unit 2 was in the Run mode. At that time, the reactor scrammed on Average Power Range Monitor (APRM, EIlS Code IG) high neutron flux after reactor power had increased to approximately 120.5 percent rated thermal power as a result of a rapid increase in reactor pressure vessel pressure. Pressure increased quickly as a result of the unexpected and sudden closure of main steam line isolation valve (EUS Code SB) 22B2 1-F028B. The closure of the main steam line isolation valve isolated one ofthe four main steam lines (EIIS Code SB). Although the flow rates in the remaining three steam lines increased to compensate partially for the isolated line, the sudden isolation of one steam line was sufficient to cause reactor vessel pressure to increase from a nominal value of 1035 psig to 1041.2 psig within 0.3 seconds. This rapid rate of change in pressure caused reactor power to increase to 120.5 percent rated thermal power within the same 0.3-second period and the reactor to scram on high neutron flux level per design.

Following the automatic reactor scramn, vessel water level decreased due to void collapse from the rapid reduction in power. Water level reached a minimum of 33.5 inches below instrument zero (approximately 125 inches above the top of the active fuel) resulting in closure of the Group 2 primary containment isolation valves (EIS Code I.

Water level, however, did not decrease to the actuation setpoint for any other protective action system; therefore, no systems other than the Group 2 primary containment isolation valves actuated or were required to actuate.

The Reactor Feedwater Pumps (EIIS Code SJ) rapidly recovered reactor vessel water level, restoring level to its pre-event value of approximately 36 inches above instrument zero within 30 seconds of the scram.

Reactor pressure reached its maximum value of 1048.2 psig 0.6 seconds after the scram. It decreased thereafter and was maintained below 975 psig by 'the main turbine bypass valves. No safety/relief valves lifted nor were any required to lift to reduce pressure.

CAUSE OF EVENT This event was the result of component failure. Specifically, the stem in main steam line isolation valve 2B2 1-F028B failed completely from high-cycle fatigue, causing the stem disc (pilot valve) to fall to the closed position.

Failure initiation was in the root region of the first thread at the disc-end of the stem. When the stem disc closed, differential pressure forces on the main valve disc (poppet) caused it to close suddenly. The sudden closing of the main steam isolation valve caused reactor vessel pressure to increase from a nominal value of 1035 psig to 1041.2 psig within 0.3 seconds.' This rapid rate of change in pressure caused reactor power to increase to 120.5 percent rated thermal power within the same 0.3-second period and the reactor to scram on high neutron flux level per design.

The reason the main steam line isolation valve stem failed due to high-cycle fatigue could not be determined conclusively. The available data support no definitive conclusions regarding the causes of the stem failure. High-cycle fatigue occurs when the number of cycles and level of stress exceed the endurance limit of the failed NRC ForM 366A (1.2001)

V NRC FORM 366A , U.S. NUCLEAR REGULATORY COMMISSION (W4el)

LICENSEE EVENT REPORT (LER)

TEXT CONTINUATION FACILITY NAME (1) DOCKET LER NUMBER 6 PAGE (3)

YEAR SEQUENTAL REVISION Edwin I. Hatch Nuclear Plant - Unit 2 05000-366 2001 -- 003 -- 00 3 OF 4 TEXT(f mm spae Is reX use ad wpes of NRC FOM 364) 7.

material. Poor surface conditions and degradation of material condition can reduce the stem material's endurance limit to the point that normal cyclic loading would be sufficient to result in fatigue failure. Conversely, cyclic

-loading stresses and frequency could change such that the expected material endurance limit would be exceeded.

The number of cycles and/or the level of stress experienced by isolation valve 2B2 I-F028B may be different from other isolation valves whose stems have not failed. Also, the stem material's endurance limit may be different:

either it changed while the stem was in service (material condition) or it was reduced by a defect (stress riser) in this stem or both. There is insufficient evidence, however, to determine to what extent, if any, these factors contributed to the high-cycle fatigue failure.

REPORTABILITY ANALYSIS AND SAFETY ASSESSMENT This report is required by 10 CFR 50.73 (a)(2)(iv)(A) because of the unplanned actuation of reportable systems.

Specifically, the reactor protection system (EIIS Code JC) actuated on APRM high neutron flux. Group 2 primary containment isolation valves closed as a result of the expected reactor vessel water level decrease following the scram.

Two isolation valves are welded in a horizontal run in each of the four main steam lines. Each of the main steam line isolation valves is a 24-inch, Y-pattern, globe valve. The main valve disc is attached to the lower end of the stem and moves in guides at a 45-degree angle from the inlet pipe. Normal steam flow and higher inlet pressure tend to close the main valve disc. A stem disc attached to the end of the valve stem closes a small pressure-balancing hole in the main disc. When the pressure-balancing hole is open, it acts as a pilot valve to relieve these differential pressure forces on the main disc thereby allowing it to open.

The APRM channels provide the primary indication of neutron flux within the core and respond almost instantaneously to neutron flux increases. The APRM channels receive input -signals from the local power range monitors (EHS Code IG) within the reactor core to provide an indication of the power distribution and local power changes. The APRM channels average these local power range monitor signals to provide a continuous indication of average reactor power from a few percent to greater than rated thermal power. The APRM high neutron flux function is capable of generating a reactor protection system trip signal in sufficient time to prevent fuel damage or excessive reactor coolant system pressure.

In this event, the reactor scrammed on Average Power Range Monitor high neutron flux resulting from a rapid increase in reactor pressure vessel pressure. Pressure increased quickly as a result of the unexpected and sudden closure of main steam line isolation. valve 2B21-F028B. All systems functioned as expected and per their design given the core thermal power, water level, and pressure transients caused by this event. Fuel cladding integrity was not jeopardized because of the rapid response of the APRMs to the neutron flux increase. This response- resulted in a reactor scram before the increased energy from the fuel pellets could be transferred fully to the metal cladding.

Additionally, reactor vessel water level was maintained well above the top of the active fuel throughout the event.

Based upon the preceding analysis, it is concluded this event had no adverse impact on nuclear safety. The analysis is applicable to all power. levels.

RCForm 366A (1001).

NRC FORM 366A U.S. NUCLEAR REGULATORY COMMISSION (1-2D01)

LICENSEE EVENT REPORT (LER)

TEXT CONTINUATION FACILITY NAME (1) DOCKET LER NUMBER 16I PAGE 3)

YEAR I SEQUENTIAL I RIION I YEA1R , NUMB8ER Edwin I. Hatch Nuclear Plant - Unit 2 05000-366 2001 -- 003 - 00 4 OF 4 EXT (if more space is required, use additional copies of NRC FOIr 366A (17)

CORRECTIVE ACTIONS The main steam line isolation valve stem was replaced per Maintenance Work Order 2-01-03746. Local leak rate testing, valve cycling, and valve stroke timing were performed successfully and the valve was returned to an operable status.

Southern Nuclear will perform an investigation to determine the feasibility and cost of options to reduce or eliminate main steam line isolation valve stem assembly vibration.

ADDITIONAL INFORMATION No systems other than those already mentioned in this report were affected by this event.

This LER does not contain any permanent licensing commitments.

Failed Component Information:

Master Parts List Number: 2B21-F028B EUS System Code: SB Manufacturer: Rockwell International Reportable to EPIX: Yes Model Number: 16 12 JM MNTY Root Cause Code: X Type: Valve, Shutoff EIIS Component Code: SHV Manufacturer Code: R344 Previous similar events in the last two years in which the reactor scrammed automatically while critical were reported in the following Licensee Event Reports:

50-321/2000-002, dated 2/25/2000 50-321/2000-004, dated 8/4/2000 50-321/2001-002, dated 5/21/2001 50-366/2001-002, dated 12/14/2001.

Corrective actions for these previous similar events could not have prevented this event because they involved different components and were the result of different causes.

NRC Form 366A 2D001)

/i Lewis Sumner Southern Nuclear Vice President Operating Company, Inc Hatch Project Support 401nness Parkway Post office BEo129.

Birmingham, Alabama 35201 4

Tel ZIM5.992.7279 Fax 2051.920341 SOUTHEN£M COMPAN Ene~yto ServYrW"od August 4, 2000 Docket No. 50-321 HL-5967 U.S. Nuclear Regulatory Commission ATJN Document Control Desk Washington, D.C. 20555 Edwin I. Hatch Nuclear Plant - Unit 1 Licensee Event Rrt Component Failure Causes Turbine Trip and Reactor Scram Ladies and Gentlemen:

In accordance with the sin-kgrts of 10 CFR 50.73(aX2Xiv), Southern Nuclear Opeting Company is submitting the enclosed Licensee Event Report LER) concerning a ccIptmnt failure which resulted in a turbine trip and reactor scram.

Ril y submitte, -,

H. L. Stunner, Jr.

OCV/eb

Enclosure:

LER 50-321/200004 cc: Southern Nuclear Opmakim Company Mr. P. H. Wells, Nuclear Plant General Manager SNC Document Management (R-Type A02.001)

U.S. Nuclear Regulatw Commission. Washington D.C.

Mr. L. N. Olishan, Project Manager - Hatch U.S. Nuclear Regulatory Commission. Regio 11 Mr. L. A. Reyes, Regional Administrator Mr. J. T. Munday, Senior Resident Inspector :- Hatch

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BSTPRACT #nto 1400 vacav. La.. apw-'mty 16 sea-pacetw Imal 1i' On 07/10/2000 at 1050 EDT, Unit 1 was in the Run mode at a power level of 2754 CMWT (99.7 percent rated thermal power). At that time- the reactor scrammed and ffie reactor recirculation pumps 'tipped automatically on turoiie stop valve fast closue caused by a tubine trip. The turbine trip when the vi oninstee't #1 bearing failed causing a false highvibration tip signal to be generated Following the reactor scram, water level decreased due to void collapse from the rapid reduction in power.

However, the reactor feedwater pmps maintained water level higher than seventeen inches above instrument zero. Consequently, no safety system actuations on low level* were received nor were any required. Pressure reached a maximum value of 1128 psig; nine of eleven safety/relief valves lifted to reduce reactor pressure. Pressure did not reach the nominal acion se for Ihe remaining two  :

safety/relief valves. The enmpaure in the vessel bottom head region decreased by more than the Technical Speification allowed 100F in one hour before a recirculation pump could be re-started.

This event was caused by co4m nent failure. The vibraton insinent on the #10 bearing failed, generating a false fhigh vibration signal. The high bration igna caused the main turbine to trip, producing a reactor scram on turbine stop valve fast closure per design.L The failed vibration instonnent was replaced. The vibration instnrments on the remaining bea were checked resultng in the rplacement of the shaft rider probe on the #6 bearing. No'other instrurnent prblems were found.

WRC FORM 586 0D649891

I NRC FORM4 38BA U.S. NUCLEAR RiEGULATORY COMUiSSION LICENSEE EVENT REPORT (LER)

TEXT CONnTNUAON FACILITY NAME 11) DOC.T hR NUMBE i8s PAGE 43)

YM IA GEEW 1 1S Edwin IHat&hNuclearPlant Unit 1 05000-321 20O 004 . . OF6 00 PLANT AND SYSTEM IDENMhCATION General Electric - Boiling Water Reactor Energy Industry Identification System codes appear in the text as (EIIS Code X).

DESCMON OF EVENT On 07/10/2000 at 1050 EDT, Unit 1 was in the Run mode at a power level of 2754 CMWT (99.7 percent rated thermal power). At that time, the reactor automatically scrarrm ed and the reactor recirculation pumps (EIIS Code AD) automatically tripped on turbine stop valve (ElIS Code TA) fist closure caused by a main turbine (EIIS Code TA) trip. The main turbine tripped when the vibration instrument on the #10-bearing, the Lmain generator exciter fiIS Code Th) outboard bearing, failed. The instrument failure produced a false high bearing vibration signal, causing the main turbine to trip automatically on high bearing vibration. The turbine trip resulted in fast closure of the turbine stop valves. Turbine stop valve fast closure is a direct input to the reactor protection system (EPS Code JC) logic system Following the automatic reactor scram, vessel water level decreased due to void collapse from the rapid reduction in power. However, the reactor feedwater pumps (EPS Code SI continued to operate limiting the drop in water level. The minimum water level reached during this event was eighteen inches above instrument zero (176.44 inches above the top of the active fuel), a decrease of approximately 19 inches from a normal level of 37 inches above instrument zero. Vessel water level did not decrease to the actuation setpoint of three inches above instrument zero. Thus, no safety system, itclbdirg emergency core cooling Piston, actuations on low water level were received nor were any required Vessel pressure reached a maximum value of 1128 psig after receipt of the scram. Nne of the eleven safety/relief valves actuated to reduce reactor pressure. Vessel pressure did not reach the nominal actuation setpoint of 1140 psig for safety/reliefvalves 11321-FO13E and 1B21-FO13J; therefore, they did not actuate nor were they required to actuate. (Although safety/relief valve 1321-F013B. has a nominal setpoint of 1140 psig, it actuated during this event The maximum vessel pressure of 1128 psig was within its Technical Specification-allowed setpoint tolerance of 1115.5 psig to 1184.5 psig. Therefore, the safety/relief valve fimctioned properly during the event.) As vessel pressure was reduced below its pre-event value of 1034 psig, all but the four low-low set safety/relief valves closed. The low-low set safety/relief valves closed as vessel pressure decreased to 883 psig, 874 psig, 859 psig, and 843 psig, respectively.

Non-emergency 4160-volt bus IB failed to trader automatically from its normal to its alternate supply as expected when the main turbine tripped Operations personnel manually energized the bus, which provides power to the IB reactor recirculation pump, from its alternate supply at 1115 EDT.

The reactor coolant temperature in the vessel bottom head region, as measured by the vessel bottom head drain line temperature, decreased by 180¶F in one hour. Unit 1 Technical Specification Limiting Condition for Oeraon 3.4.9 limits the reactor coolant SyStemncooldown rate to a maxmum of 100F in one hour.

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NRC: FORM M6A U.S. NUCLEAR IREGUIATORY COMAM2SSO1 LICENSEE EVENT REPORT (LER)

TEXT CONTINUATION FCLT AE1)DOCKET ICR NNABER II) PAGEO4)

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.u"Waiu b x4 Hatch Nuclear Plant -.Unit 1 05000S321 - 2000 00 - 0 3W*E OF6 Because the temperature difference between the bottom head coolant temperature and the reactor coolant temperature in the steam dome exceeded the maximum allowed by Unit 1 Technical Specifications Surveillance Requirement SR 3.4.9.3, the reactor recirculation pumps could not be restarted. Therefore, the bottom head coolant temperature continued to decrease as expected, albeit at a rate within the 1000F per hour liit CAUSE OF EVENT This event was caused by component failure. The vibration instrument on the #10 bearing, the main generator exciter outboard bearing.failed when a solder connection inside the shaft rider probe came apart This created a loose wire that made intermittent contact with a coil within the probe. The loose wire contacted the coil such that a false high vibration signal was generatedi The high vibration signal caused the main turbine to trip automatically, producing a reactor scram on turbine stop valve fast closure per design Non-emergency 4160-volt bus lB failed to transfer automatically because its normal supply breaker was slow in opening. The automatic transfer logic requires the normal supply breaker to open within ten cycles (166.7 milliseconds). If the normal supply breaker does not open within the required time, the transfer logic prevents the alternate supply breaker from closing The firsttest ofthenormal supply breaker performed after it had opened during the event revealed that the breaker opened in 124 milliseconds, nearly three times the procedural acceptance criterion of 45 milliseconds. Subsequent tests of the breaker indicated it would open faster the more it was exercised. For example, the breaker opened in 114 milliseconds during the third test and 91.6 milliseconds during the fourth test, a 26 percent improvement from the time recorded in the first test. Finally, testing revealed that actuation of the logic necessary to indicate that the normal supply breaker was open added 33 to 50 milliseconds to the transfer logic signal.

Considering this additional time and the likelihood that the opening time of the normal supply breaker was greater than 124 milliseconds, investigating personnel concluded that the breaker opened too slowly, preventing transfer to the alternate power supply.

REPORTABILITY ANALYSIS AND SAFETY ASSESSMENT This report is required by 10 CFR 50.73 (a)(2)(iv) because of the unplanned actuation of Engineered Safety Feature systems. The reactor protection system, an Engineered Safety Feature system, actuated on turbine stop valve fast closure when the main turbine tripped on a false high bearing vibration signal. Both reactor recirculation pumps tripped also on turbine stop valve fast closure. Nine of eleven safety/relief valves opened on- high vessel pressure; four of the valves continued to operate in the low-ow set mode until pressure decreased to their respective closure setpoints.

Fast closwure of the turbine stop valves is iniiated whenever the main tubine tips. The turbine stop valves close as rapidly as possible to prevent overspeed of the turbine-generator rotor. Valve closing causes a sudden reduction in stema flow that, inturn results in a reactor vessel pressure increase. If the pressure increases to the pressure

,iCci 864am P(0618)

KRC FORM 386A  : US. NUCLEAR REGULATORY COMMSSION LICENSEE EVENT REPORT (LER)

TEXT CONTUATION FACILITY NAM 11) DOCKET ER NUMBER (a) PAGE 3)

'Edwin Hatc NuclearPlant Unit 1 05000-321 2000 _ 004 - 00 4 OF 6 1XW.iw ~- qm. iCFr SJ41  !~~'iq, relief setpoints, some or all of the safety/relief valves will briefly discharge steam to the suppression pool (X.. Code BL).

Reactor scram and recirculation pump trip initiation by turbine stop valve fast closure prevent the core from exceeding thermal hydraulic safety limits following a main turbiie trip. Closure of the turbiie stop valves results in the loss of the normal heat sink (main condenser) thereby producing reactor pressure, neutron flux, and heat flux transients that must be limited A reactor scram is initiated on turbine stop valve fast closure in anticipation ofthese -transients. The smAn, along with the reactor recirculation pump trip system, ensures that the minimum critical power ratio safety limit is not exceeded The recirculation pump trip system, upon sensing a turbile stop valve fast closure, trips the reactor recirculation pumps, resulting in a decrease in core flow. The rapid core flow reduction increases void content and reduces reactivity in conjunction with the reactor scram to reduce the severity of the transients caused by the turbine trip.

In this event, the main turbine tripped on a false high bearing vibration trip signal. The turbine trip actuated the reactor protection system 'and scrammed the reactor. All systems functioned as expected and per their design given the water level and pressure' transients caused by the turbiie trip and reactor scram. Vessel water level was maintained well above the top of the active ' fuel throughout the transient and indeed never decreased to the Level 3 actuation .setpoint: Because the water level decrease was mild, no safety system actuations on low water level were received nor were any required Typically, the bottom head region of the pressure vessel experiences rapid cooling following a scram coincident with a trip of the reactor recirculation pu Mps. This cooling is the result of the loss of effective water mixing due to the trip of the recirculation pumps and increased cold water flow from the control rod drive. (EIIS Code AA) system following a scram. In this event, the temperature in the vessel bottom head region decreased by 180P in one hour. However, a bounding analysis indicated cooldown up to 397.7'F in one hour will not place unacceptable stress on components of the reactor coolant system.

Based upon the preceding analysis, this event had no adverse impact on nuclear safety. The analysis is applicable to all power levels.

ARCFaCEm4Bje

NRC FORM 386A W6198 1.FAOILTY NAME 41)

LICENSEE EVENT REPORT (LERD TEXT CONTINUATION U.S. NUCLEAR REGULATORY COMMISSION I

Edwint HatchNuclearPlant-Unit 1 unx ID'0" 4= i jo*qWIuft &M &~WWu)cIw o MG "MJ1 05WA £17)

ICORRECTIVE ACTIONS The vibration instrument for the #10 bearing was replaced on 7/12/2000 per Maintenance Work Order 1 02145. Additionally, the remaining vibration instruments were checked on 7/12/2000 per Maintenance Work Order 1-00-02159. As a result of this inspection, the dmf rider probe of the vibration instniment for the #6 bearing was replaced No problems were found with any of the other bearing vibration instrments.

The high bearing vilratio trip from the #9 and #10 bearings, with the concurrence of the turbine vendor, has been temporarily disabled- The fnal disposition of the main turbine high bearing vibration trips will be determined through the corrective action program.

Personnel assessed the effects of the excessive cooldown rate on the reactor coolant system. An evaluation performed by General Electric in May 1994 (NEDC-323. 19P) was used in assessing the effects of this event. The May 1994 evaluation, intended to eliminate the need to perform an evaluation for each specific event, demonstrated that reactor pressure vessel cooldown rates up to 397.7 0F per hour were acceptable provided certain bounding conditions were met General Electric and Southern Nuclear personnel reviewed the May 1994 evaluation and concluded that the cooldown of 180% in one hour experienced during this event was, bounded by the generic evaluation. Therefore, personnel determined that the Unit 1 reactor coolant system was acceptable for operation.

The normal supply breaker for non-emergency 4160-volt bus lB was removed and replaced with a refurbished breaker on 7112/2000 per Maintenance Work Order 1-99-04564. A fast transfer functional test of the newly installed normal supply breaker was completed succesfully.

ADDlTIONAL INFR1MATION No systems other than those alredy mentioned in this report were affected by this event This LER does not contain any permanent licensing commitments.

Failed Component Ifrmation:

Master Parts List Number: N3 l-N892 EIIS System Code: TA Manufacturer: General Electric Reportable to EPIC: Yes Model Number 3S7700VBIOOAI Root Cause Code: X Type: Vibration Transmitter EIIS Component Code: VT Manufacturer Code: G080 EI1C Farm A F643Uj

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1 NRC FORM SSfA U.S. NUCLEAR REMUlATORY COMMISSION V84998)

UCENSEE EVENT REPORT (LER)

TEXT CONTINUATION  :

FACUTY KAM I Edwin hBatch Nuclear Plant - Unit i

.WM WSMIb q" MO adaweckzei XWF'm ism (1 previous simia events in the last two years in which the reactor scrammed automatically while critical were reported in the following Licensee Event Reports:

50-321/1999-003 dated 6/11999 50-321/2000-002 dated 2J25t2000 50-366/1999-005 : dated 5/27/1999 50-366/1999-007 dated 7/27/1999 Corrcive actions for these previous similar events could not have prevented this event because their causes were different Specifically, none of the other previous similar events was the result of an instnrent failure. Indeed, only one of the previous four events was caused by a main turbine trip.. In that event reported in Licensee Event Report 50-366/1999-005, the main turbiie tripped when the main generator tripped on an actual ground fat. Therefore, any corective actions taken for the previous events would not have addressed trbiie bearing vibration instrments.

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l 1 I... I I 1I

Lewis Sumner Southern Nuclear Vice President Operating Company, Inc.

Hatch Project Suppofl 40 lnvemess Parkway Post Office Box 1295 Birmingham, Alabama 35201 Tel 205992.7279 F a 205.992.0341 SOUTHERN CoMPrn

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Energy to Serve Your WorldsM May 21, 2001 Docket No. 50-321 US. Nuclear Regulatory Commission ATTN: Document Control Desk Washington, D.C. 20555 Edwin I. Hatch Nuclear Plant - Unit 1 Licensee Event Report Com~onent Failure Causes Turbine Trir, and Reactor Scram Ladies and Gentlemen:

In accordance with the requirements of 10 CFR 50.73(a)(2)(iv)(A), Southern Nuclear Operating Company is submitting the enclosed Licensee Event Report (LER) concerning a component failure which caused a turbine trip and reactor scram.

Respectfully submitted, H. L. Sumner, Jr.

Enclosure:

LER 50-32V2OO 1-002 cc: Southern Nuclear Operating Company Mr. P. H. Wells, Nuclear Plant General Manager SNC Document Management @-Type A02.001)

US. Nuclear

- - Regulatory

- Commission, Washington, D.C.

Mr. L. N. Olshan, Project Manager - Hatch U S . Nuclear Regulatory Commission. Regiofl Mr. L. A. Reyes, Regional Administrator Mr. J. T. Munday, Senior Resident Inspector - Hatch Institute of Nuclear Power Operations LEREvents@inpo.org AitkenSY@lnpo.org

l RC FORM 366 U.S. NUCLEAR REGULATORY COMMISSION APPROVED BY OMB NO. 3150-0104 EXPIRES 06/3012001 1-2001) Estimated burden per response to comply with this mandatory informiatiot collection request: 50 his. Reported lessons learned are crporated Into th, L N EVENT REPORelte T LRC~s licensing process and led back to wKdustry. send comments regarding burdei lICENSE E VENT REPORT axon/ 1estimate to the Records Management Branch (T6 E6). U.S. Nuclea Regulatory Commission, Washington, DC 20655-0001, or by Internet e-mail t l(See reverse for required number of bisl(Onrcgov, and to the Desk Oflcer, Office of Information and Regulator digits/characters for each block) Affairs. NEO13-10202 (31500104), Office of Management and Budgel Washington. DC 20503. Ha means used to Impose information collection doe not display a ourrently valid OMB control number, the NRC may not conduct o l _ _ _ __ sponsor, and a person is not reouired to respond to, the Inormation collection.

FACLITY NAMAE (1). D OCKET NUMBER (2) PAGE (3)

.Edwin L Hatch Nuclear Plant - Unit 1 05000-321 1OF4 TfILE (4)

C2 mponent Failure Causes Turbine Trip and Reactor Scram  :

EVENT DATE (51 LER NUMBER (61 L 1 REPORT DATE (7)

MO I ____AR NAMED OTHER FACILLES INVOLVED (8) l OCKET NUMBER(S)

IONTH DAY Y YEAR NUMABE REvISON MONTH DAY YEAR 05000 03 OPERATING 28 2 _00 2001 I002I I05.I IIJII~ 05 21 I 105000 120011.

THIS REPORT IS SUBMITTED PURSUANT TO THE REOUIREMENTS OF 10 CFR 4: (Check one or more' 111)

D T UBR(S)

MO-EI( )

11.' -

20.2201(b) 202203(a)(3)0i) 50.73(a)(2)(Ji)(B) 50.73(a)(2)Qx)(A) 20.2201(d) 20.2203(a)(4) 50.73fa)(211fiii) 60.73(a)(21x1 20.2203(a)(1) 50.a6(c)(1)(i)(A) X 60.73(a) (2)(tv)(A) 73.71(a)(4) 2'0.2203(a)(2)()

20-2203(a)(2)(1) 50.36(c)(1i)(11) 50.36(c)(2)

. 5.3a2(A) 50.73(a)(2)(v)(B) 1:173.71(a)(5)

. OTHER

-1 20-2203aX2)(iiQ 20.2203(a)(2)(iv) i) 50.46(aX3)(1i) 50.73(a)(2)0)(A)

- J 50.78(a)(2)(v)(C) 50.73(a)(2)(v)(D)

Specify in Abstract below or in NRC Form 366A 2D.2203(a)(2)(y) 20.2203(e)(2)(vi) 020()3() W  :

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fI50 73{a)(2)O)(B) 50.73(a)X2)(i)(C) 6I0.73(aX(2)(li)(A)

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50-73(a)(2)(Vill)(A)

I 0.13(a)(2)(Viii)(B)

LICENSEE CONTACT FOR THIS LER (12)

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. Steven B. Tipps, Nuclear Safety and Compliance Manx Eff_.. or &S a .M . C_

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OUPPLtbMNIAL tCrUKI AXPTEIDU(141 I -I I YES l Yes, complete EXPECTED SUBMISSION DATE)

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ABSTRACT (Limit to 1400 spades i.e., approxrmateiy 15 single-space typewritten Ones) (16)

..On 03/28/2001 at 1853 EST, Unit I was in the Run mode at a power level of 2763 CMWT (100 percent rated thermal power). At that time, the reactor scrammed on turbine control valve fast closure caused by a turbine trip.

The turbine tripped when actuation of phase 2 and 3 differential relays for unit auxiliary transformer IB resulted in actuation of a lockout relay, generating a direct turbine trip signal. Following the scram, water level decreased due to-void collapse from the rapid reduction in power resulting in closure of Group 2 and the outboard Group 5 primary lcontainment isolation valves and automatic initiation of the Reactor Core Isolation Cooling and High Pressure Coolant Injection systems. The low level initiation signal cleared before either system could inject water to the vessel. The outboard secondary containment dampers automatically isolated, and all trains of the Unit I and Unit 2 Standby Gas Treatment systems automatically started on low water level. Level reached a minimum of 37 inches below instrument zero. The Reactor Feedwater Pumps restored. level to its pre-event value of approximately 35 inches above instrument zero within 30 seconds of the scram.: Pressure reached a maximum value of 1127 psig; five of eleven safety/relief valves lifted to reduce pressure. Pressure did not reach the nominal actuation setpoints for the remaining safety/relief valves.

This event was caused by. an internal fault in unit auxiliary transformer lB. The fault occurred on the high side winding of transformer phase 3. The transformer was removed from service; its loads will continue to be -supplied from their alternate supply until a new transformer can be procured and installed.

NRC FORM 366A U.S. NUCLEAR REGULATORY COMMISSION 11-2001)

LICENSEE EVENT REPORT (LER)

TEXT CONTINUATION FACILITY NAME (1) DOCKET LER NUMBER (6 l PAGE 3)

.I  :.lYEARI SEQUENTBE l L REVISION

. Ii I YEAR l NUMBER Edwin I. Hatch Nuclear Plant -Unit I 0502001 - 002 - 00 0F oEXT (if more space Is required, use additional copies of NRC Form 366A) (17)

PLANT AND SYSTEM IDENTIFICATION General Electric - Boiling Water Reactor Energy Industry Identification System codes appear in the text as (EIIS Code XX).

DESCRIPTION OF EVENT On 03/28/2001 at 1853 EST, Unit I was in the Run mode at a power level of 2763 CMWT (100 percent rated thermal power). At that time, the-reactor automatically scrammed on turbine control valve (EIIS Code TA) fast closure caused by a main turbine (EIIS Code TA) trip. The main turbine tripped when actuation of phase 2 and phase 3 differential relays monitoring unit auxiliary transformer IB (EIIS Code EA) resulted in actuation of lockout relay 87T1BX. Actuation of this lockout relay generated a direct turbine trip signal and the main turbine tripped per design. The turbine trip resulted in fast closure of the turbine'control valves. Turbine control valve fast closure is a direct input to the reactor protection system (EIIS Code JC).

Following the automatic reactor scram, vessel water level decreased due to void collapse from the rapid reduction in power. Water level reached a minimum of approximately 37 inches below instrument zero (approximately 121 inches above the top of the active fuel) resulting in closure of the Group 2 and outboard Group 5 primary containment isolation valves (EIIS Code JM) and automatic initiation of the Reactor Core Isolation Cooling (RCIC, EIIS Code BN) and High Pressure Coolant Injection (HPCI, EIIS Code BJ) systems. The outboard secondary containment isolation dampers automatically closed and all four trains of the Unit I and Unit 2 Standby Gas Treatment (EIIS Code BH) systems (SGTS) automatically started.

The Reactor Feedwater Pumps (EIIS Code SJ) rapidly recovered reactor vessel water level, restoring level to its pre-event valve of approximately 35 inches above instrument zero within 30 seconds of the scram. As a result, the HPCI and RCIC system low water level initiation signals cleared before either system could inject makeup water to the reactor vessel. Also, the inboard Group S primary containment isolation valve and the inboard secondary containment isolation dampers did not close because water level increased before all of the logic necessary to isolate the inboard valve and dampers sensed, and could actuate on, a low, water level condition.

Vessel pressure reached a maximum value of 1127 psig after receipt of the scram. Five of the eleven safety/relief valves actuated to reduce reactor pressure. Vessel pressure did not reach the nominal actuation setpoints of the remaining safety/relief valves; therefore, they did not actuate nor were they required to actuate. (Although safety/relief valve 1B21-F0l3B has a nominal setpoint of 1140 psig, it actuated during this event The maximum vessel pressure of 1127 psig, however, was within its Technical Specification-allowed setpoint tolerance of 1115.5 psig to 1184.5. psig. Therefore, the safety/relief valve functioned properly-during the event.) As vessel pressure was reduced, the low-low set safety/relief valves closed at 887 psig, 877 psig, 862 psig, and 847 psig, respectively.

The main turbine bypass valves functioned to control vessel pressure thereafter, maintaining pressure below 975 psig.

CAUSE OF EVENT This event was caused by an internal fault in unit auxiliary transformer IB. An inspection revealed a tum-to-turn failure caused extensive, damage to the high side winding of transformer phase 3. Although an Event Review Team, investigated this event, the root causes of the transformer internal fault were not determined.

IC Forn 366A (1-2001)

NRC FORM 366A U.S. NUCLEAR REGULATORY COMMISSION

1-2001).' l LICENSEE EVENT REPORT (LER)

TEXT CONTINUATION FACIUTY NAME (1) DOCKET LER NUMBER 16) PAGE (3)

.SQYEAR l SE ATL[REVIN

.YEAR lNUMBER EdfiinL. Hakifh M~orlmtt- Unit i 05000-321 2001 - 002 -- 00 3OF4

'EXT (if mote space Is required, use additonal copies of NRC Form 366A) (17)

Some evidence gathered by the Event Review Team, that is, transformer winding temperatures from Main Control Room recorder IN41-R900, six-month load voltage readings, and'transformer operating history, appeared to indicate the possibility of a load-induced or cooling-related problem as the direct cause of the transformer fault.

However, other evidence, such as the periodic recording of local transformer winding and oil temperature gauge readings, which indicated temperatures significantly lower than the recorder readings, and a successful check of transformer temperature switch operation, was inconsistent with this conclusion.

An internal transformer fault might have developed if contamination had been introduced in 1999 when part of phase 3 was re-wound as a result of a problem discovered during routine- testing of the transformer. However, the damage from the fault destroyed any evidence that might have existed. Therefore, it is impossible to confirm the presence, or lack, of contamination and to prove, or disprove, contamination as the direct cause of the internal fault in unit auxiliary transformer lB. It should be noted that internal contamination almost certainly was not the cause of failures of the high side winding of transformer phase 3 in 1984 and 1999 due to the many years of in-service time between those failures, making it less likely to be the cause for this most recent similar failure.

REPORTABILITY ANALYSIS AND SAFETY ASSESSMENT This report is required by 10 CFR 50.73 (a)(2)(iv)(A) because of the unplanned actuation of reportable systems.

Specifically, the reactor protection system actuated on turbine control valve fast closure when the main turbine tripped following the detection of a fault in unit auxiliary transformer lB. Group 2 and outboard Group 5 primary containment isolation valves closed and the RCIC and HPCI systems initiated. Five of eleven safety/relief valves opened on high vessel pressure; four of the valves continued to operate in the low-low set mode until pressure decreased to their respective closure setpoints.

Fast closure of the turbine control valves is initiated whenever the main turbine trips. The turbine control valves close as rapidly as possible to prevent overspeed of the turbine-generator rotor. Valve closing causes a sudden reduction in steam flow that, in turn, results in a reactor vessel pressure increase. If the pressure increases to the pressure relief setpoints, some or all of the safety/relief valves will briefly discharge steam to the suppression pool (EIIS Code BL).

Reactor scram initiation by turbine control valve fast closure prevents the core from exceeding thermal hydraulic safety limits following a main turbine trip. Closure of the turbine control valves results in the loss of the normal heat sink' (main condenser, EIIS Code SQ) thereby producing reactor pressure, neutron flux, and heat flux transients that must be limited. A reactor scram is initiated on turbine control valve fast closure in anticipation of these transients.

The scram ensures that the minimum critical power ratio safety limit is not exceeded.

In this event, the main turbine tripped when the unit auxiliary transformer lockout relay actuated on signals from the phase 2 and phase 3 differential current relays. The turbine trip actuated the reactor protection system and scrammed the reactor. All systems functioned as expected and per their design given the water level and pressure transients caused by the turbine trip and reactor scram. Vessel water level was maintained well above the top of the active fuel throughout the transient.

Based upon the preceding analysis, it. is concluded this event had no adverse impact on nuclear safety. The analysis is applicable to all power levels.

IKG ForM ----

ISA (1-7.U1j

4RC FORM 366A U.S. NUCLEAR REGULATORY COMMISSION I-200,)

LICENSEE EVENT REPORT (LER)

TEXT CONTINUATION FACILITY NAME 1 DOCKET LER NUMBER (6) PAGE (3)

YEARl SEOUENT"A REVISION..

. YE.R lSYEAR 'NUMBER Edwin I. Hatch Nuclear Plant - Unit I 05000-321 2001 - 002- 00 4 OF 4 EXT (Imif f requied use additional copies of NRC FoIn 364) (17) spae isP CORRECTIVE ACTIONS The unit auxiliary transformer was removed from service and taken to an off-site facility for further inspection.

This inspection revealed extensive damage to the high side windings of phase 3 caused by a turn-to-turn fault. The transformer loads will continue to be supplied from their alternate power supply, startup transformer IC (EIIS Code EA), until a new transformer can be procured and installed.

ADDITIONAL INFORMATION No systems other than those already mentioned in this report were affected by this event.

This LER does not contain any permanent licensing commitments.

Failed Component Information:

Master Parts List Number: IS 11-S003 EIIS System Code: EA Manufacturer: General Electric Reportable to EPIX: Yes Model Number: NP 167B5 180 Root Cause Code: X Type: Transformer EIIS Component Code: XFMR Manufacturer Code: GO80 Previous similar events in the last two years in which the reactor scrammed automatically while critical were reported in the following Licensee Event Reports:

50-321/1999-003, dated 611/1999 50-321/2000-002, dated 2/25/2000 50-32 12000-004, dated 8/4/2000 50-366/1999-005, dated 5/27/1999 50-366/1999-007, dated 7/27/1999 Corrective actions for these previous similar events could not have prevented this event because they involved different components and were the result of different direct causes.

Similar failures of unit auxiliary transformer IB occurred in 1984 and 1999. Specifically, the high side windings of phase 3 of the unit auxiliary transfonner failed in August 1984 after approximately ten years of service; this event resulted in an unplanned automatic reactor scram while critical (Licensee Event Report 50-321/1984-015, dated 8/3011984). The high side windings of this phase also failed a routine doble test in March 1999 after almost fifteen years of service; this problem was discovered before the windings had deteriorated to the point of causing an internal transformer fault. The transformer was completely rebuilt as a result of the former event. Part of the high side windings of phase 3 was rebuilt as a result of the latter event In neither event were the root causes of the failure determined; therefore, the corrective action of repairing the transformer-was not intended to address the causes of the failure and to prevent subsequent failures.

_t rorm 36r.A 41-2oo1)

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i3 a0 Progress Energy January 5, 2004 SERIAL: BSEP03-0158 10 CFR 50.73 U. S. Nuclear Regulatory Commission AITN: Document Control Desk Washington, DC 20555-0001

Subject:

Brunswick Steam Electric Plant, Unit No. 2 Docket No. 50-324/License No. DPR-62 Licensee Event Report 2-03-004 Gentlemen:

In accordance with the Code of Federal Regulations, Title 10, Part 50.73, Progress Energy Carolinas, Inc. submits the enclosed Licensee Event Report. This report fulfills the requirement for a written report within sixty (60) days of a reportable occurrence.

Please refer any questions regarding this submittal to Mr. Edward T. O'Neil, Manager - Support Services, at (910) 457-3512.

Sincerely, David H. Hinds Plant General Manager Brunswick Steam Electric Plant CRE/cre

Enclosure:

Licensee Event Report Progress Energy Caroinas. Inc; Buswvick Nuclear Plant P.O.Box 10429 Southpofl, NC 28461

Document Control Desk BSEP 03-0158 /Page 2 cc (with enclosure):

U. S. Nuclear Regulatory Commission, Region II AWTN: Mr. Luis A. Reyes, Regional Administrator Sam Nunn Atlanta Federal Center 61 Forsyth Street, SW, Suite 23T85 Atlanta, GA 30303-8931 U. S. Nuclear Regulatory Commission AT17N: Mr. Eugene M. DiPaolo, NRC Senior Resident Inspector 8470 River Road Southport, NC 28461-8869 U. S. Nuclear Regulatory Commission AWN: Ms. Brenda L. Mozafari (Mail Stop OWFN 8G9) (Electronic Copy Only) 11555 Rockville Pike Rockville, MD 20852-2738 U. S. Nuclear Regulatory Commission ATIN: Ms. Margaret Chemoff (Mail Stop OWFN 8G9A) (Electronic Copy Only) 11555 Rockville Pike.

Rockville, MD 20852-2738 Ms. JoA. Sanford Chair - North Carolina Utilities Commission P.O. Box 29510 Raleigh, NC 27626-051

NRC FORM 366 US. NUCLEAR REGULATORY APPROVED BY OMB NO. 315040104 EXPIRES 7-31.2004 (740013 COMMISSION Erb p b h vU wa1oy h=Wucn ecfl.1an SO.. 5 eRq~ad 1ee ad at I1~oie To It Icudri p~s Mid d bedca LICENSEE EVENT REPORT (LER) .e sr oxa (See reverse orequired nwrberd gtardbt OskOr~ee~ceced Wtulm wdRegysts.

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1. FACILITY NAME .2 DOCKET NUMBER 3. PAGE Brunswick Steam Electric Plant (BSEP), Unit 2 05000324 1 OF 6

4. TITLE .

Loss of Generator Excitation Results in Reactor Protection System and Other Specified System Actuations j

it

5. EVENT DATE 6. LER NUMBER 7. REPORT DATE 8. OTHER FACILITIES INVOLVED MO DAY YEAR SEOUENTIAL REV MO DAY YEAR FACLTY NMIE owET NUMBER NUMBER NO BSEP, Unit 1 05000325 11 04 2 032003 -004-- -LITY RTS00 SUBLSEN' 01 05 2004,FOOI(E NUMBI

9. OPERATING 11.THTI SSUBMITTEDPURSUANT TO THE REOUIREMENTS OF10 CFR -(Checkoneor 0

MODE _ 20.22201(b) 2203(a)(3)() 6.7_3(a)(2)(al - .7axA)

10. POWER _202201(d) _20203(a)(4) 60.73(a)2)Qi) -U.73(a)(2)(x)

LEVEL 9 202203ta)[1) 50.36(c)(1)(i)(A) 5O.73(a)(2)(iv)(A) 73.71(a)(4) 20.2203(aa)X2) 50.36{c)(1)(UXA) 50.73(a)(2)(vXA) 73.71(aX5) 202203(a)(2)(id) _ 50.36(c)(2) _ 0.73(aX2)(vXB) _ OTHER

.. 202203(a)(2)(U) 50(a)(2XiA) 50.73(a)(2)(vXC) _ Nr 202203(a)(2)(iv) 50.73(a)(2Xi(A) 5O.73(aX2)(vA)

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__-_.___--:__ 202200.73(a)(2)(ii)(A) = 5.73(a)(2)(viii)(B)

• _-_-_*:_--_i_-

12. UCENSEE CONTACT FOR THIS LER NAME i EELEPONE NUMbhti (Include Area Lode)

Charles R. Elberfeld, Lead Engineering Technical Support Specialist (910) 457-2136

13. COMPLETE ONE LINE FOR EACH COMPONENT FAIIURE DESCRIBED IN THIS REPORT CAUSE SYSTEM COMPONENT I MANUi- REPORTABLE CAUSE SYSTEM COMPONENT AANU- REPORTABLE I FACTURER TOEPIX FACTURER_ TOEPI B TL EXC GCnealiEcctric y_

14. SUPPLEMENTAL REPORT EXPECTED 15. EXPECTED MO DAY YEAR SUBMISSION _

otmplete EXPECTED cYES yes SUBMISS DATE

16. YES.EiATyemit to Ace e Bppro7rnly ION 14 nIeAce INes) t tten

&ABSTRAUT (Urritt014006paCOSLejappfOdmratly15ssnle-spaoeoewdntenlines)X On November 4, 2003, at approximately 1732 hours0.02 days <br />0.481 hours <br />0.00286 weeks <br />6.59026e-4 months <br />, Unit 2 received a generatorlturbine trip due to loss of generator excitation, which resulted in a Reactor Protection System (RPS) actuation. All control rods fully inserted into the core. Plant response to the transient also resulted in High Pressure Coolant Injection and Reactor Core Isolation Cooling System actuations on low reactor pressure vessel (RPV) coolant level with injection into the RPV. Additionally, Primary Containment Isolation System (PCIS) actuation signals for Valve Groups 1, 2,-3, 6, and 8 were received and the valves closed as required. All four Emergency Diesel Generators automatically started but did not load because electrical power was not lost to the emergency buses.

The initiator of the plant transient event and system actuations was the failure of the generator exciter inner collector ring and brush holders, which resulted in loss of excitation to the generator. The root cause of the failure is a fabrication deficiency due to poor workmanship at the time of original installation of the collector ring onto the exciter shaft. Weaknesses in brush maintenance, preventive maintenance, monitoring, and trending were also identified as the root cause of the event.

The damaged components were replaced. Enhanced exciter brush monitoring has been implemented on both Units 1 and 2. This event is being reported in accordance with 10 CFR 50.73(a)(2)(iv)(A). The safety significance of this occurrence is considered minimal.

NRC FORM 366A U.S. NUCLEAR REGULATORY COMMISSION g1.2001)

LICENSEE EVENT REPORT (LER)

FACILITY NAME (1) DOCKET (2) i LER NUMBER (6) PAGE (3) lYEART SEOUENTIAL lREVIION Brunswick Steam Electric Plant (BSEP), Unit 2 05000324 0 S NUJS8L NUMBER 2 oF 6 200 004 - 00 NARRATIVE (itmore space i srequired, useadditonapie opfNRCFoni3684) (17)

Energy Industry Identification System (EUS) codes are identified in the text as [XX].

INTRODUCTION On November 4. 2003, at approximately 1732 hours0.02 days <br />0.481 hours <br />0.00286 weeks <br />6.59026e-4 months <br />, Unit 2 received a generator/turbine trip due to loss of generator excitation r[L], which resulted in a Reactor Protection System (RPS) [JC] actuation. All control rods fully inserted into the core. Plant response to the transient also resulted in High Pressure Coolant Injection (HPCI) [BJJ and Reactor Core Isolation Cooling (RCIC) [BN] System actuations on low reactor pressure vessel (RPV) coolant level, with injection into the RPV. Additionally, Primary Containment Isolation System (PCIS) [J3M actuation signals for Valve Groups 1, 2, 3, 6, and 8 were received and the valves closed as required. As a result of the associated electrical transient, a PCIS Valve Group 6 isolation was also received on Unit 1. All four Emergency Diesel Generators (EDGs) [EK] automatically started but did not load because electrical power was not lost to the emergency buses. At the time of the event, Unit 2 was in Mode I, (i.e., Run) at approximately 96 percent of rated thermal power (RTP) and Unit 1 was in Mode 1 at 93 percent of RTP, with all Emergency Core Cooling Systems operable for both units. At approximately 1857 hours0.0215 days <br />0.516 hours <br />0.00307 weeks <br />7.065885e-4 months <br />, with Unit 2 in Mode 3 (i.e., Hot Shutdown), another RPS actuation was received due to low RPV coolant level while cycling Safety Relief Valves (SRVs) [RV]. At 2120 hours0.0245 days <br />0.589 hours <br />0.00351 weeks <br />8.0666e-4 months <br />, notification was made to the NRC (i.e., Event Number 40297) in accordance with 10 CFR 50.72(b)(2)(iv)(A),.

(b)(2)(iv)(B), and (b)(3)(iv)(A). This event is being reported in accordance with 10 CFR 50.73(a)(2)(iv)(A) as manual and automatic actuation of specified systems.

EVENT DESCRIPTION On November 4, 2003, at approximately 1732 hours0.02 days <br />0.481 hours <br />0.00286 weeks <br />6.59026e-4 months <br />, the Unit 2 generator exciter [EXC] inboard collector ring (i.e., Altenex Serial # CH8371544, General Electric Company, Reference TAB 32'S GEK 18539C Figure 7, Mechanical Outline Drawing GEK 34D105050) and brush holders failed resulting in a loss of generator excitation. The loss of generator excitation resulted in a decrease in generator voltage and AC bus voltages on Unit 2 for about three to four seconds, with a dip to approximately 40 percent of nominal voltage values. After the generator tripped, the Unit 2 bus loads were automatically transferred from the Unit Auxiliary Transformer to the Site Auxiliary Transformer (SAT). Additionally, all four EDGs automatically started, as a result of the generator trip, but did not load because electrical power was not lost to the emergency buses. Upon transfer to the SAT, the bus voltages returned to nominal values. Details of this event will be discussed in two sections: (1) Unit 2 Scram and Associated Transients, and (2) Plant Responses to the Voltage Transient.

Unit 2 Scram and Associated Transients On November 4, 2003, at approximately 1732 hours0.02 days <br />0.481 hours <br />0.00286 weeks <br />6.59026e-4 months <br />, and approximately three seconds into the voltage transient, the Unit 2 generatorlturbine tripped, resulting in. an RPS actuation. The voltage decrease also resulted in PCIS Valve Group 1 (i.e., Main Steam Isolation valves (MSIVs), Main Steam Line Drain valves, and Reactor Recirculation Sample valves), Group 3 (i.e., Reactor Water Cleanup isolation valves), and Group 6 (i.e., Containment Atmosphere Control/Dilution, Containment Atmosphere Monitoring, and Post NRC FORMf 366A (I-=I)

NRC FORM 366A U.S. NUCLEAR REGULATORY COMMISSION (S12001)

LICENSEE EVENT REPORT (LER)

FACILITY NAME (1) DOCKET (2) LER NUMBER (6) PAGE (3)

YEAR QUENTIJAL REVISION Brunswick Steam Electric Plant (BSEP), Unit 2 05000324 3 oFF6NUMBER 6

2003 004 - -00 NARRATIVE I)t1mor, space IsrequiredU se additionalcopiesatNRC Form 3664) (17)

-EVENT DESCRIPTION (continued).

Unit 2 Scram and Associated Transients (continued)

Accident Sampling System isolation valves) isolations. Event Notification 40297 stated that a Group 10 (i.e., Non-Interruptible Air to Drywell Isolation Valves) isolation occurred; however, review of the event and plant documentation could not validate the isolation. Four of 11 SRVs opened for a short duration on mechanical setpoints in response to the pressure transient. Maximum RPV steam dome pressure measured during the event was 1108 psig..i .

RPV coolant level decreased to below the Low Level 1 setpoint, which resulted in a Group 2 (i.e., Drywell Equipment and Floor Drain, Traversing In-core Probe, Residual Heat Removal (RHR) Discharge to Radwaste, and RHR Process Sample isolation valves) isolation and a Group 8 (i.e., RHR Shutdown Cooling Suction and RHR Inboard Injection isolation valves) isolation signal; however, the Group 8 valves were already closed as required by plant conditions prior to the event. RPV coolant level continued to decrease to the Low Level 2 setpoint, at which time the HPCI and RCIC Systems actuated and injected into the RPV to restore level.

After RPV coolant level was restored the HPCI System was secured. RPV coolant level and pressure were ontrolled using the Control Rod Drive [AAJ System flow, the RCIC System, and by manually cycling SRVs. The RHR loops were placed in the suppression pool cooling mode of operation as needed to remove decay heat. Activities were in progress to open the MSIVs to use the main condenser for the reactor cooldown. At approximately 1857 hours0.0215 days <br />0.516 hours <br />0.00307 weeks <br />7.065885e-4 months <br />, a second RPS actuation was received when RPV coolant level decreased below the Low Level I setpoint due to level shrink after an SRV was closed during manual cycling. RPS logic was reset at approximately 1922 hours0.0222 days <br />0.534 hours <br />0.00318 weeks <br />7.31321e-4 months <br />. At approximately 1934 hours0.0224 days <br />0.537 hours <br />0.0032 weeks <br />7.35887e-4 months <br />, the MSIVs were opened to re-establish the main condenser as a heat sink. At approximately 2300 hours0.0266 days <br />0.639 hours <br />0.0038 weeks <br />8.7515e-4 months <br />, the 2B Reactor Feed Pump was started to provide makeup to the RPV and the RCIC System was secured.

On November 5, 2003, at approximately 0452 hours0.00523 days <br />0.126 hours <br />7.473545e-4 weeks <br />1.71986e-4 months <br />, RHR loop A was placed in the shutdown cooling mode of operation. At approximately 0554 hours0.00641 days <br />0.154 hours <br />9.160053e-4 weeks <br />2.10797e-4 months <br />, Unit 2 entered Mode 4 (i.e., Cold Shutdown).

Plant Responses to Voltane Transient On November 4, 2003, at approximately 1732 hours0.02 days <br />0.481 hours <br />0.00286 weeks <br />6.59026e-4 months <br />, the loss of Unit 2 generator excitation resulted in a voltage transient on Unit 2 AC buses. The transient was characterized as a voltage decrease for about three or four seconds, with a dip to approximately 40 percent of nominal voltage values, at which time the voltages returned to normal values. The voltage transient caused the main stack radiation monitor, which is common to both Units I and 2, to initiate a logic signal resulting in isolation of the Reactor Building Ventilation [VA] Systems, automatic starting of the Standby Gas Treatment (SGI) Systems [BH], and PCIS Group 6 isolations for both units. The affected equipment responded successfully except for the Unit 2 SGT System Train A. Operations personnel reset a high temperature trip signal that was locked in during the voltage transient and were able to successfully start Train A manually.

N$IC F0RM366A (1-2D00)

NRC FORM 366A U.S. NUCLEAR REGULATORY COMMISSION (1.2001)

LICENSEE EVENT REPORT (LER)

FACILITY NAME (1) DOCKET (2) LER NUMBER (6) PAGE (3)

YEAR SEUENTIAL REVISION Brunswick Steam Electric Plant (BSEP), Unit 2 05000324 4 OF 6 2003 ,.004 .00 NARRATIVE fit More space IS equlr4, use add6naf COPIeS OfNJR? FOm 3664) (17)

EVENT DESCRIPTION continued)

Plant Responses to Voltage Transient (continued)

On November 4, 2003, at approximately 1812 hours0.021 days <br />0.503 hours <br />0.003 weeks <br />6.89466e-4 months <br />, the Unit 1 Reactor Building Ventilation System was restarted and at approximately 1825 hours0.0211 days <br />0.507 hours <br />0.00302 weeks <br />6.944125e-4 months <br />, it was restarted for Unit 2. At approximately 1824 hours0.0211 days <br />0.507 hours <br />0.00302 weeks <br />6.94032e-4 months <br />, the Unit 1 SGT System was secured and at approximately 2055 hours0.0238 days <br />0.571 hours <br />0.0034 weeks <br />7.819275e-4 months <br />, the Unit 2 SGT System was placed in standby. The PCIS Group 6 isolations were reset for both units as conditions allowed. By 2034 hours0.0235 days <br />0.565 hours <br />0.00336 weeks <br />7.73937e-4 months <br />, all four EDMs were placed in standby.

The voltage transient also affected other equipment on both units which required operator action to restore the equipment. The occurrences were evaluated considering the plant design and it was determined that these effects were to be expected based on the nature of the voltage transient and automatic load stripping of the emergency buses. The adequacy of the plant under-voltage protection logic was evaluated in light of the voltage transient associated with this event and it was determined that the present design is adequate.

EVENT CAUSE Loss of Generator Excitation The initiator of the plant transient event and system actuations was the failure of the generator exciter inner collector ring and brush holders, which resulted in loss of excitation to the generator. The root cause of the failure is a fabrication deficiency due to poor workmanship at the time of original installation of the collector ring-onto the exciter shaft in the early 1970s. The collector ring is designed to have a tight interference fit on the exciter shaft to minimize vibration. The poor workmanship was the fit-up of the collector ring assembly utilizing a peening methodology on the anti-rotation key in lieu of the proper shrink fit of the collector ring on the exciter rotor shaft. Post-failure inspection and laboratory evaluation support this conclusion.

Weaknesses in brush maintenance, preventive maintenance, monitoring, and trending were also identified as the root cause of the event. Comparison of site activities with original equipment manufacturer and industry recommendations indicate that the event may have been avoided if brush and brush rigging.

vibration monitoring and trending, as well as collector ring strobe light inspection activities, had been implemented per recommendations. On October 21, 2003, during the weekly exciter brush inspection, the' three inboard brush currents were noted to be unequal, indicating a degraded condition with the collector ring/brushes. An action plan was developed and being implemented to address the degraded condition, but the activities were not effective in preventing the equipment failure and subsequent event.

Additional contributing causal factors include insufficient detail/incomplete training for maintenance and engineering personnel, as well as inadequate attention to emerging problems and ineffective use of operating experience. General Electric Company notified equipment users of an improved brush holder and rigging design in the early 1990 timeframe. Operating experience from other utilities indicated success with mitigation of brush vibration issues using the improved design. The improved design was not implemented at BSEP.

NRC FORM 3SA (1-2001)

. . 9 NRC FORM 366A U.S. NUCLEAR REGULATORY COMMISSION (140031)

LICENSEE EVENT REPORT (LER)

FACILITY NAME(1) DOCKET (2) LER NUMBER (6) PAGE (3).

YEAR l SEOUENTIAL REVISION O 6 Brunswick Steam Electric Plant (BSEP), Unit 2. NUMBER NUMBER OF6 324 2003 004 - 00 NARRATIVE (ItmorvspaceIsrequired, useadditonalcoptes of NRCFomi 368J) (17)

EVENT CAUSE (continued)

Low Level I RPS Actuation due to RPV Coolant Level Shrink The cause of the Low Level 1 RPS actuation is attributed to the level shrink caused by manual SRV cycling until the MSIVs could be re-opened. Although this method is allowed by plant procedures, pressure control using manual SRV cycling is not as stable as using the HPCI System, in the pressure control mode of operation, and the RCIC System.

Unit 2 SGT System Train A Failure to Automatically Start on Demand Each SGT System train is designed to be able to automatically start after a complete loss of electrical power, and incorporates a specific relay logic scheme to allow that capability. On November 4,2003, the electrical transient resulted in a short-term voltage drop to approximately 40 percent of the nominal voltage value. The voltage value during the transient decreased to a value where some relays in the start logic may or may not have dropped out. For the Unit 2 SGT System Train A only, the relays responded such that the logic had to be reset before the train could start.

CORRECTIVE ACTIONS

• The damaged components (i.e., the collector ring, the anti-rotation key, the brushes, and brush rigging) were replaced. The collector ring was properly installed on the rotor shaft.

• Preventive maintenance, exciter brush vibration monitoring, and trending program improvements are being developed and will be implemented by February 20,2004. Program improvements for other brush applications on site are also being considered.

. Enhanced exciter brush monitoring has been implemented on both Units I and 2. Unit I exciter collector rings are scheduled to be replaced during the next refuel outage, which is scheduled to begin in February 2004.

• Design improvements to the exciter brush holders and inspection windows are being reviewed and developed.

• Training is being developed for appropriate engineering, operations, and maintenance personnel on brush maintenance topics.

• As part of the approved licensed operator training program, thisevent and the lessons learned associated with RPV coolant level control will be reviewed with the operating crews.

' A modification has been installed in the logic for both SGT System trains for both units to enhance logic response under degraded voltage conditions such as those experienced during this event.

NRC FORM 36M (12001)

p.

NRC FORM 366A U.S. NUCLEAR REGULATORY COMMISSION LICENSEE EVENT REPORT (LER)

FACILTY NAME (1) DOCKET (2) LER NUMBER (6) PAGE (3)

.YEAR 1.SEOUENTLALREVIS*lN Brunswick Steam Electric Plant (BSEP), Unit 2 05000324 YEAR [

2003-- 004 U-ET O

- 00 6 OF6 NARRATIVE (it more space Isrequired, use addiional copies of NRC Form 3661) (17)

SAFETY ASSESSMENT The safety significance of this occurrence is considered minimal. Plant systems responded as designed to the transient and so the consequences of the transient on the fuel and vessel overpressure were minimal.

The analyses in Chapter 15 of the Updated Final Safety Analysis Report fully bounded this event.

PREVIOUS SIMILAR EVENTS A review of events occurring within the past three years has not identified any previous similar occurrences.

COMMITMENTS Those actions committed to by Progress Energy Carolinas, Inc. (PEC) in this document are identified below.

Any other actions discussed in this submittal represent intended or planned actions by PEC. They are described for the NRC's information and are not regulatory commitments. Please notify the Manager -

Support Services at BSEP of any questions regarding this document or any associated regulatory commitments.

• Preventive maintenance, exciter brush vibration monitoring, and trending program improvements are being developed and will be implemented by February 20, 2004.

NFC FORM136A(1400})

Ex ek I Exelon Generation www.exeloncorp.corn Dresden Generating Station Nuclear 6500 North Dresden Road Monis. IL60450-976S Tel 815-942-2920 10 CFR 50.73 t

March 24, 2004 SVPLTR # 04-0009 U. S. Nuclear Regulatory Commission ATTN: Document Control Desk Washington, DC 20555-0001 Dresden Nuclear Power Station, Unit 3 Facility Operating License No. DRP-25 NRC Docket No. 50-249

Subject:

Licensee Event Report 2004-001-00, "Unit 3 Automatic Scram During Testing of the Main Turbine Master Trip Solenoid Valves' Enclosed Is Licensee Event Report 2004-001-00, 'Unit 3 Automatic Scram During Testing of the Main Turbine Master Trip Solenoid Valves,' for Dresden Nuclear Power Station. This event Is being reported in accordance with 10 CFR 50.73(a)(2)(iv)(A), "Any event or condition that resulted In manual or automatic actuation of any of the systems listed In paragraph

• (a)(2)(iv)(B) of this section."-

Should you have any questions concerning this report, please contact Jeff Hansen, Regulatory Assurance Manager, at (815) 416-2800.

Respectfully, Danny G/?ost Site Vice President:

Dresden Nuclear Power Station Enclosure.

cc: Regional Administrator- NRC Region IIII NRC Senior Resident Inspector - Dresden Nuclear Power Station.

................t ,11

NRC FORM 366 U.S. NUCLEAR REGULATORY APPROVED BY OBM NO. 3150.0104 EXP 7-31.2004

(-2001) COMMISSION EsSmlated burden per response to comply with tis mandatory hfonralon cllecton request 50 hours5.787037e-4 days <br />0.0139 hours <br />8.267196e-5 weeks <br />1.9025e-5 months <br />. Reporled lessons learned are ncorporated Irdo the process aensno nd led back to .idustry.Send comments regarding burden estmate to te Records Management Branch (F.

LICENSEE EVENT REPORT (LER) 6 ES, U3. Nudear Regulatry C , Washington, DC 205550001 or by Internet a-

.mall bi1nruc~gov, and to te Desk Offer, Of1ce of Infontaton and Aegutatory Alfairs, NEOBt0202 (3150.D104). 06fce of Management and Budget. Washnton. DC 20603. Ha

.neans used to kpose information cotlectn does not display a Currently varid OMB Control number, to NRC mnaynot conduct or sponsor, and a person Isnot reqired to respond to. to

.__ _ _ _ _ -kifo

_ _ _ _ _ _ _ _ _ _ _ _ _ _ _ nnation collecti n _ _ _ _ _ _ _ _ _ _ _

1. FACILITY NAME. 2. DOCKET NUMBER 3. PAGE Dresden Nuclear Power Station Unit 3 05000249 1of 4 4.TITLE Unit 3 Automatic Scram During Testing of the Main Turbine Masler Trip Solenoid Valves S.EVENT DATE 6. LER NUMBER 7.REPORT DATE aL OTHER FACILTIES INVOLVED u RE . FACILITY NAME DOCKET NUMBER MO DAY. YEAR YER IN/AUMER N MO Y YEAR NJA z .1.1 _ FACILITY NAME DOCKET NUMBER 01 24 2004 2004 - 001 - 00 03 24 2004 N/A NrA

9. OPERATING . _THIS REPORTIS SUMTED PURSUANTTO THE REOUIREMENTS O CFR6 (ChecsaIatsppy)

MODE - 20.2201(b) 20_2(aX3)(- 50.73(aX)2)(1iX) _ 50.73(aY2)Ix)_A) 1D. POWER . 20.2201(d) _ 20.2203CaX4) _ 50.73(aX2Xm) _ 50.73(aX2Xx)

LEVEL 096 - 20.2203(a)(i) 50.36(XXIXi)(A) X 60.73(aX2XhvXA) -73.71 (aXW4)

- . -20.2203(aY)(2k) -50.36(cXIXiI)(A) -50.73(a)(Xv)(vA) -73.71(a)X5)

.

• 20.2203(aX2KU)2 50.36(cX2) 50.73(a)12KvKB) OTHER

.. t .- Specify In Abstract below or In

20.2203(a)(2XlIi) 50A16(a)(3)W() 50.73(aW2WvyC) NRCFomn366A

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,. - 20.203(aX3)K) I 50.73(a)(2XllXA) I 50.73CA)(2XyIKdXB) .; *

12. LICENSEE CONTACT FOR THIS LER NAME TELEPHONE NUMBER (Include Area Code)

George Papanic Jr. (815 416-2815

13. COMPLETE ONE LINE FOR EACH COMPONENT FAILURE DESCRIBED IN THIS REPORT CAUSE SYSTEM COMPONENT FACTURER TO EPIX CAUSE SYSTEM COMPONET FACTURER TOEPIX B TG SOL G080 Y. _ ._:_._

14. SUPPLEMENTAL REPORT EXPECTED i 15. EXPE E MOTH DAY YEAR

.__ SUBMISSION I IYES If yes, complete EXPECTED SUBMISSION DATE) I X INO DATE l l . .

I6L ABSTRACT Limt to 1400 spaces. Le.. epproximately 15 stine-spaced typewritten fines)

On January 24, 2004, at 0037 hours4.282407e-4 days <br />0.0103 hours <br />6.117725e-5 weeks <br />1.40785e-5 months <br /> (CST), with Unit 3 at 96 percent power In Mode 1, an automatic scram occurred while performing the weekly surveillance of the Main Turbine Master Trip Solenoid Valves. The surveillance testing was performed In accordance with procedure DOS 5600-02, OPeriodic Main Turbine, EHC and Generator Tests.* The event was caused byap malfunction of the Main Turbine Master Trip Solenold Valves, which resulted In the depressurization of the Emergency Trip Supply hydraulic header and the resulting momentary closure of the Main Turbine Stop Valves below 90 percent full open. The Reactor Protection System actuated as a result of the Main Turbine Stop Valve position and, as designed, automatically scrammed the reactor. The plant responded as expected to the automatic scram.

The root cause of the malfunction of the Main Turbine Master Trip Solenoid Valves was attributed to an Improperly designed position switch rod and its associated housing by the Original Equipment Manufacturer, General Electric. The corrective actions to prevent reoccurrence are to replace the Main Turbine Master Trip Solenoid Valves with valves of a different design.

The safety significance of this event was rninimal. All control rods fully Inserted and all systems responded as expected to the automatic scram. There were no subsequent major equipment malfunctions.

NRC FORM 366A U.S. NUCLEAR REGULATORY COMMISSION (m.2OOn LICENSEE EVENT REPORT (LER)

1. FACILITY NAME 2. DOCKET NUMBER 6. LER NUMBER 3. PAGE YEAR iSEUENTIL REVISION Dresden Nuclear Power Station Unit 3 05000249 NUMBER NUMBER

.2004 001- 00 2of4

17. NARRATIVE (If more space Is required, use additional copies of NRC Form 366A)

Dresden Nuclear Power Station Unit 3 is a General Electric Company Boiling Water Reactor with a licensed maximum power level of 2957 megawatts thermal. The Energy Industry Identification System codes used In the text are Identified as

• is.

A. Plant Conditions Prior to Event:

Unit: 03 Event Date: 01-24-2004 Event Time: 0037 CST Reactor Mode: I Mode Name: Power Operation Power Level: 96 percent Reactor Coolant System Pressure: 1000 pslg B. Descrintion of Event:

Dresden Nuclear Power Station (Dresden) and other Exelon stations have been experiencing performance issues with their Main Turbine Master Trip Solenoid Valves (MTSVs) ITG] [SOL]. The cause of the poor solenoid performance was determined to be a 'silting' phenomenon. General Electric (GE), the Original Equipment Manufacturer, was-requested to evaluate the Silting' condition and find an alternate design to improve the solenoid performance. GE responded to this request by proposing the use of poppet solenoid MTSVs to replace the

• existingspool solenoid MTSVs. GE Indicated that, unlike the spool valve, a poppet valve Is not prone to stick due to its Inherent design. The poppet solenoid valve has a line-contact on its seating surface verses a sliding surface contact with tight clearance tolerances on a spool solenoid valve.

GE successfully tested the poppet solenoid MTSVs. However, after completing the testing, GE modified the position switch on the original poppet solenoid valve assembly. This modification was done to eliminate the need of additional cables to power the position switch. The modified position switch was never tested on the test assembly. GE's evaluation concluded that the new poppet solenoid MTSV was a direct replacement for the currently used spool solenoid MTSV.

In September 2003, LaSalle County Station (LaSalle) was preparing for a Unit 2 outage and performed pre-Installation testing of the poppet solenoid MTSVs. During pre-installation testing, LaSalle Identified that the position switch on the poppet valve assembly was not functioning. GE suspected that the target area at the end of the switch rod was too small for it to function properly and decided to Increase the target area of the switch.

LaSalle returned the poppet solenoid MTSVs for switch modification and the poppet solenoid MTSVs were not installed.

In October 2003, Dresden performed pre-installation testing on the poppet solenoid MTSVs and found that the limit switch was still not functioning properly, even after the target area on the rod end had been increased based on the LaSalle experience. Further Investigation revealed that the switch adapter material should have been stainless steel Instead of carbon steel. GE agreed to make the adapter material change but additional testing following the change by GE was not performed.,

On October 21, 2003, Dresden Unit 2 was In a refueling outage and the MTSVs were replaced wlith the poppet solenoid MTSVs. Post maintenance testing was performed satisfactorily without any problems.

On November 18, 2003, during weekly testing on Unit 3 per procedure DOS 5600-02, oPerlodic Main Turbine, EHC and Generator Tests, MTSV 'Aw failed to trip. 'The cause of this MTSV failure to trip was determined to be

'silting.' Based on this, Dresden engineering recommended that the Unit 3 MTSVs be replaced with poppet solenoid MTSVs during the upcoming maintenance outage In December 2003.

NRC FORM 366A U.S. NUCLEAR REGULATORY COMMISSION (7)001)

LICENSEE EVENT REPORT (LER)

1. FACILITY NAME 2. DOCKET NUMBER 6. LER NUMBER 3. PAGE YEAR SEQUENTIL REVISION Dresden Nuclear Power Station Unit3 . 05000249 NUMBER NUMSER

. 2004 001 00 3of 4

17. NARRATIVE (Ifmore space Isrequired, use additional copies of NRCForm 366A)

On December 12,2003, the Unit 3 MTSVs were replaced with poppet solenoid MTSVs. Post maintenance testing was performed with satisfactory results.

From November 2003 to January 23.2004, Dresden Unit 2 successfully tested the poppet solenoid MTSVs during nine weekly on-line tests and Dresden Unit 3 successfully tested the valves during four weekly on-line tests.

On January 24. 2004, at 0037 hours4.282407e-4 days <br />0.0103 hours <br />6.117725e-5 weeks <br />1.40785e-5 months <br /> (CST), with Unit 3 at 96 percent power In Mode 1, an automatic scram occurred while performing the weekly surveillance of the MTSVs. The surveillance testing was performed In accordance with applicable site procedures. The scram was caused by the momentary closure of the Main Turbine Stop Valves below 90 percent full open. The Reactor Protection System actuated as a result of the Main Turbine Stop Valve position and as designed, automatically scrammed the reactor. The plant responded as expected to the automatic scram.

An Emergency Notification System (ENS) call was made on January 24,2004, at 0222 hours0.00257 days <br />0.0617 hours <br />3.670635e-4 weeks <br />8.4471e-5 months <br /> (CST) for the above-described event. The assigned ENS event number was 40474.

Post trip testing confirmed that the cause of the automatic scram was the result of the poppet solenoid MTSVs malfunctioning. Dresden decided to replace the Unit 3 poppet solenoid MTSVs with spool solenoid MTSVs. The decision was based in part on, the failure mode associated with the poppet solenoid MTSVs was not applicable to the spool solenoid MTSVs. The spool solenoid MTSVs are Installed on all GE turbines of similar design to Dresden's turbine and, except for occasional sticking, the performance of the spool solenoid MTSVs has been satisfactory. The unit was synchronized to the grid on January 25,2004 at 1324 hours0.0153 days <br />0.368 hours <br />0.00219 weeks <br />5.03782e-4 months <br /> (CST).

This event Is being reported in accordance with 10 CFR 50.73(a)(2Xiv)(A), Any event or condition that resulted in manual or automatic actuation of any of the systems listed Inparagraph (a)(2)(iv)(B) of this section." The

automatic actuation of the reactor protection system Islisted in 10 CFR 50.73(a)(2)(iv)(B).

Dresden Unit 2 Is scheduled to replace Its Installed poppet solenoid MTSVs with the spool s6lenoid MTSVs during a maintenance outage. Dresden has completed an engineering evaluation that permits the suspension of MTSV testing until the MTSVs are replaced.

Additionally to resolve the "silting issue, Dresden replaced the existing electro-hydraulic fluid with higher temperature rated synthetic fluid, cleaned the fluld reservoirs and replaced the filter cartridges with a different designed cartridge In October 2003 on Unit 2 and December 2003 on Unit 3.

C. Cause of Event:

The root cause of the malfunction of the poppet solenoid MTSVs was attributed to an Improperly designed position switch rod and Its associated housing by the Original Equipment Manufacturer, GE.

The two poppet solenoid MTSVs that were removed from-Dresden Unit 3 and two poppet solenoid MTSVs that had not been Installed were subjected to failure analysis testing. The failure analysis testing Included response time testing, disassembly to Inspect for foreign material and overall Inspection of the Internal valve components.

The results of the testing were as follows.

The poppet solenoid MTSVs were bench tested to determine if their response times were In the range of 40 to 60 millisecond. A high response time of the poppet valve Is a concern as the poppet solenoid

NRC FORM 366A U.S. NUCLEAR REGULATORY COMMISSION 17.2001)

LICENSEE EVENT REPORT (LER)

1. FACILITY NAME 2. DOCKET NUMBER 6. LER NUMBER 3. PAGE YEAR SEQUENTIAL REVISION.

Dresden Nuclear Power Station Unit 3 05000249 NUMBER . NUMBER 2004 001 00 4 of 4

17. NARRATIVE (If more space is required, use additional copies of NRC Form 366A)

MTSVs design momentarily ties the pressure and drain ports together. If the ports are tied together for a sufficient time, the Emergency Trip Supply hydraulic header will depressurize. One of the poppet solenoid MTSVs removed from Dresden Unit 3 had a response time of 200 milliseconds.

• An optical microscope inspection of the poppet solenoid MTSVs did not reveal any foreign material around the valve seat area. Additionally, the inspection found no indication of tearing or deterioration of the internal o-rings and backing rings.

• The overall visual inspection revealed that the Internal position switch rod was bent on all four valves.

Further examination revealed that the target could catch on threads within the switch housing. This defect would cause the observed delay In the response time of the valves;

• GE determined that the damage to the Internal components most probably occurred during manufacturing.

The high response time of the poppet valves cn Unit 3 caused the pressure and drain ports to be tied together for a sufficient Utme to cause the Emergency Trip Supply hydraulic header to depressurize and resulted in the momentary closure of the Main Turbine Stop Valves below 90 percent full open.

D. Safety Analysis:

The safety significance of this event was minimal. All control rods fully Inserted and all systems responded as expected to the automatic scram. There were no subsequent major equipment malfunctions. Therefore, the consequences of this event had minimal Impact on the health and safety of the public and reactor safety.

E. Corrective Actions:

The poppet solenoid MTSVs were replaced with spool solenoid MTSVs on Dresden Unit 3.

The poppet solenoid MTSVs will be replaced with the spool solenoid MTSVs during a scheduled maintenance outage on Dresden Unit 2.

An engineering evaluation was completed to permit the suspension of MTSV testing on Unit 2 until the poppet solenoid MTSVs are replaced with spool solenoid MTSVs.

. Previous Occurrences:

A review of Dresden Nuclear Power Station Licensee Event Reports (LERs) and operating experience over the previous five years did not find any similar MTSV occurrences.

G. Component Failure Data:

GE poppet solenoid MTSV Part Number 378A3294PD001

I /5, Exelkn.

Exelon Generation Company. LLC www.exeloncorp.com Nuclear Dresden Nudear Power Station 6500 North Dresden Road Morris. IL60450-9765 10 CFR 50.73 March 30, 2004 SVPLTR: #04-0013

.U.S. Nuclear Regulatory Commission ATTN: Document Control Desk Washington, DC 20555-0001 Dresden Nuclear Power Station, Units 2 and 3 Facility Operating License Nos. DRP-19 and DRP-25 NRC Docket Nos. 50-237 and 50-249

Subject:

Licensee Event Report 2004-002-00, "Unit 3 Automatic Scram Due To Main Turbine Low Oil Pressure Trip and Subsequent Discovery of Inoperability of the Units 2 and 3 High Pressure Coolant Injection Systems' Enclosed Is Licensee Event Report 2004-002-00, 'Unit 3 Automatic Scram pue To Main Turbine Low Oil Pressure Trip and Subsequent Discovery of Inoperabilityof the Units 2 and 3 High Pressure Coolant Injection Systems,' for Dresden Nuclear Power Station. These events are being reported In accordance with 10 CFR 50.73(a)(2)(iv)(A), 'Any event or condition that resulted In manual or automatic actuation of any of the systems listed in paragraph (a)(2)(iv)(B) of this section,' and 10 CFR 50.73(a)(2)(v)(D), 'Any event or condition that could have prevented the fulfillment of the safety function of structures or systems that are needed to mitigate the consequences of an accident.'

Should you have any questions concerning this report, please contact Jeff Hansen, Regulatory Assurance Manager, at (815) 416-2800.

Respectfully, Danny Site I President ALsG Dr en Nuclear Power Station Enclosure cc: Regional Administrator- NRC Region IlIl NRC Senior Resident Inspector - Dresden Nuclear Power Station

NRC FORM 366 U.S. NUCLEAR REGULATORY APPROVED BY OBM NO. 3150.0104 EXP 7431.2004 (r-20013 :COMMISSION Estrnated burden per response to comply ft lu mandatory offnation odlecton request 50 hour5.787037e-4 days <br />0.0139 hours <br />8.267196e-5 weeks <br />1.9025e-5 months <br />. Reported lessons learned are Icorporated Ito te censng process and led back I hdus.

n Send corments regardng burden estimate to Ihe Records Management Branci (rT LICENSEE EVENT REPORT (LER) 6E6),US; Nucear Regulatory Commson, Washington, DC 20555.001 or by Intemet e.

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- ;number, hie NRC may not conduct or sponsor, and a person Isnot required to respond to, ti

________________________________________________ Wrmation cofeclon._______________

1. FACILITY NAME .2. DOCKET NUMBER . .PAGE

.. Dresden Nuclear Power Station Unit 3 05000249 lof 5 1

4.rm.E Unit 3 Automatic Scram Due To Main Turbine Low Oil Pressure Trip and .:

Subsequent Discovery of Inoperability of the Units 2 and 3 High Pressure Coolant Iniection Systems

5. EVENT DATIE C . LER NUMBER 7. REPORT DATE l S.OTHER FACILITES INVOLVED I..RE 1FACILITY NAIE DOCKET NUMBER Z. 11111 l

MO -DAY: YEAR ~j~ N UMNO V MO DAY YEAR Dresden Unit 2 05000237 FACILITY NAME DOCKET NME 01 30 2004 2004 -002 -00 03 30 2004 NIA j N/A 9, OPERATING _ 11, THIS REPORT ISSUBMITED PURSUANT TOz TH ERECUIREMENTS OF i10 CF'R 5: (Coeok all tat a*pl)

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my1.1LCENSEE CONTACT FOR THIS LER-NAME -TELEPHONE NUMBER (lacude Area Cede)

George Pa anic Jr. - 815)416-2815.

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13. COMPLETE ONE LINE FOR EACH COMPONENT FAILUIRF DESCRIBED) IN THIS REPORT 1

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14. SUP'PLEMENTALLREPORT EXPECTED 15.EXPECTED l ONTHl AY YEAR IYES (If yes. complete EXPECTED SUBMISSION DATE) lX INO l DATE l I l l __

16. ABSTRACT (LMAR to 1400 spaces. I.e. approxmaely 15 slngre-spaced typewrflten lGnes)

On January 30, 2004,: at 11 55 hours6.365741e-4 days <br />0.0153 hours <br />9.093915e-5 weeks <br />2.09275e-5 months <br /> (CST). with Unit 3 at 97 percent power hii Mode 1, an automatic scram occurred due to a Main Turbine trip from low lube oil pressure. The event occurred during a swapping of lube oil coolers. After the scram, reactorwater level increased above the Reactor Feed Pump High Level trip set point. Reactor water level was subsequently restored to normal and the Reactor Feed Pumps were restarted.

On February 1, 2004, at 0400 hours0.00463 days <br />0.111 hours <br />6.613757e-4 weeks <br />1.522e-4 months <br /> (CST), subsequent Investigations into the.January 30, 2004, event determined that the High Pressure Coolant Injection Systems for Dresden Units 2 and 3 were Inoperable. The inoperability was due to evaluations that determined that the Feedwater Level Control System would not maintain the post scram reactor water level below that which would prevent water from entering the High Pressure Coolant Injecti6n System's turbine steam line.

The root cause of the automatic scram was Inadequate procedural guidance for the swapping of Main Turbine lube oil coolers. The root cause of the High Pressure Coolant Injection System Inoperability was low margin in the Feedwater Level Control System to accommodate changes to the post-scram vessel level response. The corrective action to prevent reoccurrence of the scram is to modify procedure DOP 5100-04, "Turbine Oil Cooler Operation. The corrective action to prevent reoccurrence of the High Pressure Coolant Injection Systems Inoperability Is to modify the post-scram response of the Feedwater Level Control System.

NRC FORM 366A U.S. NUCLEAR REGULATORY COMMISSION LICENSEE EVENT REPORT (LER)

1. FACILITY NAME 2. DOCKET NUMBER 6. LER NUMBER 3. PAGE YEAR SEQUENA REVISION Dresden Nuclear Power Station Unit 3 05000249 . NUMBER NUMBER 2004 002 00 2 of 5

17. NARRATIVE (If more space Is requied, use addional copies of NRC Form 356A)

Dresden Nuclear Power Station Units 2 and 3 are General Electric Company Boiling Water Reactors with a licensed maximum power level of 2957 megawatts thermal. The Energy Industry Identification System codes used In the text are Identified as pq..

A. Plant Conditions Prior to Event:

Unit: 03 Event Date: 1-30-2004 Event Time: 1155 CST Reactor Mode: 1 Mode Name: Power Operation Power Level: 97 percent Reactor Coolant System Pressure: 1000 psig B. Description of Event:

On January 30, 2004, the Shift Manager decided to swap the Unit 3 Main Turbine Lube Oil Coolers [TD] as the Turbine Oil Continuous Filter Differential Pressure had been increasing for several days. On January 30, 2004, at 1155 hours0.0134 days <br />0.321 hours <br />0.00191 weeks <br />4.394775e-4 months <br /> (CST), with Unit 3 at 97 percent power In Mode 1, an automatic scram occurred due to a Main Turbine trip from low lube oil pressure. The event occurred during a swapping of lube oil coolers. Immediately following the scram, the position of the Feedwater Regulating Valves (FRVs) [SJt Increased from 56 percent (%) open to 63 %. The Increase In the position of the FRVs, combined with the post-scram decreasing reactor pressure, caused an increase In total feedwater flow that led to the trip of the 'B' Reactor Feedwater Pump (RFP) [P] on low suction pressure. Additionally, subsequent FRVs response to increasing reactor vessel level was not fast enough to prevent the level from reaching the RFP High Level trip set point and resulted In the tripping of the 'A and "C' RFPs. Reactor water level was subsequently restored to normal and the RFPs were restarted. All rods Inserted and other than the feedwater response, all other system responded as expected to the automatic scram.

An Emergency Notification System (ENS) call was made on January 30,2004, at 1335 hours0.0155 days <br />0.371 hours <br />0.00221 weeks <br />5.079675e-4 months <br /> (CST) for the above-described scram event. The assigned ENS event number was 40491.

On February 1, 2004, at 0400 hours0.00463 days <br />0.111 hours <br />6.613757e-4 weeks <br />1.522e-4 months <br /> (CST), subsequent Investigations into the January 30, 2004 event determined that the High Pressure Coolant Injection (HPCI) Systems [BJ] for Dresden Units 2 and 3 were Inoperable. An evaluation by engineering determined that the Feedwater Level Control System (FWLCS) [SJ] would not maintain the post-scram reactor water level below that which would prevent water from entering the HPCI turbine steam line. Dresden Units 2 and 3 have separate HPCI nozzles in the reactor vessels that are located approximately 50 Inches below the main steam nozzles. Technical Specification (TS) 3.5.1, 6ECCS-Operating, requires HPCI operable in Modes 1, 2 and 3 with reactor steam dome pressure greater than 150 pounds per square Inch gage (psig). At the time of discovery, Unit 2 was In Mode I and Unit 3 was In Mode 4.

An ENS call for Unit 2 was made on February 1, 2004, at 0854 hours0.00988 days <br />0.237 hours <br />0.00141 weeks <br />3.24947e-4 months <br /> (CST) for the above-described HPCI event.

The assigned ENS event number was 40494.

The Units 2 and 3 FWLCS post-scram level setpoints were modified on February 2,2004 and HPCI was declared operable. Unit 3 was synchronized to the grid on February 2,2004, at 1813 hours0.021 days <br />0.504 hours <br />0.003 weeks <br />6.898465e-4 months <br /> (CST).

These events are being reported In accordance with:

• 10 CFR 50.73(a)(2)(iv)(A), Any event or condition that resulted in manual or automatic actuation of any of the systems listed in paragraph (a)(2)(iv)(B) of this section." The automatic actuation of the reactor protection system Is listed In 10 CFR 50.73(a)(2)(lv)(B).

NRC FORM 366A U.S. NUCLEAR REGULATORY COMMISSION LICENSEE EVENT REPORT (LER)

1. FACILITY NAME 2.DOCKETNUMBER . 6. LER NUMBER 3.PAGE YEAR SEQUENTIAL REVISION Dresden Nuclear Power Station Unit 3 05000249 NUMBER NUMBER 2004 002 00 3 of 5

17. NARRATIVE (Ifmwre space Is requdred, use addtional copies of NRC Form 366A)

• 10 CFR 50.73(a)(2)(v)(D), Any event or condition that could have prevented the fulfillment of the safety function of structures or systems that are needed to mitigate the consequences of an accident." The HPCI Is a single train system and the water was in the HPCI turbine steam line for approximately 20 minutes.

C. Cause of Event:

The root cause of the scram event was Incorrect procedural guidance In Dresden Operating Procedure DOP 5100-04 'Turbine Oil Cooler Operation." The procedure directs the operator to stop filling the oncoming Main Turbine lube oil cooler prior to swapping. This caused air to be Induced into the oncoming lube oil cooler from the hot lube-oil volume being cooled by cold service water, and resulted In the Main Turbine trip from low lube oil pressure.

This procedural guidance had been in place since 1991 and had been used approximately seven times since 1999. However, system realignment had only occurred once in the month of January.

The root cause of the HPCI Inoperability was low margin In the FWLCS to accommodate changes to the post-scram vessel level response. The FWLCS Is designed to respond to a scram by adjusting the vessel level set point from +30 inches to +5 inches and then after approximately 2 seconds, to lock the FRVs in place for approximately 15 seconds. After 15 seconds, the valve demand signal positions the FRVs at 30% of their previous position. At that time, the FWLCS reverts to controlling In the normal mode where the FRVs are positioned based on the rate of change Invessel level and the difference between the vessel level and the FWLCS set point.

Following the reactor scram on January 30, 2004, the following occurred.

• The position of the FRVs Immediately Increased from 56% open to 63% open during the approximately 2 seconds it takes for the FWLCS to lock the FRVs In place for 15 seconds. During this period, the Increase Inthe position of the FRVs, combined with decreasing reactor pressure, caused an Increase Intotal feedwater flow that led to the trip of the *B RFP on low suction pressure. A RFP had not tripped on previous similar scrams, as the similar scrams occurred prior to the need to operate with 3 RFPs at full power.

• The FRVs began to close from 63% open at approximately 16 seconds after the scram signal due to the pulse down signal from the FWLCS to reposition the FRVs to 30% of their previous position. The FRVs never reached 30% of the previous position because at 24 seconds after the scram, FWLCS signaled the valves to reopen. At approximately 30 seconds after the scram signal the FWLCS signaled the FRVs to close. However, the rate at which the FRVs closed was not fast enough to prevent overfilling the vessel, tripping the FA and "CO RFPs on high water level, and putting water into the HPCi steam supply line.

The FWLCS operated as designed during this event. The condition that the FWLCS had low margin to accommodate changes to the post-scram vessel level response was not known prior to this event because no analytical model capable of predicting the dynamic Interaction between the FWLCS and other factors affecting vessel level was available. This resulted in the failure to adequately evaluate or test the post-scram response of the FWLCS prior to Implementation of 3 RFP operation.

The Immediate corrective actions for Units 2 and 3 were to lower the FWLCS post-scram vessel level set point from +5 Inches to -10 inches. These set point changes provide reasonable assurance that a vessel overfill event will not recur.

NRC FORM 366A U.S. NUCLEAR REGULATORY COMMISSION (7C2ar)

LICENSEE EVENT REPORT (LER)

1. FACILITY NAME 2. DOCKET NUMBER 6. LER NUMBER 3. PAGE YEAR EQUENTIAL REVISION Dresden Nuclear Power Station Unit 3 . 05000249 NUMBER NUMBER 2004 002 00 4 of 5

17. NARRATIVE (If more space Is required, use addiional copies of NRC Form 366A)

The corrective action to prevent reoccurrence is to re-design the FWLCS post-scram response. Exeon

.:Engineering will develop a dynamic model capable of accurately predicting the response of the FWLCS. This model will be benchmarked against the two most recent scrams and used to optimize the re-design. The modifications to Install the Improved FWLCS design will be Implemented If necessary, during the next refueling outage of each unit or outage of sufficient duration after the development of the analytical model to predict the Interaction of the FWLCS and post scram vessel level response.

D. Safety Analysis:

The safety significance of the scram event was minimal. All control rods fully Inserted and other than the feedwater response, all systems responded as expected to the automatic scram.

The safety significance of the HPCI inoperability event was minimal. For Dresden Units 2 and 3,2 transients and 2 design basis accidents have the potential for water carryover Into the HPCI steam line and assume the avallablity of the HPCI for redundant long term Inventory make-up. For these events, a conservative analysis has been performed using Automatic Depressurization System and low pressure Emergency Core Cooling Systems as an alternate core cooling sequence that demonstrates there is a substantial margin to predicted cladding perforation.

Therefore, the consequences of these events had minimal Impact on the health and safety of the public and reactor safety.

E. Corrective Actions:

Procedure DOP 5100-04 has been revised.

The Immediate corrective actions for Units 2 and 3 were to lower the FWLCS post-scram level set point from +5 Inches to -10 Inches.

Exelon will develop an analytical model to predict the Interaction of the FWLCS and post scram vessel level response and If necessary, the FWLCS post-scram response will be modified.

F. Previous Occurrences:

A review of Dresden Nuclear Power Station Licensee Event Reports (LERs) and operating experience over the previous five years did not find any similar occurrences associated with the Main Turbine Lube Oil Coolers.

A review of Dresden Nuclear Power Station LERs Identified that the most recent LER associated with the FWLCS and a reactor vessel high water level was LER 98-003-00, Reactor Scram Results from MSIV Closure Caused by a Spurious Group I Isolation Signal due to Inadequate Preventive Maintenance.' Following the scram, a feedwater transient occurred which resulted In water entering the HPCI steam supply line. The LER corrective actions Included modifications to the FWLCS. The actions were successful In preventing water from entering the HPCI steam supply line during. subsequent .

similar scram events when the plant was operated with 2 RFPs.

NRC FORM 366A U.S. NUCLEAR REGULATORY COMMISSION LICENSEE EVENT REPORT (LER)

1. FACILITY NAME 2. DOCKETNUMBER 6. LER NUMBER 3. PAGE YEAR SEQUENTIAL REVISION Dresden Nuclear Power Station Unit3. 05000249 . NUMOER NUMBER 2004 002 00 5o15

17. NARRATIVE (if more space Isrequired, use additional copies of NRC Forn 366A)

G. Component Failure Data:

NA

IA Exelkn.

Exelon Generation Company, LLC www.exeloncorp.com Nuclear Dresden Nuclear Power Station.

6500 North Dresden Road Morris, 11.604SO-976S 10 CFR 50.73 July 6, 2004 SVPLTR: #04-0045 U. S. Nuclear Regulatory Commission ATTN: Document Control Desk Washington, DC 20555-0001 Dresden Nuclear Power Station, Units 2 and 3 Facility Operating License Nos. DRP-19 and DPR-25 NRC Docket Nos. 50-237 and 50-249

Subject:

Licensee Event Report 2004-003-00, "Unit 3 Scram Due to Loss of Offsite Power and Subsequent Inoperability of the Standby Gas Treatment System for Units 2 and S' Enclosed is Licensee Event Report 2004-003-00, 'Unit 3 Scram Due to Loss of Offsite Power and Subsequent Inoperability of the Standby Gas Treatment System for Units 2 and 3, for Dresden Nuclear Power Station. This event is being reported In accordance with 10 CFR 50.73(a)(2)(iv)(A), mAny event or condition that resulted In manual or automatic actuation of any of the systems listed In paragraph (a)(2)(lv)(B) of this section, and 10 CFR 50.73(a)(2)(i)(B),

-Any operation or condition which was prohibited by the plant's Technical Specifications."

Should you have any questions concerning this report, please contact Jeff Hansen, Regulatory Assurance Manager, at (815):416-2800.

Respectfully, Danny G. Bost Site Vice President Dresden Nuclear Power Station Enclosure cc: Regional Administrator.- NRC Region IlIl NRC Senior Resident Inspector - Dresden Nuclear Power Station

I .. I NRC FORM 366 U.S. NUCLEAR REGULATORY APPROVED BY OBM NO. 3150-0104 EXP 7-31-2004 oouI COMMISSION Estmated burden per response IDcomply with ts mandatory Information collection request 50 hours5.787037e-4 days <br />0.0139 hours <br />8.267196e-5 weeks <br />1.9025e-5 months <br />. Repored lessons learned are kIcoporated Into fte lensn process and fed back N REO LICENSEE EVENT RE RT6(L tondustry.

IE Send comments regardit burden estimate toteRecords Management Branch (T.

U. Nuear RegaoqC omsn. WashIgton. 00 20555-X101 or by Internet e

. . ~maflt blonro rcgv,anbtohe Dek Ofcer, Ofcefdnfronration end Regdatory pairs,

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. . .nunber, the NRC may not conduct or sponsor, and a person Isnot requied to respond lo, the

1. FACILITY NAME 2. DOCKET NUMBER 3. PAGE Dresden Nuclear Power Station Unit 3 05000249 1 of 4 4.mLE Unit 3 Scram Due to Loss of Offsfte Power and Subsequent Inoperability of the Standby Gas Treatment System for Units 2 and 3

. EVENT DATE  :. LER NUMBER 7.REPORT DATE S.OThER FACILITIES INVOLVED 1 FACILITY NAME DOCKET NUMBER MO DAY YEAR jEAR INujem NO MO DAY YEAR Dresden Unit 2 J 05000237 l FACILITY NAME DOCKET NUMBER 05 05 2004 2004 -003 00 07 06 2004 N/A N1A W

S. OPERATING .. THIS REPORT IS SUBMrITED PURSUANTTO THE RECUIREMENTS OF 1C oP c Check all thaapply)

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12. ICENSEE CONTACT FOR THIS LER NAME TELEPHONE NUMBER (Include Area Code)

George Papanic Jr. (815 416-2815

13. COMPLETE ONE UNE FOR EACH COMPONENT FAILURE DESCRIBED IN THIS REPORT M"'1- VOMSEO-' RM"AME CAUSE X

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14. SUPPLEMENTAL REPORT EXPECTED 1005 N .L.

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- E TO epix YEAR X YES (it Ys, complete EXPECTED SUBMISSION DATE) l NO DATE 10 30 2004

16. ABSTRACT Q(LrA to 1400 spaces. L.,approdmatety 15 single-spaced typewiten Enes)

On May 5, 2004, at 1327 hours0.0154 days <br />0.369 hours <br />0.00219 weeks <br />5.049235e-4 months <br /> (CDT), with Unit S at 100 percent power in Mode I, an automatic scram occurred due to a Main Generator Load Reject when a loss of of site power occurred. The Emergency Diesel Generators automatically started and powered their respective electrical busses. Al control rods fully Inserted and Group 1.11 and Ill Isolations occurred as expected. Operations personnel manually Initiated the Isolation Condenser System for reactor pressure control, the High Pressure Coolant Injection System for reactor water level control, and the Low Pressure Coolant Injection System for Torus cooling. LAl systems initially responded to the scram as expected except the Standby Gas Treatment System was unable to maintain the Secondary Containment at the Technical Specification Surveillance Requirement lmit of greater than or equal to 0.25 Inches of vacuum water gauge. An Unusual Event for the loss of offsite power was declared at 1342 hours0.0155 days <br />0.373 hours <br />0.00222 weeks <br />5.10631e-4 months <br /> (CDT) and terminated at 1601 hours0.0185 days <br />0.445 hours <br />0.00265 weeks <br />6.091805e-4 months <br /> (CDT) on May 5, 2004. Additionally, during restoration of offsite electrical power to Bus 33, the Emergency Diesel Generator 2/3 output electrical breaker tripped.

The root causes associated with the load reject and loss of offsite power and the low Secondary Containment vacuum were respectively, equipment failure Inthe *Cm phase of the 345 kilovolt circuit breaker 8-15 and a degraded Secondary Containment boundary not detected due to an inadequate leak rate test procedure. The cause of the Emergency Diesel Generator output breaker trip remains under Investigation.

NRC FORM 366A -U.S.NUCLEAR REGULATORY COMMISSION (7.2001)

LICENSEE EVENT REPORT (LER)

I. FACIUTY NAME 2. DOCKET NUMBER 6. LER NUMBER 3. PAGE YEAR SEQUENTIAL REVISION Dresden Nuclear Power Station Unit 3 0000249 NUMBER NUMBER 2004 003 °° 2of4

17. NARRATIVE (1Imore space Is required, use additional copies of NRC Form 366A)

Dresden Nuclear Power Station (DNPS) Units 2 and 3 are a General Electric Company Boiling Water Reactor with a licensed maximum power level of 2957 megawatts thermal. The Energy Industry Identification System codes used in the text are Identified as [XXJ.

Al Plant Conditions Prior to Event:

Unit: 03 Event Date: 5-5-2004 Event Time: 1327 CDT Reactor Mode: 1 Mode Name: Power Operation Power Level: 100 percent Reactor Coolant System Pressure: 1000 psig B. Description of Event:

On May 5, 2004, electrical breaker switching was being performed Inthe DNPS switchyard to support the testing of a 345 kilovolt (kv) offsite electrical line. A loss of offsite power (LOOP) occurred to Unit 3 when 345 kv breaker 8-15 [BKRI located in the switchyard [FK] was opened.

On May 5, 2004, at 1327 hours0.0154 days <br />0.369 hours <br />0.00219 weeks <br />5.049235e-4 months <br /> (CDT), with Unit 3 at 100 percent power InMode 1, an automatic scram occurred due a Main Generator Load Reject when the LOOP occurred. The Emergency Diesel Generators (EDGs) [DGJ automatically started and powered their respective electrical busses. All control rods fully inserted and Group I, 1I and IlI isolations occurred as expected. Operations personnel manually Initiated the Isolation Condenser System

[BL] for reactor pressure control, High Pressure Coolant Injection System [BJJ for reactor water level control, and Low Pressure Coolant Injection System [BOJ for Torws cooling. All systems Initially responded as expected to the scram except for the Standby Gas Treatment System (SGT) [Bi] that was unable to maintain the Secondary Containment at the Technical Specification Surveillance Requirement limit of greater than or equal to 0.25 inches of vacuum water gauge. Secondary containment was declared inoperable for Units 2 and 3.

An Unusual Event for the LOOP was declared at 1342 hours0.0155 days <br />0.373 hours <br />0.00222 weeks <br />5.10631e-4 months <br /> (CDT). An ENS call was made at 1429 hours0.0165 days <br />0.397 hours <br />0.00236 weeks <br />5.437345e-4 months <br /> (CDT) for the above-described event. The assigned ENS event number was 40727.

At 1558 hours0.018 days <br />0.433 hours <br />0.00258 weeks <br />5.92819e-4 months <br /> (CDT), the EDG 213 output electrical breaker tripped on reverse power during restoration of offsite electrical Power to Bus 33 that was being fed from EDG 2/3. Bus 33 remained powered from the offsite source.

The Unusual Event was terminated at 1601 hours0.0185 days <br />0.445 hours <br />0.00265 weeks <br />6.091805e-4 months <br /> (CDT) when offsite power was restored to Unit S.

At 1630 hours0.0189 days <br />0.453 hours <br />0.0027 weeks <br />6.20215e-4 months <br /> (CDT), SGT was declared operable when the Secondary Containment pressure was restored to greater than 0.25 Inches of vacuum water gauge.

This event is being reported In accordance with:

• 10 CFR 50.73(a)(2)(iv)(A) Any event or condition that resulted in manual or automatic actuation of any of the systems listed In paragraph (a)(2)(1y)(B) of this section," and

• .10 CFR 50.73(a)(2)(1(B), "Any operation or condition which was prohibited by the plants Technical Specifications."

)

NRC FORM 366A -U.S. NUCLEAR REGULATORY COMMISSION (7-2001)

LICENSEE EVENT REPORT (LER)

1. FACILITY NAME 2. DOCKET NUMBER 6. LER NUMBER 3. PAGE YEAR IR6EQUENTIAL FIEVISION Dresden Nuclear Power Station Unit 3 05000249 NUMBER 2004 003 00 3 of 4

17. NARRATIVE (It more space Is required, use additional copies of NRC Form 366A)

These events are addressed Inthe NRC Special Inspection Report Number 0500024912004009 dated June 21, 2004.

C. Cause of Event:

The root causes associated with the load reject and LOOP and the low Secondary Containment vacuum were respectively, equipment failure In the NC" phase of the 345 kv circuit breaker 8-15 and a degraded secondary containment boundary not detected due to an Inadequate leak rate test procedure. The cause of the EDG output breaker trip is still under Investigation.

The equipment failure of the 345 kv circuit breaker 8-15 circuit breaker occurred due to age-related and application related degradation. The vendor, prior to the event, did not provide Information to Exelon Corporation, a product advisory Issued InJuly2003, regarding the possibility of breaker slow operation or failure to operate; This Is applicable to circuit breakers 8-15 and 6-7. The corrective action to prevent reoccurrence Is to revise the preventative maintenance procedure governing both circuit breakers 8-15 and 6-7 to Implement the product advisory recommendations.

The degraded-secondary containment boundary resulted from air in-leakage into the Unit 2 Drywell and Torus Purge Exhaust (DTPE) filter housings. At the time of the event, Unit 2 was in a maintenance outage and the DTPE fans were In operation due to activities Inthe Unit 2 drywell. The DTPE fans are not normally In operation and the secondary containment leak rate test procedure does not test with the DTPE fans operating as a part of the secondary containment barrier. Two corrective actions to prevent reoccurrence are being taken:

The first Is to modify the current design to trip the DTPE fans on both units following an automatic SGT system initiation from either unit, rather than operate the DTPE fans during the secondary containment leak rate test. The second action Is to develop a source document that clearly Identifies the secondary containment boundaries.

D. Safety Analvsis:

The safety significance of the LOOP event was minimal. All systems Initially responded as expected to the scram except for the SGT system that was unable to maintain the secondary containment at the Technical Specification Surveillance,Requirement limit of greater than or equal to 025 Inches of vacuum water gauge. However, secondary containment was maintained at a negative pressure at all times during the event. The EDGs were supplying power to their respective busses, as designed, and offsite power was availiable through Unit 2.

Therefore, the consequences of this event had minimal impact on the health and safety of the public and reactor safety.

E. Corrective Actions:

345 kv circuit breaker 8-15 was repaired and a vendor upgrade kit was Installed. The circuit breaker upgrade kit will be Installed on circuit breaker 6-7 at the next available opportunity.

The preventive maintenance procedure for circuit breakers 8-15 and 6-7 will be revised to Incorporate appropriate vendor advisory recommendations.

DNPS procedures were revised to require the securing of the DTPE Fans upon Initiation of SGT.

The DTPE filter housing In-leakage has been repaired to correct air Inleakage.

The SGT initiation logic will be changed to Include the tripping of the DTPE Fans for both units.

NRC FORM 366A U.S. NUCLEAR REGULATORY COMMISSION (7-2001)

LICENSEE EVENT REPORT (LER)

.1. FACILITY NAME 2. DOCKET NUMBER 6. LER NUMBER 3. PAGE YEAR SEQUENTIAL REVISION Dresden Nuclear Power Station Unit 3 05000249 N NEFI

. .2004 003 00 4 o

17. NARRATIVE (If more space Is required, use additional copies of NRC Form 366A)

The final corrective actions to prevent reoccurrence for the Emergency Diesel Generator output breaker will be described In a supplemental report scheduled to be submitted no later than October 30, 2004.

F. Previous Occurrences:

A review of Dresden Nuclear Power Station Ucensee Event Reports (LERs) and operating experience Identified the following LER.

Unit 3 LER 89-001.01 described a March 25, 1989, event In which an electrical fault In the 345 kilovolt circuit breaker 8-15 phase A Internal ground capacitor and slow transfer of the 4 kv Bus 32 from transformer 32 to 31 caused a LOOP for Unit 3. The corrective actions Included the removal of the Internal ground capacitors from 345 kilovolt circuit breaker 8-15.

G. Component Fallure Data:

I.T.E. Power Circuit Breaker, Model C Type GA

Ii

/7, VERMONT YANKHT!' NUCLEAR Ik)0WE' C(ORPORATION 1' 0. BOX 157 GOVERINOR fit'.N ROAD

'ERNO.N. VFRMONT 05354 April 12, 1991 VYV # 91-104 U.S. Nuclear Regulatory Commiasion Document Control Desk Washington, D.C. 20555

REFERENCE:

Operating Licenue DPR-28 Docket No. 50-271 Reportable Occurrence No. LER 0 91-05

Dear Sire:

As defined by 10 CFR 50.73, we are reporting the attached Reportable.

Occurrence as LER 1 91-05.

Very truly yourr, VERMONT YANKEE NUCLEAR POWER CORPORATION 4 DonaldA. eid Plant Manager cc: Regional Administrator USNRC Region I

. 475 Allendale Road King of Pruisia,.PA 19406 916J41;R0-44 910412 1' I--

fPDR ECiC AD  : 4-7 S GOR

MC For 66 U.S. NUCLEAR R-GULATORY COM"ISSION APPROVED OHS NO.3150-0104 EXPIRES 4/30/92 ESTIMATED BURDEN PER RESPONSE TO COMPLY WITH THIS INFORMATION COLLECTION REQUEST:

50.0 HRS. FORWARD COMNENTS REGARDING :-

LICENSEE EVENT REPORT (LER) BURDEN ESTIMATE TO THE RECORDS AND REPORTS PANAGEMENT BRANCH (P-630), U.S. NUCLEAR REGULATORY CONMISSION, WASHINGTON, DC 20555, AND TO THE PAPERWORK REDUCTION PROJECT (3160-0104). OFFICE OF MANAGEMENT Awn SU VirT - USImfulTnu_ DC 20 FACILITY NAME (I) DOCKET NO. ()PE YANKEE NUCLEAR POWER STATION 0 1510101012 17110 11 II TITLE (* -

Reactor Scram due to Mechanical Failure of 34SKV Switchyard Bus caused by Broken High Voltace Insulator Stack EVENT DATE ) I LER IMER

• I REPORT ATE (') OTHER FACILITIES INVOLVED (*)

' DAY YEAR [YEAR j SE . U REVS 1 DAY YEAR FACILITY NAMES DOCKET NO.(S)

OPERATING 1 13 9 11 li__

THIS REPORT IS SUBMITTED PURSUANT TO REO'MTS OF IOCFR i:

11 ' ONE OR MORE (")

... (. _) N _ 20.402(b) 20.405(c) 60.73(a)(2)(iv) U 73.71(b)

OR ._20.40(aIll) (i) 50.36(c)(1) _ .73(a)(2)(v) _ 73.71(c)

LYEI lda_20.40S(a)l1)i{i) 50.36(c)(2) _ 0O73(a)(2)(vii) OTHER:

20.405(a)(1)(iii) _60.73(a)(2)(i) 50.73(a)(2)(viii)(A)

............... . 20.405(a)(1)(i)vJ H 60.13(a)(2) i a60.?3(a)(2 )[vJlT)(E)

...._ 20.405(a)(1) (v) I 60.73(a) (2)(ii) I 50.?3(a)(2)(x) .

LICENSEE CONTACT FOR THIS LER ("1" ME IE TELEPHONE NO.

. CODE DONALD A. REID, PLANT MIMER d71 11 COWPLETE ONE LINE FOR EACH COMPONENT FAILURE DESCRIBED IN THIS RE r C ts CAUSE 1TO SYST CONPUT MFR 4

REPORTABLE .....

n PRDS

CAUME SYST COMPMT MFR REPORTABLE TO HPROS j . .' ' N I. NIA Li. I L ... L. ..

E SUPPLEMENTAL REPORT EXPECTED (0d) EXPECTED NO 1A YR

. i SU~BIISSION YES (If yes, eciolete FEPECTED SUBMISSIO DATE)1N hXT no)

AESTRACT (Limit to I4UU Spaces. i.e., approx. fifteen single-space typewritten lines) (")

On 3/13191 at 2228 hours0.0258 days <br />0.619 hours <br />0.00368 weeks <br />8.47754e-4 months <br />, with reactor power at iOoS, a Reactor scram occurred due to a geacrator/turbine trip as a result of the failure of an 80 ft. vertical section of 346KV switchyard Bus (B Phase) between the Main Transformer aerial Ti disconnect switch and the horizental bus bar spanning the IT-II and 81-1T-2 disconnect switches. The cause of the bus failure is attributed to a broken insulator stac% which secured the bus to the tower. The plant was subsequently stablized by resetting Primary Containment isolations, restarting Reactor Water Cleanup and establishing level control using the 10% Feedwater Regulator valve. Shutdown Cooling was later employed at 0504 hours0.00583 days <br />0.14 hours <br />8.333333e-4 weeks <br />1.91772e-4 months <br /> on 3/14/91 and maintained until the necessary repairs and testing were completed. The reactor was returned to critical on 3/1/91 at 0OS5 hours. The need to expand present Switchyard system maintenance is being evaluated.

RC-Form 366 (6-89)

MKC Fh NO U.S. NUCLEAR REGULATORY COMMSSION APPROED OS NO.3160-0104 EXPIRES 4/30/92 ESTIMATED BURDEN PER RESPONSE TO COMPLY WITH THIS INFORMATION COLLECTION REQUEST:

60.0 HNS. FORWARD COMMENTS REGARDING LICNSEE EVENT REPORT (LER) BURDEN ESTIMATE TO ThE RECORDS AND REPORTS TEXT CONTINUATION MANAGEMENT BRANCH (P-530), U.S. NUCLEAR REGULATORY COMMISSION, WASHINGTON, DC 20555, AND TO 1HE PAPERWORK REDUCTION PROJECT (3160-0104). OFFICE OF MANAGEMENT AND BUDGET. WASHINGTON. DC 20603.

UTLITY U E ') ocET NO. (2) ER Rl')

ULER PAGE (5)

-YEAR SEQ. J8 REVS N TYNmEE UCLEAR POWER STATIONId dd 911 O o15 11

- - dOo d Of d 4 TEXT (If. ore spe is required, use addit ional NRC Form 366A) I.)

ESQIPTION OF EVENT, On 3/13/91 at 2226 hours0.0258 days <br />0.618 hours <br />0.00368 weeks <br />8.46993e-4 months <br />, during normal operation with Reactor power at 100%. a Reactor serm occurred as a result of a turbine trip on Gencrator Load Reject due to a 345KV arltfiard Tie Line Differential Fault. During the first 14 seconds of the event, the following automatic system responses occurred without Operator intervention:

a. Trip of Tie Line breakers IT and 81-IT.

b. Fast Transfer of 4WV uses and 1 and 2 to the Startup transformers.

c. Rector scram on Turbine Control Valve Fast Closure signal.

d. Priaary Containment Isolation System (PCIS)(JM) Initiation, Groups 2, and 3 on Reactor Vessel "Lo" water level.

Operations personnel responded to the scra by impleaenting the required steps delineated in Eeemcy Operating Procedure OE-3100 "Scram Procedure which governs reactor operation in a Vnt-5cu envitoi ent.

hutomatic system responses a) thru c) were anticipated as a result of the 345KV Tie Line Fault. The Primary Containment Isolation System (PCIS) initiations experienced subsequert to the turbine trip were in response to the characteristic drop in Reactor water level f om vessel void collapse. Vessel level, which initially dropped to a 120 inch level from the void collapse, quicxly recovered with the uAw and "Cm Reactor Feedwater pumps running In an effort to control the increasing level, the C" Reactor Feedwater pump was secured by Operations personnel. At 2230 hours0.0258 days <br />0.619 hours <br />0.00369 weeks <br />8.48515e-4 months <br /> (2 minutes into the event), the "A" Reactor Feeidwater pump tripped on High Reactor water level I?? -inches).

'At 2231 hours0.0258 days <br />0.62 hours <br />0.00369 weeks <br />8.488955e-4 months <br />, the Reactor scram was reset and the plant subsequently stabilized in Hot Standby by: restarting Reactor Water Cleanup: resetting PCIS Group 2, 3, and 5 isolations and establishing level control using the IOt Feedwater Regulator valve.

At 2235 hours0.0259 days <br />0.621 hours <br />0.0037 weeks <br />8.504175e-4 months <br />, operators received a report from Security that a large flash had been cebm-d in the Switchyard just prior to the Reactor scram. The local Fire Department was notified, but no fire ensued. The flash that had been observed was an electrical arc resulting from the connection break of the 4B0 phase.

At 2356 hours0.0273 days <br />0.654 hours <br />0.0039 weeks <br />8.96458e-4 months <br />, Reactor depressurization and cooldown began using the Main Condenser and the Dypass Opening Jack. At 0504 hours0.00583 days <br />0.14 hours <br />8.333333e-4 weeks <br />1.91772e-4 months <br /> on 3/14/91, RHR Shutdown Cooling was established on the e" loop.

• Ene"M Information Identification Svstem MEIS) Component Identifier IfC Form 36A (6-39)

-i M MM aeon U.N. NLEAR MMULATMT CIzSSzow APPROVED OM 0.3150-0104 W(M4 EXPIRES 4/30/92 ESTIMATED BURDEN PER RESPONSE TO COW Y WITH THIS INFORMATION COLLECTION REQmST:

. 60.0 HRS. FORWARD COWNTS REGARDING LICENSEE EVENT REPORT (LER) E ESTIMATE TO THE RECORDS AND REPORT!

TEXT CONTINUATION MANAGEMENT BRANCH (P-630), U.S. NUCLEAR REGULATORY CORMISSION. WASHINGTON. DC 20555, AND TO THE PAPERNORK REDUCT ION PROJECT (3160-0104). OFFICE OF MANAGEMENT AND BUDGET, WASHINGTON, DC 20603.

UTLITY N () DOCKET NO. (') LER NUMBER (') PAGE l')

. .YEA S£Q. 0 tV~

VE lONTYAMUEE NUCLEAR POWERSTT d191 iold d dO I sI-lolo o di3Iol d TMT (If moe Spe is required, use additional 1C Form 366A) (")

OESCRIPTION OF EVENT (Contd.)

The reactor was returned to critical on 3/18/91 at 0055 hours6.365741e-4 days <br />0.0153 hours <br />9.093915e-5 weeks <br />2.09275e-5 months <br />.

Ouring the course of the event, the following additional anomalies occurred:

a) Turbine Pressure Control switched from Electrical regulation to Mechanical regulation shich remained In effect during Reactor cooldown.

b) AO wAN and "BU Train Recaobiners tripped and isolated. The O" Recombiner was reset and returned to service.

c) RPS Alternate Power Supply breakers from "CC 88 tripped. The breakers were sub-sequently manually reset.

d) Spurious Reactor and Turbine Area Radiation alara3 were received during the event.

The alarms were subsequently cleared and did not return.

el The PCIS group 2A. 3A& SA and SB (RWCU) isolation signals occurred within one second of the trip. These isolations were expected to occur after the low water level trip 8.5 seconds into the event.

An analysis of the above events was performed. Recorded data confirmed that the above equipment/circuitry responses occurred coincident with the Switchyard Fault. A review of recorded bus voltage data for buses supplying the above equipment and circuitry revealed that 4 separate voltage dips on the buses had occurred during the fault. These voltage dips were concluded significant enough to cause the equipment responesr experienced which in each case, the equipment had Undervoltage features or Seal-In circuitry.

An inspection of the Switchyard was performed iinediately after the event which revealed the lower section of " Phase bus bar to be broken off at the lower horizontal bus bar attachment point. (Reference attached pictorial.) The upper insulator stack and I connec-tor which served as a tie point for the lower and upper bus bar sections was observed broken betiusen the third and fourth inslators with the fourth insulator and I connector still attached to the busmork. Ouring the course of inspectiors the next morning (on 3/14/91). a, gust of wind caused the hanging bus work to break off at the T-1 disconnect switch Jaw and fall to the ground. No additional Switchyard dama" occurred from the falling bus.

CAUSE OF EVENT The root cause of the Switchyard bus failure is attributed to a failed insulator support between the bus and the tower. The lower insulator stack, which is coqprised of four insula tors coupled together, broke away from the tower at the base of the first insulator. This caused a swinging moment arm developing a force on the bus connector at the opposite end of the insulator. The excessive force snapped the vertical bar out of the welded socket on the horizontal bus bar. This resulted in an open circuit in "B" Phase and a "B" to C Phase flashover as the bus swung past the C" Phase vertical bus bar. The combination of these two events initiated the Tie Line Differential Protective elaRins.

URC Form 3MA (6-69)

_ rUv ow wee v .@ LVA n&,0ILM InT LAA1 . SW MFTwuVWm NPJ4 WU4-VAV (64$. EXPIRES 4/30/92 ESTIMATED BURDEN PER RESPONSE TO COMPLY WITH THIS INFORMATION COLLECTION REQUEST:

50.0 HRS. FORWARD COMMENTS REGARDING LICENSEE EVENT REPORT (LER) BURDEN ESTIMATE TO THE RECORDS AND REPORU TEXT CONTINUATION MANAGEMENT BRANCH (P-630). U.S. NUCLEAR REGULATORY COMIISSION WASHINGTON, DC

.20555, AND TO THE PAPERWORK REDUCtION PROJECT (3160-0104). OFFICE OF MANAGEMENT AND _ ET. WASHINGTON. DC 20603.

FAD UTILITY NME (') D ET NO. (1) LER HUMBER li I PAGE (S)

. T.N- YEAR SEQ. I*II REV S SrRACMT YANK;EE NUCLEAR POWER STATION 21 dh 9 d1 - i 10 IS -O dA TEXT (If more space is required, use additional NRC Form 366A) (")

n&ALYSIS OF EVENT The events detailed in this report did not have adverse safety implications.

1. The Tie Line Differential Protective Relaying operated as designed which initiated the generator trip and Fast Transfer of plant buses to the Startup transformers.

2. The Reactor Protective System operated as designed and si.ramsed the reactor after receiving a Turbine Control Valve fast closure signal.

3. All other safety system responded as expected.

CORRECTIVE ACTIONS IMMEDIATE CORRECTlIE ACTIONS

1. Imnediate corrective actions included recovering from the Reactor scram utilizing appropriate plant procedures.

2. Efforts were ine diately initiated to repair the 1B and C" phase vertical bus work. A visual and them raphy inspection was conducted of the entire Switchyard to identify any additional trouble spots. An additional insulator on the "An Phase wMs found With arc damage and subsequently replaced.

3. The Main and Auxiliary transformers were Doble tested and oil samples were taken to assess any damage which might have been caused by the Switchyard fault. No anoma-lies or degradation were found., The fault effects on the transformers were analyzed and determined to be bounded by the design.

LONG TERM CO CTIVE CTIONS

1. The plant will meet with VELCQ (Vermont Electric Power Co., Inc.) and evaluate the adequacy of the Switchyard Maintenance Program.

2. The failed insulator has been returned to the manufacturer for analysis and repc endations.

3. A detailed engineering analysis of the Switchyard vertical buswork will be performed to determine the adequacy of the present mounting configuration.

The above long term corrective actions are expected to be completed by 12/31/91. Based upon analysis results and findings, additional corrective actions will be initiated as appropriate.

ADDITIONAL INFORMATION There have been no similar events of this type reported to the Commission in the past five years.

RC Form 355A (-659)

• . -a LER 91-05 q

VPRMONT YANKEE:

NUCLEAR POwVER CORPORATION PV \'*- ' . * - ;S, .

I V, w .

. 8:. * '. ' I"

, s June 6, 1991 VYV I 91-135 U.S. Nuclear Regulatory Commission Document Control Desk Washington, D.C. 20555

REFERENCE:

Operating License DPR-28 Docket No. 50-271 Peportable Occurrence No. LER 91-09

Dear Sirs:

As defined by 10 CFR 50. 73, we are reporting the attached Reportable Occurrence as LER 91-09.

This report was originally scheduled for submittal on 05/23/91. However, a two week extension was granted on 05/22/91 by R. BarkIey, Acting Section Chief, Reactor Projects 3A (via T. Hiltz, NRC Resident Engineer at Vermont Yankee).

Very truly yours, VERMONT YANKEE NUCLEAR POWER CORPORATION

& Donald A. Reid Plant Manager-cc: Regional Administrator USNRC Region I 475 Allendale Road King of Prussia, PA 19406

r' 7  :

1. F

NRC Form 366 U.S. NUCLEAR REGULATORY COMMISSION APPROVED ONS NO.3150-0104 (6-89) EXPIRES 4/30/92 ESTIMATED BURDEN PER RESPONSE TO COMPLY WITH THIS INFORMATION COLLECTION REQUEST:

50.0 HRS. FORWARDOCOMMENTS REGARDING LICENSEE EVENT REPORT (LER) BURDEN ESTIMATE TO THE RECORDS AND REPORT MANAGEMENT BRANCH (P-530), U.S. NUCLEAR REGULATORY COMMISSION, WASHINGTON, DC 20555. AND TO THE PAPERWORK REDUCTION PROJECT (3160-0104). OCFICE OF MANAGEMENT

. AND BUDGET. WASHINGTON, DC 20603.

FACILITY NAME ('I) IDOCKET NO. O () '

aDCE PAGE I v VERMONT YANKEE NUCLEAR POWER STATION o 1 1 1O I 12l7 11 I 11 OF 0 19 TITLE (4)

Reactor Scram Due to Loss of Normal Off-site Power (LNP) Caused By Inadequate Procedure Guideline EVENT DATE () LER NUMBER (') REPORT DATE (') OTHER FACILITIES INVOLVED (6) 1DNT DAY YEAR YEAR i I SEQ. # REV# MONT DAY YEAR FACILITY NAMES DOCKET NO.(S)

OPERATING I

II 9 I00I0lolo 0 12 THIS REPORT IS SUBMITTED PURSUANT TO REQM"TS 3I OF 10CFR S:. ONE OR MORE (" )

I I-MODE_11) N l20.402(b) 20.405(c) X 50.73(a)(2)(iv) 73.11(b)

POWER VELV*)1 d 20.405(a)(1)(i) 20.405(a)(1)(ii) 20.405(a)(1)(iii) 20.405(a)(1)(iv) 20.405(a)(1)(v) 50.36(c)(1) 50.36(c)(2) 50.73(a)(2)(i) 50.73(a)(2)(ii) 60.73(aH(2)(iii)

_fj 0 5D.73(a)(2)(v) 50.73(a)(2)(vii) 0.73(a)(2)(viii)(A).

50.73(a)(2)(viii)(B) 50.73(a)(2)(A) 73.iic)

OTHER:

LICENSEE CONTACT FOR THIS LER I')

kAWE  : TELEPHONE NO.

AREA CODE DONALD A. REID. PLANT MANAGER _ -d d2I d 71 it1

_2 i I7

- COMPLETE ONE LINE FOR EACH COMPONENT FAILURE DESCRIBED IN THIS REPORT rIl)

CAUSE SYST COMPNT MFR R EPORTABLE ...... SYST COMPNT MFR SREPORTA CCAUS

- TO NPRDS _ _____ _..... TO NPRDS _ .

X FIKliFl VI C El 31 513 N NIA.............. ............... :... _

N.... . NA L L LL _ ......

X FI K N ..... N/A I_... LL.L SUPPLEMENTAL REPORT EXPECTED (t-) EXPECTED. IO DA YR SUBMISSIONl X IYES (If yes. complete EXPECTED SUBMISSION DATE)Rl-NO DATE (1")

ABSTRACT (Limit to:1400:spaces, i.e., approx. fifteen single-space typewritten lines) (C")

On 04/23/91 at 1448 hours0.0168 days <br />0.402 hours <br />0.00239 weeks <br />5.50964e-4 months <br />. during normal operation with Reactor power at 100S. a Reactor Scram occurred as a result of a Generator/Turbine trip on Generator Load Reject due to the receipt of a 345KV Breaker Failure Signal. The Failure Signal was the result of Breaker Failure Interlock (BFI) signals that occurred simultaneously in the 345KV and 116KV Breaker control circuitry during the restoration of a battery bank to Switchyard Bus DC 4A.

The cumulative effects of both ,(F1) signals resulted in a total loss of 345KV and 115KV off-site power. An Unusual Event was declared at 1507 hours0.0174 days <br />0.419 hours <br />0.00249 weeks <br />5.734135e-4 months <br />. Both Emergency Diesel Generators provided power for essential safety.related systems during the LNP until approximately 0430 hours0.00498 days <br />0.119 hours <br />7.109788e-4 weeks <br />1.63615e-4 months <br /> on 04f24/91 at which point off-site 345KV power was restored and backfed through the Station Auxiliary Transformer. During the event, Torus Water volume exceeded the Technical Specification limit of 70,000 cubic ft. The Unusual Event was terminated at 1950 hours0.0226 days <br />0.542 hours <br />0.00322 weeks <br />7.41975e-4 months <br /> on 04/24/91. The reactor reached Cold Shutdown at 0357 hours0.00413 days <br />0.0992 hours <br />5.902778e-4 weeks <br />1.358385e-4 months <br /> on 04/26/91 and was returned to critical at 0300 hours0.00347 days <br />0.0833 hours <br />4.960317e-4 weeks <br />1.1415e-4 months <br /> on 04/30/91. The Root Cause of this event is failure of the repair department personnel to recognize the consequences of operating a DC bus without a connected battery bank. Corrective Actions to prevent reoccurence are presently being finalized and will be presented in a supplemental report.

I f -

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____ ___ ____ ___ ____ ___ AND _BUDGET, _WASHI NGTON ._DC _20603.

DOCKET NO. ('3 LER NUMBER ' PAGE (a)

UTILITY NAME

[EAJ 1 E0 LREVS I VEMN AKEE NUCLEAR POWER STATIONlof 5Iof ofd2I711 119 I -009 dIOFI dO9 TEXT (If more space is required. use additional NRC form 366A) (11)-

DESCRIPTION OF EVENT On04/23/91 at 144 hours, during normal operation with Reactor power at 100*. a Reactor scram occurred as a result of a Generator/Turbine trip on Generator Load Reject due to the receipt of a 34SKV Breaker'Failure Signal. The 346KV Breaker Failure Signa wsrreceived as a result of -Breake~r. Failure Interlock (BF13 signals that occurred simultaneously in the 346KV-Breaker 81-iT and 115 Ky Breaker K-i control circuitry.

The (SF)siga from 116KV Breaker K-I initiated the, following automatic system responses:

-Opening of 116KV Breaker K-18O

-Opening of 34SKV Breakers 379.and 381 The loss of 381 and 319 breakers removed all power sources to the Auto Transformer which In conjunction with the K186 trip resulted in a total loss of 115KV power.

T~he (6F!) signal from 345KV Breaker SI-IT initiated the following automatic system

-Generation of 345KVBreaker Failure Signal

-Opening of 345KV Breakers 381 and IT

-Lockout of Main Generator 86GP and 86GB relays, causing the Main Generator and Exciter Field breakers to open The Generator Primary and Backup Lockout relays init iated the following automatic system

-Main Turbine Trip

-Opening of 345KVBreaker.81-11 and Northfield Line, trip' at Northfield

-Attempted Fast Transfer of 4KV Buses 1 and 2 to the Startup Transformers but 115KV power was unavailable The umaulative effects of both (SFI) signals resulted inartotal loss of.345KV and 115KV off-site power. However, an additional off-site power source was available'through the .Vernon Hydro Station Tie line. The 4KVHydro Station routput, which is designated as a delayed access off-,site power source, was available throughout the.event.

Prior to the eVent, the plant was in the process of completing the replacement of SwItchyard Battery Bank 4A in accordance with a Maintenance Department guideline. All work with the exception of restoring the connection of the battery bank to the DC 4A bus, ascompleted without incident. While performing the final sequence of actions necessary to reconnect the battery bank to DC Bus 4A, a DC voltage transient occurred on the bus which initiated the event.

INCV rorm,a*" to-ay)

I.NC For 36SA U.S. NUCLEAR REGULATORY COMMISSION APPROVED COOS NO.3160-0104

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UTILITY NAME (D) DOCKET NO. (') LER NUMBER (6) PAGE I8)'

YERISEO. I IREVS II VERMONTYANKEE NUCLEAR POWER STATION dgdd 7-d 9 IIt d I lo 9IgIo Id Ofld TE1T (If more space is required, use additional NRC Form 366A) 1")

DESCRIPTION OF EVENT (cont.)

During the first second of the event (1448:29 hours), as a result of the inablility

. to reenergize 4KV buses 1 and 2 from Fast Transfer to the Startup transformers, all station loads fed from these buses were lost. Major system responses to the loss of the power included the trip of Reactor Protection System (RPS)(*JC) "A and "B" NG sets and receipt of Primary Containment Isolation Signals (PC1S)(*JM) Groups 1. 2, 3 and S resulting in the required closure of PCIS Groups 1,. 2 and 3 isolation valves Motor operated valve closures within these Groups occurred after Emergency Diesel Generator power was supplied to the ctive buses).

The loss of all power on 4KV Buses 1 thru 4 initiated the opening of Tie breakers 317 and 4t2 to provide isolation of Safety Buses 3 and 4 which, in the event of normal power loss, are aligned with the station Emergency Diesel Generators. An autostart of both diesels followed which reenergized Bus 3 and Bus 4 at 1448246 hours. Both diesels remained in operation without incident until approximately 0430 hours0.00498 days <br />0.119 hours <br />7.109788e-4 weeks <br />1.63615e-4 months <br /> on 04/24/91 at which tine off-site 345KV power was restored and backfed through the Station Auxiliary Transformer.

In response to the Scram, Operation personnel entered Emergency Operating Procedure OE 3100, "Scram Procedure" which governs reactor operation in a post-scram environment.

Immediate actions initiated at 1450 hours0.0168 days <br />0.403 hours <br />0.0024 weeks <br />5.51725e-4 months <br /> by Operations personnel to stabilize Reactor pressure and level included the manual lifting of Safety Relief Valve (SRv)-A. the manual initiation of High Pressure Coolant Injection System (HPCI)(*SJ). and startup of both RHR loops in the Torus Cooling mode. Both RPS MG sets were successfully restarted and RPS buses-reenergized at 1516 hours0.0175 days <br />0.421 hours <br />0.00251 weeks <br />5.76838e-4 months <br />. The initial scram was reset at 1533 hours0.0177 days <br />0.426 hours <br />0.00253 weeks <br />5.833065e-4 months <br />.

Ouring the period from 1450 hours0.0168 days <br />0.403 hours <br />0.0024 weeks <br />5.51725e-4 months <br /> on 04/23/91 to 1346 hours0.0156 days <br />0.374 hours <br />0.00223 weeks <br />5.12153e-4 months <br /> on 04/24/91, the combination of HPCI and Reactor Core Isolation Cooling (RCIC) (*BN) systems and SRV's were manually employed in accordance with procedure OE 3100 to control Reactor pressure level The first use of RCIC system began at 1645 hours0.019 days <br />0.457 hours <br />0.00272 weeks <br />6.259225e-4 months <br /> on 04/23/91. During the above 23 hour2.662037e-4 days <br />0.00639 hours <br />3.80291e-5 weeks <br />8.7515e-6 months <br /> period, several additional events transpired. The following is a summary and discussion of those events

• Energy Information Identification System (EIIS) component Identifier I MU Form 366A 1b-OV)

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UTILITY NAME (') DOCKET NO. (') I LER NUMBER {X) PAGE (3)

YANKEERNCEARP I STAI I EVI

_FNM YANKEE NUCLEAR IPOWER STATION d d d1 d d 217 1l I I 0101oI l-00lF d TEXT (If more space is required, use additional NRC Form 356A) (t)

QESCRIPTION OF EVENT (cont.)

A. Reactor Scrams on "Lo" Reactor Water Lev 1 were experienced at 1534 hours0.0178 days <br />0.426 hours <br />0.00254 weeks <br />5.83687e-4 months <br /> and 2112 hours0.0244 days <br />0.587 hours <br />0.00349 weeks <br />8.03616e-4 months <br /> on 04/23/91.

The first Scram occurred due to low Reactor water level during the process of securing HPCI and transferring to RCIC. Prior to the scram, reactor pressure and level had been steadily decreasing during the first 30 minutes of HPCI operation which-prompted a change in cooling systems by Operations personnel. During the process of securing HPCI, Reactor Water level continued to decline to the 132 inch "Lo" level setpoint which initiated the Reactor scram. PCIS - Groups 2, 3, and 5 isolations which would normally initiate.on "Lo" Reactor water level were already present from the initial Scram at 1448 hours0.0168 days <br />0.402 hours <br />0.00239 weeks <br />5.50964e-4 months <br />. After receiving the Scram, Operations personnel completed the transfer to RCIC for level and pressure control. Reactor pressure and level recovered after RCIC initiation. The Scram and PCIS Groups 2, 3. and 6 isolations were subsequently reset at 1548 hours0.0179 days <br />0.43 hours <br />0.00256 weeks <br />5.89014e-4 months <br />.

The second Scram resulted as a momentary drop in water level was experienced due to level shrink resulting:from an increase. in Reactor pressure experienced after cycling SRV-D. Water level dropped to approximately 112 inches during the pressure surge. The initiation of PCIS Groups 2, 3, and 5 logic occurred coincident with the level drop as required. The scram was subsequently reset at 2127 hours0.0246 days <br />0.591 hours <br />0.00352 weeks <br />8.093235e-4 months <br />. PCIS Groups 2 and 6 logic were reset at 2128 hours and Group 3 logic later reset at 2154 hours.

B. Emergency Operating Procedure DE 3104. "Torus Temperature and Level Control Procedure",

was entered at 1633 hours0.0189 days <br />0.454 hours <br />0.0027 weeks <br />6.213565e-4 months <br /> and 2112 hours0.0244 days <br />0.587 hours <br />0.00349 weeks <br />8.03616e-4 months <br /> on 04/23/91 due to Torus water volume exceeding the Technical Specification limit of 70,000 cubic ft.

In both occurrences, actions were taken in accordance with Ot 3104 to reduce Torus water volume. Water reduction actions undertaken after the first entry into OE 3104 were successful and Torus water volume was reduced and maintained below 70,000 cubic ft. Later in the event, at 2112 hours0.0244 days <br />0.587 hours <br />0.00349 weeks <br />8.03616e-4 months <br />, Torus water volume was not able to be maintained below 70,000 cubic ft. This resulted in the entry into the Technical Specification. "Required Cold Shutdown in 24 Hour" require ment. Due to the volume limitations of Torus water being processed through Radwaste, the Torus volume remained above 70,000 cubic ft. until 1926 hours0.0223 days <br />0.535 hours <br />0.00318 weeks <br />7.32843e-4 months <br /> on 04/24/91. The Technical Specification cold shutdown requirement and OE43104 were excited at this time.

C. ACIC tripped on overspeed at 1904 hours0.022 days <br />0.529 hours <br />0.00315 weeks <br />7.24472e-4 months <br /> on 04/23/91. The overspeed trip was reset at 1912 hours0.0221 days <br />0.531 hours <br />0.00316 weeks <br />7.27516e-4 months <br /> and operation of the system-resumed.

• Energy Information Identification System (EIIS) Component Identifier INC Form 366A (6-89)

I-Folm 36A 36C U.S. NUCLEAR REGULATORY COMMISSION A.3160-0104 g-9)- EXPIRES 4/30/92 ESTIATED RMEN PER RESPONSE TO COMPLY WITH THIS INFORMATION COLLECTION REQUEST:

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UTILITY ANAE ')DOCKET O. LER NUMBER PACE 1)

YS YEAR - SEQ. R OEVFC.

,VE 0N YANKEE MUCLEAR POWER STTaIONd d1 d1d oi d i121 Il1 1O]O 9 lds TEXT (If more space is required, use additional NRC Form 366A) (")

DESCRIPTION OF EVENT (cont.)

The tsip is attributed to an operator error in the adjustment of the RCIC Flow Controller prior to switching from the MANUAL to AUTO mode.

D. The "A" Station Air Compressor tripped at 1542 hours0.0178 days <br />0.428 hours <br />0.00255 weeks <br />5.86731e-4 months <br /> on 04/23/91 due to inadequate Service Water cooling flow. A reserve diesel air compressor was subsequently connected to the outlet of the "D" Station air compressor and became operable at 1759 hours0.0204 days <br />0.489 hours <br />0.00291 weeks <br />6.692995e-4 months <br />.

The remaining S"BStation Air compressor also tripped at 1731 hours0.02 days <br />0.481 hours <br />0.00286 weeks <br />6.586455e-4 months <br /> on thermal overload due to inadequate Service Water cooling flow and was subsequently restarted at 1736 hours0.0201 days <br />0.482 hours <br />0.00287 weeks <br />6.60548e-4 months <br />. The OCO and "0" station Air compressors were unavailable due to the LNP. The five (5) minute interval in which all Station Air compressors were out of service resulted in a 15 psig. Instrument Air header pressure drop. In response to the "8" Station Air Compressor Trip, Operations personnel entered procedure ON 3146, fLow

-Instrument/Scram Air Header Pressure", and initiated i ediate efforts to restart the "8" Station Air Compressor., No air supplied equipment malfunctions were experienced during this interval. The reduced Service Water flow to the Station Air compressors and other plant equipment is being reported separately as Licensee Event Report (LER) 91-12.

At 1926 hours0.0223 days <br />0.535 hours <br />0.00318 weeks <br />7.32843e-4 months <br /> on 04/23/91, 115KV Breaker K186 was manually closed which restored power to the Startup transformers via the Keene (KI86) line. 4 KV bus breakers 13 and 23 were subsequently closed to reenergize Buses 1 and 2 which power the normal station loads. Because of the fact that testing was continuing in the Switchyard with only one breaker closed, the decision was made to leave the emergency diesels connected to

=Vbuses 3 and 4. This would ensure that power to 4KV buses 3 and 4 would not be interrupted if another LNP occurred.

At 1950 h w rs on 04/24/91, based on normal off-site power having been restored and Torus water volume having been reduced below 70,000 cubic ft., the Unusual Event was terminated. At 0207 hours0.0024 days <br />0.0575 hours <br />3.422619e-4 weeks <br />7.87635e-5 months <br /> on 04/26/91. Shutdown Cooling using the -D- RHR p.up on the OB" loop was initiated. The reactor reached cold shutdown at 0357 hours0.00413 days <br />0.0992 hours <br />5.902778e-4 weeks <br />1.358385e-4 months <br />.

Tle reactor was returned to critical at 0300 hours0.00347 days <br />0.0833 hours <br />4.960317e-4 weeks <br />1.1415e-4 months <br /> on 04/30/91.

Investigations into the cause of the event, along with troubleshooting, testing, and repair efforts were initiated imediately after the start of the event. A Switchyard response team was formed with specific directives to:

- recover off-site power

- stabilize the switchyard

- gather technical information related to the event

- begin root cause analysis research

'WIC Forn 366A (6-89)

ANIVIZ r - .- ,

OM 366A U.S. NUCLEAR REGULATORY CO~tISSIOW APPROVED OHS NO.3150-0104

.. tv} ...-

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._ ANDBUDGET, WASHINGTONDC 20603.

UTILITY.E( DOCKET NO. LEER) NUMBER ) PACE (8)

YEAR ISEQ, 8 ._ i I1IREV I I VERNONTYWANKEE NUCLEAR POWER STATION d ofd d d 21 71 Io11 oIoI9 -oIoI dOFIwd EXT (If more space is required, use additional NRC Form 356A) (")

D!SCRIPTION OF EVENT (cont.)

The recovery of Off-site power began with the attempt to restore 11KV power from the Switchyard via 116KV Breaker K186 and the Startup transformers. This was determined to t* the easiest path in obtaining an off-site power source due to the need to close only one breaker. :Hwewer. the KI Breaker BFI signal remained locked in due to a failed vener diode on the associated trip card and prevented the closure of K1S6. At 1925 hours0.0223 days <br />0.535 hours <br />0.00318 weeks <br />7.324625e-4 months <br />, the BF1 signal from the KI to the K186 Breaker was blocked allowing reclosure of KISG and s&*sequent restoration of power to 4KV buses 1 and 2. The KI BtI trip card was subsequently replaced with an identical card from a spare breaker. The 4 hour4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> effort to close the KIS6 breaker was a direct result of the length of time required-for New England Power service Co. (NEPSCO) relay technicians to travel to Vermont Yankee from Providence, Sihode Island.

After 115 KY power -as established through the Keene Ki86 line, efforts to close fteaker KI continued in order to establish a more reliable source of 11SKV power through the Auto Transformer. Homever, due to c unication problems between VY and the Mew England Switching Authority (RENVEC) concerning priorities over breaker testing, a three hour delay occurred before 115KV power was made available through the Auto Transformer. While Vermont Yankee was attepting to close the KI breaker. RENVEC.was pursuing efforts to eWstablish connections between the ring bus and the Northfield line by reclosing the l-IT breaker.

En a parallel effort, at 1900 hours0.022 days <br />0.528 hours <br />0.00314 weeks <br />7.2295e-4 months <br />, Operation orders were given to complete lbackfeeding of the plant from the 345 yard through the Main Transformer. The effort to backfeed was possible due to the availability of the Coolidge.and Scobie lines.

The Northfield line was unavailable due to the SI-IT BF1 signal. Again, the backfeed effort was hampered by communication probles with REMVEC, personnel delays, and equipment malfunctions. Backfeeding was completed at 0410 hours0.00475 days <br />0.114 hours <br />6.779101e-4 weeks <br />1.56005e-4 months <br /> on 04/24/91.

Vermo Ynkee Technical Specification requirements for Off-Site.Power were met during the Sackfeeding effort by the availability of one off-site transmission line (Keene KISS line in service) and a delayed access power source (Vernon Hydro Station).

In conjunction with the above efforts, Maintenance department personnel with the help of. technicians supplied by NEPSCO and the battery charger vendor, performed preventative and corrective maintenance on the four battery chargers related to DC Bus LA an4d 6. Significant repairs and testing were performed on the.affected units.

Additional testing and repairs were initiated to the Stuck Breaker Failure Unit ISBFUI Logic trip cards for the 81-iT, 381 and K) breakers. The cards for 381 and KI breakers e*re found to have failed zener diodes. The 81-IT (SBFU) relay was found to be functioning properly.

NRC Form 366A (6-89)

Form 366A U.S. NUCLEAR REGULATORY COMMISSION APPROVED OS NO.3160-0104

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TEXT CONTINUATION MANAGEMENT BRANCH (P-530), U.S. NUCLEAR REGULATORY COMIISSION, WASHINGTON, DC 20555. AND TO THE PAPERWORK REDUCTION PROJECT (3160-0104). OFFICE OF MANAGEMENT

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UTILITY NAME (DOCKET NO. LER NUBER L') ) PAGE (1)

.YEA _ SEQ. REVS VIM YAtNKEE NUCLEAR POWER STATtd d4 d d 71 1 XgI 0I -O I, o OFI d s 1 TEXT (If sore space is required, use additional NRC Fore 366A) (")

tESCRIPTION OF EVENT {cont.)

Discussions with the manufacturer indicated that the zener diodes are no longer employed on newer revision trip cards and have recommended the removal of the zener diodes based on their vulnerability to voltage transients. Based on this recommendation, the Maintenance Dept. has removed the rener diodes from these units in accordance with written direction from the vendor.

After response team efforts were completed, a Root Cause/Corrective Action Report (CAR) was drafted on the event from a Switchyard perspective. In the draft report, the following conclusions were reached:

- The voltage transient on the DC 4A bus occurred when battery charger 4A-SA was disconnected from the DC-GA bus which rendered bus DC LA susceptible to voltage spikes due to the absence of a battery bank.

- The specific cause of the zener diode failures which resulted in the 81-IT and KI breaker (BFI) signals is attributed to the voltage transient which occurred on Bus DC A.

- A portion of the additional problems found with DC Bus 4A and SA battery chargers which ranged from shorted diodes/SCRs and blown surge suppressor fuses.

were concluded to be pre-existing and were responsible for the voltage transient.

CAUSE OF EVENT The Root Cause of this event is the failure of the repair department personnel to recognize the consequences of operating a DC bus without a connected battery bank.

The Maintenance Guideline, an internal Maintenance Department document prepared by the department Electrical Engineering staff, was inadequate in that it did not take into monsideration all battery charger failure modes when floating a DC bus without. a battery tos*. The conspqunces of losing battery charger power while the bus is energized without a battery connected were considered during the revision of the Guideline, but not the potential of the battery chargers to fail high or induce a high voltage spike on the tos, both which have the potential to damage electronic circuitry.

The previous revision of the Guideline called for the two DC buses (LA & BA) to tie cross-connected and fed jointly by the 4A/SA battery charger during the maintenance on the batteries. Following cross-connection, the Guideline required opening of the battery treakers. This evolution was successfully accomplished and the required work on the NRC Form 3GG (6-89)

NRFr 366A U.S. NUCLEAR REGULATORY COMMISSION APPROVED OHS NO.3150-0104 6-SO? .. EXPIRES 4/30/92 ESTIMATED BURDEN PER RESPONSE TO COMPLY WITH THIS INFORMATION COLLECTION REQUEST:

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rEXT CONTINUATION MANAGEMENT BRANCH IP-530), U.S. NUCLEAR REGULATORY COMMISSION, WASHINGTON, DC 20655. AND TO THE PAPERWORK REDUCTION PROJECT (3160-0104). OFFICE OF MANAGEMENT AND BUDGET, WASHINGTON. DC 20603.

UTILITY NAME (')DOCKET NO. (3) LERNUMBER I* PAGE (a)

YEA I _SEO.;0 l REVI IS YUIONT YANKEE NUCLEAR POWER STATION d1 d d d I 1YA I I OI

e0OfId9 TEXT{If more space is required, use additional NRC Form 366A) ("i) gUSE OF EVENT (eont.)

batteries was completed without incident. Recovery of the battery required the closure of the battery output breaker first, essentially paralleling the two battery banks until the 4Ag5A charger output breaker wns opened. In June 1990. the Guideline was revised due to Operations Department concern with paralleling batteries. The new revision required that the cross connection between bus 4A and SA provided by battery charger 4A/SA be opened prior to the reclosure of the bus 4A battey breaker. This configuration rendered bus LA without a battery and susceptible to voltage excursions from either the 4A or LAI6 battery chargers.

CONTRIBUTING CAUSES

1. 345KV and 116KV breaker failure relays were susceptible to false initiation due to control voltage transients.

2. The switchyard battery chargers were in a degraded mode such that they created DC bus control voltage disturbance when the chargers were disconnected from associated batteries.

3. Lack of Switchyard battery charger and overall Switchyard preventative maintenance.

AMkLYStS OF EVENT The events had minimal adverse safety implications.

1. The plant responded to the reactor trip and LUP as designed. The Emergency Diesel Generators operated as designed and supplied power to Emergency plant buses until off-site power was restored.

2. The Reactor Protective System operated as designed and scrammed the reactor on Generator Load Reject resulting from the 345KV Breaker Failure Signal

3. An evaluation was performed by the Operations Department relevant to the loss of both "UA and OBD Station Air compressors. The analysis concluded that the 5 minute interval in which tte "B" Station Air compressor was out of service which resulted in a 15 psig. drop in the station air supply system did not significantly challenge any plant equipment.

4. All other safety systems responded as expected.

MC Form 366A (6-89)

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LICENSEE EVENT REPORT (LER) BURDEN ESTIMATE TO THE RECORDS AND REPORT TEXT CONTINUATION MANAGEMENT BRANCH (P-630). U.S. NUCLEAR REGULATORY COMISSION. WASHINGTON, DC 20666. AND TO THE PAPERWORK REDUCTION PROJECT (3160-0104). OFFICE OF MWNAGEMENT

_AND BUDGET. WASHINGTON. DC 20603.

UTILITY NAME WM1DOCKET NO. (") LER NUMBER %') D PAGE (-"

.... YEAR l SEO. 0 tREV# l VERWONT YANKEE NUCLEAR POWER STATION d d d d X1 791 1 11-1 I-. I R II l TEXT (If more space is required, use additional NRC Form 366A) (")

CORRECTIVE ACTIONS SHORT TERM CORRECTIVE ACTIONS

1. Immediate corrective actions included recovering from the reactor scram, restoration of off-site power. and Switchyard and reactor stabilization utilizing appropriate plant procedures.

2. The current revision of the Maintenance Dept. Guideline has been-cancelled and the previous revision reinstated with an additional requirement that a review be performed prior to its use for dealing with any evolution requiring switchyard battery removal.

3. Review all other plant guidelines and Procedures pertainiing to battery switching operations.

LONGTERM CORRECTIVE ACTIONS Long Term Corrective Actions are presently being addressed per our Root Cause/Corrective Action process. The Corrective Action Report is presently being finalized. In accordance with prior commitments made to the NRC at the AIT exit meeting held in King of Prussia on 05/14/91. a letter detailing plant Corrective Actions to be initiated in response to the event and NRC concerns will be forwarded to the NRC by 07/15/91. Based on information presented in the finalized Corrective Action Report, a supplement to this report will be forwarded to the Commission.

p0OITIONAL INFORMATION There have been no similar events of this type reported to:the commission in the past five years.

ATTACH'E--S

.Sketches: a. Switchyard Distribution

b. Switchyard DC Bus Systes NRC Form 366A (6-99) .-

NRC FoM $GA U.S. NUCLEAR REGULATORY COMMISSION APPOVED NO.3150-0I04

-(6491 EXPIRES 4/30/92

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- (802)25-7711i July 11, 1"l vrv U 91-140 U.S. Nuclear RAgplatory omi@lom Documeat Control Desk Washington, D.C. 20555 RaflRZNOS Operating License Dw-20 Docket No. 50-271 Reportable Ommrrence Ho. LZA 91-14 Dear Sires As dfied by 10 CM 50.7?, w are reporting the attached Reortable Occurrence " L3 91-14.

Vry truly yor, vim"os rAsi UUOLZAR roeua COMStow Donald A. PAid Plat Manager cc$ Regional ALsiaistrator wm RegLon I 475 4 Allendale Road 1,King of prusetv, PA 19408 S71 91071 I ft DRM ' 0W0QI

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-0 0/15/91 St 2224 bours, dur moml opeatio with Reactor pnr at 100I, a Reactor SWrm occurred due to S Turbine Control Vale Fastt C1se on Generator L1ad Reject resulting frm a los of the 3451V North Switchya S= Use ent Was initiated ds a thwnderstorm im whch a lightning strike occurred on te ** pb of t 31 tranustsion line betwee enmost Tankee and Parthfield. 2h fPlt rested n th o rf all 34SKV kr Trip rea ers ( AS )} .  : et Isolatio un e en, a ut Reactor SCrM and corresponding ?r y ot flstCIS)(*AJN) Cos 2an 3 were received da to Low Reactor Vater level. n Reactor was Uilsed In Not Standby using the lain Condenser, Condeste edte yst.

At 2100 bours on 06/16/91, after Reactor depressurisation vaS camleted Shutdown Cooling ust ti D p o US th 053 loop vat Initiated. th reactor reached Cold Shutdomm at 00 hour0 days <br />0 hours <br />0 weeks <br />0 months <br /> on 06191. Th reator s retund to CritiC&a at 1413 hours0.0164 days <br />0.393 hours <br />0.00234 weeks <br />5.376465e-4 months <br /> -on 06/20/91.

th Root Cause of tW ev t Is a defective (horted) transistor in offsite (Scobie Fond Protectie Relaying STate Carrier euilment. t2 nee to perform additiona1 testing of Carrier syst-s isbeing evaluated.

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De 06/1/S91 at 2224:22 bours, during normal operation vith Reactor power at 1002, a Reactor scram occurred as a result of Turbine Control Valve Vast Closure on Generator Load Rejct due to a-loss of the 345KV North Mvitcbyard Bus. the event vas initiated duringar thunderstorm Is which a lightning strike occurred on the 5l" phase of the 381 transmission line between Varmont Tanke and Northfield, Ma. The fault resulted In the opening of the 81-tT and 381 Air Trip Breakers (AM). An ueanticipated trip of the 379 Scoble lIne on Carrier Overreach also occured coincident vith the fault resulting In trips of the 379 and 79-40 A19s. The cumulative effect of the breaker openings left only the Coolidge (340) Line connected to Vermont Yankee.

This line subsequently tri ped on overload, opening tbaT AST. . Vith all 345KV ALTs open, all load paths for Yermot Tnkee's output were shed which resulted In a Generator Load Reject aid subsequent plant scro.

following the Generator Load Reject and Turbine Control Valv Vast Closure, plant buses remained connected to the Main Generator via the Aux Transformer for approximately 30 seconds at which point the Turbine tripped from & OLo Scram Air Reader Pressure Time Delayed Signal.

-Deing the first 10 seconds of this Interval, plant buses experienced voltage oscillations whle-the Main Generator voltage output attepted to regulate during the transition from 00fI to approxiately 5X load. The voltage oscillations experienced resulted in the folloving major system responses:-

- Primary Containment Isolation System (?CIS) (*.J)Groups 1A, 2A, 3U, SA and 53 vere received due to low 120VAC Instrnent bus voltarw resulting in the closure ofCroup S Isolation valves as required.

- *A And

• Stat tion Air Compressors tripped due to lov 120VAC Instrunent bus voltage. Both air Compressors vere restarted at 2233 hours0.0258 days <br />0.62 hours <br />0.00369 weeks <br />8.496565e-4 months <br />.

- Reactor Decirculation Units (1i0s) 2 and 4 Tripped due to dropout of a 120VAC Orywell Cooling and Control Room Air Conditioning BlockingSrelay from low voltage. both IRNs wer restarted at 2233 hours0.0258 days <br />0.62 hours <br />0.00369 weeks <br />8.496565e-4 months <br />.

s oB and *Cm Reactor fedvater Pumps Tripped on Low Suction Pressure resulting fro transients In the Condensate System which were caused by the undervoltage conditions. Fed flow was restored vithin 10 seconds.

- *A and 5' 3.circ pump Breakers opened due to Low Lube Oil ?zessure. The loss of Lube Oil was a result of blown control circuit fuses.

- 'a' nd 6B' Advanced Off Gas (AOG) Recombinnrs tripped due to low 12OVAC Instrument bus voltage. This resulted in the blovout of a Steam Jet Air Vector (SJAZ) Rupture Disc.

In addition to the (lov voltage) received ICtS signals, a decreasing 127 inch 'LOI Reactor Vater level Val experienced 7 seconds Into the event, at 2224:29 hours, generating a Reactor Scram and remaining ?CIS Group 25 and 3D isolation sinals resulting in the required Group 2 nd -3 Isolations. The water level reached & lov of 122 Inches and is attributed to void collapse from the initial Scram.

• snergyInformation Identification System (2EES) Component Identifier

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Approxiately 10 seconds into the event, at 2224:32 hours, the 381 ATS reclosed which

-tonergized the Auto Transformer. The 379 AT3 reclosed 12 seconds later at 2224:44 hours.-

i.Coiocident vith the turbine trip at 2224:50 hours, a Generator Lockout was Initiated which zesulted to fast Transfer of plant buses to the Startup Transformers. Vith reliable 115KV power available from the Auto Transformer, 4KV and 480 Ls voltages remained stable from this point on.

In response to the Scram, Operations personnel entered bmergency Operating Procedure 0-3100 8cran Procedurte which governs reactor operation in A post-scrm environment. Operators noted during the Scras that approximately 25% of the Control Rods lacked-Vull In" Indication (tbe associated rod display was blank). Reactor powe a verified to be less than 2X, by Average tower Range ponitor (UAPM) downscale Indication. This' condition. prompted the entry Amtouergency Operatang ?rocedure 01-3101 lReactor tressure Vessel (tV) Control -Procedure to which a u Scrm was initiated at 2226 bours and subsequently reset at 2228 hours0.0258 days <br />0.619 hours <br />0.00368 weeks <br />8.47754e-4 months <br />. Upon tesetting of the Scram, all rods indicated -0O' and 03-3101 was exited. The loss of Indication for a portion of the Control Rods Is attributed to a knova phenom na called rod overtravel in which a loss.of position indication can occur If a control rod Wnserts slightly past the full An position resulting In a misalignment of the corresponding position Indication switches.

Duting the event, Reactor pressure and level were maintained using the Rain Condenser, Condensate, and eoedvater systems. At 2100 hours0.0243 days <br />0.583 hours <br />0.00347 weeks <br />7.9905e-4 months <br /> on 06/16/91, Shutdown Cooling vas initiated

Insthe a RMS pump on the -OS loop. The reactor reached Cold Shutdown at 0500 hours0.00579 days <br />0.139 hours <br />8.267196e-4 weeks <br />1.9025e-4 months <br /> on b 06/17/91. Tbe reactor vas returned to critical at 1413 hours0.0164 days <br />0.393 hours <br />0.00234 weeks <br />5.376465e-4 months <br /> on 06/20/91.-

Ci...O i The Root Cause of this eventis; a defective (shorted) transistor in offaite (Scobie Pond)

Ptrotective Rulaying System Carrier equipment. The lightning strike hibch occurred on the OB' pha&e of the 381 Transmission line between VT. and Northfield, Ma. would normally have only resulted In an isolation of the 381 line. However, the defective component in the Scobie tond Carrier equipment caused a subse uent loss of the 379 llne. This routed the full Generator output througb the 340 (Coolidge) line. The Coolidge line cannot handle full generator output.

aad tripped out on overload which resulted in a*loss of the 3451V yard and caused the Reactor

• to Scram on Generator Load Reject.

After the plant Scram, an extensive testing and troublshooting effort was performed by, Tazaont Yankee and Nev England tower Service Co. (NIPSCO) to determine the cause of the Scobie LUne Carrier trip. It was found that the the equipment on the WT end operated as dtsi ed and sent a Carrier block sgnal to Scoble to prevent tripping. Although the signal was receIved at Scobil Pond, the trip signal v"a not blocked. A failed transistor Inthe Carrier equipment logic section prevented the blocking signal from reaching the tripping logic. Since the trlplnS loglc did not see a blocking sIgnal It caused the Scoble line to trip at Scobie Pond 02dpversont Yankee.

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V&CSILhIT NAN (1) DOCE3T *0 (2) los NUMBER (5) PAGEa3)

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V~OROws sa sas NUCLEAR PowSa STAssON 0151010101211 9 1l 1l 4l 014 or 4 ISIT (If mote space is required, use additional NRC Form 366A) (i7)

1. Ligtning strike on the B phase of the Northfield line was the contributing cause to the event.

The events had minimal adverse safety implications.

1. The Reactor Protective System operated as designed and scrammed the reactor on Generator Load Reject resulting from the loss of 345KV pover.

2. Fast transfer to an off-site source occurred as designed upon receipt of a Generator Lockout.

3. All other safety systems responded as expected.

Immediate corrective actions included recovering from the reactor scrams, troubleshooting and repair of the Scobie Pond equipment, and reactor stabilization utilizing appropriate plant procedures-VYMaintenance Department and VELCO Svitchyard Engineers vill evaluate testing requirements for Svitchyard Carrier systems.

The above Long Term Corrective Action will be completed by 11101/91.

There have been no similar events of this type reported to the commission In the past five t earn.-

SKETCH: Switchyard Distribution

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-X Entoery Nudear Operations, Inc.

Vermont Yankee P.O. Box 0500

' . Entergy 185 Old Ferty Road BraWeboro, Vr 053024500 Tel 802 2S7 6271 June 14,2005 BVY 05-064 U.S. Nuclear Regulatory Commission ATTN: Document Control Desk Washington, DC 20555

Subject:

Vermont Yankee Nuclear Power Station License No. DPR-28 (Docket No. 50-271)

Reportable Occurrence No. LER 2004-003-01 As defined by 10 CFR 50.73(a)(2)(iv)(A), we are submitting the attached revision for a Reportable Occurrence that occurred on June 18,2004 as LER 2004-003-01 to report a change to the root cause of the event based upon the results of laboratory analysis.

Sincerely, Entergy Nuclear Operations, Inc.

Vermont Yankee 4-William F. Phl General lan, cc: USNRC Region I Administrator USNRC Resident Inspector - VYNPS USNRC Project Manager - VYNPS Vermont Department of Public Service a C-,--

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9-NRC FORM 366 U.S. NUCLEAR REGULATORY COMMISSION APPROVED BY OMB: NO. 3150.0104 EXPIRES: 06/3012007 (6-004) Estimated burden per response to comply with this mandatory collection request 50 hours5.787037e-4 days <br />0.0139 hours <br />8.267196e-5 weeks <br />1.9025e-5 months <br />. Reported lessons learned are Incorporated Into the licensing process and fed back to Industry. Send comments regarding burden estimate to the Records and FOlAIPlivacy Service Branch (T-5 F52). U.S.

LICENSEE EVENT REPORT (LER) andeguatoy Ofer. Officeof lnformation Detsko Afais. E .020.(350.104). Office of Management and Budget, Washington. 020503. If a means used to Impose aniInformation colecion does riot display a currently valid OMB control number, the NRC may niot conduct or sponsor, and a person Is not required lo respond to. the

_ :__ __ _ In ormation collectfon.<

1. FACILITY NAME VERMONT YANKEE NUCLEAR POWER STATION (VY)

4. TITLE

2. DOCKET NUMBER 05000 271 PAGE I OF 5 Automatic Reactor Scram due to a Main GeneratorTrip as a result of an Iso-Phase Bus Duct Two-Phase Electrical Fault S.EVENT DATE 6. LER NUMBER 7. REPORT DATE B.OTHER FACILITIES INVOLVED YER1ER ISEQENIALRE FACILIIY NAEDOCKCET NUMBER MONTH DAY jj N SoR I o MONTH DAY YEAR NA W 05000

_ FACILITY NAME DOCKET NUMBER 06 18 2004 2004 - 003 - 01 06 14 2005 N/AO0000

9. OPERATING MODE 11.THIS REPORT IS SUBMiTTED PURSUANT TO THEREQUIREMENTS OF 10 CFR§ 5(Checkaltlhaf appl

[J 20.2201(b) U 20.2203(af3)() 50.73(a)(2X()(C) D 50.73(a)(2)(vli)

N 20.2201(d) L 202203(a)C3)(H) 3 50.73(a)(2)11)(A) J 50.73(a)(2XvIii)(A) go 20.2203(a~l) DJ 20.2203(aX4) El 50.73(a)(2)(1i)(B) n 50.73(a)(2Xvifl)(B)

O 20.2203(a)S2)M a 50.36(CX1)(1)(A A 0 50.73(a)(2KXI Q 50.73(a)(2)(IxXA)

10. POWER LEVEL a 202203(aX2)(9) Q 50.36(c)(1)(I)(A) El 50.73(aX2)(lvxA) a 50.73(a)(2)(X)

O 202203(a)(2)Xiii) a 50.36(cX2) 3 50.73CX2)(vXA) U 73.71(a)(4)

O 202203(aX2Xlv) 0 50A6(aX3)(i) 50.73(aX2Xv)(B) Q 73.71(a)(5) 100 0 202203(aX2)(v) 50.73(aX2)(IXA) D 50.73(a)2)(2v)(C) Q OTHER o 20o2203aX2)c(vo 3 50-73(ax2)xB) a 50.73(a)(2)(v)(D) Spodlin AbsrCnt below or1n NRC Form 366A

12. UICENSEE CONTACT FOR THIS LER I

1FACILTY NAME ITELqrI4NE NU!MER PXW*dA~a Cede) 1Ii F:M - G-nal ---- - - (822771 - I

13. COMPLETE ONE LINE FOR EACH COMPONENT FAILURE DESCRIBED IN THIS REPORT CAUSE l SYSTEM COMPONENT l MANU REPORTABLE I F rRER TO EPIX jFACTURER TO EPIX E E FCON [ P295 Yes E I EL IPBU P295 Yes E I EL BDUC l P295 Yes E LAR I G066 Yes

14. SUPPLEMENTAL REPORT EXPECTED 15. EXPECTED ONTH DAY EAR SUBMISSION a YES (1yess complete I& EXPECTED SUBMISSION DATE) NO DATE ABSTRACT o140 Orpce L..papsonety 15 aSpacedhbpewin "iea) tLWo On 06/18104 at 0640, with the plant at full power, a turbine load reject scram occurred due to a two phase electrical fault to ground on the 22 kV Iso-phase bus. All safety systems responded as designed and the reactor was shutdown without incident. Off-site power transmission lines and station emergency power sources were available throughout the event. Arcing and heat generated during the fault damaged an area around the iso-phase bus ducts and Main Transformer low voltage bushings. The electrical faults disrupted an oil line flange between the Main Transformer oil conservator (expansion tank) and the ACT phase low voltage bushing box, and the leaking oil Ignited. Fire suppression systems activated automatically. An Unusual Event was declared at 0650 for a fire lasting greater than 10 minutes. The VY fire brigade and local community fire departments declared the fire under control at 0717. At 1245, the Unusual Event was terminated. The electrical grounds that Initiated the event were caused by loose material in the uB" Iso-phase bus duct as a result of the failure of a flexible connector. The grounds raised the voltage on the WA' and 'C0 Iso-phase busses contributing to the failure of the "A. phase surge arrester.

The root causes of the event were determined to be the result of a flexible connector fabrication deficiency

-and preventative maintenance not being performed on the surge arresters located in the Main Generator Potential Transformer (PT) Cabinet. There was no release of radioactivity, breach of secondary containment or personnel injury during this event.

FOR 820)PITD NRC! E AE

.NRC FORMNR 56 366 (6W0042 PRINTED ON RECYCLED PAPER

II NRC FORM 366A U.S. NUCLEAR REGULATORY COMMISSION LICENSEE EVENT REPORT (LER)

1. FACILITY NAME 2. DOCKET 6. LER NUMBER 3. PAGE VERMONT YANKEE l SNU MBER lNLUBER NUCLEAR POWER STATION 05000 271 2 OF 5 2004 - 003 - 01

17. NARRATIVE (ff more apacei fquhrd, meddonal copies of ARC A= 364)

DESCRIPTION:

On 06/18/04 at 0640, with the plant operating at full power, a two-phase electrical fault-to-ground occurred on the 22kV System (EIIS=IPBU, BDUC). The ABE phase faulted to ground Inthe low voltage bushing box on top of the Main Transformer (EIIS=XFMR), and the WA* phase faulted to ground in the surge arrester cubicle of the Main Generator Potential Transformer (PT) Cabinet through the 'A' phase surge arrester (EIIS=LAR).

Within less than one cycle (11 milliseconds) of the Initial electrical fault, the Main Generator protective relaying sensed the condition and Isolated the generator from the grid within the following 5 cycles (80 milliseconds). A generator load rejection reactor scram then occurred. Approximately 400 milliseconds following the initial electrical faults to ground from OK and U.B"phases, arcing and Ionization In the ¶B" phase low voltage bushing box carried over to the 'C" phase low voltage bushing box on top of the Main Transformer. The electrical faults disrupted a flange in the oil piping between the Main Transformer oil conservator (expansion tank) and the "Cm phase low voltage bushing box. The arcing or heat from the fault Ignited the oil, resulting In a fire. Fire suppression systems activated automatically as expected.

The plant response following the scram was as expected, with the exception that both Recirculation pumps tripped and other AC voltage effects were observed as a result of the voltage transient associated with the high fault current. All safety systems functioned as designed and the reactor was shutdown without Incident. There

- - was no release of radioactivity and no personneljnjuries..

The W fire brigade was dispatched at 0641. An Unusual Event was declared at 0650 due to "Any unplanned on-site or In-plant fire not extinguished within 10 minutes". The VY fire brigade Initiated fire hose spray from a nearby hydrant and quenched the fire. Local fire departments began arriving at 0705. The fire was declared under control at approximately 0717 and re-flash watches were established. Off-site power transmission lines and station emergency power sources were available at all times throughout the event.

The States of Vermont, New Hampshire and Massachusetts were provided with Initial notification of the event at 0721. The NRC Operations Center was notified of the event at 0748, recorded as NRC Event Number 40827. In addition to the declaration of the emergency classification, a 4-Hour NRC Non-Emergency Notification was completed due to an RPS actuation with the reactor critical, pursuant to 10CFR50.72(b)(2)(lv)(B). At 1245, the Unusual Event was terminated.

I The iso-phase bus flexible connector (EIIS=FCON) that failed (expansion joints) was part of the original bus supplied and designed by H. K Porter, Drawing Numbers ¢-191144 & G-191146. All flexible connectors were replaced with an upgraded design supplied by Delta-Unibus. The surge arresters were GE Alugard Station Arrestors, Model Number 9L1 1LAB, Installed as original plant equipment. All of the surge arresters were replaced.

CAUSES:

The root causes of the event were determined to be the result of a flexible connector fabrication deficiency and preventative maintenance not being performed on the surge arresters located In the Generator Potential Transformer (PT) Cabinet.

The electrical grounds that Initiated the event were caused by loose material In the "B" iso-phase bus duct as a result of the failed flexible connectorthat allows the Iso-phase bus to thermally expand and contract. The grounds raised the voltage on the UAW and "Cm Iso-phase busses, contributing to the failure of the SAX phase surge arrester.

NRC FORM 386A 11-2001)

NRC FORM 366A US. NUCLEAR REGULATORY COMMISSION LICENSEE EVENT REPORT (LER)

1. FACILITY NAME 2. DOCKET 6. LER NUMBER 3. PAGE SEFM KVIAEtSION VERMONT YANKEE NUMBE NUMBER NUCLEAR POWER STATION (VY) 050 271 3 OF 2004 - 003 - 01

17. NARRATIVE (Itmore space Is eqtre4 use addtonalcopies ofNRC Fom 3664 I Although the iso-phase bus Is subjected to preventative maintenance cleaning and Doble Testing each refueling outage, the cleaning and Inspection Is limited to the stand-off Insulators. Additional Inspections to evaluate the condition of the bus (including Its flexible connectors) would have detected the degraded flexible connectors.

A detailed equipment failure evaluation was conducted on the flexible connectors associated with the Main Generator 22 kV Electrical System. The cause of the 8B' phase flexible connector failure was that weld porosity and excessive weld grinding (reinforcement removal) during original fabrication weakened the laminate weld.

During approximately 32 years of plant operation, differential thermal expansion and contraction caused thermally Induced stress at the flexible connector attachment welds. These thermally Induced stresses caused the propagation of fatigue cracks at the attachment welds. The fatigue cracks grew and, combined with voids In the weld metal and lack of edge welds, resulted Inover stressing the remaining weld metal that failed due to tensile and shear over load ultimately leading to the failure and separation of the outer laminate from the bus.

The end closest to the generator on the 'B" phase flexible connector failed first allowing the outer laminate to be lifted Into the cooling air flow, thereby placing additional stresses on the undersized weld ligaments at the transformer end.

There was no sign of cracking at any other flexible connector weld, Indicating that the Increased air

-flow/velocity in the bus duct did not result In flow Induced vibration of the outer-iaminates and contribute iothe.-

failure. The Increased air flow within the bus duct following the refueling outage modifications may have accelerated the failure timetable for the laminate; however, the failure would have occurred at some time In the I near future at the original flow rates.

The need for inspecting the flexible connectors was Identified during a recent review of Industry operating experience (OE). This OE is being Included as recommended preventative maintenance for future outages; however, It was not included in the preventative maintenance Inspection performed during RFO-24.

The OAw surge arrester failure was the result of the combination of a ground occurring on the "B* iso-phase bus that caused an Increase In voltage on the SAX and OC Iso-phase busses and not performing preventative maintenance necessary to monitor age related degradation of the 'A' surge arrester. Industry experience has revealed that surge arresters degrade over time due to a combination of age, service environment and service conditions. Periodic Inspectionitesting could have detected degradation and allowed replacement prior to failure.

Three contributing causes were Identified by the Investigation: failure to effectively use Industry OE to prevent similar events from occurring at VY, Inadequate preventive maintenance of the generator Iso-phase bus, and Inadequate failure modes and effects evaluation. Specifically, It was noted that; the actions taken by VY In response to recommendations provided within the INPO Significant Operating Experience Report (SOER) 90.01 for "Ground Faults on AC Electrical Distribution' were Inadequate. In addition to the SOER, guidance provided within EPRI's Isolated Phase Bus Maintenance Guide' TR-1 12784 (1999) for the 22 kV flexible connectors and periodic Inspections/lesting was not utilized.

NRCFORht66A(142002

NRC FORM 366A U.S. NUCLEAR REGULATORY COMMISSION LICENSEE EVENT REPORT (LER)

1. FACILITY NAME 2. DOCKET 6. LER NUMBER 3. PAGE YEAk UBR NUMBER VERMONT YANKEE . YA EN4TOL Q0 NUCLEAR POWER STATION (VY)000 5 271_ - 4 OF E-2004 00 1

17. NARRATIVE (iNmoe space Isrequired, use additonalcopes of NRC Form 366A)

ASSESSMENT OF SAFETY CONSEQUENCES:

All safety systems and fire suppression systems responded as designed. The reactor was shutdown without Incident. Off-site power sources and station emergency power sources were available at all times throughout the event. Emergency response personnel acted promptly to prevent the fire from significantly damaging or breaching the adjacent turbine building. There was no release of radioactivity or personnel Injury during this event. Therefore, this event did not significantly Increase the risk to the health and safety of the public.

CORRECTIVE ACTIONS:

Immediate:

1.An Unusual Event was declared at 0650.

2. The station fire brigade on scene to combat the fire at 0652. Local fire departments arrived on-site at 0705 to provide assistance. The fire was under control at 0717.

3. Completed the initial notification to the States of Vermont, New Hampshire and Massachusetts at 0721.

4. Notified the NRC Operations Center of the Unusual Event at 0748.

5. Secured all affected site and plant areas for personnel safety and Isolated affected equipment as necessary to maintain Investigation Integrity.

-6:Condition Reports were generated for thisevent and potentially associated issues as appropriate for entry into the Corrective Actions Program.

7. A Root Cause Investigation team was established to assess damage and to secure the area.

8. Initial testing was completed on the main transformer, station auxiliary transformer, and main generator with no Indication of damage that would affect the operation of the transformers or generator.

9. A Preliminary Nuclear Network Entry was completed to inform the Industry of the Initial findings and conditions of the event.

Prior to Plant Start Up:

1.The phase A, B, and C 22 kV surge arresters and capacitors were replaced prior to energizing the 22kV bus.

2. The phase A, B. and C 22 kV flexible connectors were replaced with an upgraded design supplied by Delta-Unibus prior to energizing the 22kV bus.'

3. A cleanliness Inspection was performed and documented as part 'of Iso-Phase Bus Duct Modification.

4. Maintenance department personnel Inspected the cooler and leads fans for foreign material. Foliowing operation of the fans, an additional Inspection of the fans and coolers was performed.

5. Operator Alarm response sheets were revised to enhance operator actions in the event of future ground faults.

6. A preventative maintenance schedule was established for increased sampling of transformer oil for the main, auxiliary, and two startup transformers for four weeks after start-up.

7. The iso-phase bus duct system was monitored after assembly with the fans running to ensure that vibration levels were acceptable.

8. VY discussed this event and associated Issues with the Entergy Fleet and Industry experts as'necessary to gather Information pertinent to the root cause Investigation and equipment recovery.

NRC FORM 366A (1401

I NRC FORM 366A U.S. NUCLEAR REGULATORY COMMISSION (14W1)

LICENSEE EVENT REPORT (LER)

1. FACILITY NAME 2.DOCKET 6. LER NUMBER . PAGE VERMONT YANKEE NUMBER NUMBER .

NUCLEAR POWER STATION (VY) 05000 271 5 OF 5

. 2004 -003 -01

17. NARRATIVE (11more space is reqide use additional coiges of NRCFotn 36A Long Term:

1.The 22kV surge arresters and capacitors have been Included In the preventative maintenance program with specifically defined periodic replacement requirements. With this change the cubicles containing these components have been assigned unique Preventative Maintenance Identification numbers and the activities associated with the planned maintenance has been expanded to reflect lessons learned from this event.

2. The 22kV Iso-phase bus preventative maintenance program was revised to provide periodic Inspection requirements to prevent recurrence of this event. This revision provides direction for extensive Iso-phase bus Inspection, Including the flexible connections.

3. Completed testing of the selected components Involved In the event. The root cause analysis report has been revised to reflect the findings from the off-site lab analysis.

ADDITIONAL INFORMATION:

Approximately.350 Condition Reports generated since 06f01/1995 regarding the components and systems Involved with this event were reviewed during the root cause Investigation. No similar event with a related cause was Identified to have occurred at Vermont Yankee during this period.

NRC FORM 366A (1400)

~~:

Entergy Nuclear Northeast Entergy NuclearOperations, Inc.

Vermont Yankee P.O. Box 0500

. "Entergy 185 Old Feny Road Brattleboro, VT 05302-0500 Tel 802 257 5271 September 22, 2005 BVY 05-087 U.S. Nuclear Regulatory Commission

ATTN: Document Control Desk Washington, DC 20555.

Subject:

Vermont Yankee Nuclear Power Station License No. DPR-28 (Docket No. 50-271)

Reportable Occurrence No. LER 2005-001-00 As defined by 10 CFR 50.73(a)(2)(iv)(A), we are reporting the attached Reportable Occurrence that occurred on July 25, 2005 as LER 2005-001-00. No Regulatory Commitments have been generated as a result of this event.

Sincerely, Entergy Nuclear Operations, Inc.

Vermont Yankee William F. KidguireN General M ant Operations cc: USNRC Region I Administrator USNRC Resident Inspector - VYNPS USNRC Project Manager - VYNPS Vermont Department of Public Service

NRC FORM 366 U.S. NUCLEAR REGULATORY COMMISSION APPROVED BY OMB: NO. 3160.0104 EXPIRES: 0@301203 (r- ) Estimated burden per response to comply with this mandatory collection request: 50 hours5.787037e-4 days <br />0.0139 hours <br />8.267196e-5 weeks <br />1.9025e-5 months <br />. Repoed lessons arned are Incorporated Into the licensing process and fed back to Industry. Send comments regardIng burden estimate to the Records and FOIA/rivacy Service Branch eF2).

U.s.

Nuclear Regulatory Comrntsston. Washington. DC 20555001,.or itre LICENSEE EVENT REPORT (LER) imto Infoollects@nrc^gov, and to the Desk Officer, Office of Inmation and RegulatoryAffaiNE -10202. (31504104), Oflice of Management and Budget. Washington CC20503 If. a means used to impose an Information collection does not aisplay a currently valid OMB control number, the NRC may not conduct or sponsor, and a person Is not required to respond to, the Information collection.

1. FACILITY NAME 2. DOCKET NUMBER & PAGE VERMONT YANKEE NUCLEAR POWER STATION (05000 271 I OF 4

4. TITLE Reactor Trip Caused by an Electrical Insulator Failure In the 345 kV Switchyard due to a Manufacturing Defect

5. EVENT DATE 6. LER NUMBER 7. REPORT DATE 8. OTHER FACILITIES INVOLVED MONTH 07 DAY 25 YEAR 2005 2005 11 SEQUENTIAL

.001

~

00 REV N.

09 22 2005 FACITY NAME N/A05000 FACILImYNAME NA05000 0OC5r0NUMBER DOCKET NUMBER 9.OPERATING MODE 11. THIS REPORT IS SUBMITTED PURSUANT TO THE REQUIREMENTS OF 10 CFRO: (Check althat apply)

O3 202201(b) [ 202203(a)(3)(!) a 50.73(a)(2M1)(C) 0 50.73(a)(2)(,AI)

N 0 20.2201(d) 0 202203(aX3)0Q) 0 50.73(aX2)0(IXA) D 50.73(a)(2XvI1XA)

D 20.2203(a)(1) [J 20.2203(a)(4) 0 5.73(sX2)0iXB) a 50.73(a)(2XviliXB)

O 20.2203(a)(2)(i) D 50.36(cX1)(1(A) 0 50.73(a)(2)(i9) o 5D.73(a)(2)(IxXA)

10. POWER LEVEL 0 202203(a)(2X1) D 50.36(c)1)i)(A) E0 50.73(a)(2Xhv)(A) 50.73(a)(2Xx) o 20.2203(a)(2)(110 E350.36(cX2) 50.73(eX2Xv)(A) i73.71(SX4) 100 0 20.2203(a)(2)Mv) 0 046(aX3)(l) Q3 50o73(ax2)(v)(B) 73.71(a)(5) o 20.2203(a)(2)(v) D 60o73(aX2)zwA) 0 so.73(a)(2)(v)(c) a a

OTHER 0 20.2203(a)(2)(vi) 0 50.73(aX2)(1)(B) D SO673(a)(2mvxD) Speorfy inAbstract below or In NRC Form 366A

12. UCENSEE CONTACT FOR THIS LER CONTACT NAME TELEPHONE NUMBER (hsde eaCoda)

William F. Maguire, General Manager Plant Operations .(802) 257-771

13. COMPLETE ONE UNE FOR EACH COMPONENT FAILURE DESCRIBED IN THIS REPORT CAUSE SYSTEM COMPONENT FACTURER ETORTBX CAUSE SYSTEM COMPONENT FACTURER TOEPOTB B FK INS LOSS Y B MOD S318 Y QYES

14. SUPPLEMENTAL REPORT EXPECTED (ffyes, complete I5. EXPECTED SUBMISSION DATE) ~ NO

[ 15 EXPECTED SUBMISSION DATE MONTH DAY YEAR ABSTRACT (Lftt to 1400 spaces La.. appoximatety 15 single-saced 4Vewnten Unes)

On July 25, 2005 at 1525, with the reactor at full power, a generator load reject trip and subsequent reactor trip occurred as a result of an electrical transient that originated in the 345 kV Switchyard. The electrical transient was due to a failure of the 345 kV Motor Operated Disconnect (MOD) Switch, T-1, SC' phase that was caused by the failure of an electrical Insulator. An off-site laboratory performed an examination of the porcelain Insulator revealing that the failure was caused by a manufacturing defect. The appropriate NRC 4-hour notifications were completed at 1735 In accordance with 10 CFR 50.72(b) as NRC Event Number 41868. This event Is being reported as an LER pursuant to 10 CFR 50.73(a)(2)(iv)(A) as an event that resulted in the automatic actuation of systems listed within 10 CFR 50.73(a)(2)(iv)(B). Plant equipment and operator response to the event was as expected, and the reactor was shutdown with no complications. No release of radioactivity or personnel Injury occurred as a result of this event. Therefore, this event did not Increase the risk to the health and safety of the public.

NRC ORM355(6.204)PRITEDON RCYCED APE NRC FORM 366 (&=w4 PRINTED ON RECYCLED PAPi

NRC FORM 366A U.S. NUCLEAR REGULATORY COMMISSIOI 4 (142001)

LICENSEE EVENT REPORT (LER)

1. FACILITY NAME 2. DOCKET 6. LER NUMBER 3. PAGE YEAR SEQUENTIAL REVISION VERMONT YANKEE YA I NUMBER NuMER NUCLEAR POWER STATION NY) 05000 271 2  : 2 OF 4

. 2.D 0 0 05001

17. NARRATIVE (ifmore space Isrequired use addtonal copes of NRC Fom 366A)

DESCRIPTION:

On July 25, 2005 at 1525 with the reactor at full power, a generator load reject trip and reactor scram occurred due to an electrical transient that originated in the 345 kV Switchyard. An electrical Insulator [EIIS=INS, FK] ailed, causing a failure of the "CO phase on the 345 kV Motor Operated Disconnect (MOD) Switch T-1 [EIIS=, MOD,FKJ ultimately leading to a reactor scram. The plant was placed in a stable condition and reactor water level was restored to its normal band within 25 seconds of the condition that promulgated the event. Plant equipment and operator response to the event was as expected and the reactor was shutdown with no complications. The appropriate NRC 4 hour4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> notifications were completed at 1735 in accordance with 10CFR50.72(b) as NRC Event Number 41868. This event is being reported as an LER pursuant to I OCFR50.73(a)(2)(iv)(A) as an event that resulted in the automatic actuation of systems listed within 10CFR50.73(a)(2)(iv)(B).

The T-1 MOD Is physically located between the 345 kV windings of the Main Transformer and the Main Generator output breakers 1T and 81 -IT. The electrical insulator that failed was located on the line side of T-1 MOD, providing support for the NC" phase of T-1 MOD. The insulator that failed was manufactured by Lapp Insulator Company, Model J80104-70 Post Stack Insulator, Drawing 3597-51, RO.

Following the plant trip, interviews were conducted with personnel who observed the 345 kV Switchyard events as they transpired, thereby supporting the following conclusions:

1. Arcing occurred at the "C" phase of the T-1 MOD switch.

2. Part of the T-1 MOD switch fell, resulting in a number of audible sounds.

3. Flashes occurred while the T-1 parts fell.

4. The 345 kV high line between the tower and the 345 kV Switchyard moved up and down after the insulator fell.

5. T-1 MOD opened after the fault occurred.

During the first 14 seconds of the event, the following automatic system responses occurred as designed without operator intervention. Action times are provided In the brackets succeeding each item where appropriate:

1. The OC" Phase 87/TL1 Differential Relay senses the development of a *C" Phase to Ground Fault that is a result ofthe arcing at the T-1 disconnect caused by the insulator failure.

2. The Generator 86/TL1 Tie LUne Lockout Relay actuated due to a trip signal from the associated "C" Phase 871TL1 Differential Relay. (T=O]

3. Main Generator Breakers 81-1 T and iT open from the 86/TL1 signal, isolating the fault from the 345/115 kV system. [T=30 to 33 milliseconds]

4. 4 kV Bus 1 and 2 High Speed Synch Check Relays 25/1 and 25/2 indicated a loss of synchronism between the Auxiliary and Startup Transformers. As designed, this blocks a Fast Transfer of station loads to the Startup Transformers as necessary to prevent possible equipment damage that could occur due to an out-of-phase transfer. [T=33 milliseconds]

5. Generator Primary Lockout Relay Trip indication received on ERFIS. [41 milliseconds) NOTE: The Lockout Relay to ERFIS is received via an auxiliary relay, therefore the trip actually occurred 10 milliseconds before the Indication was received.

6. Turbine Trip is actuated by a Main Generator Lockout Relay. [T=90 milliseconds]

7. Both channels of the Reactor Protection System (RPS) are received for a full Reactor SCRAM - all rods fully.

Inserted. The ERFIS sequence,of events log Indicates that the Main Generator Load Reject Scram Signal was received just prior to the Turbine Stop valve Closure Signal. [T=1 36 milliseconds] RPS system actuation Is reportable to the NRC as an LER pursuant to 10CFR50.73(a)(2)(lv)(A).

8. "A" and 'C" Reactor Feedwater Pumps are automatically trpped by the 4 kV Bus Fast/Residual Transfer Scheme. This occurs as a result of the Startup Transformer Breakers not closing within 0.3 seconds of the opening of the Auxiliary Transformer Breakers. Reactor Feedwater Pump trips are expected on a Residual Bus Transfer. (T=350 milliseconds]

NRC FORM 366A (14001)

NRC FORM 366A U.S. NUCLEAR REGULATORY COMMISSION LICENSEE EVENT REPORT (LER)

1. FACILITY NAME 2. DOCKET c . LER NUMBER 3. PAGE VERMONT YANKEE NUCLEAR POWER STATION (VY) 05000 271 j TA YEAR I

SEQENTNAL M

ERVISN NUMBER i RERVISION 3 OF 4

. 2006 001 -00

17. NARRATIVE (f mornspace Isruquired,use adddional cpies of NRC Fwm 366A)

9. Breakers 13 and 23 close to re-energize Bus 1 and 2 after bus voltage has decayed to 1000 volts. [T=623-705 milliseconds]

10. "A" Service Water Pump Starts. [T=1 second]

11. "B"Standby Gas Treatment System (SBGT) starts as a result of the Residual Bus Transfer. [T=2 seconds]

12. Reactor Water Level Low (127") Scram Signal initiates a Primary Containment Isolation System (PCIS) Group 2,3 and 5 Isolation. [T=5.5 seconds] PCIS actuation is reportable to the NRC as an LER pursuant to 10CFR50.73(a)(2)(iv)(A).

13. WASBGT System starts on a Reactor Water Low Level Signal. [T=7 seconds]

14. The 4 kV Supply Breaker to the OB Recirculation Motor Generator (MG) trips on MG system oil pressure following a six second delay in MG control logic. [T=8 seconds]

15. Reactor Low-Low Water Level (82.5") and PCIS Group 1 Isolation. The following system actions occurred for the Group 1 Isolation; Main Steam Isolation Valves (MSIVs) closed, Reactor Core Isolation Cooling (RCIC)

System start and Inject signal, High Pressure Coolant Injection (HPCI) system start and Inject signal, both Emergency Diesel Generators started (running unloaded), and the A Recirculation Pump MG Supply Breaker tripped. [T=14 seconds]

PCIS actuations are reportable to the NRC as an LER pursuant to 10CFR50.73(a)(2)(iv)(A). The NRC was notified of the PCIS actuation 10CFR50.72(b)(3)(iv)(A).

ECCS actuations are reportable to the NRC as an LER pursuant to 10CFR50.73(a)(2)(iv)(A). The NRC was notified of this event per 10CFR50.72(b)(3)(iv)(A) and 10CFR5O.72(b)(2)(lv)(A)

The following operator actions were taken to stabilize the plant:

1. Placed the Mode Switch to Shutdown. [T=21 seconds]

2. Started ABE Reactor Feedwater Pump to re-establish normal level control. [T=25 seconds]

Within 25 seconds following the operator actions, all reactor water low level alarms were clear.

At 2248, Operations documented that HPCI, RCIC, SBGT, and both EDGs had been secured and returned to standby status. Operations then commenced cool down of the reactor.

ANALYSIS:

The events detailed In this report did not have adverse safety Implications. The 4 kV Bus Fast/Residual Transfer Scheme operated as designed to secure and transfer electrical loads as necessary to prevent damage to equipment.

The Reactor Protection System operated as designed and scrammed the reactor after receiving the Generator Load Reject Scram signal. All other safety systems responded as expected.

An off-site laboratory performed an examination of the porcelain insulator revealing that the failure was caused by a manufacturing defect located below the top of the cemented joint obscuring visual inspection. The lab determined that the defect was not detectable by visual inspection or predictive maintenance. The failure was found to be structural and evidence of a dielectric breakdown was not present; therefore predictive maintenance techniques, such as corona, acoustic and thermography would not have detected the failure.

CAUSE:

A root cause investgaton team determined that the MOD failure was caused by the failure of a porcelain electrical insulator as a result of a manufacturing defect A laboratory examination of the insulator was performed by an off-site lab. The examination revealed a void area in the cement that attached the failed section of the Insulator to the metal flanges and a geometric off-set in the placement of the insulator in the flanges. Close examination of the void NRC FORM 366A (1401)

I NRC FORM 366A U.S. NUCLEAR REGULATORY COMMISSION (142001)

LICENSEE EVENT REPORT (LER)

1. FACILITY NAME 2. DOCKET 6. LER NUMBER 3. PAGE

YEAR uENTNUMBE REVISION VERMONT YANKEE N E NUCLEAR POWER STATION Pm 05000 271 4 OF 4 2005 - 001 - 00

17. NARRATIVE ({fnmo space Is requhed, use additional copies ofNRC Ferm 3654) surfaces showed that this void was pre-existing and occurred during the manufacturing of the assembly. These conditions caused a stress riser to occur on the northwest side when wind and other cyclic loads were applied to the insulator. The repeated cyclical loading and unloading produced a stress crack in the porcelain, weakening the insulator and ultimately leading to failure, prior to its design lifetime of 40 years. The Insulator was original plant equipment.

CORRECTIVE ACTIONS:

1. Failed components in the 345 kV Switchyard were tagged out, grounded and replaced.

2. Visual, thermography and corona inspections of the 345 kV and 115 kV Switchyards was performed. No additional anomalies were Identified. The inspections included components such as bus work, disconnect switches, insulators, etc.

3. Testing was performed to evaluate any potential impact on the Main Transformer and found acceptable.

4. The 345 kV high line section between the tower and Switchyard was inspected and found acceptable (that included insulators, disconnects, bus work, etc.).

5. Other T-1 MOD, 1T-22 and IT-11 insulators were Inspected for damage, and none was found.

6. Preliminary lab analysis of failed components was performed.

7. The five remaining Lapp Model J801 04-70 insulators on the line and load ends of the T-1 disconnect switch are scheduled for further inspection and replacement during the Fall 2005 scheduled outage (RF-25). Laboratory analysis will be performed on the insulators removed.

8. Insulators In the Switchyard that pose a risk to generation or potential for a loss of off-site power will be evaluated for replacement.

9. The preventative maintenance frequency for the 345 kV and 115 kV Disconnect Switches and Vertical Bus Insulators will be revised. VY will also ensure that the visual inspection attributes include the flange to porcelain cemented joints and entails inspecting for voids, cracks and off-center assemblies.

ASSESSMENT OF SAFETY CONSEQUENCES:

The reactor was safely shutdown without complications. No failure of safety related equipment occurred during or as a result of this event The T-1 MOD disconnect is a non-safety related component and is not relied upon for the safe shutdown of the plant; hence, there was no Impact on nuclear safety. Mitigating safety systems and non-safety systems responded as designed. A reactor trip with a Primary Containment Isolation System (PCIS) Group 1 Isolation, concurrent with a loss of feed water is an analyzed event. The T-1 MOD is physically located in the 345 kV Switchyard, outside of the Radiological Controlled Area (RCA). There was no increased radiological risk to plant personnel or the general public.

ADDITIONAL INFORMATION A similar event occurred on 03/13191 at VY that was reported to the NRC as LER 91 -005-00 on 04/12/91, "Reactor Scram due to Mechanical Failure of 345 kV Switchyard Bus caused by Broken High Voltage Insulator Stack. The root cause of the bus failure was attributed to a loose bus connection at the lower Insulator stack between the bus and the tower. Off-site lab analysis of the fractured Insulator completed during the two months succeeding the event were Inconclusive. The remaining Intact pieces were subjected to specific gravity and dye penetration testing in' addition to visual examination and mechanical testing for strength versus rating. Other than some evidence of sand-glaze separation on the porcelain surface within the cap, It was determined that the insulator had been properly fired and that no porosity was present. No defects were discovered and the insulator was demonstrated as capable of performing within Its designed rating.

NRC FORW386A (-2001)

January 4, 2006 The Honorable Nils J. Diaz Chairman U. S. Nuclear Regulatory Commission Washington, DC 20555-0001

SUBJECT:

VERMONT YANKEE EXTENDED POWER UPRATE

Dear Chairman Diaz:

During the 528th meeting of the Advisory Committee on Reactor Safeguards, December 7-9, 2005, we discussed the Vermont Yankee Extended Power Uprate (EPU) Application. As part of this review, our Subcommittee on Power Uprates held a meeting on November 15 -16, 2005 in Brattleboro, Vermont to receive input from the public, the applicant, and the staff. A second Subcommittee meeting was held in Rockville, Maryland on November 29 - 30, 2005. During our review, we had the benefit of discussions with the staff, the public, and Entergy Nuclear Vermont Yankee, LLC and Entergy Nuclear Operations, Inc. (Entergy), the licensee. We also had the benefit of the documents referenced.

CONCLUSIONS AND RECOMMENDATIONS

1. The Entergy application for the extended power uprate at the Vermont Yankee Nuclear Power Station (VY) should be approved.

2. The change in the licensing basis associated with the requested containment overpressure credit should be approved.

3. Load rejection and main steam isolation valve closure transient tests are not warranted.

The planned transient testing program adequately addresses the performance of the modified systems.

4. The times available to perform critical operator actions remain adequate under EPU conditions.

5. The margin added to the safety limit minimum critical power ratio (SLMCPR) is an appropriate interim measure until General Electric (GE) obtains additional data to complete the validation of nuclear analysis methods.

6. The monitoring that will be performed during the ascension to uprate power provides adequate assurance that, if resonant vibrational modes are induced in the steam dryer, they will be identified prior to component failure.

7. An enhanced, focused engineering inspection was performed. An additional expanded inspection is not warranted.

8. The review standard for extended power uprates (RS-001) provides a structured process

for the review of applications for extended power uprates. Its continued use and improvement are encouraged.

BACKGROUND Vermont Yankee Nuclear Power Station (VY) is a boiling-water reactor of the BWR/4 design with a Mark-1 containment. Entergy has applied for an extended power uprate of approximately 20% from the current maximum authorized power level of 1593 MWt to 1912 MWt. The application is similar to other uprates that have been approved within the last five years at Duane Arnold, Dresden Units 2 and 3, Quad Cities Units I and 2, and Brunswick Units 1 and 2.

In Constant Pressure Power Uprates (CPPU), except for steam and feedwater flow rates, plant operating conditions are essentially unchanged from the pre-EPU values. The extra power is generated largely by flattening the power distribution across the core, and the fuel design safety limits are met at the proposed extended power uprate conditions.

DISCUSSION When a large-break design-basis loss-of-coolant accident (LOCA) and anticipated transient without scram (ATWS) were analyzed at VY at the proposed EPU level using current design basis assumptions and methodologies, the available net positive suction head (NPSH) was found to be insufficient to avoid cavitation of the low pressure coolant injection (LPCI) and core spray pumps. The need for increased NPSH occurs because at the higher power level the suppression pool heats up more in both of these scenarios than at the currently licensed power level. In the calculations performed to support VY's existing operating license, containment pressure was assumed to be atmospheric when computing the available NPSH.

In its application, Entergy requests changing its licensing basis methodology to grant credit for containment accident pressure in determining available NPSH for emergency core cooling pumps for these LOCA and ATWS scenarios. Using conservative methods and a containment leak rate consistent with its technical specifications, Entergy has determined a conservative lower bound for the time-dependent pressure in containment that would result from these scenarios under EPU conditions. The incremental pressure credits that are requested for these two scenarios are less than these computed pressures. For the LOCA scenario, the maximum containment pressure credit is 6 psi, and the total time for which some overpressure credit is required is 56 hours6.481481e-4 days <br />0.0156 hours <br />9.259259e-5 weeks <br />2.1308e-5 months <br />. For the ATWS scenario, the corresponding values are 2 psi and 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br />.

The ACRS has historically opposed a general granting of containment overpressure credit. in determining whether such credit should be granted, one aspect to be considered is whether practical alternatives exist, such as the replacement of pumps with those with less restrictive NPSH requirements. If no practical alternatives are available, important considerations include (1) the length of time for which containment pressure credit is required and (2) the margin between the magnitude of the pressure increment that Is being granted and the expected minimum containment pressure. Another consideration is the nature of the containment design and whether it provides a positive indication of integrity, prior to the event, as is the case in subatmospheric and inerted designs.

Because of the plant configuration, extent of modifications required, and worker dose that would be involved, we conclude that there are no practical design modifications that would preclude the need to consider the request for containment overpressure credit. VY has an inerted containment. There is, then, a low likelihood of significant pre-existing containment leakage.

For the ATWS scenario, the magnitude of pressure required to show adequate NPSH is small compared to the accident pressure, and the time during which the overpressure credit is required is short For the LOCA scenario, although the duration for which the containment overpressure credit is required is comparatively long, the overpressure credit requested is smaller than what is conservatively predicted to be available.

Under the EPU conditions at VY, the general design requirements regarding single failures in design-basis accidents do not prevent granting of the overpressure credit for the LOCA scenario of concern. The worst single failure that was identified by the licensee involves loss of one train of heat removal from the suppression pool. Conservative, bounding calculations show that the containment overpressures during this scenario are higher than needed to provide sufficient NPSH. Allowing no credit for containment overpressure is equivalent to assuming an additional failure that causes loss of the overpressure. Thus, for all scenarios involving only a single failure, sufficient NPSH is available to ensure that pump cavitation damage is avoided. To maintain defense-in-depth, however, it has been staff practice to require the assumption that containment overpressure is not available in assessing the potential for pump damage.

In evaluating Entergy's request for containment overpressure credit, the staff included in its decisionmaking process more realistic analyses to determine whether containment overpressure would be needed at the proposed EPU power level to prevent pump cavitation in actual accident scenarios. The staff also considered the results of probabilistic analyses to assess the risk significance of scenarios in which containment overpressure is lost.

Design-basis accidents are typically analyzed using conservative methodologies and input assumptions to ensure safety in spite of uncertainties in input and methodology. An alternative approach is to use realistic analyses with a more complete and explicit consideration of uncertainties. Such a methodology has not yet been fully developed for analysis of the need for containment overpressure credit. The staff and the licensee have instead performed sensitivity analyses to determine the effect of relaxing some of the conservative assumptions. More realistic values were used for a number of input parameters to determine the associated reduction in the predicted temperature of the suppression pool, which is the major parameter in determining whether overpressure credit is necessary. The staff concluded that, on a more realistic but still conservative basis, the temperature of the suppression pool would not become high enough in the LOCA scenario to require a credit for containment overpressure.

Independent risk analyses were performed by the staff and the licensee to determine the potential risk significance of granting credit for containment overpressure. These analyses included the conservative assumption that the emergency core cooling system (ECCS) success criteria would not be met whenever containment overpressure is lost and design-basis analyses would suggest that overpressure credit was needed, although the licensee's sensitivity studies indicated that peak suppression pool temperature would probably not be high enough that containment overpressure credit would be required. The results of the analyses Indicate that the overall risk associated with the EPU is small and that the change in risk resulting from allowing the requested containment overpressure credit is also small.

Although we concur with the staffs conclusion to grant credit for containment overpressure, we would have preferred to see the assessment performed and presented in a more coherent manner, with a more complete and rigorous consideration of uncertainties. The staff is developing additional guidance to be used in the consideration of overpressure credit in the future. We look forward to reviewing their proposed approach.

The staff performed an expanded engineering inspection of VY. Such an inspection was requested by the Public Service Board of the State of Vermont. The inspection focused on safety-significant components and operator actions. It was performed under the direction of the NRC Office of Nuclear Reactor Regulation (NRR) and included regional inspectors and contractors who had no recent oversight responsibilities for VY. There were eight findings, but they were of low safety significance. A number of members of the public asked for a more extensive inspection, similar to that performed at the Maine Yankee plant. Based on the results of the inspection that was performed and the performance of VY as determined by the Reactor Oversight Process, such an extensive inspection is not warranted.

Hardware and operational changes are required for the power uprate. In order to achieve the proposed EPU power level, all three feedwater pumps must operate, rather than the two pumps currently required. If one of these pumps fails, the plant will undergo an automatic runback of power so that the two remaining pumps will be sufficient. A new signal has been added to trip a feedwater pump in the event of a condensate pump trip. A concern has been raised about the potential for loss of all feed pumps due to low suction pressure as a result of a condensate pump trip. Consequently, Entergy has agreed to perform a trip of a condensate pump to demonstrate that it will not cause loss of all feedwater. This will also test the integrated response of control systems associated with recirculation flow runback, feedwater level control, and reactor pressure control.

Entergy does not plan to undertake large transient tests, such as a main steam isolation valve closure that would result in a reactor trip. Such tests would not directly address confirmation of the performance of systems changed to support EPU. The ACRS concurs with the staffs assessment that the large transient tests are not warranted.

Only minor changes have been made in the emergency operating procedures to accommodate EPU modifications. One of the impacts of the power uprate Is a reduction in available response time for operator actions. The operators respond in essentially the same manner as for the current operating conditions but, in some cases, have less time to take an action. A systematic assessment has been made by Entergy of the maximum time available for critical operator actions. The VY simulator has been modified to represent the EPU condition and operators have been trained for EPU conditions. The simulator exercises have demonstrated the ability of the operators to respond correctly within the required time period.

The reactor operating domain is defined so that: (1) the core will not be operated in an unstable regime, (2) the minimum critical power ratio is low enough to prevent dryout of the fuel pins, and (3) the linear heat generation rate is low enough to assure the integrity of fuel cladding during steady and transient conditions. The boundaries of this operating domain are based on neutronic and thermal-hydraulic calculations performed by GE. The computer codes that are used in these analyses have been reviewed and approved by the staff.

4 In reviewing the application of these methods to EPU uprates, the staff determined that the operation of the fuel extends into a region where the expected void fraction within the fuel bundle is greater than that for which the codes have been validated. To demonstrate the ability of the code to predict isotopic concentrations in this regime, GE has committed to performing gamma scans on the fuel design that is being used in the power uprate. In the interim, Entergy has undertaken an "Alternative Approach" in which it has performed an uncertainty analysis for the model predictions and, as a result, has added an additional margin of 0.02 to the SLMCPR.

We concur with the staffs assessment that the addition of such a margin is an appropriate interim measure. The review of the adequacy of the GE computer codes is a generic activity that is being undertaken by the staff. We will have an opportunity to review the staff's assessment of these codes in more detail when we consider the MELLLA+ topical report in 2006.

Higher steam and feedwater flow rates at EPU conditions may lead to an increase in flow accelerated corrosion for some components. The evidence indicates that current flow accelerated corrosion rates at VY are low. Many of the components that would most likely be affected use chromium- molybdenum alloy materials that are resistant to flow accelerated corrosion, and Entergy has committed to an inspection program that will provide reasonable assurance that degradation will be detected prior to reaching an unsafe condition.

Increased flow rates also have the potential to induce vibrations that could lead to failure of components. Because of the previous experience at Quad Cities, the steam dryer has been the primary focus of attention. A number of cracks have been found in inspections of the VY steam dryer. Two cracks found near the lifting lugs were attributed to the initial fabrication of the steam dryer. These cracks have been ground out and repaired. The other cracks that have been found appear to be superficial and were deemed to be the result of intergranular stress corrosion, not flow-induced vibration. Stiffeners have been added to the dryer to provide additional strength and also to raise its natural frequencies.

Entergy has performed hydrodynamic, acoustic and structural resonance analyses to assess the potential for stimulation of a resonant mode of the dryer. These analyses indicate that there is margin between the magnitude of the potential stresses imposed on the steam dryer and the level at which fatigue failure would occur. However, the state of validation of these methods is poor.

To provide further assurance of the integrity of the dryer, additional strain gages have been added to the steam lines at VY. Experiments performed in a scale-model system by GE indicate that acoustic signals initiated in the region of the steam dryer can be correlated with signals measured by strain gages on the steam lines. A similar correlation has been observed at Quad Cities Unit 2 where both the steam dryer and steam lines have been instrumented.

Entergy has developed a program for power ascension involving holds at a number of power levels. The steam line strain gages will be monitored at the various power levels. Any anomalies will lead to a reduction in power until the issue is resolved. Entergy has also committed to inspections of the steam dryers in the next three outages following the uprate.

The additional monitoring, the power ascension program, and the inspections provide confidence that, if excessive excitation does occur in the steam dryer, it will be identified before substantial damage is incurred.

Power uprates are not submitted as risk-informed license applications. Nevertheless, licensees have submitted assessments of risk associated with the extended power uprates and the staff includes consideration of this risk information in its decisionmaking process. The purpose of the staff's risk review as stated in RS-001 is to "determine if there are any issues that would potentially rebut the presumption of adequate protection provided by the licensee meeting the deterministic requirements and regulations." The staff has reviewed Entergy's assessment of risk at the proposed EPU conditions and compared the VY probabilistic risk assessment (PRA) results with the staffs SPAR model results for this plant. The values of core damage frequency (CDF) and large early release frequency (LERF) are low and provide substantial margin to values that raise questions of adequate levels of safety. As we noted previously, the staff also used risk insights in their independent determination of the acceptability of the potential for pump cavitation during long-term core cooling in LOCA and ATWS scenarios.

This was the second application by the staff of RS-001 in the review of an EPU proposed upgrade. RS-001 provides a structured approach to the review.

Sincerely,

/RAI Graham B. Wallis Chairman Additional Comments by ACRS Members Richard S. Denning, Thomas S. Kress, Victor H.

Ransom, and Graham B. Wallis Considering all the evidence, including precedents set at other similar plants, we agreed with our colleagues to approve the proposed 20% EPU for VY.

It seems unlikely that there will be a problem with adequate NPSH of the core spray and residual heat removal (RHR) pumps at Vermont Yankee, with a 20% power uprate. However, we were asked to make a professional judgment that would have been more straightforward if the information supplied to us had been more complete. We suspect that more information already exists that could be reorganized, supplemented as needed, and presented logically to provide a more convincing case in the following way, which would set a better precedent for future applications:

1. Derive sufficient detail of the probability distribution for containment pressure following large LOCA and ATW S sequences, based on realistic analysis of the physical phenomena and the attendant uncertainties:

i

2. Derive sufficient detail of the probability distribution for suppression pool temperature following these events, based on realistic analysis of the physical phenomena and the attendant uncertainties.

3. Combine the results of steps I and 2 with realistic and uncertainty analyses of other phenomena influencing NPSH to derive the probability of successful operation of RHR and core spray pumps. This may provide adequate evidence for a conclusion to be reached, if it can be shown that only a small containment overpressure is likely to be needed for a short time, if at all, and it has a high probability of being available. If further evidence is required, these results can be incorporated into the PRA to derive the realistic contribution, if any, to total plant risk due to insufficient NPSH.

Both Entergy and the staff have shown that relaxing a few of the many conservatisms and using realistic values (for example, of the initial temperature of the suppression pool) removes the need for additional NPSH. Such arguments are insufficiently conclusive. The reason is that when one gives up an element of conservatism, without replacing it by a less stringent assumption that is still demonstrably conservative, there is a finite probability that values of the derived parameter will not bound all possibilities.

The proper way to relax the many conservative assumptions is to make (some of) them realistic with the inclusion of uncertainty. This will lead to a probability distribution (or more precisely some aspects of it, such as the 95/95 confidence level) for an output such as pool temperature.

From the analyses that we have seen in presentations by Entergy and by the staff, it appears likely that the realistic contribution to risk from inadequate RHR and core spray pump NPSH will prove to be very small, even essentially zero, for the case of the proposed power uprate at VY, but this could be better demonstrated in a manner which is both physically and logically consistent. The probabilities associated with the governing physical phenomena may be regarded as more secure than some other inputs to the usual PRA assessment. Conclusions based on them may help to convince those who doubt if conventional risk-based arguments alone should allow the relaxation of defense-in-depth that is achieved by the independence of cladding and containment barriers to radioactivity release. In particular, if it can be shown that the probability of needing containment overpressure is sufficiently small, the independence of these barriers would effectively be preserved.

REFERENCES:

1. Memorandum from Ledyard B. Marsh to John Larkins, Vermont Yankee Nuclear Power Station - Draft Safety Evaluation for the Proposed Extended Power Uprate (TAC No.

MC0761)", October 21, 2005

2. Letter from Wayne Lanning to Jay Thayer, Vermont Yankee Nuclear Power Station, NRC Inspection Report 05000271/2004008", December 2, 2004

0*

Power uprates are not submitted as risk-informed license applications. Nevertheless, licensees have submitted assessments of risk associated with the extended power uprates and the staff includes consideration of this risk information in its decisionmaking process. The purpose of the staff's risk review as stated in RS-001 is to "determine if there are any issues that would potentially rebut the presumption of adequate protection provided by the licensee meeting the deterministic requirements and regulations." The staff has reviewed Entergy's assessment of risk at the proposed EPU conditions and compared the VY probabilistic risk assessment (PRA) results with the staff's SPAR model results for this plant. The values of core damage frequency (CDF) and large early release frequency (LERF) are low and provide substantial margin to values that raise questions of adequate levels of safety. As we noted previously, the staff also used risk insights in their independent determination of the acceptability of the potential for pump cavitation during long-term core cooling in LOCA and ATWS scenarios.

This was the second application by the staff of RS-001 in the review of an EPU proposed upgrade. RS-001 provides a structured approach to the review.

Sincerely, Graham B. Wallis Chairman Additional Comments by ACRS Members Richard S. Denning, Thomas S. Kress, Victor H.

Ransom, and Graham B. Wallis Considering all the evidence, including precedents set at other similar plants, we agreed with our colleagues to approve the proposed 20% EPU for VY.

It seems unlikely that there will be a problem with adequate NPSH of the core spray and residual heat removal (RHR) pumps at Vermont Yankee, with a 20% power uprate. However, we were asked to make a professional judgment that would have been more straightforward if the information supplied to us had been more complete. We suspect that more information already exists that could be reorganized, supplemented as needed, and presented logically to provide a more convincing case in the following way, which would set a better precedent for future applications:

1. Derive sufficient detail of the probability distribution for containment pressure following large LOCA and ATWS sequences, based on realistic analysis of the physical phenomena and the attendant uncertainties.

• See previous concurrence.

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