ML053490276

Entergy'S Motion for Summary Disposition of New England Coalition Contention 3

ML053490276
Person / Time
Site:	Vermont Yankee File:NorthStar Vermont Yankee icon.png
Issue date:	12/02/2005
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-OLA, RAS 10811
Download: ML053490276 (204)

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December 2, 2005 JUNITED STATES OF AMERICA DOCKETED NUCLEAR REGULATORY COMMISSION USNRC Before the Atomic Safety and Licensing Board December 5, 2005 (8:15am)

) OFFICE OF SECRETARY In the Matter of RULEMAKINGS AND ADJUDICATIONS STAFF 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 MOTION FOR

SUMMARY

DISPOSITION OF NEW ENGLAND COALITION CONTENTION 3 Applicants Entergy Nuclear Vermont Yankee, LLC and Entergy Nuclear Operations, Inc.

(collectively "Entergy") file this motion, pursuant to 10 C.F.R. §2.1205(a)' and the Atomic Safety and Licensing Board's ("Board") Memorandum and Order, LBP-04-28 (Nov. 22, 2004),2 to seek dismissal by summary disposition of the New England Coalition's ("NEC") Contention 3 in this proceeding ("NEC Contention 3"). Entergy seeks summary disposition of the contention on the grounds that no genuine issue as to any material fact exists and Entergy is entitled to a de-cision as a matter of law. This motion is supported by a Statement of Material Facts as to which Entergy asserts there is no genuine dispute and the Declaration of Craig J. Nichols ("Nichols Declaration").

10 C.F.R. §2.1205(a) states: "(a) Unless the presiding officer or the Commission directs otherwise, motions for summary disposition may be submitted to the presiding officer by any party no later than forty-five (45) days be-fore the commencement of hearing. The motions must be in writing and must include a written explanation of the basis of the motion, and affidavits to support statements of fact. Motions for summary disposition must be served on the parties and the Secretary at the same time that they are submitted to the presiding officer."

2 Memorandum and Order, LBP-04-28, 60 NRC 548 (2004).

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I. STATEMENT OF FACTS One of the contentions originally proposed by NEC was Contention 3, which asserts that Entergy's application for an extended power uprate ("EPU") for the Vermont Yankee Nuclear Power Station ("VY") ("Application") should not be approved unless performance of Large Transient Testing ("LTT") is a made a condition of the uprate.3 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" defines the Main Steam Isolation Valve ("MSIV") Closure and the Generator Load Rejec-tion tests as the LTT applicable to V. 4 NRC's Review Standard RS-001, "Review Standard for Extended Power Uprates," Revision 0 (December 2003) references the Standard Review Plan (SRP) 14.2.1, "Generic Guidelines for Extended Power Uprate Testing Programs," for the testing related to extended power uprates. SRP 14.2.1 specifies that LIT is to be performed in a similar manner to the testing that was performed during initial startup testing of the plant. The SRP also provides guidance on how to justify a request for deletion of the LTT requirement.

In accordance with the SRP guidance, Entergy included in its Application a separate at-tachment devoted to discussing the bases for an exception to performing LIT at VY in connec-tion with the proposed EPU. 6 In that attachment, Entergy addressed factors that justify not per-forming the LIT, 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.

i i' 1 I11 1 3 As admitted by the Board, NEC Contention 3 reads: "The license amendment should ot be approved unless Large Transient Testing is a condition of the Extended Power Uprate." 60 NRC at 58t, Aendix 1.

4 Nichols Declaration, 1 8.

5 Id., ¶l 11. A copy of SRP 14.2.1 is attached as Exhibit 2 to the Nichols Declaration.,

6 Application, Att. 7, "Justification for Exception to Large Transient Testing" (I-Justificatiop'). Entergy subse-quently supplemented its justification discussion. See, Application, Supplement 3, Att. 2 (Oct. 28, 2003). Cop-ies of these materials are included as Exhibits 3 and 4 to the Nichols Declaration.

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The Board's rationale for admitting NEC Contention 3 was twofold: (1) the LTT excep-.

tion request was part of the EPU Application and was consequently within the scope of this pro-ceeding, and (2) NEC had submitted in support of its proposed contention a declaration by its consultant Arnold Gundersen 7 which the Board determined set forth an" expert opinion, sup-ported by specific references to the EPU application and citations to relevant Staff documents,

[which] provides a concise statement of the alleged facts or expert opinions which support NEC's position.'8 As will be seen, the statements by Mr. Gundersen are refuted by conclusive technical evidence and do not warrant the holding of a hearing on this contention.

II. ENTERGY IS ENTITLED TO

SUMMARY

DISPOSITION A. Legal Standards for Summary Disposition Commission regulations provide for summary disposition. Motions for summary disposi-tion in a 10 C.F.R. Part 2, Subpart L, proceeding may be submitted up to 45 days before the commencement of a hearing, unless the presiding officer orders otherwise. 10 C.F.R.

§2.1205(a). 9 In ruling on motions for summary disposition, the Board is to apply the standards for summary disposition set forth in subpart G of 10 C.F.R. Part 2. Id. §2.1205(c). The standards for summary disposition under Subpart G are set forth in 10 C.F.R. §2.710, which states that the "presiding officer shall render the decision sought if... there is no genuine issue as to any mate-rial fact and ... the moving party is entitled to a decision as a matter of law." Id., §2.71 0(d)(2).

The Commission's requirements for summary disposition are satisfied with respect to NEC Con-7 Declaration of Arnold Gundersen in Support of Petitioners' Contention (August 30, 2004) ("Gundersen Declara-tion"), Attachment D to New England Coalition's Request for Hearing, Demonstration of Standing, Discussion of Scope of Proceeding and Contentions" (Aug. 30, 2004).

' LBP-04-28, 60 NRC at 572.

9 In its Initial Scheduling Order, the Board set 30 days after the issuance by the Staff of the Draft Safety Evalua-tion Report for the EPU ("Draft SER") as the deadline for filing motions for summary disposition herein. Initial Scheduling Order (Feb. 1, 2005) at 3. The draft was posted on ADAMS on November 2, 2005 (Accession Num-ber ML053010167).

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tention 3 because there is no genuine issue of disputed fact that would require a hearing and En-tergy is entitled to a favorable decision as a matter of law.

Under the NRC Rules of Practice, a moving party is entitled to summary disposition of a contention as a matter of law if the filings in the proceeding, together with the statements of the parties and the affidavits, demonstrate that there is no genuine issue as to any material fact. The Rules "long have allowed summary disposition in cases where there is no genuine issue as to any material fact and where the moving party is entitled to a decision as a matter of law." Carolina Power & Light Co. (Shearon Harris Nuclear Power Plant), CLI-01-1 1, 53 NRC 370, 384 (2001)

(internal quotations omitted); Advanced Medical Sys., Inc. (One Factory Row, Geneva, Ohio),

CLI-93-22, 38 NRC 98, 102-03 (1993). Commission case law is clear that for there to be a genuine issue, "the factual record, considered in its entirety, must be enough in doubt so that there is a reason to hold a hearing to resolve the issue." Cleveland ElectricIlluminating Co.

(Perry Nuclear Power Plant, Units 1 and 2), LBP-83-46, 18 NRC 218,223 (1983). Summary disposition "is a useful tool for resolving contentions that ... are shown by undisputed facts to have nothing to commend them." Private Fuel Storage, L.L.C. (Independent Fuel Storage Instal-lation), LBP-01-39, 54 NRC 497, 509 (2001).

Those principles apply here. Lacking any genuine factual dispute, NEC Contention 3 clearly has "nothing to commend" it for further litigation in this proceeding and should be dis-missed.

B. There Is No Factual Dispute Requiring Litigation In his Declaration, Mr. Gundersen raised without much elaboration three reasons why the justification provided by Entergy for deleting the LT7 requirement was insufficient:

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• Operational experience does not provide adequate support for the exception being sought.°10

• VY's successful experience with full power transients at 100% level does not demonstrate the performance at 120% level.11

• Component testing does not obviate the need for full power testing of the tran-sients.' 2 None of these claims has a defensible factual basis. Thus, there remains no genuine issue as to any material fact relevant to NEC Contention 3.

1. The analytical tools used by Entergy will accurately predict plant perform-ance in large transient events under EPU conditions The transient analyses for VY are performed using the NRC-approved code ODYN, which models the behavior of the safety- and non-safety-related systems of the plant during op-erational events. 13 These analytical tools have been accepted by the NRC Staff.14 The transient analyses for VY include the two LiT events. 15 Neither NEC nor its consultant Mr. Gundersen has challenged the validity of the W analytical tools or their results.

The transient analyses for VY model both the performance of the secondary side of the plant and any potential interactions between primary and secondary systems in a transient.' 6 The analyses assume operational configurations and component/system failures that bound (i.e., rep-

'° Gunderson Declaration at 4.

" Id.

12 Id. at 5.

3 Nichols Declaration, 1 16.

14 Id.

'5 Id.

6 Id., 17.

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resent more severe conditions than) the transients that would occur during actual EPU.plant op-erations or during LTTs."'

While some of the plant operating parameters (e.g., core power distribution) will be modified to accommodate higher power operation after EPU, none of the plant modifications that have been or will be made for the EPU will introduce new thermal-hydraulic phenomena, nor will there be any new system interactions during or as the result of analyzed transients intro-duced.18 Nor will there be any impairment of the safety function of components such as piping and pipe supports."9 Accordingly, there is every reason to anticipate that the transient analyses will accurately predict the plant response to large transient events without need to perform actual LrT. 2 0

2. Operational experience in the United States and abroad justifies the grant-ing of the exception There is a wealth of worldwide operational experience demonstrating that the perform-ance of boiling water reactors ("BWRs") such as VY during transients matches the predictions of analytical tools used by Entergy and other utilities to analyze those transients. Examples in-clude:

1. Southern Nuclear Operating Company's (SNOC) application for EPU of Hatch Units 1 and 2 was granted without requirements to perform large transient testing. VY and Hatch are both BWR/4 plants with Mark I containments.2 '

17 Id.

18 Id., 1 18.

19 Id., 19.

20 Id., 20.

21 Id., 21.

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2. Hatch Unit 2 experienced a post-EPU unplanned event that resulted in a generator load rejection from approximately 111% Original Licensed Thermal Power ("OLTP")

(98% of uprated power) in May 1999. All systems functioned as expected and there were no anomalies were seen in the plant's response to this event.

3. Hatch Unit 2 also experienced post-EPU reactor trip on high reactor pressure as a result of MSrV closure (from 113% OLTP (100% of uprated power)) in 2001. Systems func-tioned as expected and designed, given the conditions experienced during the event.23

4. Hatch Unit 1 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 behaviors for either plant were observed. 2 4

5. Progress Energy's Brunswick Units I and 2 were licensed to 120% of OLTP and was granted the license amendment without requirements to perform LTT. VY and Brunswick are BWR/4 plants with Mark I containments. Brunswick Unit 2 experienced a post-EPU unplanned event that resulted in a generator/turbine trip due to loss of generator excita-tion from 1 5.2% OLTP (96% of uprated thermal power) in the fall of 2003. No anoma-lies were experienced in the plant's response to this event, and no unanticipated plant re-sponse was observed. 2 5

6. 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. VY, Quad Cities and Dresden units are similar plants with Mark I containments. Dresden 3 22 SNOC's LER 1999-005-00, attached as Exhibit 6 to the Nichols Declaration.

23 SNOC's LER 2001-003-00, attached as Exhibit 7 to the Nichols Declaration.

24 SNOC's LERs 2000-004-00 and 2001-002-00, attached as Exhibits 8 and 9 to the Nichols Declaration.

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has experienced several turbine 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). The plant response was as expected and no new plant behaviors were observed.2 6

7. 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).

Plant response was as anticipated. 27

8. The Kernkraftwerk (KKL) plant in Leibstadt, Switzerland had an EPU from 104.2% to 1 6.7% OLTP which was performed during the period from 1995 to 2000. Power was raised in steps, and LTI was performed at 110.5% OLTP in 1998, 113.5% OLTP in 1999 and 1 6.7% OLTP 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 demonstrated the performance of equipment that was modified in preparation for the higher power levels. 28 In its draft SER, the NRC reviewed this operational experience and concluded:

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 1 and 2, was granted an EPU by the NRC without the requirement to perform large transient testing and that the VYNPS and Hatch are both Footnote continued from previous page 25 Progress Energy's LER 2003-004-00, attached as Exhibit 10 to the Nichols Declaration.

26 See Exhibits 11 and 12 to the Nichols Declaration.

27 See Exhibit 13 to the Nichols Declaration.

28 Nichols Declaration, In 25-26.

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BWR/4 designs with Mark I containments. Hatch Unit 2 experi-enced an unplanned event that resulted in a generator load reject from 98% of uprated power in the summer of 1999. As noted in Southern 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 re-ported in LERs 2000-004 and 2001-002. Again, the behavior of the primary safety systems was as expected indicating that the analyti-cal 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 tran-sients 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 consis-tently reflected the behavior of the plant.

Draft SER at 265-66. Thus, as the NRC Staff determined in the SER, "the behavior of the pri-mary safety systems was as expected indicating that the analytical models being used are capable of modeling plant behavior at EPU conditions." The agreement between analytical predictions and the transient performance of these planned and unplanned transients in plants similar in de-sign to VY is fully applicable and demonstrates that the analytical methods used by Entergy to evaluate the plant response to LTT can accurately predict the response without need to conduct actual testing.2 9 29 Mr. Gundersen cited a request for additional information issued by the NRC Staff in the Duane Arnold EPU ap-plication, which asked the applicant to address how the operating experience at the Hatch Unit I and 2 demon-strates that transient analyses for the Duane Arnold plant would provide equivalent protection compared to the LTT. Gunderson Declaration at 4. However, the Staff ultimately agreed that reliance on the Hatch experience was relevant and probative of the ability of the Duane Arnold plant to predict the response of the plant's systems to large transients and concluded that "[nlo new plant behaviors have been observed that would indicate that the analytical models being used are not capable of modeling plant behavior at the EPU conditions." Letter dated March 17, 2005 from Deirdre W. Spaulding (NRC) to Mark A. Peifer (Duane Arnold Energy Center), Attach-ment 2 at 11, copy included as Exhibit 14 to the Nichols Declaration.

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3. The VY Operational Experience Justifies the Requested Exception Mr. Gundersen dismisses VY's operational experience as the basis for the proposed ex-ception in two sentences: "Entergy argues that Vermont Yankee has experienced full power load rejections at 100% power and that no significant anomalies were seen. How this bears on per-formance at 120% power is somewhat of a mystery." 3 0 It is, however, hardly a mystery. The operational experience of VY at its current licensed power level is very relevant to how the plant is expected to perform in transients from EPU operation.

The VY transient experience includes:

• On 3/13/91, the with reactor at full power, a reactor scram occurred as a result of Turbine/Generator rip on Generator Load Rejection due to a 345 kV Switchyard Tie Line Differential Fault. This event was reported to the NRC in LER 1991-005-00, dated 4/12/9 .L"

• On 4/23/91, with the reactor at 100% power, a reactor scram occurred as a re-sult of a turbine/generator trip on generator load rejection due to the receipt of a 345 kV breaker failure signal. The event included a loss of offsite power.

This was reported to the NRC in LER 1991-009-00, dated 05/23/91.32

• On 6/15/91, during normal operation with reactor power at 100% power, a re-actor scram occurred due to a Turbine Control Valve Fast Closure on Genera-tor Load Rejection resulting from a loss of the 345 kV North Switchyard bus.

This event was reported to the NRC in LER 1991-014-00, dated 7/l5/9 .L"

• On 6/18/2004, during normal operation with the reactor at 100% 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 30 Gunderson Declaration at 5.

31 Nichols Declaration, Exhibit 16.

32 Id., Exhibit 17.

3 Id., Exhibit 18.

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Rejection reactor scram. This event was reported to the NRC in LER 2004-003-00, dated 8/16/2004.34 On 7/25/2005, during normal operation with the reactor at full power, a gen-erator load rejection scram occurred due to an electrical transient in the 345 kV Switchyard. This event was reported to the NRC in LER 2005-001-00.35 Significantly, most of the modifications associated with the EPU, 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 fil-tered bypass were already installed at the time of these two transients. 36 In each instance, the modified or added equipment functioned normally during the transient. 3 7 VY performed as expected in response to all the transients. No significant anomalies were seen in the plant's response to the events. The performance of VY in the transients it ex-perienced at current power levels was well within the bounds of analyzed VY response. 3 8 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. Also, the VY EPU is performed without a change in operating reactor dome pressure from current plant operation. Therefore, there is no basis for the transient performance of the plant under EPU to be outside the NRC Staff accepted experience base for EPU. 3 9 In its draft SER, the NRC Staff has concluded that the VY operating experience supports the granting of the LIT exclusion:

I Jd., Exhibit 19.

3 Id., Exhibit 20.

36 Nichols Declaration, 1 29.

37 Id.

38 Id., 30.

39 Id., 31.

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Another factor used 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, 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.

Draft SER at 266.

4. Component testing at VY provides assurance that the plant's safety sns-tems will operate as intended during transient conditions In its Application, Entergy explained that the important nuclear characteristics required for transient analysis are confirmed by the steady state testing of systems and components. 40 Mr.

Gundersen dismissed, without elaboration, the applicability of component testing as a predictor of system performance during transients. There is no basis for such a dismissal. Surveillance testing performed during normal plant operations confirms the important performance character-istics required for appropriate transient response. 4 1 Technical Specification-required surveillance testing (e.g., component testing, trip logic system testing, simulated actuation testing) demon-strates that the systems, structures and components ("SSCs") will perform their functions, includ-ing integrated performance for transient mitigation as assumed in the transient analysis. 42 For example, 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 design during large transients; their periodic testing assures that their performance during large transients will be acceptable. Likewise, the reactor protection system instrumentation is tested quarterly, assuring that it will carry out its design function in the event of a large transient. 43 40 See Justification at 2.

41 Nichols Declaration, ¶ 33.

42 Id.

43 Id.,1 34.

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The characteristics and functions of SSCs do not need to be demonstrated further in a large transient test.44 In addition, limiting transient analyses (i.e., those that affect core operating and safety limits) are reperformed each cycle and are included as part of the reload licensing analysis. 45 In the Draft SER, the NRC credits the steady-state testing program conducted by Entergy:

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 tran-sient 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 Septem-ber 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.

Draft SER at 267. Except for requesting the performance of additional condensate and feedwater system transient testing (to which Entergy has agreed), the Staff accepted Entergy's steady-state testing program as a predictor of plant performance during transients. NEC has offered no ar-guments to the contrary.

C. Entergy is Entitled to a Favorable Decision as a Matter of Law.

There is no genuine issue on a material fact regarding NEC Contention 3 that could result in the denial of Entergy's application. Accordingly, Entergy is entitled to summary disposition of the contention as a matter of law.

44 Id., 35.

45 Id.

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III. CONCLUSION As demonstrated above, none of the objections to the LTT exclusion raised by NEC and its consultant in Contention 3 has any factual merit. Accordingly, there is no genuine dispute of material fact remaining.to litigate and Entergy is entitled to a decision as a matter of law on NEC Contention 3.

CERTIFICATION In accordance with 10 C.F.R. §2.323(b), counsel for Entergy has discussed this motion with counsel for the other parties in this proceeding in an attempt to resolve this issue.

Respectfully submitted, Jay E. lberg 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: December 2, 2005 14

I 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) )

)

STATEMENT OF MATERIAL FACTS REGARDING NEC CONTENTION 3 ON WHICH NO GENUINE DISPUTE EXISTS Applicants Entergy Nuclear Vermont Yankee, LLC and Entergy Nuclear Operations, Inc.

(collectively "Entergy") submit, in support of their motion for summary disposition of NEC Con-tention 3, that there is no genuine issue to be heard with respect to the following material facts.

I. On August 30,2004, the New England Coalition ("NEC") sought admission, inter alia, of its Contention 3 ("NEC Contention 3"). New England Coalition's Request For Hearing, Demonstration of Standing, Discussion of Scope of Proceeding and Contentions, dated August 30, 2004 at 11.

2. 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."

3. The VY EPU request was prepared 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"). Declaration of Craig J. Nichols ("Nichols Declara-tion"), 1 7.

.I

4. Implementation of the guidance in NEDC-33004P-A results in an increase in reactor power without an increase in plant operating pressure (i.e., a "constant pressure power uprate").. Nichols Declaration, ¶ 7.

5. NEDC-33004P-A defines two Large Transient Tests ("LTTs") applicable to EPU op-erations: the Main Steam Isolation Valve ("MSIV") Closure and the Generator Load Rejection tests. Nichols Declaration, ¶ 8.

6. These tests, when conducted during EPU operation, are similar to counterpart tests performed during initial plant startup testing. Nichols Declaration, ¶ 8.

7. NRC's Review Standard RS-001, "Review Standard for Extended Power Uprates,"

Revision 0 (December 2003) references to Standard Review Plan (SRP) 14.2.1, "Ge-neric Guidelines for Extended Power Uprate Testing Programs," for the testing re-lated to extended power uprates. Nichols Declaration, ¶ 11.

8. SRP 14.2.1 specifies that LTT is to be performed in a similar manner to the testing that was performed during initial startup testing of the plant. Nichols Declaration, ¶ 11.

9. The SRP also provides guidance on how to justify a request for elimination of the LTT requirement. Nichols Declaration, ¶ 11.

10. Entergy has followed the SRP guidance in taking exception to performing LTT dur-ing EPU operations at VY. Nichols Declaration, ¶ 12.

11. On November 2, 2005 the NRC Staff issued its draft Safety Evaluation Report ("Draft SER"), in which the Staff concluded that the requested exception from LTT at VY should be granted. Exhibit 5 to Nichols Declaration.

12. The transient analyses for VY were performed using the NRC-approved code ODYN, which models the behavior of the safety- and non-safety-related systems of the plant during operational events. Nichols Declaration, ¶ 16.

13. The transient analyses for VY had been accepted by the NRC Staff. Nichols Declara-tion, 1 16.

14. The transient analyses of record for VY include the two LTT events. Nichols Decla-ration, 1 16.

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15. The transient analyses for VY model both the performance of the secondary side of the plant and any potential interactions between primary and secondary systems in a transient. Nichols Declaration, 1 17.

16. The transient analyses for VY assume operational configurations and compo-nent/systeni failures that bound (i.e., represent more severe conditions than) the tran-sients that would occur during actual EPU plant operations or during LiTis. Nichols Declaration, 1 17.

a.

17. While some of the plant operating parameters (e.g., core power distribution) will be modified to accommodate higher power operation after EPU, none of the plant modi-fications that have been or will be made for the EPU will introduce new thermal-hydraulic phenomena, nor will there be any new system interactions during or as the result of analyzed transients introduced. Nichols Declaration, 1 18.

18. As part of the EPU analyses, Entergy evaluated the increase in main steam flow re-sulting from EPU operation and its effect on the loadings on piping and pipe supports during large transients. Entergy's analyses determined that the loadings on piping and pipe supports during large transients at EPU power levels are within acceptable bounds. Entergy's evaluation of the performance of piping and pipe supports was re-viewed and accepted by the NRC Staff. Draft SER § 2.2.1 at 29.

19. Since the analyses assume operational configurations and component/system failures that bound the transients that would occur during actual EPU operations and since no changes will be made to the plant that could be reasonably anticipated to introduce new thermal-hydraulic phenomena or give rise to any new system interactions during the transients, there is every reason to anticipate that the transient analyses will accu-rately predict the plant response to large transient events without need to perform ac-tual LTT. Nichols Declaration, ¶ 20.

20. Thirteen boiling water reactor ("BWR") plants similar to VY have implemented EPUs without increasing operating pressure:

• Hatch Units 1 and 2 (105% to 113% of Original Licensed Thermal Power ("OLTP"))

• Monticello (106% OLTP)

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

• Leibstadt (i.e., KKL) (105% to 117% OLTP)

• Duane Arnold (105% to 120% OLTP)

• Brunswick Units 1 and 2 (105% to 120% OLTP) 3

• Quad Cities Units 1 and 2(100% to 117% OLTP)

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

• Clinton (100% to 120% OLTP)

Nichols Declaration, ¶ 14.

21. Of the thirteen BWR plants analogous to VY that have implemented EPUs without increased reactor operating pressure, four (Hatch 1 and 2, Brunswick 2 and Dresden

3) have experienced one or more unplanned large transients from uprated power lev-els'. Nichols Declaration, ¶ 21.

22. In every instance in which unplanned large transient power levels have been experi-enced at those four plants, the plant's response matched the analytical predictions and exhibited no new phenomena. Nichols Declaration, ¶ 22.

23. The analytical tools used to predict the performance of those plants during transients are the same as those used at VY. Nichols Declaration, 1 22.

24. The KKL plant in Leibstadt, Switzerland performed LTT as part of its EPU imple-mentation. Nichols Declaration, 1 25.

25. The Leibstadt LTT results matched the analytical predictions and identified no anomalous plant behavior. Nichols Declaration, ¶ 26.

26. The analytical tools used to predict the performance of the Leibstadt plant during transients are the same as those used at VY. Nichols Declaration, ¶ 26.

27. In the draft SER, the NRC Staff concluded that the experience at the plants that have undergone large unplanned transients shows that "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." Draft SER at 266.

28. In the draft SER, the NRC Staff concluded that the Leibstadt LTT program results "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." Draft SER at 266.

4

29. In approving the EPU application for the Duane Arnold Energy Center, the NRC Staff concluded that "[n]o new plant behaviors have been observed that would indi-cate that the analytical models being used are not capable of modeling plant behavior at the EPU conditions." Letter dated March 17, 2005 from Deirdre W. Spaulding (NRC) to Mark A. Peifer (Duane Arnold Energy Center), Attachment 2 at 11, Exhibit 14 to the Nichols Declaration.

30. During its operation at current licensed power levels, VY has experienced the follow-ing unplanned transients: (1) On 3/13/91, the with reactor at full power, a reactor scram occurred as a result of Turbine/Generator rip on Generator Load Rejection due to a 345 kV Switchyard Tie Line Differential Fault. This event was reported to the NRC in LER 1991-005-00, dated 4/12/91. (2) On 4/23/91, with the reactor at 100%

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 event in-cluded a loss of offsite power. This was reported to the NRC in LER 1991-009-00, dated 05/23/91. (3) On 6/15/91, during normal operation with reactor power at 100%

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 event was reported to the NRC in LER 1991-014-00, dated 7/15/91. (4) On 6/18/2004, during normal operation with the reactor at 100% 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 event was reported to the NRC in LER 2004-003-00, dated 8/16/2004.

(5) 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 event was reported to the NRC in LER 2005-001-00. Nichols Declaration, 1 28.

31. Most of the modifications associated with EPU, 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 deminer-alizer filtered bypass were already installed at the time of the most recent (August 2004 and July 2005) transients. Nichols Declaration, 1 29. In each instance, the modified or added equipment functioned normally during the transient. Id.

32. VY performed as expected in response to all the transients. No significant anomalies were seen in the plant's response to the events. Nichols Declaration, 1 30.

33. The performance of VY in the transients it experienced at current power levels was well within the bounds of analyzed VY response. Nichols Declaration, ¶ 30.

34. No systems have been added or changed at VY that are required to mitigate the con-sequences of the large transients that would be the subject of the LTIT. Also, the VY 5

EPU is performed without a change in operating reactor dome pressure from current plant operation. Nichols Declaration, ¶ 31.

35. There is no basis for the transient performance of the plant under EPU to be outside the NRC Staff accepted experience base for EPU. Nichols Declaration, 1 31.

36. In the draft SER, the NRC made the following determination with respect to the large transient experience at VY: "Another factor used 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." Draft SER at 266.

37. Technical Specification-required surveillance testing (e.g., component testing, trip logic system testing, simulated actuation testing) performed during plant operations demonstrates that the systems, structures and components ("SSCs") required for ap-propriate transient performance will perform their functions, including integrated per-formance for transient mitigation as assumed in the transient analysis. Nichols Decla-ration, 1 33.

38. 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 accor-dance with the design during large transients; their periodic testing assures that their performance during large transients will be acceptable. Likewise, the reactor protec-tion system instrumentation is tested quarterly, assuring that it will carry out its de-sign function in the event of a large transient. Nichols Declaration, ¶ 34.

39. 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 re-load licensing analysis. Nichols Declaration, 1 35.

40. The performance of a scram from high power as those occurring during LTT results is a transient cycle on the primary system. Nichols Declaration, 1 37.

41. Primary system transient cycles should be avoided if at all possible, since they intro-duce unnecessary stresses on the primary system. Nichols Declaration, 1 37.

6

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 Motion for Summary Disposition of New England Coalition Contention 3," "Statement of Material Facts Regarding NEC Contention 3 on Which no Genuine Dispute Exists," and "Declaration of Craig J. Nich-ols" were served on the persons listed below by deposit in the U.S. Mail, first class, post-age prepaid, and where indicated by an asterisk by electronic mail, this 2nd day of De-cember, 2005.

• 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 lesrrr(comcast.net Washington, D.C. 20555-0001 ask2(anrc.2ov

• 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 aib5a)nrc.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 secy(nrc.gov, hearinpdocket( nrc.2ov

• Sarah Hofmann *Sherwin E. Turk, Esq.

Special Counsel *Robert Weisman, Esq.

Department of Public Service *Jason C. Zorn, Esq.

112 State Street - Drawer 20 Office of the General Counsel Montpelier, VT 05620-2601 Mail Stop 0-15 D21 Sarah.Hofmiann(~state.vt.us U.S. Nuclear Regulatory Commission Washington, D.C. 20555-0001 set(nrc.gov, rmw0nrc.gov. icz(inrc.gov

• Anthony Z. Roisman *Raymond Shadis National Legal Scholars Law Firm New England Coalition 84 East Thetford Rd. P.O. Box 98 Lyme, NH 03768 Shadis Road aroismananationallegalscholars.com Edgecomb ME 04556 shadisgprexar.com

• Jonathan Rund *Jered Lindsay 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 imr3aiDnrc.gov JJL5anrc.&ov

/ i5 "4~'

Matias F. Travieso-Diaz 2

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) )

DECLARATION OF CRAIG J. NICHOLS Craig J. Nichols states as follows under penalties of perjury:

I. Introduction

1. I am Extended Power Uprate Project Manager for Entergy Nuclear Operations, Inc.

("Entergy"), and I am the manager for the proposed extended power uprate ("EPU") at the Vermont Yankee Nuclear Power Station ("VY"). I am providing this declaration in support of Applicant's Motion or Summary Disposition of New England Coalition's ("NEC") Contention 3

("NEC Contention 3") in the above captioned proceeding.

2. My professional and educational experience is summarized in the curriculum vitae attached as Exhibit I to this declaration. Briefly summarized, I have over twenty years of professional experience 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 proposed EPU at VY.

3. In my capacity as manager for the VY EPU project, I am responsible for overseeing the plant modifications that are needed to implement the upgrade and the performance of the technical evaluations and analyses required to demonstrate W's ability to operate safely under uprate conditions. I am familiar with VY's operating history, current plant operations, and the anticipated operating conditions after the uprate.

4. In NEC Contention 3, as admitted, NEC asserts that: "The license amendment should not be approved unless Large Transient Testing is a condition of the Extended Power Uprate."

In this Declaration, I will address this contention and demonstrate it lacks technical or factual basis.

5. In particular, I will demonstrate that, based on the (a) similarity of the VY design configuration and system functions at pre-EPU to post-EPU; (b) results of past transient testing at VY and the plant's responses to unplanned transients; (c) the close correlation between past transient and safety analyses and the results from actual transients; and (d) the experience with planned and unplanned transients at other post-EPU plants, the effects of transients at EPU conditions at VY can be accurately predicted analytically without the need for actual transient testing. The transient analyses performed for the VY EPU demonstrate that all safety criteria are met and that the uprate does not cause any previous non-limiting events to become limiting. On the other hand, a scram from EPU power levels -- such as those that would occur during LTT --

would cause an undesirable transient cycle on the primary system. Such transients should be avoided if possible.

II. Background on Large Transient Testing

6. In its license amendment application to increase VY's authorized power level from 1593 megawatts thermal ("MWt") to 1912 MWt, Entergy seeks to be exempted from performing Large Transient Testing ("LTI'). NEC Contention 3 asserts that LTT must be conducted to assure that public health and safety is protected during EPU operations and that the EPU should not be approved unless LTT is required to be performed.

7. The VY EPU request was prepared following the guidelines contained in the NRC-approved document "General Electric Company Licensing Topical Report for Constant Pressure Power Uprate Safety Analysis (CLTR): 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 plant operating pressure (i.e., a "constant pressure power uprate.")

8. NEDC-33004P-A defines two LTTs applicable to EPU operations: 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. Standard Review Plan (SRP) 14.2.1, "Generic Guidelines for Extended Power Uprate Testing Programs" (Draft, 2002) ("SRP 14.2.1"),Section III.C.2.f

9. Closure of all MSIVs is an "Abnormal Operational Transient" as described in Chapter 14 of the VY Updated Final Safety Analysis Report ("UFSAR"). The MSIV closure test requires the fast closure (within 3.0 to 5.0 seconds) of all eight MSIVs from full rated power.

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. The transient produced by an MSIV closure test is the most severe abnormal operational transient from the standpoint of increase in nuclear system pressure.

10. A Generator Load Rejection From High Power Without Bypass ("GLRWB")

(commonly referred to as generator load rejection) is also an Abnormal Operational Transient as described in Chapter 14 of the UFSAR. The GLRWB analysis assumes that the transient is initiated by a rapid closure of the turbine control valves (after a load rejection). It also assumes that all bypass valves fail to open. The purpose of this test is to determine and demonstrate reactor response to a generator trip, with particular attention to the rates of changes and peak values of power level, reactor steam pressure and turbine speed. A GLRWB is the most severe transient in terms of challenge to the fuel thermal limits.

11. NRC's Review Standard RS-001, "Review Standard for Extended Power Uprates,"

Revision 0 (December 2003) references SRP 14.2.1 for the testing related to extended power uprates. The SRP, in turn, specifies that LTT is to be performed in a similar manner to the testing that was performed during initial startup testing of the plant. The SRP also provides guidance on how to justify a request for elimination of the LTT requirement. Previous operating experience and the introduction of no new thermal-hydraulic phenomena or unanalyzed system interactions are among the factors that the Staff will take into account in evaluating suih a request. SRP 14.2.1,Section III. C.2. A copy of SRP 14.2.1 is included as Exhibit 2 hereto.

12. Entergy followed the SRP guidance in taking exception to performing LTT during EPU operations at VY. Entergy included in its Application a separate attachment discussing the bases for an exception to performing LTr at VY in connection with the proposed EPU. 1 The basis for seeking an exception to the LTT requirement is that additional MSIV closure and generator load rejection tests are not necessary. If performed, these tests would not confirm any new or significant aspect of performance that is not routinely demonstrated by component level testing and would impose additional and unnecessary transient cycles on the primary system.

13. On November 2, 2005 the NRC Staff issued its draft Safety Evaluation Report ("Draft SER"), in which the Staff concluded that the requested exception from LTT at VY should be granted. Specifically, the Staff concluded that "in justifying test eliminations or deviations, other than the condensate and feedwater testing discussed in SE Section 2.5.4.4, the licensee adequately addressed factors which included previous industry operating experience at recently uprated BWRs, plant response to actual turbine and generator trip tests from the KKL plant, and experience gained from actual plant transients experienced in 1991 at the VYNPS." The Staff concluded: "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. The staff also noted that the licensee followed NRC staff approved GE topical report guidance which was developed for the VYNPS EPU licensing application." Relevant excerpts from the Draft SER are attached as Exhibit 5 hereto.

14. Thirteen boiling water reactor ("BWR") plants similar to VY have implemented or are implementing EPUs without increasing operating pressure:

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

• Monticello (106% OLTP)

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

• Leibstadt (i.e., KKL) (105% to 119.7% OLTP)

• Duane Arnold (105% to 120% OLTP)

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

Application, Att. 7, "Justification for Exception to Large Transient Testing" ("Justification"). Entergy subsequently supplemented its justification discussion. See, Application, Supplement 3, Att. 2 (Oct. 28, 2003).

Copies of these materials are included as Exhibits 3 and 4 hereto.

• Quad Cities Units 1 and 2(100% to 117% OLTP)

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

• Clinton (100% to 120% OLTP).

15. There is a wealth of operational experience on the performance of these plants under unplanned large transients, as well as under LTT. I will discuss that experience below.

III. Adequacv of the analytical tools used by Entergv to accurately predict plant performance in large transient events under EPU conditions

16. The transient analyses for.VY were performed using the NRC-approved code ODYN, which models the behavior of the safety- and non-safety-related systems in the plant during operational events. The transient analyses for VY have been accepted by the NRC Staff. The transient analyses for VY include the two large transients for which LUT is required.

17. The transient analyses for VY model both the performance of the secondary side of the plant and any potential interactions between primary and secondary systems in a transient.

The analyses assume operational configurations and componentlsystem failures that bound (i.e.,

.represent more severe conditions than) the transients that would occur during actual EPU plant operations or during LT1Ts.

18. While some of the plant operating parameters (e.g., core power distribution) will change to accommodate higher power operation after EPU, none of the plant modifications made for the EPU will introduce new thermal-hydraulic phenomena, nor will there be any new system interactions during or as the result of analyzed transients.

19. As part of the EPU analyses, Entergy evaluated the increase in main steam flow resulting from EPU operation and its effect on the loadings on piping and pipe supports during large transients. Entergy's analyses determined that the loadings on piping and pipe supports during large transients at EPU power levels are within acceptable bounds. Entergy's evaluation of the performance of piping and pipe supports was reviewed and accepted by the NRC Staff.

Draft SER § 2.2.1 at 29.

20. Since the analyses assume operational configurations and component/system failures that bound the transients that would occur during actual EPU operations and since no changes will be made to the plant that could introduce new thermal-hydraulic phenomena or give rise to any new system interactions during the transients. Therefore, the transient analyses accurately predict the plant response to large transient events without need to perform actual LTT.

IV. Operational experience at plants in the United States and abroad that have implemented EPUs

21. 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 unplanned 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 requirement 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 event 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 6), all systems functioned as expected and no anomalies were seen in the plant's response to this event.

• 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. As noted in SNOC's LER 2001-003-00 (attached as Exhibit 7), systems functioned as expected and designed, given the conditions experienced during the event.

• In addition, Hatch Unit 1 has experienced two post-EPU turbine 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 8 and 9).

Again, the behavior of the primary safety systems was as expected. No new plant behaviors for either plant were observed. The Hatch operating experience shows that the analytical models being used (which are the same as those in use at VY) are capable of modeling plant behavior at EPU conditions.

Progress Energy's Brunswick Units 1 and 2 were licensed to 120% of OLTP and were granted the license amendments without a requirement to perform LTT. VY and Brunswick are BWR/4 plants with Mark I containments. Brunswick Unit 2 experienced a post-EPU unplanned event 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 (attached as Exhibit 10), no anomalies were experienced in the plant's response to this event, 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 similar plants to VY, featuring Mark I containments. Dresden 3 has experienced several turbine 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 11 and 12). The plant response was as predicted in the transient analyses, which use the same methodology as those performed at VY.

The plant response indicates that the analytical models used for transient analyses are capable of accurately predicting transient plant behavior at EPU conditions.

• Similar plant response was observed in May 2004, when Dresden 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). Exelon LER 2004-003-00, attached as Exhibit 13.

22. In every instance in which unplanned large transient power levels have been experienced at these four plants, the plant's response was similar to the analytical predictions and exhibited no new phenomena. The analytical tools (i.e., the ODYN code) used to predict the performance of these plants to the transients are the same used by Entergy at VY.

23. During its review of the EPU application for the Duane Arnold Energy Center, the NRC Staff inquired about the applicability of operational experience at other plants to Duane Arnold. Ultimately, however, the NRC Staff concluded that the operational experience showed that "[n]o new plant behaviors have been observed that would indicate that the analytical models being used are not capable of modeling plant behavior at the EPU conditions." Letter dated March 17, 2005 from Deirdre W. Spaulding (NRC) to Mark A. Peifer (Duane Arnold Energy Center), Attachment 2 at 11, Exhibit 14 hereto.

24. Likewise, in its Draft SER, the NRC Staff concluded that the experience at the plants that have undergone large unplanned transients shows that "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." Draft SER at 265-66.

25. The KKL (Leibstadt) power uprate implementation program was performed during the period from 1995 to 2Q00. Power was raised in steps from its previous operating power level of 104.2% OLTP to 119.7% OLTP. Uprate testing was performed at 110.4% OLTP in 1998, 113.4% OLTP in 1999, 116.7% OLTP in 2000 and 119.7% OLTP in 2002. KKL testing for major transients involved turbine trips at 113.4% OLTP and 116.7% OLTP, and a generator load rejection test at 104.2% OLTP. See Exhibit 15 hereto.2

26. These large transient tests at KKL demonstrated the response of the equipment and the reactor response. The close correlation to the predicted response (which was obtained using the same analytical tools employed at VY) provides additional confidence that the uprate licensing analyses consistently reflected the behavior of the plant.

27. In the draft SER, the NRC Staff concluded that the Leibstadt LIT program results "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." Draft SER at 266.

2 The attachments to Exhibit 15 are proprietary and are not included.

V. VY Operational Experience

28. VY has experienced a number of unplanned large transients during its operating history:

• On 3/13/1991, with the reactor at full power, a reactor scram occurred as a result of Turbine/Generator Trip on Generator Load Rejection due to a 345 kV Switchyard Tie Line Differential Fault. This event was reported to the NRC in LER 1991-005-00, dated 4/12/91 (attached as Exhibit 16).

• 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 event included a loss of offsite power.

This was reported to the NRC in LER 1991-009-00, dated 05/23/91 (attached as Exhibit 17).

• 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 event was reported to the NRC in LER 1991-014-00, dated 7/15/91 (attached as Exhibit 18).

• 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 event was reported to the NRC in LER 2004-003-00, dated 8/16/2004 (attached as Exhibit 19).

• 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 event was reported to the NRC in LER 2005-001-00 (attached as Exhibit 20).

29. It is important to note that most of the modifications associated with EPU, 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 were already installed at the time of the June 2004 and July 25, 2005 transients. In each instance, the modified or added equipment functioned normally during the transient.

30. VY performed as expected in response to all the transients. No significant anomalies were seen in the plant's response to the events. The performance of VY in the transients it experienced at current power levels was well within the bounds of analyzed VY response.

31. 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. Also, the VY EPU is performed without a change in operating reactor dome pressure from current plant operation.

Therefore, there is no basis for the transient performance of the plant under EPU to be outside the NRC Staff accepted experience base for EPU, that is, the transients described in para. 21 above.

32. In the draft SER, the NRC made the following determination with respect to the large transient experience at VY: "Another factor used 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."

Draft SER at 266.

VI. Role of component testing at VY in providing assurance that the plant's safety systems will operate as intended during transient condition

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

Such testing demonstrates that the systems, structures and components ("SSCs") required for

-. 10-

appropriate transient performance will perform their functions, including integrated performance for transient mitigation as assumed in the transient analysis.

34. For example, 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 design during large transients; their periodic testing assures that their performance during large transients will be acceptable. Likewise, the reactor protection system instrumentation is tested quarterly, assuring that it will carry out its design function in the event of a large transient.

35. 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.

VII. Summarv and Conclusions

36. My testimony in this Declaration justifies the following conclusions:

• Previous industry operating experience Operating experience at other plants that have implemented a constant pressure power uprate such as that proposed by Entergy at VY has shown that the transient analysis results bound the performance observed during actual operational transients. This industry operating experience is applicable to the VY because of the similarity in its design to that of those plants and because the analytical methodologies are also the same.

Previous VY operating experience Previous operating experience at VY for large transient events has shown 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 transient events 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 these recent transients demonstrates that the EPU modifications do not significantly affect the plant's response during transient conditions.

• Absence of new thermal-hydraulic phenomena or system interactions The operation of VY after the EPU will result in different operating parameters (e.g., core power distribution, feedwater flow, moisture carryover) but will not result in any new thermal-hydraulic phenomena in the event of a plant transient.

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.

• Demonstration of system and component performance through surveillance testing Technical Specification-required surveillance testing, routinely performed during plant operations and during plant shutdown, demonstrates that the SSCs required for appropriate transient performance will perform their functions, including integrated performance for transient mitigation as assumed in the transient analysis.

37. The performance of a scram from high power as those occurring during LTT results is an undesirable transient cycle on the primary system. Primary system transient cycles should be avoided if at all possible, since they introduce unnecessary stresses on the primary system components. In light of the above discussed considerations, LTT is unnecessary and its undesirable effects outweigh any limited benefits that might accrue from the performance of such tests.

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

Executed on December 2, 2005.

raig J. Nichols

-.12 -

1 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 it 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.

• Achieved 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

• 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.

Acting Maintenance Manager October 1996 to January 1997

• Successful completion of 1996 Refuel Outage including recovery from MSIV 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

2 (ForAeXORM068

+4'<'%* U.S. NUCLEAR REGULATORY COMMISSION

'I STANDARD REVIEW PLAN 7/* OFFICE OF NUCLEAR REACTOR REGULATION 14.2.1 GENERIC GUIDEIUNES 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 majorplant 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 - Deaember 2002 USNRC STANDARD REVIEW PLAN Standard review plans are prepared for te guidance of am Ofice of Nuclear Reactor Regulation staff responsible for the review of so s to construct and operate nuclar power Plants. These documents are made available to the public a Dart of the Commission's poliy to inform the nucer industiy argd the eneral public of Mgulatory Procedures and polies. Standard review plans are not substitutes for regulatory guIdes or the CommIssion's regulations and compliance with them is not euired. The standard review pan sections are keyed to the Standard Format and Content of Saety Analysts Reports for Nuclear Power Plants. Not ll sections the Standard Format have a corresponding review plan.

Published standard reviewptans 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, Offien of Nuclear Reactor Regulation, Washington. D.C. 20555.

1. AREAS OF REVIEW The Equipment and Human Performance Branch coordinates the review of the overall K-I power uprate testing program. Secondaryrevlew branches are responsible for reviewing 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 Inthe review of proposed testing plans and acceptance crteria, as needed.

The review of EPU testing programs should be performed Inconjunction 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 3150-001 1.

Public Protection Notification If a means used to Impose an Information collection does not display 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.

DRAFT Rev. 0 - December 2002 14.2.1-2 1%')

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," to 10 CFR Part 50, 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 UC-100, OControl of Ucensing Basis for Operating Reactors,* the General Design Criteria (GDC) are not applicable to plants With construction permits Issued before May 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 8 tolo 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 in applicable design documents.

• IO 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 for original applications. Section 50.34, 'Contents of Applications:

- -Technical Information," which specifies requirements for the original operating

'license 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 power-uprate related modifications to the facility have been adequately constructed and Implemented; and (2) the facility can be operated at the proposed EPU conditions Inaccordance 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,

- erected and tested to quality standards commensurate with the importance of the safety fdnctions to be performed. Where generally recognized codes and standards are used, they shall be Identified and evaluated to determine their applicability. Additionally, a'cuality assurance program shall be established to ensure that SSCs will satisfactorily perform their safety functions.

14.2.1-3 DRAFT Rev. 0 - December2002

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 Inthe 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 Inthe 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 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 forrn prescribed for the original application. Section 5.34, "Contents of Applications: Technical Information," specifies requirements for the original operating license application.

In particular, 10 CFR 60.34(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) to the EPU test program ensures that the licensee submits adequate Information, commitments, and plans 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 safeti functions. This also ensures that preoperational and Initial startup testing Invalidated by the requested increase Inpower level are evaluated and reperformed as necessary to demonstrate safe operationof the plant.

1ll. REVIEW PROCEDURES The purpose of this review Isto 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 sufficient 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 Prooosed EPU Test Program to the Initial Plant Test Program

1. General Discussion The licensee should provide a comparison of the proposed EPU testing program to the original power-ascenslon 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 Nthe 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. S*ecific Accentance Criteria Within Its associated technical discipline, each secondary branch reviewer will determine If the licensee has adequately Identified the following Inthe 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.

142.1-5 DRAFT Rev. 0 - December 2002

The reviewer should refer to the plant-specific testing Identified In FSAR Chapter 14.2, 4Initial 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,w 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 performnance 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 III.C, below, for guidance on assessing the adequacy of justifications for proposed differences.

B. Post Modification Testing Reauirements for Functions Imoortant to Safety Imoacted by EPU-Related Plant Modifications I1. 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 setpotnt adjustments necessary to support operation at power uprate conditions, and i 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, setpoint 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 Attachment 2, 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 functional testing.

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 1ilA and lll.B above. The licensed shall provide an adequate Justification for each of these normally required power-ascension tests that are not included in the EPU test program. For each proposed test exception within its technical area, each secondary review branch will verify the adequacy of the licensee's

- justification:

2. S2ecific Acceptance Criteria If the licensee proposes to not perform a power-ascension test that would normally be required by the review criteria contained In Sections iILA and 11l.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 Ogerating Experience 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 thermal-hydraulic phenomena or system interactions that may be 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 Facflitv Ooeration and Trial Use of OPeratina and Emergencv 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

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

e. Margin Reduction In Safety Analysis Results for Anticipated 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 rhargln 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 Inanalysis 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 Ucerising Topical Report, 'Generic Guidelines for General Electric Boiling Water Reactor Extended Power Uprate" (referred to as ELTR-1), NEDC-32424P-A, Class III, February 1 999, as anlacceptable 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 5.1 1.9.d and Appendix L2.4

• - 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 14.2.1-8 - DRAFT Rev. 0- December2002

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 uprate.

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.

9. Risk ImDlications For cases where the licensee proposes a risk-informed basis for not performing certain transient tests, SPSB should be consulted to assist In the review. Risk-informed Justifications for not performing transient tests should be carefully weighed against the potential benefits of perfonning 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 circumstances during transient testing. In any case, a risk-informed Justification should not be used as the sole basis for not performing transient testing.

If the 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 Adeauacv of Proposed Transient Testing Plans

1. 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 Acceptance 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 will 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 Ifthe 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 1 and 2 to this SRP section provide a generic listing of funl 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

- 'operted 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 Ifabove, a statement similar to the following should be provided Inthe staffs Safety Evaluation Report (SER):

SThe staff has reviewed the EPU test program Information provided in the license amendment request in accordance with SRP Section 142.1 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 program-satisfies the requirements of Criterion Xl, 'Test Control,'of 10 CFR Part S0, Appendix B. and Is therefore acceptable."

14.2.1-1 1 DRAFT Rev. 0 - December2002

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, §52.47 'Contents of Applications."

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

3. NUREG-1503, eFinal Safety Evaluation Report Related to the Certification of the Advanced Boiling Water Reactor, Volumes I 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 Ucensing 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 Ucensing Topical Report "Generic Evaluations of General Electric Boiling Water Reactor Extended Power Uprate," (ELTR-2), NEDC-32523P-A, Class 111,February 2000, and Supplement 1, Volumes I and 11.

7. General Electric Company Ucensing Topical Report, "Constant Pressure Power Uprate,"

NEDO-33004P, Revislon 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 Ucensing 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 Informnation Notice 2002-26, Failure of Steam Dryer Cover Plate After a Recent Power Uprate,' September 11, 2002.

K ..

142.1-13 DRAFT Rev. 0 - December 2002

Steady-State Power Ascension Testing ApRIlcable to Extended Power Unrates Power Ascension Test Reference Recommended Initial CondMtIone Typical Test Acceptance Criterla Pnmy Technical ReVIEW Branch Conduct vibration tes Regulatory Gude (RG) 1 68, lowest practical power lve rector vessel and reactor coolant system EMEB aNd mntorng of reactor App A component vibration characternstics withn design vessel internals and reactor 4.s. 59 See NRC Information Notice 2002-26 and RG 120 coolant system components Measure power reactivity Re 16 8, AppA 100% of RTP characteristics haccordance with des"i SRXB coefficients (PWR) or pow"r 5.9 vs flow characteritics (BW R)_ _ _ _ _ _____

Sle "t ore RG 1 6. App A 100% oRTP charactenstics inaccordance with design SRXB pe111)rfor ance 5b _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _

Control rod pattems RG Ies. App A powr equal to hgs power lve that rod core lmts not exceeded SRX5 exchage So exchanes witl be solwed at power Control rd misalignment RO 168. App A 100% o RTP demonstretabeby to detect men SRXS testing 51 rod misagnment equal to or less than TS limits Fasled tuel detection sten RO 1 68 pp A i00% o RTP veriy proper operation IEHO

_ __ _ _ _ _ _ _ Sq _ _ ___

Plant process computer RO 1.68. App A 100% of RTP inpu and calculetion wre coned SPLBIEEIB Sr Cadibrate maor or pricipl RG t.68.App A 100% of RTP veanyper _nance SRXBSPLB plant cnrol systems Sa Mm steam and rmn RO 1.6. App A 100% o RTP operate in accordance with performance SPLB feedwater system operation 5v -re Shield ad penetration RO 1 68. App A 100% of RTP mnintain temperature wih design lmits SPLB cooling systems 5.w ESF auxiliary and RG 1.68. App A 100% Of RTP capable of performng design functions SPLB envonmental system 5x Cabate systems used to RG 1 68 AppA 100%ofRTP venfyperformance EEIB determIne reactor thermal 5y power Chienial and radlochernicl RG 1 68. App A 100% of RTP control systems function h accordance with design IEHB control systems 5.aoa Sample reactor coont RG 1 68. App A 100% of RTP chemistry limits we not exceeded EMCB system and secondary 5..

coolant systems DRAFT Rev. 0 - December 2002 14.2.1-14 ATTACHMENT 1

( K

I

( ( (

Power Ascension Test _ efrence Reconmended rnlhtCondtIms Typical Test Acceptance Citeda Primer yechnical RevIew Branch Ro 1.e., App A 100%ORTP Whelding adequacyand Identify 10 CFR Pert 20 IEHB Radfatlonusrveys 5bb hblhrdetion RnI e8.AppA 100% OfRTP main MvtcehhheswW*desetnlrnls 8PLB Venhabon Systems (Inckmdim Wy 41end9tf cotainment end steam fin RoG l1S, App A. towest practical power level panietms wIthn destan vetoe EMER Accepebfy olqeector Intemals. ppi, end I.e.1. 1.tl 3.1 ae.and 5 ea s end espn alons .__ _. __ _

vi e ,o .. _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _

DRAFT Rev. 0 - December 2002 14.2.1-15 ATTACHMENT I

Transient Testina Anplicable to Extended Power Unrates Transient Test Reference Typical Reactor Plant initial Typical Transient Test Acceptance Criteria and Applicable Accident Analyses Conditions Associated Functions Important to Safety (SRP Section)

Rebel valve bestwng RG 6 APPA Reactor power level et predetemined Relel valve tin at a specified pressure setting 15.1.2 nadvertent Opening of a 4 p and 5t power level plateaus Steam Generator Relief or Dely time between tm signal hilsting redef valve open"S and Safety Valve Inspecton AAireire valves set In auto the sart ofmotosn Rocdre (P) t156.1 Inadvertent Opening of

• PWR 72510 kdu* vveWundt tests Opening stroke Wm of to main valve dis and distance Preasunser Press Reliet prescibed power level plateaus Valve or. BWR Pressure ClosIng t time of IN main valve piston following release of Rebe Valve Individual vale cap" teats at low powe the pneumatIcally operated mechanical push rod (25% of RTP) using bypass valve Movement or tubine generator output as a mneasurement vatable Dynami response of plant RG t 6S.AppA 100% of RTP Performance Ihnacordance with deslgn bodesn load s*g 5j Reactor core Isolaon iP 7512 Steady-state reactor operations at rated Staup from hot standby condlons and discharge of rated low cood1ng fnlctional lste temperatue and pressure into the reactor vessel at rated pressure and temperature witin a specified time RCIC agned for atandby operabon Verfication of meIIUIII rated flow Isolation bip Reator power at approximately 25% of RFP Venfication of overspad Irip Turbine gland condenser system shal prevent team leak to aftosphere Dynamic response of ptlnt RG 165. AppA 100% ofRTP Peaormance In accordance withdestin 1531 (BWR) & 15 3 2 (PWR) totimisti reactorcoolant 511 Pump btps or Clos" o Trip from teeadtate power operation Insarumentation Is adiusted to provide an accurate conversion of Less of Forced Reactor reactorcoolant sysemflow IP n512 individual det pump 6p values to a summned cr flow over the Coolant Flow ticluding Trip of Cont valves cording of transients fWi trip And range ot twopump opeaions PUmp Motor dunng purmp restart (Reactor coolant Recirculalton pump insthunentatin Is calibrated recirculallon puinp trip test) Recording of imii heat transfer paremeters Loop fl rom single-tap and double-lap puwps a*rees witsn 3%

Return to twopump operation in accord with facility oipebring procedures Core low ftrom srigle-tap and double-tap pumps agrees within 2%

Trip of a single pump and of both pumps sh1ultaneously. Individual let pump flow variation from average pump flow Is linmied Dynamic response of the RG tIe. AppA 90% of RTP performance In accordance with design 15.1.1 Decrease InFeedwater plnt o loss ofeedwater S k Temperature heaters that results In mot severe feedwater temperature reduction DRAFT Rev. 0 - December 2002 14.2.1-16 ATTACHMENT 2

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C C (

Trans5ent Test Reference Typial Reactor Plant Intal Typical Tmnslent Test Acceptance Criteria and Appflcabl Accident Analyses CondItions Associated Functions Important to Safety (SRP Section)

Dynambrespnse ofplant ROIS6. Appendix plet perforance n acrdae dsdesIgn 182.7 Loss of Nannl Feedweter to lo" of eedwaterflow A. Seclon 5 Flow Dynm respons of plant RO 1.". App A 100% f RTP vh eletl syslem aIn P fome hI aeodance wi desin Ihudtg 152.6 Loss of Nonere gonyAC forbul load reetion 56n forrinr l l-power operaton and lod Power to the Stion reJedton th tmidutjectLi e uto fer o pnt loads as dened utoe tat of uxli sof Oft Power IP72517 m*miaedM overspeedondlffon dieselgena i ts Tas$ speclled sequence IP7238 stesdy-takte plant operations with greater thn 10% generao outp P 72517 6 Rectr pressre remnhs below live f seetyvav setting 72182) Pressrizer sfely aves do uotlilt t of t plant with reibkers Inspecified Al saely syems uisRPS. HPCI. dIesel nert and poIn o tht plnt loads s be RCIC hco wIthout mu aitane trtferred diey to the dsel pnert fowg ss d ouse power Normal reetr cooli ryms should antalI adequate owe bnus and pevent duatn ef the Auh e re*ulallon systflow nol mode De Ss stm; h erted relifvses ma specived hnclon to ono pmere Turbtie bypss system operates to manth specifed prensure Sleamn syste powe-cutd presure reifvlet"F open and dco e qasctd vau P spryvalves open and oe s speled values.

Reaftor coont r ellnslip reman pbt~nedvedues,..

Pessr level IsmaIned wtIn presiaed Imits Stem genraorel mawn b e..

prses _ _

DRAFT Rev. 0 - December 2002 14.2.1-17 ATTACHMENT 2

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

Dynamic response of plant RG 1 68. App A tIr from steady stabt operalton grsater Performance In accordance with design, Including 15 2.1 Turbine Tnp toturbine Iep Sll Ihan S%o RTP reactor coolant pumps do not trip (TuTilne tnp or generator IP 72580 eation of the lost by trip of the man IMP) IP 72514 gererator output breaker pressurizer spray valve opens and cdoses at the specfied values recirculation system flow control mode rnust reactor pressure remains below the elpotf the first safely be specified valves. pressuzer saflly valves do not Witor weep pressurizer level wihn prescnbed swMs steam system power actuated pressure rellef valve opens and doss at specfied values reator coolant _pume rare relatohip mawhttin defined values steam generator level rems withh prescrbed ltis no loding of the steam lm during the ariK no _ition of ECCS and MSIV Isolation during he ltraset turbine bypass system operates to main specft pressure (plants with 100% bypass capblty hl reman at power

-hu scram during the transient) plants with aeleltod et s maintain power wi scram from rocirculetion pump overspeed or cold feedwater effect reactor poeon system functions shwuld be ve d ci safety and ECCS systems suh as RPS. hPCI, diesl generators, and RCIC function wihu manual asmesnce d called upon normal reactor cooling systems should maintain adeqte coollng nd prevent ectutlion of automatic depressurization stlem even though relief valves may hmcton to control pressure plant elektl loads (transferred as dened) turbine overspeed critena met Dynamic rponse of plant RG 168. App A Intial power level of 100% of RTP performance anaccordance wdh design 15.2.4 Main Steam Isolation Valve to automatic closure Of al 5 m.m CIoSrI (SWR) main ale isolation valves acceptance criteria Include MSIV closIng tans IP 72510 DRAFT Rev. 0 - December 2002 14.2.1-18 ATTACHMENT 2

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S. I HRO M 35tS. NUCLEAR REGULATORY COMMISSION 1.REPORT NUMBER CZ4M(ASsigned by NRC~ AOdVot, Sup. Ibv, NnCUI1."BIBUOGRAPHIC DATA SHEET 2 TrrILEANO SUm£TME NUREG-0800 NUREG*0800, Standard Review Plan..

. 3 DATE REPORT FLUESFED 14+/-1, Generic Guidelines For Extended Power Uprate Testing Programs MONTH t December 2002

4. FRN OR GRANT NUIBER L AIJHORCS) 6TYPEOFREPORT Robert Pettis Kevin Coyne Paul Prescott 7.PERIODCOVERED Attwwral

& PERFORMING ORGANIZATION - N EA DDR 4ARp*;p a1wv0, Li M Division of Inspection Program Management Office of Nuclear Reactor Regulation U.S. Nuclear Regulatory Commission Washington. DC 2055540001 L SPONSORINGORGANMAION*NAMEANDADRESS /A p4 5 1 r hRssv0 rP US MborvPe;1*W67C0WdSV Same as above

10. SUPPLEMENTMY N3TES 11.AS5TRATgOw*=s.'hs)

This Standard Review Plan (SRP) section provides general guidelines for reviewl 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 WORDStDESCR RS 0IS AVALA1WAEITrJ1 Extended Power Uprate, EPU, testing, test program, power ascension testing, transient testing unlimited 4 Z; 14 SECLMITYCLASSIFIGAMON unclassified unclassified 15 NUMBER OF PAGES 16 PRICE h a s ~ahfypuu~ ?IAFdm Ol s ~

_4q7 3 ,OL MFCFORUA = 924SZ TM IMM -S 04*W-Dy produmd by M Fdml PPM& k,,-

3 I

Docket No. 50-71 BVY 0380 Attobment 7 Vermont Yankee Nuclear Power Station :

Proposed Technical Specification Campge No. 263 Extended Power Uprate Justification for Exception to Lare Transient Testing 0

BVY 03-S0 /Attacdment 7/Page I JUSTW[CATION FOR EXCEPON TO LARGE TRANST TESTING

Background

The basis for the Constant P}essure Power Uprate (CPPU) request was prepared following the guidelines contined in the NRC approved, General Electric (GE) Company Licensing Topical Report for Constant Ptessure Power Uprate (CLTR) Safety Analysis: NEDC-33004P-A Rev. 4, July 2003. Ile NRC staff did not accept GEs proposal for the eerc elimination of large transient testing (Le, Main Steam Isolation Valve (MSIM) closure and turbine generator load rejection) presented in NEDC-33004P Rev. 3. Therfor on a plant specific basis, Vermont Yankee Nuclear Power Station (VYNPS) is taking exception to the large transient tests; MSIV closwe and turbine generator load rejection.

The CPPU methodology, maitaming a constant preaur, simplifies the analyses and plant changes required to achieve uprated condition Although no plants have implemented an Extended Power Uprate (E) using the C1#M, thirteen plants have Implemented EPUs without increasing reactor pressUre.

• Hatch Unite I and 2 (105% to 113% of Original Licensed Thermal Power (OLTM)

• Monticello (106% OL1P)

• Muelleberg (Le, KKM) (105% to 116% OLTP)

• Leibstadt(Le, KEL) (1O5% to 117% OLIP)

• Duane Arnold (105% to 120% OLTP)

• Brunswick Units I and 2 (105Y to 120%e OLTP)

• Quad Cities Units I and2 (lO%to 117% OLTP)

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

• Clinton (10%to 120%)

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

Entergy believes that additional MSIV closart and generator load refection tests are not

f. f

. Ierformen nedse ets wuld ot c m new or signcnt spet of pformance that is not routinely demonstrated by component level testing. This f ir1he supported by Industry experience which has demonstrated plant perfrmamce, as predicted, under EPU conditions. VYNPS has exerienced generator load reJecdons from 100% current licensed thermal power (see VYWPS Licensee Event Reports (LER)91-005, 91-9, and 91-014). No significant anomalies were seen in the plans response to these events. Further testing is not necessary to demonstrate safe operation of the plant at CPPU conditions. A Scram from high power ievel results in an unnecssary and undesirable transient cycle on the primary system. In addition, the risk posed by intentionally initiating a MSIV closure transient or a generator load rejection, although small, should not be incurred unnecessarily.

VYNPS Response to Unplanned Transientsi VYNS experienced an unplanned Generator Load Rejection from 100l power on 04J23/91.

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

BVY 03-80 /Attachment 7/Page 2 ugoal. Ihis was reported to the NRC in LER 91-009, dated 05t23191. No significat anomalies were seen in the plats response to this event. VYNPS also exmienced the foowig unp d generator loadrjection everds:

• On 3/13/91 with reactor power at 100% a reactor scram occurrcd as a result of torbine trip on genator load rject due to a 345KV Swchyad Tie Line Diftal Fault. Thi event was reported to the NRC in LER 91-005, dated 4/12191.

• On W15191 dring normal operatin with reactor power at 100%/a a reactor incram ocd due to a Turbine Contrl Vlve Fast Closure on Generator Load Rect resulting from a loss of the 345KV North Switchyard bus. Ths event was reported to the NRC in LER 91-014, dated 7/15191.

No significant anomalies were seca in the pla's response to these events. Tran*ie cxerience.

at high powers and for a wide range of power levels at operating BWR plantsbs shown a close correlation of the plant trnsient data to the predicated response.

Based on the similariy of plants, past transient testng, past analyses, and the evabati of test eults, the effects of the CYPU RIP level can be analytically determined on a plant specific basi e transient analysis pafirmed for the VYNPS CQPU demonstrates that all safety criteria ae met and that this upuate does not cause any previous non-limiting events to become limitng. No safety related systems were signiffcanly modified for the CPPU, however some in setpoints were changed. The instrumt setpoints that were changed do not conrIbue to the response to large tranet even No pbysical modification or selpoint changes were made to the SRVs. No new system or features were installed for mitigation of rapid pressmizatio S anticipafed opeational ocurrenes for this CPU. A Scram from high powe level results in an ujne=ssay and undesirable transient cycle on the primary syst. Therfor, additional trnsient testing involving sam from hih power levels is not justifiable Shoud any fiture large transients occr, VYPS procedures require verification that the actual plant response is in ac*rdance with the predicted response. Existing plant ever daft ora s capable of acquiring the necessary data to confirm the actual ves cxpected response.

Further, the vmoran uclear characteritics required for transient analysis am confirmed by th teady state physics testing. Transient mitigation capability is demonstrated by other equipment surveillance tests reqired by the Technical Specifications. In addition, the limiting tansien se E d as pat atthe reload J s anarls MSIV Closure Event Claomrc of al MSIVS is an Abnodnal Operational Thnsicat as described in Chapter 14 of the VYNPS Updated Fmial Safety Analysis Report (UFSAR). Te transient produced by the fast closue (3.0 seconds) of all main steam line isolatioa valves represents the most severe abnormal operal tmsient resulting in a muclear systm pressure rise when direct scrams are ignored.

The Code overpressure protection analys assumes the failure of the direct isolation valve position scrum. The MSIV closum hr net, assuming the backup flx scram verses the valve positio scrm, is more significaut. This case has been re-evaluated for CPPU with acceptable results The CLTR states ta: 'rhe same performance critria will be used as in the original power ascesion tests, anless they have been replaced by updated citeia since the inital test program."

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

BVY 03-801 Attachmeat7 /Page 3 As such, if the original MSWV closure test were roperfaaned, the results would be much less

• uignziflcant han the MSIV closure ansalysis performed by GB for CPPU.

The original MSIV losr test was intended to dmionstmte the followinx

1. Deteilnereartorrtra bea vird ngadfollowinginmutmeousf d se of a) Ractorpm re shal be ma ia below 1230psig.

b) Mximn eactorpressreshould be 35psi below thefirst qfe vave setpoint t77s mmgi2for if valve weppL).

2. FwmtoallychecttheAMgVsforprperoperaionanddetermine M cosl em a) CosrwetIme between 3 and5aecoads.

Item 1: Reactor Transient Behavior For this cvent fthe closure of the MSI~s cause a vessel pressure inc and an increase in reactivity. The negave ractvity of the scram foam MSIV position switches should offiet the poitie reactiity of the pressure increase such that there is a mnal increase in hat fk=

Thcrefmre, the mal performance during the proposed MS1V closure test is much less himiting than ay of the transients routinely revaluated. CFPU will have minial impact on the c ponents huportant to adbieving the desired them prfonmanc. Reactor Protectio systae (Tps) logic is unaffected arnd with no steam dome press incea overall control rod insertion tmes will not be significantly affected. MIV closure speed is controlled by adjusients to the actuator and is considered very reliable as idicated below.

Reactor Pressure Due to the miial- nature of the flux transent, the ected reactor pressure rise, Rtem I above, is largely dependent on SRV setpoint pefance At VYNPS all four SRVs a replaced with

-a p I d aj age. A , ume ouage. te removed valves am sent cut for testing and reculibration for installation in the following outage. Over the past ten >:ars there have been twenty five SRV tests performed. In those twenty five tests boly one test found the as-found setting outside the Technical Specification (TS) carent allowable tolerance of *3%. This valve was found to deviate by 3A% of its nominal lift setpoint. Note that this is bounded by the VYNPS design analysis for peak vessel pressure which assmes one of the four SRVs does not open at all (onc SRY out of service Given the historical performance of the VYNPS SREs along with the design margins, pfmance of an actual MSIV closure test would provide little beefit for de s vese ovesur protection that is not already accomplished by the c level testing 1hat is rotinely pefomed, in accordance with the VYNPS TSs.

Because reed vessel steam dome pressure is not being increased and SRV secpints not being changed, there is no increase in the probability of leahge afte a SRV liH&Since SRV leakage pe ac e is considered acceptable at the ctmunt conditions, which match CPPU condions with respect to steam dame pressure and SRV selpns, SRV leakage pcforance should b continue to be acceptable at CPPU conditions. An MSIV closure test would provide no

BVY 03-80/Attachment 7 /PAge4 ignificant additional confirmation of hem 1 performance criteia thatm routine component testngperformedevay cycle, in accordance with the VYNPS TSs.

Item 2: MSIV Closure Time Sluc stea flow assists MSIV closure, te focus of Item 2 was to V fythat the sm flow from mhe reactor was not shut off fister than assumed (L.e., 3 seconds). During maintenance and survelance, MSW actuat are evaluated and adjusted as necessary to control closure speed, and VYNpS test per has be= good. To accormnt for - or variatons in stroe *ims, the calirton test procedure for MSIV closure (OP 5303) requires an as left fast closure time of 4.0 +02 seconds Th MSIVs were evaluated for CPPU. The evaluation included MSIV closre time and determined that tie MSMs are acceptable for CPPU operation. Intry eiperie ncluding VYNPS, has shown that there ar no significant generic problems with actutor design. Conidence i v high that steam line dosure would xot be less th assutmed by the analysis.

Other Plant Systems and Componts Response The MSIV Elimt switches tlat provide the scram signal are ighy relible dnvices that are sutable for all aspects of this applicatio inchlug envirocnental reqirements. There is no direct efect by any CPPU changes on these switches. 7here may be an indirect kmpact caused by sightly higher ambient tempcraures, but the increased temperatures wll still be below the qualfication. tepeature. These switches ar expcte to be eqally reliable before and after

• ~C:PFU. cwu.

The Reactor Pmotectioc System (RPS) and Contwl Rod Drve (CRD) conoents that convert the scramrsignals into CRD motian are not dedy affected by any CP PU changes Minor changes in pressme drops aermss vessel components may result in very islt changes in control blade isrtion zates. These changes have teen evaluated and detcined to be insignficant The ability, to meet the scram performance requarment is not afected by CPPU. Techical Specification CM requirements fbr te crmporents Wi cotie to be met.

CPPU Modifications Feedwater System opeaton will eqaire operaion of al three feed pumps at CPPT conditions (unlike CLTP conditions). Operation of he additional Reactor Feed Pump (RFP) will not affect plant response to an MSIV closure trndent fAn t punps recuive a tdp signal prior to level reaching 177 inches. OvrI of the vessel after a,trp would only occur if level exceeded ap daly 235.5 inches Since the feodwater pumps the High Pressure Coolant Injectio (PM) turbine, and the RCIC turbine all rcive trip sgnal par to level reaching 177 inches, a sutantial margin exsts. VYWS operating history has demonstrated that this mtargin greatly xceeds vessel level overshoot during trandent events. Based on ths, there is adequate confidc that the vessel level will nnm well below the main steam lines under CPPU conditions.. The HPCI and RCIC pump trip fiactions am routinely verified as required by TSs and are caodered very reliable.

The mnodification adding a reciuatdon pump runback following a REFP trip will not affect the plant response to this transient The reactor scram signal from the MSIV limit switches will result in cotrol rod insertion prior to any ranual or automatic operation of the RPFPs. Since

EVY03-80 /AtachmeatPage5 contrl rods will alrmdy be Inserted, a subsequp t nmback of the recrculatin pumps will not affect the plant rpon.

1he modifcation (BVY 03-23 aARTSMELLLA7)to add an additional iu ped Spring Safety Valv (Ss will not affect the plant respons toothis transient The new thrd SSV will bave the same lift sedpoint as the two csting SSVs. This unsedt does not result in an opening of a SSV, noris credit takn for SSV actuatio Generator Load Reject Testing

'khnexator Load R Fmni High Power Without Bypass" (GLRWB) is an Abnornal qection p onal Transemt as described in Chapter 14 of th VYNPS Updated Final Safety Analysis Report (FSAR). This tansiet campetes with the turbmie p without bypass as the most limign transient that dialleages fh- llimits for each cycle The GRWB analysis assunes dia the tansiat is Initiated by a rapid cosure of the utinecontrol vales. it also assumies that all bypass valves fail to open.

The CLTR states.that "The same perfbnance criteria will be used as in the oiginal power asc tests, unless tr have been rqplaced by updated csiteria snce the inial test program."

The strtp test for generator load ueject allowed the select rod Insert feature to reduce the reactor power levd and, in coeuaction with bypass valv opening, conrol the tvinsient such that the reactor does not cnmm Cmrcnt VYNPS. design does not inde the select rod insert featue The PlA was also modified to Include a scram fiom the acceleration relay of the turbine control "ystem. Under cent plant design, tie original generator load rqect test can not be rc-performe If a generator load reject with bypass test *ere perfrmed, the results would be mch less signficant than the genetor load rject.wifthout bypass closue analysis performed by GE for CPFU.

Ihe original generator load rgect test was nteaded to daionsttate the followng L Detennine and demonstae reactor response to a generator Vp, with pardcular attenon to the rates ofchanges andpeak values ofpower ev4 reactorsteam premu and trbinespeed a Af testpresuretwuns must have ma;m n preurevalues below 1230 Fsit

b. Man rectorpressure should be 35 p bdeow the first sofety valve se int ( is marginfor sfetyVale weep .

c 2he selc rod insertfeature shall operote and in congzmctlon with proper bygp= valve opening shal control the trani such that the reactordoes not scram DQCtD plant modification discussed above, Criterion c. above would no longer be applicable for a generator load reject test. The gcnator load reject startup test was performed at 93.7% power; however, a reactor swnan occured during testing and invalidated the test. A design hange to iniate an Immediate scram on generator load reject was implemted and this startup test was bs cancelled since it was no longer applicable.

BVY 03-8O/AMtChMe+/-7I/Page6 Item 1 Reictor Response For a geeratrwload riject with bypass event, give curt plant design, the fist cloue of te Turbine Control Valves rCVs) cams a tap of the acceleration relay in the turbine control systemL The accration ra trip nitiates a full reactor swa The bypass valves open, however, since the capaciy of the bypass valves at CPU is 879%, vessel pssu increases. This results in an izaease in reacti . The negative reactivity of the TCV fs closure scrm fiom the acceleration relay should offset the positive reactivy ofhe pressure mcrease such that there is a yjnima increase in heat fhu Ibhrefoe the temal peformance daring a geerat load rejectio test would be much less limiting than san of the transiets routiney re-evaluated.

CPPU will have 1mni impact on th components important to achieving the desired therma perman= Raco Protecon systm (BPS) logic is unaffcted and with no steam dome Pressure, incases overal conarol rod inserto imes will not be sgaificantly affected. A trip channe and alanm fnctional test of the tbine conl valve fast closur scram is peforrmed every ree months in ecodae with plant techical opecificatious. This tip function Is co r veryreliable.

Reactor Pressur Due to the minal nature of tme fl= transient, the cxpected reator pressure rnse, Criteria a. and

b. above, are largely dependent on SRV ietpoint pufixmnce. Refer to the MSIV dosure Reactor Pssure secdon above for discussion of SRV setpoint perfrmae.

Because raed vessel steam dom pressure is not bing increaed and SRV setpoints are not being changed, there is no increase in the probability of leakge after a SRV hif Since SRV leakage po ce is considered acceptable at the current conditions, whih match OPFU coitos wih respect to stearm dome pressme and SRV selpoints, SRV leakage performe will contie tobe acceptable at CPU c iti. A geator load rectio test would pride no sgnificant additioal comtion of perft an criteria a. and b. than te routine component testing peromed every cycle, in accordance with the Y PS TS.

Other Plant Systems and Components Response

'The tubin controI*V=k acccleato rea hydraulic f sui re swhs tstvie sta= tahEgmy reiablecl;h we suiteabl~e fo l aspects of '&-qbwdm including mtal requftiens.. Then is no direat ef eatby any CPU changi an these presse switches. Tbese swches a expected tobe equally reliable before and af= CPPU.

Te Reactor Protection System (RPS and Control Rod Dve (CRD) components that convert the scam sigals Into CRD motion are not direcly affected by any CPPU changes. Mir changes prse drops across vessel componmt may result In very slit changes in control blade insertion rates. These changes have been evaluated and determined to be insignificant The ablity to mee the scam pefma requirmentt is not affected by CITU. TS requireme for these components wl Continue to be meSt CPPU Modifications As preiously described, Feedwater System operation will require all three feed pumps at CPPU conditons. Operation of Ihe addional Reacto Feed Pump (REP) will not affct plant response to this transient All feedwate pumps receive a -trip signal prior to lev reaching 177 ;iches.

BW03-80/ Attachmen 7/Page7 Overill of te vessel after a trp would only occur if level exceed approximately 2355 inches.

Smnce the feedwater prnws, the H4 Pressie Coolant hiection (HPC) turbine, and the RCIC tuibine all receive trp signals prior to lel reaching 177 inches, a substantial margin ess.

VYNPS openaing histoiry has demonstrated that this margin greatly exceeds vessel level overshoot during transent cvmts Based on this, there is adequate confidence tbat the vessel level will remain well blow the main stem lines under CPPU conditions. The ,E I and RCIC pump tip funefions ae routinely verified as required by TSs and are considered very reliable.

The modification adding a recirculation pump nmback following a RFP trip will not affect the plant response to this transient. Mm reactor scram signal frm tmubine control valve fast closure will result im cont blade insertion pior to any mnual or automatic operation of the RPs.

Since control Q bades will aready be inserted, a subsequn nback of the recirculai pumps will not affect the plant rePonse The modicaStn (BVY 03-23) 'ARTS/MM A) to add an additional unpiped SSV will not affect fte plant respne to this transient. The new tird SSV will have the same lift setpoint of the two e-isting SSVa. Tbis transient does not result in an opening of a SSV nor is credi t n for SSV actuation HP Tbine modificatio rces the steam flow path but will not affect the turbine control systeg hydraulic pressure switches that provide the tubine control valve fit closure scram signalto tbhe RPS system.

Industry Boiling Water Reactor WR) Power Uprate Experience Southcl aCI Operating CompanWys (SNOC) Application forE U of Hatclh Units 1 and 2 was granted wifhout requirements to perfrm lare tansient testing. VYNPS and Hatch are both BWR/4 with Mark 1 Alhoaugh Hatch was not required to perfoim large transient testing Eaitch Unit 2 experienced an upplanned vwt that resulted in a generator load reject fom 98% ofuprated powerlnthe gum=e of 1999. As noted in SNOC's LER 1999-0, to anmalies Were seen in the plant's response to (his event. In addition, Hatch Unit I has iexeenced cne turbine tLip and one generator load reject event subsequent to its uprate x.c, LE~s 20004004 and 2001-002). Again, the bebavior of theprimary aft sytems was as expected. No mew plant.

- --- bebzviorsi wer vdCtI wad 'dicaz rhar tho nayaiM2aCWc 6afg used arenot capable Ye of modlingplant behavior at EPU condtios. -

The KKL power uprate implementation progam was performed during the penod fronm 1995 to 2000. Power was raised in teps from its prei operating power level of 3138 MWt (Le, 1042% of OLTP) to 3515 MWt (Ie, 116.7% OLTP). Uprate testing was performed at 3327 Mwt (L.e, 1105M% OLTP) in 1998, 3420 MWt (Le., 113.5% OLTP) in 1999 and 3515 MWt in 2000.

KKL testing form ajonents involved turine trips at l10% OLT and 113.5% OLIP and a genrator load rejection test at 104.2% OLTP. The KKL turbine and generator trip testing d taed he percfiman of c gqpmet that was modified in prepratio for the higher powerlvclvs. Equm tbat was not modified perf ed as before. The reactorvesse pressure was controlled at the same operating point for all of the uprated power conditions. No unexpeted performance was obserwvd ecept in the finetuning of the tuxbme bypass opening that was done as the series of tests progressed. Thesc large transient tests at KKEL demonstrated the reponse of the equpme and the reactor response. The close matches observed wfith

.BVY 03-80 / Aftschent 7/PAge B prEdicted response provide additioal confidence that the uprate icensiog analyses consisenty refiected the behavior of the plaz+/-

Plant Modg . Data Conection. and Agabe From the power iprate cece discdssed above, it ca be concluded that lar ft=Liwts either planmed or uuplanied, have not provided any significant ew infoination about transient modeling or actual plan respoas& Sinc the VYNPS %rate does not involve reactor pre r chne s, this eqxpeience is considered applicable.

The safty analyses performed for VYNS used the INRC- ro ODYN fhasent modding codc The NRC acc tsthis codeforEBBWRs witharsngefpowerlevel andpowerdesities that bound the requested power uprate for VYNPS. Ue ODYN code has been benchmaked against BWR test data and has iorponftd idustry cxpedee gaied fim previous fransient modeling codes ODYN uses plant spemic imputs and models all the essentl pyal p om for predicting integrted plant response to the analyzed transients. Thus, tie ODYN code will acratey and/or conservative predict the iintegred plant rpMse t thes transent at CPPUpower levels and no new infoination about trandient modeling is cxpected to be gained ftom pelfaMing these large 1msient tests.

CONCLUSION 0 VYNPS believes that sufficient justification kwa been provided to demonstrate that an. MSIV tnient test and a geneator load rgjection test is not necessary or prudet Also, the risk iqposed by intentionally initiating large tansient testing should not be incred unecessarly.

As such, Enterg does not plan to pefo addiiond larg trandent testing following the VYNPS CP.PU.

4 0

Docket No. 50-271 BVY 03-98 Attachment Vermont Yankee Nuclear Power Station Technical Specification Proposed Change No. 263 Supplement No. 3 Extended Power prate - Updated Information Justification for Exception to Large Transient Testing

BVY 03-98 /Attachment 7 /Page I JUSTIMFCATION 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 (i.e, 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.

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

• Monticello (106% OLTP)

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

• Leibstadt (i.e., KKL) (105% to 117% OLTP)

• Duane Arnold (05% to 120 OLTP)

• Brunswick Units I and 2 (10S% to 120% OLTP)

• Quad Cities Units I and 2 (100% 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 1 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 performance 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 from 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 incurred unnecessarily.

VYNPS Response to Unplanned 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 turbine/generator 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 / Aftachment 7/ Page 2 were seen in the plant's response to this event VYNPS also experienced the following unplanned generator load rejection events:

• On 3/13191 with reactor power at 100% a reactor scram occurred as a result of turbinedgenerator trip on generator load rejection due to a 345KV Switchyard Tie Line Differential Fault. This event was reported to the NRC in LER 91-005, dated 4/12/91.

• On 6/15191 during normal operation with reactor power at 100% 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 7/15191.

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 levels'at operating BWR plants has shown a close correlation ofthe 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 ofthe reload licensing analysis.

MSIV Clasure Event Closure of all MS]Vs 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 representsehe 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 MS1V 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 result The CLTR states that SThe 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 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.

BVY 03-98 / Attachment 7 / Page 3 0

The original MSWV closure test was intended to demonstrate the following

1. Determine reactor transient behavior during andfollowing simultaneousfidl closwe of all MSJ~s.

Criteria:

a) Reactorpressureshall be matainedbelow 1230 pslg.

b) Maimum reactorpre&sure should be 35psi below the first safety valve setpoint.

(i. s is rmarginforsafetyvalve weeping).

2. Functionallycheck the MSIVs for properoperation and determine MSJVclosure time.

Criteria:

a) Closure time between 3 andS seconds Item 1: Reactor Transient Behavior For this event, the closure of the MSIVs cause a vessel pressure increase and an increase in rctivity. The negative reactivity of the scrarn from MSIV position switches should offset the positive reactivity of the pressure increase such that them is a minims increase in heat flux.

Therefore, the thermal performance during the proposed MSIV closure test is much less limiting than any of the transients routinely rc-cvaluate4. CPPU will r 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. MSIV 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 I above, is largely dependent on SRV setpoint performance. At VYNPS all four SKY: are replaced with refurbished and pre-tested valves each outage. After the outage, the removed valves are sent out for testing and recalibration for installation 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-wound setang ouaside IMe TecM ical Speccarion CMTcurt allowabe tolerance of z3%. ihis valve was found to deviate by 3.4% of its nominal 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 all (one SRV out of service). Given the historical performance of the VYNPS SRVs along with the design margins, performance of an actual MSIV 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 0

Item 2: MSIV Closure Time Since steam flow assists MSIV closure, the focus of Item 2 was to verify that the steam flow from the reactor was not shut off faster than assumed (Le., 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 MS1V 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 determmined 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 Components Response The MSIV limit switches that provide the scram signal are highly reliable devices that are suitable for all aspects of this application including envirownental 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 (TS) 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 plntr respc au MiV

-o E trset.

s Alterd um < ip-signalrior 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 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 fimctions 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 o3-9 / Attachment 7 /Page S The modification (BVY 03-23 "ARTSMELILA") 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 eisting 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 1) 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: flhe 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 current plant design, the original generator load reject test can not be re-performed. If a generator load reject with bypass test wer 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 aTention to the rates of changes andpeak values of power kvelv reactorsteam pressure and turbinespeea' Criteria:

a. All test pressure transientsmust have maximum pressure values below 1230 psig

b. Maximum reactor pressure should be 35 psi below the first safety valve setpont. (Alis is marginfor sofey valve weeping).

c. The select rod insertfeature shall operate and in conjunction with proper bypass valve openung, shall control the transientsuch that the reactordoes 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 (ICfVs) 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 CPP`U 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 (BPS) 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 MSIV 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 awe suitable tor all aspects of tBis appncanon 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) 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. 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 (RFP) 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 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 sam 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 already be inserted, a subsequent runback of the recirculation pumps will not affect the plant response.

The ARTSMELLLA 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 1 and 2 was granted without requirements to perform large transient testing. VYNPS and Hatch are both BWRI4 with Mark 1 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 9sv. of uprared power In he usummer of 1999. As outed ini SN3V'. L R 1999-00;, no anomali 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 of modeling 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.e.,

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.

KL 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 / Attacluent 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 Modeling. 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 perfonned 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.

5 CORRECTED NICHOLS EXHIBIT 5 I I

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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 planned 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 lIl.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 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 IIL.A and III.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;

• margin reduction in safety analysis results for A0Os;

• guidance contained in vendor topical reports; and

• risk implications.

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The NRC staff reviewed the licensee's justification, in Attachment 2 of Reference 20, for not reperforming 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 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 reperformed 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 EPU.

• STP-13. Process ComDuter. The test is not required to be re-performed since operation of the process computer is not affected by 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.

• STP-21, Response to Control Rod Motion. The test is not required to be re-performed since operation at EPU 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.

• STP-25, Main Steam Isolation Valves (MSIVs). In accordance 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 is that the initial startup test involving simultaneous

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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 Trio, and STP-28, Generator Trio. 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 staff's review of the licensee's justification follows.

• 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 in the 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 1 and 2, was granted an EPU by the NRC without the requirement to perform large transient testing and that the VYNPS and Hatch are both BWRI4 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 Southern Nuclear Operating Company's licensee event report (LER) 1999-005, no anomalies were seen in the plant's response to this event. In

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addition, Hatch Unit I has experienced a turbine trip and a generator load reject event subsequent to its uprpte, 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 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, 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%

power. 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 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.

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.

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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 staff's review of this issue and the need for a license condition is discussed in SE Section 2.5.4.4.

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 adequately addressed factors which included previous industry operating experience at recently uprated BWRs, plant response to actual turbine and generator trip tests for the KKL plant, 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. 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.

SRP 14.2.1 Section III.D Evaluate the Adequacy of Proposed Transient Testing Plans SRP 14.2.1 Section III.D, specifies the guidance and acceptance criteria the licensee should use to include plans for the initial approach to the increased EPU power level and testing that should be used to verify that the reactor plant operates within the values of EPU design parameters. The test plan should assure that the test objectives, test methods, and the acceptance criteria are acceptable and consistent with the design basis for the facility. The

6 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 to reduce reactor pressure.

Pressure 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-RO03A, 2S32-RO03B, 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-FO13H; 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 cooldywn 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 theibottom 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 (EIS 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 heacier 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 ths 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 we ding the thin sheet metal. Additionally, portions of the rail also broke 1 ose from the side of the duct at or near the weld points. Visual examina ion revealed these points likewise had experienced metal burn-out. Althou h the gage thickness of the turning vanes was in agreement with th Duct Contraction Standard of the Sheet Metal and Air-Conditioning Contra tor National Association, the manufacturer should have used thicker heet metal since welding was used to secure the vanes and rails. Moreov r, 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, tle 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) beca se of the unplanned actuation of Engineered Safety Feature systems. The reactor protection system, an Engineered Safety Feature system, actuated on turbine control

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 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

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

Lewis Sumner Southern Nuclear Ar) Presiddnt Operating Company, Inc.

Hatch Priect Support 40 Inverness Parkway Post Off ice Bco1295 Birmingham, Alabama 35201 Tel 205.992.7279 Fax 205.9920341 U SOUTHERNt COMPANY EnerVy to Serve Your Worlde February 14, 2002 Docket No. 50-366 HL-6184 U.S. Nuclear Regulatory Commission ATTN: Document Control Desk Washington, D.C. 20555 Edwin 1. 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(a)(2XivXA), 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 flux.

Respectfully submitted, H. L. Sumner, Jr.

CLT/eb

Enclosure:

LER 50-36612001-003 cc: Southern Nuclear Operating Company Mr. P. H. Wells, Nuclear Plant General Manager SNC Document Management (R-Type A02.001)

U.S. Nuclear Regulator= Commission. Washington. D.C.

Mr. L. N. Olshan, Project Manager - Hatch U.S. Nuclear Regulatory Commission. Region 11 Mr. L. A. Reyes, Regional Administrator Mr. J. T. Munday, Senior Resident Inspector - Hatch Institute of Nuclear Power Operations LEREventstinpo.org makucinjm~inpo.org 4J$)

INRC FORM 366 U.S. NUCLEAR REGULATORY COMMISSION APPROVED BY OMS NO.315040104 EXPIRES 713112004

('-200 1) Estimated burden per response to comply with this mandatory information collection request: 50 hrs. Reported lessons learned are incorporated into the LICENSEE EVENT REPORT EVEN REPRT(ER)licensing (LER) process and fed back to tndustry. Send comments regarding burden estimate to the Records Management Branch (T-6 ES). U.S. Nuclear Regulatory Commission. Washington, DC 205550001. or by Internet e-mail to (Sae reverse for ralirrd mbti of tblsl(%@ngov, and to the Desk Officer. Offite of Information and Regulatory dgits/cactrs for eah block) Affairs, NEOB-10202 (31804104) Office of Management and Budget Vfingtcon CC 2aM 1 a mrs used to haposeIrfaition cledtion does not display a aurrdy vlid OM crnsh nustr. the NRC my no crnduc or Vas e a personis rmredre nto to r-sxil to. Ole hirfne, acolilection 1i.FACIUlTY NAME nDOCKET . NUMBER 3.PAGE Edwin I. Hatch Nuclear Plant

• Unit 2 05000-366 1 OF4 4.Tm.!

Sudden Closure o Main Steam Line Isolation Valve Causes Pressure Increase and Reactor Scram on APRM High Flux.

5. EVENT DATE C LER NUMBER 7. REPORT IATE S. OTHER FACILIMES INVOLVED ONT MOT DAY YEA IA ER cyE YA WJWE WI-NA ' M ONHDY rMOA YA CAYCITYNAME TNUJMiBER(S) 05000 12 25 2001 2001 003 0 02 14 2002 FACIYME l TNUMR(S) l9.OPERATING 11. THIS REPORT IS SUBMI'lED PURSUANT1O THE REQUIREMENTS OF 1 CFR S: (Cheek all that apply) lMODE 21(b)2 I2 aX3XD) I 0.7X8X2XIXB) _0.73(aX2XixXA) 10- POWER I 20 2201(da4) - 2073(aXX2XI) 50.73(aX2xx)

LEVEL 100 I2203M(X1) 50X36(cX1XIXA) X 50.73(aX2XivXA) 73.71(__4_

I._20(aX2XI) - 50 3 i(cXIXIXA) = 5O.73T(X2XvXA) =_T3.T__(__)

_ 202aX2X1) = 50.36(cX2) 50.7X(aX2XvXB) OTHER 2O%?203(aX2Xli1) SEO.48(U3XII) 50.73(aX2XvXC) Specify InAbstract below 202z03(aX2Xv) 5o.73(aX2)OXA) =50.73(X2XvXD) hlor NRC Form 36MA

__20220XX2X_ ) _ 57.3(aX2XiXB) 5O.73(aX2Xv1) 20.2203(aX2XVI) _ 0.73(aX2)(IXC) 50.73(aX2XvI1IXA) 20R0.3(XXI3 XA) -50.73(a.01! I -B

[~~4 _ b 5 OIxIFRlFNOMTAI;T FflP T541 _ P COMPLETE ONE LINE Steven B. Tipps, Nuclear Safety and Compliance Manager, Hatch l13. FOR EACH COMPOEN IEHI D

MYMAEDEC l(912)

EPORT 367-785 1 CAUSE SYSTEM COMPONENT I MANUFACTUER CAUSE SYSTEM CO MFONENT MANUFACTURER PABLE

14. SUPPLEMENTAL REPORT EXPECT 15. EXPECTED MONTH D EAR I YES (If yes, complete EXPECTED SUBMISSION DATE) 16 Atb I HAGI (LimIt to 4e spaces1 l4UU approximately ISUB INl 1t Ei9e-spaced typewritten ulnn WMISSION DATE l

IX l I On 12MI001 at 18 19 EST, Unit 2 was in the Run mode. At that time, the reactor scrammed 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 2B21 -F028B. 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 from 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-FO28B failed completely, causing the valve to close and reactor vessel pressure to increase. Corrective actions include replacing the stem and determinin the feasibility and cost of options to reduce or eliminate stem vibration.

NRC FORM 366A (1I0011

NRC FORM 366A

• U.S. NUCLEAR REGULATORY COMMISSION UCENSEE EVENT REPORT (LER)

TEXT CONTINUATION FACILITY NAME (1) DOCKET LER NUMBER 6) PAG 3 WR QUETIAl REI N . )

Edwin I. Hatch NuclaPkMA- Unit 2 05000-366 2001 - 00 2 OF4 TEXT (If moM space is ,wquied, use additonal copies ofNRC Form 366A ( 7)

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 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, EIIS 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) 2B2 1-F028B. The closure of the main steam line isolation valve isolated one of the 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 scram, 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 (EIIS Code JM).

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 03-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 KmC Fonn 366A j1<2S01)

NRC FORM 366A - U.S. NUCLEAR REGULATORY COMMISSION IO-WN LICENSEE EVENT REPORT (LER)

TEXT CONTINUATION FACILITY NAME (1) DOCKET LER NUMBER (6) PAGE (3) l YEI REYVSON 1

Edwin I. Hatch Nuclear Plant - Unit 2 05000-366 2001 - 003 - 00 3 OF 4 TEXT mm spaw a xqAD4 m aW wpm of ARC F} 78) 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 232 1-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 (EIIS 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.

NK(CForm 366A (I2001)

NRC FORM 366A -- U.S. NUCLEAR REGULATORY COMMISSION I -200D LICENSEE EVENT REPORT (LER)

TEXT CONTINUATION Edwin I. Hatch Nuclear Plant

• Unit 2 rEXT (If more space is required, use additionalcopies of NRC I

FOm 366AJ) (17) 05000-366 I

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 EIIS 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 8/412000 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 Fomin 36A Wl20011

8 Lewis Sumner Southern Nuclear Vice President Operating Company, Inc.

Hatch Project Support 40dinvuess Parkway Post office Box 1295 Birnmngham, Alabama 35201 Tel Zi15S92279 Fix 205.992.0341 SOUTHERN N.

COMPANY ED ytoSerwrY#=We 0 August 4, 2000 Doxkct Na 50-321 HL-5967 US. Nxile Reutory Cam issicn ATFN Document Control Desk Washington, D.C. 20555 Edwin l. Hatch Nuclear Plant - Unit I Licensee Event Report Component Failure Causes Turbine Trip and Reactor Scram Ladies and Gentlemen:

In accordance with the Buirerans of 10 CFR 50.73(aX2Xiv), Southern Nuclear Operating Company is submitting the enclosed Licensee Event Report (LER) concerning a component failure which resulted in a turbine trip and reactor scram.

H. L. Stunner, Jr.

OCV/eb

Enclosure:

LER 50-321/2000-004 cc: Southern Nuclear Operating Companv Mr. P. H. Wells, Nuclear Plant General Manager SNC Document Management (R-Type A02.001)

US. Nuclear Regulatory Commission. Washington D.C.

Mr. L. N. 0lshan, Project Manager - Hatch U.S. Nuclear Regulatory Commission. Ecri It 1*. L A Rqeys, Regicnal Ahrfii h M*. J. T. Miray, Senior Residert ispector - Hatch

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TO EPI I Cr WA TUSTECWSTE COMPONENT~ llANFACRIRER l F 1 rar X lTA l VT lG080 l. Yesvl lll REPORT L1(PuETEO (4) I EXPECTED IwVEARIoa LI NO SUBU=ON Qt*s l EXPECTED SU SON DATE)A 11t) 3ISTHCTIbitt o 1400 4aca. La. 16ratel 15 Gint*wac tyPah utl " 1iii On 07/10/2000 at 1050 EDT, Unit 1 was in the Run mode at a power level of 2754 CMWr (99.7 percent rated thermal power). At that time, the reactor scrammed and the reactor recirculation pumps tripped automatically on turbile stop valve fast closure caused by a turbine trip. The turbine tripped when the vibration instrument on the #10 bearing failed causing a false high vibration trip 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 pumps mairtined water level higher than seventeen inches above instrument zero. Co(bqetly, 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 actuation setpoints for the remaining two ssf*y/relief valvs The tBr n in te vesl bottom head region decreased by more than the Technical Specification allowed lwF in one hour before a recirculation pump could be re-started.

This event was caused by component failure. The vibration instn on the #10 bearing failed, generating a false high vibration signal. The high vibration sgd caused the main turbine to trip, producing a reactor scram on turbine stop valve fast closure per design. The failed vibration instrument was replaced. The vibration instruments on the remaining bearings were checked resulting in the replacement of the shaft rider probe on the #6 bearing No'other instnmnent problems were found.

NRC FORM seeCl-hIl

N=RC FORM 305A U.S. IUCLEAR REGULATORY COMMSSION LICENSEE EVENT REPORT (LER)

TEXTCONTiNUATION FAIRY JAME 11) DOCKEL PUMER 166 FACE A)

VM ISEVEMMN Mm Edwin I. Hatch Nuclear Plant

• Unit I 05000-321 2000 - 004 -

• 2 OF6 V cMe AwOe U111 PLANT AND SYSTEM IDENTIFICATION General Electric - Boiling Water Reactor Energy Industry Identification System codes appear in the text as (EIIS Code XX).

PESCREMlTON OF EVEWT ...

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 scramm ed and the reactor recirculation pumps (EIS Code AD) automatically tripped on turbine stop valve (EIIS Code TA) fast closure caused by amrain turbine (EIIS Code TA) trip. The main turbine tripped when the vibration instrument on the #10 bearing, the main generator exciter (HIS Code TB) 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 (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 S) 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, inchlding emergency core cooling system, actuations on low water buI were received nor were any required.

Vessel pressure reached a maximum value of 1128 psig 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/reliefvalves IB21-FO13E and IB21-FO13J; therefore, they did not actuate nor were they required to actuate. (Although safety/relief valve IB21-FO13B 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 fumctioed 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 nonnal to its alternate supply as expected when the main turbine tripped. Operations personnel manually energized the bus, which provides power to the lB 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 1800F in one hour. Unit I Technical Specification Limiting Condition for Operation 3.4.9 limits the reactor coolant system cooldown rate to a maximum of lO(YF in one hour.

FOmSU" p64ss96 iiRC

ARC FORM 385A U.S. NUCLEAR fEEULATORY COUMMSS101 MIMM LICENSEE EVENT REPORT (LER)

TEXT CONTINUATION Edwin Io Hatch Nuclear Plant . Unit I 05000-321 200 - 004 - 00 3 6 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 100¶F per hour limit CAUSE OF EVENT This event was caused by component failure. The vibration instrunment 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 generated. 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 1B 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 first test of the normal 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 (aX2X 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-low set mode until pressure decreased to their respective closure setpoints.

Fast closure of the tUn stop ves is imitated the min tubi 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 stn flow that, intumn resilts in a rcor esd prssue ina If the pressure increases to the pressure FCFarmSGA 14-38

NRC FOM A UMSNUCLEAR REGULTORY COMMSSION LICENSEE EVENT REPORT (LER)

TEXT CONTINUATION FACIUiT NIARM £) DOCKET UR UWMMER (a) PC 3

~UA amqo EdwinEul& .qJs hNI~sear Plnt- Unite1I m 85541 an? OS00D-321 2000 -U04O 4 OF 6i relief setpoints, some or all of the safety/reliefvalves will briefly discharge steam to the suppression pool (EIIS 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 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 turbiie 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 purnps. 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 18(0F 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.

-a- .c.

ER maA-

.gB ram

INRC FORM 3 U.S. NUCLEAR REGULATORY COMMISSION LICENSEE EVENT REPORT (LER)

TEXT CONTINUATION FACILITY NAME 11) DOCKCET ER KLWER 40) FACE 13)

_I wQUT REVO Edwin Hatch Nuclear Plant- Unit 1 05000-321 2000 - 004 - *S OF 6 CORRECTIVE ACTIONS The vibration instrument for the #10 bearing was replaced on 7/12000 per Maintenance Work Order 1 02145. Additionally, the rernaining vibration instruments were checked on 7/12/2000 per Maintenance Work Order 1-00-02159. As a result of this inspection, the dft rider probe of the vibration instrument for the #6 bearing was replaced. No problems were found with any of the other bearing vibration instruments.

The high bearing vibration trip from the #9 and #10 bearings, with the concurrence of the turbine vendor, has been temporarily disabled. The final disposition of the main turbine high bearing vibration trips will be determined through the corrective action program.

Personnel assessed the eftecs 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 397.70 F per hour were acceptable provided certain bounding conditions were met General Electric and Southem 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 7/1212000 per Maintenance Work Order 1-99-04564. A fast transfer functional test of the newly installed normal supply breaker was completed successfully.

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: IN3 1-N892 EIIS System Code: TA Manufacturer: General Electric Reportable to EPIC: Yes Model Number. 3S7700VB0IAI Root Cause Code: X Type: Vibration Transmitter EIIS Component Code: VT Manufacturer Code: G080 NRKaFt 06 MIN

NRC F 368A U.S NUCLEAR REGULATORY COwMSSION I19 UCENSEE EVENT REPORT (LER)

TEXT CONTINUATION EdwinL Hatc Nucear Mt -Unit I W= Awe *br- At aw zimzu eptsd AC Frn 36U W 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 6I/1999 50-321O0.02 dated 2/25/2000 5D-366/1999-005 dated 5/27/1999 5D-361999-07 dated 7/27/1999 Corrective 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 instrument failure. Indeed, only one of the previous four events was caused by a main turbine trip. In that event, reported in Licensee Event Report 50-3661999-005, the main turbiie tripped when the main generator tripped on an adlch ground fault Therefore, any corrective actions taken for the previous events would not have addressed turbiie bearing vibration instruments.

WWR FoIU IG6Aq-1JMj

, . I, I...,..

Lewis Sumner Southern Nuclear Vice President Operaing Company, Inc.

Hatch Project Support 40 Inverness Parkway Post Office Box 1295 Birmingham, Alabama 35201 Tel 20599Z7279 Fax ~2mno3 SOUTHERA COMPANY Energy to Serve YbarWorld' May 21, 2001 Docket No. 50-321 HL-6088 U.S. Nuclear Regulatory Commission AITN: Document Control Desk Washington, D.C. 20555 Edwin 1. Hatch Nuclear Plant - Unit I Licensee Event Report Component Failure Causes Turbine Trip and Reactor Scram Ladies and Gentlemen:

In accordance with the requirements of 10 CFR 50.73(a)(2)(ivXA), 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.

DMC/eb

Enclosure:

LER 50-321/2001-002 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. 0lshan, Project Manager - Hatch U.S. Nuclear Regulatory Commission. Region 11 Mr. L. A. Reyes, Regional Administrator Mr. J. T. Munday, Senior Resident Inspector - Hatch Institute of Nuclear Power Operations LEREventseinpo.org AitkenSY~Inpo.org

4RC FORM 366 U.S. NUCLEAR REGULATORY COMMISSION APPROVED BY OMB NO. 315O-0104 EXPIRES 06130/2001 1-2001) Estimated burden per response to comply with this mandatory bIformatior collection request: 50 hrs. Reported lessons learned are Incorporated into th.

LICENSEE EVENT REPORT (LER) licensing process and led back to hIdustry. Send comments regarding burdet estimate to the Records Management Branch (T-6 Es), U.S. Nudela Regulatory Commission. WashIngton. 00 20555-0001. or by internet e-mail b (See reverse for required number of blsl(Onrc.gov, and to the Desk Officer, Office of Information and Regulator digits/characters for each block) Atfairs, NEOS-10202 (3150-0104). Office of Management and Budget Washington. DC 20503. If a means used to impose information collection doe:

not display a currently valid OMB control number, the NRC may not conduct a somrisor. and a nerson Isnotrequired to reseond to. the Inlonnatlon collection FACLUTY NAME (1) DOCKET NUMBER (2) PAGE (3)

Edwin 1.Hatch Nuclear Plant - Unit 1 05000-321 1 OF4 TITLE (4)

Component Failure Causes Turbine Trip and Reactor Scram EVE NfT DATE *5) NUMBER 6 REPORIT D OTHER FACILMES INVOLVED (8) lONTH 1

40NOUIYEAR DAY 0 YEAR LER Tl sA l R R F MOM 1O DAY I7 YEAR FACILITY NAME DCIET NUMBER(S) 05000 03 lOPER A 1 2001 2001 002 T_ IS REPORT IS SUBM T 00 05 21 2001 l V-RSUATTOTHE REQUI EMNTS OF 10 CFR §: (Checkonor more)(111 NUMBE05000 MODE (9) 20.221(b) I 20223aX3XI) I50.73(aX2)(i)(B) 50.73(a)(2)(ix)(A)

POWER 20.2201(d) _ 20203(aX4) 50.73(a)(2)(l0) 50.73(a)(2)(x)

UVEL (t10) 100 _ 20.2203(a)(1) _ 50316(c)(1X1)(A) 2 50.73(a)(2)(iv)(A) _73_._711_(_a_)_(_4_)

.- i ' t _ 20.2203(a)(2X1) = UL16(cXl1)fi)(A) 50.73(a)(2)(v)(A) =_73.71(a)(5) 20-2203(aX2)(ii) = 50.36(cX2) 50.73(a)(2)(v)(B) OTHER 20-2203(aX2)(i-u) 50.46(aX3)(fi) 50.73(a)(2)(v)(C) Specify InAbstract below 20.22m3(aX2)(iv) = 50.73(aX2)(1)(A) 50.73(a)(2)(vXD) or h NRC Fom 366A

• 20.2203(a)(2)(v) I60.73(a)(2X1)(B) 50.73(a)(2Xvi) 20.2=5a)(2)(vl) i50.73(a)(2)1)(C) _ 50. a2 i 20.223()_X -50.73(a)(2Wpi)(A) 50.73(a)(2 villIB LICENSEE CONTACT FOR TIHS LER (12)

S vNAeE NHELEPHONE NUMBER (Include Area Code)

Steven B. Tipps, Nuclear Safety and Compliance Manager, Hatch (912) 367-7851 COMPLEE ONE LINE FOR EACH COMPONENT FAILURE DESCRIBEDIN THIS REPORT 13_

CASE SYTEOCMPNETBLE A~uRCAUSE SYSTEM COMPONENT MANUFACTURER RPRAL CAUS SYSEM TO PIXTo OMPOENT MANUACR EPIX X EA XFMR G080 Yes

-&PPLEMENTAL SU_ REPORT EXPECTED (I)I EXPECTED IMOM DAY EA YES l I NO SUBMISSION (If yes, complete EXPECTED SUBMISSION DATE) X DATE (15)

ABSTRACT (Umit to 1400 spaces, Le., approximately 15 single-space typewritten lnes) (1I)

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 containment 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 IE 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 C1w2001)

LICENSEE EVENT REPORT (LER)

TEXT CONTINUATION FACIUTY NAME (1) DOCKET LER NUMBER (6) PAGE 3)

_fEAR lSEQUENTAL REVISION l EAR NUMBER Edwin 1. Hatch Nuclear Plant - Unit 1 05000-321 2001 - 002 -- 00 2 OF 4 EXT (If more space isrequired, use additionalcopies of NRC Form 366A) (17)

PLANT AND SYSTEM IDENTIFICATION General Electric - Boiling Water Reactor Energy Industry Identification System codes appear in the text as (EUS Code XX).

DESCRIPTION OF EVENT On 03/28/2001 at 1853 EST, Unit 1 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 87TIBX. 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 5 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-F013B 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 turn-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 Form, 3OBA(1.2001)

NRC FORM 366A U.S. NUCLEAR REGULATORY COMMISSION 1-2001)

LICENSEE EVENT REPORT (LER)

TEXT CONTINUATION FACILITY NAME 1 DOCKET LER NUMBER (6) PAGE (3)

YEAR SEQUENTAL REVISION YEYAR NUMBER EdmdnI. Hal& Ntai1farLlnrt- Uit i 05000-321 l2001 - 002 00 3 OF 4 EXT (if more space Is required, use addiional copies ofNRC Fon& 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 IB. 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 IB. 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, EUS 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.

IRC Form 366A (1.2001)

4RC FORM 366A U.S. NUCLEAR REGULATORY COMMISSION I-n2o0)

LICENSEE EVENT REPORT (LER)

TEXT CONTINUATION FACILITY NAME 1 DOCKET LER NUMBER (6) PAGE (3)

I sEourE AL I IREVSION Edwin 1. Hatch Nuclear Plant - Unit 1 05000-321 YEAR I I YEAR 2001 00 I NUMBER 4 OF 4 EXT (if more space is required use additional copies of NRC Fon" 3684) (17)

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 6/1/1999 50-321/2000-002, dated 2/25/2000 50-32 1/2000-004, dated 8/4/2000 50-366/1999-005, dated 5/27/1999 50-366/1999-007, dated 7127/1999 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 transformer 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 8/30/1984). 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.

1CForn 366A (1.2001)

10 aProgress Energy January 5, 2004 SERIAL: BSEP03-0158 10 CFR 50.73 U. S. Nuclear Regulatory Commission ATTN: Document Control Desk Washington, DC 20555-0001

Subject:

Brunswick Steam Electric Plant, Unit No. 2 Docket No. 50-324lLicense 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 Carolinas. Inc-BOrwsick Nuclear Mra Box 10429 P.O.

SouorL NC29451

Document Control Desk BSEP03-0158 IPage 2 cc (with enclosure):

U. S. Nuclear Regulatory Commission, Region II ATI-N: 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 ATTN: Mr. Eugene M. DiPaolo, NRC Senior Resident Inspector 8470 River Road Southport, NC 28461-8869 U. S. Nuclear Regulatory Commission ATIN: Ms. Brenda L. Mozafari (Mail Stop OWFN 8G9) (Electronic Copy Only) 11555 Rockville Pike Rockville, MD 20852-2738 U. S. Nuclear Regulatory Commission A1TN: Ms. Margaret Chernoff (Mail Stop OWN 8G9A) (Electronic Copy Only) 11555 Rockville Pike Rockville, MD 20852-2738 Ms. Jo A. Sanford Chair - North Carolina Utilities Commission P.O. Box 29510 Raleigh, NC 27626-051

.1 NRC FORM 366 U.S. NUCLEAR REGULATORY APPROVED BY OMB NO. 3150-0104 EXPIRES 7-31.2004 COMMISSION A~mod bard pw p Cow) ,tt t 'rM2UIY Wr=nuan vQW LICENSEE EVENT REPORT (LER)

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1. FACIUTY NAME 2. DOCKET NUMBER 3. PAGE Brunswick Steam Electric Plant (BSEP), Unit 2 05000324 1 OF 6 4.TLE Loss of Generator Excitation Results in Reactor Protection System and Other Specified System Actuations

5. EVENT DATE S. LER NUMBER 7. REPORT DATE S.OTHER FACILITIES INVOLVED MO DAY YEAR YEARl EQUENTAL l REV MO DAY YEAR FAO.LTYAME _ DOCKETNUMaER NUMBER NO BSEP, Unit 1 05000325

_1 04 2003 2003 - 004- 00 01 05 2004 Fa050NM00

9. OPERATING 11.THIS REPORT IS SUBM TTEDPURSUANT TOTHE REOUIREMENTS OP 10CFR i Jhedone or ore)

MODE I _ 220=1b) j202203(a)(3)()

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12.LICENSEE CONTACT FOR THIS LER NAME tPLephONe NUMItHI (Include Area Lode)

Charles R. Elberfeld, Leas (910) 457-2136 I

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 I 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.

NRr FORM =0GV-20011

I NRC FORM 366A US. NUCLEAR REGULATORY COMMISSION (14001)

LICENSEE EVENT REPORT (LER)

FACIUTY NAME (1) DOCKET (2) LER NUMBER (6) PAGE (3)

_ YEAR I SEOUENTI IREVISION Brunswick Steam Electric Plant (BSEP), Unit 2 05000324 I NUMBER NUMBER 2 OF 6

_2003 - 004 - OD NARRATIVE (itmore space is required. use additional copies of NRC Fo= 36684) (17)

Energy Industry Identification System (EIIS) 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 [IL], 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 1, (i.e., Run) at approximately 96 percent of rated thermal power (RTP) and Unit 1 was in Mode I 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., Alterrex 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 FORM 366A (I4001)

NRC FORMs66A U.S. NUCLEAR REGULATORYCOMMJSSION (14001)

LICENSEE EVENT REPORT (LER)

FACILTY NAME (S) DOCKET (2) LER NUMBER (6) PAGE (3)

YEAR SEOUENTIAL REVISION Brunswick Steam Electric Plant (BSEP), Unit 2 05000324 2003 ONUMBR3OF6 2003 -0 4- 00 NARRATIVE (imors space lsfquIrect useaaditionalcopies oNRCForm 66.4) (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 II 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.

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 controlled using the Control Rod Drive [AA] 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 1 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 (ie., Cold Shutdown).

Plant Responses to Voltage 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 1 and 2, to initiate a logic signal resulting in isolation of the Reactor Building Ventilation [VA] Systems, automatic starting of the Standby Gas Treatment (SGT) Systems [BH1], 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.

NRC FORM 366A (12001)

NRC FORM 366A US. NUCLEAR REGULATORY COMMISSION LICENSEE EVENT REPORT (LER)

FACIUTY NAME (1) DOCKET (2) LER NUMBER (6) PAGE (3)

.YEAR SEQUENTIAL REVISION Brunswick Steam Electric Plant (BSEP), Unit 2 05000324 I BE UME 4OF 6

_2003 004- 00 NARRATIVE (itmore space Is required, use addilfonalcopies ofNC Fom 36) (17)

EVENT DESCRIPTION (continued)

Plant Responses to Voltage Transient (continued)

On November4, 2003, at approximately 1812 hours0.021 days <br />0.503 hours <br />0.003 weeks <br />6.89466e-4 months <br />, the Unit 1 ReactorBuilding 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 EDGs 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.

NACFORU365A(t-200I)

I I NRC FORM 366A U.S. NUCLEAR REGULATORY COMMISSION LICENSEE EVENT REPORT (LER)

FACILITY NAME (1) DOCKET (2) LER NUMBER (6) PAGE (3)

YEAR 6ECUENTIAL REVION Brunswick Steam Electric Plant (BSEP), Unit 2 05000324 NUMER5NUMBER OF6 2003 -004 - 00 NARRATIVE (I more space Is requred,use addigonal coples ofNRCFonn 966A) (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 otherbrush applications on site are also being considered.

• Enhanced exciter brush monitoring has been implemented on both Units i and 2. Unit 1 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, this event 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 3S6A (I4001)

NRC FORM 366A U.S. NUCLEAR REGULATORY COMMISSION LICENSEE EVENT REPORT (LER)

FACILITY NAME (1) DOCKET (2) LER NUMBER (6) PAGE (3)

YEAR SEOUENTIAL REVISION Bnunswick Steam Electric Plant (BSEP), Unit 2 05000324 INUMBER INUMBER 6 OF 6 2003 004 -00 NARRATIVE (1imore space Is requed,use additinal Copies at NRC Fonm 384) (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.

NRC FONRI 2A3=14001)

Exelon Generation www.exeloncorptorn Exekbn. Nuclear Dresden Generating Station 6S00 North Dresden Road Morris. IL60450-9765 10 CFR 50.73 Tel 815-942-2920 1 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, KUnit 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)(lv)(A), 'Any event or condition that resulted in manual or automatic actuation of any of the systems listed in paragraph (a)(2)(iv)XB) of this section.-

• Should you have any questions concerning this report, please contact Jeff Hansen, Regulatory Assurance Manager, at (815) 416-2800.

Respectfully, DannyG Yost Site Vice President Dresden 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. 31500104 EXP 7.31.2004 COMMISSION

.Eslaed burden per respmnse lo mply ti rmandatory WormaSon colhecion request 501h Reponled lessons barned ar t porated idie Icensing process and fed back loIrdustry. Send cornrents regardog burden estmate to tie Records Maagemtent Branch Cr-LICENSEE EVENT REPORT (LER) 6E6U. Nucsar R t Waskgtcn, DC 2055501 or by 8Inteet te Officr, Office Ifounaton and Regui Hairs UE0t~z2 315010),Offcs l antemetand Budet Waffilgton, D 2050. Hai meansa used to pose Wounabon cotecon does not dIsay a currently varid OMB conblr er, e NRC rnayanoteonduct ersposor, and a person rot requhd I respond to. the

1. FACILITY NAME 2. DOCKET NUMBER 3. PAGE Dresden Nuclear Power Station Unit 3 05000249 1 of 4 4.nTILE Unit 3 Automatic Scram During Testing of the Main Turbine Master Trip Solenold Valves

. EVENT DATE 6. LER NUMBER 7. REPORT DATE 3. OTHER FACIUITIES INVOLVED FACILITY NAME DOCKET NUMBER MO DAY YEAR YEAR I SEOUENTML RE-V O DAY lER NIA NIA O FACILITY NAME DOCKET NUMBER 01 24 2004 2004 -001 -00 03 24 2004 N/A N/A

9. OPERATING 11 THIS REPORT IS SUBMTED PURSUANTTO THE RECUIREMENTS OF I CFR I: (Check aln thatSp)

MODE 2022DI(b) _ 2022=31aX3X1) _ 60.73(aX2)(0XiB) - 50.73(aX2)(2xA)

10. POWER _ 20.2201(d) _ 20.22D3Ia)(4) _ 50.73(aN)(02) _ 50.73Sa)X2Wx)

LEVEL 096 _ 20.2203(aN1) _ 50.36(c)(1XIA) X 50.73(a)(2)(Wv)A) _ 73.71(ea4) 20.2203(a2)(I) _ 50.36(cXXi)(IA) _ 50.73(aX2XvWA) = 73.71(aX5)

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12. LICENSEE CONTACT FOR THIS LER NAME TEIEPHONE NUMBER (Include Area Code)

George Papanic Jr. I (815)416-2815

13. COMPLETE ONE LINE FOR EACH COMPONENT FAILURE DESCRIBED IN THIS REPORT CAUSE SYSTEM ICOM t I BTMAG GPOBOE SOL FACTURER TO EPX

C SYSTEMU JUAT 7 m FACER REPORAIE TO EPOX B TG SOL IG080 Y .7P- MOT DAY-

14. SUPPLEMENTAL REPORT EXPECTED 15. TED YEAR YES (If yes, complete EXPECTED SUBMISSION DATE) X NO DATE

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16. ABSTRACT (Unitto 1400 spaces. Le.. appromxlnately 15 zte-spaced t4pewrten Ines)

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, *Periodic Main Turbine, EHC and Generator Tests. The event was caused bya malfunction of the Main Turbine Master Trip Solenold Valves, which resulted Inthe depressurizatlon 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 minimal. 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 UCENSEE EVENT REPORT (LER)

1. FACILITY NAME l . DOCKET NUMBER 6. LER NUMBER 3. PAGE YEAR SEQUENTIAL I REVISION Dresden Nuclear Power Station Unit 3 05000249 NUMBER NUMBER

.. 2004 001 00 2 of4

17. NARRATIVE (Iftnme space Is requIred, use addl~onal coples 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 Inthe text are Identified as A. Plant Conditions Prior to Event:

Unit: 03 Event Date: 01-24-2004 Event lime: 0037 CST Reactor Mode: I Mode Name: Power Operation Power Level: 96 percent Reactor-Coolant System Pressure: 1000 psig B. Description 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 usilting phenomenon. General Electric (GE), the Original Equipment Manufacturer, was-requested to evaluate the 0siting' 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 existing spool solenoid MTSVs. GE Indicated that, unlike the spool valve, a poppet valve Isnot 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.

InSeptember 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 Itto 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 with 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, Periodic Main Turbine, EHC and Generator Tests,- MTSV A failed to trip. The cause of this MTSV failure to trip was determined to be sllting.* 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 (74201)

LICENSEE EVENT REPORT (LER)

1. FACILITY NAME 2. DOCKET NUMBER 6. LER NUMBER 3. PAGE I I YEAR REVISION Dresden Nuclear Power Station Unit 3 05000249 2 NUMBER NUMER 2004 001 00 30f4

17. NARRATIVE (It mnore space Is equIred, use additional copies of NRC Form 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 weely 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 Inaccordance 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 Inparagraph (a)(2)(iv)(B) of this section." The automatic actuation of the reactor protection system Is listed In 10 CFR 50.73(a)(2)(iv)(B).

Dresden UnIt 2 Is scheduled to replace Its Installed poppet solenoid MTSVs with the spool solenoid 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 *sifting" issue, Dresden replaced the existing electro-hydraulic fluid with higher temperature rated synthetic fluid, cleaned the fluid reservoirs and replaced the filter cartridges with a different designed cartridge InOctober 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 i their response times were Inthe range of 40 to 60 millisecond. A high response Utme of the poppet valve Is a concern as the poppet solenoid

NRC FORM 366A U.S. NUCLEAR REGULATORY COMMISSION (701)

LICENSEE EVENT REPORT (LER)

1. FACILITY NAME 2.DOCKETNUMBER 6. LER NUMBER 3. PAGE Yeas SEQUENTIAL REVISION.

Dresden Nuclear Power Station Unit 3 05000249 NUMBER NUMBER I 2004 001 00 4 of 4

17. NARRATIVE (If m-e space Isrequired, use sddtonal copies o 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 c-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 ime of the poppet valves on Unit 3 caused the pressure and drain ports to be tied together for a sufficient time to cause the Emergency Trip Supply hydraulic header to depressurize and resulted in the momentary dosure 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.

F. Previous Occurrences:

A review of Dresden Nuclear Power Station Ucensee 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 378A3294P0001

§ 12

Exekrn.

Exelon Generation Company. uLC www.exeioncorp com NucleaT Dresden Nuclear 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 Inoperablilty of the Units 2 and 3 High Pressure Coolant Injection Systems Enclosed is Licensee Event Report 2004-002-00, uUnit 3 Automatic Scram Pue To Main Turbine Low Oil Pressure Trip and Subsequent Discovery of Inoperabilitypf the Units 2 and 3 High Pressure Coolant Injection Systems," for Dresden Nuclear Power Station. Thef e events are being reported in accordance with 10 CFR 50.73(a)(2)(iv)(A), OAny 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, nny GIS.

Site VI resident Dr en Nuclear Power Station Enclosure cc: Regional Administrator- NRC Region Ill NRC Senior Resident Inspector - Dresden Nuclear Power Station

NRC FORM 366 U.S. NUCLEAR REGULATORY APPROVED BY OSM NO. 3150.0104 EXP 7-31.2004 (7.200) COMMISSION Esimated burden per response to wl* wIit libtmandatory koamaton cection request 50 hows. Reported lssons lamed are hicpated VWt Ie kcens process and fed bad; Send comments Soldust burdeneesmab t IDe RecoRds Management Branch (1.

LICENSEE EVENT REPORT (LER) E6. US. Nudear Regulatory Commisson Washgon DC 205554001. or by -emete mail to bis1nrc ov. and to lie DeskOicerOffice d hration and Regulatory Atfairs, NEOB-10202 (1 0104). Oce of Manapenent and Budget. Wastgton, DC 20503. a means used t npose iloonation coflet oes not display a currently vafld OMB cnol newrer, lie NRC may not conduct or sponsor, and aperson riot required to resnd b. lie hifonnatlmcoledle0n.

1. FACILITY NAME , 2 DOCKET NUMBER 3. PAGE Dresden Nuclear Power Station Unit 3 05000249 1 of 5 4.Tmi.E Unit 3 Automatic Scram Due To Main Turbine Low Oil Pressure Trip and Subsequent Discovery of Inoperabtlity of the Units 2 and 3 High Pressure Coolant Injection Systems S. EVENT DATE 6. LER NUMBER 7. REPORT DATE S. OTHER FACILITIES INVOLVED D FACILITY NAME DOCKET NUMBER MO DAY YEAR N MO DAY YEAR Dresden Unit 2 05000237 FACILITY NAME DOCKET NUMBER 01 30 2004 2004 - 002 - 00 03 30 2004 NIA N/A

9. OPERATING _ 11.THIS REPORT IS UBMITTED PURSUANTTO THE REOUIREMENTS OF iO CFR 5: (Check amthat apply)

MODE 1 _ 20.2201(b) 7 20.2203(aX3WU) 50.73(aX2)i XB) l 50.73(aV2XbxWA)

10. POWER 20.2201(d) 20.2203(a)4) _ 50.73(aX2)(Mi) _ 50.73(a)(2)Cx)

LEVEL 097 _ 202203(a)(1) _ 50.36(c)1)X1XA) X 50.73(a)(2)(1vyA) - 7331 (aN4)

• 202203(IX2XI) _ 50.36(cX)I)WA) _ 50.73(aY2XvXA) _ 73.71(a W5)

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12. ICENSEE CONTACT FOR THIS LER NAME TELEPHONE NUMBER (Include Area Code)

GeorgePapanic Jr. (815)416-2815

13. COMPLETE ONE LINE FOR EACH COMPONENT FAILURE DESCRIBED INTHIS REPORT I MCOMMOlNET J

______I___KUBR _ LE CAUSE L S ISTE COMPONENT___ACTER U TO EPO. CAjSE STEM COMPONEN R FADERl TOEPIX

14. SUPPLEMENTAL REPORT EXPECTED . EXPE MON H DAY YEAR IYES (Ifyes completeEXPECTEDSUBMISSIONDATE) IX INO DATE l l I 1L ABSTRACT (rmnitto 1400 spaces, Le, approxImately 15 single-spaced t oeden Ines)

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 ir Mode 1, an automatic scram occurred due to a Main Turbine trip from low lube oRl pressure. The event occurred during a swapping of lube oil coolers. After the scram, reactor water 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 Injection 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 Inthe 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, "TurbineOil Cooler Operation. The corrective action to prevent reoccurrence of the High Pressure Coolant Injection Systems Inoperabllity Is to modify the post-scram response of the Feedwater Level Control System.

NRC FORM 366A UPS. NUJCLEAR REGULATORY COMMISSION iUCENYSEE EVENT REPORT (LER) 11.FACILITY NAME l2. DOCKET NUMBER S. LER NUMBER l3. PAGE VYEAR lSEOUEINTIAL IREVISION Dresden Nuclear Power Station Unit 3 05000249 I NUMBER NUMBER 2004 002 00 2 of 5

17. NARRATIVE (If more space Is required, use addillonal copies of NRC Form 366A)

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 [YjI.

A. Plant Conditions Prior to Event:

Unit: 03 Event Date: 1-30-2004 Event Time: 1155 CST Reactor Mode: I 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 Contnuous 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) [SJ] 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 Intotal feedwater flow that led to the trip of the 'B Reactor Feedwater Pump (RFP) [PI on low suction pressure. Additionafly, 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 Inthe tripping of the *A and 8C*

RFPs. Reactor water level was subsequently restored to normal and the RFPs were restarted. All rods Inserted and other than the feedwater response, aelother 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 [BJ1 for Dresden Units 2 and 3 were Inoperable. An evaluation by engineering determined that the Feedwater Level Control System (FWLCS) (s5] 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.*ECCS-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 1 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 numberwas 40494.

The Units 2 and 3 FWLCS post-scram level setpolnts 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 Inmanual 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)(2Xiv)(B).

NRC FORM 366A US. NUCLEAR REGULATORY COMMISSION LICENSEE EVENT REPORT (LER)

1. FACILITY NAME 2.DOCKETNUMBER . 6. LER NUMBER 3.PAGE YEAR SEQUENTI I REVISION Dresden Nuclear P1ower Station Unit 3 05000249 NUMBER . NUMBER 2004 002 00 3of 5

17. NARRATIVE (ilnore spaceIsrequredluseaddiUinalcopiesofNRCForm 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 ON 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 In vessel 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 In the position of the FRVs, combined with decreasing reactor pressure, caused an Increase In total 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 'A and 'C' 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 (7400fl LICENSEE EVENT REPORT (LER)

1. FACILITY NAME 2. DOCKET NUMBER C. LER NUMBER 3. PAGE SEQUENTIAL REVISION Dresden Nuclear Power Station Unit 3 05000249 . NUMBER NUMBER 2004 002 00 4 of 5

17. NARRATIVE (Ifmore space Is requIred, use addtIonal copies of NRC Form 366A)

The corrective action to prevent reoccurrence Is to re-design the FWLCS post-scram response. Exelon 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 signifcance of the HPCI Inoperabirty 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 availability 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 Ucensee Event Reports (LERs) and operating experience over the previous five years did not find any similar occurrences associated with the Main Turbine Lube Oi 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 Inwater 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 UaS. NUCLEAR REGULATORY COMMISSION UICENSEE EVENTr REPORT (LER)

1. FACILITYNAME l2. DOCKET NUMBER S. LER NUMBER 3. PAGE YEAR SEQUENTALIREIO Dresden Nuclear Power Station Unit 3 . l05000249.NME .MME 17, NARRATIVE (If more space Is feqtdred. use adonal woles of NRC Form 3616A)204020 1`

G. Component Failure Data:

NA

13 Exekrn.

Exelon Generation Company. ULC wwwexeloncotp.comri Nuclear Dresden Nuclear Power Station 6S00 North Dresden Road Moris, IL60450-9765 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 3 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), "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)(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

1. ¶ NRC FORM 366 US. NUCLEAR REGULATORY APPROVED BY OBM NO. 3150.0104 EXP 7431.2004 p .2001) COMMISSION EsCM Iated burden per response b comply wihI mandatory Wormation collection request 50 ows. Reported essons baned ame lo tie Icensirg process and led back nled LICENSEE EVENT REPORT (LER) ran enesatei Records Management h Sranch r.

LICESEEEVET REORT(LE) 6ES).U1.N- earRegulatory CommIssion. washngfton IDC 2O555-0wl. or by Internet e*

ai to bls and bl Desk Officer. Ofce bofomIafor atnd Regulatory Affais, NEO 202 (315>0.04). Oice ofd Manasement and Budge. WasNnghn DC 20503. Ifa means used ID h e onnon coleebon does notdsplay a crrenly valid OMB corWoI ere NRC may not cduct or sponsor, and a person I not required lo respnd o,the hionnalin colecton.

1. FACILITY NAME 2. DOCKET NUMBER S. PAGE Dresden Nuclear Power Station Unit 3 05000249 1of 4

.Lmxn Unt 3 Scram Due to Loss of Offsite Power and Subsequent Inoperability of the Standby Gas Treatment System for Units 2 and 3 S.EVENTDATE _.LLER NUMBER 7. REPORTDATE B. OTHER FACILIS INVOLVED

- FACUiY NAME DOCKET NUMBER MO DAY R YEAR lNUMM I NO MO DAY YE Dresden Unit 2 05000237 FACLITY NAME DOCKET NUMBER 05 05 2004 2004 - 003 00 07 06 2004 NWA NrA

9. OPERAING _ 11. THIS REPORT ISwUBMrTED PURSUAN T IE rEOUEMENS OF IS CFR 9: (Check aff Vu! a=

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12 _ICENSEE CONTACT FOR THIS LER NAME TELEPHONE NUMBER (Inlude Area Code)

George Papanic Jr. 1 (815) 416-2815

13. COMPLETE ONEUNE FOR EACH COMPONENT FAILURE DESCRIBED INTTHIS REPORT_

I NMAREOR VAM REtPORTA=L CAUSE S ISTE

. -JT FATUwERl JJ DLI.. COlOT F R Is MA X FK BRK 1005 l N _ _ l L _

14. SUPPLEMENTAL REPORT EXPECTED 15. ExPE TED MONTH DAY YEAR

____ SUBMISSION x YES O s.eompnIot EXPECTED SUBMISSION DA NO DATE 10 30 2004

16. ABSTRACT Mto 140 spaces. Le. apprxoatey 15 sie-spaced tpewren mis)

On May5, 2004, at 1327 hours0.0154 days <br />0.369 hours <br />0.00219 weeks <br />5.049235e-4 months <br /> (CDT), with Unit3 at 100 percent power InMode1, an automatic scram occurred due to a Main Generator Load Reject when a loss of offsite power occurred. The Emergency Diesel Generators automatically started and powered their respective electrical busses. All control rods fully Inserted and Group l, II andlIl 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. ARlsystems Initially responded to the scram as expected except the Standby Gas Treatment System wasunable 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. An Unusual Event for the loss of offslte 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 213 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 "v phase of the 345 kIlovolt circuit breaker8-15 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 underInvestigation.

NRC FORM 366A U.S. NUCLEAR REGULATORY COMMISSION (7.2001)

LICENSEE EVENT REPORT (LER)

1. FACILITY NAME 2DCENME .LRNME PG YEAR SEQUENUQL REVISION Dresden Nuclear Power Station Unit 3 05000249 NUMBER INME 2004 003 °° 2 of 4

17. NARRATIVE (It more space Is required, use additional copies of NRC Fmi 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 Inthe text are identified as [XX].

A. 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. Descrintion of Event:

On May 5, 2004. electrical breaker switching was being performed In the DNPS switchyard to support the testing of a 345 kilovolt (kv) offslte electrical tine. A loss of ofsite power (LOOP) occurred to Unit 3 when 345 kv breaker 8-15 [BKRJ located Inthe 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 In Mode 1, an automatic scram occurred due a Main Generator Load Reject when the LOOP occurred. The Emergency Diesel Generators (EDGs) [DG) automatically started and powered their respective electrical busses. All control rods fully Inserted and Group 1,!1 and Ill 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 [BO] for Torus cooling. All systems Initially responded as expected to the scram except for the Standby Gas Treatment System (SGT) [BK] 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 bower to Bus 33 that was being fed from EDG 213. 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 3.

At 1630 hours0.0189 days <br />0.453 hours <br />0.0027 weeks <br />6.20215e-4 months <br /> (CDT). SOT 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 fisted Inparagraph (a)(2)(v)(B) of this section," and

• 10 CFR 50.73(a)(2)@(B), "Any operation or condition which was prohibited by the plants Technical Specifications."

NRC FORM 366A US. NUCLEAR REGULATORY COMMISSION LICENSEE EVENT REPORT (LER)

1. FACILITY NAME -2 DOCKET NUMBER 6. LER NUMBER 3. PAGE YEAR l SEQUENTIAL REVISION Dresden Nuclear Power Station Unit 3 05000249 NUMBER NUMBER 2004 003 00 3of4

17. NARRATIVE (I mlore space I eqred, use addional opiesd NRC Form3A)

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 uCE 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 InJuly 2003, 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 Isto 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 Ina maintenance outage and the DTPE fans were In operation due to activities Inthe Unit 2 drywall. 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 Isto 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 Analysis:

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 avalliable 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 LICENSEE EVENT REPORT (LER)

1. FACILrTY NAME 2. DOCKET NUMBER 6. LER NUMBER 3. PAGE YEAR I SEOUENTAL IR4EVISION Dresden Nuclear Power Station Unit 3 05000249 MS NUMJER 2004 003 00 4of4

17. NARRATIVE (Itmore space Isrequired, use addionalecopies of NRC Fonn 366A)

The final corrective actions to prevent reoccurrence for the Emergency Diesel Generator output breaker will be described Ina 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 Inwhich an electrical fault Inthe 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 Failure Data:

I.T.E. Power Circuit Breaker, Model C Type GA

P.81/22 MPP-22-2W0 MAR-22-2005 17:36 17:36 P. 01/22

-4A UNITED STATES NUCLEAR REGULATORY COMMISSION WASHINaTON. DAC 205550f01 March 17, 2005 Mark A.Pelfer Site Vice President Duane Arnold Energy Center Nuclear Management Company, LL1 3277 DAEC Road Palo, IA S2324-0351

SUBJECT:

DUANE ARNOLD ENERGY CENTER EISSUANCE OF AMENDMENT RE: LICENSE AMENDMENT REQUEST TSOR-056, MODIFY LICENSE CONDITON 2.C.(2)(b) TO EUMIMATE MAIN STEAM ISOLATION VALVE CLOSURE TEST FOR EXTENDED POWER UPRATE (TAC NO. M02320)

Dear Mr. Pelfer.

The U.S. Nudear Regulatory Comrission has Issued the enclosed Amendment No. 257 to Facility Operating Ucense No. DPR-49 for the Duane Arnold Energy Center. This amendment consists of a change to the Operating License Inresponse to your application dated February 27, 2004, as supplemented by letters dated August 9, 2004, and January 7, 2005.

The amendment modifies license condition 2.C.(2)(b) to remove the requirement to perform a full main steam Isolation valve closure test assoclated with extended power uprate. In accordance with your request Inletter dated January 7, 2005, licensee condition 2.C.(2)(b) to eliminate the requirement to perform a main generator load reject test Is not Included Inthis amendment and will be addressed by separate correspondence. Our review of this effort will now be performed under a separate TAC.

A copy of the Safety Evaluation Is also enclosed. A Notice of Issuance will be Included Inthe Commission's next biweekly Federal Regstrnotice.

Sincerely, BAt4 Deirdre W. Spaulding, Project Manager, Section 1 Project Directorate IlI DivisIon of Ucensing Project Management Office of Nuclear Reactor Regulation Docket No.60-331

Enclosures:

1. Amendment No. 257 to Ucense No. DPR-49

2. Safety Evaluation cc w/encls: See next page

P.82/22 MRZ2-E105 I'-22-2e85 17:36 17:36 P. 02/22 Duane Arnold Energy Center cc; Mr. John Paul Cowan Daniel McGhee Executive Vice President & Utilities Division Chief Nuclear Officer Iowa Department of Commerce Nuclear Management Company, 110 Lucas Office Buildings, 5th floor 700 First Street Des Moines, IA 60319 Hudson, Mi 84016 Chairman, Unn County John Bjorseth Board of Supervisors Plant Manager 930 1st Street SW Duane Arnold Energy Center Cedar Rapids, IA 52404 3277 DAEC Road Palo, IA 62324 Craig G. Anderson Senior Vice President, Group Operations Steven R. Catron 700 First reet Manager, Regulatory Affairs Hudson, WI 54016 Duane Arnold Energy Center 3277 DAEC Road Palo. IA 52324 U. S. Nuclear Regulatory Commission Resident Inspectors Office Rural Route #1 Palo, IA62324 Regional Administrator, Region IiI U. S. Nuclear Regulatory CommissIon 2443 Warrenville Road, Suite 210 Usle. IL 60532-4352 Jonathan Rogoff Vice President, Counsel & Secretary Nuoloar Management Company, LLC 700 First Street Hudson, WI 54016 Bruce Letcy Nuclear Asset Manager Alliant Energy/Interstate Power and Ught Compary 3277 DAEC Road Palo, IA 62324 November2004

P.322:36 UNITED STATES NUCLEAR REGULATORY COMMISSION WASIHNGTON D.C. 2055-00M NUCLEAR3 MANAGEMERT COMPANY, LIC DOCKET NO §00-3 DUANE ARNOLD ENERGY CENTER AMENDMENT TO FACILITY OPERATING LICENSE Amendment No. 257 oLiense No. DPR.49

1. 'the U.S. Nuclear Regulatory Comrrdssion (the Commission) has found that:

A. The application for amendment by Nuclear Management Company, LLC (NMC) dated February 27,2004, as supplemented by letters dated August 9, 2004, and January 7, 2005, complies with the standards and requirements of the Atomic Energy Aot of 1954, as amended (the Act), and the Commission's rules and regulations set forth In 10 CFR Chapter l; B. The facility will operate Inconformity with the application, the provisions of the Act, and the rules and regulations of the Commission; C. There Is reasonable assurance (C)that the activiUes authorized by this amendment can be conducted without endangering the health and safety of the public, and (ii)that such activities will be conducted in compliance with the Commission's regulations; D. The Issuance of this amendment will not be Inimical to the common defense and security or to the health and safety of the public; and E. The Issuance of this amenciment Is Inaccordance with 1o CFR Part 61 of the Commission's regulations and all applicable requirements have been satisfied.

P.842 173 M~~-22-20e5 MAR-22-2005 M37 P.04-/22

2. Accordingly, the license Isamended by changes to paragraph 2.C.(2)(b) of Facility Operaing Ucense No. DPR-49 Is hereby amended to read as follows; (b) The licensee will perform the generator load reject transient test required by the General Electric Ucensing Topical Report for Extended Power Uprate (NEDO-32424P-A) - ELTR-1, Including the allowances described In Section L.2.4 (2)of ELTR-1 regarding credit for unplanned plant transient events, using the thermal power level (1658 MWt) to estabflsh the ELTR-1 power level limit The testing shall be performed at an Initiating power level greater than the steady-state operation power level exceeding the ELTR-1 power level imit for the generator load reject transient.

3. This license amendment Is effective as of Its date of Issuance ahd shall be Implemented within 30 days of the date of Issuance.

FOR THE NUCLEAR REGULATORY COMMISSION L.Raghavan, Cef, Secton 1 Project Directot Ill Dsion of Ucensing Project Management Office of Nuclear Reactor Regulation

Attachment:

Change to the Operating Uoense Date of Issuance: Harch 17, 2005

rAR-22-2005 17:37 P. 05/22 ATTACHMENT TO LICENSE AMENDMENT NO. 257 FAILrIY OPERATING LICENSE NO. DPR-49 DOCKET NO. 50-31 Replace the following page of the Facility Operating Ucense DPR-49 with th atched revised page as Indicated. The revised page Is Identified by order number and contains marginal Ines Indicating the area of change.

Remwoe Poan Insert Pawe 4 4

MAR-22-2B05 17:37 P*0622 (a) For Surveillance Requirements (BRs) whose acceptance criteria are modified, either directly or indirectly, by the Increase in authorized maximum power level In2.C.(1) above, Inaccordance with Amendment No. 243 to Facility Operating Lioense DPR-49, those SRs are not required to be performed until their next scheduled performnance, which Is due at the end of the first surveillance Interval that begins on the date the Surveillance was last performed prior to implementation of Amendment No. 243.

(b) The licensee will perform the generator load reject transient test required by the General Electric Ucensing Topical Report for Extended Power Uprate (NEDO-32424P-A) - ELTR-1, Including the allowances described InSection L.2.4 (2)of ELTR-1 regarding credit for unplanned plant transient events, using the thermal power level (1658 MWt) to establish the ELTR-1 power level limit The testng shall be performed at an Initiating power level greater than the steady-state operation power level exceeding the ELTR-1 power level lmit for the generator load reject transient.

(3) Flre Proteglin NMC shall Implement and maintain Ineffect all provisions of the approved fire protection program as described Inthe Final Safety Analysis Report for the Duane Arnold Energy Center and as approved Inthe SER dated June 1, 1978, and Supplement dated February 10, 1981, subject to the following provision:

NMC may miake changes to the approved fire protection program without prior approval of the Commission only If those changes would not adversely affect the ability to achieve and maintain safe shutdown Inthe event of a fire.

(4) The licensee Isauthorized to operate the Duane Amold Energy Center following Installation of modified safe-ends on the eight primary reclrculatlon system Inlet lines which are described Inthe licensee letter dated July 31, 1978, and supplemented by letter dated December 8, 1978.

(5) Physical Protection NMC shall fully Implement and maintain Ineffect all provisions of the ComrnIssion- approved physical security, training and qualification, and safeguards contingency plans Including amendments made pursuant to provisions of the Miscellaneous Amendments and Search Requirements revisions to 10 CFR 73.55 (51 FR 27817 and 27822) and to the authority of 10 CFR 50.90 and 10 CFR 50.54(p). The combined set of plans, which oontains Safeguards Informatlon protected under 10 CFR 73.21, Isentitled: NuClear Management Company Duane Arnold Energy Center Physical Security Plan, Revision 0"submitted by letter dated October 18. as supplemented by letter dated October 21, 2004.

Amendment No. 4S,4f, 5e, 6O. CZ, 74. 11B, 12, 190, 1 98, 14. 223, 292, 243 fRvised by Letter; atedI OtLbr 28, E00 levised by istt& deaed Beeembe. 40,2004 Revised by letter dated Hfarc 17, 2005 i!

MAR-22-2005 17:37 P.07/22 UNITED STATES NUCLEAR REGULATORY COMMISSION WASHINGTON, D.C. 2O055O1 SAFETY EVALUATION BY THE OFFICE OF NUCLEAR REACTOR REGULA71ON RELATED TO AMENDMENT NO. 257 TOFACILITY OPERATING LICENSE-NO. DPR-49 NUCLEARi MANAGEMENT COMPAN. LLIC DUANE ARNOLD ENERGY -ENTER OC0KET NO. 60..31 1.0 lNTRODUCTIQN By application dated February 27, 2004, as supplemented by letters dated August X,2004, and January 7,2005, the Nuclear Management Company, LLC (NMC or the licensee), requested a change to Facility Operating Ucense No. DPR-49 for the Duane Arnold Energy Center (DAEC).

The proposed change was to remove license condition 2.C.(2)(b) which requires that two specific large transient tests (LTTr) be performed at specified reactor thermal power levels, as part of power ascension testing for the extended power uprate (EPU) project at the DAEC. Ina letter dated February 27, 2004, NMC requested approval of this change prior to March 1.2005, as modifications were planned for the upcoming refuel outage at the DAEC which will allow the reactor power level to reach the license condition for performing the first of the two LTTs, the full main steamline Isolation valve (MSIV) closure test However, these planned modifications will not allow the reactor to achieve the thermal power level required to Invoke the second of the two LTTs required by the license condition, namely the main generator load reject test.

Given the staggered nature of the plant modifications Inthe DAEC EPU project, NMUs letter dated January 7, 2006, requested that the U.S. Nuclear Regulatory Commission (NRC) to issue separate license amendments, one for each of the two LTTs.

The supplemental letters contained clarifying Information and did not change the Initial no significant hazards consideration determination end did not expand the scope of the original federal Register notice.

The NRC staff reviewed the licensee's submittals and prepared this safety evaluation (SE) that addresses the MSIV closure test provision of the DARC Operating Ucense. The main generator load reject test provision will be addressed Inseparate correspondence, DAEC provided supplemental Information concerning the elimination of license condition 2.C.(2)(b) for performance of large transient tests for EPU Ina letter dated August 9, 2004, In response to an NRC staff request for additional Information (RAI). In addition, the NRC staff reviewed the relevant portions of the documents listed InSection 3 of this SE. NRC staff guidance for reviewing EPU test programs Isdescribed InNUREG-0800, Standard Review Plan (SRP) 14.2.1, OGeneric GuIdelines for EPU Testing Programs," and provides reasonable assurance that the proposed testing program verifies those plant structures, systems, and

MAR-22-2005 17:38 P. 0822 components (SSCs) that are affected by the proposed power uprate will perform satisfactorily In service at the proposed power uprate level. The NRC staff review focused on the licensee adequately addressing the applicable portions of the guidance described In SRP 14.2.1 related to LTT.

In a letter dated November 6, 2001, the NRC Issued Amendment No. 243 that approved the EPU for DAEC. This amendment consisted of Changes to the operating license and Technical Specifications (TSs) to allow an Increase Inthe maximum power level at DAEC from 1658 Megawatts thermal (MWt) to 1912 MWt representing a power Increase of 15.3 percent.

Amendment No. 243 also added license condition 2.C.(2)(b) requiring the licensee to perform generator load reject and fuln MSIV closure transient tests at specified reactor thermal power levels. As discussed, the lcensee's February 27, 2004, application as supplemented, is seeking two amendments that would elimInate this license condition entirely with the first amendment eliminating only the full MSIV closure test Although the NRC staff used SRP 14.2.1, the staff noted that SRP 142.1 covers the entire EPU test program and a review of the licensee's overall EPU test program was performed Inthe SE for Amendment No. 243.

Therefore, the focus of this SE Is on Issues related to the elimination of the performance of the full IMSIV closure transient test.

License condition 2.C.(2)(b) states, MThe licensee will perform the generator load reject and full main steam line Isolation valve closure transients tests required by the General Electric Ucensing Topical Report for Extended Power Uprate (NEDC-32424P-A)-ELTR-1, Including the allowances described In Section L2A(2) of ELTR-1 regarding credit for unplanned plant transient events, using t thermal power level (1658 MWt) to establish ELTR-1 power level limits. The testing shall be performed at an Initiating power level greater than the steady-state operation power level exceeding the respective ELTR-1 power level limit for each transient.s NEDC-32424P-A. "Generic Guidelines for General Electric Boiling Water Reactor Extended Power Uprate,n Is hereinafter referred to as ELTR-1. Following the Issuance of DAEC Amendment No. 243, General Electric (GE) Company revised ELTR-1 to state that testing Involving an automatic scram from a high power (which would Include the DAEC generator load reject and MSIV closure tests) Is not required. In a letter to GE dated March 31, 2003, the NRC took exception to GE's proposed elimination of large transient testing and stated that the NRC staff was preparing guidance to generically address the requirement for conducting large transient tests in conjunction with power uprates. The NRC subsequently provided this guidance In SRP 14.2.1. SRP 14.2.1 eflows licensees to either perform the large transient tests (which would include the DAEC generator load reject and MSIV closure tests) or provide adequate technical Justification for not performing the tests. To ensure consistency throughout this SE when power levels are discussed, the following table Is Included:

Power Date Related Information Level Original Rated Thermal 1593 MWt 1974 InItIal plant licensed thermal Power power ID Current" Rated 1658 MWt 1985 Thermal Power (CRTP)

MAR-22-2005 17:38 P.09.'22 EPU Phase 1 1790 MWt December 2001 EPU Phase II 1840 MWt Spring 2005. 1840 MWt Is planned. Final achievable power level to be

. determined.

EPU Phase III 1912 MWt Not yet scheduled __-

Power Level InELTR-1 1823.8 MWt Power level In ELTR-1 for for Maln Steam test (10% of 1658 MWt).

Isolation Valve Closure Test Power Level In ELTR-1 1906.7 MWt Power level InELTR-1 for for Generator Load test (15% of 1858 MWt).

Reject Test

2.0 REGULATORY EVALUATION

The purpose of the EPU test program Isto verify that SSCs will perform satisfactorily Inservice at the proposed EPU power level. The NRC staffs review covers (1) plans for the Initial approach to the proposed maxImum licensed thenral power level, Including -verification of adequate plant performance, (2)Integrated plant systems testing, Including transient testing, if necessary, to demonstrate that plant equipment will perform satisfactorily at the proposed Increased maximurn licensed thermal power level, and (3)the test program's conformance with applicable regulations. The NRC staffs acceptance criteria for the proposed EPU test program was based, In part, on (1)Appendix 8 to 10 CFR Part 60. Criterion Xl, which requires establishment of a test program to demonstrate that SSCs will perform satisfactorily Inservice, (2) General Design Criterion 1,EQuality Standards and Records," of Appendix A, General Design Criteria for Nuclear Power Plants," to 10 CFR Part 50, Insofar as It requires that SSCs Important to safety be tested to quality standards commensurate with the Importance of the safety functions to be performed, (3)10 CFR Part 50.34, "Contents of Applications: Technical Information," which specifies requirements for the content of the original operating license application, Including Final Safety Analysis Report (FSAR) plans for pre-operational testing and Initial operations, and (4) Regulatory Guide (RG) 1.68, Appendix A, Section 5, Power Ascension Tests," which describes tests that demonstrate that the facility operates In accordance with design both during normal steady-state conditions, and, to the extent practical, during and following anticipated operational occurrences (AOOs). Specific review and acceptance criteria are contained In SRP 14.2.1.

3.0 TECHNICAL EVALUATION

3.1 SRP 14-.2.1 Section il.A - Comnarison of Proposed Test Program to the Initial Plant Test PLroram 3.1.1 EvaluatIgn Criteria of SRP 14.2.1 Section 11lA SRP 14.2.1 Section IIIA, specifes the guidance and acceptance criteria that the licensee should use to compare the proposed EPU testing program to the original power ascension test

1IR-22-2005 17:39 P.10 program performed during initial plant licensing. The scope of this comparison should include (1)all Initial power ascension tests performed at a power level of equal to or greater than 80 percent of the original licensed thermal power level, and (2) initial test program tests performed at lower power levels ff the EPU would Invalidate the test results. The licenses shall ether repeat Initial power ascension tests within the scope of this comparison or adequately Justify proposed deviations from the initial power ascension test program. The following specific criteria should be identified In the EPU test program:

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 test program tests perfonned at power levels lower than 80 percent of the original licensed thermal power level that would be Invalidated by the EPU, and differences between the proposed EPU power ascension test program and the portions of the Initial test program Identified by the previous criteria.

3.1.2 bIRC Staff Evaluation Using SRPA4.2.1 Section I-.A.

The NRC staff reviewed the licensee's Plant Uprate Safety Analysis Report for testing recommended In ELTR-1. The licensee compared the Initial startup test program, and consistent with the NRC-approved generic EPU guidelines In ELTR-1, the EPU was determined

• to require only a limited subset of the odginal startup test program. As applicable to this plant's design, testing for the EPU Is consistent with the description In ELTR-1. Specifically, the following testing was performed for Phase I and will be performed for Phases II and iII during the power ascension steps of the EPU.

• Testing will be performed In accordance with the TS surveillance requirements on the Instrumentation that requires re-calibration for the EPU conditions.

e Steady-state data wfi1 be taken at points from 90 percent up to the previous reactor thermal power so that system performance parameters can be projected for the EPU before the previous power rating is exceeded.

• Power Increases beyond the previous reactor thermal power level will be made In Increments of equal to or less than 5 percent power. Steady-state operating data, including fuel thermal margin, will be taken and evaluated at each step. Routine measurements of reactor and system pressures, flows, and vibration will be evaluated from each measurement point prior to the next power increment.

• Control system tests will be performed for the feedwater/reactor water level controls and pressure controls. These operational tests will be made at the appropriate plant conditions for each test and at each power Increment above the previous rated power condition to show acceptable adjustments and operational capability. The same performance criteria will be used as In the original power ascension tests.

• A test specification will Identify the EPU tests, the associated acceptance criteria, and the appropriate test conditions. All testing will be done In accordance wAth Appendix 8 to 10 CFR Part 50, Criterion XI.

MAR-22-205 17:39 P.11/22 The licensee's test plan foflows the guidance of ELTR-1 and satisfies the applicable requirements In Appendix B to 10 CFR Part 50; therefore, the NRC staff found the test plan acceptable.

The staff reviewed the power ascension testing performed as part of the original plan described In the DAEC Updated Final Safety Analysis Report (UFSAR) Table 14.2-3. The basis for testing was described In UFSAR Section 14.2.1.3. The startup testing requirements for the original DAEC test program were lited In Specification 22A2669, 'General Electric Startup Test Specification.' By letter dated August 9, 2004, the licensee provided a comparison of the EPU test program with the original plant startup test program, as described In DAEC UFSAR Section 14.2. Additionally, thle licensee provided a matrix of these tests versus the thermal power levels at which testing was performed for Phase I and future phases of the EPU program. The NRC staff found that essentially, the test plans were umiilar in scope. However, the EPU plans do not Include a full MSIV closure test (or main generator bad reject test).

The NRC staff reviewed the following EPU test plan Information provided by the licensee In order to verify that the Initial EPU flicense amendment submittal, supplemental Information provided In response to NRC staff RAis, and applicable sections of TSs and the UFSAR addressed the specific criteria for en adequate EPU test program as described in SRP 14.2.1.

Specifically, the following documents were reviewed during the NRC staffs evaluation:

• FSAR Section 14, 'InItial Test Program' - Provided a detailed description of the licensee's Initial startup test progranms (1) administrative controls (2) scope of testing (systems tested), and (3) the overall test objectives, methods, and acceptance criteria.

DAEC letter N-O0-I0010, 'Request for Segmented Review of Ucense Amendment Request (TSCR-056),- dated January 7, 2005 - Provided a descipUon of the revised request of the proposed change to the operatIng license, which would eliminate the MSIV closure test as part of the EPU.

• DAEC letter NG-04-011, 'License Amendment Request (TSCR-056): Elimination of License Condition 2.C.(2)(b) for Performance of Large Transient Tests for Extended Power Uprate,' dated February 27, 2004 - Provided a description of the proposed change, the supporting technical analysis, and evaluation of the No Significant Hazards Consideration for removing the license condition to perform large transient testing as part of the EPU.

DAEC letter NG-04-0478, Response to Request for Additional Information Regarding License Amendment Request (TSCR-056): Elimination of Ucense Condition 2.C.(2)(b) for Performance of Large Transient Tests for Extended Power Uprate,w dated August 9.

2004 - Provided responses to NRC staff questions for (1) a comparison of the EPU test program to the Initial plant test program, (2) modifications and the associated post-modification tests (PMTs) that were performed and are planned.for the EPU, and (3) the licensee's response on how SRP 14.2.1 was addressed.

DAEC letter NO-01 -764. "Response to Request for Additional Information (RAI) to Technical Specification Change Request TSCR-042 - Extended Power Uprate," dated June 11, 2001 - Provided licensee responses to RAls on (1) proposed Implementation of the power uprate phases. (2) types of high power startup tests performed, (3) recent

MAR-2-200 17 40 P. 12M2 transient events that could be an Indicator of plant response to the EPU, and (4) post-scram evaluation of applicable transient events.

DASC letter NG-01-1 198, OFinal Typed Pages for Technical Specification Change Request TSCR-042 - Extended Power Uprate," dated October 17, 2001 - Provided Inclusion of the commitment to perform certain transient testing during power ascension to the new licensed power level.

DAEC letter NG-02-01 87, "Startup Test Report for Extended Power Uprate . Phase 1,'

dated March 4, 2002 - Provided a summary of the startup testing performed at DAEC following Implementation of te first phase of the EPU, which Increased thermal power 8 percent from 1658 MW: (CRTP) to 1790 MWt (Phase 1).

Safety Evaluation by the Office of Nuclear Reactor Regulation Related to Amendment No. 243 to Facility Operating Ucense No. DPR-49 Nuclear Management Company, LLC Duane Amold Energy Center Docket No. 50-331,' dated November 6, 2001 - Provided an NRC safety evaluation of the licensee's proposed amendment request to allow an Increase of the authorized operating power level from 1658 MWt (CRTP) to 1912 MWt (Phase l1l). The change represented an increase of 15.3 percent power above the current rated thermal power and therefore, was considered an EPU.

As part of this SE, the NRC staff reviewed the previous staff assessment of the EPU test program done for Amendment No. 243. Amendment No. 243 authorized operation up to 1912 MWt. Actual Implementation of the EPU Is being conducted In phases that support the licensee's modification schedule. Refer to the table In Section 1 of this SE for the power levels associated with the EPU phases.

As part of the licensee's review of the original test program, the following additional tests were evaluated for applicability to the EPU and added.

• Steady-State Data Collection: Key nuclear steam supply system and balance of plant parameters were recorded to ensure proper plant equipment performance.

• Power Conversion System Piping VibratIon Monitorung. Main steam and feedwater (FW) piping was Instrumented and monitored for unacceptable flow-induced vibrations,

• Turbine Combined Intennediate Valve (CIV) and Turbine Control Valve (TCV)

Surveillance Testing: Testing similar to original testing for the turbine stop valve was conducted on the ClVs and TCVs. The purpose of the testing was to establish the proper level for conducting on-line surveillance testing of the CJVs and TCVs.

X General Service Water (GSW) Heat Exchanger Performance Monitoring: GSW piping size was increased for the EPU to provide additional cooling to key components. This monitoring program will confirm adequate design cooling.

Phase I Test Program During performance of the Phase I test program, some acceptance criteria needed to be modified, as the original FSAR startup testing requirements were no longer applicable to the

MR-22-205 17: 40 P. 13/22 existing plant configuration. A problem Inthe FIN level control system was discovered that required maintenance and re-perfornance of those tests at 1658 MWt Aiso, based upon review of test data at lower power levels, the test matrbi at high power was simplified and some tests were not performed, as they would not have provided useful data.

The completed testing at the Phase I target power level of 1790 MWt demonstrated stable plant operation. Changes In plant chemistry and radiological conditions were minor, vibration monitoring of main steam and FW piping was normal, and no plant equipment anomalies were noted.

The NRC staff found that all tests described Inthe Initial stariup test program were addressed In the description of the Phase I EPU test program. The NRC resident staff observed portions of the Phase I testing. No significant deficiencies were noted.

Phase 11 Test Program The NRC staff reviewed the proposed testing for Phase 11, which will increase power to approximately 1840 MWt. Specifically. the NRC staff reviewed the changes to the test program for Phase IIthat differ from the NRC staff review performed for Amendment No. 243. The licensee Isherein proposing to eliminate the following test discussed below:

Test No. 25b, MSIVs - Full MSIV Closure Test This test was not required as part of EPU Phase I testing, as the required power level per the license condition Is 1823.8 MWt (ELTR-1 power level for the MSIV closure test), which was not reached InPhase 1.

This test Is currently required to be performed as part of Phase 11 testing. However. the purpose of this license amendment request Isto not perform this test as part of EPU testing.

3.1.3 NRC Staff ConclusIons Related to SRP 14.2.1 Section 111A.

The NRC staff concludes, through comparison of the documents referenced above, a review of test results from Phase I referenced Inthe FSAR, and a review of the test commitments proposed for Phase II,that the proposed EPU test program adequately identified (1) all initial power ascension tests performed at a power level of equal to or greater than 80 percent of the original licensed thermal power level, and (2) differences between the proposed EPU power ascension test program and the portions of the Initial test program.

3.2 P Section .8.:EPLt Mofi tlo Testin Reguire tIr s nt to Safety Impacted by EPU-Related Plant Modifications 3.2.1 E__luatlon Criteria of SRP 14.2.1 Section 111.5 SRP 14.2.1 Section 111.1., specifies the guidance and acceptance criteria which the licensee should use to assess the aggregate Impact of the EPU plant modifications, setpoint adjustments, and parameter changes that could adversely Impact the dynamic response of the plant to AOOs. AOOs Include those conditions of normal operation that are expected to occur one or more times during the Ufe of the plant and Include events such as loss of all offsite power, tripping of the main turbine generator set, and loss of power to all reactor coolant pumps. The EPU test program should adequately demonstrate the performance of SSCs

MR-22-2005 17:40 P.14/22

-8 important to safety that meet all of the following criteria (1)the performance of the SSC Is Impacted by EPU-related modifications, (2)the SSC Isused to mItigate an AOO described In the plant-specific design-basis, and (3)Involves the Integrated response of multiple SSCs. The following should be Identified Inthe EPU test program as It pertains to the above paragraph:

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

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

3.2.2 NRC Staff Evaluation Usina SRP 14.2.1 Section 111.1 The NRC staff reviewed the planned EPU modificatons and teIr potential effect on SSCs as documented Inthe DAEC letter NG-04-0478. The PMTs listed Inthe attachment to that letter were the acceptance tests to demonstrate design function performance and Integration with the existing plant. The NRC staff also reviewed the basis for the licensee's conclusions that the modifications did not change the design function of the SSCs or the methods of performing or controlling their functions. The following modifications and PMT descriptions were reviewed by the NRC staff.

The following modifications were completed InMay 2001 for Phase I (operation to 1790 MWt):

• Changes to the main turbine Included (1)the high pressure turbine was replaced, (2) turbine control valve operation was converted to partial arc admission, and adjustments made to the electra-hydraulIc control (EHC) system.

Changes to the main generator Included (1)now hydrogen coolers with increased cooling capacity. and (2) new GSW piping of increased capacity to support the larger hydrogen coolers.

• Larger main transformer coolers were Installed.

New temperature sensors to monitor Isophase buss temperature were Installed.

• A capacitor bank was Installed to Increase plant volts-ampere reactive capability and enhance grid stablWty.

Changes to the FW heaters Included (1)adjustment to FW heater level control settings to new heat balance, (2)trim on FW heater level control valves to allow higher flow, and (3) Installation of a bypass around FW heaters SAN to maintain extraction steam flow at pre-EPU values for heater tube vibration concerns.

e Tube stakes were Installed on the high and low pressure condenser tubes for vibration dampenIng.

Instrumentation upgrades Included (1)re-callbration of the local power range monitors and average power range monitors to the new 100 percent power, (2)trip reference cards Installed for the maximum extended load-fine limIt analysis (MELLLA) operating

MAR-22-205 17:41 P.15/22 domain on the power-to-flow map, (3)new main stearnfine high flow trip Instruments installed and re-calibrated to new setpolnt, (4)turbine first stage pressure (reactor protection system and end-of-cycle recirudation pump trip bypass) were re-callbrated to new setpolnts, based upon operating characteristics of the new high pressure turbine, (4) revised alarm setpoInt for the standby liquid control system tank volume alarm, (5) control room indications respanned to new ranges, and (6)the process computer re-programmed to new Instrument ranges.

Sensors and a data collection system were Installed for the main steam and FW piping vibration monitoring system.

The main steam reheater cross-around relief valve capacity was Increased (phased upgrade - one valve planned for each outage over four refueling outages).

Al of the Phase I modifications have been Installed, tested (performance monitoring, calibrations and startup testing) and are currently Inoperation. The NRC resident staff observed several of the PMTs performed for the above modifications. Also, portions of the Phase I power ascension were also observed. Inaddition, during the ensuing plant operation since EPIU Implementation, several plant events have occurred, Including manual scrams from Intermediate power levels, as well as a dual main recirculation pump runback event. Innone of these actual events has te plants dynamic response been abnormal. The NRC staff found the PMTs and subsequent observed equipment performance acceptable for the modifications performed InPhase 1.

The following modifications are scheduled to be completed Inthe spring of 2005 for Phase 11 (operation to approximately 1840 MWt):

The condensate pumps and motors will be upgraded to allow higher flow rate and their electrical protective relay settings adjusted. The PMT will Include (1)factory acceptance testing (full flow performance test with motor), (2)pump and motor vibration baseline measurements, and (3)performance monitoring.

FW heater upgrades wll continue with replacement of the 3A/B, 4AIB and SA/B FW heaters. The PMT will Include (1)factory acceptance testing (eddy-current testing and non-destructive examination of welds), (2) In-service leak testing, (3)thermal performance testing. and (4)FW heater level controller adjustments.

The Phase II modifications are primarily to address current FW and condensate system flow capacity limitations. The modifications Will bring system capacity up to that needed to achieve a target power level of approxrmatety 1840 MWM Because modifications are focused on the FW and condensate system, testing will target this equipment, Inaddition to the general testing required during power ascension. These modifications will not significantly change the overall plant dynamic response to the anticipated Initiating events described in the UFSAR. The NRC staff found the proposed PMTs acceptable for the modifications to be conducted InPhase 11.

32.3 NRC Staff Condluslons Related to SRP 14.2.1 Section I11.B The NRC staff concludes, based on review of each planned modification, the associated PMT, and the basis for determining the appropriate test, that the EPU test program will adequately

MAqR-22-2e05 17:41 P.16/22 demonstrate the performance of SSCs Important to safety; Included in this analysis are those SSCs (1) impacted by EPU-related modifications, (2) used to mitigate an AOO described Inthe plant design basis, and (3) supported a function that relied on Integrated operation of multiple systems and components.

The NRC staff concludes that the proposed test program adequately identified plant modifications and setpolnt adjustments necessary to support operation at the uprated power level and changes Inplant operating parameters (such as reactor coolant temperature, pressure, reactor pressure, flow, etc.) resulting from operation at EPU conditions. Additionally, the NRC staff determines there are no unacceptable system Interactions because of modifications to the plant 3.3 SRP 14.2.1 S ion ill.C - stificato for iminatio EPU wr Asceion Tests 3.3.1 Evaluation Criteria Using BRP 14.2.1 Section lll.C SRP 14.2.1 Section 111.C., spedfies the guidance and acceptance criteria the Ucensee should use to provide Justification for e test program that does not Include all of Xt power ascension testing that should be considered for Inclusion Inthe EPU test program pursuant to the review criteria of Sections 1 and 2 above. The proposed EPU test program shall be sufficient to demonstrate that SSCs will perform satisfactorily Inservice. The following factors should be considered, as applicable, when justifying elimination of power ascension tests:

• previous operating experience,

• Introduction of new thermal-hydrauric 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,

• margin reduction In safety analysis results for anticipated operational occurrences, and

• -guidance contained In vendor topical reports risk Implications.

3.3.2 RC S Evaluation Usn SRP 14.2. Seo I The NRC staff focused the review on Information regarding the following exception to original startup testing contained In the licensee RAJ response letters NG.04-0478 end NG-01-0764.

• Test No. 25b, MSIVs - FuN MSIV Closure Test; This test was not required as part of EPU Phase I testing, as the required power level per the license condition Is 1823.8 MWt (ELTR-1 power level for MSIV closure test), which was not reached In Phase 1.As part of the license condition, this test Iscurrently required to be performed as part of Phase 11testing. However, the purpose of this license amendment request is to not perform this test as part of EPU testing.

MPR-22-2005 17:42 P. 17./22 The NRC staff reviewed the licensee's response In NG-01-0764 regarding previous operating experience. The DAEC experienced unplanned events at approximately 1658 MWt (CRTP),

which provided data for the MSIV closure test In the frst event when the reactor was operating at approximately 1658 MWt, one MSIV unexpactedly closed due to a failed solenoid.

Reactor pressure and reactor power Increased and steam flow through the remaining three steanilines Increased, until a full isolation of the main steamlines was InItiated on high steam flow. No significant anomalies in the plant response were observed. In the second event, with the same reactor power, the main generator backup lockout differential current trip resulted Ina turbine control valve fast closure event The primary sourbe signal for the reactor scram was the pressure switches on the EHC system that signal the fast closure of the turbine control valve. Again, no significant anornarles in the plant response were observed, with one exception. The FW controls allowed reactor level to Increase to greater than the FW pump trip setpoint. While the Level 2 criterion (licensee established criterion for FW level control) was not met, the Level 1 criterion ftt the steamllnes not flood was met. There Is no safety consequence to the level 2 criterion not being met Normal reactor water level control was subsequently established. The NRC resident staff observed the FW control troubleshooting.

The licensee adequate resolved the FW control setpoint Issue.

The licensee also cited Hatch Nuclear Plant, Unit 2, as an example of a similar plant which had an event subsequent to their EPU. Plant Hatch, Unit 2, Is a boiling-water reactor (BWR) 4 with a Mark I containment of essentially the same design as the DAEC, Including the key balance of plant area of turbine generator control logic. Hatch Nuclear Plant, Unit 2, had an unplanned event which resulted In a generator load reject from their fuU uprated power level. No anomalies were seen in the plants response to this event In addition, Plant Hatch, Unit 1, has experienced one turbine trip end one generator load reject event subsequent to its uprate.

Again, the primary safety systems perfomned as expected. No new plant behaviors have been observed that would Indicate that the analytical models being used are not capable of modeling plant behavior at the EPU conditions. A turbine trip and generator load reject event result In a pressurization transient similar to an MSIV closure event In response to the possible Introduction of new thermal-hydraulic phenomena or Identified system Interactions. the licensee responded that none of the modifications Implemented should have an Impact in this area. The major EPU modification to the DAEC was to modify the main steam now path from the reactor to the turbine generator to accommodate the higher steam flow due to the EPU. A new, more efficient high pressure turbine was Installed and the TCV's were converted to partial arc mode. However, neither of these modifications introduced new thermal-hydraulic phenomena In the plant, nor do they Introduce new or different system Interactions that would warrant performing a pressurization transient test. The conversion to partial arc admission lessens the severity of a pressurization transient from operation in full arc admission, In addition, no Instrument setpolnts were modified that Initiate equipment relied upon to mitigate this event.

Specifically, MSIV stroke times were not changed, nor were the opening settings of the safety/relief valves (S/RVe). No Instrument setpolnts were modified that Initiate equipment relied upon to mitigate this event, such as the MSIV closure signal that Initiates a reactor scram.

The MSIV closure Is a pressurization transient caused by a fast shutoff of steam flow from the reactor vessel, from closure of the MSIVs. The transient severity Is primarily determined by the Initial operating pressure and rate of pressure Increase (i.e., valve closure time). Rated reactor

MAR-22-2005 17:43 P. 18/2 power (i.e., rated steam flow), has a noticeable, but secondary effect on the rate of pressure Increase. NMC has implemented the DAEC EPU without a reactor pressure Increase (commonly referred to as a constant pressure power uprate), or change In the shutoff valve stroke times. In addition, no modifications to the major SSCs used to mitigate this transient, such as the SI/Rs or turbine bypass valves, have been made. Only rated steam flow has been affected by the EPU.

The NRC staff reviewed the lioensee's response In NG-04-01 11 to he Introduction of new thermal-hydraulic phenomena or Identified system Interactions. The major EPU modification to the plant was to modify the main steam flow path from te reactor to te turbine generator to accommodate the higher steam flow due to the EPU. A new, more efficlenr high pressure turbine was Installed and the turbine control valves were converted to partial arc mode.

However, neither of these modifications Introduced now thermal-hydraulic phenomena Inthe plant, nor do they Introduce new or different system Interactions that would warrant performing the MSIV closure test. As noted above, the conversion to partial arc admission lessens the severity of a pressurization transient from operation Infull arc admission.

The NRC staff reviewed Section 3.7 of the Nuclear Reactor Regulation (NER) SE for the DAEC EPU. Section 3.7 discussed the assessment of the effects of the EPU on the MISIV closure times. The original SE indicated that the NRC staff accepted the generic assessment on the MSIVs, which was documented In Section 4.7 of Supplement I to ELTR-2. The generic evaluation covered the effects of the power uprate changes on (1) the capability of the MSI/s to meet pressure boundary structural requirements, and (2) the safety function of the MSIVs.

The NRC staff accepted the generic assessment that the MSIV closure time can be maintained as analyzed and specified In the TSs. In addition, various surveillances require routine monitoring of MSIV closure time and leakage to ensure that the licensing basis for the MSIVs is preserved.

Based on the review of the evaluation and rationale, the NRC staff agreed with the conclusion that EPU operation would remain bounded by the generic evaluation in Section 4.7 of ELTR-2 and that the plant operation at the EPU level will not affect the ability of the MSIVs to perform their safety function.

The NRC staff reviewed the licensee's response In NG-04O01 I to facility conformance to limItations associated with analytical analysis methods. The licensee used General Electrics analytical model for analyzing transients (ODYN) and associated methods (GEMINI), which have been proven to acceptably predict plant behavior during a pressurization transient Including the DAEC, even at EPU conditions (eg., Hatch). These methods are routinely used In the analysis of core reloads that form the basis for the core operating limit requirements. No new limitations on these methods have been Imposed as a result of EPU Implementation.

The NRC staff reviewed plant staff familiarization with facility operation and trial use of operating and emergency operating procedures. The NRC staff has previously reviewed and approved NMC's process for updating the plant operating procedures (normal and off-normal),

training (including plant simulator), end human factors aspects of the DAEC's EPU Implementation.

MAR-22-2005 17:44 P 19/22 The NRC staff also noted that In describing and Justfn test exceptions or deviations, the licensee adequately considered previous operating experience, the possible Introduction of new thermal-hydraullc phenomena or system interactions, and margin reduction In safety analysis results for A0Os. Other factors used to determine the EPU test elimination Included use of baseline operational data, updated computer modeling analyses, and Industry experience.

Risk Informed Justifications for not performing a transient test was considered, as described In Section 10.4 of the SE for Amendment No. 243, but was not the sole factor Indetermining elimination of those tests. Previous operating experience, the Initial startup test program report, computer model analyses and surveillance requirements were the major factors on those decisions.

3.

3.3 NRC Staff Conclusion

s Related to SKP 14,2. Section 111.0 The NRC staff concludes that, Injustifying test eliminations or deviations, the licensee adequately addressed factors that Included (1) previous operating experience, (2) Introduction of new thermal-hydraulic phenomena or system Interactions, and (3) staff familiarization with facility operation and use of operating and emergency operating procedures. The NRC staff determined that the licensee did not rely on analytical analysis as the sole basis for ellmination of a power ascension test from the proposed EPU test program. Construction, instaflation and/or pre-operational testing for each modification will be performed In accordance with the plant design process procedures. The final acceptance tests will demonstrate that the modifications will perform their design function and Integrate appropriately with the existing plant 3A SRP .2.1 Sectio - Adus of Pro ed stna Plans 3.4.1 Evaluation Criteria of SRP 14.2.1 Section I1.0 SRP 14.2.1 Section il.D, specifies the guidance and acceptance criteria the licensee should use to include plans for the Initial approach to the Increased EPU power level and testing that should be used to verify that the reactor plant operates within the values of EPU design parameters. The test plan should assure that the test objectives, test methods, and the acceptance criteria are acceptable and consistent with the design basis for the facility. The predicted testing responses and acceptance criteria should not be developed from values or plant conditions used for conservative evaluations of postulated accidents. During testing, safety-related SSCs relied upon during operation shall be verified to be operable in accordance with existing and Quality Assurance Program requirements. The following should be Identified In the EPU test program:

• the method in which Initial approach to the uprated EPU power level Is performed Inan incremental manner Including steady-state power hold points to evaluate plant performance above the original full-power level,

• appropriate testing and acceptance criteria to ensure that the plant responds within design predictions including development of predicted responses using real or expected values of Items such as begInnIngoflife core reactivity coefficients, flow rates, pressures, temperatures, response times of equipment and the actual status of the plant,

MRI-22-20 17:44

• contingency plans i the predicted plant response Is not obtained, and e a test schedule and sequence to minimize the time untested SSCs Important to safety are relied upon during operation above the original licensed full-power level.

3.42 NRC Staff Evaluation Using SiRP 14,21 Section 1,ID The NRC staff reviewed Attachment 6 of NG-00-1900, which outlined the licensee's proposed EPU test plan. The NRC staff also reviewed the original NRR SEs conclusions on the adequacy of the startup test program. The NRC staff had concluded that the licensee's test plan followed the guidelines of ELTR-1 and satisfied the applicable requirements inAppendix B to 10 CFR Part 60.

The licensee win conduct limited startup testing at the time of Implementation of the proposed EPU. The tests will be conducted Inaccordance with the guidelines of ELTR-1 to demonstrate the capability of plant systems to perform their design functions under uprated conditions.

The tests will be similar to some of the original startup tests described in Table 14.2-3 and Section 14.2.1.3 of the DAEC UFSAR. Testing will be conducted with established controls and procedures which have been revised to reflect the uprated conditions.

The tests will consist essentially of steady-state, baseline tests between 90 and 100 percent of the currently licensed power leveL Several sets of date will be obtained between 100 and 115.3 percent current power with no greater than 6 percent power Increments between data sets. A final set of data at the proposed EPU power level wll also be obtained. The tests will be conducted In accordance with a sIte-specific test procedure, currently being developed by the licensee. The test procedure will be developed Inaccordance with written procedures as required by 10 CFR Part 50, Appendix B. Criterion Xl. Test Controls The licensee Indicated that the power Increase test plan will have features as described Inthe Power Uprate Safety Analysis Report, Section 10.4, "Required Testing.3 Initial power ascension testing Is outlined InSection 2.B.1 of this SE.

The guidelines InELTR-1, Section 6.11.0. specify that pro-operational tests will be performed for systems or components which have revised performance requirements. These tests will occur during the ascension to EPU conditions. The performance tests and associated acceptance criteria are based on DAEC's original startup test specifications and previous General Electric BWR EPU test programs. The licensee's performance tests are discussed in Section 2.B.2 of this SE.

The NRC staff noted that the results from the uprate test program will be used to revise the operator training program to more accurately reflect the effects of the proposed EPU.

Inaddition, the plant staff, through classroom andlor simulator training, will be familiarized with the operation of the plant under EPU conditions. The training will Include (1) plant modification and parameter value changes, (2)Implemertation/execution of normal, abnormal, and emergency operating procedures, and (3)accident mitigation strategies.

MR-22-2005 17:45 P.21'22 3.

4.3 NRC Staff Conclusion

s Related to'SRP 14.2.1 Section III.P The NRC staff concludes that the proposed test plan will adequately assure that the test objectives, test methods, and test acceptance criteria are consistent with the design-basis for the facility. Additionally, the NRC staff concludes that the test schedule would be performed in an Incremental manner, with appropriate hold points for evaluation, and contingency plans exist If predicted plant response Is not obtained.

3.5 Tecn1ic uationSumwa The NRC staff has reviewed the EPU test program In accordance Oith BRP Section 14.2.1.

This review Included an evaluation of: (1) plans for the Initial approach to the proposed Phase 11thennal power level, Including verification of adequate plant performance, (2) transient testing necessary to demonstrate that plant equipment will perform satisfactorily at the proposed Phase If thermal power level, and (3) the test program's conformance with applicable regulations. For the reasons set forth above, the NRC staff concludes that the proposed EPU test program provides reasonable assurance that the plant will operate In accordance with design criteria and that SSCs affected by the EPU or modified to support the proposed power uprate will perform satisfactorily while in service. On this basis, the NRC staff finds that the EPU testing program satisfies the requirements of 10 CFR Part 60, Appendix S. Criterion Xl, "Test Control."

Therefore, the NRC staff finds the Rlcensee's proposed license amendment request to modify license condition 2.C.(2)(b) to eliminate the requirement to perform the full MSIV closure test from the EPU test program acceptable.

4.0 STATE CONSULTATION

In accordance with the Commissions regulations, the Iowa State official was notified of the proposed Issuance of the amendment. The State official had no comments.

5.0 ENVIRONMENTAL CONSIDERATION

S The amendment changes a requirement with respect to the Installation or use of a facility component located within the restricted area as defined In 10 CFR Part 20. The NRC staff has determined that the amendment involves no significant Increase Inthe amounts, and no significant change in the types, of any effluents that may be released offslte, and that there is no significant Increase Inindividual or cumulative occupational radiation exposure. The Commission has previously Issued a proposed finding that the amendment Involves no significant hazards consideration and there has been no public comment on such finding published April 13, 2004, (69 FR 19572). Accordingly, the amendment meets the eligibility crIteria for categorical exclusion set forth in 10 CFR 5122(c)(9). Pursuant to 10 CFR 51.22(b),

no environmental Impact statement or environmental assessment need be prepared In connection with the Issuance of the amendment

MiR-22-2005 17:45 P.22/22

6.0 CONCLUSION

above, that: (1)there The Commission has concluded, based on the considerations discussed will not be endangered by Isreasonable assurance that the health and safety of the public In compliance with the operation Inthe proposed manner, (2) ouch activities wIg be conducted will not be Inimical to the Commission's regulations, and (3)the Issuance of the amendment common defense and secWity or to the health and Gafety of the public.

Principal Contributor. P. Prescott Date: March 17, 2005 TOTAL P.22

15 GE Energy, Nuclear 3901 Castle Hayne Rd Wilmington, NC 28401 December 2,2005 Action Requested by: NA GE-WNPS-AEP-415 Response to: N/A DRF 0000-0007-5271 Project Deliverable: NA GE Company Proprietary - This Letter is non-proprietary upon removal of Attachments cc: G.Paptzun B.Hobbs (ENOI)

To: Craig Nichols (ENQI)

From: Michael Dick Author Michael Dick

Subject:

Information Copies of KKL (Leibstadt) Large Transient Test Comparison Reports

References:

1. Entergy Nuclear Operations Inc., Vermont Yankee Nuclear Power Station, AEP, GE Proposal No. 208-1JX8XA-HB1, Revision 5, dated November 13,2002.

2. Entergy Nuclear Operations, Inc. Contract Order No. W015144 (Asset Enhancement Program)

Attached to this letter please find information copies of the following large transient test comparison reports that were performed in support of the KKL (Leibstadt) extended power uprate project

1. GENE-A13-00400-05, "Engineering Evaluation of KKL Load Rejection Test 100%

Power (3138 MWt) 13 September 1996"

2. GENE-A13-00413-04-01, "Engineering Evaluation of KKL Turbine Trip Test 109%

Power (3420 MWt0 11 September 1999"

3. GENE-0000-0003-1181-01, "Engineering Evaluation of KKL Turbine Trip Test 112%

Power (3515 MWt) 07 September 2001" These reports show comparisons of transient predictions using the GE ODYN code versus actual KKL test data. These reports are considered GE proprietary in their entirety and may not be released to any third party unless a proprietary information agreement between GE and the third party is in place.

As a point of clarification, the KKL original licensed thermal power (OLTP) is 3012 MWt.

KKL performed a stretch power uprate to 104.2% OLTP (3138 MWt) after original plant licensing. KKL referenced all of the extended power uprote evaluations as a percentage

GE-WNPS-AEP-415 Revision 0 December 2,2005 of the stretch power uprate level. Therefore, the 112% power level (3515 MWtO is actually 116.7% of OLTP.

A signed copy of this letter is included in DRF 0000-0007-5271. Supporting technical information and evidence of verification for the Attachment 1 are contained in DRF 0000-0039-3917.

If you have any questions in this matter, please contact me.

MJD Attachments:

1. GENE-A13-00400-05, "Engineering Evaluation of KKL Load Rejection Test 100%

Power (3138 MWt) 13 September 19960 GE Proprietary Information

2. GENE-A13-00413-04-01, Engineering Evaluation of KKL Turbine Trip Test 109%

Power (3420 MWt) 11 September 1999N GE Proprietary Information

3. GENE-0000-0003-1181-01, *Engineering Evaluation of KKL Turbine Trip Test 112%

Power (3515 MWtO 07 September 2001" GE Proprietary Information

VERMONT Y ANIEE NUCLEAR IPOWSR ('ORP'ORATION P 0. BOX 157 LW(.'VIItNOR I1-.NT ROAD

'ERNON. VERMONT 05354 April 12, 1991 VYV I 91-104 U.S. Nuclear Regulatory Commission Document Control Desk Washington, D.C. 20555

REFERENCE:

Operating License DPR-28 Docket No. 50-271 Reportable Occurrence No. LER I 91-05

Dear Sirs:

As defined by 10 CFR 50.73, we are reporting the attached Reportable Occurrence as LER 1 91-05.

Very truly yours, VERMONT YANKEE NUCLEAR POWER CORPORATION 4 .

• idl Plant Kanager cc: Regional Administrator USNRC Region I 475 Allendale Road King of Prussia, PA 19406 914j-;30Z44 ';10541,' -'.10 PFR Ar>i: l '1.O6'0 271 S PDR

MC Form 365 U.S. NUCLEAR R7GULATORY OoISSION APPROVED OHS NO.3150-0104

• i-wei EXPIRES 4/30/92 ESTIMATED BURDEN PER RESPOPSE TO COMPLY WITH THIS INFORMATION COLLECTION REQUEST:

50.0 HRS. FORWARD COMMENTS REGARDING LICENSEE EVENT REPORT (LER) BURDEN ESTIMATE TO THE RECORDS AND REPORTS MANAGEMENT BRANCH (P-S30), U.S. NUCLEAR REGUlATORY COMMISSION, WASHINGTON, DC 20SS5, AND TO THE PAPERWORK REDUCTION PROJECT (3160-0104). OFFICE OF MANAGEMENT ANO RBUFGT. MASHiWGTc. DC 206l0.

FACILITY NM DOCKET NO. PAGE (_*

VERMONT YANKEE NUCLEAR POWER STATION 10 15 10 I 0 1.0 12 17 1 1 10 1 1f O1 10 14 TITLE (4)

Reactor Screw due to Mechanical Failure of 34SKV Switchyard Eus caused by Broken High voltaoe Insulator Stack EvENr DATE ) I LER NUMBER (") REPORT DATE lL) OTHER FACILITIES INVOLVED (')

4M- AY- YEA YEAR iiSfO. I REVJ N DAY IYEAR FACILITY N ES ET NO.(S) d5 d d Id 1013 1 13 9 I 19 I 1 lo Is5 1J 1 9 I1 0111el 1 1 OPATING THIS REPORT IS sueMITIED PURSUANT TO REG 'Nlr OF IOCFR St f ONE OR MORE l")

-oD_ 9 _ 20.402(b) _ 20.405(c) 50.73(a)(2)(iv) 73.71 (b)

_ 20.40S(a)(l)(ii) _ 0.3(a)(2) 50.73(a)(2)(v) _A73.7ic LEVELI') il _ 20.405(a)(l)(ii) 60.36(c) (2) _ 0.73(a)(2)(vii) _ OTHER:

P .....

........ _ 20.405(a)(1)(i) 6O..36()(2)(i) 50.73(a)(2)(viii) _A1

...... ... _ 20.405(a)(1)(iv) 60.13(a)(2)(ii) _O.13(a)(2)(viiij(B) 0....... . ... 2O.4O5{a1tl)

-. v_ SO.73(a)(2)liii) I 60.73(a)(2Ux) I _ _

LICENSEE CONTACT FOR THIS LER ("I)

SAME TELEPHONE NO.

AREA COOE DONALD A. REID. PLANT HANAGER - 4 71 N211l COMPLETE a E LINE FOR EACH COMPONENT FAILURE DESCRIBED IN THIS REPORT (Is)

CAUSE SYST CONPNT NFR REPORTABLE ..... CAUSE SYST COMPNT lFR REPORTABLE NPRDS l TO T- NPRDS

_i

_TO _ __l X d Si

• l N/A I I I I I I M/A I I/A _

• NAL II.I IFA I I III  ::

SUPPLEMENTAL REPORT EXPECTED I*" IEXPECTED Ho DA YR SUBMISSION YES (If ves. complete EXPECTED SUBMISSION DATE) hX NO DATE t"1)

ABSTRACT (LiEit to 14uO spaces. I.e.. approx. fifteen zingle-space typewritten lines) (so)

On 3/13/91 at 2226 hours0.0258 days <br />0.618 hours <br />0.00368 weeks <br />8.46993e-4 months <br />, with reactor power at 100t. a Reactor scram occurred due to a generator/turbine trip as a result of the failure of an 80 ft. vertical section of 345KV Switchyard Bus (B Phase) between the Main Transformer aerial TI disconnect switch and the horizental bus bar spanning the IT-11 and 81-IT-2 disconnect switches. The cause of the bus failure is attributed to a broken insulator stack hich secured the bus to the tower. The plant wns sutsequently stablized by resetting Primary Containment isolations, restarting Reactor Water Cleanup and establishing level control using the 10t 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/l8/91 at 0OSS hours. The need to expand present Switchyard system maintenance is being evaluated.

C Form 356 (6-89)

UK Form SWA U.S. NUCLEAR REGULATORY COOhISSION APPROVED OHS NO.3150-0104 C4 t3 WlEXPIRES 4/30/92 ESTIMATED BURDEN PER RESPONSE TO COMPLY WITH THIS INFO00ATION COLLECTION REQUEST:

50.0 MRS. FORWARD COPHENTS REGARDING LICENSEE EVENT REPORT (LER) BURDEN ESTIMATE TO THE RECORDS AND REPORTS EXT CONTINUATION MANAGEMENT BRANCH (P-630), U.S. NUCLEAR REGULATORY COMMISSION, WASHINGTON, DC 2055S, AND TO THE PAPERWORK REDUCTION PROJECT (3160-0104), OFFICE OF MANAGEMENT AND BUDGET. WASHINGTON. DC 20603.

UTILITY NME (') DOCKET NO. (a) LENWIBER ('6 PAGE (3 5AjjSEO.

Y I I IREV#

-WM INTaM ENgCLEARPOWER S TIONI dg d d j27I I~i-I otols I- Ido 1 20 1 TEXT (If *ore space is required, use additiFnal NRC Form 366A) (")

ESrIPTION OF EVENt On 3/13191 at 2228 hours0.0258 days <br />0.619 hours <br />0.00368 weeks <br />8.47754e-4 months <br />, during normal operation with Reactor power at 100%. a Reactor scram occurred as a result of a turbine trip on Generator Load Reject due to a 345KV Switchyard 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 *V Buses and I and 2 to the Startup transformers.

c. Reactor scram on Turbine Control Valve Fast Closure signal.

d. Primary Contaiinent Isolation System (PCIS)(JM)* Initiation, Groups 2, and 3 on Neactor Vessel 'Lou water level.

Oprattions personnel responded to the scram by iapleaenting the required steps delineated in Emergency Operating Procedure OE-3100 "Scram Procedure" which governs reactor operation in a post-sc environeent.

hutcmatic system responses a) thru cl 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, quicely recovered with the "Al and "CO Reactor Feedwater pumps running.

In an effort to control the increasing level, the "Cm Reactor Feedwater pump was secured bV Operations personnel. 4t 2230 hours0.0258 days <br />0.619 hours <br />0.00369 weeks <br />8.48515e-4 months <br /> (2 minutes into the event), the mA" Reactor Feedmter pump tripped on High Reactor water level (1?7 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 Cleanups resetting PCIS Group 2, 3, and 5 isolations and establishing level control using the 10% 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 cbserved in the Suitchyard jumt prior to the Reactor scram. The local Fire Department was notif ied, but no fire ensued. The flash that had been observed was an electrical arc resulting from the connection break of the OB" 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 Sypass 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 0

the 0ng j. loop.

• Energy Infom tion Identification System (EIIS) Component Identifier MC Form 36 (6-39)

-- ruM q~ U.:i. MRLtM UILAJWIT ^wI51J WPRUVED GM W.3150-0104 WM} EXPIRES 4/30/92 ESTIMATED SURDEN PER RESPONSE T0 COMPLY WITH THIS IFORATION COLLECTION REQUEST:

60.0 HRS. FORWARD COPHENTS REGARDING LICENSEE EVENT REPORT (LER) BURDEN ESTIMATE TO THE RECORS AND REPORTS TEXT CONTINUTION HANACENENT SRANCH (P-S30), U.S. NUCLEAR REGULATORY COCHISSION. WASHINGTON, DC 20565, AND TO THE PAPEPJR REDUCTION PROJECT (3160-0104). OFFICE OF MANAGEMENT I A DET._WASHINGTON. DC 20603.

UTILITY NW£ (') DOCKET N0O. ) LER NMER C*) PACE ( )

Wm i SEQ.

• R£VJ VE3T TEXt (If YANKEENUCLEAR STAttO PO ERR I ddLdd d2[1 It 191 more space is required. use additional hRC Form 366A)

- 0I olo C"

I iOF d 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 />.

During the course of the event, the following additional anomalies occurred:

a) Turbine Pressure Control switched from Electrical regulation to Nechanical regulation mhich remained in effect during Reactor cooldown.

b) ADO 'A and 080 Train Reco biners tripped and isolated. The '" Recombiner was reset and returned to service.

c) RPS Alternate Poner Supply breakers from MCC 08 tripped. The breakers were sub-sequently manually reset.

dl Spurious Reactor and Turbine Area Radiation alaras were received during the event.

The alarms were subsequently cleared and did not return.

e1 The PCIS group 2A. 3A. 5£ and 58 (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 responses experienced. which in each case, the equip ent had Undervoltage features or Seal-In circuitry.

An inspection of the Switchyard Nas performed immediately after the event Which revealed the loner section of "&a Phase bus bar to be broken off at the lower horizontal bus bar attach ent point. (Reference attached pictorial.) The upper insulator stack and T connec-tor which served as a tie point for the lower and upper bus bar sections was observed broken between the third and fourth insdlators with the fourth insulator and T connector still attached to the busmork. During the course of inspectiors the next orning (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 da age 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 co prised 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 fonce snapped the vertical bar out of the welded socket on the horizontal bus bar. This resulted in an open circuit in "So Phase and a 08C to "CO Phase flashover as the bus swung past the OCO Phase vertical bus bar. The combination of these two events initiated the Tie Line Differential Protective Relaving.

MC Form 3x6 (6-89)

-w s - OW woo* P inW nwmLMIrT hJo mVTwUvw %W-m naue Ulu (W EXPIRES 4/30/92 ESTIMATED BURDEN PER RESPONSE TO COMPLY WITH THIS INFORMATION COLLECTION REQUEST:

50.0 HRS. FORWARD CONENTS REGARDING LICENSEE EVENT REPORT (LER) BURDEN ESTIMATE TO THE RECORDS AND REPORTS TEXT CONTINUATION MANAGEMENT BRACH (P-530). U.S. NUCLEAR REGULATORY COMMISSION, KASHINGTON. DC 20555, AND TO THE PAPERWORK REDUCTION PROJECT (3160-0104), OFFICE OF MANAGEMENT 0 BUDGET. WASHINGTON. DC 20603.

UTILITY NAME (') DOCKET NO. (') LER HUNGER I6) PACE (I)

YEAR I SEQ. 0 I REVXU VERMONT YANKEE NUCLEAR POWER STATION d d d d dd 7I1 11oIoIs 1_ oEIo d OF c4 TEXT (If more space is required, use additional NRC Form 366A) C")

ANALYSIS 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 surined the reactor after receiving a Turbine Control Valve fast closure signal.

3. All other safety system responded as expected.

CORRECTIVE ACTIONS IWEDIATE CORRECTIVE ACTIONS

1. Imtediate corrective actions included recovering from the Reactor scraem utilizing appropriate plant procedures.

2. Efforts were immediately initiated to repair the 'B" and "C0 phase vertical bus work. A visual and thermography inspection was conducted of the entire Switchyard to identify any additional trouble spots. An additional insulator on the "*A Phase was found with arc dbmage and subsequently replaced.

3. The Main and Auxiliary transformers were Doble tested and oil samples were taken to assess any diaage 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 CORRECTIVE ACTIONS

1. The plant will meet with VELCO (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 recomendat'ons.

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 Comission in the past five years.

-RC Form 366A (6-89)

N * . S LER 91-05

U VERMONT YANKEE:

NucLEAR POWVER CORlPOR.ATION PO 8.- -', G -, #-; - ,I If ve W e-. .n' ! ',::1 " .'

. .. &.1;: .1', . . ..

W.

June 6, 1991 VYV U 91-135 U.S. Nuclear Regulatory Commission Document Control Desk Washington. D.C. 20555

REFERENCE:

Operating License DPR-26 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. Barkley, 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 r 475 Allendale Road sing of Prussia, PA 19406

. :.-A * .

F r'  ;.,-I. -8 .,, 19:I, i Fr - F-reau

NRC Form 366 U.S. NUCLEAR REGULATORY COMMISSION APPROVED OHS NO.3150-0104 (6-39) .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 REPORTS MANAGEMENT BRANCH (P-530), U.S. NUCLEAR REGULATORY COMMISSION, WASHINGTON, DC 20555, AND TO THE PAPERWORK REDUCTION PROJECT (3160-0104). OFFICE OF MANAGEMENT AND BUDGET, WASHINGTON, DC 20603.

FACILITY NAME D')

IOOCKET NO. (') I PAGE a VERMONT YANKEE NUCLEAR POWER STATION 10501 0 01217110 OF 09 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 (')

MON DAY YEAR YEAR ISEQ. 8 I REV MONT DAY YEAR FACILITY NAMES DOCKET NO.(S)

I . _ ~d sl aldlI OPERATING THIS REPORT IS SUBMITTED PURSUANT TO REQ'HTS OF lOCfR S: ONE OR MORE l" )

MODE f) N_ 20.402(b) 20.405(c) _ 50.73(a)(2)(iv) _ 73.71(b)

POWER l _ 20.405(a)(1)(i) 50.36(c)(1) H 50.73(a)(2)(v) 73.iifc)

LEVEL(..) 20.405(a)(1)(ii) 50.36(c)(2) 50.73(a)(2)(vii) _ OTHER

..... .......... 20.405(a.3()(2)1i) 50.73(a)(2)(viii)(A)

................ _ 20.405(a)(1)(iv) 50.73(a)(2)(ii) 60.73(a)(2)(viii)(B)

... ..... _ 20.405(a)(1)(v) _ 50.73(a)(2)(iii) 50.73(a)(2)(4) _

LICENSEE CONTACT FOR THIS LER (" )

MAKE T tELEPHONE NO.

. AREA ICODE DONALD A.-REID, PLANT MANAGER -CE2l Asl71 4 7171 1 COMPLETE ONE LINE FOR EACH COMPONENT FAILURE DESCRIBED IN THIS REPORT ("1)

CAUSE SYST COMPNT MFR REPORTABLE ..... CAUSE SYST COMPNT HEfR REPORTABLE .

TO NPRDS .. . TO NPRDS ..

X N N/A .........

X F K 1 N SUPPLEMENTAL REPORT EXPECTED (1')

N .....

EXPECTED N0O DA YR X YES (If yes, co plete EXPECTED SUBMISSION DATE) 1___ _ _ _ __

NO A051KAGI (LI1ot to 14UU spaces, i.e., approx. titteen single-space typewritten lines 1SUBMISSION DATE (" ) I d 1i

("3 A

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 10O. 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 115KV Breaker control circuitry during the restoration of a battery bank to Switchyard Bus DC 4A.

The cumulative effects of both (BFI) 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 )4124/91 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 04/25/91 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 prcsented in a supplemental report.

qRC For 366A U.S. NUCLEAR REGULATORY COMMISSION APPROVED OS NO.3160-0104 3 :45-9' .EXPIRES 4/30/92

.ESTIMATED BURDEN PER RESPONSE TO COMPLY WITH THIS INFORMATION COLLECTION REQUEST:

60.0 HRS. FOR1ARD COMMENTS REGARDING LICENSEE EVENT REPORT (LER) BURDEN ESTIMATE TO THE RECORDS AND REPORT TEXT CONTINUATION MANAGEMENT BRANCH (P-630), U.S. NUCLEAR REGULATORY COMMISSION, WASHINGTON, DC 20555, AND TO THE PAPERWORK REDUCTION PROJECT (3160-0104), OFFICE OF MANAGEMENT AND BUDGET. WASHINGTON. DC 20603.

UTILITY NANE (') DOCKET NO. (') LER NUMBER I PAGE '

I YEAR SEQ.* l REVY VERMONT YANKEE NUCLEAR POWER STATION (.9 d d d el d A sl - o oI Ig - lo odI( OF TEXT (If sore space is required, use additional NRC Form 366A)(")

DESCRIPTION OF EVENT 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 tOO, 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 345KV Breaker Failure Signal was received as a result of Breaker Failure Interlock (BFI) signals that occurred simultaneously in the 345KV Breaker 81-IT and 116 KV Breaker K-1 control circuitry.

The (BF!) signal from 116KV Breaker K-I initiated the following automatic system responses:

- Opening of 115KV Breaker K-186

- Opening of 345KV Breakers 379 and 381 The loss of 381 and 379 breakers removed all power sources to the Auto Transformer which in conjunction with the K186 trip resulted in a total loss of IS6KV power.

The (BFI) signal from 345KV Breaker 81-iT initiated the following automatic system responses:

- Generation of 345KV Breaker Failure Signal

- Opening of 345KV Breakers 381 and IT

- Lockout of Main Generator BGP and 86G6 relays, causing the Main Generator and Exciter Field breakers to open The Generator Primary and Backup Lockout relays initiated the following automatic system responses

- Main Turbine Trip

- Opening of 345KV Breaker B1-IT 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 cumulative effects of both (BFI) signals resulted in a total loss of 345KV and 116KV off-site power. However, an additional off-site power source was available through the Vernon Hydra Station Tie line. The 4KV Hydra station output, 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, was completed 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.

hRC Form 366A (6-89)

C Form 366A U.S. NUCLEAR REGULATORY COMMISSION APPROVED OHS NO.3160-0104 t ($-S9) *EXPIRES 4/30/92 ESTIMATED BURDEN PER RESPONSE TO COMPLY WITH THIS INFORMATION COLLECTION REQUEST:

60.0 HRS. FORWARD COGIENTS REGARDING LICENSEE EVENT REPORT (LER) BURDEN ESTIMATE TO THE RECORDS AND REPORTS TEXT CONTINUATION MANAGEMENT BRANCH (P-630), U.S. NUCLEAR REGULATORY COMHISSION, WASHINGTON, DC 20555, AND TO THE PAPERWORK REDUCTION PROJECT (3160-0104), OFFICE OF MANAGEMENT AND BUDGET, WASHINGTON, DC 20603.

UTILITY NAME V1) DOCKET NO. (ERA NUMBER (l) PAGE Is)

ISEO.

YYEARI - loEVd!

I EROTYANKEE NUCLEAR POWER STATION d -el dO f2f1-4iI9 IIoO IIo Iaor TEXT (If more space is required, use additional NRC Fore 366A) (")

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 "BS MG sets and receipt of Primary Containment Isolation Signals (PCIS)(*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 respective buses).

The loss of all power on 4KV Buses I thru 4 initiated the opening of Tie breakers 3T1 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 1448:45 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 time off-site 34SKV power was restored and backfed through the Station Auxiliary Transformer.

In response to the Scram. Operation personnel entered Emergency Operating Procedure OE 3100, fScraa Procedure" which governs reactor operation in a post-scram environment.

Iamediate 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 anual initiation of High Pressure Coolant Injection System (HPCI)('BJ), and startup of both RHR loops in the Torus Cooling mode. Both RPS MG sets were successfully restarted and APS buses reenergized at 1515 hours0.0175 days <br />0.421 hours <br />0.0025 weeks <br />5.764575e-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 />.

During 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) (*SN) 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 sumoary and discussion of those events:

• Energy Information Identification System (EIIS) component Identifier NRC Form 366A (6-89)

bloc Form 366A U.S. NUCLEAR REGULATORY CO"MISSION APPROVED ONS NO.3150-0104

) .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 REPORTS TEXT CONTINUATION MANAGEMENT BRANCH (P-530). U.S. NUCLEAR REGULATORY COMMISSION, WASHINGTON, DC 2055S5, AND TO THE PAPERWORK REDUCTION PROJECT (3160-0104), OFFICE OF MANAGEMENT AND BUDGET. WASHINGTON. DC 20603.

UTILITY NAME I') DOCKET NO. (a) LER NUMBER l I PAGE (S)

YEAR I RE I

. I IO VERMONT YANKEE NUCLEAR POWER STATIONd d dd1 1 d 21I 719 I XI - I lo I 91 -1 IoAId ' O I TEXT (If more space is required, use additional NRC Form 366A) lai DESCRIPTION OF EVENT (cont.)

A. Reactor Scrams on "Loa Reactor Water Level 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 nLo" level setpoint which initiated the Reactor scram. PCIS - Groups 2. 3S 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 2121 hours0.0245 days <br />0.589 hours <br />0.00351 weeks <br />8.070405e-4 months <br />. PCIS Groups 2 and 5 logic were reset at 2128 hours0.0246 days <br />0.591 hours <br />0.00352 weeks <br />8.09704e-4 months <br /> and Group 3 logic later reset at 2154 hours0.0249 days <br />0.598 hours <br />0.00356 weeks <br />8.19597e-4 months <br />.

B. Emergency Operating Procedure OE 3104, Tlorus Temperature and Level Control Procedure",

was entered at 1533 hours0.0177 days <br />0.426 hours <br />0.00253 weeks <br />5.833065e-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 OE 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. uRequired Cold Shutdown in 24 Hour" requirement. Due to the volume limitations of Torus water being processed through Radwaste, the Torus volume remained above 70,000 cubic ft. until 1925 hours0.0223 days <br />0.535 hours <br />0.00318 weeks <br />7.324625e-4 months <br /> on 04/24/91. The Technical Specification cold shutdown requirement and DE 3104 were excited at this time.

C. RCIC 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 NRC Form 366A (6-89)

hRC ForM 3S6 U.S. NUCLEAR REGULATORY COMMISSION APPROVED OHS NO.3150-0104 (6R9) *EXPIRES 4/30/92 ESTIMATED BURDEN PER RESPONSE TO COMPLY WITH THIS INFORMATION COLLECTION REQUEST:

60.0 HRS. FORWARD COMMENTS REGARDING LICENSEE EVENT REPORT (LER) BURDEN ESTIMATE TO THE RECORDS AND REPORTS TEXT CONTINUATION MANAGEMENT BRANCH (P-530), U.S. NUCLEAR REGULATORY CO"MISSION, WASHINGTON, DC 20555, AND TO THE PAPERWORK REDUCTION PROJECT (3160-0104). OFFICE OF MANAGEMENT ND BUDGET WASHINGTON DC 20603.

UTILITY NAME (') DOCKET NO. (') LER NUMBER (*) PAGE I')

YETRE_ SEP. F

- o RE _

,VEOT YANKEE NUCILEAR POWER STATION d d df d d 21 71 I_ _9 o I oO soIod0 OF Oft TEXT (If sore space is required, use additional NRC Fore 366A) I"_

DESCRIPTION OF EVENT (cont.)

The tVip 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 OAN 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 "0" 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 OB" Station 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 "CO and "D" station Air compressors were unavailable due to the LNP. The five (6) 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 "SB Station Air Compressor Trip, Operations personnel entered procedure ON 3146, "Low Instrument/Scram Air Header Pressure", and initiated imediate efforts to restart the uB 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, 11SKV Breaker KISS was manually closed which restored power to the Startup transformers via the Keene (K186) 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 4KV buses 3 and 4. This would ensure that power to 4KV buses 3 and 4 would not be interrupted if another LNP occurred.

At 1950 hours0.0226 days <br />0.542 hours <br />0.00322 weeks <br />7.41975e-4 months <br /> 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 pump on the wB" 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 />.

The 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 evvnt

- begin root cause analysis research NRC Form 366A (6-89)

. pC tor 366A U.S. NUCLEAR REGULATORY COISSION APPROVED OHS NO.3150-0104 A6-69)- EXPIRES 4/30/92 ESTIMATED BURDEN PER RESPONSE TO COWPLY WITH THIS INFORMATION COLLECTION REQUEST:

50.0 HRS. FORUARD COENtS REGARDING LICENSEE EVENT REPORT (LER) BURDEN ESTIMATE TO THE RECORDS AND REPORT!

TEXT CONTINUATION MANAGEMENT BRANCH (P-630), U.S. NUCLEAR REGULATORY COMMISSION. WASHINGTON. DC 20555, AND TO THE PAPERWORK REDUCTION PROJECT (3160-0104), OFFICE OF MANAGEMENT AND BUDGET WASHINGTON DC 2003.

UTILITY NAME ( ) DOCKET NO. ' NB) i PAGE is)

YNLEAR P TEVO YT VERMOIT YA(EE NSUCLEAR PWR STATION d1 d d dOdfllI . .. olo1 -10o l 0o if TEXT (If ore space is required, use additional NRC Form 366A) "I)

DESCRIPTION OF EVENT (cont.)

The recovery of off-site power began with the attempt to restore 116KV power from the 9,itchyard via 11SKV Breaker KIS6 and the Startup transformers. This was determined to be the easiest path in obtaining an off-site power source due to the need to close only one breaker. However, the KI Breaker BFI signal remained locked in due to a failed sener diode on the associated trip card and prevented the closure of K186. 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 K186 and subsequent restoration of power to 4KV buses 1 and 2. The Kl 1BF 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, Rhode Island.

After 115 KY power was established through the Keene K186 line, efforts to close Breaker Kl continued in order to establish a more reliable source of 115KV power through the Auto Transformer. However, due to communication problems between VY and the New England Suitching 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 attempting to close the Kl breaker, RENVEC was pursuing efforts to establish connections between the ring bus and the Northfield line by reclosing the S1-IT breaker.

In 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 backfeeding of the plant from the 345 yard through the Main Transformer. The effort to backfeedrwas possible due to the availability of tne Coolidge and Scobie lines.

The northfield line was unavailable due to the SI-IT SF1 signal. Again, the backfeed effort was hJapered by communication problems with REfVEC, 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.

Vermont TankeelTechnical Specification requirements for Off-Site Power were met during the Backfeeding effort by the availability of one off-site transmission line (Keene K18S line in service) and & 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 A and 5A. Significant repairs and testing were performed on the affected units.

Additional testing and repairs were initiated to the Stuck Breaker Failure Unit (S8FU) Logic trip cards for the 8lI-T, 301 and K1 breakers. The cards for 381 and K! breakers %ere found to have failed zener diodes. The S-tT (SSFU) relay was found to be functioning properly.

kRC Form 366A (6-09)

CFor*S6A U.S. NUCLEAR REGULATORY COMMISSION APPROVED MHS NO.3110-0104 (4

1l .EXPIRES 4/30/92 ESTIMATED BURDEN PER RESPONSE TO COMPLY WITH THIS INFORMATION COLLECTION REQUEST:

60.0 HRS. FORWARD COMMENTS REGARDING LICENSEE EVENT REPORT (LER) BURDEN ESTIMATE TO THE RECORDS AND REPORTS TEXT CONTINUATION MANAGEMENT BRANCH (P-530), U.S. NUCLEAR REGULATORY COMMISSION, WASHINGTON, DC 20565, AND TO THE PAPERWORK REDUCTION PROJECT (3160-0104), OFFICE OF MANAGEMENT

__ _ __.A______ _ AND BUDGET. WASHINGTON. DC 20603.

UTILITY AMME (D DOCKET NO. (') LER NUMBER I) PACE (2)

l SEQ. 6 lREYGS I

.YROHT YANKEE NUCLEAR POWER STATION d de d d do o2197 1 1I91It-l TEXT (If more space is required, use additional NRC Form 366A) ("

d looOfI DESCRIPTION OF EVENT (cont.)

Discussions with the manufacturer indicated that the zener diodes are no longer employed on newer revision trip cards and have recomnended the removal of the zener diodes based on their vulnerability to voltage transients. Based on this reco endation, the Maintenance Oept. has removed the zener diodes from these units in accordance with witten 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 U bus occurred when battery charger 4A-5A was disconnected from the DC-IA bus which rendered bus DC "A 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 (BFt) signals is attributed to the voltage transient which occurred on Bus DC A.

- A portion of the additional problems found with DC Bus A and SA battery chargers which ranged from shorted diodesfSCRs and blown surge suppressor fuses, mete 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 consideration all battery charger failure modes when floating a DC bus without a battery bank. The consequences 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 bus, both which have the potential to damage electronic circuitry.

The previous revision of the Guideline called for the two DC buses (4A & SA) to be cross-connected and fed jointly by the U/IA battery charger during the maintenance on the batteries. Following cross-connection, the Guideline required opening of the battery breakers. This evolution was successfully accomplished and the required work on the

%RC Form 36S (6-69)

RC Form 366A U.S. NUCLEAR REGULATORY CO9IISSION APPROVED OHS NO.3160-0104 (6-S9f EXPIRES 4/30/92 ESTIMATED BURDEN PER RESPONSE TO COMPLY WITH THIS INFORMATION COLLECTION REQUEST:

60.0 HRS. FORWARD CONHENTS REGARDING LICENSEE EVENT REPORT (LER) BURDEN ESTIMATE TO THE RECORDS AND REPORTS fEXT CONTINUATION MANAGEMENT BRANCH (P-530), U.S. NUCLEAR REGULATORY CO ISSION, WASHINGTON, DC 20565, AND TO THE PAPERWORK REDUCTION PROJECT (3160-0104). OFFICE OF MANAOEMENT WASHINGTON.

GANDPUET, DC 20503.

UTILITY NAME (')DOCKET NO. (LER NUMBSER PAGE (2)

• YEARI ISE. S I REV#

VEfRMONT YANKEE NUCLEAR POWER STATION ddd d X12I711 911 l 0oIl I-l 07 of 17 MtAI Irr more space is requirea. use aoditional KRC teorm 3bI ()

CAUSE OF EVENT (cont.)

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 4A/JA charger output breaker wsis 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 5A provided by battery charger LA/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 HA or 4A/SA battery chargers.

CONTRIBUTING CAUSES

1. 345KV and 115KV 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.

ANALYSIS 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 NAw and 0BE Station Air compressors. The analysis concluded that the 5 minute interval in which the O" 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. Al1 other safety systems responded as expected.

NRC Form 366A (6-89)

FtCore 36 U.S. NUCLEAR REGULATORY COHISSION APPROVED OM NO.3160-0104

.(-69) EXPIRES 4/30/92 ESTIMPTED 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 REPORT TEXT CONTINUATION MANAGEMENT BRANCH (P-530). U.S. NUCLEAR REGULATORY COMMISSION, WASHINGTON, DC 20565, AND TO THE PAPERWORK REDUCTION PROJECT (3160-0104). OFFICE OF MANAGEMENT ADUDGET, A B_ WASHINGTON. DC 20603.

UTILITY AMAE DCKET NO. (E)

DO) LER NUMBER (*) PAGE (8)

YEAR SEO. SI lREVS VW YANKEE NUCLEAR POWER STATION d_ OF d l7 1 TEXT (If more space is required, use additional NRC Form 366A) ( "})

CORRECTIVE ACTIONS SHORT TERN1 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 pertaining to battery switching operations.

LONG TERM 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 O5S/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.

ADDITIONAL INFORMATION There have been no similar events of this type reported to the commission in the past five years.

ATTACHMENTS Sketches: a. Switchyard Distribution

b. Switchyard DC Bus System NRC Form 366A (6-89)

NRC Form 366A U.S. NUCLEAR REGULATORY COMISSION APPROVED OHS NO.3150-0104 (69) 1EXPIRES 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 REPORTS TEXT CONTINUATION MANAGEMENT BRANCH (P-630), U.S. NUCLEAR REGULATORY COOISSION, WASHINGTON, DC 2055., AND TO THE PAPERWORK REDUCTION PROJECT (3160-0104), OFFICE OF PANAGEMENT

_______ _____OOiit__ _l')_8UWGEt.__ , S tN ONMDC 20603.

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TEXT CONTINUATION MANAGEMENT BRANCH (P-I)30, U.S. NUCLEAR REGULATORY COMMISSION. WASHINGTON. DC 20555, AND TO THE PAPERWORK REDUCTION PROJECT (3160-0104). OFFICE OF MANAGEMENT 1 . M0UWGETW ll NTON, DC 20 03.

UTILITY ME (D)OCKET . N. NUMBER I PAGE Is)

E CAo. SEO *I I OE

--yERrft TAEE NUCLEA POWER STATION d Oldd dIXflI . - olo1 1 TEXT (It more space is required, use additional NRC Form 3GM) 1")

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802)257-"71I July sit I99 vrv U 91-14 v.S. sUuoear Reglatory Omlmsml Document Control Desk Washington, D.C. 2051S IIWnPU1sa Operating License ODt-28 Docket Uo*. 50271 Reportable ocurrence no. LR 91-14 Dear Sirs AL defined by 10 dR 10.?0. US are reporting the attached Reportable Occurrence &S UM 91-24.

Very truly yours VXIT WAUZ N3CLSM M C MPRATION Donald A. Reid Plant mhnager c Regiooal Abinistrator uSM regions I 475 Allendale Road King of Pruse*i, PA 19405 s1 gj ^J 1 y~

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on 06/1St§1 at 2224 bours$ rwta m0S1 opertiton wfit eCtOt PM? at too%, a reator Scam occurred due to & turbine Control Vale Fast Clmure ac Generator Lad Reject resulting ft.. a loss of the 343K North 8vit Bus, She. vet vas Initiated duin a thmderstom in whch a lightning strike occurred om the 1 phase of thp 361 transmissulo He* betwen veroat Tanhei and Northfield. SO fault resulted 1. the opeOIng rf all 345K Air Trip Brear. (As).

ug te t a eet Reactor Scm aid corresponding Fetmaty Costa i-1et Isolation signal ICZS)(2JId) C ous 2d3 were received i4eto Low Reactor later level. te Reactor ws stmilisedin Not St the main Comimmer, Conden"te, aN feedwater system.

At 2100 boors on 06/1/ ftor e tor presurlastlo v completed, Sutdo Coolies ust the 'D' 11 oo the 3a loop vas Initatd ', t nrator reacned Cold Shutdov at O0 hours on 04/17/91. The reactor vis ret e to critical at 1413 hours0.0164 days <br />0.393 hours <br />0.00234 weeks <br />5.376465e-4 months <br /> oan 06/20/91.

she Root Cause of this event Is a defective (shorted) transiator In offste (Scoble Pond)

Protective Belayln Syst Cartier equipment. the need to perform additional testing of Cartier systms is being evaluated.

.IurgV Information Identification System (I1IS) Component Identifier

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This line subsequently tripped on ove lod, open th 1 TSD. Vith all 345KV ATss open, all load paths for Vermont nkee's outp t ed which resulted In a Generator Load Reject and subsequent plat scram.

Following the Generator toa Reject and Turbine Control Valve Vast Closure, plant bases remained connected to the 5am Generator via the Aux Transformer for approximately 30 seconds at which point the Turbine tripped fro a "Lo Scrm Air Beader Pressure Time Delayed Signal.

Varing the first 10 seconds of this interval, plant buses experienced voltage oscillations Wil the bin Generator voltage output attpted to egulat during the trasition from 100I to approximately 5S load. The voltage o lrienced resulted In the folloving major system responses:

- Primary Contaioent ISolton S em (PCIS)(*10)Groups 1s, 2, 3U, SA and 3D vere received due to lov 12OAC Instrumet bus voltag, resulting in the closure of Group 5 Isolation valves as required.

"At' and '5'Station Air Compressors tripped due to low t20VAC Instrument bus voltage. Both air compressors were restarted at 2233 hours0.0258 days <br />0.62 hours <br />0.00369 weeks <br />8.496565e-4 months <br />.

• Reactor Recirculation Units (BlUe) 2 and 4 Tripped due to dropout of a 120VAC Dryvell Cooling and Control Room Air Conditioning Blocking relay from lo voltage. Both RRUs were restarted at 2233 hours0.0258 days <br />0.62 hours <br />0.00369 weeks <br />8.496565e-4 months <br />.

"I*B'and *CO Reactor Feadwater Pumps Tripped on Low Suction Pressure resulting from transients In the Condensate System which vere caused by the undervoltage conditions. Feed flow was restored within 10 seconds.

• "A'and '5 Recire Pump Breakers opened du to Low Lube Oil tPessure. The loss of Lube Oil was a result of blown control circult fuses.

" A" and "5" Advanced Off Gas (AOG) Recombiners tripped due to low 120VAC Instrument bus voltage. this resulted In the blowout of a Steam Jet Air 3!ector (SJAE) Rupture Disc.

In addition to the (louv oltage) received PCIS signals, a decreasing 127 Inch WLO" Reactor Vater level was experienced seconds Into the event, at 2224t29 hours, generating a Reactor Scram and remaining PCIS Group 2D and 3D Isolation signals resulting in the required Group 2 and 3 Isolations. The water level reached a low of 122 Inches and Is attributed to void collapse from the Initial Scram.

• Inergy Information Identification System (311S) Component Identifier

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Approximately 10 seconds Into the event, at 2224t32 hours, the 381 ATS reclosed which resnergised the Auto Transformer. The 379 ALT reclosed 12 seconds later at 2224s44 hours5.092593e-4 days <br />0.0122 hours <br />7.275132e-5 weeks <br />1.6742e-5 months <br />.

Coincident with the turbine trip at 2224:50 bours, a Generator Lockout was initiated which resulted In Fast Trusfer of plant buses to the Startup Transformers. Pith reliable 115KV power available from the Auto Transformer, 4XV and 480V HsU voltages remained stable from this point on.

in response to the Scram, Operations personnel entered lbergency Operating Frocedure 01-3100 "cram Procedure' which governs reactor operation in a post-scram environment. Operators noted during the Scrams that approxImately 25 of the Control Rods lacked Ofull InO indication (the associated rod display was bluak). Reactor power was verified to be less than 2, by Average Power RIngo oaltor (AMRE) downscale indication. This condition prompted the entry nteo lbrgency Operating Procedure 03-3101 "Reactor Pressure Vessel (IRV) Control trocedure' 1 hilch a Banu Scram vas initiated at 2226 hours0.0258 days <br />0.618 hours <br />0.00368 weeks <br />8.46993e-4 months <br /> and subsequently reset at 2228 hours0.0258 days <br />0.619 hours <br />0.00368 weeks <br />8.47754e-4 months <br />. Upoa resetting of the Scram, all rods indicated '00' and 01-3101 was exited. The loss of indicatlon for a portiou of the Control Rods Is attributed to a Iomn phenomena called rod overtravel In which a loss of position indication can occur If a control rod inserts slightly put the full ia position resulting In a misalignment of the corresponding position indication switches.

During the event, Reactor pressure and level were maintained using the Main Condenser, Condensate, and leedwater 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 using the OD" 111 pump on the l' 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 06117191. The reactor was 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.

owe Root Cause of this event Is a defective (shorted) transistor in offsite (Scoble Pond)

Protective Relaying Sytem Carrier equipment. The lightning strike which occurred on the 'B' thase of the 381 ftansmis-ion lnMe between VT and Northfield, Na. would normally have only resulted In an isolation of the 381 line. lowever, the defective component In the Scoble Pond Carrier equipmet caused a subsequent loss of the 379 line. This touted the full Generator output through the 340 (Coolidge) line. The Coolidge line cannot handle full generator output end tripped out on overlod which resulted in a loss of the 3450V yard and caused the Reactor to Scram on Generator Load Reject.

After the plat Scram, an extensive testing and troublshooting effort was performed by Termont Yankee and Rev Ingland lonr Service Co. (NESMCO) to determine the cause of the Scobie Line Carrier trip. It was found that the the equipment on the VT end operated as designed and sent a Carrier block esigl to Scoble to prevent tripping. Although the signal was received at Scoble Pond, the trip signal was not blocked. A failed transistor in the Carrier equipment logic section prevented the blocking signal from reaching the tripping logic. Since the tripping logic did not see a blocking signal It caused the Scoble line to trip at Scoble Pond and Versont Yankee.

Mc Veta Ilia V.I. NUCILEAR a @AUTOaT CO@1a51on APPnROVED o05 gO. 3150-0104 t4391 3a11as3 4/30/32 BST!RATID BUI.DIN PER RIAPONI TO COEPLT WS1tE tS ZXP M0AZOW COLLUCIZOU 22QUSIs 50.0 E3S. FORWARD COMIEES ASOARDIRO BURDEN S31313 so 1X1 USCOIDI AND 9310118 31XAAO3XX3 L&CEUSEU En3 REPORT (LLlnIa cs (P-S3010 U.S. UUCI.a3 ft2@ULATOT 931? cuuaZaszoN coMMIsSIoN, WASa3N1S3o, DC 20555, 13 sDo Tug WAPUWVOZI a3vcZo0 PROJECT (3160-0104). orrict O0 1AORNS33 aMD SUDOES, WASX33O82 0, DC 20603.

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1. Lightning strike on the 3 phase of the Northfleld line vas the contributing cause to the event.

The events had minimial adverse safety implications.

1. The Reactor Protective System operated as designed and scramed the reactor on Generator Load Reject resulting from the loss of 345KV pover.

2. fast transfer to an off-site source occurced as designed upon receipt of a Generator Lockout.

3. All other safety system responded as expected.

- Tm _EX3 m Imediate corrective actions Included recovering from the reactor scrams, troubleshooting and repair of the Scobie *ond equipment, and reactor stabilization utilizing appropriate plant procedures.

ims: *mw x ACTr VT Maintenance Department and TELCO Ivitchyard Engineers vill evaluate testing requirements for SvItchyard Carrier systems.

Th above Long Term Corrective Action vill be completed by 11/01/91.

there have been no similar events of this type reported to the co mission in the past five years.

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19 Entergy Nuclear Northeast Entergy Nuclear Operations, Inc.

w-m--E Entergy Vermont Yankee

- 185 Old Ferry Rd.

P.O. Box S0 Brattleboro. VT 05302 Tel 802-257-5271 August 16, 2004 BVY 04-080 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 2004.003-00 As defined by I0CFR50.73, we are reporting the attached Reportable Occurrence LER 2004-003-00. No Regulatory Commitments have been generated as a result of this event.

Sincerely, Entergy Nuclear Operations, Inc.

Vermont Yankee Kevin Bronson General Manager cc: USNRC Region I Administrator USNRC Resident Inspector - WNPS USNRC Project Manager - VYNPS Vermont Department of Public Service

.I

NRC,§ORM 366 U.S NUCLEAR REGULATORY APPROVED BY CMB NO. 3150-0104 EXPIRES 7-31.2004 J 1) COMMISSION Estmled hidn e KSP- I GM* ft th MAMW kft=IM ndw n MqW= 50 hoUtRepWW hssoml wed = lraporabd hbb 1 kenir9 pe aWd led back b hy.S m pn&%;bidm UnMb RIu R U uferdlanchfr4 ES). U.S.&Sear R14hAy Cu ~Wefttm DC2555.

LICENSEE EVENT REPORT (LER) , attarCcOtolsn4 AN UtahWd

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1. FACILITY NAME VERMONT YANKEE NUCLEAR POWER STATION (VY)

2. DOCKET NUMBER 05000271 1of 4

3. PAGE

4. TITLE Automatic Reactor Scram due to a Main GeneratorTrlp as a result of an Iso-Phase Bus Duct Two-Phase Electrical Fault S. EVENT DATE 6. LER NUMBER _ 7. REPORT DATE S. OTHER FACILITIES INVOLVED

_FACIUrTY NAME DOCKET NUMBER MO DAY YEAR YEAR SEOUENTIAL REV MO DAY YEAR 05000-uM-ER NO WA IFACILUTY NAME DOCKET NUMBER 06 18 2004 2004 003 00 08 16 2004 WACI-5000

9. OPERATING 11. THIS REPORT IS SUBMITTED PURSUANT TO THE REQUIREMENTS OF 10 CFR J: (Check all that apply)

MODE N [ 20.2201(b) 1,202203(a(31)) [E s0.73ta)C2)(0iXB) 60.73(a)(2)(Ix)(A)

10. POWER I] 20.221(d) E] I0.2003(aX4) [] 50.73(a)X2)(ifl) 50.73(a)X2)(x)

LEVEL 100 [ 120.2203(a)(1) 1 .036(c)(1XI)(A) MI 60.73(a)(2)(v)(A) 73.71 (a)(4)

.  ; Li 202=1(a)X2)1) O 50.36(c)(1)U(A) Of 50.73(aX2)(y)(A) 73.71(a)(5)

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- 20.2203{a)(2Xv!) O 5.73(a)(2)XC) O ____(a_2)__i_(A)

.,. 202203(a)t3)1) Ul* 50.73(a)X2)U)(A) 9] 50.73(a)(2XD)(B)

12. LICENSEE CONTACT FOR THIS LER NAME TELEPHONE NUMBER (Include Area Code)

Kevin Bronson. General Manaaer 1 802 257-7711

13. COMPLETE ONE UNE FOR EACH COMPONENT FAILURE DESCRIBED IN THIS REPORT CAUSE I SYSTEM ICOMPONENT MANU-FACTURER REPORTABLE TO EPIX .

CAUSE SYSTEM COMPONENT MANU-FACTURER REPORTABLETO EPIX E EL I FCON P295 Yes E EL IPBU1 P295 Yes E EL I DUC P295 Yes .EL LAR G066 I Yes

14. SUPPLEMENTAL REPORT EXPECTED 115.EXPECTED MOtH DAY EAR YES (ifyes, complete EXPECTED SUBMISSION DATE) NO SUBAISSION D

IW DAT lNA I W1A I N/A

16. ABSTRACT (Limit to 1400 spaces, i.e., approximately 15 single-spaced typewritten lines)

On 06118104 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. Offsite power sources 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 'C" 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 extinguished the oil fire at 0717. At 1245, the Unusual Event was terminated. The electrical grounds that Initiated the event were caused by loose material Inthe "B6 Iso-phase bus duct as a result of the failure of a flexible connector. The grounds raised the voltage on the OA Iso-phase bus contributing to the failure of the WA" phase surge arrester. The root causes of the event were determined to be Inadequate preventative maintenance on portions of the Iso-phase bus and failure to monitor age related degradation on the surge arresters. There was no release of radioactivity or personnel Injury during this event.

NHC FORM t to-20011

NRCLFORM 366A U.S. NUCLEAR REGULATORY COMMISSION (14001)

LICENSEE EVENT REPORT (LER)

1. FACILITY NAME 2. DOCKET 6. LER NUMBER 3. PAGE SEOUENMIAL REVISION VERMONT YANKEE NUCLEAR NUMBER NUMBER POWER STATION (VY) 05000271 2004 - 003 - 00 2 OF 4

17. NARRATIVE (if more space Is required,use additionalcopies of NRC Form 366A)

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 'B' phase faulted to ground Inthe low voltage bushing box on top of the Main Transformer (EIIS=XFMR), and the 'At phase faulted to ground Inthe surge arrester cubicle of the Generator Potential Transformer (PT) Cabinet through the 'A7 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 'A' and 'BE phases, arcing and ionization Inthe 'B" phase low voltage bushing box carried over to the 'CT 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 'C' 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 personnel Injuries.

The VY 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 completely extinguished at approximately 0717and re-flash watches were established. Offslte power sources 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. Inaddition 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 10 CFR 50.72(b)(2)(lv)(B). At 1245, the Unusual Event was terminated.

The isophase bus flexible connector that failed (expansion joints) was part of the original bus supplied and designed by H.K. Porter, Drawing Numbers 6-191144 & 6-191146. All flexible connectors were replaced with an upgraded design supplied by Delta-Unibus. The surge suppressors were GE Alugard Station Arrestors, Model Number 9L1 I LAB, installed as original plant equipment. All of the surge suppressors were replaced.

CAUSES:

The electrical grounds that Initiated the event were caused by loose material Inthe 'B1iso-phase bus duct as a result of the failure of a flexible connector (EIIS=FCON) that allows the Iso-phase bus to thermally expand and contract. The grounds raised the voltage on the 'A Iso-phase bus, contributing to the failure of the "A' phase surge arrester. The root causes of the event were determined to be Inadequate preventative maintenance for cleaning and inspections during outages and failure to monitor age related degradation.

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 or the presence of loose/foreign material with the potential to ground the bus. The need for NRCFOAs IllJ

NRC.FORM 366A U.S. NUCLEAR REGULATORY COMMISSION LICENSEE EVENT REPORT (LER)

1. FACILITY NAME 2. DOCKET 6. LER NUMBER 3. PAGE SEQUENTIAL

. RREVISION VERMONT YANKEE NUCLEAR YEAR jE,,NUMSER NUMBER POWER STATION (VY) 05000271 2004 003 - 00 3 OF 4

17. NARRATIVE (Ifmore space Is required, use additionalcopiesof NRC Form 3664)

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 Inthe preventative maintenance Inspection performed during RFO-24.

The A 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 A iso-phase bus and not performing preventative maintenance necessary to monitor age related degradation of the WA surge arrester. Industry experience has revealed that surge arrestors degrade over time due to a combination of age, service environment and service conditions.

Periodic Inspectionftesting could have detected degradation and allowed replacement prior to failure.

A contributing cause to both of the conditions previously described was identified by the Investigation team as a failure to effectively use industry OE to prevent similar events from occurring at VY. 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-112784 (1999) for the 22 kV flexible connectors and periodic Inspections/testing was not utilized.

ASSESSMENT OF SAFETY CONSEQUENCES:

All safety systems and fire suppression systems responded as designed. The reactor was shutdown without incident. Offsite power sources and station emergency power sources were available at all times throughout the event. Emergency reponse personnel acted promptly to prevent the fire from significantly damaging or breeching 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 extiguished at 0717.

3. Completed the Initial notification to the States of Vermont, New Hampshire and Massachusetts at 0721.. - . a - *. *

4. Notifed 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 this event 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.

NRC FORM 366A (1-20013

N4RC FORM 366A U.S. NUCLEAR REGULATORY COMMISSION (1-2001)

LICENSEE EVENT REPORT (LER)

1. FACILITY NAME 2. DOCKET 6. LER NUMBER 3. PAGE

.SEQUENTIAL REVISION VERMONT YANKEE NUCLEAR YEAR NUMBER NUMBER POWER STATION (VY) 05000271 2004 - 003 - 00 4 OF 4 NARRATIVE (I1more space Is required, use addilonal copies vI NRC Fonn 366A) (17)

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 energizin ft122kV bus.

3. A cleanliness Inspection wasrhmid and documented as part of Iso-Phase Bus Duct Modification.

4. Maintenance department personnel Inspected the cooler and leads fans for foreign material. Following 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 Isophase bus duct system was monitored after assembly with the fans running to ensure that Vibration levels are 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.

Long Term:

1. Include the 22kV surge arresters and capacitors in the preventative maintenance program and define periodic testing requirements.

2. Revise the 22kV Isophase bus preventative maintenance program and periodic Inspection requirements as necessary to Improve performance and to prevent recurrence of this event.

3. Complete the testing of selected components Involved In the event to validate the Initial conclusions of the root cause Investigation team, and revise the root cause analysis report If needed.

ADDITIONAL INFORMATION:

No similar events with a related cause have occurred at Vermont Yankee.

NWG FORM 366A II-=I)

20

~

~

Entergy Nuclear Northeast Entergy Nuclear Operations, Inc.

Vermont Yankee P.O. Box 0500 185 Old Ferry Road Brattleboro, VT 05302-0500 Tel802 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 cc: USNRC Region I Administrator USNRC Resident inspector - VYNPS USNRC Project Manager - W N P S Vermont Department of Public Service

NRC FORM 366 U.S. NUCLEAR REGULATORY COMMISSION APPROVED BY OMB: NO. 315040104 EXPIRES: 06/3012007 (620X) 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 burde estimate to VW Records and FOIAlPrivacy Srvice Brranch T-5dF52), U.S.

NucearRealatry ommssin. ashngtn. C 2565000 *or byInternet LICENSEE EVENT REPORT (LER) Desk Oficer O fadothe ot natilon Budget. Washigton. C20503. lIe means used to Impose an information collection does not disply a curreny valid OMB control number, the NRC may not conduct or sor, and a person not required to respond to, the

___Infomation

_ collecion.

1. FACILITY NAME 2. DOCKET NUMBER 3 PAGE VERMONT YANKEE NUCLEAR POWER STATION (VY) 05000 271 [ OF 4

4. TITLE Reactor Trip Caused by an Electrical Insulator Failure In the 345 kW Swltchyard due to a Manufacturing Defect 5 EVENT DATE 6. LER NUMBER 7. REPORT DATE 6. OTHER FACILITIES INVOLVED MONTH DAY YEEAR YAR NUMBER NO. MONTH DAY YEAR WA 05000 FeaT NAMEDOCKEr NUMEF 07 25205 001 .00 2005 05000

9. OPERATING MODE 11. THIS REPORT IS SUBMITTED PURSUANT TO THE REQUIREMENTS OF 10 CFR 5: (Check all that apply)

O 20.2201(b) Q 20.2203(aX3)(l) 50.73(a)(2Xi)(C) a 50.73(a)(2)(vil)

N Q 20.2201(d) 0 20.2203(a)(3)(1i) 0 50.73{a)(2)OXiA) D 50.73(a)(2xvEri)(A) 20.2203(a)(1) 0 202203(a)(4) 50.73(aX2)Xi)(B) 0 50.73(a)(2)(vAUX1) 0 20.2203(a)(2)(i) 50.36(c)(1)1)(A) a 50.73(a)(2)(11l) 0 6O.73(a)(2)ixXA)

10. POWER LEVEL 0 20.223(a)(2)(I) 0 50.36(cX1)()(A) El 50.73(a)(2Xiv)(A) C 60.73(a)(2)(x)

O 20.2203(a)(2)(i1i) Q 50.36(cX2) 0 5o.73(aX2XvXA) D 73.71(a)(4) 100 0 20.2203(a)(2)(v)

O 202203(a)(2)(v) 50.46(aX3)(9i) 0 5.73{aX2)(i)(A) a 60.73(a)(2)(v)(B) 50.73(aX2)(V)(C) Qa 73.711(a)(5)

OTHER o 20.2203(a)(2)(vi)

_____________or 0 60.73(a)(2)(8B) Q 50.73(a)(2Xv)(D) Specify 36Abstract In NRC oram=6A below

12. LICENSEE CONTACT FOR THIS LER CONTACT NAUE l TELEPHONE NUMBER (Ohdu Am Code)

William F. Maguire, General Manager Plant Operations l(802) 257-7711

13. COMPLETE ONE LINE FOR EACH COMPONENT FAILURE DESCRIBED IN THIS REPORT CAUSE SYSTEM COMPONENT MANUR REPORTABLE CAUSE SYSTEM COMPONENT MANU- REPORTABLE IFACTURER TOEPIX IFACTURER TO EPIX B FK INS LOSS Y FKMOD S18 Y

14. SUPPLEMENTAL REPORT EXPECTED 15. EXPECTED MONTH

_ Yr I SUBDATE MISSION OYES (Iryes, complete I& EXPECTED SUBMISSION DATE) a NO ABSTRACT (tin&to 1400 spaces, Lo., approximately 15setngie..Pacedtypewdtn Snes)

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, ACE 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 41 868. 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 FORM 6 0-2004) PRINTED CMRECYCLED PAPER NRC F-OM 366 602004) PRINTED ON! RECYC1.D PAPEAR

NRC FORM 36A U.S. NUCLEAR REGULATORY COMMISSION LICENSEE EVENT REPORT (LER)

1. FACILITY NAME 2. DOCKE 6. LER NUMBER 1 PAGE YEA sEaugn A REVISION VERMONT YANKEE NUMBER NUMBER NUCLEAR POWER STATION (VY) 05000 271 2 OF 4 2005 - 001 - 00

17. NARRATIVE (ifmore spac ismqutmd~use addnal cpes ofNRC Fom 3664)

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] failed, causing a failure of the NCO phase on the 345 kV Motor Operated Disconnect (MOD) Switch T-1 [EIIS&, MODFK]

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 10CFR50.73(a)(2)(Iv)(A) as an event that resulted In the automatic actuation of systems listed within IOCFR50.73(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 "Co 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 "Cm 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 *Cm Phase 87/TL1 Differential Relay senses the development of a TC Phase to Ground Fault that Is a result of the arcing at the T-1 disconnect caused by the insulator failure.

2. The Generator 86/TL1 Tie Une Lockout Relay actuated due to a trip signal from the associated 'C0 Phase 87/TL1 Differential Relay. [T=0J

3. Main Generator Breakers 81 -1T and 1T 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. [OT=9O 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)(1v)(A).

8. WAand OC0Reactor Feedwater Pumps are automatically tripped 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 (14-01)

NRC FORM 366A U.S. NUCLEAR REGULATORY COMMISSION LICENSEE EVENT REPORT (LER)

1. FACILITY NAME 2. DOCKET . LER NUMBER 3. PAGE YEAR SEQUENTIAL REVISION VERMONT YANKEE I NUMER NUMBER 3 NUCLEAR POWER STATION Orf) 05000271 j 2005 - 001 - o 3 OF 4

17. NARRATIVE (If moe spc Isrqtuf4, use addienal cYes of NRC Fai 3684

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. OA Service Water Pump Starts. [T=1 second]

11. 5B"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 0B 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 WARecirculation 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 10CFR50.72(b)(2)(iv)(A)

The following operator actions were taken to stabilize the plant

1. Placed the Mode Switch to Shutdown. [T=21 seconds]

2. Started "BO Reactor Feedwater Pump to re-establish normal level control. JT=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 investigation 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. CAose examination of the void NRC FORM 366A(142001)

NRC FORM 366A U.S. NUCLEAR REGULATORY COMMISSION (12001)

LICENSEE EVENT REPORT (LER)

1. FACILITY NAME 2. DOCKET 6. LER NUMBER 3. PAGE YEAR SEQUENTIAL REVISION VERMONT YANKEE I NUMBER NUMBER NUCLEAR POWER STATION (VY) 05000 271 4 OF 4 2005 - 001 - 00

17. NARRATIVE (11mNi ace XIs wqd~use addimil cqiasof ARC Form 3584 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 Wits 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 1T-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 J80104-70 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/i 3/91 at VY that was reported to the NRC as LER 91-005-00 on 04112191, "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 FORM 368A (12001)