ML082600577

Attachment 1, Applicable Portions of the U.S. Nuclear Regulatory Commission (NRC) and Davis-Besse Nuclear Power Station (DBNPS) Improved. Technical Specification (ITS) Conversion Website

ML082600577
Person / Time
Site:	Davis Besse
Issue date:	05/30/2008
From:	FirstEnergy Nuclear Operating Co
To:	Office of Nuclear Reactor Regulation
References
L-08-241, TAC MD6398, TAC MD6399, TAC MD6400
Download: ML082600577 (747)

Text

{{#Wiki_filter:Attachment 1 L-08-241 Applicable Portions of the U.S. Nuclear Regulatory Commission (NRC) and Davis-Besse Nuclear Power Station (DBNPS) Improved. Technical Specification (ITS) Conversion Website

Chapter 1.0 RAIs NRC ITS Tracking Pagel1 of 3

  ~Return to View Menu~ I      Print Document RA8I Screening Required: Yes                       Status: Closed This Document will be approved. by: Tim            Regulatory Basis must be included in Comments Kobetz                                             section of this Form This document has been reviewed and                Yes information in this question contains NO SUNSI sensitive material (the checkbox to the right must be selected before this question can be submitted)

NRC ITS TRACKING NRC Reviewer ID 200711281417 Conference Call Requested? No Category In Scope ITS Section: TB POC: JFD Number: Page.Number(s): ITS 1.0 Carl Schulten None 47 Information ITS Nunmber: 051:1 DOC Number: Bases JFD Number:" 1.0 None A.17 None Identify the implementation of "administrative controls" as either a commitment by the licensee, an incorporated reference in Administrative Controls Section 5.0 of TS, or another acceptable method in order to assure safe operation of the plant and continued compliance with 10 CFR 50.36(d)(2) (i), "Limiting conditions for operation" is met by following any remedial action permitted by the technical specifications.Completion Time Example 1.3-3 discusses Completion Time conventions for Conditions of one Function X train inoperable; one Function Y train inoperable, one Function X train and one Function Y train inoperable. DOC A17 discusses the explanatory information added for all of Section 1.3.

                  "Completion Times," and states that "the addition of these sections does not add or delete technical requirements, and will be discussed specifically in those Comment. Technical Specifications where application of the added sections results in a change."

The last paragraph (Attachment 1, Volume 3, Rev. 0, Page 47 of 71) is adopted in ITS and contains the following licensee commitment:

                  "It is possible to alternate between Conditions A, B, and C in such a manner that operation could continue indefinitely without ever restoring systems to meet the LCO. However, doing so would be inconsistent with the basis of the Completion Times. Therefore, there shall be administrative controls to limit the maximum time allowed for any combination of Conditions that result in a single contiguous occurrence of failing to meet the LCO. These administrative controls shall ensure that the Completion Times for those Conditions are not inappropriately extended."

Regulatory Basis - 10 CFR 50.36(d)(2)(i), "Limiting conditions for operation" http://www.excelservices.com/exceldbs/itstrackdavisbesse.nsf/1 fddcea 1Od3bdbb585256e... 5/30/2008

NRC ITS Tracking Page 2 of 3 is met. 10 CFR 50.36(d)(2)(i) specifies: that "Limiting conditions for operation are the lowest functional capability or performance levels of equipment required for safe operation of the facility. When a limiting condition for operation of a nuclear reactor is not met, the licensee shall shut down the reactor or follow any remedial action permitted by the technical specifications until the condition can be met. When a limiting condition for operation of any process step in the system of a fuel reprocessing plant is not met, the licensee shall shut down that part of the operation or follow any remedial action permitted by the technical specifications until the condition can be met." Issue ýDate 111/28/2007 j Close Date [03/311/2008 Logged in User: Anonymous

ýResponses Licensee Response by Jerry          ITS 1.3, Example 1.3-3 (Volume 3, Page 47) states that there shall Jones on 12/20/2007                 be administrative controls to limit the maximum time allowed for any combination of Conditions result in a single contiguous occurrence of failing to meet the LCO. Davis-Besse has not yet determined the administrative controls that will be employed to meet this requirement. Davis-Besse will probably contact other utilities that have adopted this requirement (e.g., Monticello) to determine possible ways to meet the requirement. Furthermore, the method may not be developed and implemented prior to ITS Amendment approval. However, Davis-Besse is required to have the method developed and approved prior to implementation of the ITS. Since ISTS 1.3, Example 1.3-3 does not provide any specific requirements concerning the administrative controls, Davis-Besse believes that ITS approval without the administrative controls developed is acceptable. This is consistent with many other ITS requirements that require the development of a program to, meet an ITS requirement (e.g., the new ITS 5.5.14, Safety Function Determination Program). Furthermore, since ITS 1.3 specifically states that there will be administrative controls, and ITS 1.3 is part of the Technical Specifications, there is no need for a licensee commitment to comply with the Technical Specifications.

Technical Specifications are already required to be met. NRC Response by Carl Schulten Per your response, Any further review to approve use of the on 01/30/2008 second comletion time TS changes are on hold for the Davis-Besse determination of the Administrative Controls that willbe employed to meet this requirement. The NRR staff notes that Commanche. Peak TS changes which eliminated the second completion time included adminsitrative controls to ensure completion times for failing to meet the LCO are not improperly extended. Licensee Response by Bryan This' response supersedes the response dated 12/20/2007.. ITS 1.3, Kays on 03/20/2008 Example 1.3-3 (Volume 3, Page 47) states that there shall be administrative controls to limit the maximum time allowed for any combination of Conditions that result'in a single contiguous http://www.excelservices.coom/ekceldbs/itstrackdavisbesse.nsf/1 fddceal Od3bdbb585256e... 5/30/2008

NRC ITS Tracking Page 3 of 3 occurrence of failing to meet the LCO. Davis-Besse will implement the administrative controls as a commitmentto the NRC. This commitment will be documented in the supplement to the ITS Conversion Amendment. Date Created: 11/28/2007 02:17 PM by Carl Schulten Last Modified:' 03/31/2008 02:02 PM http://www.excelservices.com/exceldbs/itstrackdavisbesse.nsf/1 fddceal Od3bdbb585256e... 5/30/2008

NRC ITS Tracking Page I of 2 I Return to View Menu, Print Docmn RAI Screening Required: Yes Status: Closed This Document will be approved by: Tim Regulatory Basis must be included in Comments Kobetz section of this Form This document has been reviewed and Yes information in this question contains NO SUNSI sensitive material (the checkbox to the right must be selected before this question can be submitted) NRC ITS TRACKING NRC Reviewer ID 200711281544 Conference Call Requested? No Category In Scope

                   !TS... Section:.         TBTPOC:           JFD Number:        Page Number(s);

ITS 1.0 Carl Schulten None 47 Information ITS Nurnbe0: 01:1 DOC Number: Bases JFD Number: 1.0 None A.17 None Identify the administrative controls that will be used to limit the maximum time allowed for any combination of Conditions that result in a single contiguous occurrence of failing to meet the LCO and that will also ensure that the Completion Times for those Conditions are not inappropriately extended. This information is needed to assure safe operation of the plant and continued compliance with 10 CFR 50.36(d)(2)(i), "Limiting conditions for operation" is met by following any remedial action permitted by the technical specifications. Discussion Completion Time Example 1.3-3 discusses Completion Time conventions for Conditions of one Function X train inoperable; one Function Y train inoperable, one Function X train and one Function Y train inoperable. DOC A17 discusses the explanatory information added for all of Section 1.3. Comment "Completion Times," and states that "the addition of these sections does not add or delete technical requirements, and will be discussed specifically in those Technical Specifications where application of the added sections results in a change." The last paragraph (Attachment 1, Volume 3, Rev. 0, Page 47 of 71) is adopted in ITS and contains the following licensee commitment:

                    "It is possible to alternate between Conditions A, B, and C in such a manner that operation could continue indefinitely without ever restoring systems to meet the LCO. However, doing so would be inconsistent withthe basis of the Completion Times. Therefore, there shall be administrative controls to limit the maximum time allowed for any combination of Conditions that result in a single contiguous occurrence of failing to meet the LCO. These administrative controls shall ensure that the Completion Times for those Conditions are not http://www.excelservices.comi/exceldbs/itstrackdavisbesse.nsf/1 fddcea 1Od3bdbb585256e... 5/30/2008

NRC ITS Tracking Page 2 of 2 inappropriately extended." Regulatory Basis - 10 CFR 50.36(d)(2)(i), "Limiting conditions for operation" is met. 10 CFR 50.36(d)(2)(i) specifies that "Limiting conditions for operation are the lowest functional capability or performance levels of equipment required for safe operation of the facility. When a limiting condition for operation of a nuclear reactor is not met, the licensee shall shut down the reactor or follow any remedial action permitted by the technical specifications until the condition can be met. When a limiting condition for operation of any process step in the system of a fuel reprocessing plant is not met, the licensee shall shut down that part of the operation or follow any remedial action permitted by the technical specifications until the condition can be met." Issue tDate 11/28/2007 Close Date 03/31/2008 Logged in User: Anonymous

'Responses Licensee Response by Jerry         ITS 1.3, Example 1.3-3 (Volume 3, Page 47) states that there shall Jones on 12/06/2007                be administrative controls to limit the maximum time allowed for any combination of Conditions result in a single contiguous occurrence of failing to meet the LCO. Davis-Besse has not yet determined the administrative controls that will be employed to meet this requirement. Davis-Besse will probably contact other utilities that have adopted this requirement (e.g., Monticello) to determine possible ways to meetihe requirement. Furthermore, the method may not be developed and implemented prior to ITS Amendment approval. However, Davis-Besse is required to have the method developed and approved prior to implementation of the ITS. Since ISTS 1.3, Example 1.3-3 does not provide any specific requirements concerning the administrative controls, Davis-Besse believes that ITS approval without the administrative controls developed is acceptable. This is consistent with many other ITS requirements that require the development of a program to meet an ITS requirement (e.g., the new ITS 5.5.14, Safety Function Determination Program).

NRC Response by Carl Schulten See 200711281417 on 01/30/2008 Licensee Response by Bryan This response supersedes the response dated 12/06/2007. After Kays on 03/20/2008 verbal conversation with the reviewer, it has been determined that ther'e is no action required for this question. A commitment was made in question 200711281417 to implement administrative _________ controls. Date Created: 11/28/200703:44 PM by Carl Schulten Last Modified: 03/31/2008 10:25 AM http://www.excelservices.com/exceldbs/itstrackdavisbesse.nsf/1 fddcea 1Od3bdbb585256e... 5/30/2008

Chapter 2.0 RAIs NRC ITS Tracking Page I of ý výReturn to View Men~uj PrciD ent RAI Screening Required: No Status: Approval Not Required This is a Non RAI Dialogue This document will not be relied upon by staff for disposition of the LAR This document has been reviewed and Yes information in this question contains NO SUNSI sensitive material (the checkbox to the right must be selected before this question can be submitted) NRC ITS TRACKING NRC Reviewer ID 1200711281431 Conference Call Requested? No Category Other Technical Challenge ITS Se.ction: TB POC: JFD Number: Page Number(s): ITS 2.0 Carl Schulten None 8 Information ITS Number.: 0S1: DOC.-Number: Bases JFD Number: None None M.1 None DOC M01 discusses adding the requirement to restore RCS pressure and temperature to within limits in addtion to the CTS 2.1.1 requirement to be in MODE 3. Comment. DOC M01 states in the second paragraph: "However, since the definition of the MODE 3 does not specifically establish the conditionss consistent with the curve the added phrase is necessary." Revise DOC M01 to identify the referenced "curve." I ssue D~atjej1 11/28/2007 Close.D~a~te [ 01/30/2008 Logged in User: Anonymous "vResponses Licensee Response by Jerry The "curve" referred to in Discussion of Change (DOC) MO 1, Jones on 12/05/2007 second paragraph, is CTS Figure 2.1-1 (Volume 4, Page 6) and ITS Figure 2.1.1-1 (Page 13). It is the curve of the reactor coolant outlet pressure versus the reactor outlet temperature described in the first paragraph of DOC MO 1. DOC MO 1 will be modified to clearly identify what is meant by the word "curve." A draft markup regarding this change is attached. This change will be reflected in the supplement to this section of the ITS Conversion Amendment. http://www.excelservices.com/exceldbs/itstrackdavisbesse.nsf/l fddceal Od3bdbb585256e... 5/30/2008

NRC ITS Tracking Page 2 of 2 Date Created: 11/28/2007 02:31 PM by Carl Schulten Last Modified: 01/30/2008 11:44 AM http://www.excelse'rvices.com/exceldbs/itstrack, davisbesse.nsf/1 fddceal Od3bdbb585256e... 5/30/2008

NRC ITS Tracking Page 1 of 2 FR Return to View Menutl PrintDoc4u1ent RAI Screening Required: No Status: Approval Not Required This is a Non RAI Dialogue This document will not be relied upon by staff for disposition of the LAR This document has been reviewed and Yes information in this question contains NO SUNSI sensitive material (the checkbox to the right must be selected before this question can be submitted) NRC ITS TRACKING NRC Reviewer ID 1200711301132 Conference Call Requested? No Category In Scope ITS. Section: TB POC: JFD Number: Page Number(s):. ITS 2.0 Carl Schulten None 17 Information ITS.Nuniber: OSI: DOC Number: Bases-JFD. Number:. None None None 13 Volume 4, Pages 17 and 23 of 33. Bases Background. Revise the insert JFD 13 to include a citation of the "Criterion" specified by the UFSAR reference. Comment Volume 4, Pages 25 and 28 of 33. Bases Background.

            ............. Revise the insert JFD 13 to include a citation of the "Criterion" specified by the UFSAR reference.

Add a new UFSAR reference to insert JFD 13 for Criterion 14, Reactor Coolant Pressure Boundary. [ Issue Date 11/30/2007 Le 1a02/22/2008 Logged in User: Anonymous

'Responses Licensee Response by Bryan                   1See the Davis-Besse response for the 200711301150.

Kays on 01/20/2008 _ NRC Response by Carl Schulten] See item 200711301150 on 01/30/2008 1 Licensee Response by Jerry ]See the second Davis-Besse response to 20071,1301150. Jones on 02/11/2008 _ Date Created: 11/30/2007 11:32 AM by Carl Schulten http://www.excelservices.com/exceldbs/itstrack-davisbesse.nsf/1 fddceal Od3bdbb585256e... 5/30/2008

NRC ITS Tracking Page 2 of 2 Last Modified: 02/22/2008 03:34 PM http://www.excelservices.com/exceldbs/itstrack-davisbesse.nsf/1 fddceal Od3bdbb585256e... 5/30/2008

NRC ITS Tracking Page I of 2 j0*Return to View Menu Prit Doti ln RAI Screening Required: No Status: Approval Not Required This is a Non RAI Dialogue This document will not be relied upon by staff for disposition of the LAR This document has been reviewed and Yes information in this question contains NO SUNSI sensitive material (the checkbox to the right must be selected before this question can be submitted) NRC ITS TRACKING NflC flpvi~'wvr ID 200711301150 Conference Call Requested? No Category In Scope ITS ..Se.ction: TB POC'. JFD Number:. Page..Number(s) ITS 2.0 Carl Schulten None 17 Information ITSNumbner.:. OS.0: DOC..Numbe.r: BaWs.es JFD.Num.tber: None None None 13 Volume 4, Pages 17 and 23 of 33. Bases Background. Revise the insert JFD 13 to include a citation of the "Criterion"' specified by the UFSAR reference. Comment Volume 4, Pages 25 and 28 of 33. Bases Background. Revise the two JFD 13 inserts to include a citation of the "Criterion" specified by the UFSAR reference. Add a new UFSAR reference to insert JFD 13 for Criterion 14, Reactor Coolant Pressure Boundary. Issue 11/30/2007 Close Date [i02 / 2 2 / 2 0 08 Logged in User: Anonymous 'Responses Licensee Response by Bryan The ISTS Bases, when referring to a 10 CFR 50 Appendix A, Kays on 12/07/2007 General Design Criteria (GDC), normally includes the title of the specific GDC. However, the ISTS Bases, when referencing a UFSAR Section, does not normally include a title of the specific section. The only time it has been noted to include a title is when it is referring to a Chapter, and not always in this case. Therefore, for consistency throughout the Davis-Besse ITS Bases, Davis-Besse does not desire to include UFSAR titles for individual sections or appendices. However, in order to provide additional detail for the NRC reviewer, Bases Justification for Deviation (JFD) 13 (Volume 4, Page 31), which justifies the change from a GDC to a http://www.excelservices.com/exceldbs/itstrackdavisbesse.nsf/I fddceal Od3bdbb585256e... 5/30/2008

NRC ITS Tracking Page 2 of 2 UFSAR Appendix, will be modified to clearly show the comparison between the NRC GDC references and the UFSAR Appendix references. A draft markup regarding this change is attached. This change will be reflected in the supplement to this section of the ITS Conversion Amendment. NRC Response by Carl Schulten Revising JFD13 to give a roadmap from the ISTS Bases GCC to on 01/30/2008 the proposed ITS Bases UFSAR does not satisfy my concern. JFD 13 will have no future meaning to the resident inspectors, Region III or NRR licensing staff when it comes to understanding the licensing basis from reading the Bases. I expect text being replaced in the Bases to be at the same level of detail as the information removed. I do not expect the TS Bases to be an exercise in looking up UFSAR citations when the desire is to communicate the licensing basis for the plant. I can accept replacing the GDC citation, With an equivalent statement consistent with your licensing basis. For example: "GDC 10 (Ref. 1)" could be replaced with "design Criterion 10 (Ref. 1)" where Ref. 1 is UFSAR 3D. 1.6, "Criterion 10, "Reactor Design" or "design Criterion 10 (UFSAR 3D. 1.6)" Licensee Response by Jerry During a recent phone call with the NRC reviewer discussing the Jones on 02/11/2008 questions and responses, the NRC reviewer agreed that the requested change to the ITS Bases was not a technical issue. The NRC reviewer strongly recommended that we adopt the editorial recommendation in the question. Davis-Besse will re-review the ITS Bases with respect toadding the UFSAR criterion number. We currently plan to discuss the issue with various users of the ITS Bases, like operators, engineers, and licensing personnel.. However, since this is an editorial issue related to the Bases, Davis-Besse will not make any final decisions until after all the Bases are complete so as to evaluate the recommended changes against the entire Bases. Therefore, Davis-Besse believes that this question should be closed at this time. If Davis-Besse decides to make the suggested changes, it will be identified in the Supplement to the ITS Amendment submittal. Furthermore, since the NRC reviewer does not believe that the changes proposed to the JFD in the previous Davis-Besse response satisfy his concern, the proposed change included in the attachment to the previous Davis-Besse response will not be made. Date Created: 11/30/2007 11:50 AM by Carl Schulten Last Modified: 02/22/2008 03:33 PM http://www.excelservices.com/exceldbs/itstrackdavisbesse.nsf/1 fddceal Od3bdbb585256e... 5/30/2008

NRC ITS Tracking Page I of 2 Return to View Menu Print Dcmn RAI Screening Required: No Status: Approval Not Required This is a Non RAI Dialogue This document will not be relied upon by staff for disposition of the LAR This document has been reviewed and Yes information in this question contains NO SUNSI sensitive material (the checkbox to the right must be selected before this question can be submitted) NRC ITS TRACKING NRC Rpvip~wr ID 1200712101358 Conference Call Requested? No Categor [In Scope ITS Se.¢tion: TBPOC: JFDN H .Number: Page. Number(s):. ITS 2.0 Carl Schulten None 19 Information ITS..Nu..mb.er.T:; OSI: DiO.C.Number:. BaRses JFD Nunmbe.r::. None None' None 6 Section 2.0 Volume 4, Page 19 of 33. Applicable Safety Analyses JFD 6 Revise the Bases ASA list of reactor trips that provide automatic enforcement Comment of reactor core SLs to include "RC High Pressure trip." CTS Figure 2.1-1 o C...... . (Volume 4, Page 6 of 33) includes the RC High Pressure trip function as a parameter that protects plant Safety Limits. This limit is an important restriction to operation necessary to the protection of SIL and therefore required by 10 CFR 50.36(d)(1)(ii)(A), Limiting Safety System. Issue Date [112/10/2007 Close Date [ 02/22/2008 Logged in User: Anonymous

• ' Responses Licensee Response by Bryan The Reactor High Pressure Reactor Protection System Trip does Kays on 01/13/2008 not provide any protection for the Reactor Core Safety Limits. The RPS Low Pressure and Variable Low Pressure Trips have been established to maintain the DNB ratio greater than or equal to the minimum allowable DNB ratio for those design accidents that result in a pressure reduction. It also prevents reactor operation at pressures below the valid range of DNB correlation limits, protecting against DNB. Hence, the Low Pressure and Variable Low Pressure Trips provide protection for the Reactor Core Safety Limits, not the High Pressure Trip. The Reactor High Pressure Trip, in conjuction with the Safety Valves, provides protection http://www.excelservices.com/exceldbs/itstrackdavisbesse.nsf/l1 fddcea 1Od3bdbb585256e... 5/30/2008

NRC ITS Tracking Page 2 of 2 against the RCS Pressure Safety Limit, described in the RCS Pressure SL Bases (Page 25). Furthermore, both the ISTS 3.3.1 Bases and the Davis-Besse ITS 3.3.1 Bases (Volume 8, Page 66), makes it clear that the Reactor High Pressure Trip protects against the RCS Safety Limit, not the Reactor Core Safety Limits. The Reactor High Pressure Trip provides a backup to the High Flux Trip, as described in the CTS Bases, page B 2-6. Therefore, Davis-Besse does not believe that the Reactor High Pressure Trip should be included in the Davis-Besse specific ITS 2.1.1 Bases. NRC Response by Carl Schulten Your reply to this item stated: "The RPS Low Pressure and on 01/30/2008. Variable Low Pressure Trips have been established to maintain the DNB ratio greater than or equal to the minimum allowable DNB ratio for those design accidents that result in a pressure reduction. It also prevents reactor operation at pressures below the valid range of DNB correlation limits, protecting against DNB. Hence, the Low Pressure and Variable Low Pressure Trips provide protection for the Reactor Core Safety Limits, not the High Pressure Trip." The staff notes that the Variable Low Pressure Trip is not listed on page 19 of 33 as a trip which provides automatic enforcement of the reactor core SLs. Explain the inconsistency between the initial response to 200712101358 and the bases on page B.2.1.1-2 (STS markup), then revise the Bases to provide an accurate plant licening basis for SL 2.1.1 in the Applicable Safety Analyses. Licensee Response by Bill Variable Low Pressure Trip (ISTS Language) and RC Pressure-Bentley on 02/05/2008 Temperature Trip (Markup) are two words that describe the same trip. Date Created: 12/10/2007 01:58 PM by Carl Schulten Last Modified: 02/22/2008 03:32 PM http://www.excelservices.com/exceldbs/itstrackdavisbesse.nsf/1 fddcea 1Od3bdbb585256e.:. 5/30/2008

NRC ITS Tracking Page I of 2 11,,ýReturn to View Menul uI~n--- RAI Screening Required: No Status: Approval Not Required This is a Non RAI Dialogue This document will not be relied upon by staff for disposition of the LAR This document has been reviewed and Yes information in this question contains NO SUNSI sensitive material (the checkbox to the right must be selected before this question can be submitted) NRC ITS TRACKING NRC Reviewer ID 200712101o402 Conference Call Requested?.No Category In Scope ITS..Se-ction:. TB.-POC.: PNuAmber: JFD0 Page Number(s). ITS 2.0 Carl Schulten None Information ITS Numb.er. 0S!: D.OC.- Number: Bases.J.FD.-NAumbher: None None None 5 Section 2.0 Bases Volume 4, Page 19 & 21 of 33. Applicable Safety Analyses JFD 5 Identify the plant document that contain RPS trip setpoints established using the reactor core safety limits as the design requirement. The NRC staff issued Regulatory Issue Summary 2006-17, "NRC Staff Position o the Requirements of 10 CFR 50.36, "Technical Specifications," Regarding Limiting Safety System Settings During Periodic Testing and Calibration of Instrument Comment Channels." This RIS discusses issues that could occur during testing of LSSSs and which, therefore, may have an adverse effect on equipment operability. This RIS also presents an approach, found acceptable to the NRC staff, for addressing these issues for use in licensing actions that require prior NRC staff approval. The RIS position is that the LSP is the limiting value to which the channel must be reset at the conclusion of periodic testing to ensure the safety limit (SL) will not be exceeded if a design basis event occurs before the next periodic surveillance or calibration. Whereas the Allowable Value is a limiting value of an instrument's as-found trip setting used during surveillances. Is sueDate 12/10/2007 Close D ate 103/31/2008 Logged in User: Anonymous 'Responses Licensee Response by Jerry The ISTS words stated that the RPS setpoints are designed to assist Jones on 01/04/2008 in ensuring the applicable safety limit is met. However, for clarity, Davis-Besse changed the term setpoint to Allowable Value, since http://www.excelservices.com/exceldbs/itstrackdavisbesse.nsf/1 fddceal Od3bdbb585256e... 5/30/2008

NRC ITS Tracking Page 2 of 2 this is the setpoint that is controlled in the actual ITS. The setpoint methodology is identified in the ITS 3.3.1 Bases, as required by the ISTS. The ITS Bases clearly identifies the appropriate plant documents. Therefore, referencing ITS 3.3.1 is more applicable for this Bases discussion. NRC Response by Carl Schulten see 200711301150 on 01/31/2008 Licensee Response by Bryan This response supersedes the response made on 1/4/2008. After Kays on 03/20/2008 further review, Davis-Besse has determined that the Bases of ITS 2.1.1 should refer to the trip setpoints of the Reactor Protection System (RPS) instead of the Allowable Values, or provide clarifications concerning setpoints vs Allowable Values. Therefore, the Applicable Safety Analyses (Volume 4, Page 19) and the Safety Limits (Page 21) of ITS Bases 2.1.1 have been revised. A draft markup regarding this change is attached. This change will be reflected in the supplement to this section of the ITS Conversion Amendment. Date Created: 12/10/2007 02:02 PM by Carl Schulten Last Modified: 03/31/2008 01:43 PM http://www.excelservices.com/exceldbs/itstrackdavisbesse.nsf/1 fddcea 1Od3bdbb585256e... 5/30/2008

NRC ITS Tracking Page I of 2 Reunto View Menuj Print Document RAI Screening Required: No Status: Approval Not Required This is a Non RAI Dialogue This document will not be relied upon by staff for disposition of the LAR This document has been reviewed and Yes information in this question contains NO SUNSI sensitive material (the checkbox to the right must be selected before this question can be submitted) NRC ITS TRACKING NRC' Reviewe~r ID[ 200712101412 Conference Call Requested? No ct -oyJ InScope ITS Section: TB POC: JFD Number: Page Number(s): ITS .2.0 Carl Schulten None 6 Information ITS.Number: OSt: DOC Number: Bases JFD Number: None None A.2 None Section 2.0 - BSI Volume 4, Page 6 of 33, CTS Figure 2.1-1 DOC A02 C mt Revise the Figure 2.1-1 to retain the graphical representations of the reactor omment trips that provide automatic enforcement of the reactor core SLs. These graphs contain important restrictions to operation of the plant required by 10 CFR 50.36(d)(1)(ii)(A), Limiting Safety System Settings. Issue Date 12/10/2007 Close Date [03/31/2008 Logged in User: Anonymous

'Responses Licensee Response by Bryan             The graphical representation was removed because it was not Kays on 01/13/2008                      consistent with the ISTS. ISTS Figure 2.1.1-1 (Volume 4, Page 13) does not include this information. It is included in the ISTS Bases (Page 19). Also, the graphical representation is redundant to the RPS Allowable Values listed in ITS 3.3.1. The graphical representation depicts what we already know about the RPS trips -

they cause actuation before reaching the safety limits. Therefore, this redundant information is not required to be included in the ITS, since the restrictions are already provided in another section of the ITS. NRC Response by Carl Schulten Per you response make ITS Figure 2.1.1-1 (page 14 of 33) on 01/31/2008 consistent with ISTS figure 2.1.1-1 (page 13 of 33) by extending the SL limit graph to Reactor Outlet Temperature 618 degrees F, http://www.excelservices.com/exceldbs/itstrackdavisbesse.nsf/l fddceal0d3bdbb585256e... 5/30/2008

NRC ITS Tracking Page 2 of 2 and System Pressure 2355 psig. This extension would graph the ITS SL to the RC High Pressure Trip. Licensee Response by Jerry ITS Figure 2.1.1-1 (Volume 4, Page 14) is consistent with the Jones on 02/11/2008 current Davis-Besse Safety Limits figure, with respect to the actual Safety Limit. Therefore, no changes to the Figure should be made. Licensee Response by Bryan After further review, Davis-Besse has decided to revise ITS Figure Kays on 03/20/2008 2.1.1-1 (Volume 4, Page 14) to be consistent with CTS Figure 2.1-1 (Page 6). Additionally, Discussion of Change (DOC) A02 (Page

8) has been deleted. A draft markup regarding this change is attached. This change will be reflected in the supplement to this section of the ITS Conversion Amendment.

Date Created: 12/10/2007 02:12 PM by Carl Schulten Last Modified: 03/31/2008 01:47 PM http://www.excelservices.com/exceldbs/itstrack-davisbesse.nsf/1 fddceal Od3bdbb5 85256e... 5/30/2008

NRC ITS TrackingP Page I of 2 Reunto View Men~u IQPrntED~ct:i=en RAI Screening Required: No Status: Approval Not Required This is a Non RAI Dialogue This document will not be relied upon by staff for disposition of the LAR This document has been reviewed and Yes information in this question contains NO SUNSI sensitive material (the checkbox to the right must be selected before this question can be submitted) NRC ITS TRACKING NRC Reviewer ID 200712101433 Conference Call Requested? No Categor In Scope ITS Section: TB POC: JFD N.u1-mber: PageNumber(s): ITS 2.0 Carl Schulten None Information ITS Number: 0SI: D!OC.Numnber: Bases JFD Number: None None None 17 Section 2.0 Volume 4, Page 19 Safety Limits. JFD 17 JFD 17 justifies deleting Bases for reactor core pressure and temperature SL which explains the pressure/temperature operating region keeps the reactor Comment from exceeding a SL when operating up to design pressure, and defines the safe operating region from brittle fracture concerns. JFD 17 only justified deleting the last part of the sentence regarding the "safe operating region from brittle fracture concerns." The first part of the sentence is an applicable Bases Hfor SL 2.1.1.2 and should be retained.

       .Issue Date  12/10/2007 Close Date     02/22/2008 Logged in User: Anonymous u'Responses Licensee Response by Bryan            The Safety Limits section of ITS 2.1.1 Bases (Volume 4, Page 19)

Kays on 01/20/2008 has been revised to delete only the portion of the sentence covered by Justification for Deviation (JFD) 17. A draft markup regarding this change is attached. This change will be reflected in the _supplement to this section of the ITS Conversion Amendment. [NRC Response by Carl Schulten Correction. In the markup 2.1.1.3 should be 2.1.1.2 per the on 01/31/2008 Jnumbering in ITS Section 2.1.1. http://www.excelservices.com/exceldbs/itstrackdavisbesse.nsf/1 fddceal Od3bdbb585256e... 5/30/2008

NRC ITS Tracking Page 2 of 2 Date Created: 12/10/2007 02:33 PM by Carl Schulten Last Modified: 02/22/2008 08:27 AM http://www.excelservices.com/exceldbs/itstrackdavisbesse.nsf/1 fddcealOd3bdbb585256e... 5/30/2008

NRC ITS Tracking Page I of 2 Reunto View Menuj Prit Docu~ient RAI Screening Required: No Status: Approval Not Required This is a Non RAI Dialogue This document will not be relied upon by staff for disposition of the LAR This document has been reviewed and Yes information in this question contains NO SUNSI sensitive material (the checkbox to the right must be selected before this question can be submitted) NRC ITS TRACKING NRC Rpvpviwpr IDf200712101439 Conference Call Requested? No categr In Scope ITS Section: TB POC.:. JFD Number.: Page-Number(s): ITS 2.0 Carl Schulten None Information ITSNumber: OS: D OC Number: Bases JFD Number: None None None 4 Section 2.0 DBPage Identify 4, Comment. Volume Co of 33. Applicable Safety Analyses JFD 4 21 valves safety which may perform a function similar to the MSSVs by serving to prevent RCS heatup to reactor core SL conditions. Issue.Date 12/10/2007 Close .Date [02/22/2008 Logged in User: Anonymous "vResponses Licensee Response by Jerry This Bases Section (ITS Bases Section 2.1.1) is discussing the Jones on 02/11/2008 Reactor Core Safety Limits (SLs). The MSSVs are not used to protect the Reactor Core SLs. As stated in the Applicable Safety Analysis Section of the Bases (Volume 5, Page 19), automatic enforcement of the Reactor Core SLs is provided by the following Reactor Protection System trips: RC High Temperature Trip, RC Low Pressure Trip, High Flux Trip, RC Pressure-Temperature Trip, High Flux/Number of Reactor Coolant Pumps On Trip, and Flux-Delta Flux-Flow Trip. The ISTS included the MSSVs in this listing, but it was also deleted, similar to the deletion described in the NRC Reviewer's question above. As stated in Justification for Deviation (Page 30), the Davis-Besse Main Steam Safety Valves are not credited in the Update Final Safety Analysis Report to prevent violation of the Reactor Core SLs. Furthermore, no safety valves are assumed in the safety analysis to protect the Reactor http://www.excelservices.com/exceldbs/itstrackdavisbesse.nsf/1 fddceal 0d3bdbb585256e... 5/30/2008

NRC ITS Tracking Page 2 of 2 Core SLs from being violated. The Safety Limit related to overpressure protection is discussed in the Bases for Section 2.1.2. In this Safety Limit Bases, RCS pressurizer code safety valves are credited to ensure the RCS Pressure SL is met. Therefore, no _changes are necessary to the Davis-Besse ITS submittal. NRC Response by Carl Schulten I misstakenly closed 200712101439. I will review the response on 02/22/2008 [next week. Date Created: 12/10/2007 02:39 PM by Carl Schulten Last Modified: 02/22/2008 03:37 PM http://www.excelservices.com/exceldbs/itstrackdavisbesse.nsf/1 fddceal Od3bdbb585256e... 5/30/2008

NRC ITS Tracking Page I of I Return o View Menua Print Do~cumient RAI Screening Required: No Status: Approval Not Required This is a Non RAI Dialogue This document will not be relied upon by staff for disposition of the LAR This document has been reviewed and Yes information in this question contains NO SUNSI sensitive material (the checkbox to the right must be selected before this question can be submitted) NRC ITS TRACKING NRC Reviewer ID 200712101440 Conference Call Requested? No Categor][ In Scope ITS Section: TB POC: JFD Number: Page Number(s): ITS 2.0 Carl Schulten None Information ITS Numinbcr: 0S1: DOC.Number:';1 Bases JFD Number: None None None 15 Section 2.0 Comment Volume 4, Page 22 and 27 of 33 Safety Limit Violations JFD 15, INSERT 6 Correct the citation for the 10 CFR 50.36 requirement to shutdown when safety limits are exceeded. The citation should be 10 CFR 50.36(d)(1)(i)(A). Issue.Date [12/10/2007 Close Date [01/30/2008 Logged in User: Anonymous Responses Licensee Response by Jerry The CFR reference will be changed. A draft markup regarding this Jones on 01/04/2008 change is attached. This change will be reflected in the supplement to this section of the ITS Conversion Amendment. Date Created: 12/10/2007 02:40 PM by Carl Schulten Last Modified: 01/30/2008 11:44 AM http://www.excelservices.com/exceldbs/itstrack davisbesse.nsf/1 fddcea 1Od3bdbb585256e... 5/30/2008

NRC ITS Tracking Page I of-I Return to View Menuj Print Docuen RAI Screening Required: No Status: Approval Not Required This is a Non RAI Dialogue This document will not be relied upon by staff for disposition of the LAR This document has been reviewed and Yes information in this question contains NO SUNSI sensitive material (the checkbox to the right must be selected before this question can be submitted) NRC ITS TRACKING NRC Reviewer ID 200712101441 Conference Call Requested? No Categor JIn Scope ITS Section: TB POC: JFD-Number: Page .Number(s): ITS 2.0 Carl Schulten None Information ITS Number:. OSI: DOC Number:. Bases JFD Number: HNone. None None 13 Section 2.0 Comment Volume 4, Pages 25 and 28 of 33. Background, JFD 13 Revise the insert JFD 13 to include a citation of the "Criterion" specified by the UFSAR reference. I Issue D:ate 12/10/2007 Close Date 02/22/2008 Logged in User: Anonymous 'vResponses Licensee Response by Jerry 1 See the Davis-Besse response for question 200711301150. Jones on 01/04/2008 ___________________________ NRC Response by Carl SchultenlSee item 200711301150 on 01/30/2008 I Licensee Response by Jerry 1[See the second Davis-Besse response to 200711301150.i Jones on 02/11/2008 [ ' _ _ _ _ Date Created: 12/10/2007 02:41 PM by Carl Schulten Last Modified: 02/22/2008 03:34 PM http://www.excelservices.com/exceldbs/itstrack-davisbesse.nsfl1 fddceal Od3bdbb585256e... 5/30/2008

NRC ITS Tracking Page 1 of I Return to View Menju Print Docmn RAI Screening Required: No Status: Approval Not Required This is a Non RAI Dialogue This document will not be relied upon by staff for disposition of the LAR This document has been reviewed and Yes information in this question contains NO SUNSI sensitive material (the checkbox to the right must be selected before this question can be submitted) NRC ITS TRACKING NRC Reviewer ID200712101442 Conference Call Requested? No Category In Scope ITS Section: TB..P.OC:. JFD..Numb.er.:. Page Number.(s): ITS 2.0 Carl Schulten None Information ITS Number: OSI: DOCN~umber.: . Bases..JFD..Number.: None None None 13 Section 2.0 Comment Volume 4, Pages 25 and 28 of 33. Background, JFD 13 Add a new UFSAR reference to insert JFD 13 for Criterion 14, Reactor Coolant Pressure Boundary. Issue Date 12/10/2007 *1 Close Date [102/22/2008 Logged in User: Anonymous

'Responses JnLicensee Response by Jerry           See the Davis-Besse response for question 200711301150.

Jones on 01/04/2008 ___________________________ NRC Response by Carl Schulten See item 200711301150 [on 01/30/2008 [ Licensee Response by Jerry See the second Davis-Besse response to 200711301150.

ýJones on 02/11/2008I Date Created: 12/10/2007 02:42 PM by Carl Schulten Last Modified: 02/22/2008 03:35 PM http://www.excelservices.com/exceldbs/itstrackdavisbesse.nsf/1 fddceal Od3bdbb585256e...               5/30/2008

NRC ITS Tracking . Tage I of 2. Return to View Menuil Print Documen RAI Screening Required: No Status: Approval Not Required This is a Non RAI Dialogue This document will not be relied upon by staff for disposition of the LAR This document has been reviewed and Yes information in this question contains NO SUNSI sensitive material (the checkbox to the right must be selected before this question can be submitted) NRC ITS TRACKING NID- D nTrnI*,nr ID 200712101444 Conference Call Requested? No Categor ][ In Scope ITS Section:. TB PO*.C.:1 JD.D NuM.mber: Page Number(s): ITS 2.0 Carl Schulten None Information ITS Number:;. 01: DOC Number: Bases JFD Number: None None None 9 Section 2.0 Volume 4, Page 25, 28 and 29 of 33. Background, JFD 9 and JFD 10 Comrxlen t Specific references to the ASME Code have been deleted and replaced. Provide documentation to show these changes represent a licensing basis that was reviewed and approved by the staff. Issue.Date [ 12/10/2007. C.Iose6 03/11/2008 Logged in User: Anonymous

'Responses Licensee Response by Bryan               The ASME Code referenced in the Davis-Besse ITS Bases Kays on 01/20/2008                        (Volume 4, Pages 25, 28, and 29) is specified in UFSAR Section 7.2.1.1.1.b. Since the UFSAR is part of the Davis-Besse licensing basis, and the UFSAR is periodically provided to the NRC in accordance with 10 CFR 50.59, Davis-Besse believes that this change is acceptable. Additionally, the CTS 2.0 bases provides the year of publication (1968) for ANSI B31.7.

Licensee Response by Bryan See response for the first 200712101444. Kays on 01/22/2008 t NRC Response by Carl Schulten What is the rgulatory basis for performing a system leakage test at on 01/31/2008 normal operating pressure near the end of each refueling cycle? Insert 8 (JFD9) replaces two sentences in the Background Bases. Explain why the ISTS Bases first sentence does not apply to the D-http://www.excelservices.com/exceldbs/itstrackdavisbesse.nsf/lfddcea 1Od3bdbb585256e... 5/30/2008

NRC ITS Tracking Page 2 of 2 B license basis. Insert 8. The insert second sentence content is pretty much identical to the ISTS Bases content. Explain why the ISTS Bases does not apply. Is there an NRR staff SER that [[ establishes Ref. 4 of insert 8 as the D-B license basis? Licensee Response by Bryan The regulatory basis for performing a system leakage test at Kays on 02/27/2008 normal operating pressure near the end of each refueling cycle is ASME Boiler and Pressure Vessel Code, Section XI. The ISTS Bases (Volume 4, Page 25) which is being replaced by Insert 8 (Page 26) JFD 7 (not JFD 9 as identified by the NRC reviewer) does not apply because there are errors in the replaced BWOG STS Bases Background sentence. Section XI Code does not require testing to be performed each time the head is removed'and it does not require 100% of design pressure. The Code requires a system leakage test at normal operating pressure following each refueling (see IWB-5000, IWA-4540, and Table IWB 2500-1). The ten year update to the ISI program is performed in accordance with 10CFR50.55a(g). The NRC safety evaluation for the last update of the ISI program is attached. Furthermore, Reference 4 (Page 28) is being updated to be just the ASME Boiler and Pressure Vessel Code, Section XI. Since the Code changes every 10 years and the Code cases change, the more specific reference is not needed. A draft markup regarding this change is attached. This change will be reflected in the supplement to this section of the ITS Conversion Amendment. NRC Response by Carl Schulten The draft markup of Ref. 4 was not attached, as stated. Please on 03/03/2008 provide a citation of the Ref. 4 that will be in the supplement to the ITS conversion. Date Created: 12/10/2007 02:44 PM by Carl Schulten Last Modified: 03/11/2008 01:49 PM http://www.excelservices.com/exceldbs/itstrackdavisbesse.nsfl1 fddcea 1Od3bdbb585256e... 5/30/2008

NRC ITS Tracking Page I of 2

   .Return to View Menu aPrint Document]*

RAI Screening Required: No Status: Approval Not Required This is a Non RAI Dialogue This doCument will not be relied upon by staff for disposition of the LAR This document has been reviewed and Yes information in this question contains NO SUNSI sensitive material (the checkbox to the right must be selected before this question can, be submitted) NRC ITS TRACKING Not 0014"111"~Wn ID 200712101444 Conference Call Requested? No. Category ] In Scope ITS Section: TB POC: JFDNuimber: Page Number(s): ITS 2.0 Carl Schulten None Information ITS Number: OSI: DOC Number: Bases JFD Num.ber: None None None 10 Section 2.0 Volume 4, Page 25, 28 and 29 of 33. Background, JFD 9 and JFD 10 Comment Specific references to the ASME Code have been deleted and replaced. Provide documentation to show these changes represent a licensing basis that was reviewed and approved by the staff. Issue Date 112/10/2007

    .C..Is*.Date 03/11/2008, Logged in User: Anonymous

"'Responses Licensee Response by Bryan The ASME Code referenced in the Davis-Besse ITS Bases Kays on 01/20/2008 (Volume 4, Pages 25, 28, and 29) is specified in UFSARSection 7.2.L.1.1.b. Since the UFSAR is part of the Davis-Besse licensing basis, and the UFSAR is periodically provided to the NRC in accordance with 10 CFR 50.59, Davis-Besse believes that this change is acceptable. Additionally, the CTS 2.0 bases provides the _ year of publication (1968) for ANSI B31.7. Licensee Response by Bryan See response for the first 200712101444. Kays on 01/22/2008[ __ _ NRC Response by Carl Schulten What is the rgulatory basis for performing a system leakage test at on 01/31/2008 normal operating pressure near the end of each refueling cycle? Insert 8 (JFD9) replaces two sentences in the Background Bases. Explain why the ISTS Bases first sentence does not apply to the D-http://www.excelservices.com/exceldbs/itstrack 'davisbesse.nsf/l fddceal Od3bdbb585256e... 5/30/2008

NRC ITS Tracking Page 2 of 2 B license basis. Insert 8. The insert second sentence content is pretty much identical io the ISTS Bases content. Explain why the ISTS Bases does not apply. Is there an NRR staff SER that establishes Ref. 4 of insert 8 as the D-B license basis? Licensee Response by Bryan The regulatory basis for performing a system leakage test at Kays on 02/27/2008 normal operating pressure near the end of each refueling cycle is ASME Boiler and Pressure Vessel Code, Section XI. The ISTS Bases (Volume 4, Page 25) which is being replaced by Insert 8 (Page 26) JFD 7 (not JFD 9 as identified by the NRC reviewer) does not apply because there are errors in the replaced BWOG STS Bases Background sentence. Section XI Code does not require testing to be performed each time the head is removed and it does not require 100% of design pressure. The Code requires a system leakage test at normal operating pressure following each refueling (see IWB-5000, IWA-4540, and Table IWB 2500-1). The ten year update to the ISI program is performed in accordance with 10CFR50.55a(g). The NRC safety evaluation for the last update of the ISI program is attached. Furthermore, Reference 4 (Page 28) is being updated to be just the ASME Boiler and Pressure Vessel Code, Section XI. Since the Code changes every 10 years and the Code cases change, the more specific reference is not needed. A draft markup regarding this change is attached. This change will be reflected in the supplement to this section of the ITS Conversion Amendment. NRC Response by Carl Schulten The draft markup of Ref. 4 was not attached, as stated. Please on 03/03/2008 provide a citation of the Ref. 4 that will be in the supplement to the ITS conversion. Date Created: 12/10/2007 02:44 PM'by Carl Schulten Last Modified:' 03/11/2008 01:50 PM http://www.excelservices.com/exceldbs/itstrackdavisbesse.nsf/1fddceal0d3bdbb585256e... 5/30/2008

NRC ITS Tracking Page I of 2 Return to View Menu a Print Documen RAI Screening Required: No Status: Approval Not Required This is a Non RAI Dialogue This document will not be relied upon by staff for disposition of the LAR This document has been reviewed and Yes information in this question contains NO SUNSI sensitive material (the checkbox to the right must be selected before this question can be submitted) NRC ITS TRACKING NRC Rovipwpr ID 200712101456 Conference Call Requested? No Categor In Scope ITS..Se.tion.:. TB POC:. JFDNu mbeei:. Page..Number(s);. ITS 2.0 Carl Schulten None 19 Information ITS N...u.n.ber.;. S01:1- DOC_.Number: Bases JFD Number: None None None 6 Section 2.0 - BSI Volume 4, Page 19 of 33. Applicable Safety Analyses JFD 6 Revise the Bases ASA list of reactor trips that provide automatic enforcement Comment. of reactor core SLs to include "RC High Pressure trip." CTS Figure 2.1-1

         ...........(Volume 4, Page 6 of 33) includes the RC High Pressure trip function as a parameter that protects plant Safety Limits. This limit is an important restriction to operation necessary to the protection of SL and therefore required by 10 CFR 50.36(d)(1)(ii)(A), Limiting Safety System Settings Issue Date][ 12/10/2007 Close Daýt el 02/22/2008 Logged in User: Anonymous
' Responses KyLicensee Response by Bryan           See the response for 200712101358.

Kays on 01/13/2008 ____________________________ NRC Response by Carl Schulten Your reply to this item stated: "The RPS Low Pressure and on 01/30/2008 Variable Low Pressure Trips have been established to maintain the DNB ratio greater than or equal to the minimum allowable DNB ratio for those design accidents that result in a pressure reduction. It also prevents reactor operation at pressures below the valid range of DNB correlation limits, protecting against DNB. Hence, the Low Pressure and Variable Low Pressure Trips provide protection for the Reactor Core Safety Limits, not the High Pressure Trip." The staff notes that the Variable Low Pressure Trip http://www.excelservices.com/exceldbs/itstrackdavisbesse.nsf/1 fddceal Od3bdbb585256e... 5/30/2008

NRC ITS Tracking Page 2 of 2 is not listed on page 19 of 33 as a trip which provides automatic enforcement of the reactor core SLs. Explain the inconsistency between the initial response to 200712101358 and the bases on page B.2.1.1-2 (STS markup), then revise the Bases to provide an accurate plant licening basis for SL 2.1.1 in the Applicable Safety Analyses. Licensee Response by Bill Variable Low Pressure Trip (ISTS Language) and RC Pressure-Bentley on 02/05/2008 Temperature Trip (Markup) are two descriptions of the same trip. Date Created: 12/10/2007 02:56 PM by Carl Schulten Last Modified: 02/22/2008 03:32 PM http://www.excelservices.com/exceldbs/itstrackdavisbesse.nsf/1 fddceal Od3bdbb585256e... 5/30/2008

NRC ITS Tracking Page I of I Return to View Menu ZPrint O=~1~n RAI Screening Required: No Status: Approval Not Required This is a Non RAI Dialogue This document will not be relied upon by staff for disposition of the LAR This document has been reviewed and Yes information in this question contains NO SUNSI sensitive material (the checkbox to the right must be selected before this question can be submitted) NRC ITS TRACKING NRC Reviewer ID 200712101344 Conference Call Requested? No category In Scope ITS Section: TB POC: JFD Number: Page Number(s):_ ITS 3.0 Carl Schulten 13 Information ITS NuPmber: 0S1: DOC Number: Bases JFD Number: None None None None Section 2.0 Volume 4, Pages 17 and 23 of 33. Background, JFD 13 Comment STS "Ref. 1" is a citation for GDC 10. The GDC reference is deleted and replaced with a UFSAR reference. Revise the UFSAR citation to include the title of the UFSAR reference. Issue :Da:ate. 12/10/2007 Cjj se-Date[02/22/2008 Logged in User: Anonymous 'VResponses Licensee Response by Jerry See the Davis-Besse response for question 200711301150. Also Jones on 01/04/2008 Note that the ITS Section for the Question (in the ITS Information Section) is incorrect. It should be 2.0, not 3.0. NRC Response by Carl Schulten [See item 200711301150 on 01/30/2008 1 = 1 onLicensee Response by Jerry See the second Davis-Besse response to 200711301150. Jones on 02/11/2008 _____________________________ Date Created: 12/10/2007 01:44 PM by Carl Schulten Last Modified: 02/22/2008 03:35 PM http://www.excelservices.com/exceldbs/itstrackdavisbesse.nsf/1 fddceal Od3bdbb585256e... 5/30/2008

Section 3.3 RAIs NRC ITS Tracking Page I of 2 Reunto View Menuj PrintD~o1en RAI Screening Required: Yes Status: Closed This Document will be approved by: Tim Regulatory Basis must be included in Comments Kobetz section of this Form This document has been reviewed and Yes information in this question contains NO SUNSI sensitive material (the checkbox to the right must be selected before this question can be submitted) NRC ITS TRACKING NRC Reviewer ID 200711160940 Conference Call Requested? No Categoy BSI - Beyond Scope Issue ITS Section: TB POC:ý JFD.'N-pnib er: Page.N'umnber(s);. ITS 3.3 Aron Lewin None Information !TS Number: 0S1: D!OC.Number: Bases JFD Number: 3.3.1 None None None Discuss how allowing modification to where Nominal trip setpoints are specified would effect physical application and reporting requirements of the LCO, and, in addition, still give assurance that the limiting safety system setting is chosen so that automatic protective action will correct the abnormal situation before a safety limit is exceeded in accordance with 10 CFR 50.36(d) (1)(ii)(A).

Background

The Bases for CTS 3/4.3.1 and 3/4.3.2 (page 398 of 490 in the CTS) state that "for the RPS [except Functional Unit 7], only the Allowable Value is specified for each Function. Nominal trip setpoints are specified in the setpoint analysis." The Bases for CTS 3/4.3.1 and 3/4.3.2 (page 399 of 490 in the CTS) go on to further state "for RPS Functional Unit 7, the Limiting Trip Setpoint Comment is specified in the USAR Technical Requirements Manual." The Bases for the ITS (pages 60 and 61 of 636) states "only the Allowable Values are specified for each RPS trip Function in the LCO. Nominal trip setpoints are specified in the unit specific setpoint calculations except for Functions la [High Flux - High Setpoint] and 5 [RC Pressure -ýTemperature]. For these two Functions, the Limiting Trip Setpoint and methodology used to determine the Limiting Trip Setpoint, the predefined as-found acceptance criteria, and the as-left tolerance are specified in the TRM." This statement on pages 60 and 61 seems to conflict with the statement in the ITS Bases (page 59 of 636) t states "the trip setpoint is established using Method 1 or Method 2 of Reference 6 [ISA 67.04-Part 11-19941 or 7 [ISA 67.04.02-2000]." The Bases for the STS for LCO 3.3.1 (NUREG-1430), simply state "only the Allowable Values are specified for each RPS trip Function in the LCO. Nominal trip setpoints are specified in the unit specific setpoint calculations." http://www.excelservices.com/exceldbs/itstrack davisbesse.nsf/1 fddcea 1Od3bdbb585256e... 7/18/2008

NRC ITS Tracking Page 2 of 2 10 CFR 50.36(d)(1)(ii)(A) states that "limiting safety system settings for nuclear reactors are settings for automatic protective devices related to those variables having significant safety functions. Where a limiting safety system setting is specified for a variable on which a safety limit has been placed, the setting must be so chosen that automatic protective action will correct the abnormal situation before a safety limit is exceeded." It is unclear how allowing modification to where Nominal trip setpoints are specified would effect physical application and reporting requirements of the LCO, and, in addition, still give assurance that the limiting safety system setting is chosen so that automatic protective action will correct the abnormal situation before a safety limit is exceeded in accordance with 10 CFR 50.36(d) (1)(ii)(A). Issue Da:te][ 11/16/2007 Close Date [01/10/2008 Logged in User: Anonymous

'Responses Licensee Response by Jerry             ITS Table 3.3.1-1 Notes (c) and (d) (Volume 8, Pages 40 and 41)

Jones on 12/10/2007 were added to SR 3.3.1.3 for ITS Table 3.3.1-1 Function L.a (High Flux - High Setpoint), consistent with the outstanding LAR for the Caldon Power Uprate. This is described in Discussion of Change (DOC) A13 (Page 23) and shown in the CTS Markup (Page 12). This is why the ITS Bases includes Function L.a as an exception. ITS Table 3.3.1-1 Function 5 includes the two Notes since the CTS already includes the two Notes (See Functional Unit 7 - Page 12). However, the wording of Justification for Deviation (JFD) 12 (Page 43) should be corrected to make this clear, because Notes (c) and (d) were not added to SR 3.3.1.3 for ITS Table 3.3.1-1 Function L.a to be consistent with the current license basis. This change is provided in the response to question 200711160953. In addition, Davis-Besse does not believe this is a Beyond Scope Issue, since it is either consistent with current licensing basis or is consistent with an outstanding license amendment request. NRC Response by Aron Lewin Technical Branch (EICB)conducting evaluation. on 12/20/2007 ___________________________ NRC Response by Aron Lewin Issue being tracked to resolution by TAC MD7470 (EICB). on 01/10/2008 Anticipate any further questions regarding this issue to be charged and documented under TAC MD7470. Date Created: 11/16/2007 09:40 AM by Aron Lewin Last Modified: 01/10/2008 07:57 AM http://www.excelservices.com/exceldbs/itstrack-davisbesse.nsf/lfddcealOd3bdbb585256e... 7/18/2008

NRC ITS Tracking Page 1 of I Return to View Menu] d Print Docuen RAI Screening Required: No Status: Approval Not Required This is a Non RAI Dialogue This document will not be relied upon by staff for disposition of the LAR This document has been reviewed and Yes information in this question contains NO SUNSI sensitive material (the checkbox to the right must be selected before this question can be submitted), NRC ITS TRACKING NRC Reviewer ID200711160946 Conference Call Requested? No Category Other Technical Challenge ITS Section: TB POC: JFD-Nujmb er:. Page.Number(s)': ITS 3.3 Aron Lewin None Information ITS Number: OSI: DO-.C Number: Bases..JFD.Number: 3.3.1 None A.6 None On page 12 of 636 (Section 3.3.1), the A06 arrow does not point to RC Pressure-Temperature (Functional Unit 7). Based on similar mark-ups on Comment page 6, page 40, and the A06 discussion on page 20, I believe this was an administrative error, and that the arrow should point to the RC Pressure-Temperature function. [A061 Issue 11/16/2007 C[ose iiDatc[ 12/20/2007 Logged in User: Anonymous

'Responses Licensee Response by Bryan          The NRC reviewer is correct. CTS Table 4.3-1, Functional Unit 7 Kays on 12/03/2007                  (Volume 8, Page 24), should include the ITS 3.3.1 footnote (a) and Discussion of Change (DOC) A06 annotation. A draft markup regarding this change is attached. This change will be reflected in

__the supplement to this section of the ITS Conversion Amendment. NRC Response by Aron Lewin 0Nfurther comment at this time. [on 12/20/2007It___________________________ Date Created: 11/16/2007 09:46 AM by Aron Lewin Last Modified: 12/20/2007 12:42 PM http://www.excelservices.com/exceldbs/itstrack-davisbesse.nsf/1fddcealOd3bdbb585256e... 7/18/2008

NRC ITS Tracking Page 1 of I Return to View Menu a Print Documn RAI Screening Required: No Status: Approval Not Required This is a Non RAI Dialogue This document will not be relied upon by staff for disposition of the LAR This document has been reviewed and Yes information in this question contains NO SUNSI sensitive material (the checkbox to the right must be selected before this question can be submitted) NRC ITS TRACKING NRC Reviewer ID 200711160947 Conference Call Requested? No Category Other Technical Challenge ITS Section: TB POC:1 JFD Number: Page Number(s). ITS 3.3 Aron Lewin None Information ITS Number:. 0S1:. DOC .Number: Ba4ses JFD-Number:; 3.3.1 None M.2 None On page 24 of 636 (Section 3.3.1),.the second paragraph of M02 references a Compmente Footnote (c). On pages 6, 12, and 40, the Footnote is actually labeled (g). I believe this is an administrative error. [M021 Issue Datei 11/16/2007 Close Date 12/20/2007 Logged in User: Anonymous

'Responses Licensee Response by Bryan            The NRC reviewer is correct. The Discussion of Change (DOC)

Kays on 12/03/2007 M02 (Volume 8, Page 24) reference to Footnote (c) should be a reference toFootnote (g). A draft markup regarding this change is attached. This change will be reflected in the supplement to this section of the ITS Conversion Amendment. NRC Response by Aron Lewin No further comments at this time. on 12/20/2007 ____ Date Created: 11/16/2007 09:47 AM by Aron Lewin Last Modified: 12/20/2007 12:43 PM http://www.excelservices.com/exceldbs/itstrackdavisbesse.nsf/1 fddcealOd3bdbb58525,6e... 7/18/2008

NRC ITS Tracking Page I of 1 [0 Return to View Menju Print Docunient] RAI Screening Required: No Status: Approval Not Required This is a Non RAI Dialogue This document will not be relied upon by staff for disposition of the LAR This document has been reviewed and Yes information in this question contains NO SUNSI sensitive material (the checkbox to the right must be selected before this question can be submitted) NRC ITS TRACKING NRC Reviewer ID1200711160948 Conference Call Requested? No Categor][ Other Technical Challenge ITS Section: TB.PO.C: JFDHNumber: P.ageNunber(s).: ITS 3.3 Aron Lewin None Information ITS Number: OSI: DOC Number: Bases JFD Number: 3.3.1 None M.7 None On page 26 of 636 (Section 3.3.1), the first paragraph of M07 references Cormmaent Footnote (b). On page 40, the Footnote is actually labeled (f). I believe this is an administrative error. [M071 Issue Date] 11/16/2007 Close..;Dit 112/20/2007 Logged in User: Anonymous

'Responses Licensee Response by Bryan             The NRC reviewer is correct. The Discussion of Change (DOC)

Kays on 12/03/2007 M07 (Volume 8, Page 26) reference to Footnote (b) should be a reference to. Footnote (f). A draft markup regarding this change is attached. This change will be reflected in the supplement to this section of the ITS Conversion Amendment. NRC Response by Aron Lewin No further comments at this time. on 12/20/2007 _ Date Created: 11/16/2007 09:48 AM by Aron Lewin Last Modified: 12/20/2007 01:03 PM http://www.excelservices.com/exceldbs/itstrack-davisbesse.nsf/1 fddceal Od3bdbb585256e... 7/18/2008

NRC ITS Tracking Page I of 2 ' Return to View Menu aEPrint D =cI~n RAI Screening Required: No Status: Approval Not Required This is a Non RAI Dialogue This document will not be relied upon by staff for disposition of the LAR This document has been reviewed and Yes information in this question contains NO SUNSI sensitive material (the checkbox to the right must be selected before this question can be submitted) NRC ITS TRACKING NRC Reviewer ID I1200711160949 Conference Call Requested? No Category Other Technical Challenge ITS Section: TB POC:. JFD Number: Page-Number(s):.. ITS 3.3 Aron Lewin None Information ITS.Number: $OS!:. DOC.Number: Bases JFD Number.: 3.3.1 None A.9 None On page 22 of 636 (Section 3.3.1), the first paragraph of A09 references Conmuent Footnote (e). On page 42, the Footnote is actually labeled (f). I believe this is an administrative error. [A091 Issue D 11/16/2007 Close :Date II12/20/2007 Logged in User: Anonymous 'Responses Licensee Response by Bryan The NRC reviewer is correct. The Discussion of Change (DOC) Kays on 12/03/2007 A09 (Volume 8, Page 22) reference to Footnote (e) should be a reference to Footnote (f). A draft markup regarding this change is attached. This change will be reflected in the supplement to this section of the ITS Conversion Amendment. Licensee Response by Bryan The NRC reviewer is correct. The CTS Markup page (Volume 8, Kays on 12/03/2007 Page 10) should be annotated with a new Discussion of Change (DOC) A15, and DOC A15 (Page 24) has been added to discuss the addition of the ITS 3.3.1 Required Action D.2 Note. Additionally, during the review of this NRC question it was discovered that Justification for Deviation (JFD) 2 (Page 43), which describes why the Note is being included in the ITS, has an administrative error in that it did not list all the Functions to which Condition D is applicable. This should also be corrected. A draft markup regarding these changes is attached. This change will be http://www.excelservices.com/exceldbs/itstrackdavisbesse.nsf/l fddceal Od3bdbb585256e... 7/18/2008

NRC ITS Tracking Page 2 of 2 ITS Conversion reflected in the supplement to this section of the an error in uploading file due to NRC Response by Aron Lewin It appears there may have been on 12/20/2007 JID200711160949 appearing twice. NRC Response by Aron Lewin No further comments at this time. [ofl 12/20/2007 ____________________________ Date Created: 11/16/2007 09:49 AM by Aron Lewin Last Modified: 12/20/2007 03:35 PM http://www.excelservices.com/exceldbs/itstrack-davisbesse.nsfl1fddcealOd3bdbb585256e... 7/18/2008

NRC ITS Tracking .Page I of ý Return to View Menu Za Prnt D=O-]en RAI Screening Required: No Status: Approval Not Required This is a Non RAI Dialogue This document will not be relied upon by staff for disposition of the LAR This document has been reviewed and Yes information in this question contains NO SUNSI sensitive material (the checkbox to the right must be selected before this question can be submitted) NRC ITS TRACKING NRC Reviewer ID [200711160949 Conference Call Requested? No Category Other Technical Challenge ITS Section: TB POC: JFD Number: Page Number(s): ITS 3.3 Aron Lewin None Information ITS.Number: OSI: D!.C-N!u!mber: Bases JFD-Number: 3.3.1 None None None On page 10 of 636 (Section 3.3.1), there is no Discussion Of Changes for "Add Commlent proposed Note to Required Action D.2." in Action 10. I believe this may be an administrative oversight. IssueDate i11/16/2007 Close Date 1 2 /20/ 2 0 0 7 Logged in User: Anonymous

'Responses Licensee Response by Bryan         The NRC reviewer is correct. The Discussion of Change (DOC)

Kays on 12/03/2007 A09 (Volume 8, Page,22) reference to Footnote(e) should be a reference to Footnote (f). A draft markup regarding this change is attached. This change will be reflected in the supplement to this section of the ITS Conversion Amendment. Licensee Response by Bryan The NRC reviewer is correct. The CTS Markup page (Volume 8, Kays on 12/03/2007 Page 10) should be annotated with a new Discussion of Change (DOC) A15, and DOC A15 (Page 24) has been added to discuss the addition of the ITS 3.3.1 Required Action D.2 Note. Additionally, during the review of this NRC question it was discovered that Justification for Deviation (JFD) 2 (Page 43), which describes why the Note is being included in the ITS, has an administrative error in that it did not list all the Functions to which Condition D is applicable. This should also be corrected. A draft markup regarding these changes is attached. This changewill be http://www.excelservices.com/exceldbs/itstrackdavisbesse.nsf/1 fddceal Od3bdbb585256e... 7/18/2008

NRC ITS Tracking Page 2 of 2 reflected in the supplement to this section of the ITS Conversion NRC Response by Aron Lewin ]jIt appears there may have been an error in uploading file due to on 12/20/2007 ]ID200711160949 appearing twice. [NRC Response by Aron Lewin No further comments at this time. [on 12/20/2007 i Date Created: 11/16/2007 09:49 AM by Aron Lewin Last Modified: 12/20/2007 03:35 PM http://www.excelservices.com/exceldbs/itstrackdavisbesse.nsf/1 fddceal 0d3bdbb585256e... 7/18/2008

NRC ITS Tracking Page I of 2 Return to View Menul Print Do.uen RAI Screening Required: No Status: Approval Not Required This is a Non RAI Dialogue This document will not be relied upon by staff for disposition of the LAR This document has been reviewed and Yes information in this question contains NO SUNSI sensitive material (the checkbox to the right must be selected before this question can be submitted) NRC ITS TRACKING NRC Reviewer ID 200711160951 Conference Call Requested? No Categgory Other Technical Challenge ITS Section: T!B P.OC:. JFD.Number: Page.Numnber(s): ITS 3.3 Aron Lewin None Information ITS Nunmbelr: 01S;: DOC.Number: Bases JFD Number:. 3.3.1 None M.7 None On page 27 of 636 (Section 3.3.1), M07 has the statement, "This change is necessary because under these conditions, the Shutdown Bypass High Pressure trip prevents normal operation {without} shutdown bypass activated and the High Flux-Low trip prevents any significant power from being produced." I Comment believe the statement should read, "This change is necessary because under these conditions, the Shutdown Bypass. High Pressure trip prevents normal operation {with} the shutdown bypass activated and the High Flux-Low trip prevents any significant power from being produced." I believe this is an administrative error. [M071 Issue Date 11/16/2007 Close,..Date [12/20/2007 Logged in User: Anonymous "'Responses Licensee Response by Bryan The third sentence in Discussion of Change (DOC) M07 (Volume Kays on 12/04/2007 8, Page 12). has been changed to be consistent with the ISTS Bases (Page 57, third paragraph, second sentence). A draft markup regarding this change is attached. This change will be reflected in __the supplement to this section of the ITS Conversion Amendment. NRC Response by Aron Lewin [No further comments at this time. on 12/20/2007 I http://www.excelservices.com/exceldbs/itstrack-davisbesse.nsfl 1fddceal Od3bdbb585256e... 7/18/2008

NRC ITS Tracking Page 2 of 2 Date Created: 11/16/2007 09:51 AM by Aron Lewin Last Modified: 12/20/2007 01:03 PM http://www.excelservices.com/exceldbs/itstrackdavisbesse.nsf/1 fddceal Od3bdbb585256e... 7/18/2008

NRC ITS Tracking Page 1 of 2 Return to ViewMeu Pitocen RAI Screening Required: Yes Status: Closed This Document will be approved by: Tim Regulatory Basis must be included in Comments Kobetz section of this Form This document has been reviewed and Yes information in this question contains NO SUNSI sensitive material (the checkbox to the right must be selected before this question can be submitted) NRC ITS TRACKING NRC Reviewer ID [200711160953 Conference Call Requested? No C.ategory j[BSI - Beyond Scope Issue ITS .S'ection: TB POC: FD Numb.ner.: Page.Numbnber(s); ITS 3.3 Aron Lewin 12 Information ITS Number: OSI: DOC__Number:n Bases. JFD Number: 3.3.1 None None None Discuss how the addition of Footnote (c) and (d) to CTS Functional Unit 2 (ITS Functional Unit la), or the fact that it is not stated for other Functional Units, ensures that the limiting safety system setting is chosen so that automatic protective action will correct the abnormal situation before a safety limit is exceeded in accordance with 10 CFR 50.36(d)(1)(ii)(A) Backround Table 4.3-1 of the CTS (page 12 of 636) does not contain a Notation that discusses setpoint issues for the High Flux (CTS Functional Unit 2). The ITS has Footnote (c) and (d) in ITS Table 3.3.1-1 (page 41 of 636), that discusses setpoint issues for the High Flux - High Setpoint (ITS Functional Unit la). STS Table 3.3.1-1 (NUREG-1430) does not contain any Footnotes on setpoint Comment issues. JD12 (page 43 of 636) mentions that these notes to the High Flux - High Setpoint (Note: JD12 refers to ITS Functional Unit lb, however the reference should be to ITS Functional Unit la) in the ITS are as a result of the current licensing bases. It is unclear why the licensee believes that Footnote (c) and (d) are part of the current licensing bases for CTS Functional Unit 2 (ITS Functional Unit la). 10 CFR 50.36(d)(1)(ii)(A) states that "limiting safety system settings for nuclear reactors are settings for automatic protective devices related to those variables having significant safety functions. Where a limiting safety system setting is specified for a variable on which a safety limit has been placed, the setting must be so chosen that automatic protective action will correct the abnormal situation before a safety limit is exceeded." It is unclear how the addition of Footnote (c) and (d) to CTS Functional Unit 2 (ITS Functional Unit la), or the fact that it is not stated for other Functional http://www.excelservices.com/exceldbs/itstrackdavisbesse.nsfl1 fddcealOd3bdbb585256e... 7/18/2008

NRC ITS Tracking Page 2 of 2 Units, ensures that the limiting safety system setting is chosen so that automatic protective action will correct the abnormal situation before a safety limit is exceeded in accordance with 10 CFR 50.36(d)(1)(ii)(A) [JFD12] IssueDFate 11/16/2007 Close Date][ 01/10/2008 1 / Logged in User: Anonymous

'Responses Licensee Response by Bryan         The addition of Footnotes (c) and (d) to SR 3.3.1.3 for ITS Kays on 12/03/2007                 Function 1.a (Volume 8, Page 40) was to make the ITS submittal consistent with the outstanding LAR for the Caldon Power update, as described in Discussion of Change (DOC) A13 (Page 23), and shown in the CTS Markup for Functional Unit 2 (Page 12).

Justification for Deviation (JFD) 12 incorrectly states that it applies to ITS Function 1.b (should be Function 1.a), and incorrectly states that the addition of the two Footnotes, for ITS Function 1.a, is to be consistent with current licensing basis. A draft markup regarding the change to JFD 12 is attached. This change will be reflected in the supplement to this section of the ITS Conversion Amendment. The fact that Footnotes (c) and (d) are not applicable for other ITS Functions is consistent with the current licensing basis. In fact, adding these notes for the other ITS Functions would have been a Beyond Scope Item. Therefore, the Footnotes Were not added. Furthermore, Davis-Besse does not believe this is a Beyond Scope Issue. [NRC Response by Aron Lewin Technical Branch (EICB) conducting evaluation. En12/20/21007I____________________________ NRC Response by Aron Lewin Issue being tracked to resolution by TAC MD7470 (EICB). on 01/10/2008 [Anticipate any further questions regarding this issue to be charged and documented under TAC MD7470. Date Created: 11/16/2007 09:53 AM by Aron Lewin Last Modified: 0 1/10/2008 08:00 AM http://www.excelservices.comlexceldbs/itstrackdavisbesse.nsf/1 fddcea 1Od3bdbb585256e... 7/18/2008

NRC ITS Tracking Pagel of3 [ Return to View Menu9* Print Document RAI Screening Required: Yes Status: Closed This Document will be approved by: Tim Regulatory Basis must be included in Comments Kobetz section of this Form This document has been reviewed and Yes information in this question contains NO SUNSI sensitive material (the checkbox to the right must be selected before this question can be submitted) NRC ITS TRACKING NRC Reviewer ID_ f200711160956 Conference Call Requested? No Category BSI - Beyond Scope Issue ITS Section: TB POC: JFD Number:. Page.Number(s): ITS 3.3 Aron Lewin None Information ITS.Number: OSR: DOC Numbe.r: Bases JFD Number: 3.3.1 None None None Discuss how allowing Method 1 or Method 2 of Reference 6 [ISA 67.04-Part II-1994] or 7 [ISA 67.04.02-20001 for all RPS Functional Units in the ITS Bases ensures that the limiting safety system setting is chosen so that automatic protective action will correct the abnormal situation before a safety limit is exceeded in accordance with 10 CFR 50.36(d)(1)(ii)(A).

Background

The Bases for CTS 3/4.3.1 and 3/4.3.2 (page 398 of 490 in the CTS), state that "for the RPS [except Functional Unit 71, only the Allowable Value is specified for each Function. Nominal trip setpoints are specified in the setpoint analysis. The nominal trip setpoints are selected to ensure the setpoints measured by CHANNEL FUNCTIONAL TESTS do not exceed the Allowable Value if the bistable is performing as required. Operation with a trip setpoint less Comment conservative acceptable provided nominal trip setpoint, but within its Allowable Value, is than thethat operation and testing are consistent with the assumptions of the specific setpoint calculations. Each Allowable Value specified is more conservative than the analytical limit assumed in the safety analysis to account for instrument uncertainties appropriate to the trip parameter. These uncertainties are defined in the specific setpoint analysis." For Functional Unit 7, the Bases for CTS 3/4.3.1 and 3/4.3.2 (page 399 of 490 in the CTS), state "for RPS Functional Unit 7, the Limiting Trip Setpoint is specified in the USAR Technical Requirements Manual. The Limiting Trip Setpoint is based on the calculated total loop uncertainty per the plant-specific methodology. The Limiting Trip Setpoint may be established using Method 1 or Method 2 of Section 7 of ISA RP67.04.02-2000, "Methodologies for the Determination of Setpoints for Nuclear Safety-Related Instrumentation." Additional information is contained in the Technical Requirements Manual." http://www.excelservices.com/exceldbs/itstrack- davisbesse.nsf/1 fddcea 1Od3bdbb585256e... 7/18/2008

NRC ITS Tracking Page 2 of 3 The Bases for the ITS (page 59 of 636) states that "the trip setpoint is established using Method 1 or Method 2 of Reference 6 [ISA 67.04-Part II-19941 or 7 [ISA 67.04.02-2000]." The Bases for the STS for LCO 3.3.1 (NUREG-1430), state "a detailed description of the methodology used to calculate the trip setpoints, including their explicit uncertainties, is provided in "[Unit Specific Setpoint Methodology]" 10 CFR 50.36(d)(1)(ii)(A) states that "limiting safety system settings for nuclear reactors are settings for automatic protective devices related to those variables having significant safety functions. Where a limiting safety system setting is specified for a variable on which a safety limit has been placed, the setting must be so chosen that automatic protective action will correct the abnormal situation before a safety limit is exceeded." It is unclear how allowing Method 1 or Method 2 of Reference 6 [ISA 67.04-Part 11-1994] or 7 [ISA 67.04.02-2000] for all RPS Functional Units in the ITS Bases ensures that the limiting safety system setting is chosen so that automatic protective action will correct the abnormal situation before a safety limit is exceeded in accordance with 10 CFR 50.36(d) (1)(ii)(A). Issue Date 11/16/2007 Close IdI 01/10/2008 Loggedin User: Anonymous

'Responses Licensee Response by Bryan            Method 1 and Method 2 of Reference 6 (ISA 67.04-Part 11-1994)

Kays on 12/03/2007 and Reference 7 (ISA 67.04.02-2000) are NRC approved methods for calculating Allowable Values and trip setpoints. The STS Bases for LCO 3.3.1 includes a bracketed requirement for the applicant to provide the unit specific setpoint methodology (Volume 8, Pages 59 and 60). The two above referenced documents are the Davis-Besse setpoint methodology. The proposed words in the Davis-Besse ITS Bases (Pages 59 and 60) are more explicit, in that, in lieu of referencing a unit specific setpoint methodology (i.e., ISA 67.04-Part 11-1994 and ISA 67.04.02-2000), it is specifically stated that the Allowable Values and trip setpoints are established using Method 1 or Method 2 of the two referenced documents. As these methods are acceptable and meet NRC requirements, maintaining the specific Methods in the ITS Bases is desired. However, if the NRC desires, the specific methods can be removed and the Bases could only state the two documents. NRC Response by Aron Lewin Technical Branch (EICB) conducting evaluation. on 1.2/20/2007I NRC Response by Aron Lewin Issue being tracked to resolution by TAC MD7470 (EICB). on 01/10/2008 Anticipate any further questions regarding this issue to be charged and documented under TAC MD7470. http://www.excelservices.com/exceldbs/itstrackdavisbesse.nsfl1 fddceal Od3bdbb585256e... 7/18/2008

NRC ITS Tracking Page 3 of 3 Date Created: 11/16/2007 09:56 AM by Aron Lewin Last Modified: 01/10/2008 08:03 AM http://www.excelservices.comlexceldbs/itstrackdavisbesse.nsf/lfddcealOd3bdbb585256e... 7/18/2008

NRC ITS Tracking Page I of 2 Return to View Menu P*Print Document RAI Screening Required: Yes Status: Closed This Document will be approved by: Tim Regulatory Basis must be included in Comments Kobetz section of this Form This document has been reviewed and Yes information in this question contains NO SUNSI sensitive material (the checkbox to the right must be selected before this question can be submitted) NRC ITS TRACKING NRC Reviewer ID 1200711161010 Conference CallRequested? No Category BSI - Beyond Scope Issue ITS Section: TB POC: JFD0 Number.: Page..Nunber(s): ITS 3.3 Aron Lewin None Information ITS Number: OSI:ý DOC..N.unm2ber.:. Bases.JFD.Number: 3.3.1 None A.13 None Discuss how allowing the licensee to reset the High Flux - High Setpoint [CTS Functional Unit 2; ITS Functional Unit la] Allowable Value in the TS with a licensee controlled requirement that can be modified by the licensee at any time without NRC prior approval, still provides assurance that the limiting safety system setting is chosen so that automatic protective action will correct the abnormal situation before a safety limit is exceeded in accordance with 10 CFR 50.36(d)(1)(ii)(A).

Background

Table 2.2-1 of the CTS (page 15 of 636) states that the Allowable value for the High Flux Trip (CTS Functional Unit 2) is "less than or equal to 105.1% of Rated Thermal Power with four pumps operating." Table 3.3.1-1 of the ITS (page 40 of 636) states that the Allowable Value for Comment the High Flux - High Setpoint (ITS Functional Unit la) is less than or equal to 104.9% RTP [with a Footnote (e)] with four pumps operating, and less than or equal to 80.6% RTP when reset for three pumps operating per LCO 3.4.4.

                  'RCS Loops MODES 1 and 2'." Footnote (e) of ITS Table 3.3.1-1 states that the Allowable Value for the High Flux - High Setpoint (ITS Functional Unit la) is "less than or equal to 103.3% RTP when reset per license controlled requirements due to an inoperable ultrasonic flow meter (UFM) instrumentation or due to not using the UFM to perform SR 3.3.1.2."

STS Table 3.3.1-1 for LCO 3.3.1 (NUREG-1430) lists brackets for the Allowable Value for the High Flux - High Setpoint, indicated plant specific values may be used. The differences between the CTS and the ITS is due to a License Amendment Request (LAR) that is currently being processed by the NRC (ML071030396). The ITS statement is captured in the LAR being reviewed by the NRC. http://www.excelservices.com/exceldbs/itstrackdavisbesse.nsf! 1fddcea 1Od3bdbb585256e... 7/18/2008

NRC ITS Tracking Page 2 of 2 10 CFR 50.36(d)(1)(ii)(A) states that "limiting safetysystem settings for nuclear reactors are settings for automatic protective devices related to those variables having significant safety functions. Where a limiting safety system setting is specified for a variable on which a safety limit has been placed, the setting must be so chosen that automatic protective action will correct the abnormal situation before a safety limit is exceeded." It is unclear how allowing the licensee to reset the High Flux - High Setpoint [CTS Functional Unit 2; ITS Functional Unit la] Allowable Value in the TS with a licensee controlled requirement that can be modified by the licensee at any time without NRC prior approval, still provides assurance that the limiting safety system setting is chosen so that automatic protective action will correct the abnormal situation before a safety limit is exceeded in accordance with 10 CFR 50.36(d)(1)(ii)(A). [I Issue Date [11/16/2007 [Close Date [12/20/2007 Logged in User: Anonymous 'vResponses Licensee Response by Bill This question appears to be similar to an RAI asked by the NRC Bentley on 11/28/2007 on the outstanding power uprate amendment, LAR 05-0007. LAR 05-0007 is currently reflected in the conversion submittal as described in Discussion of Change (DOC) A13. LAR 05-0007 will be changed as a result of the RAI. Once LAR 05-0007 has been finally approved, those approved changes will be reflected in a supplement to the conversion submittal. A copy of the RAI is attached for information. NRC Response by Aron Lewin No further comments at this time. on 12/20/2007 1 comnsa1ti ie Date Created: 11 / 16/2007 10:10 AM by Aron Lewin Last Modified: 12/20/2007 01:03 PM http://www.excelservices.com/exceldbs/itstrackdavisbesse.nsf/1 fddceal Od3bdbb585256e... 7/18/2008

NRC ITS Tracking Page I of 2 Return to View Menuil Print Document RAI Screening Required: Yes Status: Closed This Document will be approved by: Tim Regulatory Basis must be included in Comments Kobetz section of this Form This document has been reviewed and Yes information in this question contains NO SUNSI sensitive material (the checkbox to the right must be selected before this question can be submitted) NRC ITS TRACKING NRC Reviewer ID]200711161012 Conference Call Requested? No Category BSI - Beyond Scope Issue ITS Section: TBPOC:ý JFDNumbbe:. PageNunhber(s): ITS 3.3 Aron Lewin None Information ITS Number: OSI: DOC Number: Bases.JFD-Number: 3.3.1 None None None Discuss how adding a statement to the Bases in the ITS for the High Flux - Low Setpoint effects physical application and reporting requirements of the LCO, and, in addition, still give assurance that the limiting safety system setting is chosen so that automatic protective action will correct the abnormal situation before a safety limit is exceeded in accordance with 10 CFR 50.36(d) (1)(ii)(A).

Background

The Bases for CTS 3/4.3.1 and 3/4.3.2 (page 398 of 490 in the CTS) do not explicitly discuss the High Flux - Low Setpoint function. The ITS Bases (page 65 of 636), states that for the High Flux - Low Setpoint, "instrument uncertainties and other uncertainties are not factors in determining the Allowable Value." The STS Bases for LCO 3.3.1 (NUREG-1430) do not contain this statement in the High Flux - Low Setpoint discussion. 10 CFR 50.36(d)(1)(ii)(A) states that "limiting safety system settings for nuclear reactors are settings for automatic protective devices related to those variables having significant safety functions. Where a limiting safety system setting is specified for a variable on which a safety limit has been placed, the setting must be so chosen that automatic protective action will correct the abnormal situation before a safety limit is exceeded." It is unclear how adding this statement to the Bases in the ITS for the High Flux - Low Setpoint effects physical application and reporting requirements of the LCO, and, in addition, still give assurance that the limiting safety system setting is chosen so that automatic protective action will correct the abnormal situation before a safety limit is exceeded in accordance with 10 CFR 50.36(d) (1)(ii)(A). http://www.excelservices.com/exceldbs/itstrackdavisbesse.nsfl1 fddceal Od3bdbb585256e... 7/18/2008

NRC ITS Tracking Page 2 of 2 Issue Date 11/16/2007 Close Date/ 01/10/2008 Logged in User: Anonymous 'Responses Licensee Response by Bryan As described in the CTS 2.2.1 RPS Instrument Setpoints Bases, Kays on 12/03/2007 page B 2-4 (Page 120 of 490 in the CTS), the high flux setpoint, (imposed when in shutdown bypass) of less than or equal to 5% prevents any significant power from being produced. Sufficient natural circulation would be available to remove 5% of rated thermal power if none of the reactor coolant pumps were operating. In the CTS Markup, CTS Table 3.3-1 Footnote (a) (Volume 8, Page 7) and CTS Table 2.2-1 Footnote (1) (Page 16) state that various trips may be bypassed, provided the High Flux Trip Setpoint is less than or equal to 5% of RTP (CTS Table 3.3-1 footnote (a)(1) and Table 2.2-1 Footnote (1)a). This is not an Allowable Value in the sense that it protects from an analytical limit. In the CTS, the 5% setpoint is not referred to as an Allowable Value in Table 2.2-1 (Page 15). In the ISTS Bases, there are further references that support the fact that the shutdown bypass high flux setpoint is not an Allowable Value. On page 57 of the ISTS Bases, it is stated that the High Flux trip setpoint is administratively reduced'to 5% RTP (i.e., NUREG-1430 has these words, and the Davis-Besse ITS submittal maintained these words) . On page 65 of the ISTS Bases, it is stated that "While in shutdown bypass, the High Flux trip setpoint must be reduced to less than or equal to 5% RTP. The Allowable Value was chosen to be as low as practical and still lie within the range of the out of core instrumentation." The additional words about uncertainties not being a factor in determining the Allowable Value were added, to ensure there would not be any confusion about the 5% RTP setpoint. It is an administrative control, and is not determined as a result of any analysis. NRC Response by Aron Lewin Technical Branch (EICB) conducting evaluation. on 12/20/2007 i NRC Response by Aron Lewin Issue being tracked to resolution by TAC MD7470 (EICB). on 01/10/2008 Anticipate any further questions regarding this issue to be charged and documented under TAC MD7470. Date Created: 11/16/2007 10:12 AM by Aron Lewin Last Modified: 01/10/2008 08:07 AM, http://www.excelservices.com/exceldbs/itstrackdavisbesse.nsf/1 fddcea 1Od3bdbb585256e... 7/18/2008

NRC ITS Tracking Page I of 2 I Return to. Vie-w M~e.nu IIQa Print D~ocumfe..nt RAI Screening Required: Yes Status: Closed This Document will be approved by: Tim Regulatory Basis must be included in Comments Kobetz section of this Form This document has been reviewed and Yes information in this question contains NO SUNSI sensitive material (the checkbox to the right must be selected before this question can be submitted) NRC ITS TRACKING NRC Reviewer ID 1200711161015 Conference Call Requested? No

                   ]9 Category BSI - Beyond Scope Issue ITS Section:          TB POC:.             JFD Number:         Page Number(s):.

ITS 3.3 Aron Lewin None Information ITS N!umberl: 051: DOC Number: Bases JFD Number: 3.3.1 None None None Discuss how adding astatement to the Bases in the ITS for ITS SR 3.3.1.3 effects physical application and reporting requirements of the LCO, and, in addition, still gives assurance that the limiting safety system setting is chosen so that automatic protective action will correct the abnormal situation before a safety limit is exceeded in accordance with 10 CFR 50.36(d)(1)(ii)(A). It is also unclear why the added statement is only applicable to ITS Functional Unit la and ITS Functional Unit 5.

Background

The Bases for CTS 3/4.3.1 and 3/4.3.2 (page 396 thru 400 of 490 in the CTS) mention Channel Calibrations, but do not include the same discussions as found in the ITS. The Bases for the ITS (pages 79-80), discusses setpoint methodology not found in the CTS, as applied to the High Flux - High Setpoint (ITS Functional Unit Comment. la) for ITS SR 3.3.1.3, which is a Channel Calibration surveillance requirement. The STS Bases for LCO 3.3.1 (NUREG-1430) do not contain the ITS discussion in STS SR 3.3.1.5, which is the STS equivalent Channel Calibration surveillance requirement. 10 CFR 50.36(d)(1)(ii)(A) states that "limiting safety system settings for nuclear reactors are settings for automatic protective devices related to those variables having significant safety functions. Where a limiting safety system setting is specified for a variable on which a safety limit has been placed, the setting must be so chosen that automatic protective action will correct the abnormal situation before a safety limit is exceeded." It is unclear how adding this statement to the Bases in the ITS for ITS SR 3.3.1.3 effects physical application and reporting requirements of the LCO, http://www.excelservices.com/exceldbs/itstrack-davisbesse.nsf/l fddcea1Od3bdbb585256e... 7/18/2008

NRC ITS Tracking Page. 2 of 2 and, in addition, still gives assurance that the limiting safety system setting is chosen so that automatic protective action will correct the abnormal situation before a safety limit is exceeded in accordance with 10 CFR 50.36(d)(1)(ii)(A). It is also unclear why the added statement is only applicable to ITS Functional Unit la and ITS Functional Unit 5 (see question on ITS SR 3.3.1.5 / ITS SR 3.3.1.7). Issue Date 11/16/2007 Close Date [12/26/2007 J Logged in User: Anonymous ' Responses Licensee Response by Bryan The statements in question in the ITS Bases (Volume 8, Pages 79 Kays on 12/03/2007 and 80) were added in direct support of ITS Table 3.3.1-1 Notes (c) and (d) (Pages 40 and 41), which were added to SR 3.3.1.3. These Notes were added to SR 3.3.1.3 in order to be consistent with the outstanding Licensing Amendment Request (LAR) for the Caldon Power Uprate. The acceptability of the changes will be addressed by the outstanding LAR. A Discussion-of Change (DOC) has been provided referencing this LAR (DOC A13, Page 23). DOC A13 stated that the changes are consistent with the outstanding LAR, thus any changes that are required as a result of the outstanding LAR will also have to be incorporated in a supplement to the ITS Conversion submittal. Davis-Besse believes that all technical issues related to this outstanding LAR are being handled through the Davis-Besse NRC Project Manager (i.e., this outstanding LAR is not actually part of the ITS conversion - it is assumed that the LAR will be approved prior to ITS approval and that the ITS conversion will reflect whatever is approved by the NRC in the LAR amendment.) Furthermore, the statements in question are only applicable to ITS Table 3.3.1-1 Functions L.a and 5, because ITS Table 3.3.1-1 Function. 5 is the only CTS Table 4.3-1 Functional Unit which currently has the ITS.Table 3.3.1 -1 Notes (c) and (d) requirements, and because the two Notes have been added to ITS Function L.a consistent with the outstanding, LAR (which added the Notes to CTS Table 4.3-1 Functional Unit 2). The added statements are not applicable to the other ITS Table 3.3.1-1 Functions because none of the other CTS Table 4.3-1 Functional Units have the two Notes. NRC Response by Aron Lewin Will request conference call with licensee via PM. on 12/20/2007 I____________________________ NRC Response by Aron Lewin lNo further questions at this time. on 12/26/2007 I Date Created: 11/16/2007 10:15 AM by Aron Lewin Last Modified: 12/26/2007 08:22 AM http://www.excelservices.com/exceldbs/itstrack-davisbesse.nsfl1fddcealOd3bdbb585256e... 7/18/2008

NRC ITS Tracking Page I of 2 JIV/ Return to View Menu Print Document RAI Screening Required: Yes Status: Closed This Document will be approved by: Tim Regulatory Basis must be included in Comments Kobetz section of this Form This document has been reviewed and Yes information in this question contains NO SUNSI sensitive material (the checkbox to the right must be selected before this question can be submitted) NRC ITS TRACKING NRC Reviewer ID 200711161018 Conference CallRequested? No C.ategQry [BSI - Beyond Scope Issue ITSSection: TB POC.: JFD Number: Page Number(s): ITS 3.3 Aron Lewin None Information ITS-Number: OS1: DOC. Number: Bases JFD.Number: 3.3.1 None None None Discuss how adding a statement to the Bases in the ITS for ITS SR 3.3.1.5 and ITS SR 3.3.1.7 effects physical application and reporting requirements of the LCO, and, in addition, still gives assurance that the limiting safety system setting is chosen so that automatic protective action will correct the abnormal situation before a safety limit is exceeded in accordance with 10 CFR 50.36(d) (1)(ii)(A). It is also unclear why the added statement is only applicable to ITS Functional Unit la and ITS Functional Unit 5.

Background

The Bases for CTS 3/4.3.1 and 3/4.3.2 (page 396 thru 400 of 490 in the CTS) mention Channel Calibrations, but do not include the same discussions as found in the ITS. The Bases for the ITS (pages 81-84), discusses setpoint methodology not found CoVmment in the CTS, as applied to the RC Pressure - Temperature (ITS Functional Unit

5) for ITS SR 3.3.1.5 and ITS SR 3.3.1.7, which is a Channel Calibration surveillance requirement.

The STS Bases for LCO 3.3.1 (NUREG-1430) do not contain the ITS discussion in STS SR 3.3.1.5, which is the STS equivalent Channel Calibration surveillance requirement. 10 CFR 50.36(d)(1)(ii)(A) states that "limiting safety system settings for nuclear reactors are settings for automatic protective devices related to those variables having significant safety functions. Where a limiting safety system setting is specified for a variable on which a safety limit has been placed, the setting must be so chosen that automatic protective action will correct the abnormal situation before a safety limit is exceeded." It is unclear how adding this statement to the Bases in the ITS for ITS SR 3.3.1.5 and ITS SR 3.3.1.7 effects physical application and reporting http://www.excelservices.com/exceldbs/itstrackdavisbesse.nsf/1 fddceal Od3bdbb585256e... 7/18/2008

NRC ITS Tracking Page 2 of 2 requirements of the LCO, and, in addition, still gives assurance that the limiting safety system setting is chosen so that automatic protective action will correct the abnormal situation before a safety limit is exceeded in accordance with 10 CFR 50.36(d)(1)(ii)(A). It is also unclear why the added statement is only applicable to ITS Functional Unit la (see question on ITS SR 3.3.1.3) and ITS Functional Unit 5. I Issue Date ]111/16/2007 Close Date [101/10/2008 Logged in User: Anonymous

• 'Responses Licensee Response by Bryan Davis-Besse added into the Bases for ITS SR 3.3.1.5 (Volume 8, Kays on 12/03/2007 Page 82) and ITS SR 33.1.7 (Page 84) a description of how the ITS Table 3.3.1-1 Notes (c) and (d) work. The words are consistent with the words for the same Notes provided in proposed TSTF-493. Davis-Besse believes that the ITS Bases should describe the purpose and reasons for the two Notes. Providing this explanation is consistent with the ISTS Bases, in that Notes in the ISTS are generally described in the applicable Bases. Since the added words are consistent with proposed TSTF-493, and they are consistent with Davis-Besse's understanding of the purpose of the two Notes, the words should remain in the Bases. Furthermore, since the words do not change the intent of the ITS, the change is not a beyond scope issue.

NRC Response by Aron Lewin Technical Branch (EICB) conducting evaluation. on 12/20/2007JL_____________________________ NRC Response by Aron Lewin Issue being tracked to resolution by TAC MD7470 (EICB). on 01/10/2008 Anticipate any further questions regarding this issue to be charged and documented under TAC MD7470. Date Created: 11/16/2007 10:18 AM by Aron Lewin Last Modified: 01/10/2008 08:09 AM http://www.excelservices.com/exceldbs/itstrackdavisbesse.nsfl1 fddcea 1Od3bdbb585256e... 7/18/2008

NRC ITS Tracking Page I of 4 Return to View Men~u IQoPrint F RAI Screening Required: Yes Status: Closed This Document will be approved by: Tim Regulatory Basis must be included in Comments Kobetz section of this Form This document has been reviewed and Yes information in this question contains NO SUNSI sensitive material (the checkbox to the right must be selected before this question can be submitted) NRC ITS TRACKING NRC Reviewer ID 200711161029 Conference CallRequested? No Category BSI - Beyond Scope Issue ITS Sectfon: TB. PO.C:. JFD.D.Nu-mber.: Pnage..Number(s).; ITS 3.3 Aron Lewin None Information ITS Number: OSI: DOC.Number: Bases JFD Number: 3.3.1 None LA.5 None Discuss how putting a TS SR exception in a licensee controlled document instead of the TS would still assure that the necessary quality of systems and components is maintained, that facility operation will be within safety limits, and that the limiting conditions for operation will be met in accordance with 10 CFR 50.36(d)(3).

Background

CTS 4.3.1.1.3 (page 5 of 636) includes a Note (*) that states, in part, a "delay time has been assumed for the Reactor Coolant Pump monitor in the determination of the response time of the High Flux/Number of Reactor Coolant Pumps On functional unit." ITS SR 3.3.1.8 (page 38 of 636) does not carry this note over into the TS, but the licensee proposes to place this note, which discusses the exception to the C mt SR, in the TRM, as discussed in LA05 (page 29 of 636). STS SR 3.3.1.8 in LCO 3.3.1 (NUREG-1430), which is a surveillance requirement for Response Time Testing, does not list any testing exceptions associated with the Reactor Coolant Pump to Power Instrument (STS Functional Unit 7). 10 CFR 50.36(d)(3) states that "surveillance requirements are requirements relating to test, calibration, or inspection to assure that the necessary quality of systems and components is maintained, that facility operation will be within safety limits, and that the limiting conditions for operation will be met." It is unclear how putting a TS SR exception in a licensee controlled document instead of the TS would still assure that the necessary quality of systems and components is maintained, that facility operation will be within safety limits, and that the limiting conditions for operation will be met in accordance with 10 CFR 50.36(d)(3). As an example STS 3.3.1.6 (NUREG-1430) contains an http://www.excelservices.com/exceldbs/itstrackdavisbesse.nsf! 1fddceal Od3bdbb585256e... 7/18/2008

NRC ITS Tracking Page 2 of 4 exceptionwith regards to neutron detectors, and this exception is captured in the form of a TS Note. [LA051 [Issue Date [11/16/2007 Closeate [02/28/2008 Logged in User: Anonymous +'Responses Licensee Response by Jerry As stated by the NRC reviewer, the CTS 4.3.1.1.3 Note * (Volume Jones on 12/05/2007 8, Page 5), which states, in part, that a "delay time has been assumed for the Reactor Coolant Pump monitor in the determination of the response time of the High Flux/Number of Reactor Coolant Pumps On functional unit," has been proposed to be relocated to the Technical Requirements Manual (TRM), as ustified in Discussion of Change (DOC) LA05 (Page 29). ITS SR 3.3.1.8 (page 38 of 636) does not carry this note over into the TS, but the licensee proposes to place this note, which discusses the exception to the SR, in the TRM, as discussed in LA05 (page 29 of 636). The ITS continues to maintain a Surveillance Requirement (SR) to verify RPS Response Time, SR 3.3.1.8 (Page 38), and this SR is required for ITS Table 3.3.1-1 Function 7, High Flux/Number of Reactor Coolant Pumps On (Page 42). The current RPS Response Time limit for this Function is located in the TRM. The values were allowed to be relocated by the NRC as documented in License Amendment 225. This CTS note is simply providing information concerning what the response time for this Function includes. This is similar to the Notes already in the TRM stating that certain RPS Response Times exclude the neutron detectors, and include the sensors, RPS instrument delay, and breaker delay. These Notes were relocated as part of License Amendment 225. Davis-Besse believes that CTS 4.3.1.1.3 Note

• is similar in purpose and that it should be relocated to the TRM.

Furthermore, the RPS Response Time test is maintained in the ITS, thus this will ensure that proper testing will continue to occur. In addition, since this change is simply moving a Note that describes what the response time limit includes, Davis-Besse does not believe that this is a beyond scope change. Licensee Response by Jerry 1 Jones on 12/05/2007 onNRC Response by Aron Lewin Will request conference call with licersee'via PM. on 12/20/2007,____________________________ NRC Response by Aron Lewin Bases on 12/21/2007 teleconference, expecting licensee to on 12/26/2007 evaluate Note to determine if it is an, exception to the Section 1.0 definiton of Response Time Testing. Licensee Response by Jerry The Note in CTS 4.3.1.1.3 (Volume 8, Page 5) is not an exception Jones on 02/25/2008 to Section 1.0 definition of Response Time Testing. In License Amendment 148, dated May 16, 1990, the response time was changed from 0.451 to 0.631 seconds. Included in the 631 http://www.excelservices.com/exceldbs/itstrackdavisbesse.nsf/1 fddcea 1Od3bdbb585256e... 7/18/2008

NRC ITS Tracking Page 3 of 4 milliseconds is sensor and RPS delay of 371 milliseconds (240 milliseconds of that for the RCP monitors), 80 milliseconds for CRD breaker delay, and 180 milliseconds of margin. The License Amendment clearly states that the 240 millisecond Note is a clarification to identify that the total response time of 631 milliseconds includes the RCP monitor time. As stated in the previous response, the actual RPS Response Time is currently located in the Technical Requirements Manual. NRC Response by Aron Lewin Discuss the discrepancy between the 2/25/2008 response that "the on 02/26/2008 Note in CTS 4.3.1.1.3 (Volume 8, Page 5) is not an exception to Section 1.0 definition of Response Time Testing" and the 12/5/2007 response "but the licensee proposes to place this note, which discusses the exception to the SR." Also discuss the big picture of how a signal gets processed (i.e. event occurs, sensor senses event, RPS cabinet processes signal from sensor, CRD breakers open, etc) and where response time test physically starts (i.e. sensor, RPS cabinet, etc.). Licensee Response by Bill During the 12/26/07 phone call, Davis-Besse was asked to Bentley on 02/27/2008 determine if the note under question was an exception. The Davis-Besse response on 2/25/08 provided the requested information. The reference to the note as an exception in the 12/05/07 was simply rephrasing what was stated by the reviewer in the original question. So, in summary, the note under question is not an exception to the SR. The second part of the reviewer response on 2/26/08 requests information about overall response time. The definition of RPS Response Time in Section 1.0 is "that time interval from when the monitored parameter exceeds its RPS trip setpoint at the channel sensor until electrical power is interrupted at the control rod drive trip breakers." This definition has not changed from CTS to ITS. The ITS Bases for Section 3.3.1 provides detailed information concerning the layout of the RPS instrumentation and signal processing. Davis-Besse has a surveillance procedure for confirming the Overall Response Time of each RPS Channel. That procedure includes a section for the High Flux/Number of Coolant Pumps On function. The overall response time includes the sum of the measured response times for (1) The Sensing Instrument (i.e. the RCP Monitor) (2) Logic Response (i.e. RPS Cabinet) and (3) CRD Trip Breaker. NRC Response by Aron Lewin The 2/27/2008 licensee response: "Davis-Besse has a 'surveillance on 02/27/2008 procedure for confirming the Overall Response Time of each RPS Channel. That procedure includes a section for the High Flux/Number of Coolant Pumps On function. The overall response time includes the sum of the measured response times for (1) The Sensing Instrument (i.e. the RCP Monitor) (2) Logic Response (i.e. RPS Cabinet) and (3) CRD Trip Breaker," does not explicitly address the 2/26/2008 request to discuss where response time testing physically starts. This information is necessary to determine wether the Note is an exception to the 1.0 response time definition. II http:H//www.excelservices.com/exceldbs/itstrack-davisbesse.nsf/1fddcea1Od3bdbb585256e... 7/18/2008

NRC ITS Tracking Page 4 of 4 Licensee Response by Bill On the 2/28/08 phone call, the reviewer requested confirmation Bentley on 02/28/2008 that the response time of the RCP Monitor is tested. This fact is confirmed. The response time of the RCP Monitor is tested. A current input corresponding to the trip setpoint is provided, and the time for the Monitor to provide an output to RPS is measured. NRC Response by Aron Lewin [No further questions at this time. on 02/28/2008 _ Date Created: 11/16/2007 10:29 AM by Aron Lewin Last Modified: 02/28/2008 12:19 PM http://www.excelservices.com/exceldbs/itstrackdavisbesse.nsfl l fddceal 0d3bdbb585256e... 7/18/2008

NRC ITS Tracking Page I of 2

                                                     .1
-   Return to., View Menu [          Print Document RAI Screening Required: Yes                               Status: Closed This Document will be approved by: Tim                    Regulatory Basis must be included in Comments Kobetz                                                    section of this Form This document has been reviewed and                       Yes information in this question contains NO SUNSI sensitive material (the checkbox to the right must be selected before this question can be submitted)

NRC ITS TRACKING NRC Reviewer ID1 200711161031 Conference Call Requested? No C-ategory BSI - Beyond Scope Issue ITS Section: TB POC: JFD Number: Page.Number(s):. ITS 3.3 Aron Lewin 6 Information ITS Number: OS1: DOC-Number: Bases JFD Number: 3.3.1 None M.6 None Discuss how having heat balance evaluation criteria in a licensee controlled document instead of the TS would still assure that the necessary quality of systems and components is maintained, that facility operation will be within safety limits, and that the limiting conditions for operation will be met in accordance with 10 CFR 50.36(d)(3).

Background

Table 4.3-1 of the CTS (page 12 of 636) requires that a Heat Balance be performed every 24 hours, above 15% RTP (High Flux CTS Functional Unit 2, Channel Calibration D(2)). No specific evaluation criteria are listed in the CTS. However, the USAR Section 7.8.1.1 (page 2551 of 4076 in the USAR) states "Both out-of-core and incore detectors are used to obtain the-axial power distribution. The sum of the outputs from the two sections of each Comment m of ratedrange power detector thermal is calibrated to within 2% of heat balance at 100 percent power (RTP). The power range detectors are allowed to indicate more than 2 percent above the heat balance power at power levels less than 100 percent of RTP. The specific allowance is a function of power level and is controlled administratively by plant procedures. The power range detectors must not indicate more than 2 percent below the heat balance power at any power level." The ITS has a Note 1 in SR 3.3.1.2 (page 36 of 636) that states heat balance evaluation criteria as "Adjust power range channel output if the absolute difference exceeds established limits." STS SR 3.3.1.2 in LCO 3.3.1 (NUREG-1430) has very'specific heat balance evaluation criteria and states "Adjust power range channel output if the absolute difference is > [21 % RTP." 10 CFR 50.36(d)(3) states that "surveillance requirements are requirements http://www.excelservices.com/exceldbs/itstrack-davisbesse.nsf/1fddceal Od3bdbb585256e... 7/18/2008

NRC ITS Tracking Page 2 of 2 relating to test, calibration, or inspection to assure that the necessary quality of systems and components is maintained, that facility operation will be within safety limits, and that the limiting conditions for operation will be met." It is unclear how having heat balance evaluation criteria in a licensee controlled document instead of the TS would still assure that the necessary quality of systems and components is maintained, that facility operation will be within safety limits, and that the limiting conditions for operation will be met in accordance with 10 CFR 50.36(d)(3). [M06, JFD6] IssueDatel[ 11/16/2007 Close Date 01/10/2008 Logged in User: Anonymous 'Responses Licensee Response by Bryan The ISTS SR 3.3.1.2 (Volume 8, Page 36) value (2% RTP) is a Kays on 12/03/2007 bracketed value. Thus, Davis-Besse is supposed to provide our plant-specific value for this Surveillance. Currently, the plant-specific value (nor the actual requirement to adjust the power range output) is not in the Davis-Besse Current Technical Specifications, but is provided in UFSAR Section 7.8.1.1, as noted by the NRC reviewer. Davis-Besse has added the requirement to adjust the power range output to the ITS (in SR 3.3.1.2) and included this current licensing basis value (i.e., a reference to UFSAR Section 7.8.1.1) in our ITS Bases for SR 3.3.1.2 (Page 78). Davis-Besse has modified the ITS to be exactly in accordance with the current licensebasis (with respect to the location and controls of the specific value), and desires to continue to control the specific value in plant controlled documents. Since we are exactly in accordance with the current license basis, this item should not be a BSI. Furthermore, changes to the ITS Bases are controlled by a Technical Specification Program in ITS Section 5.5 and changes to the UFSAR are controlled.by the requirements of 10 CFR 50.59. Thus, any changes to this requirement will be _controlled via the requirements in the ITS or NRC regulations. NRC Response by Aron Lewin Will request conference call with licensee via PM. on 12/20/2007 NRC Response by Aron Lewin Issue being tracked to resolution by TAC MD7678 (SRXB). on 01/10/2008 Anticipate any further questions regarding this issue to be charged and documented under TAC MD7678.' Date Created: 11/16/2007 10:31 AM by Aron Lewin Last Modified: 01/10/2008 08:18 AM http://www.excelservices.com/exceldbs/itstrack-davisbesse.nsfllfddcealOd3bdbb585256e... 7/18/2008

NRC ITS Tracking Page I of 2 Retrn o View Menudl Print Do~cumenpti RAI Screening Required: Yes Status: Closed This Document will be approved by: Tim Regulatory Basis must be included in Comments Kobetz section of this Form This document has been reviewed and Yes information in this question contains NO SUNSI sensitive material (the checkbox to the right must be selected before this question can be submitted) NRC ITS TRACKING. NRC Reviewer ID [200711161033 Conference Call Requested? No Category In Scope ITS, Section.: TB .PO.C1: JFD Number.: Page-Numbher(s); ITS 3.3 Aron Lewin None Information ITS Number: 0S1: D.OC.-Numb..er: Bbas-es JFD Numl!ber-: 3.3.1 None None None Discuss how not requiring a Channel Functional Test for the High Flux (CTS Functional Unit 2, ITS Functional Unit la), Flux-Delta Flux-Flow (CTS Functional Unit 4, ITS Functional Unit 8), and High Flux/Number of Reactor Coolant Pumps On (CTS Functional Unit 8, ITS Functional Unit 7), still assures that the necessary quality of systems and components is maintained, that facility operation will be within safety limits, and that the limiting conditions for operation will be met in accordance with 10 CFR 50.36(d)(3).

Background

Table 4.3-1 of the CTS (page 12 of 636) does not require a Channel Functional Test for High Flux (CTS Functional Unit 2), Flux-Delta Flux-Flow (CTS Functional Unit 4), and High Flux/Number of Reactor Coolant Pumps On (CTS Functional Unit 8). Comment The ITS (page 40 of 636) does not require Channel Functional Tests for these ite m s a s we ll. STS Table 3.3.1-1 for LCO 3.3.1 (NUREG-1430) requires Channel Functional Tests for these items (STS Functional Units la, 7, and 8) in order to ensure that the entire channel will perform the intended function. 10 CFR 50.36(d)(3) states that "surveillance requirements are requirements relating to test, calibration, or inspection to assure that the necessary quality of systems and components is maintained, that facility operation will be within safety limits, and that the limiting conditions for operation will be met. It is unclear how not requiring a Channel Functional Test for the High Flux (CTS Functional Unit 2, ITS Functional Unit la), Flux-Delta Flux-Flow (CTS Functional Unit 4, ITS Functional Unit 8), and High Flux/Number of Reactor Coolant Pumps On (CTS Functional Unit 8, ITS Functional Unit 7), still assures that the necessary quality of systems and components is maintained, http://www.excelservices.com/exceldbs/itstrackdavisbesse.nsf/1 fddceal Od3bdbb585256e... 7/18/2008

NRC ITS Tracking Page 2 of 2 that facility operation will be within safety limits, and that the limiting conditions for operation will be met in accordance with 10 CFR 50.36(d)(3). It should be noted that the CTS ITS do require "calibrations with detector exclusions" at the same periodicity as the STS Channel Functional Test periodicity for the listed Functional Units. Issue D)ate 11/16/2007 Close D]ate 12/26/2007 Logged in User: Anonymous

'Responses Licensee Response by Bryan           CTS Table 4.3-1 (Volume 8, Page 12) does not include a specific Kays on 12/03/2007                   requirement for a CHANNEL FUNCTIONAL TEST for Functional Units 2, 4, and 8. However, the CTS does include a requirement for a quarterly CHANNEL CALIBRATION for these three Functional Units. The CTS Definition for CHANNEL CALIBRATION (Volume 3, Page 6) includes the statement "and shall include the CHANNEL FUNCTIONAL TEST." Thus, a CHANNEL FUNCTIONAL TEST is being performed in the CTS, at the same Frequency as the CHANNEL CALIBRATION. The ITS includes the same requirements. The ITS Definition of CHANNEL CALIBRATION (Volume 3, Page 32) includes a CHANNEL FUNCTIONAL TEST requirement, and the ITS includes a CHANNEL CALIBRATION requirement (ITS SR 3.3.1.3, Volume 8, Page 37), as annotated in ITS Table 3.3.1-1 in the Surveillance Requirements column for Functions L.a (Volume 8, Page 40), 7 (Page 42), and 8 (Page 42). Therefore, a CHANNEL FUNCTIONAL TEST is required and maintained in the ITS for the three Functions. Furthermore, the reason the ISTS lists both a Surveillance for the CHANNEL FUNCTIONAL TEST and the CHANNEL CALIBRATION (i.e., ISTS SRs 3.3.1.4 and 3.3.1.5 is because the Frequencies of the SRs are different - the Frequency for ISTS SR 3.3.1.4 is 45 days on a STAGGERED TEST BASIS and the Frequency for ISTS SR 3.3.1.5 is 18 months).

NRC Response by Aron Lewin Will request conference call with licensee via PM. on 12/20/2007 [NRC Response by Aron Lewin No further questions at this time. on 12/26/2007 1 Date Created: 11/16/2007 10:33 AM by Aron Lewin Last Modified: 12/26/2007 08:33 AM http://www.excelservices.com/exceldbs/itstrackdavisbesse.nsf/1 fddcea1Od3bdbb585256e... 7/18/2008

NRC ITS Tracking Page I of 2 Return to View Menu irPrint Document, RAI Screening Required: Yes Status: Closed This Document will be approved by: Tim Regulatory Basis must be included in Comments Kobetz section of this Form This document has been reviewed and Yes information in this question contains NO SUNSI sensitive material (the checkbox to the right must be selected before this question can be submitted) NRC ITS TRACKING NRC Reviewer [ID 1200711161034 Conference Call Requested? No Catego BSI - Beyond Scope Issue ITS.Section: TB POC.:. F.D NuAmber.: Page Nunmber(s):ý ITS 3.3 Aron Lewin None Information ITS-Number.: OS.:. DO..C Number: Bases JFD Number: 3.3.1 None None None Discuss how not requiring a Channel Functional Test for the High Flux - Low Setpoint still assures that the necessary quality of systems and components is maintained, that facility operation will be within safety limits, and that the limiting conditions for operation will be met in accordance with 10 CFR 50.36 (d)(3).

Background

Table 4.3-1 of the CTS (page 12 of 636) does not list a High Flux - Low Setpoint. Table 3.3.1-1 of the ITS (page 40 of 636) lists a High Flux - Low Setpoint (Function 1.b) but does not require Channel Functional Test. Comm-nent STS Table 3.3.1-1 for LCO 3.3.1 (NUREG-1430) requires a Channel Functional Test for the High Flux - Low Setpoint (STS SR 3.3.1.4). 10 CFR 50.36(d)(3) states that "surveillance requirements are requirements relating to test, calibration, or inspection to assure that the necessary quality of systems and components is maintained, that facility operation will be within safety limits, and that the limiting conditions for operation will be met. It is unclear how not requiring a Channel Functional Test for the High Flux - Low Setpoint still assures that the necessary quality of systems and components is maintained, that facility operation will be within safety limits, and that the limiting conditions for operation will be met in accordance with 10 CFR 50.36(d)(3). Issue I11/16/2007 [Date Close.Date 112/26/2007 Logged in User: Anonymous http://www.excelservices.com/exceldbs/itstrackdavisbesse.nsf/1 fddceal Od3bdbb585256e... 7/18/2008

NRC ITS Tracking .Page 2 of 2

'Responses Licensee Response by Bryan        CTS Table 4.3-1 (Volume 8, Page 12) does not include a specific Kays on 12/03/2007                requirement for a CHANNEL FUNCTIONAL TEST for Functional Unit 2. However, the CTS does include a requirement for a quarterly CHANNEL CALIBRATION for this Functional Unit. The CTS Definition for CHANNEL CALIBRATION (Volume 3, Page 6) includes the statement "and shall include the CHANNEL FUNCTIONAL TEST." Thus, a CHANNEL FUNCTIONAL TEST is being performed in the CTS, at the same Frequency as the CHANNEL CALIBRATION. The ITS includes the same requirements. The ITS Definition of CHANNEL CALIBRATION (Volume 3, Page 32) includes a CHANNEL FUNCTIONAL TEST requirement, and the ITS includes a CHANNEL CALIBRATION requirement (ITS SR 3.3.1.3, Volume 8, Page 37), as annotated in ITS Table 3.3.1-1 in the Surveillance Requirements column for Function 1.b (Volume 8, Page 40). Therefore, a CHANNEL FUNCTIONAL TEST is required and maintained in the ITS for the Function. Furthermore, the reason the ISTS lists both a Surveillance for the CHANNEL FUNCTIONAL TEST and the CHANNEL CALIBRATION (i.e.,

ISTS SRs 3.3.1.4 and 3.3.1.5 is because the Frequencies of the SRs are different - the Frequency for ISTS SR 3.3.1.4 is 45 days on a STAGGERED TEST BASIS and the Frequency for ISTS SR 3.3.1.5 is 18 months). NRC Response by Aron Lewin Will request conference call with licensee to discuss. on 12/20/2007 NRC Response by Aron Lewin No further questions at this time. on 12/26/2007 Date Created; 11/16/2007 10:34 AM by Aron Lewin Last Modified: 12/26/2007 08:33 AM http://www.excelservices.com/exceldbs/itstrack davisbesse.nsf/1 fddcea 1Od3bdbb585256e... 7/18/2008

NRC ITS Tracking Page I of 2 I Reurn to View Menlu 1..Print Documenj. RAT Screening Required: Yes Status: Closed This Document will be approved by: Tim Regulatory Basis must be included in Comments Kobetz section of this Form This document has been reviewed and Yes information in this question contains NO SUNSI sensitive material (the checkbox to the right must be selected before this question can be submitted) NRC ITS TRACKING NRC ReviewerR i 200711161036 Conference Call Requested? No cateo BSI - Beyond Scope Issue ITS.Sectio.: TB POC: JFD Number:, Page_ Numbn.e*.r(s): ITS 3.3 Aron Lewin 13 Informnation ITS.Number: OSI; DO C N.umber: Bases JFD Num-ber: 3.3.1 None None None As permitted by 10 CFR 50.36(d)(2)(i), discuss how adopting the phrase "control rod" vice "CONTROL ROD" effects physical application of remedial actions listed for ITS Required Action D.2 when compared to STS Required Action D.2.

Background

The CTS has no definition for CONTROL ROD in Section 1.0, "Definitions." The ITS does have a definition for CONTROL ROD (page 15 of 71 for ITS Chapter 1). Condition D in ITS LCO 3.3.1 (page 15 of 636 for ITS Section 3.3) lists a Required Action D.2 that uses the term "control rod." STS for LCO 3.3.1 (NUREG-1430) lists a Required Action D.2 that uses the CQommert term "CONTROL ROD." 10 CFR 50.36(d)(2)(i) states that "limiting conditions for operation are the lowest functional capability or performance levels of equipment required for safe operation of the facility. When a limiting condition for operation of a nuclear reactor is not met, the licensee shall shut down the reactor or follow any remedial action permitted by the technical specifications until the condition can be met." As permitted by 10 CFR 50.36(d)(2)(i), it is unclear if adopting the phrase "control rod" vice "CONTROL ROD" effects physical application of remedial actions listed for ITS Required Action D.2 when compared to STS Required Action D.2. [JFD13] Issue Date 11/16/2007 Close .Date [01/10/2008 Logged in User: Anonymous http://www.excelservices.com/exceldbs/itstrack-davisbesse.nsf/1fddcea1Od3bdbb585256e... 7/18/2008

NRC ITS Tracking Page 2 of 2 - 'Resoonses Licensee Response by Bryan rhis response is similar to that provided for questions Kays on 12/03/2007 200711161103, 200711161104, and 200711161106. The defined term CONTROL RODS, as defined in ITS Section 1.1 (Volume 3, Page 33) states that CONTROL RODS are full length safety and regulating rods. ISTS 3.3.1 Required Action D. 1 (Volume 8, Page

35) requires all CONTROL ROD drive (CRD) trip breakers to be open. One problem with using the term CONTROL ROD in this Required Action is that the CRD trip breakers provide power not only to the safety and regulating rods, but also to the AXIAL POWER SHAPING RODS (APSRs), which are also defined in ITS Section 1.1. Secondly, the acronym "CRD" refers to the Control Rod Drive System, and is not limited to only "CONTROL RODS" as defined in ITS Section 1.1. Therefore for consistency throughout the Davis-Besse ITS, whenever the term CONTROL RODS in the ISTS could be applied to an application that includes the APSRs, the term was changed to "control rods." This change is considered as an editorial change to correct an error in the ISTS, and no technical change is intended. Therefore, this change is not a beyond scope change and does not affect any application of the Required Actions.

NRC Response by Aron Lewin Will request conference call with licensee via PM. on 12/20/2007 ___ NRC Response by AIron Lewin Based on 12/21/07 teleconference, anticipated licensee to submit on 01/10/2008 corrections. Thread will be closed out once licensee responds indicating such actions will be taken. Licensee Response by Bryan Based on a conversation with the NRC concerning RAIs Kays on 01/10/2008 200711161036,200711'161!03,200.711161104,and 200711161106, the term "control rod" used in ITS 3.3.1 and Bases (Volume 8, Pages 35, 44, 49, 60, and 73) has been changed back to "CONTROL ROD,"' consistent with the ISTS. A draft markup, regarding- this change is attached. This change will be reflected in _ _ _ _ _ the supplement to this section of the ITS Conversion Amendment. NRC Response by' Aron Lewin No further questions at this time,. on 01/10/2008 ____________________________ DateCreated: 11/16/2007 10:36 AM by Aron Lewin Last Modified: 01/10/2008.09:22 AM http://www.excelservices.com/exceldbs/itstrackdavisbesse.nsf/1 fddceal Od3bdbb585256e... 7/18/2008

NRC ITS Tracking Page I of 2 Return to View Menu Print Document RA-I Screening Required: Yes Status: Closed This Document will be approved by: Tim Regulatory Basis must be included-in Comments Kobetz section of this Form This document has been reviewed and Yes information in this question contains NO SUNSI sensitive material (the checkbox to the right must be selected before this question can be submitted) NRC ITS TRACKING NRC Reviewer D 200711161037 Conference Call Requested? No' Categoy BSI - Beyond Scope Issue ITS Section: TB POC: JFD Number: Page.Number(s):. ITS 3.3 Aron Lewin 2 Information ITS Number: OSI: DOC N4xmb.r: B.ases-,JFD Number:' 3.3.1 None None None As permitted by 10 CFR 50.36(d)(2)(i), discuss why the addition of the Note in ITS Required Action D.2 would.be considered an appropriate remedial action if the LCO is not met.

Background

CTS Action 10 (page 10 of 636), which applies to CTS Functional Units 2 thru 9, states that "with the number of channels OPERABLE one less than the Minimum Channels OPERABLE requirement, within one hour, place one inoperable channel in trip and the second inoperable channel in bypass, and restore one of the inoperable channels to OPERABLE status within 48 hours, or be in HOT STANDBY within the next 6 hours and open the. reactor trip breakers." ITS Required Action D.2 (page 15 of 636) adds:a Note stating that the Comment requirement to open all control rod drive (CRD) trip breakers is only applicable to ITS Functions Ia (High Flux - High Setpoint), 3 (RC High Pressure), and 6 (Containment High Pressure). STS Required Action D.2 does not contain this note (i.e it is applicable to CTS equivalent Functional Units 2 thru 9). 10 CFR 50.36(d)(2)(i) states that "limiting conditions for operation are the lowest functional capability or performance levels of equipment required for safe operation of the facility. When a limiting condition for operation of a nuclear, reactor is not met, the licensee shall shut down the reactor or follow any remedial action permitted by the technical specifications until the condition can be met." As permitted by 10 CFR 50.36(d)(2)(i), it is unclear why the addition of the Note in ITS Required Action D.2 would be considered an appropriate remedial action if the LCO is not met. [JFD2] http://www.excelservices.com/exceldbs/itstrackdavisbesse.nsf/1 fddceal Od3bdbb585256e... 7/18/2.008

NRC ITS, Tracking Page 2 of 2 [IIssue Close Date 112/20/2007 vResponses Date, 11/16/2007 Logged in User: Anonymous 1 Licensee Response by Bryan CTS Table 3.3-.1 Action 10 (Volume 8, Page 10) is applicable to Kays on 12/03/2007 Functional Units with an Applicability of MODES 1 and 2. In CTS, once the Unit has entered HOT STANDBY, the LCO is no longer required to be met and any applicable Actions are no longer required to be taken, as described in CTS LCO 3.0.1. Therefore, once the unit has been placed in HOT STANDBY (MODE 3) as required by CTS Table 3.3-1 Action 10, the requirement to open the control rod drive breakers is not actually applicable. However, the Applicability forITS Table 3.3.1-1, Functions 1.a, 3, and 6 (Page 40) has been modified to include a MODE 3 Applicability requirement, as described in ITS 3.3.1 Discussion of Changes (DOCs) MO1 and M02 (Page 24). Therefore, since ITS 3.3.1 ACTION D (Page 35) applies to multiple Functions, and not all of the applicable Functions include a MODE 3 Applicability requirement, the Davis-Besse ITS includes a Required Action Note to clearly state that the requirement to open all control rod drive (CRD) trip breakers (ITS 3.3.1 Required Action D.2) only applies to Functions 1.a', 3, and 6. As stated in Justification for Deviation (JFD) 2 (Page 43), a Note has been added to ITS 3.3.1 Required Action D.2 (Page 35) that states the Required Action is only applicable to.Functions 1.a, 3, and 6. This change is necessary to be consistent with the Applicabilities of the Functions in ITS Table 3.3.1-1. ITS 3.3.1 Condition D also applies to Functions 2, 4, 5, 7, and 8; however the Functions are only required to be applicable in MODES 1 and 2. Therefore, it ismnot necessary to open all CRD trip breakers for these Functions. Also, as discussed in the response to question 200711160949, a new DOC. was added to explain the addition of the Note. Refer to the Davis-Besse response to 20071.1160949 for information on the new DOC. Therefore, since this change is only a: clarification and does not change the intent of the Required Action, Davis-Besse does not believe this item is a beyond scope change. NRC Response by Aron Lewin No further questions at this time. on 12/20/2007 _ _..__* ,_ __* Date Created: 11/16/2007 10:37 AM by Aron Lewin Last Modified: 12/20/2007 01:04 PM http://www.excelservices.com/exceldbs/itstrackdavisbesse.nsf/1 fddceal Od3bdbb585256e... 7/18/2008

NRC ITS Tracking Page I of 2 14'Return to View Menu Prit~oun RAI Screening Required: Yes Status: Closed This Document will be approved by: Tim Regulatory Basis must be included in Comments Kobetz section of this Form This document has been reviewed and Yes information in this question contains NO SUNSI sensitive material (the checkbox to the right must be selected before this question can be submitted) NRC ITS TRACKING NRC Reviewer ID 200711161039 Conference Call Requested? No Categoryj In Scope ITS.Section: TB POC: .JFD Number: Page-Number(s): ITS 3.3 Aron Lewin None Information ITS.Number: OSI.J:" DOC.Number: Bas.es.-JFD .Numbe-r-: 3.3.1 None None None Based on discussions in NUREG-737 and IE Bulletin 79-05B, discuss how omission of reactor trips for loss of feedwater and turbine trips would still result in 10 CFR 50.36(d)(1)(ii)(A) being met.

Background

The CTS do not contain reactor trips for loss of feedwater and turbine trip. The ITS do not contain reactor trips for loss of feedwater and turbine trips. STS Table 3.3.1-1 for LCO 3.3.1 (NUREG-1430) contains reactor trips for loss of feedwater (STS Function 10) and turbine trips (STS Function 9). 10 CFR 50.36(d)(1)(ii)(A) states that Technical specifications will include Comment "limiting safety system settings for nuclear reactors [which] are settings for om....n automatic protective devices related to those variables having significant safety functions." NUREG-737, "Clarification ,of TMI Action Plan Requirements," Section II.K.2.10 (on page 151 of 258 in ADAMs No. ML051400209), discusses how IE Bulletin 79-05B, Item 5, issued on April 21, 1979, directed B&W licensees to provide a design and schedule for implementation of a safety-grade reactor trip upon loss of feedwater and turbine trip. Based on discussions in NUREG-737 and IE Bulletin 79-05B, it is unclear how omission of reactor trips for loss of feedwater and turbine trips would still result in 10 CFR 50.36(d)(1)(ii)(A) being met. Issue Date 11/16/2007 Close Date [01/10/2008 Logged in User: Anonymous

'Responses http://www.excelservices.com/exceldbs/itstrackdavisbesse.nsf/1 fddceal 0d3bdbb585256e... 7/18/2008

NRC ITS Tracking Page 2 of 2 Licensee Response by Bryan Davis-Besse added the Anticipatory Reactor Trip System Kays on 12/03/2007 Instrumentation as a result of the NUREG-0737 issues described in the NRC question. These trips are not part of the Reactor Protection System instrumentation. The trips are currently required by CTS 3/4.3.2.3. However, the instrumentation does not meet any of the 10 CFR 50.36(d)(2)(ii) criteria, as discussed in CTS 3/4.3.2.3 Discussion of Change RO0 (Volume 8, Pages 622 and 623). Therefore, the requirements are not being maintained in the ITS. The entire Specification is in Attachment 19 of Volume 8, starting on Page 616. NRC Response by Aron Lewin Will request conference call with licensee via PM. on 12/20/2007 NRC Response by Aron Lewin Issue being tracked to resolution by TAC MD7679 (SRXB). on 01/10/2008 Anticipate any further questions regarding this issue to be charged and documented under TAC M1D7679. Date Created: 11/16/2007 10:39 AM by Aron Lewin Last Modified: 0 1/10/2008 08:24 AM http://www.excelservices.com/exceldbs/itstrackdavisbesse.nsf/1 fddcea 10d3bdbb585256e... 7/18/2008

NRC ITS Tracking Page I of 3 I. 11/Return to View Menu Pint Document RAI Screening Required: Yes Status: Closed This Document will be approved by: Tim Regulatory Basis must be included in Comments Kobetz section of this Form This document has been reviewed and Yes information in this question contains NO SUNSI sensitive material (the checkbox to the right must be selected before this question can be submitted) NRC ITS TRACKING NRC Reviewer ID 1200711161040 Conference Call Requested? No Category In Scope ITS Section: TB.POC: JFD Number: Page Number(s): ITS 3.3 Aron Lewin 10 Information ITS.Number: OS": DOC Number: Bases JFD Number: 3.3.1 None None None Discuss how not requiring a decade overlap of the power range monitor, still assures that the necessary quality of systems and components is maintained, that facility operation will be within safety limits, and that the limiting conditions for operation will be met in accordance with 10 CFR 50.36(d)(3).

Background

Table 4.3-1 of the CTS (page 12 of 636) does not list a requirement for a decade overlap check for the High Flux instrument (CTS Functional Unit 2). The ITS Bases (page 77 of 636) eliminates the ITS TS requirement for a decade overlap check for the High Flux instrument (ITS Functional Unit 1) as a part of the Channel Check ITS SR 3.3.1.1. The STS Bases for STS SR 3.3.1.1 (NUREG-1430), Channel Check, states "the agreement criteria includes an expectation of one decade of overlap when Comment transitioning between neutron flux instrumentation. For example, during a power increase near the top of the scale of the intermediate range monitors, a power range monitor reading is expected with at least one decade overlap. Without such an overlap, the power range monitors are considered inoperable unless it is clear that an intermediate range monitor inoperability is responsible for the lack of the expected overlap." 10 CFR 50.36(d)(3) states that "surveillance requirements are requirements relating to test, calibration, or inspection to assure that the necessary quality of systems and components is maintained, that facility operation will be within safety limits, and that the limiting conditions for operation will be met. It is unclear how not requiring a decade overlap of the power range monitor, still assures that the necessary quality of systems and components is maintained, that facility operation will be within safety limits, and that the limiting conditions for operation will be met in accordance with 10 CFR 50.36 http://www.excelservices.com/exceldbs/itstrackdavisbesse.nsfl1 fddcealOd3bdbb585256e.... 7/18/2008

NRC ITS Tracking Page 2 of 3 (d)(3). [JFD10I I Issue Daate 11/16/2007, I Close Datel01/10/2008 Logged in User: Anonymous

'Responses Licensee Response by Bryan          The ISTS Bases discussion associated with the intermediate range Kays on 12/03/2007                  and the power range overlap (Volume 8, Page 77) has been deleted. This ISTS Bases requires an overlap check to be performed between the intermediate range and the power range monitors during the top of the scale of the intermediate range monitors and states there is an expected overlap of at least a decade. The current licensing basis does not include any overlap requirements for the power range monitors, which are the only neutron flux monitor requirements in ITS 3.3.1. In addition, these requirements are not consistent with the CHANNEL CHECK requirements in the actual Surveillance Requirement. The definition of CHANNEL CHECK in ISTS Section 1.1 (Volume 3, Page 32 and 33) states "A CHANNEL CHECK shall be qualitative assessment, by observation, of channel behavior during operation.

This determination shall include, where possible, comparison of the channel indication and status to other indications or status derived from independent instrument channels measuring the same parameter." The definition does not require an overlap check of any type of channel. This overlap check described in the Bases is an additional requirement, over and above the requirements in the actual Surveillance Requirement. This information is provided in Bases Justification for Deviation (JFD) 10 (Volume 8, Page 87). In addition, these incorrect ISTS Bases words (i.e., the Bases cannot change or add requirements found in the actual ISTS) have been allowed to be deleted in previous ITS submittals (for example, Monticello ITS conversion, NRC SER dated 7/5/06) using a similar Justification for Deviation as provided in the Davis-Besse ITS submittal. Furthermore, it takes a number of hours to achieve a decade of overlap between the intermediate and power range indicators. The reactor does not just quickly go from zero power to 10% power (i.e., a decade of overlap). A better check of power range indication OPERABILITY would'be to perform a heat balance check (for example, a certain core delta T or certain feedwater flow can be roughly converted to a certain power, level). This provides a continual check of power range functioning as power level is increased, and can be checked sooner than waiting for a decade of overlap. In accordance with the plant startup procedures, an NI to Heat Balance comparison is performed at 5%, 10% and every 5% power change after that. Therefore, for the above reasons, the inclusion of this overlap requirement should not be included in the Davis-Besse ITS, and not including it should not be considered a beyond scope change. I1 http://www.excelservices.com/exceldbs/itstrackdavisbesse.nsf/1 fddcea 1Od3bdbb585256e... 7/18/2008

NRC ITS Tracking Page 3 of 3 12/20/207Respnse by Aron Lewin onRC Will request conference call with licensee via PM. NRC Response by Aron Lewin Issue being tracked to resolution by TAC MD7680 (EICB). on 01/10/2008 [Anticipate any further questions regarding this issue to be charged __and documented under TAC MD7680. Date Created: 11/16/2007 10:40 AM by Aron Lewin Last Modified: 0 1/10/2008 08:26 AM http://www.excelservices.com/exceldbs/itstrack-davisbesse.nsf/1fddcea1Od3bdbb585256e... 7/18/2008

NRC ITS Tracking Page I of 2 JJýReturn to View Menu Print DcL iýn RAI Screening Required: Yes Status: Closed This Document will be approved by: Tim Regulatory Basis must be includedin Comments Kobetz section of this Form This document has been reviewed and Yes information in this question contains NO SUNSI sensitive material (the checkbox to the right must be selected before this question can be submitted) NRC ITS TRACKING NRC Reviewer ID 1200711161050 Conference Call Requested? No Category BSI - Beyond Scope Issue ITS Section: TB P.OC.:. JFD-Number:. Page..Number(s): ITS 3.3 Aron Lewin None Information ITS Number: OSI: DOC Number: Bascs JFD Number: 3.3.1 None None None Discuss how allowing modification to the reference to Unit Specific Setpoint Methodology would effect physical application of the LCO at the plant and, in addition, still give assurance that the limiting safety system setting is chosen so that automatic protective action will correct the abnormal situation before a safety limit is exceeded in accordance with 10 CFR 50.36(d)(1)(ii)(A).

Background

The Bases for CTS 3/4.3.1 and 3/4.3.2 (page 398 and 399 of 490 in the CTS) do not explicitly discuss on-line testing. The Bases for the ITS (page 59 of 636) state "each channel can be tested online to verify that the signal and setpoint accuracy are within the specified allowance requirements of Reference 8 [UFSAR, Section 7.2.11." UFSAR 7.2.1 seems to be an RPS description and does not seem to contain instrument Comment setpoint methodology. The Bases for the STS for LCO 3.3.1 (NUREG-1430) state "each channel can be tested online to verify that the signal and setpoint accuracy are within the specified allowance requirements of Reference 5 [Unit Specific Setpoint Methodology]." 10 CFR 50.36(d)(1)(ii)(A) states that "limiting safety system settings for nuclear reactors are settings for automatic protective devices related to those variables having significant safety functions. Where a limiting safety system setting is specified for a variable on which a safety limit has been placed, the setting must be so chosen that automatic protective action will correct the abnormal situation before a safety limit is exceeded." It is unclear how allowing modification to the reference to Unit Specific Setpoint Methodology would effect physical application of the LCO at the plant and, in addition, still give assurance that the limiting safety system http://www.excelservices.com/exceldbs/itstrackdavisbesse.nsf/1 fddceal Od3bdbb585256e... 7/18/2008

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NRC ITS Tracking Page 2 of 2 setting is chosen so that automatic protective action will correct the abnormal situation before a safety limit is exceeded in accordance with 10 CFR 50.36(d) (1)(ii)(A). IssueDate 111/16/2007 I Close Date[] 12/20/2007 Logged in User: Anonymous

'Responses Licensee Response by Jerry         The NRC reviewer is correct in that UFSAR 7.2.1 is an RPS Jones on 12/05/2007                description and does nto concern instrument setpoint methodology.

This is an incorrect reference. Since the setpoint methodology is explained in a previous paragraph on the same Bases page (Volume 8, Page 59), the words "of Reference 8" in the IST Bases are not necessary. Therefore, the words will be deleted and the subsequent References will be renumbered to reflect the deletion of current Reference 8 (UFSAR, Section 7.2.1). A draft markup regarding this change is attached. This change will be reflected in the supplement to this section of the ITS Conversion Amendment. NRC Response by Aron Lewin ]No further comments at this time. on 12/20/2007 _ Date Created: 11/16/2007 10:50 AM by Aron Lewin Last Modified: 12/20/2007 01:04 PM http://www.excelservices.com/exceldbs/itstrackdavisbesse.nsfl1 fddceal0d3bdbb585256e... 7/18/2008

NRC ITS Tracking Page I of 2 Return to View Menu IdaPrnt oc~uniet RAI Screening Required: Yes Status: Closed This Document will be approved by: Carl Regulatory Basis must be included in Comments Schulten; Gerald Waig section of this Form This document has been reviewed and Yes information in this question contains NO SUNSI sensitive material (the checkbox to the right must be selected before this question can be submitted) NRC ITS TRACKING NRC Rpvipe'vr ID 200803061234 Conference Call Requested? No Catýegor Other Technical Challenge ITS Section: TB POC: J.D Numbe-r: Page Number(s): ITS 3.3 Aron Lewin None Information ITS Number: OS: DOC Number:. Bases JFD Number: 3.3.1 None None None During a 3/5/2008 teleconference call, the licensee recommended that the NRC

          ............. post Comment               a question changes          requesting that have           them to submit the ITS markups of the revised TS recently been docketed for the MUR power uprate. This thread requests that change for review.

Issue Date 03/06/2008 close Date 06/04/2008 Logged in User: Anonymous

'Responses Licensee Response by Bryan                Attached is the proposed markup to incorporate the changes to Kays on 03/13/2008                        CALDON power uprate License Amendment Request, provided in the letter dated February 20, 2008. The CALDON power uprate submittal is a change being made outside the ITS conversion process. Note that the markup includes a change to Justification for Deviation (JFD) 12, which was previously proposed to be changed in the Davis-Besse response to question 200711160953. However, this change to the JFD is not affected by the 200711160953 change, since that change only affects the first sentence of JFD 12 and this change affects the second sentence of JFD 12, and the two sentences are discussing different ITS Notes. This change will be reflected in the supplement to this section of the ITS Conversion Amendment.

Licensee Response by Jerry This response supersedes the response on 3/13/2008. Attached is Jones on 05/19/2008 the proposed markup to incorporate the changes to CALDON http://www.excelservices.com/exceldbs/itstrackdavisbesse.nsf/1 fddceal Od3bdbb585256e... 7/18/2008

NRC ITS Tracking Page 2 of 2 power uprate License Amendment Request, provided in the letter dated February 20, 2008 and updated per correspondence on May 19, 2008. The CALDON power uprate submittal is a change being made outside the ITS conversion process. Note that the markup includes a change to Justification for Deviation (JFD) 12, which was previously proposed to be changed in the Davis-Besse response to question 200711160953. However, this change to the JFD is not affected by the 200711160953 change, since that change only affects the first sentence of JFD 12 and this change affects the second sentence of JFD 12, and the two sentences are discussing different ITS Notes. This change will be reflected in the

                                 ,,supplement to this section of the ITS Conversion Amendment.

NRC Response by Aron Lewin o further questions at this time. on 06/04/2008 Na Date Created: 03/06/2008 12:34 PM by.Aron Lewin Last Modified: 06/04/2008 12:15 PM http://www.excelservices.com/exceldbs/itstrackdavisbesse.nsf/1 fddceal Od3bdbb585256e... 7/18/2008

NRC ITS Tracking Page I of 2 j0Return to View Menu& Print Docmn RAI Screening Required: Yes Status: Closed This Document will be approved by: Carl Regulatory Basis must be included in Comments Schulten; Gerald Waig section of this Form This document has been reviewed and Yes information in this question contains NO SUNSI sensitive material (the checkbox to the right must be selected before this question can -be submitted) NRC ITS TRACKING NRC Reviewer ID 200804030757 Conference Call Requested? No Categry [Other Technical Challenge ITS..Section: TB POC: JFD Number:ý Page.Numiber(s); ITS 3.3 Aron Lewin None Information ITS Number: OS:.;. OC Number: Bases JFD Number: 3.3.1 27 None None Thread 200711161012 was inadvertantly closed out due to it being tracked by TAC MD7470. The regulatory discussion in thread 200711161012 applies to this thread as well. Comment During a 4/2/08 conference call the licensee stated they would adddress the NRC concerns regarding the use of the phrase "Instrument uncertainties and other uncertanties are not a factor in determining the Allowable Vlaue." This thread is being posted to allow the licensee to address the NRC concerns since thread 200711161012 is already closed. Issue Date ] 04/03/2008 Close Date [04/07/2008 Logged in User: Anonymous

'Responses Licensee Response by Bryan                             Davis-Beese has decided to remove the phrase "Instrument Kays on 04/06/2008                                     uncertainties and other uncertainties are not a factor in determining the Allowable Value" from the ITS 3.3.1 Bases Applicable Safety Analyses, LCO and Applicability section (Volume 8, Page 65).

Additionally, Davis-Besse has restored the paragraph to its original configuration by clarifying that the Allowable Value is a setpoint Allowable Value. A draft markup regarding this change is attached. This change will be reflected in the supplement to this section of the ITS Conversion Amendment. NRC Response by Aron Lewin No further questions at this time. on 04/07/2008 http://www.excelservices.com/exceldbs/itstrackdavisbesse.nsf/1 fddcea 1Od3bdbb585256e... 7/18/2008

NRC ITS Tracking Page 2 of 2' Date Created: 04/03/2008 07:57 AM by Aron Lewin Last Modified: 04/07/2008 08:56 AM http://www.excelservices.com/exceldbs/itstrackdavisbesse.nsf/1 fddcealOd3bdbb585256e... 7/18/2008.

NRC ITS Tracking Page I of 3 Return to View Menu WPrint Doc~ument RAT Screening Required: No Status: Approval Not Required This is a Non RA! Dialogue This document will not be relied upon by staff for disposition of the LAR This document has been reviewed and Yes information in this question contains NO SUNSI sensitive material (the checkbox to the right must be selected before this question can be submitted) NRC ITS TRACKING NRC Reviewer ID 200805211307 Conference Call Requested? No Category Other Technical Challenge ITS Section: TB POC: JFD Number: Page Number(s)': ITS 3.3 Aron Lewin None Information ITS Number: OSI: DOC Number: Bases JFD Number: 3.3.1 None None None Thread 200711161039 was inadvertantly closed out. This thread continues the discussion on thread 200711161039. The regulatory discussion that applied to thread 200711161039, applies to this thread as well. Comment During a conference call on May 14, 2008, the NRC discussed regulatory and technical concerns regarding relocation of the anticipatory reactor trips out of TS. The licensee stated that they would retain the anticipatory reactor trips in TS. This thread is being kept open to facilitate the revised submittal IIssue D~ate 05/21/2008 Close Date F06/30/2008 Logged in User: Anonymous

'Responses Licensee Response by Jerry           While the ARTS does not meet any criteria of 10 CFR 50.36(d)(2)

Jones on 06/03/2008 (ii) for inclusion in the ITS, Davis-Besse will retain the ARTS in the ITS. The proposed Specification is consistent with the current licensing basis, as modified to be consistent with the ISTS format and, with changes allowed in the RPS Specification (ISTS 3.3.1) that are similar in nature to the ARTS Specification. A draft markup regarding this change is attached. This change will be reflected in the supplement to this section of the ITS Conversion Amendment. NRC Response by Aron Lewin Proposed LCO 3.3.19, "Anticipatory Reactor Trip System (ARTS) on 06/05/2008 Instrumentation" does not contain any calibration Surveillance http://www.excelservices.com/exceldbs/itstrack-davisbesse.nsfl/fddceal d3bdbb585256e... 7/18/2008

NRC ITS Tracking Page 2 of 3 Requirements (SR) for Function 1 (Turbine Trip) and Function 2 (Trip of Both Main Feed Pump Turbines), but instead only contains SR 3.3.19.3, which is a Functional Test SR. In proposed Section 1.1, "Definitions," a Channel Functional Test is defined as "a Channel Functional Test shall be the injection of a simulated or actual signal into the channel as close to the sensor' as practicable to verify Operability of all devices in the channel required for channel Operability." In proposed Section 1.1, "Definitions," a Channel Calibration is defined as "a Channel Calibration shall be the adjustment, as necessary, of the channel output such that it responds within the necessary range and accuracy to known values of the parameter that the channel monitors. The Channel Calibration shall encompass all devices in the channel required for channel Operability and the Channel Functional Test." Based on the proposed Davis-Besse definitions of a Channel Functional Test and a Channel Calibration, proposed SR 3.3.19.3 does not require testing of the sensor for Functions 1 and 2. For comparison, NUREG-1430, "Standard Technical Specifications Babcock and Wilcox Plants," contains LCO 3.3.1, "Reactor Protection System (RPS) Instrumentation," which contains Function 9 (Main Turbine Trip) and Function 10 (Loss of Main Feedwater Pumps). Both STS Functions 9 and 10, which are similar to proposed Davis-Besse Functions 1 and 2, contain STS SR 3.3.5 which is a Channel Calibration SR. The Bases for STS LCO 3.3.1 states "a Channel Calibration is a complete check of the instrument channel, including the sensor." 10 CFR 50.36(d)(3) states technical specifications will include surveillance requirements which "are requirements relating to test, calibration, or inspection to assure that the necessary quality of systems and components is maintained, that facility operation will be within safety limits, and that the limiting conditions for operation will be met," Based on the discussion in NUREG-1430, it is unclear how 10 CFR 50.36(d) (3) is met if the sensors are not required to be tested in the technical specifications for the Davis-Besse ARTS Turbine Trip (Functionl) and the ARTS Trip of Both Main Feed Pump Turbines (Function 2). Licensee Response by Jerry Davis-Besse has re-evaluated the CTS requirements and notes that Jones on 06/12/2008 the old definition of CHANNEL FUNCTIONAL TEST included a requirement to inject the signal "into the channel sensor" to verify OPERABILITY. As part of the ITS conversion, the definition was changed to only require injecting the signal as close to the sensor as practicable. While this is appropriate for other ITS sensors (since other ITS sensors include CHANNEL CALIBRATION requirements), it does not completely envelop the ARTS sensors, since no CHANNEL CALIBRATION requirement is specified in the CTS. Therefore, the ITS will require a CHANNEL CALIBRATION for these two functions at the same Frequency as the current CHANNEL FUNCTIONAL TEST requirement. This new CHANNEL CALIBRATION requirement is essentially equivalent to the CTS CHANNEL FUNCTIONAL TEST http://www.excelservices.com/exceldbs/itstrackdavisbesse.nsf/1 fddceal Od3bdbb585256e... 7/18/2008

NRC ITS Tiacking Page 3 of 3 requirement; therefore it is consistent with the Davis-Besse current licensing basis. In addition, the ITS number has been changed from ITS 3.3.19 to ITS 3.3.16 due to the previous ITS 3.3.16 being renumbered in place of the ITS 3.3.15 that was deleted as described in RAIs 200801161530 and 200801161532. A draft markup regarding this change is attached and supersedes the draft markup provided in the 6/3/08 response. This change will be reflected in the supplement to this section of the ITS Conversion Amendment. Licensee Response by Jerry During a recent phone conversation with the NRC reviewer, Jones on 06/30/2008 clarification was provided concerning the words being requested to be added to the Bases for the CHANNEL CALIBRATION. A draft markup regarding this change is attached and supersedes the draft markup provided with the Davis-Besse 6/12/08 response. This change will be reflected in the supplement to this section of the ITS Conversion Amendment. NRC Response by Aron Lewin No further questions at this time. on 06/30/2008 1 Date Created: 05/21/2008 01:07 PM by Aron Lewin Last Modified: 06/30/2008 10:18 AM http://www.excelservices.com/exceldbs/itstrackdavisbesse.nsf/1 fddcealOd3bdbb585256e... 7/18/2008

NRC ITS Tracking Page I of 3 j4ýReturn to View Menu Prn o RAI Screening Required: Yes Status: Closed This Document will be approved by: Tim Regulatory Basis must be included in Comments Kobetz section of this Form This document has been reviewed and Yes information in this question contains NO SUNSI sensitive material (the checkbox to the right must be selected before this question can be submitted) NRC ITS TRACKING NRC Reviewer ID 200711161058 Conference Call Requested? No Category BSI - Beyond Scope Issue ITS Section:. TBI-POC.:' JFDP Numb.erM:. Page Number(s):. ITS 3.3 Aron Lewin None Information ITS Number: 0S:. DOC Number: Bases.JFDN..Number:l 3.3.2 None L.1 None Discuss how Criterion 3 of 10 CFR 50.36(d)(2)(ii) would be continued to be satisfied as a result of reducing the minimum required number of operable channels, for the Manual Reactor Trip function, from two to one.

Background

CTS table 3.3-1 (page 94 of 636) lists that two channels are required to be operable for the Manual Reactor Trip function and that only one channel is required for a trip. As a result the supply and return of the electric circuit are interrupted. The ITS Bases (page 105 of 636) for LCO 3.3.2 (NUREG-1430) state that "there are two separate push button switches, and only one of the two are required for the Manual Reactor Trip Function to be OPERABLE." This would result in either the supply or the return of the electric circuit being Comment interrupted. STS LCO 3.3.2 states that "The RPS Manual Trip Function shall be Operable." The STS are based on a plant with one switch (channel) for the Manual Reactor Trip Function. However, the one switch in the STS design interrupts both the return and the supply of the electric circuit. Criterion 3 of 10 CFR 50.36(d)(2)(ii) states a TS must be established for "a structure, system, or component that is part of the primary success path and which functions or actuates to mitigate a design basis accident or transient that either assumes the failure of or presents a challenge to the integrity of a fission product barrier." It is unclear how Criterion 3 of 10 CFR 50.36(d)(2)(ii) would be continued to' be satisfied as a result of reducing the minimum required number of operable channels, for the Manual Reactor Trip function, from two to one. (It should be noted that there is an RAI question in this section regarding the licensee's http://www.excelservices.com/exceldbs/itstrackdavisbesse.nsf/1 fddceal Od3bdbb585256e... 7/18/2008

NRC ITS Tracking Page 2 of 3 position that the Manual Reactor Trip Function is not required to be in TS per Criterion 3 of 10 CFR 50.36(d)(2)(ii). That issue is separately addressed in that RAI. The issue at hand in this RAI, is the noted difference between the CTS, the ITS, and the STS.)[L01l Issue Date 11/1/6/2007 Close Date [01/28/2008 Logged in User: Anonymous -'Responses Licensee Response by Jerry The manual reactor trip push button switches are in series with Jones on 12/04/2007 each other electrically, Either switch performs exactly the same function; i.e., actuating either of the two push buttons will remove power from all four CRD trip breakers, initiating a reactor trip. Furthermore, each of the push buttons operate all eight switch contacts, which remove power from both sides of the undervoltage coil for each CRD trip breaker. This is described in the Background section of the ITS Bases (Volume 8, Pages 105 and 106). The ISTS Bases describes a design that includes only one manual push button, and actuating the one push button performs exactly the same function as each of the Davis-Besse manual push buttons - it results in a reactor trip. Therefore, only requiring one of the two installed push buttons to be OPERABLE is consistent with the design described in the ISTS Bases. Therefore, Davis-Besse does not believe that this is a beyond scope issue. The NRC reviewer also asked a question concerning the 10 CFR 50.36(d)(2) (ii) criterion themanual reactor trip meets. As stated in the ITS. Applicable Safety Analyses Bases (Page 105), as well as the Discussion of Change (DOC) justifying only one push button being required OPERABLE (DOC LO1, Page 100), the manual reactor trip is not credited in any safety analyses, thus it does not satisfy Criterion 3 of 10 CFR 50.36 (d)(2)(ii). Criterion 3 is defined as a structure, system, or component that is part of the primary success path and which functions or actuates to mitigate a design basis accident or transient that either assumes the failure of or presents a challenge to the integrity of a fission product barrier. Since the reactor manual trip is not credited in any safety analysis, it cannot meet Criterion 3. However, it has been retained in the Davis-Besse ITS for the overall redundancy and diversity of the RPS. Furthermore, while the ISTS Applicable Safety Analyses Bases states that this trip meets Criterion 3, the wording in the previous paragraph states that the trip is a backup to the automatic functions - it provides no reason as to why it meets Criterion 3 (i.e., it does not explain what safety analyses it is assumed to function for). The Davis-Besse words are taken from the BWR/4 ISTS Bases (NUREG-1433, Page B 3.3.1.1-19), since these words seem to better fit the reason why the Manual Reactor Trip Function is maintained for Davis-Besse. NRC Response by Aron Lewin

                                  *Will request conference call with licensee via PM.

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NRC ITS Tracking Page 3 of 3 on 12/20/2007 I! NRC Response by Aron Lewin Based on 12/21/07 teleconference, anticipated licensee to submit on 01/10/2008 corrections. Thread will be closed out once licensee responds indicating such actions will be taken. Licensee Response by Bryan Based on a conversation with the NRC, Davis-Besse will maintain Kays on 01/20/2008 the current licensing basis with respect to the number of manual reactor trips switches. Therefore, two manual reactor trip switches will be required to be OPERABLE. Therefore, the Manual Reactor Trip Function (Volume 8 Pages 94, 95, 99, 100, 102, 103, 105, and 107) will be changed to require two Manual Reactor Trip channels to be'OPERABLE. Anew ACTION A will be added, to reflect the current licensing basis, for when one of the two channels of the Manual Reactor Trip are inoperable. A draft markup regarding this change is attached. This change will be reflected in the supplement to this section of the 'ITS Conversion Amendment. NRC Response by Aron Lewin No further questions at this time. Date Created: 11/16/2007 10:58 AM by Aron Lewin Last Modified: 01/28/2008 03:18 PM http://www.excelservices.com/exceldbs/itstrackdavisbesse.nsf/1 fddcea 10d3bdbb585256e... 7/18/2008

NRC ITS Tracking Page I of 2 I Return to View Menu Print Document RAI Screening Required: Yes Status: Closed This Document will be approved by: Tim Regulatory Basis must be included in Comments Kobetz section of this Form This document has been reviewed and Yes information in this question contains NO SUNSI sensitive material (the checkbox to the right must be selected before this question can be submitted) NRC ITS TRACKING NRC Reviewer ID ]200711161100 Conference Call Requested? No Category BSI - Beyond Scope Issue

                       !TS .Section:..           TB P.OC:.             JFD.-Number.:      Page Number(s).:

ITS 3.3 Aron Lewin None Information ITS.Number: 0S.1 DOC Nu.m.,ber;.: Bases..JFD. .Nunib.er:. 3.3.2 None L.1 None Discuss how Criterion 3 of 10 CFR 50.36(d)(2)(ii) is satisfied when ITS LCO 3.3.2 is stated as "The RPS Manual Reactor Trip Function shall be OPERABLE," when there is more than one channel in the plant (i.e. vice stating "One RPS Manual Reactor Trip Function channel shall be OPERABLE").

Background

CTS table 3.3-1 (page 94 of 636) lists that two channels are required to be operable for the Manual Reactor Trip function and that only one channel is required for a trip. As a result the supply and return of the electric circuit are interrupted. ITS LCO 3.3.2 (page 102 of 636) states "The RPS Manual Reactor Trip Function shall be OPERABLE." However the ITS Bases (page 105 of 636) for Comment

             ..........LCO     3.3.2and switches,       (NUREG-1430)      state that "there are two separate push button only one of the two are required for the Manual Reactor Trip Function to be OPERABLE." This would result in either the supply or the return of the electric circuit being interrupted.

STS LCO 3.3.2 states that "The RPS Manual Trip Function shall be Operable." The STS are based on a plant with one switch (channel) for the Manual Reactor Trip Function. However, the one switch in the STS design interrupts both the return and the supply of the electric circuit. Criterion 3 of 10 CFR 50.36(d)(2)(ii) states a TS LCO must be established for "a structure, system, or component that is part of the primary success path and which functions or actuates to mitigate a design basis accident or transient that either assumes the failure of or presents a challenge to the integrity of a fission product barrier." It is unclear how Criterion 3 of 10 CFR 50.36(d)(2)(ii) is satisfied when ITS http://www.excelservices.com/exceldbs/itstrackdavisbesse.nsf/1 fddceal Od3bdbb585256e... 7/18/2008

NRC ITS Tracking Page 2 of 2 LCO 3.3.2 is stated as "The RPS Manual Reactor Trip Function shall be OPERABLE," when there is more than one channel in the plant (i.e. vice stating "One RPS Manual Reactor Trip Function channel shall be OPERABLE"). (It should be noted that there is an RAI question in this section regarding the licensee's position that the Manual Reactor Trip Function is not required to be in TS per Criterion 3 of 10 CFR 50.36(d)(2)(ii). That issue is separately addressed in that RAI. The issue at hand in this RAI, is the noted difference between the CTS, the ITS, and the STS.) [LO1] Issue e1 11/16/2007 Close Date 11/28/2008 Logged in User: Anonymous

'Responses Licensee Response by Jerry          See the response to question 200711161058.

Jones on 12/04/2007 ___________________________ via PM. [nNRC Response by Aron Lewin Will request conference call with licensee NRC Response by Aron Lewin Based on 12/21/07 teleconference, anticipated licensee to submit on 01/10/2008 corrections. Thread will be closed out once licensee responds indicating such actions will be taken. NRC Response by Aron Lewin Licensee submitted response to thread #200711161058 that on 01/28/2008 addresses issues in' this thread as well. No further questions at this time. Date Created: 1116/2007 11:00 AM by Aron Lewin Last Modified: 01/28/2008 03:23 PM http://www.excelservices.com/exceldbs/itstrackdavisbesse.nsf/1 fddcealOd3bdbb585256e... 7/18/2008

NRC ITS Tracking Page I of 2 VReturn to View Menu a rnt Documnent RAI Screening Required: Yes Status: Closed This Document will be approved by: Tim Regulatory Basis must be included in Comments Kobetz section of this Form This document has been reviewed and Yes information in this question contains NO SUNSI sensitive material (the checkbox to the right must be selected before this question can be submitted) NRC ITS TRACKING NRC Reviewer ID [200711161102 Conference Call Requested? No Cate eyond Scope Issue ITS Section: TB POC: JFD Number: Page Number(s).: ITS 3.3 Aron Lewin None Information ITS Number: OS1;: 0.-C Nu!mber: Bases JFD Number: 3.3.2 None None None Discuss why the Manual Reactor Trip Function is not required per Criterion 3 of 10 CFR 50.36(d)(2)(ii).

Background

The Bases for CTS 3/4.3.1 and 3/4.3.2 do not specifically discuss the Manual Reactor Trip Function with regards to Applicable Safety Analysis. The Bases for ITS LCO 3.3.2 (page 105 of 636) state, "The Manual Reactor Trip Function does not satisfy any criteria of 10 CFR 50.36(c)(2)(ii) however, it is retained for the overall redundancy and diversity of the RPS as required by Comment the NRC". The Bases for STS LCO 3.3.2 (NUREG-1430) states that "the Manual Reactor Trip Function satisfies Criterion 3 of 10 CFR 50.36(c)(2)(ii). Criterion 3 of 10 CFR 50.36(d)(2)(ii) states a TS LCO must be established for "a structure, system, or component that is part of the primary success path and which functions or actuates to mitigate a design basis accident or transient that either assumes the failure of or presents a challenge to the integrity of a fission product barrier." It is unclear why the Manual Reactor Trip Function is not required per Criterion 3 of 10 CFR 50.36(d)(2)(ii). [ Issue Date] 11/16/2007 Close Date [04/24/2008 Logged in User: Anonymous

 'Responses I Licensee Response by Jerry            11See the response to question 200711161058.

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NRC ITS Tracking Page 2 of 2 Jones on 12/04/2007 II NRC Response by Aron Lewin Will request conference call with licensee via PM. on 12/20/2007IL_____________________________ NRC Response by Aron Lewin ITSB has all information needed to make final determination. on 01/10/2008IL_____________________________ Licensee Response by Bryan The following additional information is provided to supplement Kays on 03/16/2008 our response of 12/4/2007. NRC letter dated May 9, 1998, from T. E. Murley to W. S. Wilgus (letter provided in attachment), provided, in part, the results of the NRC Staff Review of Letter dated October 15, 1987, from R. L. Gill, B&W Owners Group, to Dr. T. E. Murley, NRC,

Subject:

B&W Owners Group Technical Specification Committee Application of Selection Criteria to the B&W Standard Technical Specifications. On pages 5 and 6 of the enclosure to the letter (the NRC Staff Review document), it is stated "For the purpose of this application of the guidance in the Commission Policy Statement, the staff agrees with the Owners Groups' conclusions (emphasis added) except in two areas. First, the staff finds the Remote Shutdown Instrumentation meets the Policy Statement criteria for inclusion in Technical Specifications based on risk; and second, the staff is unable to confirm the Owners Groups' conclusion that Category 1 Post-Accident Monitoring Instrumentation is not of prime importance in limiting risk." Appendix A provides the specific results for the B&W report. Table 1 lists LCOs to be retained. Under instrumentation, Reactor Protection System Instrumentation is listed, with a Note 2. Note 2 states, in part, "The Policy Statement criteria should not be used as the basis for relocating specific trip functions, channels, or instruments within these LCOs. In the B&W report, in the summary disposition matrix, the following is noted: Page 4 of 15 __RPS Manual Trip Criteria for Inclusion - No NRC Response by Aron Lewin Consider replacing the phrase "The Manual Reactor Trip Function on 04/21/2008 does not satisfy any criteria of 10 CFR 50.36(c)(2)(ii) however, it is retained for the overall redundancy and diversity of the RPS as required by the NRC." with the following: "The Manual Reactor Trip Function is retained for the overall redundancy and diversity of the RPS as required by the NRC." Licensee Response by Jerry Davis-Besse will make the requested change to the Bases. A draft Jones on 04/23/2008 markup regarding this change is attached. This change will be reflected in the supplement to this section of the ITS Conversion Amendment. NRC Response by Aron Lewin No further questions at this time. on 04/24/2008 I Date Created: 11/16/2007 11:02 AM by Aron Lewin Last Modified: 04/24/2008 12:10 PM http://www.excelservices.com/exceldbs/itstrackdavisbesse.nsf/1 fddcea 1Od3bdbb585256e... 7/18/2008

                                                         "EXT-8-04.897 UNITED STATES NUCLEAR REGULATORY COMMISSION WASIHINGTON. 0. C. 20SSS IL I3 bORsUM NPD IUCENSINo MAY 9 igs8 Hr. Walter S. Wilgus, Chairman                                     MAY 1.0 19R8 The B&W Owners Group Suite 525                                                           NOCE*&L-. MD 3"1.230-2m0 1700 Rockville Pike.                                                                S:

Rockville, Maryland 20852 45-,

Dear Mr. Wilgus:

This letter Is in response to your report Identifying which Standard Technical Specification (STS) requirements you believe should be retained in the new STS and which can be relocated to other licensee-controlled documents. The enclosure to this letter documents the NRC staff's conclusions as to which current STS requirements must be retained in the new STS. These conclusions are based on the Commission'.s\interim Policy Statement on Technical Specifica-tion Improvements and on several interpretations of how to apply the screening criteria contained In that PolicyStatement. The NRC staff considered comments made by industry at a March 29, 108 meeting between NRC, NUMARC, and each Owners Group in making these interpretations. Based on our review. we have concluded that a significant reduction can be made In the number of Limiting Conditions for Operation (and associated Surveillance Requirements) that must be included in the STS. Our goal is to assure that the'new STS contain only requirements that are consistent with 10 CFR 50.36 and have a sound safety basis. The development of the new STS based on the staff's conclusions will result-in more efficient use of NRC and Industry resources. Safety improvements are expected through more operator-oriented Technical Specifications, improved Technical Specification Bases, a reduction in action statement-induced plant transients, and a reduction in testing at power. As you are aware, the NRC staff and industry also have~underway a parallel program of specific line item improvements to both the scope and substance of the existing Technical Specifications. The need for many of these types of improvements was identified in the report (NUREG-1024) of a major staff task group established in 1983 to study surveillance requirements in Technical Specifications and develop alternative approaches to provide better assurance that surveillance testing does not adversely impact safety. The NRC will continue to actively identify and pursue the development of specific line item Improvements to Technical Specifications and will make these improvements immediately available to licensees without waiting for the new STS. We encour-age each of the Owners Groups to continue to work with the NRC staff on these types of parallel improvements to existing Technical Specifications.

 .r. W. S. Wilgus            I We are confident that the enclosed staff report provides an adequate                   basis for the  development        of complete   new  STS  In accordance ,

the Owners Groups to proceed with with the Commission's Interim Policy Statement. We will continue to interact with the NUMARC echnical Specificationkeep Working Group and each of the Individual vendor Owners Groups as..ded to this important program moving forward. Sincerely, Or .!! '.;.!. *Air~aY  : ii**: The~bs Thomas E. Kurley, Director Office of Nuclear Reactor Regulation

Enclosure:

As stated S cc see next page DISTRIBUTION: SAVarga DOEA R/F DCrutchfield OTSB Members JGPartlow PDR jPStohr Central Files JWRoe Murley/Sniezek FJI3iraglia TThartin BABoger CERossi GCLalnas EJButcher FSchroeder AThadani JRichardson LShao (W.S.WILGUS/LTR/SPLIT REPORT) CONCURRENCE:

                    *(see previous concurrence)
    *TSB:DOEA:KRR   *TSB:NRR     *C:TSB:NRR        *D:DOEA:NRR *D:DESI:NRR *D:DEST:NRR DCFlscher EJButcher              CERossi         AThadani      LShao KCesai:psic                                                      04126/88      04/26/98 4/18188         04/19/88     04/20/88            04/22/88 0    *D:DREP:NRR ^ADT:NRR JRStohr       M~artin 05/05/88 D"

Erley 5/t/*, 04/28/88

J. Mr. W. S. Wilgus cc w/encl: Mr. Robert Gill B&W Owners Group P. 0. Box 33189. *:.

                                              ' "'.::;:        i
                                                         *" "f-A~

4ZZ South Church Street 28242 Charlotte, North Carolina Mr. R. E.:Bradley BWR Owners Group c/o Georgia Power Nuclear Operations Department 14th Floor 333 Piedmont Avenue Atlanta, Georgia 30308 Mr. Edward Lozito Westinghouse Owners Group c/o Virginia Power P. 0. Box 26666 Richmond, Virginia 23261 Mr. Joseph B. George Westinghouse Owners Group Texas Utilities 400 North Olive Dallas, Texas 75201 Mr. Stewart Webster CE Owners Group, 1000 Prospect Hill Road Winstor. Connecticut 06095-0500 Mr. R. A. Bernier CE Owners Group co Arizona Nuclear Power Project P. 0. Box 52034 M.S. 7048 Phoenix. Arizona 85072 Mr. Thomas Tipton NUMARC 1776 Eye Street. N.W. Suite 300 Washington, D. C. 20006-2496

I NRC STAFF REVIEW 5 OF NUCLEAR STEAM SUPPLY SYSTEM VENDOR OWNERS GROUPS' APPLICATION OF b THE COMMISSION'S INKTRIM POLICY STATEMENT CRITERIA TO STANDARD TECHNICAL SPECIFICATIONS I

1. INTRODUCTION On February 6, 1987, the Commission issued its Interim Policy Statement on Technical Specification Improvements (52 FR 3788). The Policy Statement encourages the Industry to develop new Standard Technical Specifications (STS) to be used as guides for licensees in preparing improved Technical Specifications (TS) for their facilities. The Interim Policy Statement contains criteria (including a discussion of each) for determining which regulatory requirements and operating restrictions should be retained in the new STS and ultimately in plant TS. It also Identifies four additional systems that are to be retained on the basis of operating experience, and probabilistic risk assessments (PRA).

Finally, the Policy Statement indicates that risk evaluations are an appropriate tool for defining requirements,'that should be retained in the STS/TS where including such requirements is consistent with the purpose of TS (as stated in the Policy Statement). Requirements that are not retained in the new STS would generally not be retained In individual plant TS. Current TS requirements not retained In the STS will be relocated to other licensee-controlled documents. One of the first steps In the program to implement the Commission's Interim Policy Statement is to determine which Limiting Conditions for Operation (LCOs) contained in the existing STS should be retained in the new MTS. An early decision on this issue will facilitate efforts to make the other improvements (described in the Policy Statement) to the text and Bases of those requirements that must be retained in the new STS.

 -Each Nuclear Steam Supply System (NSSS) vendor Owners Group has   submitted a report to the NRC for review that identifies which SS LCOs the    group believes should be retained In the new STS and which can be relocated to   other licensee-controlled documents. These four NSSS vendor submittals are as    follows:

(1) Letter dated October 15, 1987, R. L. Gill, B&W:Owners Group, to Dr. I. E. Murley, NRC,

Subject:

"B&M1 Owners Group Technical Specification Committee  Application of Selection Criteria to the B&w Standard Technical Specifications."

• TOTAL PAGE.O]

0

I (2) Letter dated November 12, 1987, R. A. Newton, Westinghouse Owners Group, to NRC Document Control Desk,

Subject:

"Westinghouse.Owners Group MERITS Program Phase II, Task 5, Criteria Application Topical Report."

(3) Letter dated December 11, 1987, J. K. Gasper, Combustion Engineering Owners Group, to Dr. T. E. Murley, NRC

Subject:

"CEN-355, CE Owners Group Restructured Standard Technical Specifications - Volume I (Criteria Application)."

(4) Letter dated November 12, 1987, R. F. Janecek, BWR Owners Group, to R. E. Starostecki, NRC,

Subject:

"BWR Owners Group Technical Specification screening Criteria Applichtion and Risk Assessment.'

These submittals provide the rationale for why each STS requirement (e.g. Limiting Condition for Operation) should be retained in the new STS or why it can be relocated to a licensee-controlled document. They also describe how each Owners Group used risk insights in determining the appropriate content of the new STS.

2. STAFF REVIEW The NRC staff focused its review on those requirements identified by the Owners Groups as candidates for relocation. The staff evaluated each of these requirements to determine whether it agreed with the Owners Groups' conclusions.

During the NRC Staff's review, several issues were raised concerning the proper interpretation or application of the criteria in the Commisslon's Interim Policy Statement. The NRC Staff has considered these Issues and concluded the following: (1) Criterion 1 should be interpreted to include only instrumentation used to detect actual leaks and not more broadly to include instrumentation used

to detect precursors to an actual breech of the reactor coolant pressure boundary or instrumentation to identify the source of actual leakage (e.g., loose parts monitor, seismic instrumentation, valve position indicators). t2) The "initial conditions" captured under Criterion 2 should not be limited to only "process variables" assumed in safety analyses. They should also Include certain active design features (e.g., high pressure/low pressure system valves and Interlocks) and operating restrictions (e.g., pressure-temperature operating limit curves), needed to preclude unanalyzed accidents. In this context, "active design features' include only design features under the control of operTtions personnel (i.e.. licensed operators and personnel who perform control.functions at the direction of licensed opera-tors). This position is consistent with the conclusions reached by the Staff during the trial application of the criteria to the Wolf Creek and Limerick Technical Specifications. (3) The "initial conditions" of design-basis accidents (DBA) and transients, as used in Criterion 2, should not be limited to only those directly *monitored and controlleed from the control room. Initial conditions should also in-clude other features/characteristics that are specifically assumed in DBA and transient analyses even if they can not be directly observed in the control room. For example, initial conditions (e.g., moderator temperature coefficient and hot channel factors) that are periodically monitored by other than licensed operators (e.g., core engineers, instrumentation and control technicians) toýprovide licensed operators with the information required to take those actions necessary to assure that the'plant is being operated within the bounds of design and analysis assumptions, meet Criterion 2 and should be retained in Technical Specifications. Initial conditions do'not, however, include things that are purely design requirements. (4) The phrase "primary success path." used in Criterion 3, should be interpreted to include only the primary equipment (including redundant trains/components)

      ¶. a    *trtjdtjtS 6d trTOsients, Privmry success path does not include
                                   - or iSt tM        Ure'et to used toyze r%4 we'rS e_P maT'f

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                                         -4.

accidents or transients or to improve reliability of the mitigation function (e.g., rod withdrawal block which is backup to the average power range monitor high flux trip in the startup mode, safety valves which are backup to low temperature over pressure relief valves during cold shutdown). (5) Post-Accident Monitoring Instrumentation that satisfies the definition of Type A variables in Regulatory Guide 1.97, "Instrumentation for Water-Cooled Nuclear Power Plants to Assess Plant and Environs Conditions During and Following an Acctdent,n meets Criterion 3 and should be retained in Technical Specifications. Type A variables provide primary Information (i.e., information that'it essentiol for the direct accomplishment of the specified manual actions (Incbdlng long-term recovery actions) for which no automatic control is provided and that are required for safety systems to accomplish their safety functions for DOAs. or transients). Type A variables do not include-those variables associated with contingency actions that may also be identified in written procedures to compensate for failures of primary equipment. Because only Type A variables meet Criterion 3, the STS should contain a narrative statement that indicates that individual plant Technical Specifications should contain a list of Post-Accident Instrumentation that includes Type A variables. Other Post-Accident Instrumentation (i.e., non-Type A Category 1) Is discussed on page' 6. (6) The NAC's design basis for licensing a plant is the plant's Final Safety Analysis Report (FSAR) as qualified by the analysis performed by the staff and documented in the staff's safety evaluation report (SER). Because the staff's review and resulting SER are based on the acceptance criteria in the NRC's Standard Review Plan (NUREG-0800. SRP), the dose ifmits used In licensing a particular plant may be "some small fraction" of those specified in the Conmission's regulations In Title 10 of the Code of Federal Regulations Part 100 (10 CFR 100). Accordingly, the SRP limits should be used to define the equipment in the primary success path for mitigating accidents and transients when developing the new STS. These types of conservatisms are required to compensate for uncertainties in analysis techniques and

provide reasonable assurance that the absolute numerical limits of the regulations will be satisfied. On a plant-specific basis, systems and equipment that are identified in the tRC staff SER and assumed by the staff to function are considered part of the licensing basis for the plant and are captured by Criterion 3 (e.g., radiation monitoring instrumentation that initiates an isolation function, penetration room exhaust air cleanup system). (7) DBA and transients, as.used in Criteria 2 and 3, should be interpreted to include any design-basis tvent described in the FSAR (i.e., not just those events described in Chapters 6 and 15 of the FSAR). For example, there may be requirements for some plants which should be retained in Technical Specifications because of the risks associated with some site-specific characteristic (e.g., although not normally required, a Technical Specifi-cation on the chlorine detection system might be appropriate where a sig-nificant chlorine hazard exists in the site.vicinity; similarly, a Tech-nical Specification on flood protection might be appropriate where a plant is particularly vulnerable to flooding and is designed with special flood protection features). Criteria 2 and 3 should not be interpreted to in-clude purely generic design requirements applicable to all plants (e.g., the requirements of General Design Criterion 19 in Appendix A to 10 CFR Part 50 for control room design). The NRC staff has used the Commission's Interim Policy Statement and the conclusions described above to define the appropriate content of the new STS. The staff plans to factor these conclusions into the Final Policy Statement on Technical Specification Improvements that will be proposed to the Commission. The staff reviewed the methodology and results provided by each Owners Group, to verify that none of the requirements proposed for relocation contains constraints of prime importance in limiting the likelihood or severity of accident sequences that are commonly found to dominate risk. For the purpose

of this application of the guidance in the Commission Policy Statement, the staff agrees with the Owners Groups' conclusions except in two areas. First, the staff finds that the Remote Shutdown Instrumentation meets the Policy State-ment criteria for inclusion in Technical Specifications based on risk; and second, the staff is unable to confirm the Owners Groups' conclusion that Category 1 Post-Accident Monitoring Instrumentation is not of prime importance in limiting risk. Recent PRAs have shown the risk significance of operator re-covery actions which would require a knowledge of Category 1 variables. Furthermore, recent severe accident studies have shown significant potential for risk reduction from accident management. The Owners Groups' should develop further risk-based justification tin support of relocating any or all Category 1 variables from the Standard Technieal Specifications. As stated in the Commission's Interim Policy Statement, licensees should also use plant-specific PRAs or risk surveys as they prepare license amendments to adopt the revised STS to their plant. Where PRAs or surveys are available, licensees should use them to strengthen the Bases as well as to screen those Technical Specifications to be relocated. Where such plant-specific risk surveys are not available, licensees should use the literature available on risk insights and PRAs. Licensees need not complete a plant-specific PRA before they can adopt the new STS. The NRC staff will also use risk insights and PRAs in evaluating the plant-specific submittals.

3. RESULTS OF THE STAFF'S REVIEW Appendices A through D present the detailed results of the staff's review of the Babcock and Wilcox, Westinghouse, Combustion Engineering, and General Electric application of the selection criteria to the existing STS. Each Appendix con-sists of two tables. Table I identifies those LCUs that must be retained in the new STS. Table 2 lists those LCOs that may be wholly or partially relocated to licensee-controlled documents (or be reformatted as a surveillance requirement for another LCO). Where the staff placed specific conditions on relocation of particular LCOs the staff has so noted in the Tables. As a part of the

plant specific Implementation of the new SIS, the staff plans to review the location of, and controls over, relocated requirements. In as much as practi-cable, the Owners Groups should'propose standard locations for, and controls over, relocated requirements. For each LCO listed in Table 1, the criterion (criteria) that required that the LCO be retained in Technical Specifications is identified. If an LCO was retained in Technical Specifications solely on the basis of risk, "Risk" appears in the criteria column. Where an Owners Group determined that an LCO had to stay in Technical Specificatins (because of either a particular criterion or risk) and the Staff agreed that the LCO should be retained in Technical Specif-ications, the staff did not, in gePeral, verify the Owners Group's basis for retention. However, in several instances the Owners Groups cited risk consider-ations alone as the basis for retaining Technical Specifications and the staff disagreed with the Owners Groups. In these instances, the staff's basis for retention appears in the criteria column of Table 1. Any LCO not specifically identified in Table 1 or Table 2 (e.g., an LCO unique ,to an STS not addressed .in the Owners Groups submittals.such as the BWR5 STS) shourld be retained in the STS until-the Owners Group proposes and the staff makes a specific determination that it can be-relocated to a licensee-controlled document. tNotwlthstanding the results of this review, the staff will give further consideration for relocation of additional LCOs as the staff and industry proceed with the development of the new STS.

4. CONCLUSION The results of the effort of the Owners Groups and of the NRC staff to apply the Policy Statement selection criteria to the existing STS are an important step toward ensuringrthat the new SIs contain only those, requirements that are consistent with 10 CFR 50.36 and have a sound safety basis. As shown in the

I following tables, application of the criteria contained in the Commisslon's Interim Policy Statement resulted in a significant reduction in the number of LCOs to be included in the new STS. The development of the new STS based on the staff's conclusions will result In more efficient use of NRC and industry resources. Safety improvements are expected through more operator-oriented Technical Specifications, improved Technical Specification Bases, a reduction in action statement-induced plant transients, and a reduction in testing at power. b

                        -----------------     - -   - - - - -  -   - - - - - l- ! - ii -   iI
                                                                                           -   iilll
                                                                                                -    - - I BABCOCK                                                                  GENERAL COMBUSTION                 ELECTRIC LCOs            WILCOX               WESTINGHOUSE              ENGINEERING                BVR4/BWR6 Total Number           137                       165                    159                      124/144 Retained          75                        92                     87                         81/86 Relocated         62                        73                     72                         43/58 Percent Relocated         45%                       44%                    45%                     35%/40%

We'are confident that the staff's conclusions will provide an adequate'basis for the Owners Groups to proceed with the development of complete, new STS in accordance with the Commission's Interim Policy Statement.

APPENDIX A RESULTS OF THE NRC STAFF REVIEW BABCOCK & KILCOX OWNERS GROUP'S SUBMITTAL RETENTION AND RELOCATION bF SPECIFIC TECHNICAL SPECIFICATIONS

APPENDIX A TABLE 1 LCOs TO BE RETAINED IN BABCOCK A WILCOX STANDARD TECHNICAL SPECIFICATIONS LCO CRITERIA 3.1 REACTIVITY CONTROL SYSTEM 3.1.1.1 Shutdown Margin (Note 1) 2 3.1.1.2 Moderator Temperature Coefficient 2 3.1.1.3 Minimum Temperature for Criticality 2 3.1.3.1 Group Height - Safety and Regulating Rod Groups, 2 3.1.3.2 Group Height - Axial Power Shaping Rod Group 3.1.3.6 Safety Rod Insqrtion Limit 2 3.1.3.7 Regulating Rod tnsertion Limits 3.1.3.9 Xenon Reactivity 2 3.2 POWER DISTRIBUTION LIMITS 3.2.1 Axial Power Imbalance 2 3.2.2 Nuclear Heat Flux Hot Channel Factor 2 3.2.3 Nuclear Enthalpy Rise Hot Channel Factor 2 3.2.4 Quadrant Power Tilt 2 3.2.5 DNB Parameters 2 3.3 INSTRUMENTATION 3.3.1 Reactor Protection System Instrumentation (Note 2) 3 3.3.2 Engineered Safety Feature Actuation System Instrumentation (Note 2) 3 3.3.3.1 Radiation Monitoring Instrumentation (Notes 2 & 3) 3 3.3.3.5 Remote Shutdown Instrumentation (Notes 2 & 4) Risk 3.3.3.6 Accident Monitoring Instrumentation 3 3.4 REACTOR COOLANT SYSTEM , 3.4.1.1 Startup and Power Operation 3 3.4.1.2 Hot Standby 3 3.4.1.3 Hot Shutdown 3 3.4.1.4 Cold Shutdown Policy Statement (DHR) 3.4.3 Safety Valve - Operatinp 3 3.4.4 Pressurizer 2 &3 3.4.5 Reliet Valve 3 3.4.6 Steam Generators - Water Level 2 3.4.7.1 Leakage Detection System 1 A-I

B&W-TABLE I (Continued) LCO CRITERIA 3.4.7.2 Operational Leakage 3.4.9 Speciffc Activity 2 3.4.10.1 Reactor Coolant System Pressure/Temperature Limits 2 3.4.10.3 Overpressure Protection System 2 3.5 EMERGENCY CORE COOLiNG SYSTEM (ECCS) 3.5.1 Core Flooding Tanks 2 &3 3.5.2 ECCS Subsystems - Tar (305)°F 3 3.5.3 ECCS Subsystems - Tavg <(305)°F 3 3.5.4 Borated Water Storage Tank 2 &3 3.6 CONTAIINNENT SYSTEMS 3.6.1.1 Ccrntainment Integrity 3 3.6.1.3 Containment Air Locks 3 3.6.1.5 Internal Pressure 2 3.6.1.6 Air lemperature 2 3.6.1.8 Containment Ventilation System 3 3.6.2.1 Containment Spray System 3 .3.6.2.2 Spray Additive System 2 &3 3.6.2.3 Containment Cooling System 3 3.6.3 Iodine Cleanup System 3 3.6.4 Containment Isolation Valves 3 3.6.5.1 Hydrogen Analyzers 3 3.6.5.2 Electric Hydrogen Recombiners (Note 5) 3 3.6.6 Penetration Room Exhaust Air Cleanup System 3 3.7 PLANT SYSTEMS 3.7.1.1 Safety Valves 3 3.7.1.2 Auxiliary Feedwater System 3 3.7.1.3 Condensate Storage Tank 2 &3 3.7.1.4 Activity 2 3.7.1.5 Main Steam Line Isolation Valves 3 3.7.3 Component Cooling Water System 3 3.7.4 Service Water System 3 3.7.5 Ultimate Heat Sink 3 3.7.6 Flood Protection, (optional) 3 3.7.7 Control Room Emergency Air Cleanup System 3 3.7.8 ECCS Pump Room Exhaust Air Cleanup System 3 (optional) A-2

I 8&W-TABLE 1 (Continued) LCO CRITERIA 3.8 ELECTRICAL POWER SYSTEM4S 3.8.1.1 A.C. Sources - Operating 3 3.8.1.2 A.C. Sources - Shutdown Policy Statement (DHR) 3.8.2.1 A.C. Distribution - Operating 3 (OHR) 3.8.2.2 A.C. Distribution - Shutdown Policy-Statement (DHR) 3.8.2.3 D.C. Distribution - Operating 3 3.8.2.4 D.C. Distribution - Shutdown Policy Statement (DH ) 3.9 REFUELING OPERATIONS 3.9.1 Boron Concentration 2 3.9.2 Instrumentation 3 3.9.3 Decay Time 2 3.9.4 Containment Building Penetration 3 3.9.8.1 Residual Heat Removal and Coolant Circulation - All Water Levels - Policy Statement (DHR) 3.9.8.2 Residual Heat Removal and Coolant Circulation - Low Water Levels Policy Statement (OHR) 3.9.9 Containment Purge and Exhaust Isolation System 3 3.9.10 Water Level - Reactor Vessel 2 3.9.11 Water Level - Storage Pool 2 3.9.1**2 Storage Pool Air Cleanup System 2 Notes:

1. Required for Modes 3 through 5. May be relocated for Modes 1 and 2.

2. The LCO for this system should be retained in STS. The Policy Statement criteria should not be used as the basis for relocating specific trip functions, channels, or instruments within these LCOs.

3. The staff is pursuing alternative approaches which would allow relocation of some of these LCOs on a schedule consistent with the schedule for development of the new STS. The staff is also initiating rulemaking to delete the requirement that RETS be included in Technical Specifications.

4. Because fires (either inside or outside the control room) can be a significant contributor to the core melt frequency and because the uncertainties with fire initiation frequency can be significant, the staff believes that this LCD should be retrained in the STS at this time. The staff will consider relocation of Remote Shutdown Instrumentation on a plant-specific basis.

5. This LCO will be considered for relocation to a licensee-controlled document on a plant-specific basis.

A-3

TABLE 2 (Note 1) BABCOCK & WILCOX STANDARD TECHNICAL SPECIFICATION LCOs WHICH MAY BE RELOCATED tCO 3.1 REACTIVITY CONTROL SYSTEMS 3.1.2.1 Flow Paths - Shutdown 3.1.2.2 Flow Paths - Operating 3.1.2.3 Makeup Pump - Shutdown 3.1.2.4 Makeup Pump - Operating 3.1.2.5 Decay Heat Removal Pump,- Shutdown 3.1.2.6 Boric Acid Pumps - Shutdown 3.1.2.7 Boric Acid Pumps - Operating 3.1.2.8 Borated Water. Surce - Shutdown 3.1.2.9 Borated Water Sburce -. Operating 3.1.3.3 Position Indicatioi Channels - Operating (Note 2) 3.1.3.4 Position Indication-Channels - Shutdovm (Note 2) 3.1.3.5 Rod Drop Time (Note-2) 3.1.3.8 Rod Program 3.3 INSTRUMENTATION 3.3.3.2 Incore Detectors 3.3.3.3 Seismic Instrumentation 3.3.3.4 Meteorological Instrumentation 3.3.3.7 Chlorine Detection System 3.3.3.8 Fire Detection 3,3.3.9 Radioactive Liquid Effluent Monitor (Note 3) 3.3.3.10 Radioactive Gaseous Effluent Monitor (Note 3) 3.3.4 Turbine Overspeed Protection 3.4 REACTOR COOLANT SYSTEM 3.4.2 Safety Valves - Shutdown 3.4.6 Steam Generators Tube Surveillance (Note 4) 3.4.8 Chemistry 3.4.10.2 Pressurizer Temperatures 3.4.11 Structural Integrity ASME Code (Note 4) 3.4.12 RCS Vents 3.6 CONTAINMENT SYSTEMS 3.6.1.2 Containment Leakage (Note 5) 3.6.1.7 Containment Structural Integrity (Note 2) 3.7 PLANT SYSTEMS 3.7.2 Steam Generator Pressure/Temperature Limits 3.7.9 Snubbers 3.7.10 Sealed Source Contamination LA-

I B&W-TABLE 2 (Continued) LCO 3.7.11.1 Fire Suppression Water System 3.7.11.2 Spray and/or Sprinkler Systems 3.7.11.3 CO System 3.7.11.4 Haion System 3.7.11.5 Fire Hose Stations 3.7.11.6 Yard Fire Hydrants and Hydrant Hose Houses 3.7.12 Fire Barrier Penetrations 3.7.13 Area Temperature Monitoring 3.9 REFUELING OPERATIONS 3.9.5 Communications 3.9.6 Fuel Handling Bridge 3.9.7 Crane Travel ;pent Fuel Storage Pool Building 3.10 SPECIAL TEST EXCEPTIONS 3.10.1 Shutdown Margin (Note 6) 3.10.2 Group Height Insertion Limits and Power Distribution Limits (Note 6) 3.10.3 Physics Tests (Note 6) 3.10.4 Reactor Coolant Loops (Note 6) 3.11 RADIOACTIVE EFFLUENTS .(Note 3) 3.11.1.1 Concentration 3.11.1.2 Dose 3.11.1.3 Liquid Radwaste Treatment System 3.11.1.4 Liquid Holdup Tanks 3.11.2.1 Dose 3.11.2.2 Dose - Noble Gases 3.11.2.3 Dose - Iodine - 131, Tritium and Radionuclides in Particulate Form 3.11.2.4 Gaseous Radwaste Treatment Systems 3.11.2.5 Explosive Gas Mixture 3.11.2.6 Gas Storage Tanks 3.11.3 Solid Radioactive Waste 3.11.4 Total Dose 3.12 RADIOACTIVE ENVIRONKENIAL MONITORING (Note 3) 3.12.1 Monitoring Program 3.12.2 Land Use Census 3.12.3 Interlaboratory Comparison Program A-S

B&W-TABLE 2 (Continued) Notes:

1. Specifications listed in this table may be relocated contingent upon NRC staff approval of the location of and controls over relocated requirements.

2. This LCO may be removed from the STS. However, If the associated Surveillance Requirement(s) is necessary to meet the OPERABILITY requirements for a retained LCO, the Surveillance Requirement(s) should be relocated to the retained LCO.

3. The staff Is pursuing alternative approaches which would allow relocation of some of these LCUs on a schedule consistent with the schedule for develop-ment of the new STS. The staff is also initiating rulemaking to delete the requirement that RETS be Included in Technical Specifications.

4. This LCO may be relocated. ot of Technical Specifications. However, the associated Surveillance Reqbirement(s) must be relocated to Technical Specification Section 4.0, Surv~illance Requirements.

S. This LCO may be relocated. However, Pa, La, Ld, and Lt must be either retained in1TS or in the Bases of the appropriate Containment LCO.

6. Special Test Exceptions may be included with corresponding LCOs.

NRC ITS Tracking Page 1 of 2 Retrnto View Menu jLntjoahPr ent RAI Screening Required: Yes Status: Closed This Document will be approved by: Tim Regulatory Basis must be included in Comments Kobetz section of this Form This document has been reviewed and Yes information in this question contains NO SUNSI sensitive material (the checkbox to the right must be selected before this question can be submitted) NRC ITS TRACKING NRC Reviewer ID 200711161103 Conference Call.Requested? No Category I BSI - Beyond Scope Issue ITS Section: TB POC: JFD Number: Page!ýNumber(s): ITS 3.3 Aron Lewin 1 Information ITS Number: OS1: DOC Number: Bases JFD Numbe!r: 3.3.2 None None None Discuss if adopting the phrase "control rod" vice "CONTROL ROD" effects physical application of the applicability requirements listed for ITS LCO 3.3.2, when compared to STS LCO 3.3.2, thereby ensuring that the lowest functional capability or performance levels of equipment required for safe operation of the facility are maintained as required by 10 CFR 50.36(d)(2)(i).

Background

The CTS has no definition for CONTROL ROD in Section 1.0, "Definitions." The ITS does have a definition for CONTROL ROD (page 15 of 71 for ITS Chapter 1). The Applicability for ITS LCO 3.3.2 (page 102 of 636) uses the Comment term "control rod." C....... STS for LCO 3.3.2 (NUREG-1430) uses the term "CONTROL ROD." 10 CFR 50.36(d)(2)(i) states that "limiting conditions for operation are the lowest functional capability or performance levels of equipment required for safe operation of the facility." It is unclear if adopting the phrase "control rod" vice "CONTROL ROD" effects physical application of the applicability requirements listed for ITS LCO 3.3.2, when comparedto STS LCO 3.3.2, thereby ensuring that the lowest functional capability or performance levels of equipment required for safe operation of the facility are maintained as required by 10 CFR 50.36(d)(2) (i). [JFD1] I Issue Date 11/16/2007 IClose Da~te 101/10/2008 Logged in User: Anonymous 'Responses http://www.excelservices.com/exceldbs/itstrack-davisbesse.nsf/1 fddcea 10d3bdbb585256e... 7/18/2008

NRC ITS Tracking Page 2 of 2 Licensee Response by Bryan This response is similar to that provided for questions Kays on 12/03/2007 200711161036, 200711161104, and 200711161106. The defined term CONTROL RODS, as defined in ITS Section 1.1 (Volume 3, Page 33) states that CONTROL RODS are full length safety and regulating rods. ISTS 3.3.2 Applicability (Volume 8, Page 102) includes the term "with any CONTROL ROD drive (CRD) trip breaker in the closed position." One problem with using the term CONTROL ROD in this Applicability is that the CRD trip breakers provide power not only to the safety and regulating rods, but also to the AXIAL POWER SHAPING RODS (APSRs), which are also defined in ITS Section 1.1. Secondly, the acronym "CRD" refers to the Control Rod Drive System, and is not limited to only "CONTROL RODS" as defined in ITS Section 1.1. Therefore for consistency throughout the Davis-Besse ITS, whenever the term CONTROL RODS in the ISTS could be applied to an application that includes the APSRs, the term was changed to "control rods." This change is considered as an editorial change to correct an error in the ISTS, and no technical change is intended. Therefore, this change is not a beyond scope change and does not affect any application of the Required Actions. NRC Response by Aron Lewin Will request conference call with licensee via PM. on 12/20/20071 NRC Response by Aron Lewin Based on 12/21/07 teleconference, anticipated licensee to submit on 01/10/2008 corrections. Thread will be closed out once licensee responds indicating such actions will be taken. Licensee Response by Bryan Based on a conversation with the NRC concerning RAIs Kays on 01/10/2008 200711161036,200711161103,200711161104,and 200711161106, the term "control rod" used in ITS 3.3.2 and Bases (Volume 8, Pages 102, 103, 105, and 107) has been changed ba.ck to "CONTROL ROD," consistent with the ISTS. A draft markup regarding this change is attached. This change will be reflected in the supplement to this section of the ITS Conversion Amendment. NRC Response by Aron Lewin No further questions at this time. on 01/10/2008 Date Created: 11/16/2007 11:03 AM by Aron Lewin Last Modified: 01/10/2008 09:19.AM http://www.excelservices.com/exceldbs/itstrackdavisbesse.nsfl1fddcealOd3bdbb585256e... 7/18/2008

NRC ITS Tracking Page I of 2 Return to View Menu Prit Docum~n RI*U Screening Required: Yes Status: Closed This Document will be approved by: Tim Regulatory Basis must be included in Comments Kobetz section of this Form This document has been reviewed and Yes information in this question contains NO SUNSI sensitive material (the checkbox to the right must be selected before this question can be submitted) NRC ITS TRACKING NRC Reviewer ID ][200711161104 Conference Call Requested? No C ategoy IlBSI - Beyond Scope Issue ITS Section: TB.POC.: JFD. Number: ageNumber(s).: ITS 3.3 Aron Lewin 4 Information I NTSNumber: OS!: DOC.-Number: Bases JFD Number: 3.3.3 None None None Discuss if adopting the phrase "control rod" vice "CONTROL ROD" effects physical application of the applicability requirements listed for ITS LCO 3.3.3, when compared to STS LCO 3.3.3, thereby ensuring that the lowest functional capability or performance levels of equipment required for safe operation of the facility are maintained as required by 10 CFR 50.36(d)(2)(i).

Background

The CTS has no definition for CONTROL ROD in Section 1.0, "Definitions." The ITS does have a definition for CONTROL ROD (page 15 of 71 for ITS Chapter 1). The Applicability for ITS LCO 3.3.3 (page 125 of 636) uses the Comment term "control rod." STS for LCO 3.3.3 (NUREG-1430) uses the term "CONTROL ROD." 10 CFR 50.36(d)(2)(I) states that "limiting conditions for operation are the lowest functional capability or performance levels of equipment required for safe operation of the facility." It is unclear if adopting the phrase "control rod" vice "CONTROL ROD" effects physical application of the applicability requirements listed for ITS LCO 3.3.3, when compared to STS LCO 3.3.3, thereby ensuring that the lowest functional capability or performance levels of equipment required for safe operation of the facility are maintained as required by 10 CFR 50.36(d)(2) (i). [JFD4] Issue.D:1ate] 11/16/2007 Close DaDte ]101/10/2008 Logged in User: Anonymous .'Responses http://www.excelservices.com/exceldbs/itstrackdavisbesse.nsf/l fddcealOd3bdbb585256e... 7/18/2008

NRC ITS Tracking Page 2 of 2 Licensee Response by Bryan This response is similar to that provided for questions Kays on 12/03/2007 200711161036, 200711161103,, and 200711161106. The defined term CONTROL RODS, as defined in ITS Section 1.1 (Volume 3, Page 33) states that CONTROL RODS are full length safety and regulating rods. ISTS 3.3.3 Applicability (Volume 8, Page 125) includes the term "CONTROL ROD drive (CRD) trip." One problem with using the term CONTROL ROD in this Applicability is that the CRD trip breakers provide power not only to the safety and regulating rods, but also to the AXIAL POWER SHAPING RODS (APSRs), which are also defined in.ITS Section 1.1. Secondly, the acronym "CRD" refers to the Control Rod Drive System, and is not limited to only "CONTROL RODS" as defined in ITS Section 1.1. Therefore for consistency throughout the Davis-Besse ITS, whenever the term CONTROL RODS in the ISTS could be applied to an application that includes the APSRs, the term was changed to "control rods." This change is considered as an editorial change to correct an error in the ISTS, and no technical change is intended. Therefore; this change is not a beyond scope change and does not affect any application of the Required Actions. NRC Response by Aron Lewin Will request conference call with-licensee via PM. on 12/20/2007 Licensee Response by Bryan Based on a conversation with the NRC concerning RAIs Kays on 01/10/2008 200711161036,200711161103,200711161104,and 200711161106, the term "control rod" used in ITS 3.3.3 and Bases (Volume 8, Pages 125, 127, and 129) has been changed back to "CONTROL ROD," consistent with the ISTS. A draft markup regarding this change is attached. This change will be reflected in the supplement to this section of the ITS Conversion Amendment. NRC Response by Aron Lewin Based on 12/21/07 teleconference, anticipated licensee to submit on 01/10/2008 corrections. Thread will be closed out once licensee responds indicating such actions will be taken. NRC Response by Aron Lewin No further questions at this time. (Note: last NRC comment on 01/10/2008 appeared after licensee stating corrections will be made due to NRC and licensee simultaneously working on database. Date Created: 11/16/2007 11:04 AM by Aron Lewin Last Modified: 01/10/2008 09:15 AM http://www.excelservices.com/exceldbs/itstrack-davisbesse.nsf/lfddcealOd3bdbb585256e... 7/18/2008

NRC ITS Tracking Page I of 2 JIVReturn to View MenuI Print Docuen RIAI Screening Required: Yes Status: Closed This Document will be approved by: Tim Regulatory Basis must be included in Comments Kobetz section of this Form This document has been reviewed and Yes information in this question contains NO SUNSI sensitive material (the checkbox to the right must be selected before this question can be submitted) NRC ITS TRACKING NRC Reviewer ID 200711161106 Conference Call Requested? No Category BSI - Beyond Scope Issue ITS Section: TB.P.OC: JFD Number: Page Numbe~r(s): ITS 3.3 Aron Lewin 8 Information ITS Number: OSI: DOC Number: Bases ,FD Number: 3.3.4 None None None Discuss if adopting the phrase "control rod" vice "CONTROL ROD" effects physical application of ITS LCO 3.3.4, when compared to STS LCO 3.3.4, - thereby ensuring that the lowest functional capability or performance levels of equipment required for safe operation of the facility are maintained as required by 10 CFR 50.36(d)(2)(i).

Background

The CTS has no definition for CONTROL ROD in Section 1.0, "Definitions." The ITS does have a definition for CONTROL ROD (page 15 of 71 for ITS Comment Chapter 1). ITS LCO 3.3.4 (page 154 of 636) uses the term "control rod." STS for LCO 3.3.4 (NUREG-1430) uses the term "CONTROL ROD." 10 CFR 50.36(d)(2)(1) states that "limiting conditions for operation are the lowest functional capability or performance levels of equipment required for safe operation of the facility." It is unclear if adopting the phrase "control rod" vice "CONTROL ROD" effects physical application of ITS LCO 3.3.4, when compared to STS LCO 3.3.4, thereby ensuring that the lowest functional capability or performance levels of equipment required for safe operation of the facility are maintained as required by 10 CFR 50.36(d)(2)(i).. [J3D81 Issue Date 11/16/2007 Close Date [/28/2008 Logged in.User: Anonymous -'Responses Licensee. Response by Bryan This response is similar to-that provided for questions http://www.excelservices.com/exceldbs/itstrack-davisbesse.nsf/lfddcealOd3bdbb585256e... 7/18/2008

NRC ITS Tracking Page 2 of 2 Kays on 12/03/2007 200711161036, 200711161103, and 200711161104. The defined term CONTROL RODS, as defined in ITS Section 1.1 (Volume 3, Page 33) states that CONTROL RODS are full length safety and regulating rods. The title of ISTS 3.3.4 (Volume 8, Page 154) includes the term "CONTROL ROD drive (CRD) trip devices." One problem with using the term CONTROL ROD in this Specification is that the CRD trip breakers provide power not only to the safety and regulating rods, but also to the AXIAL POWER SHAPING RODS (APSRs), which are also defined in ITS Section 1.1. Secondly, the acronym "CRD" refers to the Control Rod Drive System, and is not limited to only "CONTROL RODS" as defined in ITS Section 1.1. Therefore for consistency throughout the Davis-Besse ITS, whenever the term CONTROL RODS in the ISTS could be applied to an application that includes the APSRs, the term was changed to "control rods." This change is considered as an editorial change to correct an error in the ISTS, and no technical change is intended. Therefore, this change is not a beyond scope change and does not affect any application of the Required Actions. on Response by Aron Lewin Will request conference call with licensee via PM. NRC Response by Aron Lewin Based on 12/21/07 teleconference, anticipated licensee to submit on 01/10/2008 corrections. Thread will be closed out once licensee responds indicating such actions will be taken. Licensee Response by Bryan Based on a conversation with the NRC concerning RAIs Kays on 01/17/2008 200711161036,200711161103,200711161104,and 200711161106, the term "control rod" used in ITS 3.3.4 and Bases (Volume 8, Pages 154, 157, 159, and 163) has been changed back to "CONTROL ROD," consistent with the ISTS. Additionally, the statement "except Group 8" has been deleted. Group 8 is the ASPR which is not part of the definition of CONTROL ROD. Therefore, the statement is not required. A draft markup regarding this change is attached. This change will be reflected in the supplement to this section of the ITS Conversion Amendment. NRC Response by Aron Lewin No further questions at this time. on 01/28/2008 I Date Created: 11/16/2007 11:06 AM by Aron Lewin Last Modified: 01/28/2008 03:39 PM http://www.excelservices.com/exceldbs/itstrack davisbesse.nsf/lfddcealOd3bdbb585256e... 7/18/2008

NRC ITS Tracking Page I of 3 I

  '4'Return to View MenuWjQ Print Documentl RAI Screening Required: Yes                          Status: Closed This Document will be approved by: Tim               Regulatory Basis must be included in Comments Kobetz                                               section of this Form This document has been reviewed and                  Yes information in this question contains NO SUNSI sensitive material (the checkbox to the right must be selected before this question can be submitted)

NRC ITS TRACKING NRC Reviewer ID 200711161108 Conference Call Requested? No Category BSI - Beyond Scope Issue ITS Section: TB POC: JFD Number: Page..Nu.Mbr().:. ITS 3.3 Aron Lewin None Information ITS Number: OSI: DOC Number: Bases JFD. Number: 3.3.5 None A.3 None Based on the information in the USAR, discuss if the BWST - Low Low Function has an associated response time, and if so why response time testing would not be required by 10 CFR 50.36(d)(3) in order to assure that the necessary quality of systems and components is maintained, that facility operation will be within safety limits, and that the limiting conditions for operation will be met.

Background

SR 4.3.2.1.3 of CTS 3/4.3.2 (page 173 of 636) states that the response time of "each" SFAS function shall be demonstrated. ITS SR 3.3.5 does not adopt a response time test for the Borated Water Stowage Tank - Low Low instrument (ITS Parameter 5) (page 195 of 636). DOC A03 (page 182 of 636) states this is acceptable since the TRM has N/A for Comment response time for the BWST. However, the USAR (page 2407 [item 91 and page 2422 of 4076 in the USAR) lists a SFAS performance requirement of less than or equal to 5 seconds system response time for the BWST level. STS Table 3.3.5-1 (NUREG-1430) does not list a Borated Water Stowage Tank

                   - Low Low instrument, however response time testing is required for all listed STS parameters.

10 CFR 50.36(d)(3) states that "surveillance requirements are requirements relating to test, calibration, or inspection to assure that the necessary quality of systems and components is maintained, that facility operation will be within safety limits, and that the limiting conditions foroperation will be met." Based on the information in the USAR, it is unclear if the BWST - Low Low Function has an associated response time, and if so why response time testing would not be required by 10 CFR 50.36(d)(3) in order to assure that the necessary quality of systems and components is maintained, that facility http://www.excelservices.com/exceldbs/itstrackdavisbesse.nsf/l fddceal Od3bdbb585256e... 7/18/2008

NRC ITS Tracking Page 2 of 3 operation will be within safety limits, and that the limiting conditions for operation will be met. [A03] [,Issue D:ate [11/16/2007 C7oseDa1te[ 02/21/2008 Logged in User: Anonymous

'Responses Licensee Response by Jerry            The original design of Davis-Besse included an'automatic Jones on 12/06/2007                   swapover on BWST-Low Low Level. However, this automatic swapover was changed to a manual swapover, as approved in License Amendment 36, dated January 24, 1981. The 5 second instrument response time referenced in the NRC reviewer's question is the original design value for the instrument. Since it is the design of the instrument, it has not been deleted from the UFSAR, even though the swapover is now a manual action.

License Amendment 40, dated June 1, 1981, approved additional changes with respect to the manual swapover: (1) Surveillances were added to verify the interlock between the BWST outlet valves and Containment Emergency Sump valves, and to verify the valve stroke time; and (2) The SFAS Response Time requirements for the BWST Low Low Level Function were deleted, since the valve Surveillances described above included a stroke time. At the time of License Amendment 40, the SFAS Response Time requirements were in CTS 3.3.5, Table 3.3-5. These SFAS Response Time values were removed from the Davis-Besse CTS and placed under Davis-Besse control as documented in the NRC Safety Evaluation Report for License Amendment 225, dated July 7, 1998. The valve interlock Surveillance described above is maintained as ITS SR 3.5.2.8 (Volume 10, Page 45). The valve stroke time requirement is being relocated to the Inservice Test Program, as described in ITS 3.5.2, DOC LA05 (Volume 10, Page 36), and consistent with the ISTS allowances. Based on the above explanation, there is no response time requirement for the BWST Level - Low Function in the CTS and should not be required in the ITS. Furthermore, this should not be a Beyond

                                     ,Scope Issue since it is consistent with the current licensing basis.

NRC Response by Aron Lewin Will request conference call with licensee via PM. on 12/20/2007 NRC Response by Aron Lewin Please provide a further discussion on the 5 second instrument on 12/26/2007 response time with respect to the current design requirements (i.e. what is the current design function that requires the 5 seconds to be maintained in the USAR?). Licensee Response by Bill There are no current design functions that require 5 seconds to be Bentley on 02/18/2008 maintained in the USAR. The BWST low level setpoint generates a SFAS Incident Level 5 signal which generates a permissive to allow manual transfer of ECCS pump suction from the BWST to the containment sump. The transfer must take place after a http://www.excelservices.com/exceldbs/itstrack davisbesse.nsf/1 fddceal 0d3bdbb585256e... 7/18/2008

NRC ITS Tracking Page 3 of 3 minimum of 360,000 gallons have been injected in order to provide sufficient net positive suction head for the ECCS pumps when drawing from the containment sump. The transfer must take place prior to the BWST reaching a level where pump cavitation or pump air entrainment (due to vortexing) would be of concern. actions to Sufficient time must exist to account for operator accomplish the manual transfer. The allotted time for initiating operator action is 3 minutes after the SFAS BWST low level permissive is received (completed within 4 1/2 minutes). NRC Response by Aron Lewin Will request conference call with licensee via PM. on 02/20/2008 Licensee Response by Jerry During a recent NRC phone call discussing the status of this Jones on 02/21/2008 question, the NRC reviewer requested that the first sentence in the second response (Bill Bentley response dated 2/18) be clarified. The sentence that reads "There are no current design functions that require 5 seconds to be maintained in the USAR" means that Davis-Besse could delete this 5 second value from the USAR. NRC Response by Aron Lewin No further questions at this time. on 02/21/2008 Date Created: 11/16/2007 11:08 AM by Aron Lewin Last Modified: 02/21/2008 02:44 PM http://www.excelservices.com/exceldbs/itstrackdavisbesse.nsf/1 fddcea 1Od3bdbb585256e... 7/18/2008

NRC ITS Tracking Page I of 2 Return to View Menu a Print Document RAI Screening Required: Yes Status: Closed This Document will be approved by: Tim Regulatory Basis must be included in Comments Kobetz section of this Form This document has been reviewed and Yes information in this question contains NO SUNSI sensitive material (the checkbox to the right must be selected before this question can be submitted) NRC ITS TRACKING NRC Reviewer

              .ID     [200711161109                              Conference Call Requested? No CategoQ       [BSI   - Beyond Scope Issue ITS.Section:         TB POC:             JFD Nnumber:.        Page Number(s):

ITS 3.3 Aron Lewin None Information, ITS-Number: OSRI: D.OC....Number: Bases..JFD Number:. 3.3.5 None LA.4 None Discuss why the Interlock associated with the pressurizer heaters and the Decay Heat System that is based on RCS Pressure is not required in TS per Criterion 3 of 10 CFR 50.36(d)(2)(ii). [LA04]

Background

Table 3.3-3 (pagel75 of 636) and Table 3.3-4 (page 178 of 636) of CTS 3/4.3.2 have operability and surveillance requirements for an Interlock associated with the pressurizer heaters and the Decay Heat System that is based on RCS Pressure (CTS Functional Unit 5.b in Table 3.3-3). The USAR (page 1872 of 4076 in the USAR) discusses the interaction between the pressurizer heaters and the decay heat system and states, "to ensure both [decay heat system] valves are closed before system repressurization, interlocks are provided that trip off pressurizer heaters when pressure increases above setpoint and one of Comment the valves is not closed." TheUSAR (page 1872 of 4076) also states that "the design bases of the Normal Decay Heat Removal Valve Control System [consists of] generating station conditions which require protective action," such as "RC system pressure above the design pressure of the decay heat removal system." ITS Table 3.3.5-1 (page 194 of 636) does not adopt operability or surveillance requirements for CTS Functional Unit 5.b in Table 3.3-3. Table 3.3.5-1 of the STS (NUREG-1430) does not mention the interlock either, however the STS seems to be based on a Crystal River design that does not have the interlock. Criterion 3 of 10 CFR 50.36(d)(2)(ii) states.a TS must be established for "a structure, system, or component that is part of the primary success path and which functions or actuates to mitigate a design basis accident or transient that either assumes the failure of or presents a challenge to the integrity of a, http://www.excelservices.com/exceldbs/itstrackdavisbesse.nsf/1 fddcea 1Od3bdbb585256e... 7/18/2008

NRC ITS Tracking Page 2 of 2 fission product barrier." It is unclear why the Interlock associated with the pressurizer heaters and the Decay Heat System that is based on RCS Pressure is not required in TS per Criterion 3 of 10 CFR 50.36(d)(2)(ii). [LA04] Issue.Date 11/16/2007 Cl.ose.Dte 5; [ 01/10/2008 Logged in User: Anonymous

'Responses Licensee Response by Jerry         The UFSAR statement referenced in the NRC reviewer's question Jones on 12/05/2007                is accurate. The Pressurizer Heater Interlocks specified in CTS table 3.3-1 (Volume 8, Page 175) prevent the pressurizer heaters from being a source for overpressurizing the DHR System .suction piping. The Pressurizer Heater Interlocks are derived from the signal comparators located in the SFAS channels 1 and 4. The signal comparators receive their RCS pressure signal from the RCS loop 1 or 2 wide range pressure transmitters that supply the signal for the corresponding SFAS channel. The DHR System outboard suction isolation valve, DH 11, utilizes the same signal comparator for the Decay Heat Isolation Valve interlock. The DHR System inboard suction isolation valve, DH12, utilizes a pressure switch in RC loop 1 for the Decay Heat Isolation Valve interlock. However, the Pressurizer Heater Interlocks are not credited in the safety analysis, nor are modeled in the Davis Besse Probabilistic Risk Assessment. Therefore, the pressurizer heater portion of the interlock, which provides a backup type signal, does not meet any of the criteria in 10 CFR 50.36(d)(2)(ii), thus is not necessary to be included in the ITS. This information is provided in Discussion of Change LA04 (Page 186 and 187). Therefore, Davis-Besse does not believe that this is a beyond scope change, since conversion to the ITS includes relocating items that do not meet the criteria of 10 CFR 50.36(d)(2)(ii). The Decay Heat Isolation Valve portion of the interlock is being maintained in the ITS as part of ITS 3.4.14 (in Volume 10). Thus, on a high pressure signal, the decay heat removal valves will close.

NRC Response by Aron Lewin Will request conference call with licensee via PM. [on 12/20/2007ii_____________________________ NRC Response by Aron Lewin Issue being tracked to resolution by TAC MD7681 (SRXB). on 01/10/2008 Anticipate any further questions regarding this issue to be charged and documented under TAC MD768 1. Date Created: 11/16/2007 11:09 AM by Aron Lewin Last Modified: 0 1/10/2008 09:41 AM http://www.excelservices.com/exceldbs/itstrack-davisbesse.nsfllfddcea1Od3bdbb585256e... 7/18/2008

NRC ITS Tracking Pagel of2

   .I.PReturn      to...View Menu,1Q .Print !ocuti RAI Screening Required: Yes                                       Status: Closed This Document will be approved by: Tim                            Regulatory Basis must be included in Comments Kobetz                                                            section of this Form This document has been reviewed and                               Yes information in this question contains NO SUNSI sensitive material (the checkbox to the right must be selected before this question can be submitted)

NRC ITS TRACKING NRC Reviewer ID 200711161110 Conference Call Requested? No Category BSI - Beyond Scope Issue ITS Section: TB POC.: JFD Number: Page Numnber(s): ITS 3.3 Aron Lewin None Information ITS Number: OS: DOCNuamber: Bases JFD.Number: 3.3.5 None None None Discuss how allowing Method 1 or Method 2 of Reference 5 [ISA 67.04-Part II-19941 or 6 [ISA 67.04.02-20001 for all SFAS Functional Units in the ITS Bases ensures that the limiting safety system setting is chosen so that automatic protective action will correct the abnormal situation before a safety limit is exceeded in accordance with 10 CFR 50.36(d)(1)(ii)(A).

Background

The Bases for CTS 3/4.3.1 and 3/4.3.2 (page 398 of 490 in the CTS), state that

                              ."for the SFAS, only the Allowable Value is specified for each Function.

Nominal trip setpoints are specified in the setpoint analysis. The nominal trip setpoints are selected to ensure the setpoints measured by CHANNEL FUNCTIONAL TESTS do not exceed the Allowable Value if the bistable is performing as required. Operation with a trip setpoint less conservative than Comment the nominal trip setpoint,, but within -itsAllowable Value, is acceptable

         ................. provided that operation and testing are consistent with the assumptions of the specific setpoint calculations. Each Allowable Value specified is more conservative than the analytical limit assumed in the safety analysis to account for instrument uncertainties appropriate to the trip parameter. These uncertainties are defined in the specific setpoint analysis."

The Bases for the ITS (page 209 of 636) states that "the trip setpoint is established using Method 1 or Method 2 of Reference 5 [ISA 67.04-Part II-1994] or 6 [ISA 67.04.02-2000]." The Bases for the STS for LCO 3.3.5 (NUREG-1430), state "a detailed description of the methodology used to calculate the trip setpoints, including their explicit uncertainties, is provided in "[Unit Specific Setpoint Methodology]". 10 CFR 50.36(d)(1)(ii)(A) states that "limiting safety system settings for http://www.excelservices.com/exceldbs/itstrackdavisbesse.nsfl1 fddceal Od3bdbb585256e... 7/18/2008

NRC ITS Tracking Page 2 of 2 nuclear reactors are settings for automatic protective devices related to those variables having significant safety functions. Where a limiting safety system setting is specified for a variable on which a safety limit has been placed, the setting must be so chosen that automatic protective action will correct the abnormal situation before a safety limit is exceeded." It is unclear how allowing Method 1 or Method 2 of Reference 5 [ISA 67.04-Part 11-19941 or 6 [ISA 67.04.02-2000] for all SFAS Functional Units in the ITS Bases ensures that the limiting safety system setting is chosen so that automatic protective action will correct the abnormal situation before a safety limit is exceeded in accordance with 10 CFR 50.36(d)(1)(ii)(A). Issue Date 11/16/2007 Cloe a~ej01/10/2008 s DLogged in User: Anonymous

' Responses Licensee Response by Jerry            Method 1 and Method 2 of Reference 5 (ISA 67.04-Part 11-1994)

Jones on 12/05/2007 and Reference 6 (ISA 67.04.02-2000) are NRC approved methods for calculating Allowable Values and trip setpoints. The STS Bases for LCO 3.3.5 includes a bracketed requirement for the applicant to provide the unit specific setpoint methodology (Volume 8, Pages 209, 210, and 224). The two above referenced documents are the Davis-Besse setpoint methodology. The proposed words in the Davis-Besse ITS Bases (Pages 209 and 210) are more explicit, in that, in lieu of referencing a unit specific setpoint methodology (i.e., ISA 67.04-Part 11-1994 and ISA 67.04.02-2000), it is specifically stated that the Allowable Values and trip setpoints are established using Method 1 or Method 2 of the two referenced documents. As these methods are acceptable and meet NRC requirements, maintaining the specific Methods in the ITS Bases is desired. However, if the NRC desires, the specific methods can be removed and the Bases could only state the two documents. Note that this question is similar to that asked about the RPS setpoint methodology in question 200711160956. NRC Response by Aron Lewin Will request conference call with licensee via PM. on 12/20/2007 NRC Response by Aron Lewin Issue being tracked to resolution by TAC MD7470 (EICB). on 01/10/2008 Anticipate any further questions regarding this issue to be charged and documented under TAC MD7470. Date Created: 11/16/2007 11:10 AM by Aron Lewin Last Modified: 01/10/2008 09:44 AM http://www.excelservices.comlexceldbs/itstrackdavisbesse.nsfl1 fddceal Od3bdbb585256e... 7/18/2008

NRC ITS Tracking Page I of 2 Return to View Menu Print Docuen RAI Screening Required: No Status: Approval Not Required This is a Non RAI Dialogue This document will not be relied upon by staff for disposition of the LAR This document has been reviewed and Yes information in this question contains NO SUNSI sensitive material (the checkbox to the right must be selected before this question can be submitted) NRC ITS TRACKING NRC Reviewer ID 200801231601 Conference Call Requested? No Category Other Technical Challenge ITS Sec-tio.n TB POC: JFD .Number:. P-age Number(s); ITS 3.3 Aron Lewin None' Information ITS.Number: OS1: DOC.Number: Bases JFD .Number; 3.3.5 None None" None Regarding ID#200711161109 (Pzr Htr - Decay Valve Interlock) Discuss why the Pressurizer Heater Interlock is being removed from the CTS Co.nmment while the Decay Heat Isolation Valve Interlock is being retained in TS, given that both interlocks seem to provide the same function of ensuring that integrity of the Decay Heat System is maintained. Issue Date 01/23/2008 Close ate 01/24/2008 Logged in User: Anonymous

' Responses Licensee Response by Jerry             The capability of DH-4849 to provide LTOP is accomplished by Jones on 02/11/2008                    opening the DHR isolation valves DH-1 1 and DH-12 and removing control power from their motor operators. Plant cooldown and depressurization continues with DH-1 1 and DH-12 open and incapable of inadvertent closure. During plant heatup and repressurization, control power is restored to the motor operators of DH- 11 and DH-12 and the valves are closed. The decay heat isolation valve interlocks are intended to ensure double valve isolation between the RCS and relatively low pressure decay heat removal system is established during plant heatup and maintained during plant operation. The pressurizer heater interlocks were installed prior to the start of the second fuel cycle. The purpose of the design modification was to allow removal of power from DH-11 and DH-12, making them incapable of inadvertent closure, http://www.excelservices.com/exceldbs/itstrack-davisbesse.nsf/lfddcealOd3bdbb585256e...               7/18/2008

NRC ITS Tracking Page 2 of 2 while providing assurance that multiple operator errors would not result in increasing reactor coolant system pressure with the valves inadvertently left open during heatup. The pressurizer heater interlock prevents pressurizer heater operation with either of the two in-series decay heat isolation valves (DH- 11 or DH-12) not fully closed and RCS pressure above the interlock's setpoint. This interlock serves as an automatic prompt to the operator to properly position both decay heat isolation valves and enable the automatic valve closure interlocks prior to raising RCS pressure. Once both valves are closed, the decay heat isolation valve interlocks provide the redundant, diverse over-pressurization protection of the DHR system (i.e. the isolation valve interlocks prevent opening the valves when RCS pressure is above the setpoint). The pressurizer heater interlock is not being retained in Technical Specifications because it does not meet any of the four selection criterion of 10 CFR 50.36(d)(2)(ii) for inclusion. It provides assurance that multiple operator errors would not result in increasing reactor coolant system pressure with the valves inadvertently left open during heatup. Specifically, 1) The pressurizer heater interlock is not used for, nor capable of, detecting a significant abnormal degradation of the reactor coolant pressure boundary during operations prior to a DBA. 2) The pressurizer heater interlock is not a process variable, design feature, or operating restriction that is an initial assumption in a DBA or transient. 3) The pressurizer heater interlock is not part of a primary success path in the mitigation of a DBA or transient. 4) The pressurizer heater interlock is not credited in the safety analysis, nor modeled in the Davis Besse Probabilistic Risk Assessment and does not contain constraints of prime importance in limiting the likelihood or severity of the accident sequences that are commonly found to dominate risk. Furthermore, the Decay Heat Removal (DHR) System Valve Interlocks, which do are being retained in the Davis-Besse ITS since ISTS 3.4.14 includes these interlocks (See Volume 9, Page 296). Ensuring the DHR System valve interlock function that closes the valves and prevents the valves from being opened is OPERABLE ensures that RCS pressure will not pressurize the DHR System beyond its test pressure. Date Created: 01/23/2008 04:01 PM by Aron Lewin Last Modified: 01/24/2008 07:29 AM http://www.excelservices.com/exceldbs/itstrackdavisbesse.nsf/1 fddceal Od3bdbb585256e... 7/18/2008

NRC ITS Tracking Page I of 2 Return to View MenuJ Prnt Doýlen RAI Screening Required: Yes Status: Closed This Document will be approved by: Carl Regulatory Basis must be included in Comments Schulten; Gerald Waig section of this Form This document has been reviewed and Yes information in this question contains NO SUNSI sensitive material (the checkbox to the right must be selected before this question can be submitted) NRC ITS TRACKING NRC Reviewer ID }f200801240737 Conference Call Requested? No Category BSI - Beyond Scope Issue ITS...Seetion: TB POC: JF..D Number: Page.Numnber(s).:. ITS 3.3 Aron Lewin None Information ITS Number: OS: DOC Number: BaseseJ-D Number: 3.3.5 None None None Regarding ID#200711161109 / NRC OSI#45 (Pzr Htr - Decay Valve Interlock) ID#200711161109, which referenced Criterion 3 of 10 CFR 50.36(d)(2)(ii) as a regulatory basis, was closed out since it is currently being tracked / reviewed by the technical branch (MD7681). However, based on a 12/21/2007 conference Commentt call with the licensee, the licensee stated they would: Discuss why the Pressurizer Heater Interlock is being removed from the CTS while the Decay Heat Isolation Valve Interlock is being retained in TS, given that both interlocks seem to provide the same function of ensuring that integrity of the Decay Heat System is maintained. Issue.Date I 01/24/20'08 Close Date] 02/20/2008 Logged in User: Anonymous 'Responses oLicensee Response2by Jerry See the response to 200801231601. [Jones on 02/11/2008 :7771__________________ NRC Response by Aron Lewin No further questions at this time. Reference to 200801231601 on 02/20/2008 means that information provided in that thread is used for making a regulatory decision, even though that thread itself was not initially screened as an RAI. (It should be noted that 200801231601 was initially submitted by the NRC in error and closed out immediately. However, due to database error, the licensee was able to respond on a closed thread.) http://www.excelservices.com/exceldbs/itstrack-davisbesse.nsf/l fddceal Od3bdbb585256e... 7/18/2008

NRC ITS Tracking Page 2 of 2 Date Created: 01/24/2008 07:37 AM by Aron Lewin Last Modified: 02/20/2008 03:20 PM http://www.excelservices.com/exceldbs/itstrackdavisbesse.nsf/lfddcealOd3bdbb585256e... 7/18/2008

NRC ITS Tracking Page I of 2 jjVReturn to View MenuJ Print Document RATI Screening Required: Yes Status: Closed This Document will be approved by: Gerald Regulatory Basis must be included in Comments Waig; Tim Kobetz section of this Form This document has been reviewed and Yes information in this question contains NO SUNSI sensitive material (the checkbox to the right must be selected before this question can be submitted) NRC ITS TRACKING NRC Reviewer ID 200712260933 Conference Call Requested? No Catego;y BSI - Beyond Scope Issue ITS Section:. TB POC: JFD. Number:. Page Number(s): ITS 3.3 Aron Lewin None Information ITS..Number:, OSI: DO CNumber: Bases.JFD Number: 3.3.8 None None None NRC OSI#48 Discuss how removing a statement in the ITS Bases effects physical application and reporting requirements of the LCO, and, in addition, still gives assurance that the limiting safety system setting is chosen so that automatic protective action will correct the abnormal situation before a safety limit is exceeded in accordance with 10 CFR 50.36(d)(1)(ii)(A).

Background

The Bases for CTS 3/4.3.1 and 3/4.3.2 (page 396 thru 400 of 490 in the CTS) do not seem to discuss Allowable Values associated with the Degraded Voltage Functional Unit (CTS Unit 4.b) and the Loss of Voltage Functional Unit (CTS Unit 4.c). The ITS Bases (page 295 of 636) removes an Allowable Value statement that is Comment found in the STS. The STS Bases for LCO 3.3.8 (NUREG-1430) states "Setpoints in accordance with the Allowable Value will assure that limits of Chapter 2.0, "Safety Limits," in the Technical Specifications are not violated during anticipated operational occurrences (AOOs); that the consequences of accidents will be acceptable, providing the unit is operated from within the LCOs at the onset of the AOO or accident; and that the equipment functions as designed." 10 CFR 50.36(d)(1)(ii)(A) states that "limiting safety system settings for nuclear reactors are settings for automatic protective devices related to those variables having significant safety functions. Where a limiting safety system setting is specified for a variable on which a safety limit has been placed, the setting must be so chosen that automatic protective action will correct the abnormal situation before a safety limit is exceeded." http://www.excelservices.com/exceldbs/itstrack-davisbesse.nsf/1fddcea1Od3bdbb585256e... 7/18/2008

NRC ITS Tracking Page 2 of 2 [ Issue.. Date 12/26/2007 Closte ] 04/03/2008 Logged in User: Anonymous

'vResponses Licensee Response by Bryan        As part of the Amendment 275 process, a footnote was'added to Kays on 03/03/2008                CTS Table 4.3-2 stating: "The as-left setting shall be returned to a setting within the tolerance band of the trip setpoint established to protect the safety limit." Thisstatement now appears in Volume 8 on Page 304. The paragraph in question (Page 295) incorrectly states Allowable Value instead of trip setpoint. The paragraph was deleted to better align with TSTF 493.

onNRC Response by Aron Lewin No further questions at this time. [on 04/03/2008 i Date Created: 12/26/2007 09:33 AM by Aron Lewin Last Modified: 04/03/2008 07:52 AM http://www.excelservices.com/exceldbs/itstrack-davisbesse.nsf/1fddceal d3bdbb585256e... 7/18/2008

NRC ITS Tracking Page I of 2 R1 Return to View Menu] Print Doctume RAI Screening Required: Yes Status: Closed This Document will be approved, by: Gerald Regulatory Basis must be included in Comments Waig; Tim Kobetz section of this Form This document has been reviewed and Yes information in this question contains NO SUNSI sensitive material (the checkbox to the right must be selected before this question can be submitted) NRC ITS TRACKING NRC Reviewer ID1200712260937 Conference Call Requested? No Categoy

        ..             BSI - Beyond Scope Issue ITS Section:          TB P...OC.:.          JFDrNumber.:        Page Number(s):.

ITS 3.3 Aron Lewin None Information [TSINurmber.: 0..11: DOC.. Num..be.r:1 Bases-JFD Number.; 3.3.8 None None None NRC OSI#49 Discuss how adding s statements in the ITS Bases, for Allowable Value setpoint methodology associated with the Degraded Voltage Functional Unit, effects physical application and reporting requirements of the LCO, and, in addition, still gives assurance that the limiting safety system setting is chosen so that automatic protective action will correct the abnormal situation before a safety limit is exceeded in accordance with 10 CFR 50.36(d)(1)(ii)(A).

Background

The Bases for CTS 3/4.3.1 and 3/4.3.2 (page 396 thru 400 of 490 in the CTS) do not seem to discuss Allowable Value setpoint methodology associated with the Degraded Voltage Functional Unit (CTS Unit 4.b). The ITS Bases (page 299 of 636) has a discussion on Degraded Voltage LOPS Comment Allowable Value setpoint methodology not found in the CTS or the STS. The STS Bases for LCO 3.3.8 (NUREG-1430) does not have the ITS Bases discussion on Allowable Value setpoint methodology for the Degraded Voltage Functional Unit. 10 CFR 50.36(d)(1)(ii)(A) states that "limiting safety system settings for nuclear reactors are settings for automatic protective devices related to those variables having significant safety functions. Where a limiting safety system setting is specified for a variable on which a safety limit has been placed, the setting must be so chosen that automatic protective action will correct the abnormal situation before a safety limit is exceeded." It is unclear how adding statements in the ITS Bases, for Allowable Value setpoint methodology associated with the Degraded Voltage Functional Unit, effects physical application and reporting requirements of the LCO, and; in addition, still gives assurance that the limiting safety system setting is chosen so that http://www.excelservices.com/exceldbs/itstrackdavisbesse.nsf/1 fddcea1Od3bdbb585256e... 7/18/2008

NRC ITS Tracking Page 2 of 2 automatic protective action will correct the abnormal situation before a safety [ Issue Close Dýt Date limit is exceeded in accordance with 10 CFR 50.36(d)(1)(ii)(A). 12/26/2007 03/24/2008 Logged in User: Anonymous "'Responses Licensee Response by Bryan The statements added to the Bases regarding Degraded Voltage Kays on 03/03/2008 LOPS are consistent with the information provided to and from the NRC associated with Amendment 275. (Serial 3009, 3100, 3186, 3193, and 3265, the NRC Safety Evaluation, and calculation C-EE-004.01-049) The changes make the Bases applicable to Davis-Besse and align with the current licensing basis. NRC Response by Aron Lewin No further questions at this time. on 03/24/2008 Date Created: 12/26/2007 09:37 AM by Aron Lewin Last Modified: 03/24/2008 10:08 AM http://www.excelservices.com/exceldbs/itstrackdavisbesse.nsfl1 fddcealOd3bdbb585256e... 7/18/2008

CALCULATION ADDENDUM NOP-CC-3002-02 Rev. 02 .DD INITIATING DOCUMENT(S) CALCULATION NO. CALCULATION RE. ADDENDUM NO. ECP 04-0294-00, Rev. 00 C-EE-004.01-049 15 A02 TITLE/

SUBJECT:

(MUST MATCH ORIGINAL CALCULATION TITLE (SUBJECT) 4.16 KV BUS C1/D1 DEGRADED VOLTAGE, LOSS OF VOLTAGE, AND 27X-6 RELAY SETPOINT [I BV I l] BV2 DB E PY Classification ] Tier 1 Calculation [] Safety-Related/Augmented Quality LI Nonsafety-Related Open Assumptions? El Yes Z No If Yes, Enter CR Tracking Number Computer Program(S) Program Name Version / Revision Category Status Description Microsoft Word 2003 C Active Word Processor ORIGINATORPDATE"; REVIEWERPD* FI DAT E'-APPROVER/DATE 7. , - cý B. M. Waybright / J.R.Chowdh Ito*N N$-- ..- OBJECTIVE OR PURPOSE OF ADDENDUM: This addendum is to revise the Degraded Voltage Relay time delay, upper and lower Allowable Values from 7.94 and 6.37 seconds to 7.9 and 6.4 seconds, respectively. The calculated values are 7.94 and 6.37 seconds. These values were not conservatively rounded to reflect the allowable values submitted in LAR 03-0014. The LAR has been approved and is License Amendment 275 (Log 6447). Based on this, the values should be updated to be consistent with Amendment 275. The required calibration frequency of the 27X-6[C1 and 27X-6/D1 is also changing. Rev. 15 of the calculation assumed the calibration frequency was being initiated by CR 04-01239, Corrective Action 3. This was proven to be incorrect per a System Engineer in ECP 04-0294-00 (DIE 03c/0). The calibration frequency is being changed as a result of industry experience and vendor recommendations. The calibration frequency is now being initiated by two PMs referenced in this addendum. SCOPE OF ADDENDUM: The scope of the addendum is to revise the Degraded Voltage Relay time delay Allowable Values to be consistent with License Amendment 275. In addition, the calibration frequency for the 27X-6 relays has been re-adjusted and correctly initiated. LIST NEW DOCUMENTS TO BE ADDED TO THE DOCUMENT INDEX (DIN):

SUMMARY

OF RESULTS/CONCLUSIONS OF ADDENDUM: There is no impact on the conclusion. The Allowable Value was revised to be consistent with Amendment 275 (LAR 03-0014). LIMITATIONS OR RESTRICTIONS CREATED BY ADDENDUM: There are no limitations or restrictions because the LAR has been approved. IMPACT OF ADDENDUM ON OUTPUT DOCUMENTS: The impact on the allowable value will be consistent with License Amendment 275. The Amendment will provide procedure and Technical Specification change implementation. ECP 04-0294-00 will implement the Relay Setting Manual changes. Based on this, there is no impact on the output documents. DESCRIBE WHERE THE ADDENDUM WILL BE EVALUATED FOR 10CFR50.59 APPLICABILITY: RAD 06-03884-00 LIST SUPPORTING DOCUMENTS: (Include total numrer of pages) Regulatory Applicability Determination 06-03884 (2 page(s))

CALCULATION ADDENDUM NOP-CC-3002-02 Rev. 02 . 7 INITIATING DOCUMENT(S) CALCULATION NO. CALCULATION RE\. ADDENDUM NO. ECP 04-0294-00, Rev. 00 C-EE-004.01-049 15 A02 TITLE/

SUBJECT:

(MUST MATCH ORIGINAL CALCULATION TITLE (SUBJECT) 4.16 KV BUS C1/D1 DEGRADED VOLTAGE, LOSS OF VOLTAGE, AND 27X-6 RELAY SETPOINT Design Interface Summary (1 page) DIE 01 (System Engineer) (2 pages) DIE 02 (Engineering Assessment Board) (I page) Design Verification Record (1 page) Calculation Review Checklist (4 pages) LIST ATTACHMENTS: (Include total number of pages) Revised Calculation page iii (1 page) Revised Calculation page ix (1 page) Revised Calculation page 21 (1 page) Revised Calculation page 30 (1 page) Revised Calculation page 33 (1 page)

Firstýne[ Page iii CALCULATION NOP-CC-3002-01 Rev. 01 A0 2., 34 7 INITIATING DOCUMENT (S) CALCULATION [I VENDOR CALC

SUMMARY

LAR 03-0014 C-EE-004.01-049 TITLE/

SUBJECT:

4.16 kV Bus C1/D1 Degraded Voltage, Loss of Voltage, and 27X-6 Relay Setpoints OBJECTIVE OR PURPOSE: The bus Degraded Voltage Relays (DVR), Loss of Voltage Relays (LVR), and 27X-6 relays are designed to separate the safety related onsite electrical distribution system from the non-safety related onsite electrical system and the offsite power system after a predetermined period of unacceptably low voltage. The purpose of this calculation is to determine Dropout, Pickup and Time Delay setpoints for the relays. The setpoints are selected to ensure that the voltage at 4.16KV Essential Buses Cl and DI will not drop below the minimum value at which all safety related loads will have sufficient voltage to perform their intended safety function. The setpoints also ensure the busses are not inappropriately disconnected from the preferred offsite source. This calculation establishes Allowable Values and Setpoints for the Dropout, Pickup and Time Delay settings of the relays. This calculation also establishes the Analytical Limits for the Upper Time Delays. SCOPE OF CALCULATION/REVISION: Rev. 15 is to establish the Analytical Limits, Allowable Values and Setpoints for the upper and lower ranges of the DVR, LVR and 27X-6 relays in support of LAR 03-0014. This revision also incorporates the appropriate information from Calculations C-EE-004.01-051 and C-EE-004.01-057 to allow for one complete and concise location for all relays associated with EDG startup.

SUMMARY

OF RESULTS/CONCLUSIONS: Voltage Sensor (DVR) Value Relay Value Degraded Voltage Relay, Pickup Analytical Limit 3786 Volts < 108.17 V Degraded Voltage Relay, Pickup Allowable Value *3771 Volts < 107.74 V Degraded Voltage Relay, Pickup Setpoint 3759 Volts Max 107.40 V Max Degraded Voltage Relay, Dropout Trip Setpoint 3734 + 7 Volts 106.69 + 0.2 V Degraded Voltage Relay, Dropout Allowable Value > 3712 Volts > 106.06V Degraded Voltage Relay, Dropout Analytical Limit 3700 Volts > 105.71 V Time Delay (DVR) Degraded Voltage Relay TD, Upper Analytical Limit 8.10 seconds Degraded Voltage Relay TD, Upper Allowable Value *<7.9 seconds Degraded Voltage Relay TD, Nominal Setting 7.5 + 0.2 seconds 7.5 + 0.2 sec Degraded Voltage Relay TD, Lower Allowable Value > 6.4 seconds Degraded Voltage Relay TD, Lower Analytical Limit 6.21 seconds

Page ix CALCULATION 01 AD 2.. ?o. e- 4&4 7 INITIATING DOCUMENT (S) CALCULATION NO. VENDOR CALC

SUMMARY

LAR 03-0014 C-EE-004.01-049 TITLE/

SUBJECT:

4.16 kV Bus CI/D1 Degraded Voltage, Loss of Voltage, and 27X-6 Relay Setpoints

90. E-64B, SH. IA/EDG 1-1 BrkAC101 Control Rev. 8 [A El El

91. E-64B, Sh. 2A / EDG 1-2 Bkr AD!01 Control, Rev. II N] El 1

92. E-64B, Sh. IE / EDG 1-1 Misc Aux Relays, Rev. 16 M El El

93. E-64B, Sh. 2E / EDG 1-2 Misc Aux Relays, Rev. 15 , H El F]

94. E-641, Sb. 17 / EDG SFAS Sequencer Start/Stop Rev. 5 0 El 0

95. E-64B, Sh. 18 / EDG SFAS Sequencer Start/Stop Rev. 3 [L El E Aux Relays

96. Specification No. 12501-E-5Q, Technical Rev. 3 E El El Specification for Operational Phase for 4,160 and 13,800 Volt Metal-Clad Switchgear

97. Framatome Document 86-5006232-01, DB-1 LOCA Rev. 01 E El El Summary Report, (EXT-02-00822)

98. Framatome Document 32-1171604-00, LPI/HPI Rev. 00 Ll ] El LBLOCA Assumptions (Film 4388, Frame 2096)

99. MPR Report 2594 (ACT# 04-0026), D-B EDG Rev. 1, 2/5/2004 El [A El Transient Response Evaluation 100. Condition Report 04-01239 N/A El 0 E]I 101. Work Order 03-000803-04 5/9/03 D] 0 El 102. DB REV-06-0611 N/A Z El n 103. DB REV-06-0612 N/A F] El n 104. Log 6447 (License Amendment 275) August 9, 2006 N 0 El

FirstEner y Page 21 CALCULATION COMPUTATION NOP-CC-3002-01 Rev. 01 Pane, S"k 7 CALCULATION NO.: "I'EVISIO: C-EE-004.01-049 15 TITLE /

SUBJECT:

4.16 kV Bus C1/D1 Degraded Voltage, Loss of Voltage, and 27X-6 Relay Setpoints Per DINs 45 and 46, the tolerance is + 0.2 seconds. The use of 0.2 seconds is well below the 10% accuracy. The higher of the Accuracy and Calibration Tolerance will be included in the final calculated value. In this case, the Accuracy is higher. 4.6.5 Temperature Effect Per vendor documentation (DIN 58) the devices were tested for temperature variations. The values were a worst case from low temperature (-25 degrees C) to a high value (75 degrees C) was 2%. This 2% value is a conservative value since the temperature ranges for these devices does not span 100 degrees C (212 degrees F). Temp Eff = 2% x 8.10 second

                         = 0.162 seconds 4.6.6    DVR Time Delay Allowable Value (Upper)

The Allowable Value is based on those uncertainties that are not "tested" based on the definition in ISA-67.04.02 - 2000 (DIN 32). The only value that is not "tested" is the Temperature Effect. This is included between the Analytical Limit and the Allowable Value as it is not a significant contributor to overall uncertainty. Per Appendix I of DIN 32, this value should be between the Analytical Limit and the Allowable Value. AVTU = AL Temp Eff

                         = 8.10 - 0.162
                         = 7.94 seconds Margin was added to decrease time to < 7.9 Seconds
                         < 7.9 seconds 4.6.7     DVR Time Delay Allowable Value (Lower)

AVTL = AL + Temp Eff

                         =6.21 + 0.162
                         = 6.37 seconds Margin was added to increase time to > 6.4 Seconds
                         > 6.4 seconds 4.6.8 4.6.9     DVR Time Delay Setpoint.

The Time Delay Setpoint is derived from the combination of the given AV and the total of all channel uncertainties. TSP (Upper) = AL - SRSS (M&TE, Accuracy, Drift, TempEff)

FirstEnergy Page 30 CALCULATION COMPUTATION NOP-CC-3002-01 Rev. 01 A 2.. Pact o 7 CALCULATION NO.: REVISIO. C-EE-004.01-049 15 TITLE I

SUBJECT:

4.16 kV Bus C1/D1 Degraded Voltage, Loss of Voltage, and 27X-6 Relay Setpoints 4.9.5 Power Supply Effects Not applicable for these relays, since accuracy of+ 2% of setpoint is over the entire operating range of temperature and voltage (See 4.9.4 above). 4.9.6 Temperature Effects, Normal These timers are located in Rooms 323 (Bus Cl) and 325 (Bus D1) in switchgear cubicles AC101 and AD101. These relays are located in a mild environment during both normal operation and accident conditions. The expected range of operating temperatures is 60'F (15.5°C) to 104'F (40'C) Ref: USAR Section 9.4.2.1). For conservatism, the maximum temperature of 131°F (55'C) will be used, with a minimum temperature of 32°F (00 C). (Ref: C-ME-30.01-008 - According to this calculation Rooms 323 and 325 will have temperature of 120.01'F (say 120'F) during the loss of normal ventilation and with a AT between room and the cabinet (that is, switchgear cubicle) of 10.9°F (say 11 F). Therefore the cabinet will be at 131 'F during the loss of normal ventilation). This is within the stated accuracy (See 4.9.4 above). 4.9.7 Vibration Effects These timers are located in Rooms 323 (Bus Cl) and 325 (Bus DI) in switchgear cubicles AC 101 and AD 101. There is no in-service vibration involved for these relays. Therefore, vibration effects are not applicable to these relays. 4.9.8 Analog to Digital Conversion As these are solid state time delay relays and having no analog to digital conversion of the output. Therefore, there is no analog to digital conversion effect. 4.9.9 Digital to Analog Conversion As these are solid state time delay relays and having no digital to 'analogconversion of the output. Therefore, there is no digital to analog conversion effect. 4.9.10 Drift Drift is assumed to be equivalent to accuracy (Assumption 2.2). This-requires a calibration on the frequency of a refueling outage frequency (18-24) months (DIN 88, and 62 (tab 78)). This calibration frequency is being initiated by DB-REV-06-0611 and DB-REV-06-0612 (DIN 102,103). Drift = 0.012 seconds

First~herg Page 33 CALCULATION COMPUTATION NOP-CC-3002-01 Rev. 01 Ao2- &j ce-7-k 7 CALCULATION NO.: REVISION: v C-EE-004.01-049 15 TITLE /

SUBJECT:

4.16 kV Bus CI/D1 Degraded Voltage, Loss of Voltage, and 27X-6 Relay Setpoints 5.0 RESULTS The results are presented below in order of highest to lowest: Voltage Sensor Value Relay Value Degraded Voltage Relay, Pickup Analytical Limit 3786 Volts

• 108.17 V.'

Degraded Voltage. Relay, Pickup Allowable Value <3771 Volts <107.74 V Degraded Voltage Relay, Pickup Setpoint 3759 Volts Max 107.40 V Max Degraded Voltage Relay, Dropout Trip Setpoint 3734 + 7 Volts 106.69 + 0.2 V Degraded Voltage Relay, Dropout Allowable Value > 3712 Volts - 106.06V Degraded Voltage Relay, Dropout Analytical Limit 3700 Volts > 105.71 V Time Delay Degraded Voltage Relay TD, Upper Analytical Limit 8.10 seconds Degraded Voltage Relay TD, Upper Allowable Value < 7.9 seconds Degraded Voltage Relay TD, Nominal Setting 7.5 + 0.2 seconds, 7.5 +/-0.2 sec Degraded Voltage Relay TD, Lower Allowable Value >_6.4 seconds Degraded Voltage Relay TD, Lower Analytical Limit 6.21 seconds Voltage Sensor Value Relay Value Loss of Voltage Relay, Pickup Analytical Limit 2500 Volts 71.43 V Loss of Voltage Relay, Pickup Allowable Value < 2492 Volts < 71.20 V Loss of Voltage Relay, Pickup Setpoint 2466 Volts Max 70.46 V Max Loss of Voltage Relay, Dropout Trip Setpoint 2429 + 7 Volts 69.40. + 0.2 V Loss of Voltage Relay, Dropout Allowable Value > 2071 Volts > 59.17V Loss of Voltage Relay, Dropout Analytical Limit N/A N/A Time Dela Loss of Voltage Relay TD, Upper Analytical Limit

• 0.6 seconds Loss of Voltage'Relay TD, Upper Allowable Value < 0.58 seconds Loss of VoltageRelay TD, Nominal Setting 0.5 + 0.05 seconds 0.5 +/- 0.05 sec

FrstEne REGULATORY APPLICABILITY DETERMINATION No. 06-03884 Page 1 of 2Re.0 Rev. 00 NO.P-LP-4003-01 Rev. 02 Initiating Activity No. ECP ECP04-0294-00, C-EE-004.01-049R15-A02, UCN06-544U Rev. 00 El BVPS I] BVPS 2 W] DBNPS El PNPP

Title:

4.16kV Bus CIID1 Degraded Voltage, Loss of Voltage, and27X-6 Relay Setpoint Brief description of activity (what is being changed and why): The Engineering Change Package revises the Degraded and Loss of Voltage Relay allowable values and field setpoints as a result of approved License Amendment 275 (Log 6447). The ECP revises the Relay Setting Manual, design drawings, and the System Description. The allowable values and field setpoints are based on the calculation C-EE-004.01-049, Rev. 15. The calculated values required a License Amendment which.has been 'approved by the NRC (Amendment 275, Log 6447). Calculation C-EE-004.01-049, Rev. 15, A02 revises the Degraded Voltage Relay (DVR) time delay allowable value. The calculated values were 7.94 and 6.37 seconds for the high and low values. These values are now rounded to 7.9 and 6.4 in the calculation. This change brings the calculation into agreement with the License Amendment. USAR Change Notice 06-544U revises the descriptions of the 90% and 59% under voltage relays in sections 8.3,1.1, 8.3.1.1.3, 8.3.1.1.4.1. Per License Amendment 275 (Log 6447), the relays are .now described as the Degraded Voltage Relays and Loss of Voltage Relays, respectively. I. EXEMPTIONS Is the scope of the entire activity exempt from the IO0CFR50.59 process because it is limited to: 1.1 Managerial or adm inistrative changes ...................................................................................  :........... El YES R] NO 1.2 UFSAR changes (or equivalent information) excluded from the requirement to perform a 10CFR50.59 Screen and Evaluation by NEI 96-07 or NEI 98-03?....... ................ OYES PI NO 1.3 Maintenance activities and temporary alterations in support of maintenance planned for 90 days or less w hile at power ............ ................................................................. .. YES [] NO 1.4 Changes evaluated under another program that included a IOCFR50.59 Scre en ..................................................................... I.......................................................................... YE S NO

2. OTHER REGULATIONS 2.1 Does the activity require a license amendment?

2.1.1 O perating License ............................................. ..................................................................... D Y ES W NO 2.1.2 Technical Specifications........................................... .................... . [,/ YES Li NO 2.1.3 Environmental Protection Plan (BVPS and PNPP only) ............................. YES R] NO 2.2 Is the activity or any portion of the activity governed by one or more of the following regulations: 2.2.1 Quality Assurance Program (10CFR50.54(a)) ......................................................... ................ YES 0] NO 2.2.2 Security Plans (IOCFR50.54(p)) ............................................ YES W] NO 2.2.3 Emergency Plan (10CFR50.54(q)) ........................................................................................ Li YES -E0NO 2.2.4 IST Program Plan (10CFR50.55(a)(f)) ........................................ Li YES [] NO 2.2.5 ISI Program Plan (10CFR50.55(a)(g)) . .......... ...:  : .. ............................. Li YES 0 NO 2.2.6 Fire Protection Program (10CFR50.48) ..................................... .............................................. Li YES , 3 NO 2.2.7 Independent Spent Fuel Storage Facility (10CFR72.48).. ....................................................... Li YES 0 NO 2.2.8 Another regulation: Standards For Protection Against Radiation (10 CFR 20 including ODCM), .................... YES [ NO Specific Exemptions (10 CFR 50.12) ............ ; .....  !...................................... Li YES [] NO ECCS Acceptance Criteria (10 CFR 50.46).. ................ ................. D YES 10 NO Environmental Protection (DBNPS only)............................................................................. [] YES Io NO Other - list the regulation(s): ......... . ...l YES

                                                                                                                                                                         ..              0. NO

F Ene..r, REGULATORY APPLICABILITY DETERMINATION No. 06-03884 NOP-LP-4003-01 Rev. 02 Page 2 of 2 Rev. Rv 00. 0 Initiating Activity No. ECP ECP 04-0294-00, C-EE-004.01-049R15-A02, UCN06-544U Rev. 00 El BVPS 1 El BVPS 2 I] DBNPS I] PNPP

3. CONCLUSION 3.1 Does 10CFR50.59 apply? ........................................ .. ... ... ..... .. .. ... . ... .. ... ... . ... . . . .. . . .. ... . .

                                                                                                                                                  .. YES [O NO 3.2 Does this activity require a change to the UFSAR? Change Request No: 06-544U                                                        ..... [Z YES El NO 3.3 Summarize the bases for responses: Include Keywords used to search documents.

Keywords: degraded voltage, 90, loss voltage, 59 These three activities are not specifically exempted under any of the categories listed in Section 1 above. They are not managerial or administrative changes. The changes implemented by ECP 04-0294-00 result in field setpoint changes that are built upon the allowable values in License Amendment 275, reviewed and approved by the NRC on 8.9.2006. The calculation addendum revises the Allowable Value for the Loss of Voltage Relays to be consistent with the conservative values in License Amendment 275. The USAR change revises the descriptions of the relays to reflect the descriptions in License Amendment 275. Section 2.1.2 Technical Specification, was marked Yes as these activities are related to the TS change being implemented by the LAR 03-0014. LAR 03-0014 has been approved and is License Amendment 275. Therefore, these activities are exempt from 10CFR 50.59 because the RC has reviewed and approved the Technical Specification change. Preparer (Print name)' Signature Date Murtha, Matthew J elc/ c/6 Reviewer (Print name) Signat Dae 2 Kendall, Joseph D I Z.O,

                                                                                                                                             /

Page I of 1

      ~~~~NOP-CC-2004-05 Rev.

FirstEner DESIGN 06 INTERFACE

SUMMARY

- DB                                                      DSRv Dagev 0f gy ~         ~         e 06                                                                                             ev Document/Activity Evaluated: Calculation C-EE-004.01-049, Addendum A02                                                                   Rev. 15 K~~      ~~~GASandPROCEDURES       INTEFACE Req'd  LSect.                             Topic                                                Prepare DIE and forward to:         -             DIE No.

El N/A Maintenance Programs & Procedures Maintenance El N/A Ops Programs & Procedures Operations Z[ N/A System Programs & Procedures Responsible Plant Engineer 01 0 [ N/A Engineering Assessment Board EAB Chairman 02 E] N/A Training Training (Information Only Copy) ESIGN INTEFA CES Potential Interface Evaluated using DIRC (NOP-CC-2004-02) Rev 05 El 1.0 ALARA Radiation Protection El 2.0 Fire Protection/Safe Shutdown Electrical/l&C Engineering Unit, DES El 3.0 Environmental Qualification Engineering Programs Unit, TSES [] 4.0 Human Factors Electrical/l&C Engineering Unit, DES El 5.0 Plant Security System Interface Electrical/l&C Engineering Unit, DES I Security Operations El 6.0 Seismic Interaction/Seismic Qualification Mechanical/Structural Engineering Unit, DES El 7.0 Pipe Rupture Interaction Engineering Analysis Unit, DES El 8.0 Internal Missile Hazards Engineering Analysis Unit, DES El 9.0 NSSS Design Basis Engineering Analysis Unit,,DES El 10.0 Containment Isolation Mechanical/Structural Engineering Unit, DES El 11.0 Materials Compatibility/Chemical Control Mechanical/Structural Engineering Unit, DES E] 12.0 Control Room Habitability Mechanical/Structural Engineering Unit, DES El 13.0 Mechanical Systems (13.1 - 13.20) Mechanical/Structural Engineering Unit, DES El 13.0 Mechanical Systems (13.21 - 13.26) Engineering Analysis Unit, DES El 14.0 Penetrations Mechanical/Structural Engineering Unit, DES El 15.0 Miscellaneous Structural Considerations Mechanical/Structural Engineering Unit, DES El 16.0 Heavy Loads Mechanical/Structural Engineering Unit, DES. E] 17.0 Electrical Systems Analysis Electrical/l&C Engineering Unit, DES El 18.0 Instrumentation and Controls Electrical/l&C Engineering Unit, DES El 19.0 Simulator (Hardware & Software) Training El [ 20.0 In-Service Testing (20.1 - 20.10) Engineering Programs Unit, TSES El 20.0 Repair/Replacement Program & ISI (20.11- Engineering Programs Unit/Rapid Response Engineering Unit, TSES 20.19) El 20.0 Snubber Program (20.20) Engineering Programs Unit, TSES Mechanical/Structural Engineering Unit, DES El 21.0 Piping and Pipe Supports Mechanical/Structural Engineering Unit, DES El 22.0 Reactor Core Operations - RE/Engineering Analysis Unit, DES El 23.0 Licensing Review Regulatory Compliance E] 24.0 LubricationNibration Monitoring Maintenance- PS El 25.0 Probabilistic Safety Assessment Engineering Analysis Unit, DES El 26.0 Piping & Equipment Mechanical/Structural Engineering Unit. DES El 27.0 Valve Programs Engineering Programs Unit, TSES [E 28.0 Plant Computers/Software Electrical/l&C Systems Engineering Unit, PEERS El 29.0 Maintenance Rule, 10CFR 50.65 Engineering Programs Unit, TSES El 30.0 Operations Impact Operations Services El 31.0 Maintenance Maintenance- ME,EL,IC,PS El 32.0 Chemistry Chemistry El 33.0 Training Training El 34.0 Testing Requirements Review Plant Engineering & Equipment Reliability El 35.0 Corrosion-Erosion Monitoring and Analysis Engineering Programs Unit, TSES El 36.0 RCS Integrated Leakage Reduction Program Engineering Programs Unit, TSES I 37.0 Boric Acid Corrosion Control Program Engineering Programs Unit, TSES El 38.0 Locked and Capped Valve Review Operations Services 0l 39.0 Dry Fuel Storage Review Operations- RE / Mechanical/Structural Engineering Unit, DES El 40.0 . Protective Coatings/Painting Mechanical/Structural Engineering Unit, DES El 41.0 Personal Safety Considerations Nuclear Training Services, Site Training Comments:

• Design-Elec/l&C is preparing Addendum ther einA rface is not required. Maintenance and OPS review is not required because the addendum does not affect any output documents. Supv. ,j iner The system en ineer will be provided with V interface review to yefy the PMs eferenced in the addendum.

Prepared by: J*nt N~44 *nd ' n) -- . Dat Reviewed by: (PrintName and Si*iAI-r-*----- . . Date B.M Waybright J~j TNflL.A\' (2.ýJkzA, ~ lil ~ f8'0 ~

Page 1 of ArstEney DESIGN INTERFACE EVALUATION NOP-CC-2004-07 Rev. 03 Document/Activity Rev. DIE No./Rev. Calculation C-EE-004.01-049, Addendum 02 00 01/00 To: Interfacing Organization (As identifiedon DIS) Contact System Engineer D.Duquette From: (Design Engineer) Mail Zone Phone DIE Response Date B.M.Waybright 3205 8498 8/29/06 Description of Change/Areas of Concern List DIRC Questions Engineering Assessment Board Review N/A IMPACT ON DESIGN AND LICENSING BASIS Aj~~o jý A4ý t Yv~J>

 "      Describe affect on current licensing basis for the system/structure/component (           .. inv(

_) ved.

• Describe affect of proposed change on existing design basis.
• Identify relevant design criteria and standards (including applicable revision/addenda).
• Identify potential failure mechanisms and failure consequences.
• Describe impact on operational configuration, system interactions, and any other pertinent considerations. Identify required actions.

INSTALLATION AND TESTING - ?,b CtfL_ "'W t fl 5h- trAU '.) L:-. m C- 7 t-

• Identify appropriate installation requirements and acceptance criteria for testing.

Iidentify any limitations such as open assumptions or engineering holds. Identify what is restrained and what is required to release the hold. IMPACT ON TRAINING - f0 1Mi~f-ATF NJ(tWjJ r'

• Does the change add, modify, orLd~.te equipment, components, systems, or processes that result in the need for personnel to acquire additional skills and knowledge? )qNo [] Yes If Yes, complete the Affected Documents section below. Identify Training as the Document Type, assign an Action Code, Responsible Organization and Tracking Number. NA all other fields.

COMMENTS/ADDITIONAL INPUT/ INFORMATION AFFECTED DOCUMENTS List new and/or existing documents requiring issue/update as a result of this activity (e.g., drawings, procedures, databases, lesson plans, and vendor manuals). List current revision/version of the document. Document Document Unit Rev; Version Action Responsible Tracking No.- Type _ Code* Organization P.0-s,*4 1,jt% NA, P #1'7X-&1L-1 -661 M04-5&C1" uction Compleuion Cuoe: 1 Document must be issued/effective at implementation of the activity prior to returning the SSC to service (Operational Acceptance). 2 Document must be issued/effective following issuance of the package, but prior to implementation. 3 Document must be issued/effective upon issuance of the package for implementation. 4 Document must be issued/effective following return of the SSC to service (Operational Acceptance) and prior to closeout of the activity. 5 Document needs to be changed as a result of the activity, but the change can be done when the responsible organization deems aoorovriate, A trackinq number is reguired for these actions. I COCUSO 0 I [] Interface Not Required (Provide Justification) Interface Provided (Indicate if Final Review required) El Final Review required ,,_._ Interface Evaluator (PrintName and S' n) . Date Ap r val (Print Name and,'r)() Daw 0 Comments need to be resolved Interface Evaluator Date El My comments/input have been properly incorporated and/or Interface Evaluator Date addressed.

DOCUMENT REVIEW ED 6864-2 fz zrt REVIEW CONDUCTED BY a - '*A ORGANIZATION INDIVIDUAL (PRINT NAME) SHEET . OF ,.. DBES Duquette A RESPONSE TO EACH COMMENT IS REQUESTED, PLEASE NO COMMENTS NO RESPONSE REQUESTED El RETURN THIS FORM WITH YOUR RESPONSE IN THE SPACE PROVIDED DOCUMENT TITLE OR NUMBER Calculation C-EE-004.0l-049 Addendum 02 COMMENTS RESPONSE DIE Input for System Engineer I - Impact of change on system - This addendum to the undervoltage relay calculation involves rounding the time delays and revising the calibration frequency of the 27X-6 relays to a refueling interval. There is no impact on the system. 2 - Change in system operation maintenance. Include all repetitive task additions/deletions. This calculation addendum allows the calibration frequency to go from yearly to a refueling interval. Existing PM revision forms DB-REV-06-0611 and 612 will be revised to reflect this frequency change. 3 - Impact on procedures/instructions under the responsibility of Plant Engineering resulting from this change. This calc addendum is beneath the level of detail in any procedures/instructions for the 4.16 UV relays. No changes are required. 4 - Test requirements and plant and/or system configuration required for testing. No testing or changes to system configuration is required for this calculation addendum.. 5 - Identify need for increased vendor oversight or enhanced procurement. This addendum to the calculation does not involve either vendor resources or the purchase of plant equipment.

        =)VIWESJATURE                          DAITE           RESOLUTION CONCURRENCE SIGNATURE] DATE,

Page 1 of/ d49 FirstEner y DESIGN INTERFACE EVALUATION NOP-CC-2004-07 Rev. 03 Document/Activity Rev. DIE No./Rev. Calculation C-EE-004.01-049, Addendum 02 00 X1*/00 To: Interfacing Organization (As identified on DIS) Contact 02. ____________________A. Migas ~~)/ From: (Design Engineer) Mail Zone Phone DIE Response Date B.M.Waybright 3205 8498 Description of ChangelAreas of Concern List DIRC Questions Engineering Assessment Board Review N/A IMPACT ON DESIGN AND LICENSING BASIS " Describe affect on current licensing basis for the system/structure/component (SSC) involved. .1/I

• Describe affect of proposed change on existing design basis.

" Identify relevant design criteria and standards (including applicable revision/addenda).'

• Identify potential failure mechanisms and failure consequences.
• Describe impact on operational configuration, system interactions, and any other pertinent consi rations. Identify required actions.

INSTALLATION AND TESTING

• Identify appropriate installation requirements and acceptance criteria for testing.
• Identify any limitations such as open assumptions or engineering holds. Identify what is restrainE d and what is required to release the hold.

IMPACT ON TRAINING

• Does the change add, modify, or delete equipment, components, systems, or processes that res it in the need for personnel to acquire additional skills and knowledge? [] No Dl Yes If Yes, complete the Affected Documents section below. Identify Training as the Document Type, assign an Action Code, Responsible Organization and Tracking Number. NA all other fields.

COMMENTSIADDITIONAL INPUT/ INFORMATION AFFECTED DOCUMENTS List new and/or existing documents requiring issue/update as a result of this activity (e.g., drawings, procedures, databases, lesson plans, and vendor manuals). List current revision/version of the document. Document Document Unit Rev. Version Action Responsible Tracking No.** Type Code* Organization

• Action Completion Code:

1 Document must be issued/effective at implementation of the activity prior to returning the SSC to service (Operational Acceptance). 2 Document must be issued/effective following issuance of the package, but prior to implementation. 3 Document must be issued/effective upon issuance of the package for implementation. 4 Document must be issued/effective following return of the SSC to service (Operational Acceptance) and prior to closeout of the activity. 5 Document needs to be changed as a result of the activity, but the change can be done when the responsible organization deems appropriate. ** A tracking number is required for these actions. CONCLUSO N El Interface Not Required (Provide Justification) A Interface Provided (Indicate if Final Review required) El Final Review required Interface Evaluator (Printa d Sign) Date Approval (Prnta ant.Sc) Date 1181J6 Approvl(Pita FIALREIW ...-

                                                                        . Interface Evaluator                                        .VDate El   Comments need to be resolved i

El My comments/input have been properly incorporated and/or Interface Evaluator Date addressed.

 -ýg E_-45,     "REV('EIAJ "PROV(015               PGA "b'B8P-,,ve.0- 000:2-*                 /        ,,,.

Page I of I FirstEnerjy DESIGN VERIFICATION RECORD NOP-CC-2001-01 Rev. 00 SECTION 1: TO BE COMPLETED BY DESIGN ORIGINATOR DOCUMENT(S)/ACTIVITY TO BE VERIFIED: C-EE-004.01-049 Rev 15 Addendum A02 [ SAFETY RELATED [] AUGMENTED QUALITY El NONSAFETY RELATED SUPPORTING/REFERENCE DOCUMENTS C-EE-004.01-049, Rev. 15 License Amendment 275 ECP 04-0294-00 DESIGN ORIGIN R: t and n Na DATE B.M.Waybright SECTION I1: TO BE COMPLETED BY V RIFIER VERIFICATION METHOD (Check one) ' DESIGN REVIEW (Complete Design El ALTERNATE CALCULATION El QUALIFICATION TESTING RJew Checklist or CalculationReview Checklist) JUSTIFICATION FOR SUPERVISOR PERFORMING VERIFICATION: N/A APPROVAL: (Print and Sign Name) DATE N/A EXTENT OF VERIFICATION: Reference calculation review checklist which addresses the scope of A02 of C-EE-004.01-049, Rev. 15. COMMENTS, ERRORS OR DEFICIENCIES IDENTIFIED? El YES NO RESOLUTION: (ForAlternate Calculation or Qualification Testing only). N/A RESOLVED BY: (Printand Sign Name) DATE VERIFIER: (Print ad,*S NDAT DATE , J.R.Chowdhary ar' APPROVED BY: (F nt and"'Sign Natd 1 DATE

                                               -'-'            -   /-    -  C

Page I of 4 FIrstEnje CALCULATION REVIEW CHECKLIST CALCULATION NO. C-EE-004.01-049 REV. 15 NOP-CC-2001-04 Rev. 03 ADDENDUM NO. A02 UNIT DB QUESTION INAI Yes INoI COMMENTS RESOLUTION GENERAL X The objectives and purpose are 1 Does the stated objective/purpose clearly describe why the calculation is being clearly described in the performed? "Objective or Purpose of Addendum" section of the addendum. The scope of the __addendum is also clearly stated.

2. Are design input / output documents and references listed and clearly identified in the X Where appropriate, applicable document index, including edition and addenda, where applicable? codes, standards, design inputs, and references are defined in the calculation. The Relay Setting Manual will revised by ECP 04-0294-00. DBE# 04-00074 is listed as DIN 88.

3. Were verbal inputs from third parties properly documented? X N/A - There are no applicable verbal inputs from third parties that apply.

4. Are design input parameters, such as physical and geometric characteristic and X N/A- This addendum rounds regulatory or code and standard requirements, accurately taken from the design input the DVR time delay to correctly documents and correctly incorporated, including tolerances and units? reflect the changes evaluated in ECP 04-0294-00.

5. Are the design inputs relevant, current, consistent with design/licensing bases and X The rounding performed by this directly applicable to the purpose of the calculation, including appropriate tolerances addendum is conservative in and ranges/modes of operation? nature and correctly reflects amendment 275 to LAR 03-0014. DBE# 04-00074 documents the vendor recommendation / justification for changing the required calibration frequency of the 27X-6/Cl and 27X-6/Dl relays. The drift value is still considered to

                                                                                      -. _                be conservative in nature.

6. Are all design inputs retrievable? If not, have they been added as attachments? X LAR 03-0014 amendment 275 and DBE# 04-00074 are I retrievable (DIN 88).

7. Are preliminary or conceptual inputs clearly identified for later confirmation as open X There are no preliminary or assumptions? conceptual inputs identified by this addendum.

8. Where applicable, were construction and operating considerations included as input X There are no applicable information? construction or operating considerations affected by rounding the time delay.

9. Were design input / output documents properly updated to reference this calculation? X The Relay Setting Manual will be revised by ECP 04-0294-00.

Page 2 of 4 FirstEne CALCULATION REVIEW CHECKLIST CALCULATION NO C-EE-0040l-049 REV. 15 NOP-CC-2001-04 Rev. 03 ADDENDUM NO. A02 UNIT DB QUESTION INA IYes NoI COMMENTS RESOLUTION ASSUMPTIONS X There are no assumptions

10. Have the assumptions necessary to perform the analysis been clearly identified and identified by this addendum.

adequately described? I

11. Are all assumptions for the calculation reasonable and consistent with design/licensing X There are no assumptions bases? identified by this addendum.

12. Have all open assumptions needing later confirmation been clearly identified on the X There are no assumptions Calculation cover sheet, including when the open assumption needs to be closed? identified by this addendum.

13. Has a Condition Report been issued for open assumptions? X There are no assumptions identified by this addendum. ._

14. Have engineering judgments been clearly identified? X There are no eng. judgments identified by this addendum.

15. Are engineering judgments reasonable and adequately documented? X There are no eng. judgments

__identified by this addendum.

16. Is suitable justification provided for all assumptions/engineering judgements (except X There are no assumptions / eng.

those based upon recognized engineering practice, physical constants or elementary judgments identified by this scientific principles)? addendum. METHOD OF ANALYSIS X This addendum uses the

17. Is the method used appropriate considering the purpose and type of calculation? appropriate methodology to conservatively round the DVR time delay upper and lower limits so that they are consistent with LAR 03-0014.

18. Is the method in accordance with applicable codes, standards, and design/licensing X There are no applicable codes bases? or standards identified by this addendum. The values for DVR time delay are being rounded to be consistent with the design /

licensing basis (License amendment 275, LAR 03-0014). DBE# 04-00074 documents the justification for changing the required calibration frequency of the 27X-6/C1 and 27X-6/D1 relays (vendor recommendation). IDENTIFICATION OF COMPUTER CODES (Ref: NOP-SS-1001) X The computer code "C" has

19. Have the versions of the computer codes emp5loyed in the design analysis been been correctly identified for certified for this application? Microsoft Word (administrative).

20. Are codes properly identified along with source (vendor, organization, etc.)? X Yes

21. Is the code applicable for the analysis being performed? X Yes

22. Is the computer program(s) being used listed on the FENOC Usable Software List for X Yes the site?

Page 3 of 4 FirstEnergy CALCULATION REVIEW CHECKLIST CALCULATION NO. C-EE-004.01-049 REV. 15 NOP-CC-2001-04 Rev. 03 ADDENDUM NO. A02 QUESTIONWe_7s UNIT DB QUESTION I NA YesNoa COMMENTS REsoLUTION

23. Does the computer model, that has been created, adequately reflect actual (or to be X Microsoft Word was utilized for modified) plant conditions (e.g., dimensional accuracy, type of model/code options administrative purposes only.

used, time steps, etc.)?

24. Did the computer output generate any ERROR or WARNING Messages that could X Microsoft Word was utilized for invalidate the results? administrative purposes.

25. Is the computer output reasonable when compared to inputs and what was expected? X Microsoft Word was utilized for administrative purposes only.

COMPUTATIONS X The conservative change to the

26. Are the equations used consistent with recognized engineering practice and calculation is in accordance with design/licensing bases? normal engineering practices.

No new equations were derived.

27. Is there a reasonable justification provided for the uses of any equations not in X No new equations were derived.

common use?

28. Were the mathematical operations performed properly and the results accurate? X The results are consistent with LAR 03-0014.

29. Have adjustment factors, uncertainties, empirical correlations, etc., used in the X The rounding was performed analysis been correctly applied? conservatively and remained within acceptable limits so as not to inadvertently impact the results or conclusions to the calculation.

30. Is the result presented with proper units and tolerance? X Yes - Results are provided in seconds.

31. Has proper consideration been given to results.that may be overly sensitive to very X No overly sensitive devices were small changes in input? identified.

CONCLUSIONS X The results correlate to LAR 03-

32. Is the magnitude of the result reasonable and expected when compared to inputs? 0014.

33. Is there a reasonable justification provided for deviations from the acceptance criteria? X No deviations from the acceptance criteria were identified.

34. Are stated conclusions justifiable based on the calculation results? X No new conclusions were derived from this addendum.

35. Are all pages sequentially numbered and marked with a valid calculation and revision X number?

36. Is all information legible and reproducible? X

37. Is the calculation presentation complete and understandable without any need to refer X back to the Originator for clarification or explanations?

38. Is calculation format presented in a logical and orderly manner, in conformance with X the standard calculation content of NOP-CC-3002 (Attachment 1)?

39. Have all changes in the documentation been initialed (or signed) and dated by the X author of the change and all required reviewers?

DESIGN/LICENSING X Yes - All results are consistent

40. Have all calculation results stayed within existing design/licensing basis parameters? . with amendment 275 (LAR 03-0014).

Page 4 of 4 FirstEnergy CALCULATION REVIEW CHECKLIST CALCULATION NO. C-EE-004.01-049 REV. 15 NOP-CC-2001-04 Rev. 03 ADDENDUM NO. A02

                                                     ,__UNIT                                                                                     DB QUESTION                                             NA   Yes    No  T           COMMENTS                      RESOLUTION

41. If the response to Question 40 is NO, has Licensing been notified as appropriate? (i.e. X UFSAR or Tech Spec Change Request has been initiated).

-42. Is the direction of trends reasonable? X

43. Has the calculation Preparer used all applicable design information/requirements X LAR 03-0014 and ECP 04-0294-provided? 00 were used to prepare this addendum.

44. Did the calculation Preparer determine if the calculation was referenced in design - No changes are required.

basis documents and/or databases?

45. Did the Preparer determine if the calculation was used as a reference in the UFSAR? X No changes are required.

46. If the calculation is used as a reference in the UFSAR, is a change to the UFSAR x No changes are required.

required or an update to the UFSAR Validation Database, if applicable, required?

47. If the answer to Question 46 is YES, have the appropriate documents been initiated? X No changes are required.

48. Has the applicability of 10CFR50.59 to this calculation been considered and X RAD 06-03884 has been created documented? to evaluate this change. A 50.59 SCREEN will not be created to evaluate this change. The function of the SCREEN has been performed under Amendment 275 (LAR 03-0014).

ACCEPTABLE x

49. Does the calculation meet its purpose/objective?

50. Is the calculation acceptable for use? _

51. What checking method was used to review the calculation? Check all that apply.

spot check for math X

      *complete check for math                                                                       X
      *comparison with tests                                                                    X
      *check by alternate method                                                                X
      *comparison with previous calculation                                                    X Review Summary:

No additional comments. Technical Re int d SignN e) Date Owner's Acceptance Review (Required for calcua/tionspreparedbya vendor) J.R. Cho" a/ 8/28/06 Reviewer (Print and Sign Name) Date Design V fficati'n (Printj/aV Si n N e) Date J.R.Cho-. ha , / 8/28/06 Approver (Print and Sign Name) Date

NRC ITS Tracking Page 1 of 2 Return to View Menu PritDocum~ent RAI Screening Required: Yes Status: Closed This Document will be approved by: Gerald Regulatory Basis must be included in Comments Waig; Tim Kobetz section of this Form This -document has been reviewed and Yes information in this question contains NO SUNSI sensitive material (the checkbox to the right must be selected before this question can be submitted) NRC ITS TRACKING NRC Reviewer ID 200712260939 Conference Call Requested? No S ..egory - Beyond Scope Issue ITS.Section: TB POC: JFD.Number: Page.Number(s): ITS 3.3 Aron Lewin None. Information ITS Number: OSI: . DOC.Number: Bases.JFD..Numb.er-. 3.3.8 None None None NRC OSI#50 Discuss how adding statements in the ITS Bases, for Allowable Value setpoint methodology associated with the Loss of Voltage Functional Unit, effects physical application and reporting requirements of the LCO, and, in addition, still gives assurance that the limiting safety system setting is chosen so that automatic protective action will correct the abnormal situation before a safety limit is exceeded in accordance with 10 CFR 50.36(d)(1)(ii)(A). Backgorund The Bases for CTS 3/4.3.1 and 3/4.3.2 (page 396 thru 400 of 490 in the CTS) do not seem to discuss Allowable Value setpoint methodology associated with the Loss of Voltage Functional Unit (CTS Unit 4.c). Co.mment The ITS Bases (page 301of 636) has a discussion on Loss of Voltage LOPS Allowable Value setpoint methodology (insert 1B) not found in the CTS or the STS. The STS Bases for LCO 3.3.8 (NUREG-1430) does not have the ITS Bases discussion on Allowable Value setpoint methodology for the Loss of Voltage Functional Unit. 10 CFR 50.36(d)(1)(ii)(A) states that "limiting safety system settings for nuclear reactors are settings for automatic protective devices related to those variables having significant safety functions. Where a limiting safety system setting is specified for a variable on which a safety limit has been placed, the setting must be so chosen that automatic protective action will correct the abnormal situation before a safety limit is exceeded." Issue Date 12/26/2007 II httpl//www.excelservices.com/exceldbs/itstrack davisbesse.nsfll fddcea 1Od3bdbb585256e.:. 7/18/2008

NRC ITS Tracking Page 2 of 2 Close Date 03/24/2008 Logged in User: Anonymous

'ResDonses Licensee Response by Bryan        The statements added to the Bases regarding Loss of Voltage Kays on 03/03/2008                LOPS are consistent with the information provided to the NRC by Davis-Besse and from the NRC to Davis-Besse associated with License Amendment 275. See Serials 3009 (ADAMS ML041310374), 3100 (ADAMS ML050210170), 3186 (ADAMS ML052870376), 3193 (ADAMS ML053120383), and 3265 (ADAMS ML061520316), the NRC Safety Evaluation for Amendment 275 (ADAMS ML060400472), and calculation C-EE-004.01-049 (attached). The changes make the Bases applicable to Davis-Besse and align with the current licensing basis.

NRC Response by Aron Lewin No further questions at this time. on 03/24/2008qusinathstme Date Created: 12/26/2007 09:39 AM by Aron Lewin Last Modified: 03/24/2008 10:09 AM http://www.excelservices.com/exceldbs/itstrack davisbesse.nsf/1 fddceal Od3bdbb585256e... 7/18/2008

CALCULATION ADDENDUM NOP-CC-3002-02 Rev. 02 INITIATING DOCUMENT(S) CALCULATION NO. CALCULATION REV. ADDENDUM NO. ECP 04-0294-00, Rev. 00 C-EE-004.01-049 15 A02 TITLE/

SUBJECT:

(MUST MATCH ORIGINAL CALCULATION TITLE (SUBJECT) 4.16 KV BUS C1/D1 DEGRADED VOLTAGE, LOSS OF VOLTAGE, AND 27X-6 RELAY SETPOINT [BV1 OBV2 DB El PY Classification [ Tier 1 Calculation [] Safety-Related/Augmented Quality El Nonsafety-Related Open Assumptions? L1 Yes Z No If Yes, Enter CR Tracking Number Computer Program(S) Program Name Version / Revision Category Status Description Microsoft Word 2003 C Active Word Processor I ORIGINATOR/DATIt' ,* REIW /D'1't':I;jDATF! E I I' APPROVERJDATE i If".', B. M. Waybright Z J'R'Chowdh* Z / /' l%._.,.. OBJECTIVE OR PURPOSE. OF ADDENDUM: This addendum is to revise the Degraded Voltage Relay time delay, upper and lower Allowable Values from 7.94 and 6:37 seconds to 7.9 and 6.4 seconds, respectively. The calculated values are 7.94 and 6.37 seconds. These values were not conservatively rounded to reflect the allowable values submitted in LAR 03-0014. The LAR has been approved and is License Amendment 275 (Log 6447). Based on this, the values should be updated to be consistent with Amendment 275. The required calibration frequency of the 27X-61C1 and 27X-6/D1 is also changing. Rev. 15 of the calculation assumed the calibration frequency was being initiated by CR 04-01239, Corrective Action 3. This was proven to be incorrect per a System Engineer in ECP 04-0294-00 (DIE 03c/0). The calibration frequency is being changed as a result of industry experience and vendor recommendations. The calibration frequency is now being initiated by two PMs referenced in. this addendum. SCOPE OF ADDENDUM: The scope of the addendum is to revise the Degraded Voltage Relay time delay Allowable Values to be consistent with License Amendment 275. In addition, the calibration frequency for the 27X-6 relays has been re-adjusted and correctly initiated. LIST NEW DOCUMENTS TO BE ADDED TO THE DOCUMENT INDEX (DIN):

          ,jA/j

SUMMARY

OF RESULTS/CONCLUSIONS OF ADDENDUM: There is no impact on the conclusion. The Allowable Value was revised to be consistent with Amendment 275 (LAR 03-0014). LIMITATIONS OR RESTRICTIONS CREATED BY ADDENDUM: There are no limitations or restrictions because the LAR has been approved. IMPACT OF ADDENDUM ON OUTPUT DOCUMENTS: The impact on the allowable value will be consistent with License Amendment 275. The Amendment will provide procedure and Technical Specification change implementation. ECP 04-0294-00 will implement the Relay Setting Manual changes. Based on this, there is no impact on the output documents. DESCRIBE WHERE THE ADDENDUM WILL BE EVALUATED FOR 10CFR50.59 APPLICABILITY: RAD 06-03884-00 LIST SUPPORTING DOCUMENTS: (Include total number of pages)

                                                      ,,-a Regulatory Applicability Determination 06-03884 (2 page(s))

CALCULATION ADDENDUM NOP-CC-3002-02 Rev. 02 .I0 2 "7 INITIATING DOCUMEINTI (' CA II ATIOIN NCALCIUI N'J I ATION RF: AflDN'FlM D NOI 00*v ECP 04-0294-00, Rev. -j IC-EE-004.01-049 15 A02 TITLE/

SUBJECT:

(MUST MATCH ORIGINAL CALCULATION TITLE (SUBJECT) 4.16 KV BUS C1/D1 DEGRADED VOLTAGE, LOSS OF VOLTAGE, AND 27X-6 RELAY SETPOINT Design Interface Summary (1 page) DIE 01 (System Engineer) (2 pages) DIE 02 (Engineering Assessment Board) (/ page) Design Verification Record (1 page) Calculation Review Checklist (4 pages). LIST ATTACHMENTS: (Include total number of pages) Revised Calculation page iii (1 page) Revised Calculation page ix (1 page) Revised Calculation page 21 (1 page) Revised Calculation page 30 (1 page) Revised Calculation page 33 (1 page)

Page iii CALCULATION NOP-CC-3002-01 Rev. 01 A 0,ZoPm. 34 7 INITIATING DOCUMEN TI*\ '"31 CA IIATIONN NO..

                            -'I

[ I VENDOR CALC

SUMMARY

LAR 03-0014 C-EE-004.'01-0419 TITLE/

SUBJECT:

4.16 kV Bus C1/D1 Degraded Voltage, Loss of Voltage, and 27X-6 Relay Setpoints OBJECTIVE OR PURPOSE: The bus Degraded Voltage Relays (DVR), Loss of Voltage Relays (LVR), and 27X-6 relays are designed to separate the safety related onsite electrical distribution system from the non-safety related onsite electrical system and the offsite power system after a predetermined period of unacceptably low voltage. The purpose of this calculation is to determine Dropout, Pickup and Time Delay setpoints for the relays. The setpoints are selected to ensure that the voltage at 4.16KV Essential Buses C1 and DI will not drop below the minimum value at which all safety related loads will have sufficient voltage to perform their intended safety function. The setpoints also ensure the busses are not inappropriately disconnected from the preferred offsite source. This calculation establishes Allowable Values and Setpoints for the Dropout, Pickup and Time Delay settings of the relays. This calculation also establishes the Analytical Limits for the Upper Time Delays. SCOPE OF CALCULATION/REVISION: Rev. 15 is to establish the Analytical Limits, Allowable Values and Setpoints for the upper and lower ranges of the DVR, LVR and 27X-6 relays in support of LAR 03-0014. This revision also incorporates the appropriate information from Calculations C-EE-004.01-051 and C-EE-004.01-057 to allow for one complete and concise location for all relays associated with EDG startup.

SUMMARY

OF RESULTS/CONCLUSIONS: Voltage Sensor (DVR) Value Relay Value Degraded Voltage Relay, Pickup Analytical Limit 3786 Volts _*108.17 V Degraded Voltage Relay, Pickup Allowable Value' _*3771 Volts _<107.74 V Degraded Voltage Relay, Pickup Setpoint 3759 Volts Max 107.40 V Max Degraded Voltage Relay, Dropout Trip Setpoint 3734 + 7 Volts 106.69 + 0.2 V Degraded Voltage Relay, Dropout Allowable Value > 3712 Volts 1l06.06V Degraded Voltage Relay, Dropout Analytical Limit 3700 Volts Ž105.71 V Time Delay (DVR) Degraded Voltage Relay TD, Upper Analytical Limit 8.10 seconds Degraded Voltage Relay TD, Upper Allowable Value _ 7.9 seconds Degraded Voltage Relay TD, Nominal Setting 7.5 + 0.2 seconds 7.5 +/- 0.2 sec Degraded Voltage Relay TD, Lower Allowable Value >_6.4 seconds Degraded Voltage Relay TD, Lower Analytical Limit 6.21 seconds

                                                                                     ...Page ix CALCULATION NOP-CC-3002-01 Rev. 01                          A 2. ?w. e 4- 7 INITIATING DOCUMENT (S)                               CALCULATION NO.       []VENDOR CALC 

SUMMARY

LAR 03-0014 C-EE-004.01-049 TITLE/

SUBJECT:

4.16 kV Bus C1/D1 Degraded Voltage, Loss of Voltage, and 27X-6 Relay Setpoints

90. E-64B, SH. A /EDG I-1 Brk AC101 Control Rev. 8.

91. E-64B, Sh. 2A / EDG 1-2 Bkr AD 101 Control, Rev. I I E ]E ]

92. E-64B, Sh. IE / EDG 1-1 Misc Aux Relays,' Rev. 16 [] El

93. E-64B, Sh. 2E / EDG 1-2 Misc Aux Relays, Rev. 15 [ D D

94. E-64B, Sh. 17 / EDG SFAS Sequencer Start/Stop Rev. 5 [ r-D

95. E-64B, Sh. 18 / EDG SFAS Sequencer Start/Stop Rev. 3 0 El Aux Relays

96. Specification No. 1250 1-E-5Q, Technical Rev. 3 Z [] El Specification for Operational Phase for 4,160 and 13,800 Volt Metal-Clad Switchgear

97. Framatome Document 86-5006232-01, DB-1 LOCA Rev. 01 El ] El Summary Report, (EXT-02-00822)

98. Framatome Document 32-1171604-00, LPI/HPI Rev. 00 El'I E LBLOCA Assumptions (Film 4388, Frame 2096)

99. MPR Report 2594 (ACT# 04-0026), D-B EDG Rev. I, 2/5/2004 El [A El Transient Response Evaluation 100. Condition Report 04-01239 N/A E. 0 El 101. Work Order 03-000803-04 5/9/03 El [9 0 102. DB REV-06-0611 N/A H El []

103. DB REV-06-0612 N/A ZEIIW 104. Log 6447 (License Amendment 275) August 9, 2006 El El

F.rstEnergy Page 21 CALCULATION COMPUTATION NOP-CC-3002-01 Rev. 01 PZ-. S-b 7 CALCULATION NO.: EVIO C-EE-004.01-049 15 TITLE (

SUBJECT:

4.16 kV Bus C1/D1 Degraded Voltage, Loss of Voltage, and 27X-6 Relay Setpoints Per DINs 45 and 46, the tolerance is + 0.2 seconds. The use of 0.2 seconds is well below the 10% accuracy. The higher of the Accuracy and Calibration Tolerance will be included in the final calculated value. In this case, the Accuracy is higher. 4.6.5 Temperature Effect Per vendor documentation (DIN 58) the devices were tested for temperature variations. The values were a worst case from low temperature (-25 degrees C) to a high value (75 degrees C) was 2%. This 2% value is a conservative value since the temperature ranges for these devices does not span 100 degrees C (212 degrees F). Temp Eff = 2% x 8.10 second

                         = 0.162 seconds 4.6.6    DVR Time Delay Allowable Value (Upper)

The Allowable Value is based on those uncertainties that are not "tested" based on the definition in ISA-67.04.02 - 2000 (DIN 32). The only value that is not "tested" is the Temperature Effect. This is included between the Analytical Limit and the Allowable Valueas it is not a significant contributor to overall uncertainty. Per Appendix I of DIN 32, this value should be between the, Analytical Limit and the Allowable Value. AVTU = AL - Temp Eff

                         = 8.10- 0.162
                         = 7.94 seconds Margin was added to decrease time to < 7.9 Seconds
                         < 7.9 seconds 4.6.7    DVR Time Delay Allowable Value (Lower)

AVTL = AL + Temp Eff

                         = 6.21 + 0.162
                         = 6.37 seconds Margin was added to increase time to > 6.4 Seconds
                         > 6.4 seconds 4.6.8 4.6.9    DVR Time Delay Setpoint The Time Delay Setpoint is derived from the combination of the given AV and the total of all channel uncertainties.

TSP (Upper) = AL - SRSS (M&TE, Accuracy, Drift, Temp Eff)

ArstEnergy Page 30 CALCULATION COMPUTATION NOP-CC-3002-01 Rev. 01 7 CALCULATION NO.: REVISIOI C-EE-004.01-049 15 TITLE I

SUBJECT:

4.16 kV Bus CIIDI Degraded Voltage, Loss of Voltage, and 27X-6 Relay Setpoints 4.9.5 Power Supply Effects Not applicable for these relays, since accuracy of + 2% of setpoint is over the entire operating range of temperature and voltage (See 4.9.4 above). 4.9.6 Temperature Effects, Normal These timers are located in Rooms 323 (Bus Cl) and 325 (Bus DI) in switchgear cubicles AC101 and AD101. These relays are located in a mild environment during both normal operation and accident conditions. The expected range of operating temperatures is 60'F (15.5°C) to 104'F (40'C) Ref: USAR Section 9.4.2.1). For conservatism, the maximum temperature of 131'F (55°C) will be used, with a minimum temperature of 32°F (0°C). (Ref: C-ME-30.01-008 - According to this calculation Rooms 323 and 325 will have temperature of 120.01°F (say 120'F) during the loss of normal ventilation and with a AT between room and the cabinet (that is, switchgear cubicle) of 10.97F (say 1 VF). Therefore the cabinet will be at 131'F during the loss of normal ventilation). This is within the stated accuracy (See 4.9.4 above). 4.9.7 Vibration Effects These timers are located in Rooms 323 (Bus Cl) and 325 (Bus D1) in switchgear cubicles AC 101 and AD101. There is no in-service vibration involved for these relays. Therefore, vibration effects are not applicable to these relays. 4.9.8 Analog to Digital Conversion As these are solid state time delay relays and having no analog to digital conversion of the output. Therefore, there is no analog to digital conversion effect. 4.9.9 Digital to Analog Conversion As these are solid state time delay relays and having no digital to analog conversion of the output. Therefore, there is no digital to analog conversion effect. 4.9.10 Drift Drift is assumed to be equivalent to accuracy (Assumption 2.2). This requires a calibration on the frequency of a refueling outage frequency (18-24) months (DIN 88, and 62 (tab 78)). This calibration frequency is being initiated by DB-REV-06-0611 and DB-REV-06-0612 (DIN 102,103). Drift = 0.012 seconds

FirstEnery Page 33 CALCULATION COMPUTATION NOP-CC-3002-01 Rev. 01 A)". Po,ýj. 7 Z CALCULATION NO.: REVISION: C-EE-004,01-049 15 TITLE /

SUBJECT:

4.16 kV Bus Ci/D1 Degraded Voltage, Loss of Voltage, and 27X-6 Relay Setpoints 5.0 RESULTS The results are presented below in order of highest to lowest: Voltage Sensor. Value Relay Value Degraded Voltage Relay, Pickup Analytical Limit 3786 Volts *108.17 V Degraded Voltage Relay, Pickup Allowable Value

• 3771 Volts *107.74 V Degraded Voltage Relay, Pickup Setpoint 3759 Volts Max 107.40 V Max Degraded Voltage Relay, Dropout Trip Setpoint 3734 + 7 Volts 106.69 + 0.2 V Degraded Voltage Relay, Dropout Allowable Value- > 3712 Volts > 106.06V Degraded Voltage Relay, Dropout Analytical Limit 3700 Volts _ 105.71 V Time Delay Degraded Voltage Relay TD, Upper Analytical Limit 8.10 seconds Degraded Voltage Relay TD, Upper Allowable Value _<7.9 seconds Degraded Voltage Relay TD, Nominal Setting 7.5 + 0.2 seconds 7.5 +/-0.2 sec Degraded Voltage Relay TD, Lower Allowable Value _Ž6.4 seconds Degraded Voltage Relay TD, Lower Analytical Limit' 6.21 seconds Voltage Sensor Value Relay Value Loss of Voltage Relay, Pickup Analytical Limit 2500 Volts 71.43 V Loss of Voltage Relay, Pickup Allowable Value *2492 Volts
• 71.20 V Loss of Voltage Relay, Pickup Setpoint 2466 Volts Max 70.46 V Max Loss of Voltage Relay, Dropout Trip Setpoint 2429 + 7 Volts 69.40 + 0.2 .V Loss of Voltage Relay, Dropout Allowable Value Ž 20 71 Volts >59.17V Loss of Voltage Relay, Dropout Analytical Limit N/A N/A Time Delay Loss of Voltage Relay TD, Upper Analytical Limit _ 0.6 seconds Loss of Voltage'Relay TD, Upper Allowable Value _ 0.58 seconds Loss of Voltage Relay TD, Nominal Setting 0.5 + 0.05 seconds 0.5 +/- 0.05 sec

No. 06.03884 REGULATORY APPLICABILITY DETERMINATION Rev. 00 NOP-LP-4003-01 Rev. 02 Page 1 of 2 Initiating Activity No. Rev. 00 ECP ECP 04-0294-00, C-EE-004.0"-049R15-A02, UCN06-544U El BVPS 1 El BVPS 2 [] DBNPS LI PNPP

Title:

4.16kV Bus C1/D1 Degraded Voltage, Loss of Voltage, and 27X-6 Relay Setpoint Brief description of activity (what is being changed and why): The Engineering Change Package revises the Degraded and Loss of Voltage Relay allowable values and field setpoints as a result of approved License Amendment 275 (Log 6447). The ECP revises the Relay Setting Manual, design drawings, and the System Description. The allowable values and field setpoints are based on the calculation C-EE-004.01-049, Rev. 15. The calculated values required a License Amendment which has been approved by the NRC (Amendment 275, Log 6447). Calculation C-EE-004.01-049, Rev. 15, A02 revises the Degraded Voltage Relay (DVR) time delay allowable value. The calculated values were 7.94 and 6.37 seconds for the high and low values. These values are now rounded to 7.9 and 6.4 in the calculation. This change brings the calculation into agreement with the License Amendment. USAR Change Notice 06-544U revises the descriptions of the 90% and 59% under voltage relays in sections 8.3.1.1, 8.3.1.1.3, 8.3.1.1.4.1. Per License Amendment 275 (Log 6447), the relays are now described as the Degraded Voltage Relays and Loss of Voltage Relays, respectively.

1. EXEMPTIONS Is the scope of the entire activity exempt from the 10CFR50.59 process because it is limited to:

1.1 Managerial or adm inistrative changes ................................................................................................ ELYES ~NO 1.2 UFSAR changes (or equivalent information) excluded from the requirement to perform a 10CFR50.59 Screen and Evaluation by NEI 96-07 or NEI 98-03? .................................................... El YES ~NO 1.3 Maintenance activities and temporary alterations in support of maintenance planned for 90 days or less while at power ........................... ................................................................................ [D YES [] NO 1.4 Changes evaluated under another program that included a 10CFR50.59 Screen ................................................................................................................................................ YES NO

2. OTHER REGULATIONS 2.1 Does the activity require a license amendment?

2 .1.1 O perating License .................................... ............................................................................... El YE S [] NO 2.1.2 Technical Specifications ........................................................................................................... W Y ES LINO 2.1.3 Environmental Protection Plan (BVPS and PNPP only) .......................................................... L YES rNO 2.2 Is the activity or any portion of the activity governed by one or more of the following regulations: 2.2.1 Quality Assurance Program (10CFR50.54(a)) ................................... .l YES 0NO 2.2.2 Security Plans (10CFR50.54(p)) ............................................................................................. [3 YES [ NO 2.2.3 Emergency Plan (10CFR50.54(q)) .......................................................................................... 30 YES [NO 2.2.4 IST Program Plan (10CFR50.55(a)(f)) ........ ................................ .l YES [] NO 2.2.5 ISI Program Plan (10CFR50.55(a)(g)) ..................................................................................... LI YES [21 NO 2.2.6 Fire Protection Program (10CFR50.48) ................................................................................... LI YES SNO 2.2.7 Independent Spent Fuel Storage Facility (IOCFR72.48) ......................................................... E YES 0NO 2.2.8 Another regulation: Standards For Protection Against Radiation (10 CFR 20 including ODCM) ........................... _] YES [NO Specific Exemptions (10 CFR 50.12) ............. :......................................................................... LI YES WNO ECCS Acceptance Criteria (10 CFR 50.46) ............................................................................ L YES J] NO Environmental Protection (DBNPS only) ........................................... [3 YES 0NO Other - list the regulation(s): ........................................... El YES [ NO

Frstne.,rg, REGULATORY APPLICABILITY DETERMINATION No. 06-03884 Page 2 of 2Re.0 Rev. 00 NOP-LP-4003-01 Rev. 02 Initiating Activity No. ECP ECP 04-0294-00, C-EE-004.01-049R15-A02, UCN06-544U Rev. 00 El BVPS I Li BVPS 2 2] DBNPS El PNPP

3. CONCLUSION 3 1 Does 10CFR50.59 apply? ................................................................................................................ El YES [0 NO 3.2 Does this activity require a change to the UFSAR? Change Request No: 06-544U ... YES El NO 3.3 Summarize the bases for responses: Include Keywords used to search documents.

Keywords: degraded voltage, 90, loss voltage, 59 These three activities are not specifically exempted under any of the categories listed in Section 1 above. They are not managerial or administrative changes. The changes implemented by ECP 04-0294-00 result in field setpoint changes that are built upon the allowable values in License Amendment 275, reviewed and approved by the NRC on 8.9.2006. The calculation addendum revises the Allowable Value for the Loss of Voltage Relays to be consistent with the conservative values in License Amendment 275. The USAR change revises the descriptions of the relays to reflect the descriptions in License Amendment 275. Section 2.1.2 Technical Specification, was marked Yes as these activities are related to the TS change being implemented by the LAR 03-0014. LAR 03-0014 has been approved and is License Amendment 275. Therefore, these activities are exempt from 10CFR 50.59 because the RC has reviewed and approved the Technical Specification change. Preparer (Print name) Signature Date Murtha, Matthew J o Z/ /6 Reviewer (Print name) Signat Date Kendall, Joseph D / E?(, 72Z

                                                                                                                                                 /

Z Z'--

Page DIge 1 of 10 DESIGN INTERFACE

SUMMARY

- DB NOP-CC-2004-05 Rev. 06                                                                                           DIS Rev. 0 Document/Activity Evaluated: Calculation C-EE-004.01-049, Addendum A02                                                                   Rev. 15
                                                .- '                ah6I PROCEDURES iNtERFACES NIOAMS                                                                           ___.__

Req'd Sect. Topic Prepare DIE and forward to: DIE No. El N/A Maintenance Programs & Procedures Maintenance El N/A Ops Programs & Procedures Operations Z N/A System Programs & Procedures Responsible Plant Engineer 01 0 N/A Engineering Assessment Board EAB Chairman 02 El N/A Training Training (Information Only Copy) DESIGN INTERFACES. Potential Interface Evaluated using DIRC (NOP-CC-2004-02) Rev 05 El 1.0 ALARA Radiation Protection [E 2.0 Fire Protection/Safe Shutdown Electrical/l&C Engineering Unit, DES El 3.0 Environmental Qualification Engineering Programs Unit, TSES E] 4.0 Human Factors Electrical/l&C Engineering Unit, DES [E 5.0 Plant Security System Interface Electrical/l&C Engineering Unit, DES / Security Operations El 6.0 Seismic Interaction/Seismic Qualification Mechanical/Structural Engineering Unit, DES El 7.0 Pipe Rupture Interaction Engineering Analysis Unit, DES El 8.0 Internal Missile Hazards Engineering Analysis Unit, DES E] 9.0 NSSS Design Basis Engineering Analysis Unit, DES E] 10.0 Containment Isolation Mechanical/Structural Engineering Unit, DES E] 11.0 Materials Compatibility/Chemical Control Mechanical/Structural Engineering Unit, DES E] 12.0 Control Room Habitability Mechanical/Structural Engineering Unit, DES El 13.0 Mechanical Systems (13.1 - 13.20) Mechanical/Structural Engineering Unit, DES El 13.0 Mechanical Systems (13.21 - 13.26) Engineering Analysis Unit, DES El 14.0 Penetrations Mechanical/Structural Engineering Unit, DES E] 15.0 Miscellaneous Structural Considerations Mechanical/Structural Engineering Unit, DES El 16.0 Heavy Loads Mechanical/Structural Engineering Unit, DES [] 17.0 Electrical Systems Analysis Electrical/l&C Engineering Unit, DES El 18.0 Instrumentation and Controls Electrical/l&C Engineering Unit, DES E] 19.0 Simulator (Hardware & Software) Training El 20.0 In-Service Testing (20.1 - 20.10) Engineering Programs Unit, TSES El 20.0 Repair/Replacement Program & ISI (20.11- Engineering Programs Unit/Rapid Response Engineering Unit; TSES 20.19) El 20.0 Snubbe(Program (20.20) Engineering Programs Unit, TSES Mechanical/Structural Engineering Unit, DES El 21.0 Piping and Pipe Supports Mechanical/Structural Engineering Unit, DES E] 22.0 Reactor Core Operations - RE/Engineering Analysis Unit, DES E] 23.0 Licensing Review Regulatory Compliance El 24.0 Lubrication/Vibration Monitoring Maintenance- PS El 25.0 Probabilistic Safety Assessment Engineering Analysis Unit, DES El 26.0 Piping & Equipment Mechanical/Structural Engineering Unit, DES El 27.0 Valve Programs Engineering Programs Unit, TSES El 28.0 Plant Computers/Software Electrical/l&C Systems Engineering Unit, PEERS El 29.0 Maintenance Rule, 10CFR 50.65 Engineering Programs Unit, TSES El 30.0 Operations Impact Operations Services El 31.0 Maintenance Maintenance- ME,EL,IC,PS El 32.0 Chemistry Chemistry El 33.0 Training Training El 34.0 Testing Requirements Review Plant Engineering & Equipment Reliability El 35.0 Corrosion-Erosion Monitoring and Analysis Engineering Programs Unit, TSES [E 36.0 RCS Integrated Leakage Reduction Program Engineering Programs Unit, TSES El 37.0 Boric Acid Corrosion Control Program Engineering Programs Unit, TSES 38.0 Locked and Capped Valve Review Operations Services

'El                                                           ________  -1 39.0     Dry Fuel Storage Review                                  Operations- RE / Mechahical/Structural Engineering Unit, DES E]      40.0. Protective Coatings/Painting                             Mechanical/Structural Engineering Unit, DES El       41.0   1Personal   Safety Considerations                       j Nuclear Training Services, Site Training Comments:

• Design-Elec/l&C is preparing Addendum ther in rface is not required. Maintenance and OPS review is not required because the addendum does not affect any output documents. Supv.

The system en ineer will be provided with ap interface reve*w to verify the PMs referenced in the addendum. Prepared by: ent-Ndf*nd-.n) I fDate

                                                        .....                 [Reviewed by: (Pr/nt Name and Skyin                              j i-Date B.M. Waybright                                                  8     06                       /                      "                         [etLG, Z

U- -SAO qnal C, - U,,

Page 1 of/ FrstEn DESIGN INTERFACE EVALUATION NOP-CC-2004-07 Rev. 03 Document/Activity Rev. DIE No.IRev. Calculation C-EE-004.01-049, Addendum 02 00 01/00 To: Interfacing Organization (As identified on DIS) Contact System Engineer D.Duquette From: (Design Engineer) Mail Zone Phone DIE Response Date

- B.M.Waybright                                                                          3205                         8488/29/06 Description of Change/Areas of Concern                                                 List DIRC Questions Engineering Assessment Board Review                                                    N/A To.b.....lee..by.he..ner..c              Evaluato      Rfr . oNO-C             4S. cio   4..1         .n    .tahmn   . guidnc-
                                                                                                                                                .o m

IMPACT ON DESIGN AND LICENSING BASIS OD"ý50"4 fS ~ t4 tA(

• Describe affect on current licensing basis for the system/structure/component (SSC) involved.
• Describe affect of proposed change on existing design basis.
• Identify relevant design criteria and standards (including applicable revision/addenda).
• Identify potential failure mechanisms and failure consequences.
• Describe impact on operational configuration, system interactions, and any other pertinent considerations. Identify required actions.

INSTALLATION AND TESTING - i,, C"* 1 '*(,, tIP / 5, ý't A- ' 'j'\ -,

• Identify appropriate installation requirements and acceptance criteria for testing.
• Identify any limitations such as open assumptions or engineering holds. Identify what is restrained and what is required to release the hold. -~~ ~

IMPACT ON TRAINING -L &MA3QK t AW t 1`J Does the change add, modify, or dite equipment, components, systems, or processes that result in the need for personnel to acquire additional skills and knowledge? )Q No [] Yes If Yes, complete the Affected Documents section below. Identify Training as the Document Type, assign an Action Code, Responsible Organization and Tracking Number. NA all other fields. COMMENTS/ADDITIONAL INPUT/ INFORMATION AFFECTED DOCUMENTS List new and/or existing documents requiring issue/update as a result of this activity (e.g., drawings, procedures, databases, lesson plans, and vendor manuals). List current revision/version of the document. Document Document Unit Rev. Version Action Responsible Tracking No.** Type Code* Organization R27e, I ' &

    -tcuon Completion Goue:

1 Document must be issued/effective at implementation of the activity prior to returning the SSC to service (Operational Acceptance). 2 Document must be issued/effective following issuance of the package, but prior to implementation. 3 Document must be issued/effective upon issuance of the package for implementation. 4 Document must be issued/effective following return of the SSC to service (Operational Acceptance) and prior to closeout of the activity. 5 Document needs to be changed as a result of the activity, but the change can be done when the responsible organization deems aoDrooflate. A trackino number is recuired for these actions. CONCLUSIO LI Interface Not Required (Provide Justification) SInterface Provided (Indicate if Final Review required) El Final Review required ___"____ Interface Evaluator (PrintName and Sign) Date Ar val (Print Name an7 ___- Da [3 Comments need to be resolved I'nterface Evaluator Date El My comments/input have been- properly incorporated and/or Interface Evaluator Date addressed. _

DOCUMENT REVIEW fLz sOm . ED 6864-2 REVIEW CONDUCTED BY

• ORGANIZATION INDIVIDUAL (PRINT NAME) SHEET iL- OF .

DBES Duquette I A RESPONSE TO EACH COMMENT IS REQUESTED, PLEASE NO COMMENTS NO RESPONSE REQUESTED LI RETURN THIS FORM WITH YOUR RESPONSE IN THE SPACE PROVIDED DOCUMENT TITLE OR NUMBER Calculation C-EE-004.01-049 Addendum 02 COMMENTS RESPONSE DIE Input for System Engineer I - Impact of change on system - This addendum to the undervoltage relay calculation involves rounding the time delays and revising the calibration frequency of the 27X-6 relays to a refueling interval. There is no impact on the system. 2 - Change in system operation maintenance. Include all repetitive task additions/deletions. This calculation addendum allows the calibration frequency to go from yearly to a refueling interval Existing PM revision forms DB-REV-06-0611 and 612 will be revised to reflect this frequency change. 3 - Impact on procedures/instructions under the responsibility of Plant Engineering resulting from this change. This Calc addendum is beneath the level of detail in any procedures/instructions for the 4.16 UV relays. No changes are required. 4 - Test requirements and plant and/or system configuration required for testing. No testing or changes to system configuration is required for this calculation addendum. 5 - Identify need for increased vendor oversight or enhanced procurement. This addendum to the calculation does not involve either vendor resources or the purchase of plant equipment. ES [' ýS-)454AUR ' -; ' ** DNTEJ*& (*/ *-' RESOLUTION ONCURRENCE SIGNATURE DT Lr

Eninern Asesmn Bor N/Aie I IMPACT ON DESIGN AND LICENSING BASIS Describe affect on current licensing basis for the system/structure/component (SSC) involved. Describe affect of proposed change on existing design basis. '1f1,4# Identify relevant design criteria and standards (including applicable revision/addenda).

• Describe impact on operational configuration, system interactions, and any other pertinent consi :rations. Identify required actions.

INSTALLATION AND TESTING

• Identify appropriate installation requirements and acceptance criteria for testing.

" Identify any limitations such as open assumptions or engineering holds. Identify what is restrainE d and what is required to release the hold. IMPACT ON TRAINING

• Does the change add, modify, or delete equipment, components, systems, or processes that res It in the need for personnel to acquire additional skills and knowledge? El No 0l Yes If Yes, complete the Affected Documents section below. Identify Training as the Document Type, assign an Action Code, Responsible Organization and Tracking Number. NA all other fields.

COMMENTS/ADDITIONAL INPUT) INFORMATION AFFECTED DOCUMENTS '/ List new and/or existing documents requiring issue/update as a result of this activity (e.g., drawings, procedures, databases, lesson plans, and vendor manuals). List current revision/version of the document. Document Document Unit Rev. Version Action Responsible Tracking No.** Type Code* Organization

• Action Completion Code:

1 Document must be issued/effective at implementation of the activity prior to returning the SSC to service (Operational Acceptance). 2 Document must be issued/effective following issuance of the package, but prior to implementation. 3 Document must be issued/effective upon issuance of the package for implementation. 4 Document must be issued/effective following return of the SSC to service (Operational Acceptance) and prior to closeout of the activity. 5 Document needs to be changed as a result of the activity, but the change can be done when the responsible organization deems approp~riate. *A tracking number is required for these actions. CONCLUSION El Interface Not Required (Provide Justification) N Interface Provided (Indicate if Final Review required) El Final Review required Interface Evaluator ( Pnnt, ap/*,* Sign) Date Approval (Print ana li) Date Interface Eval(uaDte Date El Comments need to be resolved Interface Evaluator Date

                                                                                 -                                                     +

El My comments/input have been properly incorporated and/or Interface Evaluator Date addressed.

 "*KF-a A-ev'PEtL-%AJ "-PoV,                'p~' -bEA "eaOP- NeD - 0002.

Page 1 of 1 FirstEnergy DESIGN VERIFICATION RECORD NOP-CC-2001-01 Rev. 00 SECTION I: TO BE. COMPLETED BY DESIGN ORIGINATOR DOCUMENT(S)/ACTIVITY TO BE VERIFIED: C-EE-004.01-049 Rev 15 Addendum A02 [ SAFETY RELATED El AUGMENTED QUALITY El NONSAFETY RELATED SUPPORTING/REFERENCE DOCUMENTS C-EE-004.01-049, Rev. 15 License Amendment 275 ECP 04-0294-00 6 DESIGN ORIGIN R: ta')d nNam* DATE B.M.Waybright ize 16 SECTION II: TO BE COMPLETED BYVRIFlER VERIFICATION METHOD (Check one) DESIGN REVIEW (Complete Design El ALTERNATE CALCULATION El QUALIFICATION TESTING Review Checklist or Calculation Review Checklist) JUSTIFICATION FOR SUPERVISOR PERFORMING VERIFICATION: N/A APPROVAL: (Printand Sign Name) DATE N/A EXTENT OF VERIFICATION: Reference calculation review checklist which addresses the scope of A02 of C-EE-004.01-049, Rev. 15. COMMENTS, ERRORS OR DEFICIENCIES IDENTIFIED? El YES NO RESOLUTION: (ForAlternate Calculation or Qualification Testing only) N/A RESOLVED BY: (Printand Sign Name) DATE

                                                                                                    . i DATE DATE
                                                                                                        . C-1 &     1 -

Page 1 of 4 FirstEnery CALCULATION REVIEW CHECKLIST CALCULATION NO. C-EE-004.01-049 REV. 15 NOP-CC-2001-04 Rev. 03 ADDENDUM NO. A02 UNIT DB QUESTION !NAI Yes INol COMMENTS

• RESOLUTION GENERAL X The objectives and purpose are 1 Does the stated objective/purpose clearly describe why the calculation is being clearly described in the performed? "Objective or Purpose of.

Addendum" section of the addendum. The scope of the addendum is also clearly stated..

2. Are design input / output documents and references listed and clearly identified in the X Where appropriate, applicable document index, including edition and addenda, where applicable? codes, standards, design inputs, and references are defined in the calculation. The Relay Setting Manual will revised by ECP 04-0294-00. DBE# 04-00074 is listed as DIN 88.

3. Were verbal inputs from third parties properly documented? X N/A - There are no applicable verbal inputs from third parties that apply.

4. Are design input parameters, such as physical and geometric characteristic and X N/A - This addendum rounds regulatory or code and standard requirements, accurately taken from the design input the DVR time delay to correctly documents and correctly incorporated, including tolerances and units? reflect the changes evaluated in I_ I ECP 04-0294-00.

5. Are the desigyn inputs relevant, current, consistent with design/licensing bases and X The rounding performed by this directly applicable to the purpose of the calculation, including appropriate tolerances addendum is conservative in and ranges/modes of operation? nature and correctly reflects amendment 275 to LAR 03-0014. DBE# 04-00074 documents the vendor recommendation / justification for changing the required calibration frequency of the 27X-6/Cl and 27X-6/D1 relays. The drift value is still considered to be conservative in nature.

6. Are all design inputs retrievable? If not, have they been added as attachments? X LAR 03-0014 amendment 275 and DBE# 04-00074 are I retrievable (DIN 88).

7. Are preliminary or conceptual inputs clearly identified for later confirmation as open X There are no preliminary or assumptions? conceptual inputs identified by this addendum.

8. Where applicable, were construction and operating considerations included asinput x There are no applicable information? . " construction or operating considerations affected by

___rounding the time delay.

9. Were design input / output documents properly updated to reference this calculation? X The Relay Setting Manual will be

     -      ______revised                                                                                           by ECP 04-0294-00.

Page 2 of 4 FirstEnergy CALCULATION REVIEW CHECKLIST CALCULATION NO. C-EE-004.01-049 REV. 15 NOP-CC-2001-04 Rev. 03 ADDENDUM NO. A02 UNIT DB QUESTION NA Yes No COMMENTS RESOLUTION ASSUMPTIONS X There are no assumptions

10. Have the assumptions necessary to perform the analysis been clearly identified and identified by this addendum.

adequately described?

11. Are all assumptions for the calculation reasonable and consistent with design/licensing X - There are no assumptions bases? identified by this addendum.

12. Have all open assumptions needing later confirmation been clearly identified on the X There are no assumptions Calculation cover sheet, including when the open assumption needs to be closed? identified by this addendum.

13. Has a Condition Report been issued for open assumptions? X There are no assumptions identified by this addendum.

14. Have engineering judgments been clearly identified? X There are no eng. judgments identified by this addendum.

15. Are engineering judgments reasonable and adequately documented? X There are no eng. judgments identified by this addendum.

16. Is suitable justification provided for all assumptions/engineering judgements (except X There are no assumptions / eng.

those based upon recognized engineering practice, physical constants or elementary judgments identified by this scientific principles)? addencdum. METHOD OF ANALYSIS - X This addendum uses the

17. Is the method used appropriate considering the purpose and type of calculation? appropriate methodology to conservatively round the DVR time delay upper and lower limits so that they are consistent with LA[R 03-0014.

18. Is the method in accordance with applicable codes, standards, and design/licensing X There are no applicable codes bases? or standards identified by this addendum. The values for DVR time delay are being rounded to be consistent with the design /

licensing basis (License amendment 275, LAR 03-0014). DBE# 04-00074 documents the justification for changing the required calibration frequency of the 27X-6/Cl and 27X-6/D1 relays (vendor recommendation). - IDENTIFICATION OF COMPUTER CODES (Ref: NOP-SS-1 001) X The computer code "C" has

19. Have the versions of the computer codes employed in the design analysis been been correctly identified for certified for this application? Microsoft Word (administrative).

20. Are codes properly identified along with source (vendor, organization, etc.)? X Yes

21. Is the code applicable for the analysis being performed? X Yes

22. Is the computer prograrmn(s) being used listed on the FENOC Usable Software List for X Yes the site? I III

Page 3 of 4 FrstEneCALCULATION REVIEW CHECKLIST CALCULATION NO. C-EE-004.01-049 REV. 15 NOP-CC-2001-04 Rev. 03 ADDENDUM NO. A02 UNIT DB QUESTION (NA Yes INo COMMENTS I RESOLUTION

23. Does the computer model, that has been created, adequately reflect actual (or to be X Microsoft Word was utilized for modified) plant conditions (e.g., dimensional accuracy, type of model/code options, administrative purposes only.

used, time steps, etc.)?

24. Did the computer output generate any ERROR or WARNING Messages that could X Microsoft Word was utilized for invalidate the results? administrative purposes.

25. Is the computer output reasonable when compared to inputs and what was expected? X Microsoft Word was utilized for administrative purposes only.,,

COMPUTATIONS X The conservative change to the

26. Are the equations used consistent with recognized engineering practice and calculation is in accordance with design/licensing bases? normal engineering practices.

No new equations were derived.

27. Is there a reasonable justification provided for the uses of any equations not in X No new equations were derived.

common use?

28. Were the mathematical operations performed properly and the results accurate? X The results are consistent with LAR 03-0014.

29. Have adjustment factors, uncertainties, empirical correlations, etc., used in the .. X The rounding was performed analysis been correctly applied? conservatively and remained within acceptable limits so as not to inadvertently impact the results or conclusions to the calculation.

.30. Is the result presented with proper units and tolerance? X Yes -'Results are provided in seconds.

31. Has proper consideration been given to results that may be overly sensitive to very X No overly sensitive devices were small changes in input? identified.

CONCLUSIONS X The results correlate to LAR 03-

32. Is the magnitude of the result reasonable and expected when compared to inputs? 0014.

33. Is there a reasonable justification provided for deviations from the acceptance criteria? X No deviations from the acceptance criteria were identified.

34. Are stated conclusions justifiable based on the calculation results? X No new conclusions were derived from this addendum.

35. Are all pages sequentially numbered and marked with a valid calculation and revision X number?

T6 . Is all information legible and reproducible? .X

37. Is the calculation presentation complete and understandable without any need to refer X back to the Originator for clarification or explanations?

38. Is calculation format presented in a logical and orderly manner, in conformance with X the standard calculation content Of NOP-CC-3002 (Attachment 1)?

39. Have all changes in the documentation been initialed (or signed) and dated by the X author of the change and all required reviewers?

DESIGN/LiCENSING Yes - All results are consistent

40. Have all calculation results stayed within existing design/licensing basis parameters? with amendment 275 (LAR 03-0014).

Page 4 of 4 FirstEnergy CALCULATION REVIEW CHECKLIST CALCULATION NO. C-EE-004.01-04g REV. 15 NOP-CC-2001-04 Rev. 03 ADDENDUM NO. A02 UNIT DB QUESTION NAI Yes NoI COMMENTS RESOLUTION

41. If the response to Question 40 is NO, has Licensing been notified as appropriate? (i.e. X UFSAR or Tech Spec Change Request has been initiated).

42. Is the direction of trends reasonable? X

43. Has the calculation Preparer used all applicable design information/requirements X LAR 03-0014 and ECP 04-0294-provided? 00 were used to prepare this laddendum.

44. Did the calculation Preparer determine if the calculation was referenced in design X No changes are required.

basis documents and/or databases?

45. Did the Preparer determine if the calculation was used as a reference in the UFSAR? X No changes are required.

46. If the calculation is used as a reference in the UFSAR, is a change to the UFSAR X No changes are required.

required or an update to the UFSAR Validation Database, if applicable, required?

47. If the answer to Question 46 is YES, have the appropriate documents been initiated? X No changes are required.

48. Has the applicability of 10CFR50.59 to this calculation been considered and X RAD 06-03884 has been created documented? to evaluate this change. A 50.59 SCREEN will not be created to evaluate this change. The function of the SCREEN has been performed under Amendment 275 (LAR 03-0014).

AcCEPTABLE

49. Does the calculation meet its purpose/objective?

50, is the calculation acceptable for use? x

51. What checking method was used to review the calculation? Check all that apply.

spot check for math ._.___X

• complete check for math .__X

    *_comparison with tests                                                ....                                                          _X

• check by alternate method X
• comparison with previous calculation X Review Summary:

No additional comments. Technical Re rt d Sign N e) Date Owner's Acceptance Review (Required for calcualtionspreparedbya vendor) C ary 8/28/06 Reviewer (Print and Sign Name) Date Design Vification (PrintV Si n N e) Date J.R. Cho a J.R. C /28/06 Date

                                                                                 /28106     Approver (Print and Sign Name)Dt K-.               L

NRC ITS Tracking 'Page I of 3 Return to View Menua Prnt Dounn RAI Screening Required: Yes Status: Closed This Document will be approved by: Gerald Regulatory Basis must be included in Comments Waig; Tim Kobetz section of this Form This document has been reviewed and Yes information in this question contains NO SUNSI sensitive material (the checkbox to the right must be selected before this question can be submitted) NRC ITS TRACKING NRC Reviewer ID 1200712260942 Conference Call Requested? No Category In Scope ITS Section; TB'"POC: JFD Number: Page Number(s); ITS 3.3 Aron Lewin None Information [TS ..Number: OS.I.. . DOC Number: Bases JFD Number: 3.3.8 None None None NRC OSI#51 Discuss how the CTS, or the proposed ITS, meets Criterion 21 of 10 CFR 50.36 Appendix A, in that continued operation with one LOPS channel inoperable can result in the loss of protective actions, given a single failure in the remaining channel's auxiliary relay.

Background

The CTS, Action 15.a. (page 280 of 636), currently allows for continued operation with only one channel per bus of a Degraded Voltage Function (CTS Functional Unit 4.b) or one channel per bus of a Loss of Voltage Function (CTS Functional Unit 4.c), if the inoperable channel is placed in trip within one hour. The ITS LCO (page 290 of 636) carries forward the CTS requirements. The ITS Bases (page 297 of 636) states that "with two protection channels in a one-

          ........... out-of-two, taken twice trip logic for each essential bus of the 4.16 kV power supply, no single failure will cause or prevent protective system actuation. This arrangement meets IEEE-279-1971 criteria (Ref. 3)." The statement does not appear to be accurate since four undervoltage relays with time delays are provided on each 4.16 kV essential bus for the purpose of detecting a loss of voltage condition and four undervoltage relays with time delays are provided on each 4.16 kV essential bus for the purpose of detecting a degraded voltage condition. Two undervoltage relays and an auxiliary relay per essential bus are associated with a channel (i.e. two channels for each function per bus).

Either undervoltage relay in a channel will actuate its associated auxiliary relay. The actuation of both auxiliary relays (i.e. two channels for a two-out-of-two logic) will result in protective actions. As a result if one channel is inoperable, a single failure in the remaining channel's auxiliary relay will http://www.excelservices.com/exceldbs/itstrackdavisbesse.nsfl1 fddcealOd3bdbb585256e... 7/18/2008

NRC ITS Tracking Page 2 of 3 prevent protective system actuation. In this condition, a single failure in the remaining channel will not result in protective action taking place. The STS for LCO 3.3.8 (NUREG-1430) is based on a different design that utilizes a two out of three logic design. Criterion 21 of 10 CFR 50.36 Appendix A states "the protection system shall be designed for high functional reliability and inservice testability commensurate with the safety functions to be performed. Redundancy and independence designed into the protection system shall be sufficient to assure that (1) no single failure results in loss of the protection function and (2) removal from service of any component or channel does not result in loss of the required minimum redundancy unless the acceptable reliability of operation of the protection system can be otherwise demonstrated. The protection system shall be designed to permit periodic testing of its functioning when the reactor is in operation, including a capability to test channels independently to determine failures and losses of redundancy that may have occurred." Issue 112/26/2007 1Date I Close Daated 103/07/2 008 Logged in User: Anonymous

'Responses Licensee Response by Bryan            Please refer to the attached drawing [E34B SH 14]. Using LVR as Kays on 03/03/2008                    an example, LVR has two units (channels) per essential bus. Bus C1 has two Loss of Voltage Units. One unit consists of undervoltage relays 27-1, 27-2, and auxiliary relay 27X-2. The other unit consists of undervoltage relays 27-3, 27-4, and auxiliary relay 27X-1. Either undervoltage relay will actuate the associated auxiliary relay. The actuation of both auxiliary relays will disconnect the offsite source, load shed-the essential bus, and generate an EDG LOPS. The design of the system has been reviewed by the NRC on multiple occasions, with the conclusion that it is appropriately designed. If the single failure is related to essential bus Cl, essential bus D1 can still perform its function.

Please see Amendment 211 (Adams MLN021200506) and Serial 2197(Attached). Additionally look at Amendment 275 (Adams ML060400472), Serial 3009 (Adams ML041310374), Serial 3100 (Adams ML050210170), Serial 3186 (Adams ML052870376), Serial 3193 (Adams ML053120383) and Serial 3265 (Adams ML061520316). Bus C1 has two Degraded Voltage Units, similarly configured. One unit consists of relays 27A-1, 27A-2, and 27X-4. The other unit consists of relays 27A-3, 27A-4, and 27X-5. Furthermore, loss of any one single channel for a function (i.e., loss of voltage or degraded voltage) only affects one EDG. Thus, the other EDG will still remain capable of performing the intended function if a single channel fails. This is why it is acceptable to have a two out of twotrip system for each EDG for a __given function. Licensee Response by Bryan http://www.excelservices.com/exceldbs/itstrackdavisbesse.nsf/1 fddceal Od3bdbb585256e... 7/18/2008

NRC ITS Tracking Page 3 of 3 Date Created: 12/26/2007 09:42 AM by Aron Lewin Last Modified: 03/07/2008 10:19 AM http://www.excelservices.com/exceldbs/itstrackdavisbesse.nsf! 1fddceal Od3bdbb585256e... 7/18/2008

ED1.11 SCHENENO. ACIO3 (AD103) CONTACTS FUNCTION NS. C T T 0N. CONTACTS FUNCTION NE0. REF. CONTACTS FUNCTION REF. REF: SP2 E THIS ITHIS H-f SPARE SS. S-. SPARE OPERATE F -- sTONE

               -7X- RELAY        S.1A                             SPARE                                                           NOTES."

Cl(S)) &________

1. TOEGENERAL NOTESN LOCATION DESIGNATIONS TNURIP

                    ]TRLK         SO                     TRI R                                    TRIP(051.0          E-488
     -    -    NKR AC             S            -i 0-                                a              R     C            SH.IIB            SEEDNG. INDEXE-348.

INACSI ___ --.. INTOSS(AD 0NRI) OS TRIP ITRLK SMS 21 NITRTALK - 0S2B 5 A S R 2. FOR L1 DEVELOPMENT, SEE DWG.E-308, SR.11. FIG,. HRN AC)tS II H E5- . B- r- SPARE

     -I H- BRKRACtO(ADIIO)         (I(ADI                                                                                               ANDFORCONTACT    FUNCTIONS SEE OND.E-348 SHR.I4B IN                  E-SN2B               ITP IRL             E-48B         3. SEE DRAWINO   E-22, SH.TI2 FORRELAYS27-1.27-2.

S ESTPCER E-N4B 0SEA*S I COCI l SH.17 -1 ACIIA SH.GB S HO0N I SH.CB 27-3 N 27-4. (1 12 J( 10 SPAS SEOUENCER E-N7B N I4 THIS THIS DRAWINGNAS REOANN ONCADRANl SUPERSEDES RE*V10 SPARE - .3IC,. S. SPORE S.. NONE sCHEE .... ) 10,, O , 06-23-03 27-1 27-2 27-3 27-4 SPARE DAVIS-BESSE NUCLEAR POWER STATION UNIT TM{TaED NO. I ED-SO ýA' S i SS5 4_ 114Tm 1O RTm 17-,T4 11fl ELEMENTARY WIRING DIAGRAMS A I IP15ISý1 _T_5

                       \V/--              5_2'                                  /      27X12       1 2   -V   -T --h4   -27X26                      4.16 KVFD BKRS.

BUS CM(DI) VOLTAGE &,AUIX.RELAYS SPARE RELAYTEST.TSIT-41CI(0 I BUSCI IR) AU0. -1.LE.O. IDK. (SEE E_2048 SHT 1. FORCI) UNDERVOLTAGE RELAYS (SEE E-2ODBSHT.), TFORO OT E-640SH.IE(2E) E-34B SH.14 112 OB 04-08-06 OFN-F:/SCHEME/E34BSI4.DGN

CENTERIOR ENERGY 6200 Oak Tree Boulevard Mail Address: Donald C.Shelton Independence OH P.O. Box 94661 Senior Vice President 216-447-3153 Cleveland, OH 44101-4661, Nuclear Fax 216-447-3123 Docket Number 50-346 License Number NPF-3 Serial Number 2197 March 18, 1994 United States Nuclear Regulatory Commission Document Control Desk Washington, DC 20555

Subject:

License Amendment Application to Revise Technical Specifications and Applicable Bases to Relocate Certain Cycle-Specific Protective Limits and Core Operating Limits to the Core Operating Limits Report (COLR) Gentlemen: Enclosed is an application for an amendment to the Davis-Besse Nuclear Power Station (DBNPS), Unit Number l Operating License Number NPF-3, Appendix A, Technical Specifications, to reflect the, changes attached. The proposed changes involve Technical Specification (TS) 2.1.2 (Reactor Core), TS 2.2.1 (Reactor Protection System Setpoints), Bases 2.1.1 and 2.1.2 (Reactor Core), Bases 2.2.1 (Reactor Protection System Instrumentation Setpoints), TS 3.2.2 (Power Distribution Limits, Nuclear Heat Flux Hot Channel Factor - F ), TS 3.2.3 (Power N Distribution Limits, Nuclear Enthalpy Rise Hot Channel Factor - F ), Bases 3/4.2 (Power Distribution Limits), and TS 6.9.1.7 (Administraive Controls, Core Operating Limits Report). This application is submitted in accordance with Generic Letter 88-16, "Removal of Cycle-Specific Limits from Technical Specifications", dated October 4, 1988 (Toledo Edison Log Number 2735), which requires that, for removal of cycle-specific limits from the Technical Specifications, the limits be determined using an NRC approved methodology,. On March 16, 1993, the NRC staff approved Babcock and Wilcox (B&W) Topical Report BAW-10179P, "Safety Criteria and Methodology for Acceptable Cycle Reload Analyses" (TAC No. M80189). The NRC Safety Evaluation Report (SER) concludes that the inclusion of certain operating limits in a COLR is acceptable and that BAW-10179P is an acceptable Technical Specification reference for the B&W Fuel Company methodology used to Operating Companies: Cleveland Electric Illuminating Toledo Edison

Docket Number 50-346 License Number NPF-3 Serial Number 2197 Page 2 establish the values of these limits for the B&W-designed 177-fuel-assembly class of plants (such as the DBNPS). The operating limits that may be placed in the COLR include (but are not limited to): nuclear heat flux hot channel factor limit (F 0 ), nuclear enthalpy rise hot channel factor limit (F A), axial power imbalance protective limits and trip setpoint for nuclear overpower based on Reactor Coolant System flow. The above referenced Technical Specification and Bases changes are proposed to implement this guidance. Generic Letter 88-16 identified that the use of a COLR as an alternative to including the values of cycle-specific parameters in individual Technical Specifications will eliminate an unnecessary burden on licensees and the NRC. Therefore, this application is considered to be a Cost Beneficial Licensing Action since it will allow future changes to cycle-specific limits without the expense of processing a License Amendment. Toledo Edison requests that this amendment be issued by the NRC.by July 1, 1994, to support the planning and scheduling of the Ninth Refueling Outage (9RFO). The 9RFO is currently scheduled-to commence on October 1, 1994. Should further information be required, please contact Mr. William T. O'Connor, Manager - Regulatory Affairs, at (419) 249-2366. Very tr y yours, MKL/amb Enclosure cc: J. B. Martin, Regional Administrator, NRC Region III S. Stasek, NRC Region III, DB-1 Senior Resident Inspector R. J. Stransky Jr., NRC/NRR DB-1 Project Manager J. R. Williams, Chief of Staff, Ohio Emergency Management Agency, State of Ohio (NRC Liaison) Utility Radiological Safety Board

Docket Number 50-346 License Number NPF-3 Serial Number 2197 Enclosure Page 1 APPLICATION FOR AMENDMENT TO FACILITY OPERATING LICENSE NPF-3 DAVIS-BESSE NUCLEAR POWER STATION UNIT NUMBER I Attached are requested changes to the Davis-Besse Nuclear Power Station, Unit Number 1 Facility Operating License Number NPF-3. Also included is the Safety Assessment and Significant Hazards Consideration. The proposed changes (submitted under cover letter Serial Number 2197) concern: Appendix A, Technical Specification 2.1.2, Reactor Core Appendix A, Technical Specification 2.2.1, Reactor Protection System Setpoints Appendix A, Technical Specification Bases 2.1.1, and 2.1.2, Reactor Core Appendix A, Technical Specification Bases 2.2.1, Reactor Protection System Instrumentation Setpoints Appendix A, Technical Specification 3.2.2, Power Distribution Limits, Nuclear Heat Flux Hot Channel Factor'- F Appendix A, Technical Specification 3.2.3, NPower Distribution Limits, Nuclear Enthalpy Rise Hot Channel Factor.F AH' Appendix A, Technical-Specification Bases 3/4.2, Power Distribution Limits Appendix A, Technical Specification 61.1.7, Administrative Controls, Core Operating Limits Report By: ,pO D. C. ýhel tge sint, Nuclear Sworn and Subscribed before me this 18th day of March, 1994. Notary/Public, State of Ohio EVELYN L DRESS NOTi -.

• aO.STATE OF OHIO hty Cazmoi1 E*tS 14~28, 1994

Docket Number 50-346 License Number NPF-3 Serial Number 2197 Enclosure Page 2 The following information is provided to support issuance of the requested changes to Davis-Besse Nuclear Power Station, Unit Number 1 Operating License Number NPF-3, Appendix A, Technical Specification (TS) 2.1.2 (Reactor Core), TS 2.2.1 (Reactor Protection System Setpoints), Bases 2.1.1 and 2.1.2 (Reactor Core), Bases 2.2.1 (Reactor Protection System Instrumentation Setpoints), TS 3.2.2 (Power Distribution Limits, Nuclear Heat Flux Hot Channel Factor - F ), TS 3.2.3 (Power Distribution Limits, Nuclear Enthalpy Rise Hot C~annel Factor - F ), Bases 3/4.2 (Power Distribution Limits), and TS 6.9.1.7 (Administrative*Controls, Core Operating Limits Report). A. Time Required to Implement: This change is to be implemented within 90 days after NRC issuance of the License Amendment. B. Reason for Change (License Amendment Request Number 93-0004, Revision 0): This application is submitted in accordance with Generic Letter 88-16, "Removal of Cycle-Specific Limits from Technical Specifications", dated October 4, 1988 (Toledo Edison Log Number 2735), which requires that, for removal of cycle-specific limits from the Technical Specifications, the limits be determined using an NRC approved methodology. On March 16, 1993, the NRC staff approved Babcock and Wilcox (B&W) Topical Report BAW-10179P, "Safety Criteria and Methodology for Acceptable Cycle Reload Analyses" (TAC No. M80189). The NRC Safety Evaluation Report (SER) concludes that the inclusion of certain operating limits in a COLR is acceptable and that BAW-10179P is an acceptable TS reference for the B&V Fuel Company methodology used to establish the values~of these limits. The operating limits that may be placed in the COLR include (but are not limited to): nuclear heat flux hot channgl factor limit (F.), nuclear enthalpy rise hot channel factor limit (F H), axial power imbalance protective. limits and trip setpoint for nuclear overpower based on RCS flow., The above referenced Technical Specification and Bases changes are proposed to implement this guidance. C. Safety Assessment and Significant Hazards Consideration: See Attachment

Docket Number 50-346 License Number NPF-3 Serial Number 2197 Attachment Page 1 SAFETY ASSESSMENT AND SIGNIFICANT HAZARDS CONSIDERATION FOR LICENSE AMENDMENT REQUEST NUMBER 93-0004 TITLE: Revision of Various Technical Specifications and Applicable Bases to. Relocate Certain Cycle-Specific Protective Limits and Core Operating Limits to the Core Operating Limits Report (COLR). DESCRIPTION: The purpose of the proposed changes is to modify the Davis-Besse Nuclear Power Station (DBNPS) Operating License NPF-3, Appendix A Technical Specifications (TS) and associated Bases. The changes are described in detail below.- On March 16, 1993, the NRC staff approved Babcock and Wilcox (B&W) Topical Report BAW-10179P, "Safety Criteria and Methodology for Acceptable Cycle Reload Analyses" (TAC No. M80189). The NRC Safety Evaluation Report (SER) concludes that the inclusion of certain operating limits in a COLR is acceptable and that BAW-10179P is an acceptable TS reference for the B&W Fuel Company methodology used to establish the values of these limits. The operating limits that may be placed in the COLR include (but are not limited to): nuclear heat flux hot channeh factor limit (F ), nuclear enthalpy rise hot channel factor limit (F H ), axial power imbalance protective limits and trip setpoint for nuc ear overpower based on RCS flow. The following Technical Specification and Bases changes are proposed to implement this guidance: Technical Specification 2.1.2, Reactor Core - - Remove Figure 2.1-2, Reactor Core Safety Limit; from the TS and relocate it to the COLR. This figure provides axial power imbalance protective limits for various combinations of reactor coolant pump operation. Revise TS 2.1.2 to refer to the COLR instead of Figure 2.1-2, and clarify that this figure is a "protective" limit rather than a "safety" limit. In addition, revise TS 2.1.2 to delete reference to two reactor coolant pump operation since reactor operation with fewer than three reactor coolant pumps in operation is not permitted, and revise the Action statement to clarify that compliance with the requirements of Specification 6'.7.2 is required. Technical Specification 2.2.1, Reactor Protection System Setpoints - - Remove Figure 2.2-1, Trip Setpoint for Flux - - AFlux/Flow, from the TS and relocate it to the COLR.. This figure provides trip setpoints for nuclear overpower based on reactor coolant system (RCS) flow. Revise Table 2.2-1, Reactor Protection System Instrumentation Trip Setpoints. Functional Unit 4, to refer to the COLR instead of Figure 2.2-1 and to remove the reference to footnote "I" since the allowable values for Functional Unit 4 will be in the COLR.

Docket Number 50-346 License Number NPF-3 Serial Number 2197 Attachment Page 2 Bases 2.1.1 and 2.1.2, Reactor Core, and Bases 2.2.1, Reactor Protection System Instrumentation .Setpoints - - In the fourth paragraph on page B 2-1, remove the references to the hot channel factor values. In the first paragraph on page B 2-2, refer to the COLR in lieu of Figure 2.1-2, refer to the COLR in lieu of a specific F value, refer to the COLR in lieu of a specific kw/ft limit and d~fine a protective limit. In the third paragraph on page B 2-2, refer to the COLR in lieu of Figure 2.1-2. On page B 2-5, delete the discussion of examples of typical power level and low flow rate combinations for the pump situations of Table 2.2-1 (since Figure 2.2-1 is relocated to the COLR, these examples are no longer pertinent). In the first paragraph on page B 2-6, refer to the COLR in lieu of Figure 2.2-1. Technical Specification 3.2.2, Power Distribution Limits, Nuclear Heat Flux Hot Channel Factor - F - - Remove the F limit relationship specified in the TS and rel~cate it to the COER, revising the Limiting Condition for Operation (LCO) to read: "F shall be within the limits specified in the Core Operating Limits Repgrt." Technical Specification 3.2.3, Power Yistribution Limits, Nuclear Enthalpy Rise Hot Channel Factor - (F AH) - - Remove the (F AH) limit relationship specified Nin the TS and relocate it to the COLR, revising the LCO to read "(FA ) shall be within the limits specified in the CORE OPERATING LIMITS REPORT." Bases 3/4.2, Power Distribution Limits - - Associated with the above TS changes, on page B 314 2-2, refer to the COLR in lieu of specific hot channel factor limits. Technical Specification 6.9.1.7, Administrative Controls, Core Operating Limits Report - - Add references to TS 2.1.2, 2.2.1, 3.2.2 and 3.2.3 for core operating limits to be established and documented in the COLR. Replace the present discussion of analytical methods and listing of topical reports with the following: The analytical methods used to determine the core operating limits addressed by the individual Technical Specifications shall be: those previously reviewed and approved by the NRC, as described in BAW-10179P-A, "Safety Criteria and Methodology for Acceptable Cycle Reload Analyses", or any other new.NRC-approved analytical methods used to determine core operating limits that are not yet referenced in the applicable BAW-10179P-A revision. The applicable BAW-10179P-A revision (the approved revision at the time the reload analyses are performed) shall be listed in the CORE OPERATING LIMITS REPORT. The CORE OPERATING LIMITS REPORT shall also list any new NRC-approved analytical methods used to determine core operating limits that are not yet referenced in the applicable BAW-10179P-A revision.

Docket Number 50-346 License Number NPF-3 Serial Number 2197 Attachment Page 3 Technical Specification 6.7, Safety Limit Violation, TS 6.5.1.6, Station Review Board (SRB) Responsibilities, and TS Index - - Actions have been added in a new Technical Specification 6.7.1.2 to address the actions to be taken in the event the protective limit (formerly identified as a safety limit) of revised Technical Specification 2.1.2 is violated. Technical Specification 6.5.1.6.n has been revised to reflect the SRB's responsibility to review the Protective Limit Violation Report. The TS Index has been revised to incorporate the new specification. SYSTEMS, COMPONENTS, AND ACTIVITIES AFFECTED: The proposed Technical Specification changes involve cycle-specific reactor core operating limits. Core operating limits are determined using analytical methods that have been previously reviewed and approved by the NRC. SAFETY FUNCTIONS OF THE AFFECTED SYSTEMS, COMPONENTS-AND ACTIVITIES: The core operating limits are determined so that all applicable limits (e.g. fuel thermal-mechanical limits, core thermal-hydraulic limits, Emergency Core Cooling System (ECCS) limits, and nuclear limits, such as shutdown margin and transient and accident analysis limits) of the safety analyses are met. EFFECTS ON SAFETY: As stated above, the NRC staff has approved the Babcock and Wilcox (B&W) Topical Report BAW-10179P. The NRC Safety Evaluation Report (SER) associated with approval of this topical report concludes that inclusion of certain operating limits in a Core Operating Limits Report (COLR) is acceptable and that BAW-10179P is an acceptable Technical Specification reference for the B&W Fuel Company methodology used to establish the value of these limits. Relocation of cycle-specific core operating limits to the Core Operating Limits Report (COLR) as proposed by this license amendment request, including the nuclear heat flux hot channel factor Nlimit (F ), the nuclear enthalpy rise hot channel factor limit (F A,), the axial power imbalance protective limits, and the trip setpoinE for nuclear overpower based on RCS flow, is an administrative change and will not impact the methodology used to determine the limits. Further, the NRC SER associated with approval of BAW-10179P explicitly includes these limits among those that may be placed in the COLR. Accordingly, there is no adverse effect on safety. The proposed changes to the Bases, TS 6.5.1.6, TS 6.7, TS 6.9.1.7 and the TS Index are also administrative changes and have no adverse effect on safety.

Docket Number 50-346 License Number NPF-3 Serial Number 2197 Attachment Page 4 SIGNIFICANT HAZARDS CONSIDERATION: The Nuclear Regulatory Commission has provided standards in 10CFR 50.92 (c) for determining whether a significant hazard exists due to a proposed amendment to an Operating License for a facility. A proposed amendment involves no significant hazards if operation of the facility in accordance with the proposed changes would: (1) Not involve a significant increase in the probability or consequences of an accident previously evaluated; (2) Not create the possibility of a new or different kind of accident from any previously evaluated; or (3) Not involve a significant reduction in a margin of safety. Toledo Edison has reviewed the proposed changes and determined that a significant hazards consideration does not exist because operation of the Davis-Besse Nuclear Power Station in accordance with these changes would: la. Not involve a significant increase in the probability of an accident previously evaluated because no accident initiators, assumptions or probabilities are affected by the proposed relocation of cycle-specific core operating limits to the Core Operating Limits Report. lb. Not involve a significant increase in the consequences of an accident previously evaluated. The proposed changes do not affect any equipment, accident conditions, or assumptions which could lead to a significant increase in radiological consequences. 2a. Not create the possibility of a new kind of accident from any accident previously evaluated because no new accident initiators are introduced by these proposed changes. 2b. Not create the possibility of a different kind of accident from any accident previously evaluated because no different accident initiators are introduced by these proposed changes.

3. Not involve a significant reduction in a margin of safety because the proposed changes only relocate cycle-specific core operating limits to the Core Operating Limits Report; they do not allow less conservative operating limits. The analytical methods to be used in the determination of cycle-specific core operating limits are previously approved by the NRC. The same margin of safety provided in the current Technical Specifications will continue to be maintained.

CONCLUSION: On the basis of the above, Toledo Edison has determined that the License Amendment Request does not involve a significant hazards consideration. As this License Amendment Request concerns proposed changes to the Technical Specifications that must be reviewed by the" Nuclear Regulatory Commission, this License Amendment Request does not constitute an unreviewed safety question. ATTACHMENT: Attached are the proposed marked-up changes to the Operating License.

Docket Number 50-346 License Number NPF-3 Serial Number 2197 Attachment Page 5 INDEX ADMINISTRATIVE CONTROLS SECTION PAGE Meeting Frequency ........................................ 6-9 Quor=u ............................................. 6-9 Review .................................................... 6-10 Audits ...... ........................................... 6-11 Authority ................................................. 6-12 Records ........................................ 6-12 6.5.3 Technical Review and Control .............................. 6-12 6.6 REPORTABLE EVENT ACTION ........................................ 6-12a 6.7 SAFETY LIMIT VIOLATIOJ .... 6-13 6.8 PROCEDURES AND PROGRAMS ......................................... 6-13 6.9 REPORTING REQUIREMENTS 6.9.1 Routine Reports...................................... 6-14C 6.9.2 Special Reports ......... ................. .......... 6-18 6.10 RECORD RETENTION ....................... ...................... 6-18 6.11 RADIATION PROTECTION PROGRAM ................................. 6-20 6.12 HIGH RADIATION AREA ..................................... 6-20 6.13 ENVIRONMENTAL QUALIFICATION............................... 6-21 6.14 PROCESS CONTROL PROGRA PCP) ................................. 6-22 6.1S OFFSITE DOSE CALCULATION MANUAL (00CM() ........... .......... 6-22 DAVIS-BESSE, UNIT I XVI S Amendment No.  ;,8912,170

Docket Number 50-346 License Number NPF-3 Serial Number 2197 Attachment Page 6 2.0 SAFETY LIMITS AND LIMITING SAFETY SYSTEM SETTINGS 2.1 SAFETY LIMITS REACTOR CORE 2.1.1 The combination of the reactor coolant core outlet pressure and outlet temperature shall not exceed the safety limit shovn in Figure 2.1-1. APPLICABILITY: MODES 1 and 2. ACTION: Whenever the point defined by the combination of reactor coolant core outlet pressure and outlet temperature has exceeded the safety limit, be in HOT STANDBY vithin one hour. REACTOR CORE eemtV 2.1.2 The combinationf eaor THERtMAL POME and AXIAL POVER IMBALANCE shall not exceed theje~ ' limit shovn In fv .- 2 for the various combinations of three and four reactor coolant pump operation. ATPLICABMITY: MODE 1. *4f-c.oK.E o£ A77'..)C¶.I ACTION: Whenever the point defined by the combination of Reactor Coolant System flav, AXIAL !VRIMBALANCE and THERMAL POVER has exceeded the appropriat t.& be in HOT STANDBY vithin one hour. REACTOR COOLANT SYSTEM PRESSURE 2.1.3 The Reactor Coolant System pressure shall not exceed 2750 psig. APPLICABILITY: MODES 1, 2, 3, 4 and 5. ACTION: MODES 1 and 2 - Vhenever the Reactor Coolant System pressure has exceeded 2750 psig, be in HOT STANDBY vith the Reactor Coolant System pressure vithin its limit vithin one hour. MODES 3, 4 - henever the Reactor Coolant System pressure has and 5 exceeded 2750 psig, reduce the Reactor Coolant System pressure to vithin its limit vithin 5 minutes. DAVIS-BESSE, UNIT 1 2-1

Docket Number 50-346 License Number NPF-3 Serial Number 2197 Attachment IX 4At tfl44 t4 C-Page 7 Figure 2.1-2 Reactor Core 120 (-44.0, (-49.0,100.0) 3 PUMP LIMIT (47.1,87.2) (-49.0,78.0) UNACCEPTABLE UNACCEPTABLE OPERATION ACCEPTABLE OPERATION OPERATION FOR SPECIFIED RC PUMP COMBINATION 40 20

                     -40           -20           0         20          40           60 AXIAL POWER IMBALANCE, %

Required Measured Flow to Ensure Reactor C:olant Flow. gpm Compliance, gpm 380.000 389.500 3 293.860 290,957 DAVIS-BESSE, UNIT I 2-3 Amendment No.-11,16, 33, 45, 61, 80, 91,123

Docket Number 50-346 License Number NPF-3 Serial Number 2197 Attachment Page 8 THIS PAGE PROVIDED FOR INFORMA1ION ONLY SAFETY LIMITS AND LIMITING SAFETY SYSTEM SETTINGS I 2.2 LIMITING SAFETY SYSTEM SETTINGS REACTOR PROTECTION SYSTEM SETPOINTS 2.2.1 The Reactor Protection System instrumentation setpoints shall be set consistent with the Trip Setpoint values shown in Table 2.2-1. APPLICABILITY: As shown for each channel in Table 3.3-1. ACTION: With a Reactor Protection System instrumentation setpoint less conserv-ative than the value shown in the Allowable Values column of Table 2.2-1, declare the channel inoperable and apply the applicable ACTION statement requirement of Specification 3.3.1.1 until the channel is restored to OPERABLE status with its trip setpoint adjusted consistent with the Trip Setpoint value. DAVIS-BESSE, UNIT 1 2-4

P. En r." 0 0 P1 0Cuo0 00 ro r0i-. Cu 0

                                                                                                                                 \0         M Pr t0 0MCu LA w/                         Table 2.2-1 Reactor Protection System Instrumehtation Trip Setpoints IA LA M      U*M Functional unit                            Trip setpoint                          Allovable values Hot applicable.                                                                                  t   ,

1. Manual reactor trip Hot applicable.

2. HIgh flux (104.94% of RATED THERMAL POVER vith (104.94% of RATED THERMAL POVER vith lour pumps operating lour pumps operatingi

                                           <80.6% of RATED THERMAL POWER vith           (80.6X of RATED THERMAL POVER with three pumps operating                        three pumps operatingi

3. RC high temperature <618*F 5618"PI N'

l. 4. Flux -- &lux/floV( 1 )

S. RC lov pressure~1 )

6. RC high pressure K >1900.0 psig

                                           <2355 psig 11900.0 paig* >1900.0 psIg**

j2355.0 psigk (2355.0 pslgA* C, 0

0. 7. RC pressure-temperasture(l >(16.0 Tout of - 7957.5) psig >(16.00 Tout p - 7957.5) pslgi

~..

0

     ~~1  8. High flux Tmber of RC         <55;1% of RATED THERHAL OVER vA th           (55.12 of RATED THERMAL ?OVER with 0-pumps on                      ;ne pump operating in each loop              one pump operating in each loopi 0

- I-i, <0.02 of RATED THERHAL POWER vith <0.0z of R.TED THERMAL POWERvith tvo pumps operating in one loop and tvo pumps operating in one loop and no pumps operating in the other loop no pumps operating In the other loopi

                                            <0.0% of RATED THERHAL POlER vithi no
                                                                                      )   <0.0% of RATED THERMAL POVER vith no pumps operating or only one pump             pumps operating or only one pump op-operating                                    eratinge

9. Containment pressure high (4 psIg S4 psigl G lii { I. " ff;4s .

4 4 Pmpt0W&'4/C V4'Ut.~. M04Sý 1

                                           .       k ..*
                                                 ,'4          OPMATIficD wA 4'TS           pt fdM0A eO.

R 0Krfv46W R.'P ItIfJ -Are.Ce- P1/1

M rt M - 0 00 c-I. 0 0 Table 2.2-1. (Cont'd) 0M

                               >                                                                                          rt (o)Trip may be manually bypassed vhen RCS pressure <1820 psig by actuating shutdown bypass provided that:           50 V1                                                                                                                  M   VM

a. The high flux trip setpoint Is <5Z of RATED THERMAL POWER. - N

b. The shutdown bypass high pressure trip setpoint of <1820 psig is imposed. 4 .

c. The shutdown bypass is removed vhen RCS pressure >1820 psig.

    *Allovable value for CHANNEL FUNCTIONAL TEST.
   **Allovable value for CHANNEL CALIBRATION.
                                                                        )

lAllovable value for CHANNEL FUNCTIONAL TEST and CHANNEL CALIBRATION. 0.. ICOD r9 h. LA

Docket Number 50-346 License Number NPF-3 Serial Number 2197 Attachment 4 %44- r'Cr 1 19C4--- W I Page 11

                                                                                                 %t I-Figure 2.2-1     Trip Setpoint for Flux  --   tFlux/Flow
                             % RATED THERMAL POWER UNACCEPTABLE                                   UNACCEPTABLE OPERATION                                      OPERATION-120                           Cu      shows trip

(-17.0,108.0) (,17.0,108.0) ýE oint for an proximately Mi=+I..0 25% flow reduc-tion for three pump operation (-30.6,94.4) (283.860 gpm). The actual set-Point will be calculated by tile Reactor Protection (30.6,77.1 ) System and will be (-30.6,67.0) directly propor-

                          !                                                tional to the I                                               actual flow with three pumps.

(30.6,49.7) I

                   -40         -20        0         20         40        60           80 AXIAL POWER IMBALANCE. %                                                I' 2-7                   Amendment No. 11. 16,       33, DAVIS-BESSE,  UNIT 1 45, 61, 80, 91.123

Docket Number 50-346 License Number NPF-3 Serial Number 2197 Attachment Page 12 2.1 SAFETY LIMITS BASES 2.1.1 AND 2.1.2 REACTOR CORE The restrictions of this safety limit prevent overheating of the fuel cladding and possible cladding perforation which would result in the release of fission products to the reactor coolant. Overheating of the fuel cladding is prevented by restricting fuel operation to within the nucleate boiling regime where the heat transfer coefficient is large and the cladding surface temperature is slightly above the coolant saturation temperature. Operation above the upper boundary of the nucleate boiling regime would result in excessive cladding temperatures because of the onset of departure from nucleate boiling (DNB) and the resultant sharp reduction in heat transfer coefficient. DNB is not a directly measurable parameter during operation and therefore THERMAL POWER and Reactor Coolant Temperature and Pressure have been related to DNB using critical heat flux (CHF) correlations. The local DNB heat flux ratio, DNBR, defined as the ratio of the heat flux that would cause DN8 at a particular core location to the local heat flux, is indicative of the margin to DNi. The B&W-2 and BWC CHF correlations have been developed to predict DNB for axially uniform and non-uniform heat flux distributions. The B&W-2 correlation applies to Mark-B fuel and the BWC correlation applies to all B&W fuel with zircaloy spacer grids. The minimum value of the DNBR during steady state operation, normal operational transients, and anticipated transients is limited to 1.30 (B&W-2) and 1.18 (BWC). The value correspond!; to a 95 percent probability at a 95 percent confidence level that DNB will not occur and is chosen as an appropriate margin to DNB for all operating conditions. The curve presented in Figure 2.1-1 represents the conditions at which a minimum DIBR equal to or greater than the correlation limit is predicted for the maximum possible thermal power 112% when the reactor coolant flow is 380,000 GPM, which is approximately 108% of design flow rate for four operating reactor coolant pumps. (The minimum reuired measured flow is 389,500 GPM). This curve is based on the _channe factor with potential fuel densification and fuel rod bowing effectsQ-- FH -2.8 F.N - 1 rNZ r71; I AS The design limit power peaking factors are the most restrictive calculated at full power for the range from all control rods fully withdrawn to minimum allowable control rod withdrawal, and form the core DNBR design basis. DAVIS-BESSE, UNIT I B 2-1 Amendment No. , 149

Docket Number 50-346. License Number NPF-3 Serial Number 2197 Pa ge 13 The CORE OPERATING LIMITS REPORT includes curves for protective limits for AXIAL POWER IMBALANCE and for nuclear overpower based on reactor coolant system flow. A protective limit is a cycle-specific limit that ensures that a safety limit is not exceeded by requiring operation Within both the cycle design (operating) limits and the Reactor Protection System SAFETY LIMITS setpoints. These protective limit curves reflect BASES The.........o Figur P. - 2 a,-e* bae-ftthe more restrictive of two thermal limits and account for the effects of potential fuel densificatlon and potential fuel rod bo- ' Oa Sp'A

                                                                          'C*.see A T t(, a.    ' .i, 4i(,   ',7 o. .Ap "F:*.=

Sa" I. The DNBR limit produced by a nuclear power peaking factor ef- . or the combination of the radial peak, axial peqak and position of the axial peak that yields no less than the DNBR limit. The combination of radial and axial peak that causes central fuel melting at the hot spot. .4h. Wit.- , " e8.S Wft.f'r a.. -. feei i. th:- eare. -e, K

 *1*1 Power peaking is not a directly observable quantity and therefore limits have been established on the basis of the reactor power Imbalance produced by the power peaking.

The specified flow rates for the twe euryes of-;49v*e49: orres ond nd the analyzed minimm.flow rates with four pumps and three pumps, respectively. e ec v The curve of Figure 2.1-1 is the most restrictive of all possible reactor r e a ct r ur 2 I coolant The curves pump-maximum thermal2.1power of BASES Figure combinations represent showt-An af-which the conditions BASES Figure a minimum2.1.tlum i ni DNBR equal to the DNBR limit is predicted at the maximum possible t h 7ea bhe thermal m power for the number of reactor coolant pumps in operationBASmp or thei localr I0s0 ocal 0m e'y. res pond i ng DNB quality at the point of minimum DNBR is equal to the corresponding DNS correlation quality limit. (+22% (S&W-2) or +26% (BWC)), whichever condition I is more restrictive. T k tow liz P _7

                               -,r,,

01.1 S CPO g 41 rC I i3+C 4 t;,. T)"&jv;n LJMP'rS

                                                                         +4-, "PO9'r.

op-CrO41-4 r. e-7 C19 C-oa C>,#,cAA7ItJ& LIM 17-S f-CP01 cvý,ves A,

              \  JeA4ýt{r- .AYiAL PQL.W-' Ifr7IAL,4r.jCE 0-icl 4 oVerfowt.C-     ba..scJ or- rrc~r           Coo0-nts
                                                                ýr     S7 or iue.r
                                                                               .t'/       o DAVIS-BESSE. UiUIT 1                 B 2-2                    Amendment N~o-17*I    ,.q

(

Docket Number 50-346 License Number NPF-3 Serial Number 2197 Attachment 1THIS PAGE PROVIDED SAFETY LIMITS FOR INFORMATION Oflf BASES For the curve of BASES Figure 2.1, a pressure-temperature point above and to the left of the curve would result in a DONBR greater than 1.30 (B&W-2) or 1.18 (BWC) and a local quality'at the point of minimum DNBR less than

      +22% (B&W-2) or +26% (BWC) for that particular reactor coolant pump situation.,

The DNBR curve for three pump operation is less restrictive than the four pump curve. 2.1.3 REACTOR COOLANT SYSTEM PRESSURE The restriction of this Safety Limit protects the integrity of the. Reactor Coolant System from overpressurization and thereby prevents the release of radionuclides contained in the reactor coolant from reaching the containment atmosphere. The reactor pressure vessel and pressurizer are designed to Section III of the ASME Boiler and Pressure Vessel Code which permits a maximum transient pressure of 110%, 2750 psig, of design pressure. The Reactor Coolant System piping, valves and fittings, are designed to ANSI B 31.7, 1968 Edition, which permits a maximum transient pressure of 110%, 27SO psig. of component design pressure. The Safety Limit of 2750 psig is therefore consistent with the design criteria and associated code requirements. The entire Reactor Coolant .System is hydrotested at 3125 psig, 125% of design pressure, to demonstrate integrity prior to Initial operation. DAVIS-BESSE, UNIT I B 2-3 Amendment No. ),.,,M 149

Docket Number 50-346 License Number NPF-3 .Serial Number 2197 ,Attachment PTHIS PAGE PROVIDED FOR INFORMATION ONlY 2.2 LIMITING SAFETY SYSTEM SETTINGS BASES 2.2.1 REACTOR PROTECTION SYSTEM INSTRUMENTATION SETPOINTS The reactor protection system instrumentation trip setpoints specified in Table 2.2-1 are the values at which the reactor trips are set for each param.- eter. The trip setpoints have been selected to ensure that the reactor core and reactor coolant system are prevented from exceeding their safety limits. The shutdown bypass provides for bypassing certain functions of the reactor protection system in order to permit control rod drive tests, zero power PHYS-ICS TESTS and certain star.'-uo and shutdown procedures. The purpose of the shutdown bypass high press *e trip is to prevent normal operation with shut-down bypass activated. TI high pressure trip setpoint is lower than the normal low pressure trip ser;zoint so that the reactor must be tripped before the bypass is initiated. The high flux trip setpoint of <5.0% prevents any significant reactor power from being produced. Sufficient natural circula-tion would be available to remove 5.0% of RATED THERMAL POWER if none of the reactor coolant pumps were operating. Manual Reactor Trip The manual reactor trip is a redundant channel to the automatic reactor protec-tion system instrumentation channels and provides manual reactor trip capabil-ity. High Flux A high flux trip at high power level (neutron flux) provides reactor core pro-tection against reactivity excursions which are too rapid to be protected by temperature and pressure protective circuitry. During normal station operation, reactor trip is initiated when the reactor power level reaches 104.94% of rated power. Due to transient overshoot, heat balance, and instrument errors, the maximum actual power at which a trip would be actuated could be 112%, which was used in the safety analysis. DAVIS-BESSE. UNIT I B 2-4 Amendment No. Aý, 61

Docket Number 50-346 License Number NPF-3 Serial Number 2197 Attachment Page 16 LIMITING SAFETY SYSTEM SETTINGS BASES RC High Temperature The RC high temperature trip < 61ThF prevents the reactor outlet temperature from exceeding the design limits, and acts as a backup trip for all power excursion transients. Flux -- &Flux/Flow The power level trip setpoint produced by the reactor coolant system flow is based on a flux-to-flow ratio which has been established to accommodate flow decreasing transients from high power where protection is not provided by the high flux/number of reactor coolant pumps on trips. The power level trip setpoint produced by the power-to-flow ratio provides both high power level and low flow protbction in the event the reactor power level increases or the reactor coolant flow rate decreases. The power level setpoint produced by the power-to-flow ratio provides overpower DNB protection for all modes of pump operation. For every flow rate there is a maximum permissible power level, and for every power level there is a minimum ermissible low flowrate.

   -- Examples ot typca- power level and low flow rate combinations for pump situations of Table 2.2-1 that would result in a trip ar follows:

1. Trip would occur when four reactor coolant ps are operating if power is 108.0% and reactor coolant fl ate is 100% of full flow rate, or flow rate is 92.59% of f low rate and power level is 100%.

2. Trip would occ en three reactor coolant pumps are operating if power is  % and reactor coolant flow rate is 74.7% of full flow ra r flow rate is 69.44% of full flow rate and power is 75%.

ote that the value of 80.6% in Figure 2.2-1 was truncated from the calculated value of 80.68%. For safety calculations the instrumentation errors for the power level were used. Full flow rate 4m thc boe" to-e--.Te,:r is defined as the flow calculated by the heat balance at 100% power. At the time of the calibration the RCS flow will be greater than or equal to the value in Table 3.2-2. DAVIS-BESSE, UNIT I B 2-5 Amendment No. 76, 33,4,J7,00, 123

Docket Number 50-346 License Number NPF-3 Serial Number 2197 Attachment Page 17 LIMITING SAFETY SYSTEM SETTINGS BASES The AXIAL POWER IMBALANCE boundaries are established in order to prevent reactor thermal limits from being-exceeded. These thermal limits are either power peaking kW/ft limits or DNBR limits.- The AXIAL POWER IMBALANCE reduces, the power level trip produced by a flux-to-flow ratio such that the boundaries of *r*roduc d. iI_ 7 Ze 0P4 P-A7tlA3C. IJu I TIS P.Ej0AEif CýC-JA W RC Pressure - Low, High, and Pressure Temperature The high and low trips are provided to limit the pressure range in which reactor operation is permitted. During a slow reactivity insertion startup accident from low power or a slow reactivity insertion from high power, the RC high pressure setpoint is reached before the high flux trip setpoint. The trip setpoint for RC high pressure, 2355 psig, has been established to maintain the system pressure below the safety limit, 2750 psig, for any design transient. The RC high pressure trip is backed up by the pressurizer code safety valves for RCS over pressure protection, and is therefore set lower than the set pressure for these valves,

    < 2525 psig. The RC high pressure trip also backs up the high flux trip.

The RC low pressure, 1900.0 psig, and RC pressure-temperature (16.00 Tout - 7957.5) psig, trip setpoints have been established to maintain the DNB ratio greater than or equal to the minimum allowable DNB ratio for those design accidents that result in a pressure reduction. It also prevents reactor operation at pressures below the valid range of DNB correlation limits, protecting against DNB. High Flux/Number of Reactor Coolant Pumps On In conjunction with the flux - aflux/flow trip the high flux/number of reactor coolant pumps on trip prevents the minimum core DNBR from decreasing below the minimum allowable DNB ratio by tripping the reactor due to the loss of reactor coolant pump(s). The pump monitors also restrict the power level for the number of pumps in operation. DAVIS-BESSE, UNIT 1 B 2-6 Amendment No. U,0.60.07. 149

Docket Number 50-346 License Number NPF-3 Serial Number 2197 Attachment Page 18 THIS PAGE PROVIDED FOR INFORMATION ONLY LIMITING SAFETY SYSTEM SETTINGS BASES Containment High Pressure

                    .The Containment High Pressure Trip Setpoint <.4 psig, provides positive assurance that a reactor trip will occur-in the unlikely event of a steam line failure in the containment vessel or a loss-of.-

coolant accident, even in the absence of a RC Low Pressure trip. ( BAVIS-BESSE, UNIT - B 2-7

Docket Number 50-346 License Number NPF-3 Serial Number 2197 Attachment Page 19 lPOLI.E DISTRIBU'TION LIMITS

       !JCLZ~A*   K     FLUX HOT CHA2.*MEL FACTOR -  F0 LIM'UITT.G COhDITION 7OR OPERATION F                  i.2.2 by the following reIatIo ited                                 a:
                *              ~~POWE£R           <   "
     'AI.TCA!.ILITY: MODE I ACTION:

With FQ exceeding its limit:

a. Reduce TH*MAL POWER at least 12 for each 12 FQ exceeds the limit within 15 minuces and5+/-imilarly reduce the high flux trip setpoint and flux-6 flux-flow trip setpoint within 4 hours.

b. Demonstrate through incore mapping that i0 within its

                                                             -is             iimit within 24 hours after     exceeding the limit or reduce TH'MAL POWER to less than 52 of RAM TRY.AL POWER within the next 2 hours.

c. Identify and correct the cause of the out of limit condition prior to in-creasing THERMAL POWER above the reduced limit required by a or b. above; subsequent POWER OPURATION may proceed provided that F0 is demonstrated through incore mapping to be within Its limit 'at a nominal 50% of RATED TH*E*MAL POER prior to excreding this THERMAL POWER., at a nominal 752 of T

RAME THXAL POWIER prior to exceeding this THEMMAL POWER and within 24 hours after attaining 95% or greater RATED THZLR1aL POWER. jSvnL'VhLAYCz REQuaIR.YTS 4.2.2.1 F shall be decermined to be within its limit by using the incore

   !detectors       rS obtain a power distribution map:

DAVIS-BESSE. UKIT I 3/4 2-.5 Amendment No. 45

Docket Number 50-346 License Number NPF-3 Serial Number 2197 Attachment Page 20 THIS PAGE PROVIDED POWER DISTRIBUTION LIMITS FOR INFORMATION ONlY SURVEILLANCE REQUIREMENTS (Continued)

a. Prior to initial operation above 75 percent of RATED THERMAL POWER after each fuel loading, and

b. At least once per 31 Effective Full Power Days.

c. The provisions of Specification 4.0.4 are not applicable.

4.2.2.2 The measured F of 4 2.2.1 above, shall be increased by 1.4% to account for manufactsring tolerances and further Increased by 7.5% to account for measurement uncertainty. DAVIS-BESSE. UNIT 1 3/4 2-6

Docket Number 50-346 License Number NPF-3 Serial Number 2197 Attachment Page 21 POWER DISTRIBUTION LIMITS NUCLEAR EFATHALPY RISE HOT CHANNEL FACTOR FN LIMITING CONDITION FOR OPERATION

                                        ~4'     i""'   4    7P

• 4 r'V fL CoA.E 0 ~tTl' 3.2.3 shall be imited by the following re"a.tions h-FAAI <IM 1.71 [1 0.6(1-P) where P - ER PPOW1. THEMA APPLICABILITY: MODE 1.

ACTION: WithFN N exceeding its limit:

a. Reduce THERMAL POWER at least 1% for each le that F exceeds the limit within 15 minutes and similarly reduce the HieN Flux Trip Setpoint and Flux - aFlux - Flow Trip Setpoint within 4 hours.

b. Demonstrate through in-core mapping that FN is within its limit within 24 hours after exceeding the limit Or reduce THERMAL POWER to less than 5% of RATED THERMAL POWER within the next 2 hours.

c. Identify and correct the cause of the out of limit condition prior to increasing THERMAL POWER above the reduced limit required by a or b, aboNe; subsequent POWER OPERATION may proceed provided that FH is demonstrated through in-core mapping to be within it limit at a nominal 50o of RATED THERMAL POWER prior to exceeding this THERMAL POWER, at a nominal 75% of RATED THERMAL POWER prior to exceeding this.

THERMAL POWER and within 24 hours after attaining 95% or greater RATED THERMAL POWER. DAVIS-BESSE, UNIT 1 3/4 2-7

Docket Number 50-346 License Number NPF-3 Serial Number 2197 Attachment Page 22 THIS PAGE PROVIDED POWER DISTRIBUTION LIMITS FOR INFORMATION tiNtY SURVEILLANCE REOUIREMENTS 4.2.3.1 Fa shall be determined to be vithin its limit by using the incore detectors to obtain a pover distribution maps

a. Prior to operation above 75 percent of RATED ThERMAL POVER after each fuel loading, and

b. At least once per 31 Effective Full Pover Days.

c. The provisions of Specification 4.0.4 are not applicable.

4.2.3.2 The measured FNS of 4.2.3.1 above, shall be increased by 5Z for measurement uncertainty. DAVIS-BESSE, UNIT 1 3/,4 2-8 Amendment No. 135

Docket Number 50-346 License Number NPF-3 Serial Number 2197 Attachment Page 23 THIS PAGE PROVIDED 3/4.2 POWER DISTRIBUTION LIMITS FOR INFORMATION ONlY BASES he specifications of this section provide assurance of fuel integrity during Condition I (normal operation) and IT (incidents of moderate frequency) events by: (a) maintaining the minimum DNBR in the core > the minimum allowable DNB ratio during normal operation and during short tern transients, (b) maintaining the peak linear power density . 18.4 kW/ft during normal operation, and (c) maintaining the peak power density less than the limits given in the bases to specification 2.1 during short term transients. In addition, the above criteria must be met in order to meet the assumptions used for the loss-of-oolant accidents. he power imbalance envelope and the insertion limit curves defined in the CORE PERATING LIMITS REPORT are based on LOCA analyses which have defined the ximum linear heat rate such that the maximum clad temperature will not exceed the Final Acceptance Criteria of 2200*F following a LOCA. Operation outside f the powerimbalance envelope alone does not constitute a situation that ould cause the Final Acceptance Criteria to be exceeded should a LOCA occur. he power imbalance envelope represents the boundary of operation limited by the Final Acceptance Criteria only if the control rods are at the insertion limits, as defined in the CORE OPERATING LIMITS REPORT -and if the steady-state limit QUADRANT POWER TILTvexists. Additional conservatism is introduced by pplication of:

a. Nuclear uncertainty factors.

b. Thermal calibration uncertainty.

c. Fuel densification effects.

d. Hot rod manufacturing tolerance factors.

e. Potential fuel rod bow effects.

the ACTION statements which permit limited variations from the basic require-ments are accompanied by additional restrictions which ensures that the original criteria are met. The definitions of the design limit nuclear power peaking factors as used in these specifications are as follows: FQ Nuclear heat flux hot channel factor, is defined as the maximum local fuel rod linear power density divided by the average fuel rod linear power density, assuming nominal fuel pellet and rod dimensions. DAVIS-BESSE, UNIT 1 B 31A 9p- + &^ 7, ,,. 149q cf.. 110

Docket Number 50-346 License Number NPF-3 Serial Number 2197 Attachment Page 24 POWER DISTRIBUTION LIMITS BASES F ,N Nuclear Enthalpy Rise Hot Channel Factor, is. defined as the ratio of the integral of linear power along the rod on which minimum ONBR occurs to the average rod power. It has been determined by extensive analysis of possible operating power shapes that the design limits on nuclear power peaking and on minimum DNBR at full power are me *l 4 b"*yor'9l,4wie Wiý P:Po+d

            -N....    .t  - ...             4t    of a, r ,+A GuM;t'r #A, Power peaking is not a directly observable quantity and therefore limits have been established on the bases of the AXIAL POWER IMBALANCE produced by the power peaking. It has been determined that the above hot channel factor lim-its will be met provided the following conditions are maintained.

1. Control rods in a single group move together with no individual rod in-sertion differing by more than +6.5% (indicated position) from the group average height.

2. Regulating rod groups are sequenced with overlapping groups as required in Specification 3.1.3.6.

3. The regulating rod insertion limits of Specification 3.1.3.6 are main-tained.

4. AXIAL POWER IMBALANCE limits are maintained. The AXIAL POWER IMBALANCE is a measure of the differencein power between the top and bottom halves of the core. Calculations of core average axial peaking factors for many plants and measurements from operating plants under a variety of operat-ing conditions have been correlated with AXIAL POWER IMBALANCE. The cor-relation shows that the design power shape is not exceeded if the AXIAL POWER IMBALANCE is maintained between the limits specified in Specifica-tion 3.2.1.

The design limit power peaking factors are the most restrictive calculated at full power for the range from all control rods fully withdrawn to minimum al-lowable control rod insertion and are the core DNBR design basis. Therefore, for operation at a fraction of RATED THERMAL POWER, the design limits are met. When usang incore detectors to make power distribution maps to deter-mine FQ and FýH:

a. The measurement of total peaking factor F*eas shall be increased by 1.4 percent to account for manufacturing tole 9 ances and further increased by 7.5 percent to account for measurement error.

DAVIS--BESSE, UNIT I B 3/4 2-2 Amendment No. ;j, 61

Docket Number 50-346 License Number NPF-3 Serial Number 2197 Attachment Page 25 THIS PAGE PROVIDED POWER DISTRIBUTION LIMITS FOR INFORMATION ONlY BASES

b. The measurement of enthalpy rise hot channel factor, FNH shall be increased by 5 percent to account for measurement erroP.

For Condition II events, the core is protected from exceeding the values given in the bases to specification 2.1 locally, and from going below the minimum allowable DNB ratio by automatic protection on power, AXIAL POWER IMBALANCE pressure and temperature. Only conditions I through 3, above, are mandatory since the AXIAL POWER IMBALANCE is an explicit input to the reactor protection system. The QUADRANT POWER TILT limit assures that the radial power distribution satisfies the design values used in the power capability analysis. Radial power distribution measurements are made during startup testing and periodically during power operation. The QUADRANT POWER TILT limit at which corrective action is required provides DNB and linear heat generation rate protection with x-y plane power tilts. In the event the tilt is not corrected, the margin for uncertainty on F0 is reinstated by reducing the power by 2 percent for each percent of tiMt in excess of the limit. 3/4.2.5 DNB PARAMETERS The limits on the DNB related parameters assure that each of the parameters are maintained within the normal steady state envelope of operation assumed in the transient and accident analyses. The limits are consistent with the FSAR initial assumptions and have been analytically demonstrated adequate to main-tain a minimum DNBR greater than the minimum allowable DNB ratio throughout each analyzed transient. The 12 hour periodic surveillance of these parameters through instrument read-out is sufficient to ensure that the parameters are restored within their limits following load changes and other expected transient operation. The 18 month periodic measurement of the RCS total flow rate using delta P instrumenta-tion is adequate to detect flow degradation and ensure correlation of the flow indication channels with measured flow such that the indicated percent flow will provide sufficient verification of flow rate on a 12 hour basis. DAVIS-BESSE, UNIT 1 B 3/4 2-3 TAmendment No. A,A,149

Docket Number 50-346 License Number NPF-3 Serial Number 2197 Attachment Page 26 THIS PAGE PROVIDED 3/4.4 REACTOR COOLANT SYSTEM fO INF RMATION ONY 3/4.4.1 COOLANT LOOPS AND COOLANT CIRCULATION STARTUP AND POWER OPERATION LIMITING CONDITION FOR OPERATION 3.4.1.1 Both reactor coolant loops and both reactor coolant pumps in each loop shall be In operation. APPLICABILITY: MODES 1 and 2*. ACTION:

a. With one reactor coolant pump not in operation, STARTUP and POWER OPERATION may be initiated and may proceed provided THERMAL POWER is restricted .to less than 80.6% of RATED THERMAL POWER and within 4 hours the setpoints for the following trips have been reduced in accordance with Specification 2.2.1 for operation with three reactor coolant pumps operating:

1. High Flux

2. Flux-aFlux-Flow SURVEILLANCE REQUIREMENTS 4.4.1.1.1 The above required reactor coolant loops shall be verified to be in operation and circulating reactor coolant at least once per 12 hours.

4.4.1.1.2 The Reactor Protection System trip setpoints for the instrumenta-tion channels specified in the ACTION statement above shall be verified to be in accordance with Specification 2.2.1 for the applicable number of reactor coolant pumps operating either:

a. Within 4 hours after switching to a three pump combination if the switch is made while operating, or

b. Prior to reactor criticality if the switch is made while shut-down.

        *See Special Test Exception 3.10.3.

DAVISIBESSE. UNIT 1 3/4 4-1 Amendment No. 76,M3.0, lZ, 135

Docket Number 50-346 License Number NPF-3 Serial Number 2197 Attachment *I" in Page 27 VL ADMINISTRATIVE CONTROLS COMPOSITION 6.5.1.2 The Station Review Board (SRB) shall be composed of at least six members of the Davis-Besse onsite management organization. The members shall be as a minimum, managers or individuals reporting directly to managers from each of the following disciplines: plant operations, maintenance, planning, radiological controls, engineering, and quality assurance. The members shall meet the requirements of ANSI N18.1-1971, Sections 4.2, 4.4, or 4.6 for applicable required experience. The SRB Chairman shall be drawn from the SRB members and designated in writing by the Plant Manager. ALTERNATES 6ý5.1.3 All alternate members shall be appointed in writing by the SRB Chairman; however, no more than two alternates shall participate as voting members in SRB activities at any one time. MEETING FREQUENCY 6.5.1.4 The SRB shall meet at least once per calendar month and as convened by the SRB Chairman or his designee. QUORUM 6.5.1.5 A quorum of the SRB shall consist of the Chairman or his designee and four members including ,alternates. RESPONSIBILITIES 6.5.1.6 The Station Review Board shall be responsible for:

a. Review of plant administrative procedures and changes thereto.

b. Review of the safety evaluation for 1) procedures, 2) changes to procedures, equipment or systems, and 3) tests or experiments completed under the provisions of 10 CFR 50.59, to verify that such actions do not constitute an unreviewed safety question.

c. Review of proposed procedures and changes to procedures and equipment determined to involve an unreviewed safety question as defined in 10 CFR 50.59.

DAVIS-BESSE, UNIT I 6-6 Amendment ':o. , W.2, 169

Docket Number 50-346 License Number NPF-3 Serial Number 2197 Attachment Page 28 ADMINISTRATIVE CONTROLS

d. Review of proposed tests or experiments determined to involve an unreviewed safety question as defined in 10 CFR 50.59.

e. Review of reports of violations of codes, regulations, orders, Technical Specifications, or Operating License requirements having nuclear safety significance or reports of abnormal degradation of systems designed to contain radioactive material.

f. Review of all proposed changes to the Technical Specifications or the Operating License.

g. Deleted

h. Review of reports of significant operating abnormalities or devi-ations from normal and expected performance of plant equipment that affect plant safety.

i. Review of the Industrial Security Plan, the Security Training and Qualification Plan, and the Security Contingency Plan, and changes thereto.

j. Review of the Davis-Besse Emergency Plan and changes thereto.

k. Review of items which may constitute potential nuclear safety hazards as identified during review of facility operations.

I. Investigations or analyses of special subjects as requested by the Company Nuclear Review Board. pr.* *evc.. IV .,

m. Review of all REPORTABLE EVENTS. L VOi4+;O. kepo-tS i

n. Review of all Safety Limit Violation Reports (Section 6.7).

o. Review of any unplanned, accidental or uncontrolled radioactive releases, evaluation of the event, ensurance that remedial action is identified to prevent recurrence, review of a report covering the evaluation and forwarding of the report to the Plant Manager and to the CNRB.

p. Review of the changes to the OFFSITE DOSE CALCULATION MANUAL.

q. Review of the changes to the PROCESS CONTROL PROGRAM.

r. Review of the Annual Radiological Environmental Operating Report.

s. Review of the Semiannual Radioactive Effluent Release Report.

T. Review of the Fire Protection Program and changes thereto. DAVIS-BESSE, UNIT 1 6-7 Amendment No. Z,,7 ,93,F?,LZ9, AB,/ ,17 4

Docket Number 50-346 License Number NPF-3 Serial Number 2197 Attachment Page 29 ADMINISTRATIVE CONTROLS 6.7 SAFETY LIMIT VIOLATIO op. 7oC_7'V( L*AIT- VIOLA-r`ot. 6.7.1 The following actions shall be taken in the event a Safety Limit is violated:

a. The facility shall be placed in at least HOT STANDBY within one hour.

b. The Safety Limit violation shall be reported to the NRC Operations Center by telephone as soon as possible and in all cases within one hour. In addition the Vice President, Nuclear and the CNRB shall be notified within 24 hours.

c. A Safety Limit Violation Report shall be prepared. The report shall be reviewed by the SRB. This report shall describe (1) applicable circumstances preceding the violation, (2) effects of the violation upon facility components, systems or structures, and (3) corrective action taken to prevent recurrence.

d. The Safety Limit Violation Report shall be submitted to the Commission, the CNRB and the Vice President, Nuclear within 14 days fI 6.8 PROCEDURES AND PROGRAMS 6.8.1 Written procedures shall be established, implemented and maintained covering the activities referenced below:

a. The applicable procedures recommended in Appendix "A" of Regulatory Guide 1.33, November, 1972.

b.' Refueling operations.

c. Surveillance and test activities of safety related equipment.

d. Industrial Security Plan implementation.

e. Davis-Besse Emergency Plan implementation.

f. Fire Protection Program implementation.

g. The radiological environmental monitoring program.

h. The Process Control Program.

i. Offsite Dose Calculation Manual implementation.

6.8'2 Each procedure of 6.8.1 above, and changes thereto, shall be reviewed and approved prior to implementation as set forth in 6.5.3 above. DAVIS-BESSE, UNIT 1 6-13 Amendment No. , 139

Docket Number 50-346 License Number NPF-3 Serial Number 2197 Attachment Page 30 Insert (TS 6.7.2) 6.7.2 The following actions shall be taken in the event the Protective Limit of Specification 2.1.2 is violated:

a. The facility shall be placed in at least HOT STANDBY within one hour.

b. The Protective Limit violation shall be reported to the NRC Operations Center by telephone as soon'as possible and in all cases within one hour. In addition the Vice President, Nuclear and the CNRB shall be notified within 24 hours.

c. A Protective Limit Violation Report shall be prepared. The report shall be reviewed by the SRB. This report shall describe (1) applicable circumstances preceding the violation, (2) effects of the violation upon facility components, systems or structures, and (3) corrective action taken to prevent recurrence.

d. The Protective Limit Violation Report shall be submitted to the CNRB and the Vice President, Nuclear within 14 days of the violation.

Docket Number 50-346 License Number NPF-3 Serial Number 2197 Attachment Page 31 ADMINISTRATIVE CONTROLS microcuries per gram as a function of time for the duration of the specific activity above the steady-state level; and (5) The time duration specific2.12-when thelimit*_. t~he radioiodine activity of the primary coolant exceeded R [r" 6ore_-* M4ONTHLY OPERATING REPOgRT_ - -w ,*~i, S$ IZ?. C-p4; _____________ -* A-4-aA, sf1, S 1'~~~ 6.9.1.6 Routine reports of operating statistics , shutdown experience and challenges to the Pressurizer Pilot Operated Relief Valve (PORV) and the Pressurizer Code Safety Valves shall be submitted on a monthly basis to arrive no later than the 15th of each month following the calendar month covered by the report, as follows: The signed original to the Nuclear Regulatory Commission, Document Control Desk, Washington, D. C. 20555, and one copy each to the Region III Administrator and the Davis-Besse Resident Inspector. CORE OPERATING LIMITS REPORT I Nu~e,#.4i,/.;.¢ ) C_..'nel IL%- R'. 6.9.1.7 Core operating limits shall be established and documented in the CORE OPERATIRG LIMITS REPORT before each reload cycle and any. remaining part of a reload cycle for the following:

    -3.l).].    .3c       Negative Moderator Temperature Coeffici ent Limit 3.1.3.6            Regulating Rod Insertion Limits 3.1.3.7            Rod Program 3.1.3.8            Xenon Reactivity 3.1.3.9            Axial Power Shaping Rod Insertion Limits 3.2.1              AXIAL POWER IMBALANCE 3.2.4              QUADRANT POWER TILT The analytical methods usea to determine the core operating limits addressed the individual Technical Specifications shall be those previously reviewed approved by the NRC, specifically:

1) BAW-10122A Rev. 1, "Normal Operating Controls," May 19

2) BAW-10116A, "Assemly Calculations and Fitted Nuc r Data," May 1977

3) BAW-10117P-A, "Babcock & Wilcox Version o User's Manual,"

January 1977

4) BAW-10118A, "Core Calculati Techniques and Procedures,"

December 1979

5) BAW-10124A, - A Three-Dimensional Nodal Code for Calculating Core Reactiv and Power Distributions," August 1976

6) BAW- SA. "Verification of Three-Dimensional FLAME Code," August B)AW-10152A, "NOODLE - A Multi-Dimensional Two-Group Reactor Simulator," June 1985 DAVIS-BESSE. UNITA 6-16 Amendment No.

Docket Number 50-346 License Number NPF-3 Serial Number 2197 Attachment Page 32 Insert (TS 6.9.1.7) The analytical methods used to determine the core operating limits addressed by the individual Technical Specifications shall be: those previously reviewed and approved by the NRC, as described in BAW-10179P-A, "Safety Criteria and Methodology for Acceptable Cycle Reload Analyses", or any other new NRC-approved analytical methods used to determine core operating limits that are not yet referenced in the applicable BAW-10179P-A revision. The applicable BAW-10179P-A revision (the approved revision at the time the reload analyses are performed) shall be listed in the CORE OPERATING LIMITS REPORT. The CORE OPERATING LIMITS REPORT shall also list any new NRC-approved analytical methods used to determine core operating limits that are not yet referenced in the applicable BAW-10179P-A revision.

Docket Number 50,346 License Number NPF-3 Serial Number 2197 Attachment Page 33 ADMI1NISTRATIVE CONTROLS CORE OPERATING LIMITS REPORT (Continued) S 8)* - BAW-1O1lg, "Power Peaking Nuclear Reliabi7t*t The methodolo d1 y11,990. gram received NRC approval in the Safety Evaluation) The core operating limits shall be determined so that all applicable limits (e.g., fuel thermal-mechanical limits, core thermal-hydraulic limits, ECCS limits, nuclear limits such as shutdown margin, and transient and accident analysis limits) of the safety analysis are met. The CORE OPERATING LIMITS REPORT, including any mid-cycle revision or supple-ments thereto, shall be provided upon issuance for each reload cycle to the NRC Document Control Desk with copies to the Regional Administrator and Resident Inspector. DAVIS-BESSE, UNIT 1 6-17 Amendment No. 144

NRC ITS Tracking .Page I of 2 Return to View Me~n~u.1 Print Documn RAI Screening Required: Yes Status: Closed This Document will be approved. by: Gerald Regulatory Basis must be included in Comments Waig; Tim Kobetz section of this Form This document has been reviewed and Yes information in this question contains NO SUNSI sensitive material (the checkbox to the right must be selected before this question can be submitted) NRC ITS TRACKING NRC Reviewer ID 200712260943 Conference CallRequested? No Category BSI - Beyond Scope Issue ITS Section: TB POC: JFD Number: Page Number(s): ITS 3.3 Aron Lewin None Information ITS N.unmbclr:. OSI: DOC. Nu-m-ber*: B-ases JFD.Num ber.:. 3.3.8 None None None NRC OSI#52 Discuss how the proposed ITS definition of LOPS operability meets Criterion 21 of 10 CFR 50.36 Appendix A, in that continued operation with one LOPS channel inoperable can result in the loss of protective actions, given a single failure in the remaining channel's undervoltage relay.

Background

The Bases for CTS 3/4.3.1 and 3/4.3.2 (page 396 thru 400 of 490 in the CTS) do not discuss what constitutes operability for a Degraded Voltage Functional Unit (CTS Unit 4.b) and the Loss of Voltage Functional Unit (CTS Unit 4.c). The ITS Bases (page 298 of 636) includes a statement that says a channel is considered operable as long as one of the two undervoltage relays are operable. The ITS Bases (page 296 of 636) also discuss how four undervoltage Comment relays with time.delays are provided on each 4.16 kV essential bus for the purpose of detecting a loss of voltage condition and four undervoltage relays with time delays are provided on each 4.16 kV essential bus for the purpose of detecting a degraded voltage condition. Two undervoltage relays and an auxiliary relay per essential bus are associated with a channel (i.e. two channels for each function per bus). Either undervoltage relay in a channel. will actuate its associated auxiliary relay. The actuation of both auxiliary relays (i.e. two channels for a two-out-of-two logic) will result in protective actions. The STS for LCO 3.3.8 (NUREG-1430) is based on a different design that utilizes a two out of three logic design. Criterion 21 of 10 CFR 50.36 Appendix A states "the protection system shall be designed for high functional reliability and inservice testability commensurate with the safety functions to be performed. Redundancy and http://www.excelservices.com/exceldbs/itstrackdavisbesse.nsf/1 fddcealOd3bdbb585256e... 7/18/2008

NRC ITS Tracking Page 2 of 2 independence designed into the protection system shall be sufficient to assure that (1) no single failure results in loss of the protection function and (2) removal from service of any component or channel does not result in loss of the required minimum redundancy unless the acceptable reliability of operation of the protection system can be otherwise demonstrated. The protection system shall be designed to permit periodic testing of its functioning when the reactor is in operation, including a capability to test channels independently to determine failures and losses of redundancy that may have occurred." J Issue Date 12/26/2007 Close iDat [5/08/2008 Logged in User: Anonymous ' Responses Licensee Response by Bryan See the response for 200712260942. With one undervoltage relay Kays on 03/03/2008 inoperable, the other undervoltage relay in the unit will actuate the associated auxiliary relay. The protective action is still functional. Therefore the channel is still operable. If the single failure is the remaining undervoltage relay in that unit, disabling the protective action for that essential bus, the other essential bus can still perform its function. NRC Response by Aron Lewin Technical Branch assistance formally requested. Issue being on 03/24/2008 tracked by TAC MD8348. N further questions at this time. onNRC0Response by Aron Lewin Date Created: 12/26/2007 09:43 AM by Aron Lewin Last Modified: 05/08/2008 10:38 AM http://www.excelservices.com/exceldbs/itstrackdavisbesse.nsf/1 fddcea 1Od3bdbb585256e... 7/18/2008

NRC ITS Tracking Pagel1 of 2 100Return to View Menua Print Docuen RAI Screening Required: Yes Status: Closed This Document will be approved by: Gerald Regulatory Basis must be included in Comments Waig; Tim Kobetz section of this Form This document has been reviewed and Yes information in this question contains NO SUNSI sensitive material (the checkbox to the right must be selected before this question can be submitted) NRC ITS TRACKING NRC Reviewer ID[ 200712261047 Conference Call Requested? No Category BSI - Beyond Scope Issue ITS Sec.tiond:. TB POC:ý JFD Nunmber.:. P-age Number(s):. ITS 3.3 Aron Lewin Iqbal Ahmed None 287 Information ITS Nm.nber-: OSI: DOC.Number: Bases JFD Number: 3.3.8 1 L.3 None Question submitted by Iqbal Ahmed. Provide model and make information, and instruction leaflet references for each of these two types of relays associated with "EDG Degraded Voltage & Loss of Voltage Relay Channel Check." These are associated with CTS 4.3-2 Functional Units 4.b and 4.c. The proposed TS change to limiting condition for operation (LCO) 3.3.8 is to Commrnente delete every 12-hour channel check surveillance requirement for the Loss of Voltage and degraded voltage Emergency Diesel Generator (EDG) Loss of Power Sequencing (LOPS) instrumentation. These safety functions are performed by voltage relays. The relays can be electro-mechanical or solid state design. This information is needed to ensure adequate surveillance requirements are in place to verify LCO requirements per 10 CFR 50.36. Issue D 12/26/2007 Close Date] 02/27/2008 Logged in User: Anonymous

'Responses Licensee Response by Bryan            The EDG Degraded Voltage and Loss of Voltage Relays model Kays on 01/13/2008                    and make information is as follows: Degraded Voltage Relays -

Model ABB 27N, Style 411T4175-HF-L Loss of Voltage Relays - Model ABB 27N, Style 411T6175-HF The Vendor Manual is provided as an attachment to this response. Licensee Response by Bill Information discussed on the 1/23/08 phone call: Control Power is http://www.excelservices.com/exceldbs/itstrackdavisbesse.nsf/1 fddcea 1Od3bdbb585256e... 7/18/2008

NRC ITS Tracking Page 2 of 2 Bentley on 01/25/2008 required for proper operation of the EDG Degraded Voltage and Loss of Voltage Relays. Control power is 125 VDC from the switchgear control bus and is common to the same circuit providing control power for the associated 4160V bus. There is both local indication and a Control Room Annunciator Window if control power is lost. The Annunciator alarm is 1-6-D, labeled CI/DI CONTROL PWR TRBL. There are two separate inputs to the annunciator system for this window, computer point Q418, ESSEN BUS CI CTRL PWR and Q419 ESSEN BUS DI CTRL PWR. Either of these two inputs will cause the window to alarm. NRC Response by Timothy Kolb Information. supplied by the licensee is sufficient to complete the on 02/27/2008 safety evaluation input. No further questions at this time. This item is closed. Date Created: 12/26/2007 10:47 AM by Timothy Kolb Last Modified: 02/27/2008 10:39 AM http://www.excelservices.com/exceldbs/itstrackdavisbesse.nsf/l fddcealOd3bdbb585256e... 7/18/2008

Davis-Besse Nuclear Power Station Table Of Contents For Vendor Manual E-005-001 54-04 ABB BROWN BOVERI INSTRUCTION MANUAL FOR I-T-E SINGLE VOLTAGE RELAYS Level 1 Approved,-,. FlPackage omplete:. N/A.-Administrative Change Only. F~e~po~i5IbLO Engineer DatepVe pont~~ormCo~ro r Date. . ii T0A Inde2 Vendor and Title BPub No. Rev. Date Pages 00011 213 ABB BROWN BOVARI 11B 18.4.7-2 E 7M/1988 17 INSTRUCTIONS FOR SINGLE-PHASE VOLTAGE RELAYS - UNDERVOLTAGE RELAYS AND, OVERVOLTAGE RELAYS 0002 93-04293 ABB BROWN BOVARI IB 7.7.1.7-8 A 4/1/1987 5 INSTRUCTIONS FOR TEST PLUG UNITS TYPE MT-XC & MT-XV 00031 03-0708 ABB BROWN BOVARI IB 7.4.1.7-7 E 5/1/1996 14 INSTRUCTIONS FOR SINGLE PHASE VOLTAGE RELAYS TYPES 27N & 59N Tuesday, April 05, 2005 Page I of I

Davis-Besse Nuclear Power Station Record of Revision for E-005-00154-04 ABB BROWN BOVERI INSTRUCTION MANUAL FOR I-T-E SINGLE VOLTAGE RELAYS. Submittal Description 04 Reformatting and Baseining of Vendor Manual. VMCN E-005-00154-1: Removed Asea Brown Bovari Instruction Book 18.4.7-2, Issue D and replaced it with Issue E. VMCN E-005-00154-3: Added Asea Brown Bovari Instruction Book IB 7.7.1.7-8, Issue A to back of Manual. VMCN E-005-001 54-4: Removed IB 18.4.7-2, Issue E and replaced it with IB 7.4.1.7-7, Issue E VMCN E-005-00154-7: ACT. 03-0708 makes correction to Instruction Book IB 7.4.1.7.-7 Rev. E Tuesday, April 05, 2005 Page 1

213 ABB BROWN BOVARI INSTRUCTIONS FOR SINGLE-PHASE VOLTAGE RELAYS - UNDERVOLTAGE RELAYS AND OVERVOLTAGE RELAYS 1B 18.4.7-2 Rev. E 7/1/1988 ABBB-0003

ABB ASrA BROWN BOVERI IB 18.4.7-2 Issue E IN STRUCT I ON S Single-Phase Voltage Relays Undervoltage Relays and Overvoltage Relays ITE-27, ITE-27D, ITE-27H Catalog Series 211 Standard Case ITE-27, ITE-27D, iTE-27H Catalog Series 411 Test Case ITE-59D, ITE-59H Catalog Series 211 Standard Case ITE-59D, ITE-59H Catalog Series 411 Test Case ASEA BROWN BOVERI

IB 18.4.7-2 Single-Phase Voltage Relays Page 2 TABLE OF CONTENTS Introduction .................. Page 2 Precautions ................... Page 2 Placing Relay into Service .... Page 2 Application'Data .............. Page 3 Testing ........................ Page 13 INTRODUCTION lhese instructions contain the information required to properly install, operate, and test certain single-phase undervoltage and overvoltage relays, types ITE-27, ITE-27D, ITE-27H, ITE-59D, 1TE-59H. See the section on Testing for single-phase voltage relays covered by earlier issues of this instruction book. The relay is housed in a case suitable for conventional semiflush panel mounting. All connections to the relay are made at the rear, of the case and are ciearly numbered. Relays of the 4118, 411R, and 411C catalog series are sim)iar to relays of the 2112, 211R, and 211C series. Both series provide the same basic functions and are of totally drawout construction; however, the 411B, 411R, and 411C series relays provide integral test facilities. Also, sequenced disconnects on the 411 series pre-vent nuisance operation during withdrawal or insertion of the relay if the normally-open contacts are used in the application. Most settings are made on the front-panel of the relay, behind a removable clear plastic cover. The target is reset by means of a pushbutton extending through the relay cover. PRECAUTIONS The following precautions should be taken when applying these relays: I. Incorrect wiring may result in damage. Be sure wiring agrees with the connection diagram for the particular relay before energizing. Important: connections for the 411 catalog series units are different from the 211 series units.

2. Apply only the rated control voltage marked on the relay front panel. The proper polarity must be observed when the dc control power connections are made.

3. For relays with dual-rated control voltage, withdraw the relay from the case and check that the movable link on the printed circ'uit board is in the correct position for the system control voltage.

4. High voltage insulation tests are not recommended. See the section on testing for additional information.

5. The entire circuit assembly of the relay is removable. The unit should insert smoothly. Do not use excessive force.

6. Follow test instructions to verify that the relay is in proper working order.

CAUTION: since troubleshooting entails working with energized equipment, care should be taken to avoid personal shock. Only competant technicians familiar with good Safety practices should service these devices. PLACING THE RELAY INTO SERVICE

1. RECEIVING, HANDLING, STORAGE Upon receipt of the relay (when not included as part of a switchboard) examine for shipping damage. If damage or loss Is evident, file a claim at once and promptly notify Asea Brown Boveri. Use normal care in handling to avoid mechanical damage.

Keep clean and dry.

Single-Phase Voltage Relays IB 18.4.7.-2 Page 3

2. INSTALLATION Mounting:

The outline dimensions and panel drilling and cutout information is given in Fig. 1. Connections: Internal connections are shown on page 7. Typical external connections are shown in Figure 2. rmportant: connections are different for 411B, 4f1R, and 411C series Un7ts compared to 211B, 211R, and 211C units, Control power must be connected in the proper polarity. For relays with dual-rated control power: before energi.zing, withdraw the relay from its case and inspect that the movable link on the lower printed circuit board is in the correct position for the system control voltage. (For units rated 10,vdc,'the link should be placed in the position marked 125vdc.) Relays rated for use with 120vac control power have an internal isolation transformer connected to relay terminals 7 and 8. Polarity of the ac control power to these terminals need not be observed. These relays have metal front panels which are connected through printed circuit board runs and connector wiring to a terminal at the rear of the relay case. The terminal is marked "G". In all applications this terminal should be wired to ground.

3. SETTINGS PICKUP (VOLTS)

The pickup taps are labelled by the actual value of ac input voltage which will cause the relay to operate. Note: operating voltage values other than the specific values provided by the taps can be. obtained by means of an internal adjustment potentiometer. See section on testing for setting procedure. On these relay models there is no adjustment for the differential between the operate and reset voltage values. lIME DIAL The time dial taps are identified as 1,2,3,4,5,6. Refer to the time-voltage charac-teristic curves in the Ap'plication section. Time dial selection is not provided on relays with an Instantaneous operating characteristic.

4. INDICATORS Target:

An operation target is provided. The target is set electronically when the output 'contacts transfer. The target will retain its indication on loss of dc control power. In order to reset the target, normal dc control power must be present and a "normal" ac voltage condition must exist; in other words, for an undervoltage relay the voltage must be higher than the set point, and for overvoltage relays, lower. APPLICATION DATA The single-phase voltage relays covered by this instruction book provide a wide range of application including undervoltage protection for motors, over and undervoltage protection for generators, and automatic bus transfer. The relays provide good accuracy and repeatability, and have a flat response over a frequency range of 15 to 400 hertz. Und*eoteRe~la]IT: catalog z1_T seri es 211a, 21113, 411B,, and 41_R: Typical applications include general purpose undervoltage protection for incoming lines, and initiation of transfer in automatic bus transfer schemes. Typical external connections are shown in Figure 2. The relay has an inverse time curve as shown in TVC-605817.

18 18.4.7-2 .Single-Phase Voltage Relays Page 4 I Undervoltaoe Relay, ITE-27D. catalog series 211B., 211R__.411B and 411R: Typical applications include the initiation of transfer in automatic bus transfer schemes. Typical external connections are shown in Figure 3. The ITE-27D relay has a definite-time characteristic with 2 ranges available: 0.1-1 second and 1-10 seconds, as shown in TVC-605820 and TVC-605821. Undervoltage Relayg_ ITE-27H, catalpa serjes 2118 211R 411B, 411R: Typical applications include instantaneous undervoltage detection for bus transfer schemes, and for generator intertie schemes. The low range relay is used as a residual voltage detector in motor bus transfer schemes. Typical connections are shwon in Figure 3. The relay has an instantaneous operating time as shown in TVC-605819, Overvoltage Relays, ITE-59H and ITE-59D catLaqg series 211C and 411C: These instantaneous and definite time overvoltage relays are companions to the ITE-27H and ITE-270 undervoltage relays, and offer similar characteristics where overvoltage protection is required. The time voltage characteristic for the ITE-59D is given in TVC-605839. For the ITE-59H the maximum operating time above 1.05 times pickup is 16 milliseconds. Notes on the Use of AC Control Power In general the use of a station battery to provide a reliable source of tripping and control power is preferred. However, many of the relay types described in this 1B are available for use with 120 vac control power. The output contacts may be used in a 120 vac circuit or in a capacitor trip circuit where the capacitor voltage is no more than 170 vdc nominal. (Consult factory if the higher rating is required: "-CAP" catalog suffix.) The control power for these relays should never be taken from a capacitor trip circuit as the voltage is too high and the relay will drain the capacitor in the event of loss of AC supply. ITE--27 and ITE-27D Undervoltage relays used with 120 vac control power in the "self-powered" mode, with both signal and control power taken from the same source, will not maintain their timing characteristics if the voltage drops below approximately 65 volts. The relay will trip immediately. If this characteristic is undesirable for. a particular application, the ITE--271 instantaneous relay should be used followed by a pneumatic timer with time delay on dropout. A contact from the timer would be used to trip. The timer would be picked up by a contact of the ITE-27H under "normal" line conditions. With undervoltage or loss of voltage, the timer would time out and close its contact in the tripping circuit. If the voltage loss were momentary, the timer would allow riding through the loss without tripping. This arrangement thus makes the time delay independent of control power and retains the benefits of accurate voltage sensing provided by the ITE-27H.

                                                                                                                                                 /61/ 7 Single-Phase Voltage Relays                                                           _F-5--t "5718-118.4.7-2 Page 5 SPECIFICATIONS 0   Input Circuit:

Rating: 160V, 300V, 50/60 Hz. 10 seconds. continuous. Burden: 1.2 VA, 1.0 pf at 120 volts. Taps: available models include: ITE-27, -27D, -27H : 60, 70, 80, 90, I00, 11Ov ITE-27D, -27H: 30, 35, 40, 45, 50, 55v 15, 18, 21, 24, 27, 30v ITE-69D, -59H: 100, 110, 120, 130, 140, 15Ov 60, 65, 70, 75, 80, 90v Differential between Operate and Reset Voltages: ITE-27: less than 0.5 percent. ITE-27D, -27H, ITE-59D, -59H: approximately 3 percent.. Operating Time: See Time-Voltage characteristic curves that follow. Output Circuit: Each contact Q 125 Vdc: 30 ampere tripping duty. 5 ampere continuous. 1 ampere break, resistive. 0.3 ampere break, inductive. Operating Temperature Range: -30 to +70 dig. C.

 , Control    Power:

Models available for 48/125 vdc @ 0.08 A max. 48/110 vdc @ 0.08 A max. 24/ 32 vdc @ 0.08(A max. 120 vac 50/60'Hz. @ 0.08 A. Allowable variation: 24vdc nominal: 19- 29 vdc 32vdc 25- 38 48vdc 38- 58 1 1Ovdc 88-125 1 25vdc 100-140 120vac 95-135 vac lolerances: Operating Voltage: +/- 5% These tolerances are based on the Operating Time: +/-10% printed dial markings. By using the calibration procedures given later in this book, the relay may be set precisely to the desired values of operating voltage and delay with excellent repeatability. Repeatability: variation in operating voltage for a 10 volt variation in control voltage: 0.2 volt, typical. variation in operating voltage over the temperature range 20-40 deg C: 0.5 volt, typical. Dielectric Strength: 1500 vac, 50/60 Hz., all circuits to ground. Seismic Capability: More that 69 ZPA biaxial broadband multifrequency vibration without damage or malfunction. (ANSI C37.98-1978)

IS 18.4.7-2 Single-Phase Voltage Relays Page 6

 ---------------------------L------------------------------------------------------------

0 OIMENSIONS AREN MM 5 4 3 2 1 U12 11U101Jj8J 0E*D STUDNUM~BERS IIWWX VIEW) 12 point block Figure 1: Relay Outline and Drilling Figure 2: -Typical External Connections Note: Refer to Internal Connection Diagrams and Contact Logic Chart on page 7 to select the specific terminal numbers for the output contact ("X" and "Y") for the particular relay being used. Additionally, a table has been provided on page 15 as a cross-reference.

Single-Phase Voltage Relays IB 18.4.7-2 Page 7 INTERNAL CONNECTION DIAGRAMS AND OUTPUT CONTACT LOGIC The following tables and diagrams define the output contact states under all possible conditions of the measured input voltage and the control power supply. "AS SHOWN" means that the contacts are in the state shown on the internal connection diagram for the relay being considered, "TRANSFERRED" means the contacts are in the opposite state to that shown on the internal connection diagram. FOR DIAGRAM 120211C Condition Contact State Cat. Series: 2llRxxx5 21lBxx65 21!Cxxx5 Normal Control Power AS Shown As Shown As Shown AC Input Voltage Below Setting Normal Control Power Transferred Transferred Transferred AC Input Voltage Above Setting No Control Voltage Transferred As Shown As Shown FOR DIAGRAM 160210A Condition Contact State Cat,'Series: 41lRxxx5 411Bxx65 41Cxxx5 Normal Control Power Transferred Transferred As Shown AC Input Voltage Below Settling Normal Control Power As Shown As Shown Transferred AC Input Voltage Above Setting, NoControl Voltage As Shown Transferred As Shown Single-Phase Voltage Relays Single-Phase VoltaRe Relays

                                                                                                    -       +     '16DJLOA I2DZIIC Case                                                        Std,. oe Test Case 4         3       2                                                        o        1S                 o         01 J-,                                       1T

IB 18.4.7-2 Single-Phase Voltage Relays Page 8 CHARACTERISTICS OF'COMMON UNITS The following chart gives the basic characteristics of various single--phase voltage relays from their catalog number breakdown. The relay catalog number will always be found on the front panel of the relay. Do not interpret't.his chart as a. way to specify a relay for purchase. Not all combinations are available. For new projects refer to catalog pages 7.4.0.3 for the latest listing of standard relays. ConLact the factory if your application requires'relay characteristics not liste,d. 2 1 1 R 1 1 7 5 BASIC FUNCTION AND PACKAGE STYLE 211 Single-phase voltage relay in Standard Case 411 Single-phase voltage relay in Test Case RELAY TYPE AND FUNCTION B ITE-27, -27D, -27H. Undervoltage Relay with Type 1I contact logic C ITE-59, ,-59D, -59H Overvoltage Relay D ITE-27/59 Under/Overvoltage Relay (obsolete, replaced by 410D series) E ITE-59G Ground Voltage Relay (obsolete, replaced by 210E/410E series) L ITE-27/59 Undervoltage Relay (obsolete, replaced by ITE-27N) . Q ITE-27G 180 Hz. Undervoltage Relay (obsolete, replaced by 410Q) R ITE-27, -27D, -27H. Undervoltage Relay with Type I logic

• TIME 1

4 6 0 . DELAY CHARACTERISTIC Inverse Time Delay Characteristic Defin-te-T-me-Character-sti-- Definite Definite Instantaneous Time Characteristic Time Characteristic Characteristic 1---0--second----- 1-10 0.i-1 second second range range I VOLTAGE TAP RANGE 1 Standard Range: ITE-27,-27D,-27H 60-110v, ITE-59,-59D,-59H 100-150v, IIE-59G.= 3-18v 2 LoW Range: ITE-27D,-27H = 30-55v, ITE-59D,-59H 60-90v, ITE-27G = 1-12v, ITE-59G = 1-6v

       .5          Special        Range:           ITE-27D,-27H              = 15-30v CONTROL VOLTAGE 6           120 vac 7          48/125        vdc                                                        OUTPUT         CONTACTS 9           24/   32 vdc                                                               1-        2 normally open 0          48/110        vdc                                                          5          2 form C

Aý 5 ,5 -( 1 (p Single-Phase Voltage Relays IB 18.4.7-2 Page 9

TIME-VOiTAGE CHARACTERISTICS TIME-VOLTAGE CHARACTERISTICS 120 1.2 100 1.0 TIME TAPS I TIM 80 0.8 0) sO .,I _ _t_ _ _ _ 5__ 0. t 1 I 4 SI I 0.6 I _C 40 _ _ _ _2 _ 0.4 C I C I co -~ I I I _ - 4 C I 02 20 I S.3 _ i _ _ _ 02 04 0.I 08 1.0 12 02 0.4 06 8 1.0 1.2 MULTIPLESOF TAPSET1ING 11, MULTIPLES OF TAP SETTING TYPE ITE-27D UNDERVOLTAGE RELAY TYPE ITE-27D UNDERVOLTAGE RELAY DEFINITE TIME (Short) DEFINITE TIME (Medium) Catalog Series 211x6xxx and 411x6xxx Catalog Series 211x4xxx and 411x4xxx ASEA BROWN BOVERI ASEA BROWN BOVERI ('J SS..lftOota~t M.dsMI*G PAtel MAY I, 1975 i2Y~i~~~I MAY 1, 1975 TVC-605821 0

OVERVOLTAGE RELAY TIME-VOLTAGE CHARACTERISTICS TIME-VOLTAGE CHARACTERISTICS TYPE ITE-59D OVERVOLTAGE RELAY DEFINITE TIME lS 50 VOLTAGETAPSETTINGS G) 1.01 ' 00 . M,90, 100. 110 TIME TAPS 40 (D 0 0.8 0) 5 30 (.V 30.3S.40,4 C 4 (0 C 20 0.4 ________MAXIMUM 10 2 02 ___ 1 0 02 04 0.6 08 10 1.2 0 1.0 1.2 1.4 1.0 1.8 2.0 OF TAPSETTING MULTIPLES MULTIPLS,OF TAPSETING 2 SHORT TIME Catalog Series 21IC6xxx and 411C6xxX TYPE ITE 27H UNDERVOLTAGE RELAY TIME DELAY AS SHOWN INSTANTANEOUS MEDIUM TIME Catalog Series 211C4xxx and 411C4xxA MULTIPLY TIME DELAY SHOWN BY 10 ASEA BROWN BOVERI ASEA BROWN BOVERI IV SMA Y 1, 19750,0333 TVC 50683a MAY 1, 1975 TVC-605819 0).

                                                                                                                                                                 ,7

135" 17 _-g - IB 18.4.7-2 Single-Phase Voltage Relays Page 12 TESTING

1. MAINTENANCE AND RENEWAL PARTS No routine maintenance is required on these relays. Follow test instructions to verify that the relay is in proper working order. We recommend that an inoperative relay be returned to the factory for repair; however, a schematic diagram, and in some cases a circuit description, can be provided on request, Renewal parts will be quoted by the factory on request.

There are many earlier versions of these single-phase voltage relays which are now obsolete and have been superseded. If you have a relay which has its front panel stamped with Instruction Book IB 18.4.7--2, but which is not covered by this Issue E of the book, you should request Issue D from the factory. Also see paragraph 6 on obsolete relays. 211 Series Units Drawout circuit boards of the same catalog number are interchangible. A unit is identified by the catalog number stamped on the front panel and a serial number stamped on the bottom side of the drawout circuit board. The board is removed by using the metal pull knobs on the front panel. Removing the board w7th the unit in service may cause an undesired operation. An 18 point extender board (cat 200X0018) is available for use in troubleshooting and calibration of the relay. 411 Series Units Metal handles provide leverage to withdraw the relay assembly from the case. Removing the unit in an application that uses a normally closed contact will cause an operation. The assembly is identified by the catalog number stamped on the front panel and a serial number stamped on the bottom of the circuit board. Test connections are readily made to the drawout relay unit by using standard banana plug leads at the rear vertical circuit board. This rear board is marked for easier identification of the connection points, A test plug assembly, catalog 400X0002 is available for use with the 411 series units. This device plugs into the relay case on the switchboard and allows access to all external circuits wired to the case. See Instruction Book 1B 7.7,1.7--3 for details on the use of this device.

2. HIGH POTENTIAL TESTS High potential tests are not recommended. A hi-pot test was performed at the factory before shipping. If a control wiring insulation test is required, partially withdraw the relay unit from its case sufficient to break the rear connections before applying the test voltage.

3. BUILT-IN TEST FUNCTION Be sure to take all necessary precautions if tests are run with the main circuit energized.

The built-in test is provided as a convenient functional test of the relay and assoc-iated circuit, When you depress the button labelled TRIP, the measuring and timing circuits of the relay are actuated. When the relay times out, the output contacts transfer to trip the circuit breaker or other associated circuitry, and the target is displayed. The test button must be held down continuously until operation is obtained. For the undervoltage relays, the timing is equivilent to that for a N complete loss of voltage.

Single-Phase Voltage Relays IB 18.4.7-2 Page 13

4. ACCEPTANCE TESTS Follow calibration procedures under paragraph 5. On inverse or definite-time relays, select Time Dial #3. For undervoltage relays check timing by dropping voltage from 120 to 0 volts. For overvoltage relays check timing by increasing voltage to 150%

of pickup. Tolerances should be within +/-5% for pickup and +/-10% for timing. Calibration may be adjusted to the final settings required by the application at this time.

5. CALIBRATION A typical test circuit is shown in Figure 3. Connect the relay to a proper source of control voltage to match its nameplate rating and internal plug. setting for dual-rated units. The ac test source should be harmonic-free. Sources using ferro-reso-nant-transformer regulators should not be used due to high harmonic content.

For relays with time delay, the time-dial tap pin should be placed in position #I (fastest) when checking pickup and dropout voltages. The voltage should be varied slowly to remove the effect of the time delay from the voltage measurements. Pickup may be varied between the fixed tap values by adjusting the internal pickup calibration potentiometer. For 211 series units the 18 point extender board provides easier access to the internal pots. Place the voltage tap pin in the nearest value and adjust the internal pot, repeating the test until the desired operating voltage is obtained. If the internal pot has insufficient range, move the tap pin to the next closest value and try again. Similarly the time delay may be adjusted higher or lower than the values shown on the time-voltage curves by means of the internal pot. The internal calibration pots are identified as follows: Relay Type Pickup Time Delay ITE-27, ITE-59 RIO R25 *

• Note: RT can also be used as a secondary ITE-27D, ITE-27H R13 R38 means of adjustment.

ITE-59D, ITE-59H

6. OBSOLETE UNITS The chart on page 8 indicates that certain of the 211 and 411 series single 7,phase voltage relays have been replaced by improved versions. The following gives a quick reference to the instruction books for the newer units. Should you need the instruc-tion book for the earlier units that are nameplated to call for IB 18.4.7-2, request.

issue D from the factory.' ITE-59, Inverse-time Overvoltage Relay: Catalog series 211Cllxx replaced by 210Cllx5 and 410CIlx5 series, see 1B 7.4.1.7-I. ITE-590, Ground Overvoltage Relay: Catalog series 211E replaced by 210E and 410E series, see IB 7.4.1.7--9. ITE-27G, Third Harmonic Undervoltage Relay: Catalog series 211Q replaced by 4100 series, see IB 7.4.1.7-9. ITE-27/59, Under/Overvoltage Relay: Catalog series 2110 replaced by 410D series, see 1B 7.4.1.7-1. ITE-27/59A, ITE-27/59D, ITE-27/59H Under/Overvoltage Relay: Catalog series 211L replaced by type ITE-27N, catalog series 211T and 411T, see IB 7.4.1.7-7. (Note: the 211L relays were not used for overvoltage protection; they were undervoltage relays with adjustable pickup and dropout voltages.) 0

IB 18.4.7-2 Single-Phase Voltage Relays Page 14 SELECTl R '.-VOLTMETER EIIEI 1 TIMEP SET i SOURCE I SOURCE a T" STI1P TIMER SET 2 TEST SET Ti TR

   +

DC CONIJTROL I II.... B1 1.ý' CD 0S :I J

                                                                                               ,C,2      , 1
                                      -- +

05 isE ONS 0 13 ~T)12 1[ 1C) 0I T1 TE Figure 3: Typical Test Connections Notes- Test connections shown for a 411C or 411R series unit. For other relays consult the Internal Connection Diagrams and Contact Logic Chart on pg 7 before selecting the output contact to use to stop the timer. If the test set voltage level adjustment does not have sufficient resolution to properly check and set the pickup voltage, then insert a Variac (adjustable autotransformer) and external voltmeter between the test source and the relay input terminals.

                      ,J

Single7Phase Voltage Relays IB 18.4.7-2 Page 15 Additional Notes on Figure 2, Typical External Connections The note with Figure 2 indicates that the terminal numbers associated with the output contact labelled "X- and "Y" in the diagram must be selected by referring to the internal connection diagram and contact logic chart for the particular relay being considered. As a cross-reference in this selection, the following table lists the terminals. associated with the normally-open contacts that close for tripping for the basic relay function. In other words, for an undervoltage relay, the contacts that, close for undervoltage, and for an. overvoltage relay the contacts that close on over-voltage. An "x" in the catalog number represents any digit ("don't care"). Undervoltage Relays Contacts that CLOSE on Undervoltage Cat Series 2IlRxxx5 5 - 6 11 - 12 21IBxx65 5 - 6 11 -'12 411RxxxS 11 - 12 14 - 15

                    .4ll xxx5                  11 -  12          14  -- 15 Overvoltage    Relays             Contacts that CLOSE on overvoltage Cat Series     21lCxxx5                   1 -- 2            9 -10 411CxxxS                  Ii -  12          14  -   15 (Contact closure is after appropriate time delay.)

AL 1 -I5-t ASEA BROWN BOVERI ABB Power Transmission Inc. Protective Relay Division 35 N. Snowdrift Rd. Allentown, Pa, 18106 Issue E (7/88) 215-395-7333 Supersedes issue D These instructions do not purport to cover all details or variations in equipment, nor to provide for every possible contingency to be met in Conjunction with installation, operation, or maintenance. Should particular problems arise which are not covered sufficiently for the purchaser's purposes, the matter should be referred to Asea Brown Boveri.

93-04293 ABB BROWN BOVARI INSTRUCTIONS FOR TEST PLUG UNITS TYPE MT-XC & MT-XV IB 7,7.1.7-8 Rev. A 4/1/1987 ABBB-0002

AEIB VI IB 7.7.1.7-8 S ASEA BROWN BOVERI Issue A I NSTRUCT IONS 12299 Test Plug Units 0/0 O-6 ) 1 EXTr-93-04293 Type MT-XC Catalog Number 400X0001 Type MT-XV Catalog Number 400X0002 0 2 Type MT-XC Type MT-XV ASEA BROWN BOVERI

IB 7.7.1.7-8 TEST PLUG UNITS Page 2 INTRODUCTION These instructions contain information on the Type MT-XC and Type MT-XV Test Plug units. These test plug units are accessory devices used in testing the external circuits connected to ABB Circuit-ShieldTM Protective Relays which have fully drawout construction with integral test facilities. Relays with this construction are identified by catalog numbers beginning with 4. The instruction book for a particular relay will indicate which test plug should be used. The proper instruction book is always stated on the front panel of the relay. PRECAUTIONS The following precautions should be taken when using these units:

1. CAUTION: since testing and troubleshooting entails working with energized equipment, care should be taken to avoid personal shock. Only competant technicians familiar with good safety practices should use these devices.

2. WARNING: current transformer secondary circuits must never be open-circuited when the main circuit is energized. Extremely high and hazardous voltages may occur under open circuit conditions. Be sure to connect an appropriate secondary burden before opening a shorting switch. Do not -disconnect this burden until the shorting switch is closed.

3. The test plug unit should be fully inserted into the relay case under test. Thumb screws are provided to secure the unit to the case.

CONSTRUCTION AND USE TYPE MT-XV, Catalog Number 400X0002 This test plug is used with those ABB relays which have no inputs from current transformers. The test plug, wheninserted in the case from which the relay has been withdrawn, provides universal connection points (terminals which accept lugged wires, bare wire, or -banana plugs) for all the rear terminals on the relay. The connection point numbers (1 to 16 and G) on the test plug correspond to the rear terminal numbers of the relay. The connections are shown schematically in Figure 1.

TEST PLUG UNITS IB 7.7.1.7-8 Page 3 TYPE MT-XC, Catalog Number 400X0001 This test plug is used with those ABB relays which have inputs from current transformers. The test plug includes (3) current input shorting switches and (11) universal connection points. The left side shorting switch is associated with rear terminals 1-2, the middle switch with terminals 3-4, and the right switch With terminals 5-6. The remaining connection terminals are marked with the number corresponding to the rear terminal of the relay to which each is connected (7 through 16 and G). The con-nections are shown schematically in Figure 2. The shorting switches are States-Multiamp type MTS. Note that pulling down the handle of the shorting switch does not in itself open the ct circuit. A dual-circuit plug (catalog number 1011-K) is available from States-Multiamp Corp. The ammeter or similar load is wired to this device. It in turn is plugged into the shorting switch, opening the shorting element and diverting the current into the load. See Figure 3. The shorting switches should be closed when the Test Plug unit is inserted into the relay case. Operation of the shorting switch should be as follows:

1. Connect load (ammeter or other appropriate burden) to the dual-circuit test plug.

2. Pull down the handle of the shorting switch associated with the input to be tested.

3. Insert the dual-circuit test plug into the shorting switch and make measurement. See Figure 3. DO NOT DISCONNECT THE LOAD WHILE THE SHORTING SWITCH IS OPEN.

4. At the conclusion of the measurements, reverse the above steps: remove the dual-circuit test plug from the shorting switch; reclose the shorting switch handle.

REAR TERMINALS OF RELAY 1 a 116 6 Figure 1: Connections RELAY Type MT-XV CASE 3 THRU 14 TEST . T PLUG 1 2

                                                ,1.~1.      15 16 G FRAME ROUND FRONT CONNECTIONJ ERNINALS-TEST PLUG

                                             ,e--- j --/_ý V-ý,

AL 11It S F ilpIp ASEA BROWN BOVERI ABS Power T&D Company, Inc. Protective Relay Division 35 N. Snowdrift Road Allentown, PA 18106 Issue A (4/87) 215-395-7333 Minor Revisions 1/90 REAR TERHIHALS OF RELAY RELAY CASE 16 V 9 TIIRU 14 TEST PLUG tFRAME 12 3 4 5 6 TT 16 G GROUND FRONT CONNECTION TiERMINALS-TEST PLUG Figure 2: Connections Type MT-XC These instructions do not purport to cover all details or variations in equipment nor to provide for every possible contingency to be met in connectioh with installation operation, or maintenance. Should further information be desired or should particular problems arise which are not covered sufficiently for the purchaser's purposes, the matter should be referred to Asea Brown Boveri. Figure 3: Connections to Shorting Switch

03-0708 ABB BROWN BOVARI INSTRUCTIONS FOR SINGLE PHASE VOLTAGE RELAYS TYPES 27N & 59N IB 7.4.1.7--7 Rev. E 5/1/1996 ABBB-O001

A M10 U 16--11-J'7 03 0708 June 27, 2003 First Energy Corp Davis-Bessie Nuclear Plant Attn: Joc Kendall

Subject:

Type 27N relay

Dear Sir,

Please note the following cclarificatiorn to the first sentence of the first paragraph of Setting Pickup aqd DropoutVoltages of section 5. CALIBRATION TESTS on page I I of MB 7.4.1.7-7 Issue E. The sentence should read; "Pickup may be varied for each fixed tap by adjusting the pickup calibration potentiometer R27.-

Regards, Pete Kovacic Dennis Haring System Application Engineer Quality Assurance Supervisor ABB tnc.

7036 Seawaritt Svd 2 ad.. Fa. T% hone ETO.3mS-1333 AKcnowf, PA I 6610-395-1055

                  /6                     5-q/- q
          .5 IB 7.4.1.7-7
                                                                       '4 AL 1111                                                         Issue E INSTRUCTIONS Single Phase Voltage Relays Al1p,'97-02055 Type 27N HIGH ACCURACY UNDERVOLTAGE RELAY Type 59N HIGH ACCURACY OVERVOLTAGE RELAY Type 27N Catalog Series 211T

• Standard Case Type 27N Catalog Series 411T " Test Case Type 59N Catalog Series 211U
• Standard Case Type 59N Catalog Series 411U " Test Case ABB POWER T&D COMPANY INC.

ALLENTOWN, PENNSYLVANIA, USA

IB 7.4.1.7-7 Single-Phase Voltage Relays Page 2 TABLE OF CONTENTS Introduction ................... Page 2 Precautions ................... Page 2 Placing Relay into Service .... Page 2 Application Data .............. Page 4 Testing........................ Page 10 INTRODUCTION The~e instructions contain'the' information required to properly install, operate, and test certain single-phase undervoltage relays type 27N, catalog series 211T and 411T; and overvoltage relays, type 59N, catalog series 211u and 411U, The relay is housed in a case suitable for conventional semiflush panel mounting. All connections to the relay are made at the rear of the case and are clearly numbered. Relays of the 411T, and 411U catalog series are similar to relays of' the 211T, and 211U series. Both series provide the same basic functions and-are of totally drawout construction; however, the 411T and 411U series relays provide integral test facilities. Also, sequenced disconnects on the 410 series prevent nuisance operation during withdrawal or insertion of the relay if the normally-open contacts are used in the application. Basic settings are made on the front panel of the relay, behind a removable clear plastic cover. Additional adjustment is provided by means of calibration potentio-meters inside the relay on the circuit board. The target is reset by means of a pushbutton extending through the relay cover. PRECAUTIONS

• The following precautions should be taken when applying these relays:

1. Incorrect wiring may result in damage. Be sure wiring agrees with the connection diagram for the particular relay before energizing.

2. Apply only the rated control voltage marked on the relay front panel. The proper polarity must be observed when the dc control power connections are made.

3. For relays with dual-rated control voltage, withdraw' the relay from the case and check that the movable link on the printed circuit board is in the correct position for the system control voltage.

4. High voltage insulatrion tests :are not recommended. See the section on testing for additional information.

5. The entire circuit assembly of the relay is removable. The unit should insert smoothly. Do not use excessive force.

6. Follow-test instructions to verify that the relay is in proper working order.

CAUTION: since troubleshooting entails working with energized equipment, care should be taken to avoid personal shock. Only competant technicians familiar with good safety practices should service these devices. PLACING THE RELAY INTO SERVICE

1. RECEIVING, HANDLING, STORAGE Upon receipt of the relay (when not included as part of a switchboard) examine for shipping damage. If damage or loss is evident, file a claim at once and promptly notify Asee Brown Boveri.. Use normal care in handling to avoid mechanical damage.

Keep clean and dry.

Single-Phase Voltage Relays IB 7.4.1.7-7 Page 3

2. INSTALLATION Mounting:

The outline dimensions and panel drilling and cutout information is given in Fig. 1. Connections: Typical external connections are shown in Figure 2. Internal connections and contact logic are shown in Figure 3. Control power must be connected in the proper polarity. For relays with dual-rated control power: before energizing, withdraw the relay from its case and inspect that the movable link on the lower printed circuit board is in the correct position for the system control voltage. (For units rated 110vdc, the link should be placed in the position marked 125vdc.) These relays have an external resistor wired to terminals 1 and 9 which must be in place for normal operation. The resistor is supplied mounted on the relay. These relays have metal front panels which are connected through printed circuit board runs and, connector wiring to a terminal at the rear of the relay case. The terminal is marked "G". In all applications this terminal should be wired to ground,.

3. SETTINGS PICKUP The pickup voltage taps identify the voltage level which the relay will cause the output contacts to transfer.

DROPOUT The dropout voltage taps are identified as a percentage of the pickup voltage. Taps are provided for 70%, 80%, 90%, and 99% of pickup, or, 30%, 40%, 50%, and 60% of pickup. Note: operating voltage values other than the specific values provided by the taps can be obtained by means of an internal adjustment potentiometer. See section on testing for setting procedure. TIME DIAL The time dial taps are identified as 1,2,3,4,5,6. Refer to the time-voltage charac-teristic curves in the Application section. Time dial selection is not provided on relays with an Instantaneous operating characteristic. The time delay may also be varied from that provided by the fixed tap by using the internal calibration adjust-ment. 4, OPERATION INDICATORS The types 27N and 59N provide a target indicator that is electronically actuated at the time the output contacts transfer to the trip condition. The target must be manually reset. The target can be reset only if control power is available, AND if the input voltage to the relay returns to the "normal" condition. Ah led indicator is provided for convenience in testing and calibrating the relay and to give operating personnel information on the status of the relay. See Figure 4 for the operation of this indicator. Units with a "-L" suffix on the catalog number provide a green led to indicate 'the presence of control power and internal power supply voltage. 0

1B 7.4.1.7-7 Single-Phase Voltage Relays Page 4 APPLICATION DATA Single-phase undervoltage relays and overvoltage relays are used to provide a wide range, of protective functions, including the protection of motors and generators, and to initiate bus transfer. The type 27N undervoltage relay and type 59N overvoltage relay are designed for those applications where exceptional accuracy, repeatability, and long-term stability are required. Tolerances and repeatability are given in the Ratings section. Remember that the accuracy of the pickup and dropout settings with respect to the printed dial markings is generally not a factor, as these relays are usually calibrated in the field to ob-tain the particular operating values for the application. At the time of field cal-ibration, the accuracy of the instruments used to set the relays is the important factor. Multiturn internal calibration potentiometers provide means for accurate adjustment of the relay operating points, and allow the difference between pickup and dropout to be set as low as 0.5%. The relays are supplied with instantaneous operating time, or with definite-time delay characteristic. The definite-time units are offered in four time delay ranges:

0. 1- 1 second, 1 - 10 seconds, 2-20 seconds or 10- 100 seconds.

An accurate peak detector is used in the types 27N and 59N. Harmonic distortion in the AC waveform can have a noticible effect on the relay operating point and on measuring instruments used to set the relay. An internal harmonic filter is available as an option for those applications where waveform distortion is a factor. The harmonic filter attenuates all harmonics of the 50/60 Hz. input. The relay then basically operates on the fundamental component of the input voltage signal. See figure 5 for the typical filter response curve. To specify the harmonic filter add the suffix "-HF" to the catalog number. Note in the section on ratings that the addition of the harmonic filter does reduce somewhat the repeatability of the relay vs. temperature variation. In applications where waveform distortion is a factor, it may be desirable to operate on the peak voltage. In these cases, the harmonic filter would not be used. CHARACTERISTICS OF COMMON UNITS Time Delay (see note 1) Catalog Numbers Type Pickup Range Dropout Range pickup Dropout Std Case Test Case 27N 60 - 110 v 70% - 99% Inst- Inst 211TOlx5 411T01x5 Inst 1 - 10 sec 211T41x5 411T41x5 Inst 0.1 - I sec 2A1Tflx5 4l1TBIX5 70 - 120 v 70% - 99% Inst Inst 211T03x5 411T03x5 Inst 1 - 10 sec 211T43x5 4llT43x5 rnst 0.i I sec 2llT63x5 41lT63x5 60 - 110 v 30% - 60% Inst Inst 211T02x5 411T02x5 Inst 1 - 10 sec 211T42x5 4llT42x5 Inst 0.1 - 1 sec 211T62x5 41lT62x5 59N 100 - 150 v 70% - 99% Inst Inst 211U01x5 411U01x5 1 10 s Inst 211U41x5 411U41x5 0.1 1 s Inst 211U61x5 411U6lx5 IMPORTANT NOTES:

1. Units are available wtth 2-20 second and 10-100 second definite time delay ranges. These units are identified by catalog numbers that have the digit "5"or "7" directly following the letter "T" in the catalog number: i.e.: catalog numbers of the form 41IT5xxx has the 2-20 second time delay range and the form 411TTxxx has the 10-100 second time delay range.

2. Each of the listed catalog numbers for the types 27N and 59N contains an "x" for the control voltage designation. To complete the catalog number, replace the "x" with the proper contiol voltage code digit:

481125 vdc ...... 7 250 vdc ...... 5 220 vdc ...... 2 48/110 vdc ...... 0

3. To specify the addition of the harmonic filter module, add the suffix "-HF". For example: 411T4175-HF. Harmonic filter not available on type 27N with instantaneous delay timing characteristic.

Single-Phase Voltage Relays 16 7.4.1.7-7 Page 5 SPECIFICATIONS Input Circuit: Rating: type 27N 150v maximum continuous. type 59N 160v maximum continuous. Burden: less than 0.5 VA at 120 vac. Frequency: 50/60 Hz. Taps: available models include: Type 27N: pickup - 60, 70, 80, 90, 100, 110 volts. 70, 80, 90, 100, 110, 120 volts. dropout- 60, 70, 80, 90, 99 percent of pickup. 30, 40, 50, 60 percent of pickup. Type 59N: pickup - 100, 110, 120, 130, 140, 150 volts. dropout- 60, 70, 80, 90, 99 percent of pickup. Operating Time: See Time-Voltage characteristic curves that follow. Instantaneous models: 3 cycles or less. Reset Time: 27N: less than 2 cycles; 59N: less than 3 cycles. (Type 27N resets when input voltage goes above pickup setting.) (Type 59N resets when input voltage goes below dropout setting.) Output Circuit: Each contact

                         @ 120 vac             @ 125 vdc              @ 250 vdc 30 amps.              30 amps.                  30 amps,           tripping     duty.

5 amps. 5 amps. 5 amps. continuous. 3 amps. 1 amp. 0.3 amp. break, resistive. 2 amps. 0.3 amp. 0.1 amp. break, inductive. Operating Temperature Range: -30 to +70 deg. C. Control Power: Models available for Allowable variation: 48/125 vdc @ 0.05 A max. 48 vdc nominal 38- 58 vdc 48/110 vdc @ 0.05 A max. 110 vdc 88-125 vdc 220 vdc @ 0.05 A max. 125 vdc " 100-140 vdc 250 vdc @ 0.05 A max. 220 vdc 176-246 vdc 250 vdc 200-280 vdc Tolerances: (without harmonic filter option, after 10 minute warm-up) Pickup and dropout settings with respect to printed dial markings (factory calibration) = +/- 2%. Pickup and dropout settings, repeatability at constant temperature and constant control voltage +/- 0.1%. (see note below) Pickup and dropout settings, repeatability over "allowable" dc control power range: +/- 0.1%. (see note below) Pickup and dropout settings, repeatablility over temperature range:

                                  -20 to +55 0 C +/- 0.4%-                  -20  to +70 0 C +/-0.7%

0 to +400C +/- 0.2% (see note below) Note: the three tolerances shown should be considered independent and may be cumulative. Tolerances assume pure sine wave input signal. Time Delay: Instantaneous models: 3 cycles or less. Definite time models: +/- 10 percent or +/-20 millisecs. whichever is greater. Harmonic Filter: All ratings are the same except: (optional) Pickup and dropout settings, repeatability over temperature range: 0 to +55 0 C +/- 0.75% -20 to +70 0 C +/-1.5%

                                  +10 to +40 0 C       +/-   0.40%

Dielectric Strength: 2000 vac, 50/60 Hz., 60 seconds, all circuits to ground. Seismic Capability: More than 6g ZPA biaxial broadband multifrequency vibration without damage or malfunction. (ANSI C37.98-1978)

5 ,-/ IB 7.4.1.7-7 Single-Phase Voltage Relays Page 6 Figure 1: Relay Outline and Panel Drilling

           ... . . .9                   -;

LLI S () .,)3 Figure 2: Typical External.Connections

                              )EF0 Single-Phase 541--

Voltage Relays IB 7.4.1.7-7

                                                                                                                   /'

Page 7 Figure 3: INTERNAL CONNECTION DIAGRAM AND OUTPUT CONTACT LOGIC The following table and diagram define the output contact states under all possible conditionsof the measured input voltage and the control power supply. "AS SHOWN' means that the contacts are in the state shown on the internal connection diagram for the relay being considered. "TRANSFERRED" means the contacts are in the opposite state to that shown on the internal connection diagram. Condition Contact State Type 27N Type 59N Normal Cohtrol Power Transferred As Shown AC Input Voltage Below Setting Normal Control Power As Shown Transferred AC Input Voltage Above Setting No Control Voltage As Shown AS Shown

                                          -  +         16D211H B15T       1L4T135* T12   i* 0 W EXTERNOL RES I*TOR SUPPLIEDWITH RELAY.

Pickup Voltage Level OnOf Off On Dropout Voltage Level Input On Off Voltage On Input Voltage Off Increasing Decreasing Start Start 4 Figure a: ITE-27N Operation of Figure 4b: ITE-59N Operation of Dropout Indicating Light Pickup Indikating Light Figure 4: Operation of Pickup/Dropout Light-Emitting-Diode Indicator

IB7.4.1.7-7 Single-Phase Voltage Relays Page 8 TIME VOLTAGE CHARACTERISTICS TIME VOLTAGE CHARACTERISTICS Type 59N OVERVOLTAGE RELAY '"PE 27N UNDERVOLrTAGE RELAY

           ":!weJ l DEFINITE TIME                                                           DEFINITE TIME 1.2.

TIM, TAPS TAPS 10 i::1111-:1 __ 4

    ..4I                      .                                                                                           3 2

0 10 Ij 1.2 i. 1 1 0.2 0.4 M0.6 08 1.0 1.2 MTUWLESOfPICKUPTAP S*TT* MULTJPLES of"DROPOUT SETTING SHORT TImE Catalog Soria$ 211UOXX andO4OIUSXXx SHORT TIME Caal;og Saries 211T6-o aend 4AlTRxIx TIHE DELAY AS SHOWN Time DELAY AS SHOWN MEDIUMTIME Catalog Series 2IU4Xkx anra 41I1N09 MEDIUM-TIME Catalog SaeriasZI TA- so d IT7X-A MULTIPLY TIME DELAY SHOWN BY IS MULTIPLY TIME DELAYSHOW BY I' Mont. , r*,".e I'l III, i14

                                           *00?  TO 8.0*00 INVoTSAVING 100 The time-voltage characteristic is definite-time 40 as shown above. The time-delay values verses time-dial selection for the 2-20 sec. and the 10-100 sec. definite time models are as follows:

01 60 O Time Dial Tap Nominal Delay Time (sec) Pin Position 411T5xxx 41IT7xxx

                                                                                              #1                   2 seconds           10 seconds 0

40 #2 4 20

                                                                                              #3                   6                  30
                                                                                              #4                   10                 50 20                                                                                     #5                   14                 70
                                                                                              #6                   20                  100 120          180 Frequency -    Hertz Figure 5:            Normalized Frequency Response,-.Optional                          Harmonic Filter               Module

Single-Phase Voltage Relays IB 7.4.1.7-7 Page 9 control Voltage Selector plug

• RV4 C-4 j R+4 1 RV R( - 3 Voltage\

        )25V                                  --                 -'
              "                   °,

i - FII r-- \ I - 03f. f~ll

• Pickupt I R-41 -- -lJo v)j 042) D Calibration

4 PI. J I r9 Pot.

1 ,,lljll,,-;l C5 27N: COW to Incr. nO) C3'I" ~ =~~ I 59N: CW to Incr.

                                                                                                                          .Voltage

_t't "0, Il(ý S!67 l-e . 2- Po .5-Figure 6: Typical Circuit Board Layouts, types 27N and 59N,

                                           -l7     11-    clog 1.C116        IP          -          T5I cT6"*C ro         Ritz       "\/,

LJ *LJ DRR l02 I- Z'NI, - 0U ,0' 303 IlY2 Figure 7: Typical Circuit Board Layout - Harmonic Filter Module

5V- I/ IB 7.4.1.7-7 Single-Phase Voltage Relays Page 10 TESTING

1. MAINTENANCE AND RENEWAL PARTS No routine maintenance is required on these relays. Follow test instructions to verify that the relay is in proper working order. We recommend that an inoperative relay be returned to the factory for repair; however, a circuit description booklet CD7.4.1.7-7 which includes schematic diagrams, can be provided on request. Renewal parts will be quoted by the factory on request.

211 Series Units Drawout circuit boards of the same catalog number are interchangible. A unit is identified by the catalog number stamped on the front panel and a serial number stamped on the bottom side of the drawout circuit board. The board is removed by using ,the metal pull knobs on the front panel. Removing the board with the unit in service may cause an undesired operation. An 18 point extender board (cat 200X0018) is available for use in troubleshooting and calibration of the relay. 411 Series Units Metal handles provide leverage to withdraw the relay assembly from the case. Removing the unit in an application that uses a normally closed contact will cause an operation. The assembly is identified by the catalog number stamped on the front panel and a serial number stamped on the bottom of the circuit board. Test connections are readily made to the drawout relay unit by using standard banana plug leads at the rear vertical circuit board. This rear board is marked for easier identification of the connection points. Important: these relays have an external resistor mounted on rear terminals 1 and 9. In order to test the drawout unit an equivilent resistor must be connected to terminals I & 9 on the rear vertical circuit board of the drawout unit. The resistance value must be the same as the resistor used on the relay.. A 26 or 50 watt resistor will be sufficient for testing. If no resistor is available, the resistor assembly mounted on the relay case could be removed and used. If the resistor from the case is used, be sure to remount it on the case at the conclusion of testing. Test Plug: A test plug assembly, catalog number 400X0002 is available'for use with the 410 series units. This device plugs into the relay case on the switchboard and allows access to all external circuits wired to the case, See Instruction Book IB 7.7.1.7-8 for details on the use of this device.

2. HIGH POTENTIAL TESTS High potential tests are not recommended. A hi-pot test was performed at the factory before shipping. If a control wiring insulation test is required, partially withdraw the relay unit from its case sufficient to break the rear connections before applying the test voltage.

3. BUILT-IN TEST FUNCTION Be sure to take all necessary precautions if the tests are run with the main circuit energized.

The built-in test is provided as a convenient functional test of the relay and assoc-iated circuit. When you depress the button labelled TRIP, the measuring and timing. circuits of the relay are actuated. When the relay times out, the output contacts transfer to trip the circuit breaker or other associated circuitry, and the target is displayed. The test button must be held down continuously until operation is obtained.

Ci Single-Phase Voltage Relays IB 7.4.1.7-7 Page ii

4. ACCEPTANCE TESTS Follow the test procedures under paragraph 5. For definite-time units, select Time Dial #3. For the type 27N, check timing by dropping the voltage to 50% of the dropout voltage set (or to zero volts if preferred for simplification of the test).

For the type 59N check timing byswitching the voltage to 105% of pickup (do not exceed max. input voltage rating.) Tolerances should be within those shown on page 5. If the settings required for the particular application are known, use the procedures in paragraph 5 to make the final adjustments.

5. CALIBRATION TESTS Test Connections and Test Sources:

Typical test circuit connections are shown in Figure 8. Connect the relay to a proper source of dc control voltage to match its nameplate rating (and internal plug setting for dual-rated units). Generally the types 27N and 59N are used in applica-tions where high accuracy is required. The ac test source must be stable and free of harmonics. A test source with less than 0.3% harmonic distortion, such as a "line-corrector" is recommended. Do not use a voltage source that employs a ferroresonant transformer as the stabilizing and regulating device, as these usually have high harmonic content in their output. The accuracy of the voltage measuring instruments used must also be considered when calibrating these relays. If the resolution of the ac test source adjustment means is not adequate, the arrangement using two variable transformers shown in Figure 9 to give "coarse" and "fine" adjustments is recommended. When adjusting the ac test source do not exceed the maximum input voltage rating of the relay. LED Indicator: A light emitting diode is provided on the front panel for convenience in determining the pickup and dropout voltages. The action of the indicator depends on the voltage level and the direction of voltage change, and is best explained by referring to Figure 4. The calibration potentiometers mentioned in the following procedures are of the multi-turn type for excellent resolution and ease of setting. For catalog series 211 units, the 18 point extender board provides easier access to the calibration pots. If desired, the calibration potentiometers can be resealed with a drop of nail polish at the completion of the calibration procedure. Setting Pickup and Dropout Voltaqes'!- por each ýiý -ieJL p V'iN £-5-/5f-1 il Pickup may be varied fixed taps)by adjusting the pickup calibration potentiometer R27. Pickup sho bset first, with the dropout tap set at 99% (60% on "low dropout units"). Set the pickup tap to the nearest value to the desired setting. The calibration potentiometer has approximately a +/-5% range. Decrease the voltage until dropout occurs, then check pickup by increasing the voltage. Re-adjust and repeat until pickup occurs at precisely the desired voltage. Potentiometer R16 is provided to adjust dropout. Set the dropout tap to the next lower tap to the desired value. Increase the input voltage to above pickup, and then lower the voltage until dropout occurs. Readjust R16 and repeat until the required setting has been made. Setting Time Delay: Similarly, the time delay may be adjusted higher or lower than the values shown on the time-voltage curves by means of the time delay calibration potentiometer R41. On the type 27N, time delay is initiated when the voltage drops from above the pickup. value to below the dropout value. On the type 59N, timing is initiated when the voltage increases from below dropout to above the pickup value. Referring to Fig. 4, the relay is "timing out" when the led indicator is lighted. External Resistor Values: The following resistor values may be used when testing 411 series units. Connect to rear connection points 1 & 9. Relays rated 48/125 vdc: 4000 ohms; (-HF models with harmonic filter 4000 ohms) 48/110 vdc: 4000 ohms; (-HF models with harmonic filter 3200 ohms) 250 vdc: 10000 ohms; (-HF models with harmonic filter 9000 ohms) 220 vdc: 10000 ohms; (-HF models with harmonic filter 9000 ohms)

16W - ý( A 1I It

    'PUMP ABB Power T&D Company, Inc.

Protective Relay Division 7036 North Snowdrift Road Allentown, PA 18106 issue E (5/96) Telephone: (610) 395-6888 - Fax: (610) 395-1055 Supersedes Issue D z x To AC Test Source See Fig. 9 Y Timer START Input 11I To Timer STOP Input Figure 8: Typical Test Connections T , T2 Variable Autotransformers (1.5 amp rating) T3 Filament Transformer (I amp secondary) V Accurate AC Voltmeter Y z TI T2 T3 COARSE FINE Figure 9: AC Test Source Arrangement These instructions do not purport to cover all details or variations in equipment, nor to provide for every possible contingency to be met in conjunction with installation, operation, or maintenance. Should particular problems arise which .are not covered sufficiently for the purchaser's purposes, the matter should be referred to ABB.

NRC ITS Tracking Page I of 3 VReturn to View Menu a rnt Do=iie RAI Screening Required: Yes Status: Closed This Document will be approved by: Carl Regulatory Basis must be included in Comments Schulten; Gerald Waig section of this Form This document has been reviewed and Yes information in this question contains NO SUNSI sensitive material (the checkbox to the right must be selected before this question can be submitted) NRC ITS TRACKING NRC Rpvipwpr I 200803061223 Conference Call Requested? No Category Other Technical Challenge ITS Section: TB POC: JFD .Nu.-mber-:r Page Number(s): ITS 3.3 Aron Lewin None Information ITS Number: OSI: DOC Number: Bases JFD.Number: 3.3.8 None None None The following was requested by the licensee via E-mail on 3/6/2008:

                     "Please post an RAI question in the Davis-Besse Q&A database: The licensee has identified the need to make a correction to ITS 3.3.8 surveillances, in order Comment to maintain the current technical specification allowance to bypass the functional unit for up to 2 hours during testing (Action 15a of CTS Table 3.3-3). This question has been posted at the request of the licensee so that applicable changes may be posted for NRC review."

Issue Date 03/06/2008 Close. Date [04/24/2008 Logged in User: Anonymous

'Responses Licensee Response by Bryan             Davis-Besse originally deleted a Current Technical Specification Kays on 03/09/2008                     allowance to bypass a loss of voltage or a degraded voltage channel for up to 2 hours to perform surveillance testing (i.e., a CHANNEL FUNCTIONAL TEST and a CHANNEL CALIBRATION), since the Davis-Besse design does not include bypass switches for these channels. However, when the loss of voltage and degraded voltage channels are tested, the channels are essentially bypassed and inoperable during the performance of the testing. Therefore, Davis-Besse desires to maintain this current 2 hour allowance, which is also included in NUREG-1430 (i.e., the NUREG allows the channels to be bypassed for up to 4 hours). A draft markup regarding this change is attached. This change will be http://www.excelservices.com/exceldbs/itstrackdavisbesse.nsf/1 fddceal Od3bdbb585256e...            7/18/2008

NRC ITS Tracking Page 2 of .3 reflected in the supplement to this section of the ITS Conversion Amendment. Licensee Response by Bryan This change supersedes the response on 3/9/2008. Davis-Besse Kays on 03/18/2008 originally deleted a Current Technical Specification allowance to bypass a loss of voltage or a degraded voltage channel for up to 2 hours to perform surveillance testing (i.e., a CHANNEL FUNCTIONAL TEST and a CHANNEL CALIBRATION), since the Davis-Besse design does not include bypass switches for these channels. However, when the loss of voltage and degraded voltage channels are tested, the channels are essentially bypassed and inoperable during the performance of the testing. Therefore, Davis-Besse desires to maintain this current 2 hour allowance, which is also included in NUREG-1430 (i.e., the NUREG allows the channels to be bypassed for up to 4 hours). Additionally, the Note has been changed to make it specific to one channel. A draft markup regarding this change is attached. This change will be reflected in the supplement to this section of the ITS Conversion Amendment. Licensee Response by Bryan This change supersedes the response and draft markup on Kays on 04/04/2008 3/18/2008. Davis-Besse originally deleted a Current Technical Specification allowance to bypass a loss of voltage or a degraded voltage channel for up to 2 hours to perform surveillance testing (i.e., a CHANNEL FUNCTIONAL TEST and a CHANNEL CALIBRATION), since the Davis-Besse design does not include bypass switches for these channels. However, when the loss of. voltage and degraded voltage channels are tested, the channels are essentially bypassed and inoperable during the performance of the testing. Therefore, Davis-Besse desires to maintain this current 2 hour allowance, which is also included in NUREG-1430 (i.e., the NUREG allows the channels to be bypassed for up to 4 hours). Additionally, the Note has been changed to make it specific to one channel. A draft markup regarding this change is attached. This change will be reflected in the supplement to this section of the ITS Conversion Amendment. NRC Response by Aron Lewin During a 4/2/08 conference call the NRC stated that they had on 04/08/2008 concerns that the submitted wording could allow the licensee to test a channel on each bus, thereby resulting in a total loss of function. The licensee stated that they wanted the allowance to test only one channel for up to two hours while delaying entry into the Actions Table. If the licensee still desires what was discussed during the conference call, a clear way of capturing that desire is:

                                  "When EDG LOPS instrumentation is placed in an inoperable status solely for performance of this Surveillance, entry into associated Conditions and Required Actions may be delayed up to 2 hours provided the remaining seven channels are OPERABLE or tripped." If the licensee desires an allowance to test only one channel for up to two hours while delaying entry into the Actions Table on a per Function basis, a clear way of capturing that desire is: "When EDG LOPS instrumentation is placed in an inoperable http://www.excelservices.com/exceldbs/itstrack-davisbesse.nsf/lfddcea1Od3bdbb585256e...         7/18/2008

NRC ITS Tracking Page 3 of 3 status solely for performance-of this Surveillance, entry into associated Conditions and Required Actions may be delayed as follows: (a) up to 2 hours for the degraded voltage Function, and (b) up to 2 hours for the loss of voltage Function, provided the remaining three channels monitoring the Function are OPERABLE or tripped." Licensee Response by Jerry Davis-Besse understands the NRC's concern is that they want to Jones on 04/23/2008 ensure that at least one EDG will receive a loss of voltage or degraded voltage signal during the 2 hour period. Davis-Besse will revise our draft markup to ensure that if a channel is being tested, that during the 2 hour time delay period the remaining channels for that Function are OPERABLE (i.e., the other channel monitoring the Function for the bus is OPERABLE and the two channels monitoring the Function for the other bus are OPERABLE). A draft markup regarding this change is attached, and supersedes the draft markup provided on 4/4/2008. This change will be reflected in the supplement to this section of the ITS Conversion Amendment. NRC Response by Aron Lewin No further questions at this time. on 04/24/2008 Date Created:, 03/06/2008 12:23 PM by Aron Lewin Last Modified: 04/24/2008 12:04 PM http://www.excelservices.com/exceldbs/itstrackdavisbesse.nsf/l fddceal Od3bdbb585256e... 7/18/2008

NRC ITS Tracking Page I of 4

  '4'Return to View MenmJ           rnt Doc uiuent_

RAT Screening Required: Yes Status: Closed This Document will be approved by: Gerald Regulatory Basis must be included in Comments Waig; Tim Kobetz section of this Form This document has been reviewed and Yes information in this question contains NO SUNSI sensitive material (the checkbox to the right must be selected before this question can be submitted) NRC ITS TRACKING NRC Reviewer ID 200712261004 Conference Call Requested? No IIBSI - Beyond Scope Issue ITS, S.ection:1 TB PO-C: JIFD-Number: PageNumber(s): ITS 3.3 Aron Lewin None Information ITS.Nu*nber: OSI: DOC Number:  : Bases.JFD N.umber* 3.3.9 None LA.3 None NRC OSI#53 Discuss how not requiring a decade overlap of the source range monitor, still assures that the necessary quality of systems and components is maintained, that facility operation will be within safety limits, and that the limiting conditions for operation will be met in accordance with 10 CFR 50.36(d)(3).

Background

                    -The CTS (page 315 of 636) requires a source range verification of at least one decade overlap prior to each reactor startup if not verified in the previous 7 Comment days.
                    -The ITS bases removes the source range nuclear instrument overlap check (page 329 of 636).
                     -The STS Bases for STS SR 3.3.9.1 (NUREG-1430), Channel Check, states "the agreement criteria includes an expectation of one decade of overlap when transitioning between neutron flux instrumentation."
                     -10 CFR 50.36(d)(3) states that "surveillance requirements are requirements relating to test, calibration, or inspection to assure that the necessary quality of systems and components is maintained, that facility operation will be within safety limits, and that the limiting conditions for operation will be met.

Issue Date 12/26/2007 Close Date [06/18/2008 Logged in User: Anonymous

'Responses                              ..         '.1 I.

1Licensee Response by Bryan 1The ITS SR 3.3.9.1 Bases (Volume 8, Page 329) deleted the http://www.excelservices.com/exceldbs/itstrackdavisbesse.nsf/l1 fddceal Od3bdbb585256e... 7/18/2008

NRC ITS Tracking Page 2 of 4 Kays on 03/03/2008 requirement in the CHANNEL CHECK for a decade overlap when transitioning between neutron flux instrumentation. As stated in Bases Justification for Deviation (JFD) 5 (Page 331), this requirement is not consistent with the CHANNEL CHECK requirements in the actual Surveillance Requirement. Furthermore, the definition of CHANNEL CHECK (Volume 3, Pages 32 and

33) states: "A CHANNEL CHECK shall be qualitative assessment, by observation, of channel behavior during operation. This determination shall include, where possible, comparison of the channel indication and status to other indications or status derived from independent instrument channels measuring the same parameter." The ISTS CHANNEL CHECK definition does not require an overlap check of any type of channel. This overlap check is an additional requirement, over and above the requirements in the actual Surveillance Requirement. Davis-Besse did not state that an overlap check is not needed. As discussed in Discussion of Change (DOC) LA03 (Page 319), the overlap check is being relocated to a different licensee controlled document, the Technical Requirements Manual (TRM). Thus, the Surveillance will be maintained in a 10 CFR 50.59 controlled document, just not in the ITS Bases. In addition, at a recent ITS conversion, this same Surveillance was deleted entirely with a "L" DOC and not included in either the ITS Bases nor the Technical Requirements Manual. This is shown in the NRC Safety Evaluation for Monticello (dated June 5, 2006, ADAMS Accession No.,

ML061240264). Furthermore, Davis-Besse does not believe that this question is a beyond scope issue, since the requirement is being maintained in a licensee controlled document (the TRM in lieu of the Bases). NRC Response by Aron Lewin Technical Branch assistance formally requested. Issue being on 03/04/2008 tracked by TAC MD8149. NRC Response by Aron Lewin EICB has conducted a review and has the following: "Licensee has on 04/08/2008 stated that Channel Check definition does not require an overlap check of any type of channel. However, the staff feels this is a special case as this requirement only applies whenever the plant is changing the mode. As during mode change during startup and shutdown credit is taken for different neutron detector and in order for the successful transition from one mode to another it is apparent that there should be no gap between neutron flux information to the operator. Therefore, this acceptance criterion must be included in the TS bases, otherwise operator might change the mode without proper instrumentation available to him. The licensee states that this requirement is being kept in the Technical Requirements Manual, but staff is not sure how operator will be stopped from changing mode without proper instrumentation available to him. Based on this, provide your basis for this exception to the TS bases." Licensee Response by Jerry The Davis-Besse position is that the definition of CHANNEL Jones on 04/23/2008 CHECK does not include any overlap requirements. In the CTS, http://www.excelservices.com/exceldbs/itstrackdavisbesse.nsf/1 fddcea 1Od3bdbb585256e... 7/18/2008

NRC ITS Tracking Page 3 of 4 the overlap requirement is provided in Note 5 to CTS Table 4.3-1 (Volume .8, Page 315), and is not part of the CHANNEL CHECK requirement. In fact, the Note is not even attached to the CHANNEL CHECK part of the Table. When the NRC issued the original ISTS NUREG-1430, the requirements were a separate Surveillance - they Were not part of the CHANNEL CHECK Surveillance. It was only through a TSTF that the change was made. Davis-Besse is not stating that overlap checks are not necessary - only that they are not part of the CHANNEL CHECK definition. Further, Davis-Besse believes that problems arise when this requirement is stated in the Bases for a CHANNEL CHECK. Specifically: a) The Frequency of a CHANNEL CHECK is every 12 hours. As stated in ISTS SR 3.0.4, entry into a MODE or other specified condition in the Applicability shall only be made when the LCO's Surveillances have been met within their specified Frequency. For the Source Range Monitors, this means that the CHANNEL CHECK requirement must be current prior to entering MODE 2. However, the overlap requirement, as stated in the Bases, is only required during the actual transition from the Intermediate Range Monitors to the Source Range Monitors during a power reduction. This will occur after the plant has already entered MODE 2. Furthermore, if the normal 12 hour Surveillance is current just prior to the transition (e.g., it was performed 2 hours ago), then there is no specific requirement to re-perform the CHANNEL CHECK to do the overlap part of the requirement. The CHANNEL CHECK is still current and is'not required for an additional 10 hours. So nothing appears to require the CHANNEL CHECK to be re-performed just to do the overlap part of the check. b) The overlap requirement and acceptance criteria (1 decade) only have to be met during the actual transition from the Intermediate Range Monitors to the Source Range Monitors. It is not required to be met at all times that the Source Range Monitors are required to be OPERABLE. However, the CHANNEL CHECK requirement must be met at all times when the Source Range Monitors are required OPERABLE. Thus, placing this requirement in the Bases appears to be inconsistent with the intent of the ISTS. That is, the Bases is modifying the CHANNEL CHECK requirement such'that a piece of the CHANNEL CHECK is only required under certain conditions. Normally, this would' need to be stated in the actual Surveillance. For example, the NRC in question 200712261030 makes a point that excluding the source range preamplifier from the CHANNEL CALIBRATION in the Bases is not the proper manner to exclude the preamplifier. That is, the Bases cannot change the definition of a CHANNEL CALIBRATION - it must have a Note in the SR similar to the Note excluding neutron detectors. Furthermore, for Davis-Besse, the overlap check is only required on a startup - not during a shutdown. Thus, placing the current requirement in the Bases would now make the requirement even more inconsistent, in that the CHANNEL CHECK would include an overlap requirement, http://www.excelservices.com/exceldbs/itstrackdavisbesse.nsf/1 fddceal Od3bdbb585256e... 7/18/2008

NRC ITS Tracking Page 4 of 4 but only on the way up - not on the way down. Davis-Besse believes that moving the current requirement to the TRM, which is a 10 CFR 50.59 controlled document, is an acceptable approach to ensure overlap is properly checked. These controls are similar to that required for the ISTS Bases. Furthermore, the NRC includes a license condition as part of the ITS amendment that will require Davis-Besse to move the CTS requirements identified by an LA-type Discussion of Change (the type used for this change) to the location specified in the LA Discussion of Change (DOC). Therefore, Davis-Besse believes that adequate controls for the currently-required overlap check will exist after ITS implementation. Davis-Besse also notes that this approach has previously been approved by the NRC in a recent ITS conversion. This is shown in the NRC Safety Evaluation for Monticello (dated June 5, 2006, ADAMS Accession No. ML061240264). At Monticello, the entire requirement was deleted from the Technical Specifications using an L-type DOC and not even placed in the TRM. Monticello maintained the current requirements in plant operating procedures. NRC Response by Aron Lewin During a conference call on May 14, 2008, the NRC discussed on 05/21/2008 regulatory and technical concerns regarding relocation of the overlap check out of TS. The licensee stated that they would retain the overlap checks in TS. This thread is being kept open to facilitate the revised submittal. Licensee Response by Jerry Davis-Besse continues to believe that the overlap requirement is Jones on 05/28/2008 not part of a CHANNEL CHECK requirement for the reasons specified in our response dated 4/23/08. Davis-Besse provided detailed reasons as to why the overlap check can not be part of a CHANNEL CHECK requirement. Davis-Besse notes that the NRC response of 5/21/08 does not provide any specific reasons as to why our.4/23/08 response is incorrect. However, as stated in the NRC response of 5/21/08, Davis-Besse will add back into the ITS Bases, as part of our ITS submittal, an overlap check consistent with our current licensing basis requirements. A draft markup regarding this change is attached. This change will be reflected in the supplement to this section of the ITS Conversion Amendment. NRC Response by Aron Lewin No further questions at this time. on 06/18/2008 Date Created: 12/26/2007 10:04 AM by Aron Lewin I,Last Modified: 06/18/2008 09:19 AM http://www.excelservices.com/exceldbs/itstrack-davisbesse.nsf/1fddcea1Od3bdbb585256e... 7/18/2008

NRC ITS Tracking Page 1 of 2 j' Return to View Menu Print Doc= n RAI Screening Required: No Status: Approval Not Required This is a Non RAI Dialogue This document will not be relied upon by staff for disposition of the LAR This document has been reviewed and Yes information in this question contains NO SUNSI sensitive material (the checkbox to the right must be selected before this question can be submitted) NRC ITS TRACKING NRC Reviewer ID 200712261008 Conference Call Requested? No Category BSI - Beyond Scope Issue ITS .SectionP:. TB.POC: JF-D Ni.Tmber: ?PageNumber(s): ITS 3.3 Aron Lewin None Information ITS Numai.hber: OS": DIOC Nulmber:l Bases JFD Number; 3.3.9 None None None NRC OSI#54 Condition B in ITS LCO 3.3.9 (page 322 of 636 for ITS Section 3.3) lists Required Actions that uses the term "control rod." STS for LCO 3.3.9 Comment (NUREG-1430) lists Required Actions that uses the term "CONTROL ROD." Based on teleconference discussions held on 12/21/2007, the licensee proposed to reinstate the term "CONTROL ROD" for ITS Sections 3.3.1 thru 3.3.5. Does the licensee propose to reinstate the term "CONTROL ROD" for section 3.3.9 as well? Iss.ue Date 12/26/2007 Close Date 01/10/2008 Logged in User: Anonymous Responses Licensee Response by Bryan Based on a conversation with the NRC concerning RAIs Kays on 01/10/2008 200711161036,200711161103,200711161104,and 200711161106, the term "control rod" used in ITS 3.3.9 and Bases (Volume 8, Pages 322, 323, and 328) has been changed back to "CONTROL ROD," consistent with the ISTS. A draft markup regarding this change is attached. This change will be reflected in _ the supplement to this section of the ITS Conversion Amendment. NRC Response by Aron Lewin No further questions at this time. on 01/10/2008 _ http://www.excelservices.com/exceldbs/itstrackdavisbesse.nsfl1 fddcealOd3bdbb585256e... 7/18/2008

NRC ITS Tracking Page 2 of 2 Date Created: 12/26/2007 10:08 AM by Aron Lewin Last Modified: 01/10/2008 09:57 AM http://www.excelservices.com/exceldbs/itstrackdavisbesse.nsf/l fddcealOd3bdbb585256e... 7/18/2008

NRC ITS Tracking Page I of 2 14ýReturn to View Menua Print Documn U RAT Screening Required: Yes Status: Closed This Document will be approved by: Gerald Regulatory Basis must be included in Comments Waig; Tim Kobetz section of this Form This document has been reviewed and Yes information in this question contains NO SUNSI sensitive material (the checkbox to the right must be selected before this question can be submitted) NRC ITS TRACKING NRC Reviewer ID 200712261010 Conference Call Requested? No Category BSI - Beyond Scope Issue ITS Section: TB POC: JFD Nu mber: Page Nu nmber(s): ITS 3.3 Aron Lewin None Information ITS Number: 0S1: DO CNumber: Bases JFD Number: 3.3.9 None None None NRC OSI#55 As permitted by 10 CFR 50.36(d)(2)(i), discuss why the reference to the shutdown margin requirements in the COLR have been deleted in the ITS.

Background

                    -The CTS (page 313 of 636) states that when the two source range channels are inoperable, operators must verify compliance with the shutdown margin requirements of Specification 3.1.1.1, "Shutdown Margin."
                    -ITS 3.1.1 (page 5 of 307 in Section 3.1) conforms with the STS by moving the shutdown margin requirements to the COLR. ITS Required Action B.4 (page 323 of 636) states that when the two source range channels are inoperable, Comment operators must verify compliance with the shutdown margin requirements.

The specific reference to the COLR limits, as found inthe STS, is crossed out."

                    -STS Required Action B.4 of LCO 3.3.9 (NUREG-1430) state that when the two source range channels are inoperable, operators must verify shutdown margin requirements is within the limits specified in the COLR.

10 CFR 50.36(d)(2)(i) states that "limiting conditions for operation are the lowest functional capability or performance levels of equipment required for safe operation of the facility. When a limiting condition for operation of a nuclear reactor is not met, the licensee shall shut down the reactor or follow any remedial action permitted by the technical specifications until the condition can be met." Issue 7Date [2/26/2007 Close Date[ 03/07/2008 http://www.excelservices.com/exceldbs/itstrack-davisbesse.nsf/1fddcealOd3bdbb585256e... 7/18/2008

NRC ITS Tracking Page 2 of 2 Logged in User: Anonymous

'Responses Licensee Response by Bryan        ITS 3.3.9 Required Action B.4 (Volume 8, Page 323) is being Kays on 03/03/2008                changed to require verification that the SDM is within the limits specified in the COLR. A draft markup regarding this change is attached. This change will be reflected in the supplement to this sectionof the ITS Conversion Amendment.

[NRC Response by Aron Lewin No further questions at this time. on 03/07/2008 Date Created: 12/26/2007 10:10 AM by Aron Lewin Last Modified: 03/07/2008 10:38 AM http://www.excelservices.com/exceldbs/itstrackdavisbesse.nsf/l fddcea 1Od3bdbb585256e... 7/18/2008

NRC ITS Tracking Page I of 3 Return to View Menu Print Documen RAI Screening Required: No Status: Approval Not Required This is a Non RAI Dialogue This document will not be relied upon by staff for disposition of the LAR This document has been reviewed and Yes information in this question contains NO SUNSI sensitive material (the checkbox to the right must be selected before this question can be submitted) NRC ITS TRACKING NRC Reviewer

     "         IDI 200712261018                             Conference Call Requested? No ategoyJ[ BSI  -*Beyond   Scope Issue ITS Section:         TB POC:             JFD Number:          Page Number(s);.

ITS 3.3 Aron Lewin None Information ITS.Number: 0S1: D OC.,Number: Bases JFD Number: 3.3.9 None None None NRC OSI#56 The NRC is evaluating the licensees determination that the source range channels is not considered to meet any Criterion of 10 CFR 50.36(d)(2)(ii). The information submitted by the licensee appears to be complete. Would the licensee like to submit any more information for consideration?

Background

                   -The Bases for CTS 3/4.3.1 and 3/4.3.2 do not specifically discuss the source range nuclear instrument with regards to Applicable Safety Analysis.
                   -The Bases for ITS LCO 3.3.9 (page 326 of 636) state "the source range Com.ent neutron flux channels have no safety function and are not assumed to function during any UFSAR design basis accident or transient analysis. However, the source range neutron flux channels provide on scale monitoring of neutron flux levels during startup and shutdown conditions. Therefore, they are being retained in Technical Specifications."
                   -The Bases for STS LCO 3.39 (NUREG-1430) states that "the source range neutron flux channels satisfy Criterion 2 of 10 CFR 50.36(c)(2)(ii).

10 CFR 50.36(d)(2)(ii) discusses how a technical specification limiting condition for operation of a nuclear reactor must be established for an item meeting one of the four criteria listed. Issue Date] 12/26/2007 Close DaIe[4/208 Logged in User: Anonymous

'Responses http://www.excelservices.com/exceldbs/itstrack-davisbesse.nsfl1fddcealOd3bdbb585256e...       7/18/2008

NRC ITS Tracking Page 2 of 3 Licensee Response by Bryan While the ISTS Bases for ISTS 3.3.9 states that the source range Kays on 01/13/2008 channels meet Criterion 2 of 10 CFR 50.36(d)(2)(ii), as stated in the ITS Bases (Volume 8, Page 326), the Source Range channels for Davis-Besse have no safety function and are not assumed to function during any UFSAR design basis accident or transient analysis. However, the source range neutron flux channels provide on scale monitoring of neutron flux levels during startup and shutdown conditions. Therefore, they are being retained in Technical Specifications. Davis-Besse is not attempting to relocate the Source Range channel requirements to a licensee controlled document. Furthermore, during a phone conversation with the NRC concerning this issue, one NRC reviewer stated that if we did not identify these instruments as meeting Criterion 2, we could then take them out of the ITS. However, the statement that they do not meet any of the criteria is a Bases statement, which simply states why the source range instruments are being maintained in the ITS. The statement by itself (i.e., that no criteria for inclusion are met) does not justify relocating the Source Range instruments. In order for Davis-Besse to justify their relocation, the NRC would have to review and approve a Technical Specification change. As stated above, Davis-Besse is not proposing relocating the Source Range requirements. Therefore, since this is a Bases change only, and it has no affect on the Technical Specification.requirements (the statement is only stating why the requirement is in the ITS),- the change is not a beyond scope change, as defined in NRC Generic Letter 96-04. The Generic Letter states that beyond scope issues are those that differ from existing Technical Specifications and the improved Standard Technical Specifications. Since this specific change is not a Technical Specification change and does not differ from the Davis-Besse CTS, it is not a beyond scope issue. NRC Response by Aron Lewin ITSB has all information needed to make final determination. on 01/17/2008 Licensee Response by Bryan The following additional information is provided to supplement Kays on 03/16/2008 our response of 01/13/2008. NRC letter dated May 9, 1998, from T. E. Murley to W. S. Wilgus (letter provided in attachment), provided, in part, the results of the NRC Staff Review of Letter dated October 15, 1987, from R. L. Gill, B&W Owners Group, to Dr. T. E. Murley, NRC,

Subject:

B&W Owners Group Technical Specification Committee Application of Selection Criteria to the B&W Standard Technical Specifications. On pages 5 and 6 of the enclosure to the letter (the NRC Staff Review document), it is stated "For the purpose of this application of the guidance in the Commission Policy Statement, the staff agrees with the Owners Groups' conclusions (emphasis added) except in two areas. First, the staff finds the Remote Shutdown Instrumentation meets the Policy Statement criteria for inclusion in Technical Specifications based on risk; and second, the staff is unable to confirm the Owners Groups' conclusion that Category 1 Post-Accident http://www.excelservices.com/exceldbs/itstrack-davisbesse.nsf/lfddcea1Od3bdbb585256e... 7/18/2008

NRC ITS Tracking Page 3 of 3 Monitoring Instrumentation is not of prime importance in limiting risk." Appendix A provides the specific results for the B&W report. Table 1 lists LCOs to be retained. Under instrumentation, Reactor Protection System Instrumentation is listed, with a Note 2. Note 2 states, in part, "The Policy Statement criteria should not be used as the basis .for relocating specific trip functions, channels, or instruments within these LCOs. In the B&W report, in the summary disposition matrix, the following is noted: Page 4 of 15 Source Range Criteria for Inclusion - No NRC Response by Aron Lewin No further questions at this time. Date Created: 12/26/2007 10:18 AM by Aron Lewin Last Modified: 04/21/2008 10:15 AM http://www.excelservices.com/exceldbs/itstrackdavisbesse.nsf/1 fddcea 1Od3bdbb585256e... 7/18/2008

I'EXT-88-04897 UNITED STATES NUCLEAR REGULATORY COMMISSION WASHINGTON. D. C. ZOSSS al IL NORSUM NPo UCENSING MAY 9 19p1 Hr. Walter S. Wilgus, Chairman MAY 10 1908 The B&W Owners Group Suite 525 NocramLE MD 301.230-214 1700 Rockville Pike Rockville. Maryland 20852 U

Dear Mr. Wilgus:

1> This letter is in response to your report identifying which Standard Technical I,, Specification (SS) requirements you believe should be retained in the new STS and which can be relocated to other licensee-controlled documents. The enclosure to this letter documents the NRC staff's conclusions as to which current STS requirements must be retained in the new SYS. These. conclusions are based on the CommissionasjInterim Policy Statement on Technical Specifica-tion Improvements and on severel interpretations of how to apply the screening 9 criteria contained in that PolicyStatement. The NRC staff considered comments made by industry at a March 29, 1918 meeting between NRC, HUMARC, and each Owners Group in making these interpretations. Based on our review, we have concluded that a significant reduction can be made in the number of Limiting Conditions for Operation (and associated Surveillance Requirements) that must be included in the STS. Our goal is to assure that the new SYS contain only requirements that are consistent with 10 CFR 50.36 and have a sound safety basis. The development of the new SYS based on the staff's conclusions will result in more efficient use of NRC and industry resources. Safety improvements are expected through more operator-oriented Technical Specifications, improved Technical Specification Bases, a reduction in action statement-induced plant transients, and a reduction in testing at power. As you are aware, the NRC staff and Industry also have underway a parallel program of specific line item improvements to both the scope and substance of the existing Technical Specifications. The need for many of these types of improvements was identified in the report (NUREG-1024) of a major staff task group established in 1983 to study surveillance requirements in Technical Specifications and develop alternative approaches to provide better assurance that surveillance testing does not adversely impact safety. The NRC will continue to actively identify and pursue the development of specific line item improvements to Technical Specifications and will make these improvements immediately available to licensees without waiting for-the new STS. We encour-age each of the Owners Groups to'continue to work with the KRC staff on these types of parallel improvements to existing Technical Specifications.

J Mr. W. S. Wilgus I We are confident that the enclosed staff report provides an adequate basis for the Owners Groups to proceed with the development of complete new STS in accordance

• with the Commission's Interim Policy Statement.

We will continue to interact with the NUMARC Technical Specification Working.: Group and each of the individual vendor Owners Groups as r-ded to keep this.. important program moving forward. Sicrely 1. c:&S , ,.ir:.a Thomas E. Kurley, Director Office of Nuclear Reactor Regulation

• b

Enclosure:

As stated P cc see next page I DISTRIBUTION: OUTSBRKTF SAVarga DOEA R/F DCrutchf ield OTSB Members JGPartlow PDR JPStohr Central Files JWRoe Murley/Sniezek FJMiraglia TT~artin BABoger CERossl GCLainas EJButcher FSchroeder AThadani JRfchardson LShao (W.S.WILGUS/LTR/SPLIT REPORT) CONCURRENCE:

                   *(see previous concurrence)
   *TSB:DOEA:NMR   *TSB:NRR     *C:ISB:NRR         *D:DOEA:NRR *D:DEST:NRR *D:DEST:NRR K~esai:pRIC     DCFischer EJButcher             CERossi     AThadani    LShao 4/18/88         04/19/88     04/20/88            04/22/88   04/26/88    04/26/88 0D:DREP:NRR #ADT:NRR JRStohr       MThartin          rEMley 04/28/88     05/05/88        5/t/88

                                           -~

Mr. W. S. Wilgus cc w/encl: Mr. Robert Gill B&W Owners Group P. 0. Box 33189 422 South Church Street Charlotte. North Carolina 28242 Mr. R. E. Bradley "4p BwR Owners Group c/o Georgia Power Nuclear Operations Department 14th Floor 333 Piedmont Avenue Atlanta, Georgia 30308 Mr. Edward Lozito Westinghouse Owners Group c/o Virginia Power P. 0. Box 26666 Richmond, Virginia 23261 Mr. Joseph B. George Westinghouse Owners Group Texas Utilities 400 North Olive Dallas, Texas 75201 Mr. Stewart Webster CE Owners Group 1000 Prospect Hill Road Winstor, Connecticut 06095-0500 Mr. R. A. Bernier CE Owners Group c/o Arizona Nuclear Power Project P. 0. Box 52034 M.S. 7048 Phoenix, Arizona 85072 Mr. Thowas Tipton NUMARC 1776 Eye Street. N.W. Suite 300 Washington, D. C. 20006-2496

f NRC STAFF REVIEW OF NUCLEAR STEAM SUPPLY SYSTEM VENDOR OWNERS GROUPS' APPLICATION OF THE COMiMISSION'S INTJRIH POLICY STATEMENT CRITERIA TO STANDARD TECHNICAL SPECIFICATIONS

1. INTRODUCTION On February 6, 1987, the Commission issued its Interim Policy Statement on.

Technical Specification Improvements (52 FR 3788). The Policy Statement encourages the Industry to develop new Standard Technical Specifications (STS) to be used as guides for licensees in preparing improved Technical Specifications (TS) for their facilities. The Interim Policy Statement contains criteria (including a discussion of each) for determining which regulatory requirements and operating restrictions should be retained in the new STS and ultimately in plant TS. It also Identifies four additional systems that are to be retained on the basis of operating experience and probabilistic risk assessments (PRA). Finally, the Policy Statement indicates that risk evaluations are an appropriate tool for defining requirementsithat should be retained in the STS/TS where Including such requirements is conristent with the purpose of TS (as stated in the Policy Statement). Requirements that are not retained in the new STS would generally not be retained in individual plant TS. Current TS requirements not retained In the STS will be relocated to other licensee-controlled documents. One of the first steps in the program to implement the Commission's Interim Policy Statement is to determine which Limiting Conditions for Operation (LCOs) contained in the existing STS should be retained in the new STS. An early decision on this issue will facilitate efforts to make the other improvements (described in the Policy Statement) to the text and Bases of those requirements that must be retained ,inthe new STS. .Each Nuclear Steam Supply System (NSSS) vendor Owners Group has submitted a report to the KRC for review that identifies which S7$ LCOs the group believes should be retained In the new STS and which can be relocated to other licensee-controlled documents. These four NSSS vendor submittals are as follows: (1) Letter dated October 15, 1987, R. L. Gill, B&W Owners Group, to Dr. 7. E. Murley, NRC,

Subject:

"B&MOwners Group Technical Specification Committee Application of Selection Criteria to the B&W Standard Technical Specifications."
                                                       **c TOTAL PAGE.OI   **

I (2) Letter dated November 12, 1987, R. A. Newton, Westinghouse Owners Group, to NRC Document Control Desk,

Subject:

*Westinghouse Owners Group MERITS Program Phase. I, Task 5, Criteria Application Topical Report.,

(3) Letter dated December 11, 1987, J. K. Gasper, Combustion Engineering Owners Group, to Dr. T. E. Hurley, NRC*

Subject:

"CEN-355, CE Owners Group Restructured Standard Technical Specifications - Volume 1 (Criteria Application)."

(4) Letter dated November 12, 1987, R. F. Janecek, BWR Owners Group, to R. E. Starostecki, NRC,

Subject:

"8WR Owners Group Technical Specification screening Criteria Applicbtion and Risk Assessment.'

These submittals provide the rationale for why each STS requirement (e.g. Liniting Condition for Operation) should be retained in the new STS or why it can be relocated to a licensee-controlled document. They also describe how each Owners Group used risk insights in determining the appropriate content of the new STS.

2. STAFF'REVIEW The NRC staff focused Its review on those requirements identified by the Owners Groups as candidates for relocation. The staff evaluated each of these requirements to determine whether it agreed with the Owners Groups' conclusions.

During the NRC Staff's review, several issues were raised concerning the proper interpretation or application of the criteria in the Commission's Interim Policy Statement. The NRC Staff has considered these issues and concluded the following: (1) Criterion 1 should be interpreted to include only instrumentation used to detect actual leaks and not more broadly to include instrumentation used

1 to detect precursors to an actual breech of the reactor coolant pressure boundary or instrumentation to identify the source of actual leakage (e.g., loose parts monitor, seismic instrumentation, valve position indicators). J2) The "Initial conditions" captured under Criterion 2 should not be limited to only "process variables, assumed In safety analyses. They should also include certain active design features (e.g., high pressure/low pressure system valves and interlocks) and operating restrictions (e.g., pressure-temperature operating limit curves),,needed to preclude unanalyzed accidents. In this context, "actiVe design features" include only design features under the control of operhtions personnel (I.e., licensed operators and personnel who perform controlkfunctions at the direction of licensed opera-tors). This position is consistent with the conclusions reached by the Staff during the trial application of the criteria to the Wolf Creek and Limerick Technical Specifications. (3) The "initial conditions" of design-basis accidents (DBA) and transients, as used in Criterion 2, should not be limited to only those directly "monitored and controlled" from the control room. Initial conditions should also in-clude other features/characteristics that are specifically assumed In DBA and transient analyses even if they can not be directly observed in the control room. For example, initial conditions (e.g., moderator temperature coefficient and hot channel factors) that are periodically monitored by other than licensed operators (e.g.. core engineers, instrumentation and control technicians) to provide licensed operators with the information required to take those actions necessary to assure that the plant is being operated within the bounds of design and analysis assumptions, meet Criterion 2 and should be retained in Technical Specifications. Initial conditions do not, however, include things that are purely design requirements. (4) The phrase "primary success path," used in Criterion 3, should be interpreted to include only the primary equipment (including redundant trains/components)

     ¶.   ¶A* t       te~tS nd4 taniSitets. Primary success path does not include rtadP_

IUser to PTres-ent tna"yzeA usecdtatlor

P. 02 accidents or transients or to improve reliability of the mitigation function (e.g., rod withdrawal block which is backup to the average power range monitor high flux trip In the startup mode, safety valves which are backup to low temperature over pressure relief valves during cold shutdown). (5) Post-AccIdent Monitoring Instrumentation that satisfies the definition of Type A variables in Regulatory Guide 1.97, "Instrumentation for Water-Cooled Nuclear Power Plants to Assess Plant and Environs Conditions During and Following an Accident, meets Criterion 3 and should be retained in Technical Specifications. Type A variables provide primary information (i.e., Information that't 4 essential for the direct accomplishment of the specified manual actions (inctiding long-term recovery actions) for which no automatic control is provided and that are required for safety systems to accomplish their safety functions for OBAs or transients). Type A variables do not include those variables associated with contingency actions that may also be identified in written procedures to compensate for failures of primary equipment., Because only.Type A variables meet Criterion 3, the STS should contain a narrative statement that indicates that individual plant Technical Specifications should contain a list of Post.Accident Instrumentation that includes Type A variables. Other Post-Accident Instrumentation (i.e., non-Type A Category. ) is discussed on page 6. (6) The NRC'S design basis for licensing a plant is the plant's Final Safety Analysis Report (FSAR) as qualified by the analysis performed by the staff and documented in the staff's safety evaluation report (SER). Because the staff's review and resulting SER are based on the acceptance criteria in the NRC's Standard Review Plan (NUREG-0800, SRP), the dose limits used in licensing a particular plant may be 'some small fraction" of those specified in the Commission's regulations In Title 10 of the Code of Federal Regulations Part 100 (10 CFR 100). Accordingly, the SRP limits should be used to define the equipment in the primary success path for mitigating accidents and transients when developing the new STS. These types of conservatisms are required to compensate for uncertainties in analysis techniques and

provide reasonable assurance that the absolute numerical limits of the regulations will be satisfied. On a plant-specific basis, systems and equipment that are identified In the NRC staff SER and assumed by the staff to function are considered part of the licensing basis for the plant and are captured by Criterion 3 (e.g., radiation monitoring instrumentation that initiates anisolation function, penetration room exhaust air cleanup system). (7) DBA and transients, as.used In Criteria 2 and 3, should be interpreted to include any design-basis event described in the FSAR (i.e., not just those events described in Chapters

• and 15 of the FSAR). For example, there may be requirements for some plants which should be retained in Technical Specifications because of the risks associated with some site-specific characteristic (e.g., although not normally required, a Technical Specifi-cation on the chlorine detection system might be appropriate where a sig-nificant chlorine hazard exists in the site vicinity; similarly, a Tech-nical 'Specification on flood protection might be appropriate where a plant is particularly vulnerable to flooding and is designed with special flood protection features). Criteria 2 and 3 should not be interpreted to in-clude purely generic design requirements applicable to all plants (e.g.,

the requirements of General Design Criterion 19 in Appendix A to 10 CFR Part 50 for control room design). The NRC staff has used the Commission's Interim Policy Statement and the conclusions described above to define the appropriate content of the new STS. The staff plans to factor these conclusions into the Final Policy Statement on Technical Specification Improvements that will be proposed to the Commission. The staff reviewed the methodology and results provided by each Owners Group to verify that none of the requirements proposed for relocation contains constraints of prime importance in limiting the likelihood or severity of accident sequences that are commonly found to dominate risk. For the purpose

of this application of the guidance in the Commission Policy Statement, the staff agrees with the Owners Groups' conclusions except in two-areas. First, the staff finds that the Remote Shutdown Instrumentation meets thePolicy State-ment criteria for inclusion in Technical Specifications based on risk; and second, the staff is unable to confirm the Owners Groups' conclusion that Category 1 Post-Accident Monitoring Instrumentation is not of prime importance in limiting risk. Recent PRAs have shown the risk significance of operator re-covery actions which would require a knowledge'of Category I variables. Furthermore, recent severe accident studies have shown significant potential for ýrisk reduction from accident management., The Owners Groups' should develop further risk-based justification in support of relocating any or all Category 1 variables from the'Standard Technieal Specifications. As stated in the Commission's Interim Policy Statement, licensees should also use plant-specific PRAs or risk surveys as they prepare license amendments to adopt the revised STS to their plant. Where PRAs or surveys are available, licensees' should use them to strengthen the Bases as well as to screen those Technical Specifications to be relocated. Where'such plant-specific risk surveys are not available,'licensees should use the literature available on risk-insights and PRAs. Licensees need not complete a plant-specific PRA before they can adopt the new STS. The NRC staff will also use risk insights and PRAs in evaluating the plant-specific submittals.

3. RESULTS OF THE STAFF'S REVIEW Appendices A through D present the detailed results of the staff's review of the Babcock and Wilcox, Westinghouse, Combustion Engineering, and General Electric application of the selection criteria tothe existing STS. Each Appendix con-sists of two tables. Table 1 identifies those LCUs that must be retained In the rew STS. Table 2 lists those LCOs that may be wholly or partially relocated to licensee-controlled documents (or be reformatted as a surveillance requirement for another LCO). Where the staff placed specific conditions on relocation of particular LCNs the staff has so noted ln'the;Tables. As apart of the

plant specific implementation of the new SIS, the staff plans to review the -location of, and controls over, relocated requirements. In as much as practi-cable, the Owners Groups should propose standard-locations for, and controls over, relocated requirements. For each LCO listed inTable 1, the criterion (criteria) that required that the LCO be retained in Technical Specifications is identified. If an LCO was retained in Technical Specifications solely on the basis of risk, "Risk* appears in the criteria column. Where an Owners Group determined that an LCO had to stay in Technical Specifications (because of elther a particular criterion or risk) and the Staff agreed that the LCO should be retained in Technical Specif-ications, the staff did not, in g4beral, verify the Owners Group's basis for retention. However,*in several instances the Owners Groups cited risk consider-ations alone as the basis'for retaining Technical Specifications and the staff disagreed with the Owners Groups. In these instances, the staff's basis for retention appears in the criteria column of Table 1. Any LCO not specifically Identified in Table 1 or Table 2 (e.g., an LCO unique to an STS not addressed in the Owners Groups submittals such as the BWR5 STS) should be retained in the STS until the Owners Group proposes and the staff makes a specific determination that it can be relocated to a licensee-controlled document. Notwithstanding the results of this review, the staff will give further consideration for relocation of additional LCOs as the staff and industry proceed with the development of the new STS.

4. CONCLUSION The results of the effort of the Owners Groups and of the NRC staff to apply the Policy Statement selection criteria to the existing STS are an important step toward ensuring that the new STS contain only those requirements that are consistent with 10 CFR 50.36 and have a sound safety basis. As shown in the

following tables, application of the criteria contained in the Commission's Interim Policy Statement resulted in a significant reduction in the number of LCOs to be included in the new STS. The development of the new STS based on the staff's conclusions will result in more efficient use of NRC and industry resources. Safety improvements are expected through more operator-oriented Technical Specifications, improved Technical Specification Bases, a reduction in action statement-induced plant transients, and a reduction in testing at power. BABCOCK GENERAL

                                    &                                COMBUSTION                        ELECTRIC LCOs                           WILCOX   WESTINGHOUSE                  ENGINEERING                       BiR4/BWR6 Total Number                          137        165                              159                          124/144.

Retained 75 92 87 81/86 Relocated 62 73 72 43/58 Percent Relocated 45% 44% 45% 35%/40% We'are confident that the staff's conclusions will provide an adequate basis for the Owners Groups to proceed with the development of complete new STS in accordance with the Commission's Interim Policy Statement.

APPENDIX A RESULTS OF THE NRC STAFF REVIEW BABCOCK & KILCOX .01i4ERS GROUP'S SUBMITTAL RETENTION AND RELOCATION bF SPECIFIC TECHNICAL SPECIFICATIONS

APPENDIX A TABLE 1 LCOs TO BE RETAINED IN BABCOCK & WILCOX STANDARD 7ECIHICAL-SPECIFICATIONS LCO CRITERIA 3.1 REACTIVITY CONTROL SYSTEM 3.1.1.1 Shutdown Margin (Note 1) 2 3.1.1.2 Moderator Temperature Coefficient 2 3.1.1.3 Minimum Temperature for Criticality 2 3.1.3.1 Group Height - Safety and Regulating Rod Groups 2 3.1.3.2 Group Height - Axial Power Shaping Rod Group 2; 3.1.3.6 Safety Rod Insertion Limit 2 &3 3.1.3.7 Regulating Rod Insertion Limits 2 3.1.3.9 Xenon Reactivity 2 3.2 POWER'DISTRIBUTION LIMITS 3.2.1 Axial Power Imbalance 2 3.2.2 Nuclear Heat Flux Hot Channel Factor 2 3.2.3 Nuclear Enthalpy Rise Hot Channel Factor 2 3.2.4 Quadrant Power Tilt 2 3.2.5 DNB Parameters 2 3.3 INSTRUMENTATION 3.3.1 Reactor Protection System Instrumentation (Note 2) 3 3.3.2 Engineered Safety Feature Actuation.System Instrumentation (Note 2) 3 3.3.3.1 Radiation Monitoring Instrumentation (Notes 2 & 3) 3 3.3.3.5 Remote Shutdown Instrumentation (Notes 2 & 4) Risk 3.3.3.6 Accident Monitoring Instrumentation 3 2.4 REACTOR COOLANT SYSTEM 3.4.1.1 Startup and Power:Operation 3 3.4.1.2 Hot Standby 3 3.4.1.3 Hot Shutdown 3 3.4.1.4 Cold Shutdown Policy Statement (DHR) 3.4.3 Safety Valve - Operating 3 3.4.4 Pressurizer 2 &3 3.4.5 Relief Valve 3 3.4.6 Steam Generators - Water Level 2 3.4.7.1 Leakage Detection System 1 A-1

B&W-TABLE I (Continued) LCO CRITERIA 3.4.7.2 Operational Leakage 2 3.4.9 Specific Activity 2 3.4.10.1 Reactor Coolant System Pressure/Temperature Limits 2 3.4.10.3 Overpressure Protection System 2 3.5 EMERGENCY CORE COOLING SYSTEM (ECCS) 3.5.1 Core Flooding Tanks 2 &3 3.5.2 ECCS Subsystems - Tavg (305)F 3 3.5.3 ECCS Subsystems - Tavg <(305)F 3 3.5.4 Borated Water Storage Tank 2 &3 3.6 CONTAINM&ENT SYSTTEMS 3.6.1.1 Ccrtainment Integrity 3 3.6.1.3 Containment Air Locks 3 3.6.1.5 Internal Pressure 2 3.6.1.6 Air Temperature 2 3.6.1.8 Containment Ventilation System 3 3.6.2.1 Containment Spray System 3 3.6.2.2 Spray Additive System 2 &3 3.6.2.3 Containment Cooling System 3 3.6.3 Iodine Cleanup System 3 3.6.4 Containment Isolation Valves 3 3.6.5.1 Hydrogen Analyzers 3 3.6.5.2 Electric Hydrogen Recombiners (Note 5) 3 3.6.6 Penetration-Room Exhaust Air Cleanup System 3 3.7 PLANT SYS7EMS 3.7.1.1 Safety Valves 3 3.7.1.2 Auxiliary Feedwater System 3 3.7.1.3 Condensate Storage Tank 2 &3 3.7.1.4 Activity 2 3.7.1.5 Main Steam Line Isolation Valves 3 3.7.3 Component Cooling Water System 3 3.7.4 Service Water System 3 3.7.5 Ultimate Heat Sink 3 3.7.6 Flood Protection (optional) 3 3.7.7 Control Room Emergency Air Cleanup System 3 3.7.8 ECCS Pump Room Exhaust Air Cleanup System 3 (optional) A-2

( B&W-TABLE 1 (Continued) LCO CRITERIA 3.8 ELECTRICAL POWER SYSTEMS 3.8.1.1 A. C. Sources - Operating 3 3.8.1.2 A.C. Sources - Shutdown Policy Statement (DHR) 3.6.2.1 A.C. Distribution - Operating 3 3.8.2.2 A.C. Distribution - Shutdown Policy.Statement (OHR) 3.8.2.3 D.C. Distribution - Operating 3 3.8.2.4 D.C. Distribution - Shutdown Policy Statement (DHR) 3.9 REFUELING OPERATIONS 3.9.1 Boron Concentration 2 3.9.2 Instrumentation 3 3.9.3 Decay Time 2 3.9.4 Containment Building Penetration 3 3.9.8.1 Residual Heat Removal and Coolant Circulation - All Water Levels Policy Statement (DHR) 3.9.8.2 Residual Heat Removal and Coolant Circulation - Low Water Levels( Policy Statement (DHR) 3.9.9 Containment Purge and Exhaust Isolation System 3 3.9.10 Water Level - Reactor Vessel :2 3.9.11 Water Level - Storage Pool 2 3.9.12 Storage Pool Air Cleanup System 2 Notes:

1. Required for Modes 3 through 5. May be relocated for Modes 1 and 2.

2. The LCO for this system should be retained in STS. The Policy Statement criteriz should not be used as the basis for relocating specific trip functions, channels, or instruments within these LCOs.

3. The staff is pursuing alternative approaches which would allow relocation of some of these LCOs on a schedule consistent with the schedule for development of the new STS. The staff Is also initiating rulemaking to delete the requirement that RETS be included in Technical Specifications.

4. Because fires (either inside or outside the control room) can be a significant contributor to the core melt frequency and because the uncertainties with fire initiation frequency can be significant, the staff believes that this LCO should be retrained in the STS at this time. The staff will consider relocation of Remote Shutdown Instrumentation on a plant-specific basis.

S. This LCO will be considered for relocation to a licensee-controlled document on a plant-specific basis. A-3

TABLE 2 (Note 1) BABCOCK & WILCOX STANDARD TECHNICAL SPECIFICATION LCOs WHICH MAY BE RELOCATED LCO 3.1 REACTIVITY CONTROL SYSTEMS 3.1.2.1 Flow Paths - Shutdown 3.1.2.2 Flow Paths - Operating 3.1.2.3 Makeup Pump - Shutdown 3.1.2.4 Makeup Pump - Operating 3.1.2.5 Decay Heat Removal Pump - Shutdown 3.1.2.6 Boric Acid Pumps - Shutdown 3.1.2.7 Boric Acid Pumps - Operating 3.1.2.8 Borated Water. Source - Shutdown 3.1.2.9 Borated Water Sburce - Operating 3.1.3.3 Position IndicatiofiChannels - Operating (Note 2) 3.1.3.4 Position Indication'Channels Shutdown (Note 2) 3.1.3.5 Rod Drop Time (Note 2) 3.1.3.8 Rod Program 3.3 INSTRUMENTATION 3.3.3.2 Incore Detectors 3.3.3.3 Seismic Instrumentation 3.3.3.4 Meteorological Instrumentation 3.3.3.7 Chlorine Detection System 3.3.3.8 Fire Detection 3.3.3.9 Radioactive Liquid Effluent Monitor (Note 3) 3.3.3.10 Radioactive Gaseous Effluent Monitor (Note 3) 3.3.4 Turbine Overspeed Protection 3.4 REACTOR COOLANT SYSTEM 3.4.2 Safety Valves - Shutdov.w 3.4.6 Steam Generators Tube Surveillance (Note 4) 3.4.8 Chemistry 3.4.10.2 Pressurizer Temperatures 3.4.11 Structural Integrity ASME Code (Note 4) 3.4.12 RCS Vents 3.6 CONTAINMENT SYSTEMS 3.6.1.2 Containnent Leakage (Note 5) 3.6.1.7 Containment Structural Integrity (Note 2) 3.7 PLANT SYSTEMS 3.7.2 Steam Generator Pressure/Temperature Limits 3.7.9 Snubbers 3.7.10 Sealed Source Contamination A A

I B&W-TABLE 2 (Continued) LCO 3.7.11.1 Fire Suppression Water System 3.7.11.2 Spray and/or Sprinkler Systems 3.7.11.3 CO System 3.7.11.4 Haion System 3.7.11.5 Fire Hose Stations 3.7.11.6 Yard Fire Hydrants and Hydrant Hose Houses 3.7.12 Fire Barrier Penetrations 3.7.13 Area Temperature Monitoring 3.9 REFUELING OPERATIONS 3.9.5 Communications 3.9.6 Fuel Handling Bridge 3.9.7 Crane Travel ;pent Fuel Storage Pool Building 3.10 SPECIAL TEST EXCEPTJONS 3.10.1 Shutdown Margin (Note 6) 3.10.2 Group Height Insertion Limits and Power Distribution Limits (Note 6) 3.10.3 Physics Tests (Note 6) 3.10.4 Reactor Coolant Loops (Note 6) 3.11 RADIOACTIVE EFFLUENTS (Note 3) 3.11.1.1 Concentration 3.11.1.2 Dose 3.11.1.3 Liquid Radwaste Treatment System 3.11.1.4 Liquid Holdup Tanks 3.11.2.1 Dose 3.11.2.2 Dose - Noble Gases 3.11.2.3 Dose - Iodine - 131, Tritium and Radionuclides in Particulate Form 3.11.2.4 Gaseous Radwaste Treatment Systems 3.11.2.5 Explosive Gas Mixture 3.11.2.6 Gas Storage Tanks 3.11.3 Solid Radioactive Waste 3.11.4 Total Dose 3.12 RADIOACTIVE ENVIRONMENTAL MONITORING (Note 3) 3.12.1 Monitoring Program 3.12.2 Land Use Census 3.12.3 Interlaboratory Comparison Program A-5

B&W-TABLE 2 (Continued) Notes:

1. Specifications listed in this table may be relocated contingent upon NRC staff approval of the location of and controls over relocated requirements.

2. This LCO may be removed from the STS. However, If the associated Surveillance Requirement(s) is necessary to meet the OPERABILITY requirements for a retained LCO, the Surveillance Requirement(s) should be relocated to the retained LCO.

3. The staff is pursuing alternative approaches which would allow relocation of some of these LCUs on a schedule consistent with the schedule for develop-Ment of the new STS. The staff is also Initiating rulemaking to delete the requirement that RETS be included in Technical Specifications.

4. This LCO may-be relocated. ot of Technical Specifications. However, the associated Surveillance Reqbtrement(s) must be relocated to Technical Specification Section 4.0, Surv~illance Requirements.

5. This LCO may be relocated. However, Pa, La, Ld, and Lt must be either retained in TS or in the Bases of the appropriate Containment LCO.

6. Special Test Exceptions may be included with corresponding LCOs.

NRC ITS Tracking Page'l of'2 jj-ýReturn to View Menu aZPrnt Douet RAI Screening Required: Yes Status: Closed This Document will be approved by: Gerald Regulatory Basis must be included in Comments Waig; Tim Kobetz section of this Form This document has been reviewed and Yes information in this question contains NO SUNSI sensitive material (the checkbox to the right must be selected before this question can be submitted) NRC ITS TRACKING NRC Reviewer ID1 200712261028 Conference Call Requested? No Category BSI - Beyond Scope Issue

                       !TS Section:          TBP.O.C:.           -JFD Num.nber,:,       Page-Number(s):

ITS 3.3 Aron Lewin None Information ITS Number: OS-: DOCINumber: Bases JHD Numnber:.: 3.3.9 None None None NRC OSI#57 Discuss if the additional information in the ITS Bases (discussed in background section) is editorial in nature or effects physical application of the LCO, in terms of satisfying Criterion 2 of 10 CFR 50.36(d)(2)(ii).

Background

                       -The Bases for CTS 3/4.3.1 and 3/4.3.2 do not specifically discuss operability requirements of the source range nuclear instruments.
                       -The ITS Bases (page 327 of 636) states "two source range neutron flux channels (i.e., the channels associated with the RPS) shall be operable whenever the control rods are capable of being withdrawn to provide the operator with redundant source range neutron instrumentation."

Comment -The Bases for STS LCO 3.3.9 (NUREG-1430), has the same discussion as the ITS Bases discussion, but does not include the "(i.e., the channels associated with the RPS)" clarification. Criterion 2 of 10 CFR 50.36(d)(2)(ii) states a TS LCO must be established for "a process variable, design feature, or operating restriction that is an initial condition of a design basis accident or transient analysis that either assumes the failure of or presents a challenge to the integrity of a fission product barrier." (It should be noted that NRC OSI#56 addresses the licensee's position that the source range neutron flux channels is not required to be in TS per Criterion 2 of 10 CFR 50.36(d)(2)(ii). That issue is separately addressed in that RAI. The issue at hand in this RAI, is the noted difference between the CTS, the ITS, and the STS.) Issue *1D3ate 12/26/2007 II http://www.excelservices.com/exceldbs/itstrack-davisbesse.nsfl1fddcealOd3bdbb585256eý.. 7/18/2008

NRC ITS Tracking Page 2 of 2 Close Date 1I01/29/2008 Logged in User: Anonymous

'Responses Licensee Response by Bryan        ITS 3.3.9 Bases Background Section (Volume 8, Page 326) and Kays on 01/15/2008                the LCO Section (Page 327) have clarifying information added. At Davis-Besse, there are four source range instruments. Two source range instruments are used for the Reactor Protection System (RPS) and two source range instruments are used for Post Accident Monitoring (PAM). The two source range instruments associated with PAM cannot be used to satisfy the requirements of LCO 3.3.9. Therefore, a clarifying statement was added to the Davis-Besse ITS Bases. Additionally, CTS Table 3.3-1 (Page 311) implies that the instruments are Reactor Protection System instruments, since the requirements are part of the current RPS Instrumentation Technical Specification. Without the clarifying statement in ITS Bases, it could allow the PAM source range instruments to meet the LCO requirements, which is not correct.

Furthermore, the addition of the clarifying statement is not a beyond scope issue, since it is consistent with the Davis-Besse current licensing basis. NRC Response by Aron Lewin No further questions at this time. on 01/29/2008 Date Created: 12/26/2007 10:28 AM by Aron Lewin

                                                                 -       Last Modified: 01/29/2008 08:27 AM http://www.excelservices.com/exceldbs/itstrack davisbesse.nsf/lfddcealOd3bdbb585256e...           7/18/2008

NRC ITS Tracking Page I of 5 l'`ýReturn to View Menua Print Document-RAI Screening Required: Yes Status: Closed This Document will be approved by: Gerald Regulatory Basis must be included in Comments Waig; Tim Kobetz section of this Form This document has been reviewed and Yes information in this question contains NO SUNSI sensitive material (the checkbox to the right must be selected before this question can be submitted) NRC ITS TRACKING NRC Reviewer MID200712261030 Conference Call Requested? No Categ [BSI - Beyond Scope Issue ITS Section: TB POC: JFD.,Number,: Page.Number(s):.

• ITS 3.3 Aron Lewin None Information ITS0Number. 0S1: DOC Number: Bases. JFD Numnbetr:

3.3.9 None None None NRC OSI#58 Discuss how the source range channel calibration is physically effected by referencing the RIPS cabinet vice the preamplifier, and would therefore still assure that the necessary quality of systems and components is maintained, that facility operation will be within safety limits, and that the limiting conditions for operation will be met in accordance with 10 CFR 50.36(d)(3).

Background

                     -The Bases for CTS 3/4.3.1 and 3/4.3.2 discuss channel calibrations, but does not include some statements found in the ITS Bases discussion on channel Comment calibrations.
                     -The ITS Bases (page 330 of 636) states "for source range neutron flux channels, channel calibration is a complete check and readjustment of the channels from the RPS cabinet input to the indicators."
                     -The Bases for STS LCO 3.39 (NUREG-1430) states "for source range neutron flux channels, channel calibration is a complete check and readjustment of the channels from the preamplifier input to the indicators."

10 CFR 50.36(d)(3) states that "surveillance requirements are requirements relating to test, calibration, or inspection to assure that the necessary quality of systems and components is maintained, that facility operation will be within safety limits, and that the limiting conditions for operation will be met." Issue.D.ate 12/26/2007 Close Date [05/29/2008 Logged in User: Anonymous -'Responses ,http://www.excelservices.com/exceldbs/itstrack-davisbesse.nsf/lfddcealOd3bdbb585256e... 7/18/2008

NRC ITS Tracking Page 2 of 5 Licensee Response by Bryan The RPS Source Range instrument preamplifier is a charge Kays on 01/13/2008 sensitive pulse amplifier used in RPS Source Range channels to amplify the low level detector input signal. The preamplifier receives its input from the Source Range detector which transmits a pulse of charge per each ionizing event in the proportional counter. The preamplifier accepts the charge impulse signals, shapes and amplifies them, and outputs voltage pulses with peak amplitude proportional to the input. The preamplifier provides this output to the RPS cabinets. However, the test circuits in the Source Range Channel do not provide for direct testing of the preamplifier.' During operation, preamplifier performance can only be checked by comparing the output of one source range channel with the output of the other channel (i.e., during performance of a CHANNEL CHECK). Therefore, the words in the ISTS Bases (Volume 8, Page 330) were changed to be consistent with the Davis-Besse design. As such, this Bases change should not be considered a beyond scope issue. NRC Response by Aron Lewin Issue is being resolved by the EICB technical branch. The TAC on 01/29/2008 number for the work is MD7961. It is anticipated that all further work associated with this topic will be charged to TAC MD7961. This thread is being maintained open for tracking purposes until MD7961 is resolved and closed. No further questions anticipated at this time. NRC Response by Aron Lewin EICB has conducted a review and has the following question: on 04/08/2008 "Licensee is changing the TS requirement by the basis. SR 3.9.2 only excludes the neutron detectors from the calibration requirements and not the preamplifiers. This is not an acceptable way to change the requirement. The licensee should submit the change to TS surveillance requirements with complete justification for the change. Also what has been the practice of the licensee to date? How they have been meeting the surveillance requirements until now? Why the system is designed such that the preamplifier could not be tested? How they meet the IEEE-279 requirement for test capabilities? How do they compare with other plants?" Licensee Response by Jerry The Preamplifier is a charge sensitive pulse amplifier used in Jones on 05/05/2008 Source Range Channels NI-1 and NI-2 to amplify the low level detector input signal. Because of the low signal level output of the source range detectors (Proportional counters), the Preamplifiers are required to be mounted within 100 feet of the detector. The Preamplifiers for NI-1 and NI-2 are located inside Containment. The Preamplifier is packaged in a splash proof double box arrangement to minimize difficulties from the continued operation in a high'humidity environment. The inner box contains the electronics and is insulated from the outer box. The Preamplifier internal circuitry is mounted on two printed circuit boards inside the inner box. One of these boards contains a gain link adjustment which provides five coarse gain settings. This fixed gain is set by means of a physical link held in place by screws. This fixed gain link adjustment is set as part of the bench calibration of the http://www.excelservices.comlexceldbs/itstrackdavisbesse.nsf/1 fddceal Od3bdbb585256e...- 7/18/2008

NRC ITS Tracking Page 3 of 5 preamplifier prior to installation in accordance with the Vendor Manual. The gain link is also adjusted as needed to produce the desired pulse height whenever a detector is replaced. The test circuits in the Source Range Channel do not provide for direct testing of the Preamplifier. Preamplifier performance can only be checked by comparing the output of one source range channel with the output of the other channel or by the insertion of a neutron source into the detector well. As long as indications are satisfactory, no preamplifier adjustments are necessary. The Preamplifier and source range detector configuration is original to plant design/construction, and was in place during the NRC's review for the licensing of Davis-Besse. In support of the operating license application, Final Safety Analysis Report section 7.1.2.7, Compliance with IEEE Standard 338-1971, described that the Reactor Protection System was designed in compliance with the periodic testing requirements of IEEE 338-1971. NUREG-0136, Safety Evaluation Report (December 1976) for issuance of the Davis-Besse operating license, stated in Section 7.1, Instrumentation and Controls - General, that Davis-Besse was requested to submit a final design package for all safety related equipment that would "permit a point-by-point identification from an initiating device through to the actuated devices and equipment". This document further stated that the NRC was reviewing these drawings as they were submitted and would report the results of their review in a supplemental report. Supplement 1 to NUJREG-0136 documented Davis-Besse's completion of the submittal of these drawings and the NRC's acceptance of the design. This would have included the design and location of the Preamplifier. Accordingly, the NRC accepted the RPS design based in part on it's compliance with IEEE 338-1971. CTS Table 4.3-1, Functional Unit 11 (Volume 8, Page 12), specifies an 18 month CHANNEL CALIBRATION (during MODES 2, 3, 4, and

5) and is modified by Note (6) (Page 13), which excludes the neutron detectors from the CHANNEL CALIBRATION. CTS 4.9.2 (Volume 14, Page 23) also requires a CHANNEL CALIBRATION prior to entry into MODE 6 if not performed within the last 18 months, and also excludes the neutron detectors from the CHANNEL CALIBRATION. The exception for the calibration of the detectors is maintained in the ITS and is consistent with IEEE 338-1971. IEEE 338-1971, Section 5.3.2 also supports excluding the Preamplifier. This section states that "the test input shall be introduced as close to the sensor as is practical."

Although the Davis-Besse Technical Specifications explicitly provide an exclusion to the neutron detectors for the CHANNEL CALIBRATION (similar to both the original NUREG-0103, Standard Technical Specification for B&W Plants, and NUREG-1430, Improved Technical Specifications for B&W Plants), this exclusion is also understood, consistent with IEEE 338-1971, to include the connecting portion of the channel from the detector to the location where the test signal can be introduced as close to the http://www.excelservices.com/exceldbs/itstrackdavisbesse.nsf/1 fddcea 1Od3bdbb585256e... 7/18/2008

NRC ITS Tracking Page 4 of 5 sensor (i.e., the detector) as is practical. If this were not the case, then the Technical Specifications for all plants would need to include an exclusion of the channel portion connecting the detectors to where the test signal is actually inputted. Based on the design of the instrument string, inputting a test signal into the preamplifier is not practical. In these conditions, the IEEE standard identifies that OPERABILITY will be verified by comparing readings between channels which have a known relationship to each other. This CHANNEL CHECK is currently performed once per shift (and the ITS maintains this Frequency) when source range detectors are required to be OPERABLE. The following Davis-Besse procedures are established to perform the channel calibration of source range neutron flux and rate to RPS Channels: a) DB-MI-0345 1, Channel Calibration of 78A-ISNI02 Source Range Neutron Flux and Rate to RPS Channel 1; and b) DB-MI-03452, Channel Calibration of 78A-ISNIO1 Source Range Neutron Flux and Rate to RPS Channel 2. The scope of these procedures does not encompass the preamplifier. DB-MI-05145, Source Range Detector High Voltage and Discriminator Setting Procedure is utilized in replacement of a source range detector and does measure the output of the Preamplifier based on the insertion of a neutron check source into the source well. The gain link is adjusted, if needed, to obtain the desired pulse height. Operating experience demonstrates that this link does not require adjustment between detector replacements. Other Babcock and Wilcox plants were contacted regarding testing of the Preamplifier. As a result of these discussions, it was identified that Oconee, Three Mile Island, and Arkansas Nuclear transitioned to Gamma-Metric's for source range neutron flux monitoring. Oconee identified that prior to this transition they did not include the preamplifier in the scope of their calibration for source range nuclear instruments. As a result of this question, Davis-Besse initiated a Condition Report, based on the fact that it appears we are not in literal compliance with our CTS Surveillance requirements. As part of that Condition Report, Davis-Besse performed as assessment of the source range neutron monitors (NI-1 and NI-2) with the startup data from the 15 refueling outage. This assessment included a review of the source range detector data during the period of overlap with the intermediate range detectors. Based on review of this data it was concluded that both preamplifiers are performing properly. Davis-Besse believes that there are two options to resolve this issue. The first and preferred option is to modify the ITS CHANNEL CALIBRATION Surveillances (ITS SR 3.3.9.2 and SR 3.9.2.2) to exclude the preamplifier in addition to the currently excluded neutron detectors. Davis-Besse would prefer to do this option if this new beyond scope change will not delay issuance of the ITS Amendment. The second option is to change the ITS SR 3.3.9.2 Bases (Volume 8, Page 330) and SR 3.9.2.2Bases (Volume 14, Page 35) to be consistent with the ISTS Bases wording (i.e., change "RPS cabinet" back to "preamplifier"). Davis-Besse would http://www.excelservices.com/exceldbs/itstrack-davisbesse.nsf/1fddcealOd3bdbb585256e... 7/18/2008

NRC ITS Tracking Page 5 of 5 then pursue a License Amendment change outside the scope of the ITS conversion if the second option is chosen. Licensee Response by Jerry The NRC informed Davis-Besse during a phone conversation on Jones on 05/29/2008 5/28 that the NRC desired Davis-Besse to pursue the second option stated in the Davis-Besse response dated 5/05/08. Specifically, to change the ITS SR 3.3.9.2 Bases (Volume 8, Page 330) and SR 3.9.2.2 Bases (Volume 14, Page 35) to be consistent with the ISTS Bases wording (i.e., change "RPS cabinet" back to "preamplifier"), and to pursue a Technical Specification change to correct the problem described in the 5/05/08 response at a later date. A draft markup regarding this change is attached. This change will be reflected in the supplement to this section of the ITS Conversion Amendment. NRC Response by Aron Lewin No further questions at this time. on 05/29/2008 Date Created: 12/26/2007 10:30 AM by Aron Lewin Last Modified: 05/29/2008 08:21 AM http://www.excelservices.com/exceldbs/itstrackdavisbesse.nsf/1 fddceal Od3bdbb585256e... 7/18/2008

NRC ITS Tracking Page 1 of I Reunto View Menuita ~ un RAI Screening Required: No Status: Approval Not Required This is a Non RAI Dialogue This document will not be relied upon by staff for disposition of the LAR This document has been reviewed and Yes information in this question contains NO SUNSI sensitive material (the checkbox to the right must be selected before this question can be submitted) NRC ITS TRACKING NRC Reviewer F200712261101 Conference Call Requested? No CateoryOther Technical Challenge ITS Section: TB POC: JED-N-u-mber: Page.Numnber(s).: ITS 3.3 Aron Lewin None Information ITS.Number: OSI: D-OC.Number:: Bas es..JED.Nu m.,b.er.: 3.3.10 None None None DOC L2 is referenced on page 339 of 636, but DOC table does not contain L2 CQo1mmelnt discussion (page 346 of 636). I believe this may have been an administrative oversight. Issue Date 12/26/2007 Close iDate[0/10/2008 Logged in User: Anonymous

'Responses Licensee Response by Bryan           The NRC reviewer is correct, this is an administrative oversight.

Kays on 01/10/2008 Discussion of Change (DOC) L02 (Volume 8, Page 339) should have been DOC LO 1. A draft markup regarding this change is attached. This change will be reflected in the supplement to this _section of the ITS Conversion Amendment. onNRC Response by Aron Lewin No further questions at this time. Ion 01/10/2008 1i Date Created: 12/26/2007 11:01 AM by Aron Lewin Last Modified: 01/10/2008 10:04 AM http://www.excelservices.com/exceldbs/itstrack-davisbesse.nsf/1fddcealOd3bdbb585256e... 7/18/2008

NRC ITS Tracking Page I of 2 Retu rn to V iew Meu Print Docmn RAI Screening Required: No Status: Approval Not Required This is a Non RAI Dialogue This document will not be relied upon by staff for disposition of the LAR This document has been reviewed and Yes information in this question contains NO SUNSI sensitive material (the checkbox to the right must be selected before this question can be submitted) NRC ITS TRACKING PRC Rd-vipwor ID 200712261105 Conference Call Requested? No Category IIIn Scope ITS Section: TB POC: JFD Number: Page. Number(s): ITS 3.3 Aron Lewin None Information ITS Number: OI: DO CNumber: Bases JED Number: 3.3.10 None None None The CTS has a Note (c) (page 338 of 636) that takes special test exceptions for intermediate range channels during physics testing (i.e. CTS LCO 3.10.1 and CTS LCO 3.10.2). The Note allows only one intermediate range channel to be operable during the physics testing. The ITS does not carry forward these exceptions in that the TS exception is not listed in LCO 3.3.10 (page 348 of Com.ment 636), LCO 3.1.8, "Physics Tests Exceptions - Mode 1" (page 183 of 307 in n Section 3.1), and LCO 3.1.9, "Physics Tests Exceptions - Mode 2" (page 208of 307 in Section 3.1). As a result, two intermediate range channels are expected to be operable during physics testing, and I would have expected a More Restrictive DOC. The DOC is listed as administrative (A04). STS LCO 3.1.8 and STS LCO 3.1.9 (NUREG-1430) do not list intermediate range channel exceptions during physics testing.

   /    Issue D.ate   12/26/2007 Close Date[ 01/29/2008 Logged in User: Anonymous Responses Licensee Response by Bryan               CTS Table 3.3-1 Note (c) (Volume 8, Page 338) allows an Kays on 01/17/2008                       exception to the OPERABILITY requirement for intermediate range channels, in that only one of the two channels are required during certain special tests. ITS 3.3.10 (Page 348) does not include this exception; both intermediate range channels are r'equired in the ITS. ITS 3.3.10 Discussion of Change (DOC) A04 was written to remove this exemption. As stated by the NRC reviewer, this http://www.excelservices.com/exceldbs/itstrackdavisbesse.nsf/1 fddceal Od3bdbb585256e...              7/18/2008

NRC ITS Tracking Page 2 of 2 change would require two intermediate range Neutron Flux Monitors to be OPERABLE during the Special Test Exemptions in lieu of the current one channel, i.e., the change is a more restrictive change, not administrative. Therefore, DOC A04 will be deleted and new more restrictive DOC (M03) has been written to justify the change. A draft markup regarding this change is attached. This change will be reflected in the supplement to this section of the ITS Conversion Amendment. NRC Response by Aron Lewin o further questions at this time. Date Created: 12/26/2007 11:05 AM by Aron Lewin Last Modified: 01/29/2008 10:18 AM http://www.excelservices.com/exceldbs/itstrackdavisbesse.nsf/1 fddceal Od3bdbb585256e... 7/18/2008

NRC ITS Tracking Page I of 4 j4ýReturn to View Menua Pint Duic t RAI Screening Required: Yes Status: Closed This Document Will be approved by: Gerald Regulatory Basis must be included in Comments Waig; Tim Kobetz section of this Form This document has been reviewed and Yes information in this question contains NO SUNSI sensitive material (the checkbox to the right must be selected before this question can be submitted) NRC ITS TRACKING NRC Reviewer ID 11200712261120 Conference Call Requested? No Catgo y BSI - Beyond Scope Issue ITS Section: TB POC: JFD Number: Page.,Nu!niber(s): ITS 3.3 Aron Lewin None Information ITS Nu.mbcr: OS1: DOC Number.: Bases JFD..Number: 3.3.10 None LA.3 None NRC OSI#59 Discuss how not requiring a decade overlap of the intermediate range monitor, still assures that the necessary quality of systems and components is maintained, that facility operation will be within safety limits, and that the limiting conditions for operation will be met in accordance with 10 CFR 50.36 (d)(3).

Background

                    -The CTS (page 341 of 636) requires a intermediate range verification of at least one decade overlap prior to each reactor startup if not verified in the Commen.t   previous 7 days.
                    -The ITS bases removes the intermediate range nuclear instrument overlap check (page 354 of 636).
                    -The STS Bases for STS SR 3.3.10.1 (NUREG-1430), Channel Check, states "the agreement criteria includes an expectation of one decade of overlap when transitioning between neutron flux instrumentation."

10 CFR 50.36(d)(3) states that "surveillance requirements are requirements relatingto test, calibration, or inspection to assure that the necessary quality of systems and components is maintained, that facility operation will be within safety limits, and that the limiting conditions for operation will be met. Issue Date 112/26/2007 Close Date [05/28/2008 Logged in User: Anonymous -Responses http://www.excelservices.com/exceldbs/itstrackdavisbesse.nsf/1 fddcea 1Od3bdbb585256e... 7/18/2008

NRC ITS Tracking Page 2 of 4 Licensee Response by Jerry The ITS SR 3.3.10.1 Bases (Volume 8, Page 354) deleted the Jones on 02/11/2008 requirement in the CHANNEL CHECK for a decade overlap when transitioning between neutron flux instrumentation. As stated in Bases Justification for Deviation (JFD) 5 (Page 356), this requirement is not consistent with the CHANNEL CHECK requirements in the actual Surveillance Requirement. Furthermore, the definition of CHANNEL CHECK (Volume 3, Pages 32 and

33) states: "A CHANNEL CHECK shall be qualitative assessment, by observation, of channel behavior during operation. This determination shall include, where possible, comparison of the channel indication and status to other indications or status derived from independent instrument channels measuring the same parameter." The ISTS CHANNEL CHECK definition does not require an overlap check of any type of channel. This overlap check is an additional requirement, over and above the requirements in the actual Surveillance Requirement. Davis-Besse did not state that an overlap check is not needed. As discussed in Discussion of Change (DOC) LA03 (Page 345), the overlap check is being relocated to a different licensee controlled document, the Technical Requirements Manual (TRM). Thus, the Surveillance will be maintained in a 10 CFR 50.59 controlled document, just not in the ITS Bases. In addition, at a recent ITS conversion, this same Surveillance was deleted entirely with a "L" DOC and not included in either the ITS Bases nor the Technical Requirements Manual. This is shown in the NRC Safety Evaluation for Monticello (dated June 5, 2006, ADAMS Accession No. ML061240264). Furthermore, Davis-Besse does not believe that this question is a beyond scope issue, since the requirement is being maintained in a licensee controlled document (the TRM in lieu of the Bases).

NRC Response by Aron Lewin Requesting technical branch review. Will indicate TAC number on 02/19/2008 upon assignment. NRC Response by Aron Lewin EICB has conducted a review and has the following: "Licensee has on 04/08/2008 stated that Channel Check definition does not require an overlap check of any type of channel. However, the staff feels this is a special case as this requirement only applies whenever the plant is changing the mode. As during modechange during startup and shutdown credit is taken for different neutron detector and in order for the successful transition from one mode to another it is apparent that there should be no gap between neutron flux information to the operator. Therefore, this acceptance criterion must be included in the TS bases, otherwise operator might change the mode without proper instrumentation available to him. The licensee states that this requirement is being kept in the Technical Requirements Manual, but staff is not sure how operator will be stopped from changing mode without proper instrumentation available to him. Based on this, provide your basis for this exception to the TS bases." Licensee Response by Jerry The Davis-Besse position is that the definition of CHANNEL http://www.excelservices.com/exceldbs/itstrack davisbesse.nsfY 1fddcea 1Od3bdbb585256e... 7/18/2008

NRC ITS Tracking Page 3 of 4 Jones on 04/23/2008 CHECK does not include any overlap requirements. In the CTS, the overlap requirement is provided in Note 5 to CTS Table 4.3-1 (Volume 8, Page 341), and is not part of the CHANNEL CHECK requirement. In fact, the Note is not even attached to the CHANNEL CHECK part of the Table. When the NRC issued the original ISTS NUREG-1430, the requirements were a separate Surveillance - they were not part of the CHANNEL CHECK Surveillance. It was only through a TSTF that the change was made. Davis-Besse is not stating that overlap checks are not necessary - only that they are not part of the CHANNEL CHECK definition. Further, Davis-Besse believes that problems arise when this requirement is stated in the Bases for a CHANNEL CHECK. Specifically: a) The Frequency of a CHANNEL CHECK is every 12 hours. As stated in ISTS SR 3.0.4, entry into a MODE or other specified condition in the Applicability shall only be made when the' LCO's Surveillances have been met within their specified Frequency. For the Intermediate Range Monitors, this means that the CHANNEL CHECK requirement must be current prior to entering MODE 3 during a normal reactor startup. However, the overlap requirement, as stated in the Bases, is only required during the actual transition from the Source Range Monitors to the Intermediate Range Monitors. Furthermore, if the normal 12 hour Surveillance is current just prior to the transition (e.g., it was performed 2 hours ago), then there is no specific requirement to re-perform the CHANNEL CHECK to do the overlap part of the requirement. The CHANNEL CHECK is still current and is not required for an additional 10 hours. So nothing appears to require the CHANNEL CHECK to be re-performed just to do the overlap part of the check. b) The overlap requirement and acceptance criteria (1 decade) only have to be met during the actual transition from the Source Range Monitors to the Intermediate Range Monitors. It is not required to be met at all times that the Intermediate Range Monitors are required to be OPERABLE. However, the CHANNEL CHECK requirement must be met at all times when the Intermediate Range Monitors are required OPERABLE. Thus, placing this requirement in the Bases appears to be inconsistent with the intent of the ISTS. That is, the Bases is modifying the CHANNEL CHECK requirement such that a piece of the CHANNEL CHECK is only required under certain conditions. Normally, this would need to be stated in the actual Surveillance. For example, the NRC in question 200712261030 makes a point that excluding the source range preamplifier from the CHANNEL CALIBRATION in the Bases is not the proper manner to exclude the preamplifier. That is, the Bases cannot change'the definition of a CHANNEL CALIBRATION - it must have a Note in the SR similar to the Note excluding neutron detectors. Furthermore, for Davis-Besse, the overlap check is ,only required on a startup - not during a shutdown. Thus, placing the current requirement in the Bases would now make the requirement even more inconsistent, in that the CHANNEL CHECK would http://www.excelservices.com/exceldbs/itstrackdavisbesse.nsf/1 fddceal Od3bdbb585256e... 7/18/2008

NRC ITS Tracking .1 Page 4 of 4 include an overlap requirement, but only on the way up - not on the way down. Davis-Besse believes that moving the current requirement to the TRM, which is a 10 CFR 50.59 controlled document, is an acceptable approach to ensure overlap is properly checked. These controls are similar to that required for the ISTS Bases. Furthermore, the NRC includes a license condition as part of the ITS amendment that will require Davis-Besse to move the CTS requirements identified by an LA-type Discussion of Change (the type used for this change) to the location specified in the LA Discussion of Change (DOC). Therefore, Davis-Besse believes that adequate controls for the currently-required overlap check will exist after.ITS implementation. Davis-Besse also notes that this approach has previously been approved by the NRC in a recent ITS conversion. This is shown in the NRC Safety Evaluation for Monticello (dated June 5, 2006, ADAMS Accession No. ML061240264). At Monticello, the entire requirement was deleted from the Technical Specifications using an L-type DOC and not even placed in the TRM. Monticello maintained the current requirements in plant operating procedures. NRC Response by Aron Lewin During a conference call on May 14, 2008, the NRC discussed on 05/21/2008 regulatory and technical concerns regarding relocation of the overlap check out of TS. The licensee stated that they would retain the overlap checks in TS. This thread is being kept open to facilitate the revised submittal. Licensee Response by Jerry Davis-Besse continues to believe that the overlap requirement is Jones on 05/28/2008 not part of a CHANNEL CHECK requirement for the reasons specified in our response dated 4/23/08. Davis-Besse provided detailed reasons as to why the overlap check can not be part of a CHANNEL CHECK requirement. Davis-Besse notes that the NRC response of 5/21/08 does not provide any specific reasons as to why our 4/23/08 response is incorrect. However, as stated in the NRC response of 5/21/08, Davis-Besse will add back into the ITS Bases, as part of our ITS submittal, an overlap check consistent with our current licensing basis requirements. A draft markup regarding this change is attached. This change will be reflected in the supplement to this section of the ITS Conversion Amendment. NRC Response by Aron Lewin No further questions at this time. on 05/28/2008 Date Created: 12/26/2007 11:20 AM by Aron Lewin Last Modified: 05/28/2008 01:11 PM http://www.excelservices.com/exceldbs/itstrackdavisbesse.nsf/1 fddceal Od3bdbb585256e,... 7/18/2008

NRC ITS Tracking Page I of 2 Return to View Menuj Print Docuen RAI Screening Required: No Status: Approval Not Required This is a Non RAI Dialogue This document will not be relied upon by staff for disposition of the LAR This document has been reviewed and Yes information in this question contains NO SUNSI sensitive material (the checkbox to the right must be selected before this question can be submitted) NRC ITS TRACKING NRC Reviewer ID 200712261122 Conference Call Requested? No Category BSI - Beyond Scope Issue ITS Section: TB POC:ý JFD Number:. Page.Number(s): ITS 3.3 Aron Lewin None Information ITS Number: OS1: DOC Number: Bases JFD Number: 3.3.10 None None None The applicability for ITS LCO 3.3.10 (page 348 of 636 for ITS Section 3.3) uses the term "control rod." STS for LCO 3.3.10 (NUREG-1430) uses the term "CONTROL ROD." Comment During teleconference discussions on 12/21/2007, the licensee proposed to reinstate the term "CONTROL ROD" for ITS sections 3.3.1 thru 3.3.5. Does the licensee propose to reinstate the term "CONTROL ROD" for Section 3.3.10 as well? Issue Date 112/26/2007 Close Daate 01/10/2008 Logged in User: Anonymous

'Responses Licensee Response by Bryan            Based on a conversation with the NRC concerning RAIs Kays on 01/10/2008                    200711161036,200711161103,200711161104,and 200711161106, the term "control rod" used in ITS 3.3.10 and Bases (Volume 8, Pages 343, 348, 350, and 353) has been changed back to "CONTROL ROD," consistent with the ISTS. A draft markup regarding this change is attached. This change will be reflected in the supplement to this section of the ITS Conversion Amendment.

at this time. on 01/10/2008 NRC Response by Aron Lewin 1N further questions http://www.excelservices.com/exceldbs/itstrackdavisbesse.nsf/1 fddcea 1Od3bdbb585256e... 7/18/2008

NRC ITS Tracking Page 2 of 2 Date Created: 12/26/2007 11:22 AM by Aron Lewin Last Modified: 01/10/2008 10:06 AM http://www.excelservices.comlexceldbs/itstrackdavisbesse.nsf/1 fddceal Od3bdbb585256e... 7/18/2008

NRC ITS Tracking Page I of-3 Return to View Menu Print Document RAI.Screening Required: No Status: Approval Not Required This is a Non RAI Dialogue. This document will not be relied upon by staff for disposition of the LAR This document has been reviewed and Yes information in this question contains NO SUNSI sensitive material(the checkbox to the right must be selected before this question can be submitted) NRC ITS TRACKING NRC Reviewer ID 1200712261133 Conference Call Requested? No Categ~ry IBSI - Beyond Scope Issue ITS Section: TBB POC: JFD N.I.I.M.b.er.:. PageNumnbirs).: ITS 3.3 Aron Lewin 5 Information ITS Number: OS1: DOC Number: Bases JFD Number; 3.3.10 None None None NRC OSI#61 The NRC is evaluating the licensees determination that the intermediate range channels is not considered to meet any Criterion of 10 CFR 50.36(d)(2)(ii). The information submitted by the licensee appears to be complete. Would the licensee like to submit any more information for consideration?

Background

                    -The Bases for CTS 3/4.3.1 and 3/4.3.2 do not specifically discuss the intermediate range nuclear instrument with regards to Applicable Safety Analysis.

Comment -The Bases for ITS LCO 3.3.10 (page 352of 636) state "the intermediate range neutron flux channels have no safety function and are not assumed to function during any UFSAR design basis accident or transient analysis. However, the intermediate range neutron flux channels provide on scale monitoring of neutron flux levels during startup and shutdown conditions. Therefore, they are being retained in Technical Specifications."

                    -The Bases for STS LCO 3.3.10 (NUREG-1430) states that "the intermediate range neutron flux channels satisfy Criterion 2 of 10 CFR 50.36(c)(2)(ii).

10 CFR 50.36(d)(2)(ii) discusses how a technical specification limiting condition for operation of a nuclear reactor must be established for an item meeting one of the four criteria listed. Issue D)ate 12/26/2007 [ Close Date [ 04/2'1/2008 Logged in User: Anonymous . Responses http://www.excelservices.com/exceldbs/itstrackdavisbesse.nsf/1 fddcea 1Od3bdbb585256e... 7/18/2008

NRC ITS Tracking Page 2 of 3 Licensee Response by Bryan While the ISTS Bases for ISTS 3.3.10 states that the intermediate Kays on 01/13/2008 range channels meet Criterion 2 of 10 CFR 50.36(d)(2)(ii), as stated in the ITS Bases (Volume 8, Page 352), the Intermediate Range channels for Davis-Besse have no safety function and are not assumed to function during any UFSAR design basis accident or transient analysis. However, the intermediate range neutron flux channels provide on scale monitoring of neutron flux levels during startup and shutdown conditions. Therefore, they are being retained in Technical Specifications. Davis-Besse is not attempting to relocate the Intermediate Range channel requirements to a licensee controlled document. Furthermore, during a phone conversation with the NRC concerning this issue, one NRC reviewer stated that if we did not identify these instruments as meeting Criterion 2, we could then take them out of the ITS. However, the statement that they do not meet any of the criteria is a Bases statement, which simply states why the intermediate range instruments are being maintained in the ITS. The statement by itself (i.e., that no criteria for inclusion are met) does not justify relocating the Intermediate Range instruments. In order for Davis-Besse to justify their relocation, the NRC would have to review and approve a Technical.Specification change. As stated above, Davis-Besse is not proposing relocating the Source Range requirements. Therefore, since this is a Bases change only, and it has no affect on the Technical Specification requirements (the statement is only stating why the requirement is in the ITS), the change is not a beyond scope change, as defined in NRC Generic Letter 96-04. The Generic Letter states that beyond scope issues are those that differ from existing Technical Specifications and the improved Standard Technical Specifications. Since this specific change is not a Technical Specification change and does not differ from the Davis-Besse CTS, it is not a beyond scope issue. NRC Response by Aron Lewin ITSB has all information needed to make final determination on 01/17/2008 Licensee Response by Bryan The followingadditional information is provided to supplement Kays on 03/16/2008 our response of 1/13/2008. NRC letter dated May 9, 1998, from T. E. Murley to W. S. Wilgus (letter provided in attachment), provided, in part, the results of the NRC Staff Review of Letter dated October 15, 1987, from R. L. Gill, B&W Owners Group, to Dr. T. E. Murley, NRC,

Subject:

B&W Owners Group Technical Specification Committee Application of Selection Criteria to the B&W Standard Technical Specifications. On pages 5 and 6 of the enclosure to the letter (the NRC Staff Review document), it is stated "For the purpose of this application of the guidance in the Commission Policy Statement, the staff agrees with the Owners Groups' conclusions (emphasis added) except in two areas. First, the staff finds the Remote Shutdown Instrumentation meets the Policy Statement criteria for inclusion in Technical Specifications based on risk; and second, the staff is unable to confirm the Owners Groups' conclusion that Category 1 Post-Accident http://www.excelservices.com/exceldbs/itstrackdavisbesse.nsf/1 fddceal Od3bdbb585256e... 7/18/2008

NRC ITS Tracking Page 3 of 3 Monitoring Instrumentation is not of prime importance in limiting risk." Appendix A provides the specific results for the B&W report. Table 1 lists LCOs to be retained. Under instrumentation, Reactor Protection System Instrumentation is listed, with a Note 2. Note 2 states, in part, "The Policy Statement criteria should not be used as the basis for relocating specific trip functions, channels, or instruments within these LCOs. In the B&W report, in the summary disposition matrix, the following is noted: Page 4 of 15 Intermediate Flux Range Criteria for Inclusion - No NRC Response by Aron Lewin No further questions at this time. on 04/21/2008 q Date Created: 12/26/2007 11:33 AM by Aron Lewin Last Modified: 04/21/2008 10:16 AM http://www.excelservices.com/exceldbs/itstrack-davisbesse.nsf/lfddcealOd3bdbb585256e... 7/18/2008

IrEXT-88-04897 UNITED STATES NUCLEAR REGULATORY COMMISSION WASHINOTON. D. C. 20SS1 FI IL RORSUM NPD UCENSINO MAY 9 1ga9 Hr. Walter S. Wilgus, Chairman MAY 10 19R8 The B&E Owners Group Suite 525 ockvl.E.1M0 V -' 301.230.210 1700 Rockville Pike Rockville, Maryland 20852

Dear Kr. Wilgus:

This letter is in response to your report identifying which Standard Technical Specification (STS) requirements you believe should be retained in the new STS and which can be relocated to other licensee-controlled documents. The enclosure to this letter documents the NRC staff's conclusions as to which current STS requirements must be retained in the new STS. These conclusions are based on the Commissionks\lnterim Policy Statement on Technical Specifica-tion Improvements and on several interpretations of how to apply the screening Sý criteria contained In that Policy.Statement. The NRC staff considered comments made by industry at a March 29, 19g8 meeting between NRC, NUMARC, and each Owners Group in making these Interpretations. Based on our review, we have concluded that a significant reduction can be made in the number of Limiting Conditions for Operation (and associated Surveillance Requirements) that must be included in the 51S. Our goal is to assure that the new STS contain only requirements that are consistent with 10 CFR 50.36 and have a sound safety basis. The development of the new STS based on the staff's conclusions will result in more efficient use of NRC and industry resources. Safety improvements are expected through more operator-oriented Technical Specifications, improved Technical Specification Bases. a reduction in action statement-induced plant transients, and a reduction in testing at power. As you are aware, the NRC staff and industry also have underway a parallel program of specific line item improvements to both the scope and substance of the existing Technical Specifications. The need for many of these types of improvements was identified in the report (NUREG-1024) of a major staff task group established in 1983 to study surveillance requirements in Technical Specifications and develop alternative approaches to provide better assurance that surveillance testing does not adversely impact safety. The NRC will continue to actively identify and pursue the development of specific line item improvements to Technical Specifications and will make these improvements immediately available to licensees without waiting for the new STS. We encour-age each of the Owners Groups to continue to work with the NRC staff on these, types of parallel improvements to existing Technical Specifications.

S :0 Mr. W. S. Wilgus ' We are confident that the enclosed staff report provides an adequate basis for Groups to proceed with the development of complete new STS in accordance : the Owners with the Commission's Interim Policy Statement.

 .We will continue to interact with the NUMARC Technical Specification Working, Group and each of the individual vendor Owners Groups as rpided to keep this important program moving forward.

Sincerely, S!r I .. ~tyP dj* Thomas E. Murley, Director Office of Nuclear Reactor Regulation

Enclosure:

As-stated cc see next page DISTRIBUTION: SAVarga DOEA R/F DCrutchfleld OTSB Members JGPartlow PDR JPStohr Central Files JWRoe Murley/Sniezek FJMiraglia TThartin BABoger CERossi GCLalnas EJButcher FSchroeder AThadani JRichardson LShao (W.S.WILGUS/LTR/SPLIT:REPORT) CONCURRENCE:

                       *(see previous concurrence)
      *TSB:DOEA:MRR    *TSB:NRR       *C:ISB:NRR       *D:DOEA:NRR *D:DEST:NRR *':DEST:NRR k~esaI :psi       DCFischer EJButcher            CERossi        Aihadani     LShao 4/18/88           04/19/88eB    04/20/88         04/22/88       04/26/88. 04/26/88 0      *D:DREP:NRR AM)T:NRR JRStohr      T [Martin        £" rley 5/V/  88 04/28/88     0'5/05/B8

Mr. W. S. Wilgus cc w/enc1: Mr. Robert Gill B&W Owners Group P. 0. Box 33189 422 South Church Street Charlotte, Horth Carolina 28242 Mr. R. E. Bradley BWR Owners Group c/o Georgia Power Nuclear Operations Department 14th Floor 333 Piedmont Avenue Atlanta, Georgia 30308 Mr. Edward Lozito Westinghouse Owners Group c/o Virginia Power P. 0. Box 26666 Richmond, Virginia 23261 Mr. Joseph B. George Westinghouse Owners Group Texas Utilities 400 North Olive Dallas, Texas 75201 Mr. Stewart Webster CE Owners Group 1000 Prospect Hill Road Winstor, Connecticut 06095-0500 Mr. R. A. Bernier CE Owners Group c/o Arizona Nuclear Power Project P. 0. Box 52034 M.S. 7048 Phoenix. Arizona 85072 Mr. Thomas Tipton NUMARC 1776 Eye Street. N.W. Suite 300 p0 Washington, D. C. 20006-2496

f NRC STAFF REVIEW OF NUCLEAR STEAM SUPPLY SYSTEM VENDOR OWNERS GROUPS' APPLICATION OF THE COMI4ISSION'S INTgRIM POLICY STATEMENT CRITERIA TO

       'STANDARD TECHNICAL SPECIFICATIONS

1. INTRODUCTION On February 6. 1987, the Commission issued its Interim Policy Statement on Technical Specification Improvements (52 FR 3788). The Policy Statement encourages the industry to develop new Standard Technical Specifications (STS) to be used as guides for licensees in preparing improved Technical Specifications (TS) for their facilities. The Interim Policy Statement contains criteria (including a discussion of each) for determining which regulatory requirements and operating restrictions should be retained in the new STS and ultimately in plant TS. It also identifies four additional systems that are to be retained on the basis of operating experience and probabilistic risk assessments (PRA).

Finally, the Policy Statement indicates that risk evaluations are an appropriate tool for defining requirements"that should be retained in the STS/TS where including such requirements is consistent with the purpose of TS (as stated in the Policy Statement). Requirements that are not retained in the new STS would generally not be retained In individual plant TS. Current TS requirements not retained in the STS will be relocated to other licensee-controlled documents. One of the first steps in the program to implement the Commission's Interim Policy Statement is to determine which Limiting Conditions for Operation (LCOs) contained in the existing STS should be retained in the new STS. An early decision on this issue will facilitate efforts to make the other improvements (described in the Policy Statement) to the text and Bases of those requirements that must be retained in the new STS. Each Nuclear Steam Supply System (NSSS) vendor Owners Group has submitted a report to the NRC for review that identifies which STS LCOs the group believes should be retained in the new STS and which can be relocated to other licensee-controlled documents. These four NSSS vendor submittals are as follows: (1) Letter dated October 15, 1987, R. L. Gill, B&W Owners Group, to Or. 1. E. Murley, NRC,

Subject:

"B&El Owners Group Technical Specification Committee Application of Selection Criteria to the B&W Standard Technical Specifications."
                                                      ** TOTAL  PAGE.01    **

I (2) Letter dated November 12. 1987, R. A. Newton, Westinghouse Owners Group, to NRC Document Control Desk,

Subject:

  *Westinghouse Owners Group MERITS Program Phase 11, Task 5,  Criteria Application Topical Report.'

(3) Letter dated December 11, 1987, J. K. Gasper, Combustion Engineering Owners Group, to Dr. T. E. Hurley, NRC

Subject:

"CEN-355,  CE Owners Group Restructured Standard Technical Specifications - Volume 1 (Criteria Application)."

(4) Letter dated November 12, 1987, R. F. Janecek, BWR Owners Group, to R. E. Starostecki, NRC,

Subject:

"BWR Owners Group Technical Specification screening Criteria Applicbtion and RiskAssessment.w These submittals provide the rationale for why each STS requirement (e.g.

Limiting Condition for Operation) should be retained in the new STS or why it can be relocated to a licensee-controlled document. They also describe how each Owners Group used risk insights in determining the appropriate content of the new STS.

2. STAFF REVIEW The NRC staff focused its review on those requirements identified by the Owners Groups as candidates for relocation. The staff evaluated each of these requirements to determine whether it agreed with the Owners Groups' conclusions.

During the NRC Staff's review, several issues were raised concerning the proper interpretation or application of the criteria in the Commisslon's Interim Policy Statement. The NRC Staff has considered these issues and concluded the following:' (1) Criterion 1 should be interpreted to include only instrumentation used to detect actual leaks and not more broadly to include instrumentation used

1 to detect precursors to an actual breech of the reactor coolant pressure boundary or instrumentation to identify the source of actual leakage (e.g., loose parts monitor, seismic instrumentation, valve position Indicators). E2) The "initial conditions" captured under Criterion 2 should not be limited to only "process variables" assumed In safety analyses. They should also include certain active design features (e.g., high pressure/low pressure system valves and interlocks) and operating restrictions (e.g., pressure-temperature operating limit curves), needed to preclude unanalyzed accidents. In this context, "acttve design features" include only design features under the control of operbtions personnel (i.e., licensed operators and personnel who perform control.functions at the direction of licensed opera-tors). This position is consistent with the conclusions reached by the Staff during the trial application of the criteria to the Wolf Creek and Limerick Technical Specifications. (3) The "initial conditions" of design-basis accidents (DBA) and transients, as used in Criterion 2, should not be limited to only those directly "monitored and controllee" from the control room. Initial conditions should also in-clude other features/characteristics that are specifically assumed in DBA and transient analyses even if they can not be directly observed in the control room. For example, initial conditions (e.g., moderator temperature coefficient and hot channel factors) that are periodically monitored by other than licensed operators (e.g., core engineers, instrumentation and control technicians) to provide licensed operators with the information required to take those actions necessary to assure that the plant is being operated within the bounds of design and analysis assumptions, meet Criterion 2 and should be retained in Technical Specifications. Initial conditions do not, however, include things that are purely design requirements. (4) The phrase "primary Success patha"used in Criterion 3, should be interpreted to include only the primary equipment (including redundant trains/components) to t\ý t vtp ettS and ttrasients. Prinry success path does not include W ~ 04~ 6402Yse ~tTU iAma' 1

                                         %Sr pj~tatj~OT U5ed tQ pTt'e'W At

P. 02

                                       -40 accidents or transients or to improve reliability of the mitigation function (e.g., rod withdrawal block which is backup to the average power range monitor high flux trip in the startup mode, safety valves which' are backup to low temperature over pressure relief valves during cold- shutdown).

(5) Post-Accident Monitoring Instrumentation that satisfies the definition of Type A variables in Regulatory Guide 1.97, OInstrumentation for Water-Cooled Nuclear Power Plants to Assess Plant and Environs Conditions During and Following an Accident,' meets Criterion 3 and should be retained in Technical Specifications. Type A variables provide primary information (i.e., information that.1i essential for the direct accomplishment of the specified manual actions (lncbadlng long-term recovery actions) for which no automatic control is provided and that are required for safety systems to accomplish their safety functions for DBAs or transients). Type A variables'do not include those variables associated with contingency actions that may also be Identified in written procedures to compensate for failures of primary equipment. Because only Type A variables meet Criterion 3, the STS should contain a narrative statement that indicates that individual plant Technical Specifications should contain a list of Post-Accident Instrumentation that Includes Type A variables. Other Post-Accident Instrumentation (i.e., non-Type A Category 1) is discussed on page 6. (6) The NRC's design basis for licensing a plant is the plant's Final Safety Analysis Report (FSAR) as qualified by the analysis performed by the staff and documented in the staff's safety evaluation report (SER). Because the staff's review and resulting SER are based on the acceptance criteria in the NRC's Standard Review Plan (NUREG-0800, SRP), the dose limits used In licensing a particular plant may be 'some small fraction" of those specified in the Commisslon's regulations In Title 10 of the Code of Federal Regulations Part 100 (10 CFR 100). Accordingly,, the SRP limits should be used to define the equipment in the primary success path for mitigating accidents and transients when developing the new STS. These types of conservatisms are required to compensate for uncertainties in analysis techniques and

provide reasonable assurance that the absolute numerical limits of the regulations will be satisfied. On a plant-specific basis, systems and equipment that are identified in the NRC staff SER and assumed by the staff to function are considered part of the licensing basis for the plant and are captured by Criterion 3 (e.g., radiation monitoring instrumentation that initiates an isolation function, penetration room exhaust air cleanup system). (7) DBA and transients, as.used In Criteria 2 and 3, should be interpreted to include any design-basis event described in the FSAR (i.e., not just those events described in Chapters i and 15 of the FSAR). For example, there may be requirements for some plants which should be retained in Technical Specifications because of the risks associated with some site-specific characteristic (e.g., although not normally required, a Technical Specifi-cation on the chlorine detection system might be appropriate where a sig-nificant chlorine hazard exists in the site vicinity; similarly, a Tech-nical Specification on flood protection might be appropriate where a plant is particularly vulnerable to flooding and is designed with special flood protection features). Criteria 2 and 3 should not be interpreted to in-clude purely generic design requirements applicable to all plants (e.g., the requirements of General Design Criterion 19 in Appendix A to 10 CFR Part 50 for control room design). The NRC staff has used the Commission's Interim Policy Statement and the conclusions described above to define the appropriate content of the new STS. The staff plans to factor these conclusions into the Final Policy Statement on Technical Specification Improvements that will be proposed to the Commission. The staff reviewed the methodology and results provided by each Owners Group 'to verify that none of the requirements proposed for relocation contains constraints of prime importance in limiting the likelihood or severity of accident sequences that are commonly found to dominate risk. For the purpose

of this application of the guidance in the Commission Policy Statement, the staff agrees with the Owners Groups' conclusions except in two areas. First, the staff finds that the Remote Shutdown Instrumentation meets the Policy State-ment criteria for inclusion In Technical Specifications based on risk; and second, the staff is unable to confirm the Owners Groups' conclusion that Category I Post-Accident Monitoring Instrumentation Is not of prime importance in limiting risk. Recent PRAs have shown the risk significance of operator re-covery actions which would require a knowledge of Category 1 variables. Furthermore, recent severe accident studies have shown significant potential for risk reduction from accident management. The Owners Groups' should develop further risk-based justification In support of relocating any or all Category 1 variables from the Standard Technieal Specifications. As stated in the Commission's Interim Policy Statement, licensees should also use plant-specific PRAs or risk surveys as they prepare license amendments to adopt the revised STS to their plant. Where PRAs or surveys are available, licensees should use them to strengthen the Bases as well as to screen those Technical Specifications to be relocated. Where such plant-specific risk surveys are not available, licensees should use the literature available on risk Insights and PRAs. Licensees need not complete a plant-specific PRA before they can adopt the new STS. The NRC staff will also use risk insights and PRAs in evaluating the plant-specific submittals.

3. RESULTS OF THE STAFF'S REVIEW Appendices A through 0 present the detailed results of the staff's review of the Babcock and Wilcox, Westinghouse, Combustion Engineering, and General Electric application of the selection criteria to the existing 55. Each Appendix con-sists of two tables. Table 1 identifies those LCUs that must be retained in the new STS. Table 2 lists those LCOs that may be wholly or partially relocated to licensee-controlled documents (or be reformatted as a surveillance requirement for another LCO). Where the staff placed specific conditions on relocation of particular LCOs the staff has so noted In the Tables. As a part of the

plant specific implementation of the new STS, the staff plans to review the location of, and controls over, relocated requirements. In as much as practi-cable, the Owners Groups should propose standard locations for, and controls over, relocated requirements. For each LCO listed in Table 1, the criterion (criteria) that required that the LCO be retained in Technical Specifications is identified. If an LCO was retained in Technical Specifications solely on the basis of risk, "Risk" appears In the criteria column. Where an Owners Group determined that an LCO had to stay in Technical Specificatiqns (because of either a particular criterion or risk) and the Staff agreed that the LCO should be retained in TechnicalSpecif-Ications, the staff did not, in g4beral, verify the Owners Group's basis for retention. However, in several instances the Owners Groups cited risk consider-ations alone as the basis for retaining Technical Specifications and the staff disagreed with the Owners Groups. In these instances, the staff's basis for retention appears in the criteria column of Table 1. Any LCO not specifically Identified in Table 1 or Table 2 (e.g., an LCO unique to an STS not addressed in the Owners Groups submittals such as the BWR5 STS) should be retained In the STS until the Owners Group proposes and the staff makes a specific determination that it can be relocated to a licensee-controlled document. Notwithstanding the results of this review, the staff wilt give further consideration for relocation of additional LCOs as the staff and industry proceed with the development of the new STS.

4. CONCLUSION The results of the effort of the Owners Groups and of the NRC staff to apply the Policy Statement selection criteria to the existing STS are an Important step toward ensuring that the new STS contain only those requirements that are consistent with 10 CFR 50.36 and have a sound safety basis. As shown in the

following tables, application of the criteria contained in the Commission's Interim Policy Statement resulted in a significant reduction in the number of LCOs to be Included in the new STS. The development of the new STS based on the staff's conclusions will result in more efficient use of NRC and industry resources. Safety improvements are expected through more operator-oriented Technical Specifications, improved Technical Specification Bases, a reduction in action statement-Induced plant transients, and a reduction in testing at power.

---

- ----------- ft BABCOCK GENERAL,

                 &                                 COMBUSTION          ELECTRIC LCOs            WILICOX        WESTINGHOUSE         ENGINEERING         BWR4/BWR6 Total Number          137               165                 159                124/144 Retained         75                92                  87                 81/B6 Relocated        62                73                  72                 43/58 Percent Relocated        45%               44%                 45%               35%/40%

We' are confident that the staff's conclusions will provide an adequate basis for the Owners Groups to proceed with the developmentof complete new STS in accordance with the Commission's Interim Policy Statement.

APPENDIX A RESULTS OF THE NRC STAFF REVIEW BABCOCK & WILCOX .OWNERS GROUP'S SUBMITTAL RETENTION AND RELOCATION PF SPECIFIC TECHNICAL SPECIFICATIONS

APPENDIX A TABLE I LCOs TO BE RETAINED IN BABCOCK 6 WILCOX STANDARD TECHNICAL SPECIFICATIONS LCO CRITERIA 3.1 REACTIVITY CONTROL SYSTEM 3.1.1.1 Shutdown Margin (Note 1) 2 3.1.1.2 Moderator Temperature Coefficient 2 3.1.1.3 Minimum Temperature for Criticality 2 3.1.3.1 Group Height - Safety and Regulating Rod Groups 2 3.1.3.2 Group Height -Axial Power Shaping Rod Group 2 3.1.3.6 Safety Rod Insertion Limit 2&3 3.1.3.7 Regulating Rod fnsertion Limits 2 3.1.3.9 Xenon Reactivity 2 3.2 POWER DISTRIBUTION LIMITS 3.2.1 Axial Power Imbalance 2 3.2.2 Nuclear Heat Flux Hot Channel Factor 2 3.2.3 Nuclear Enthalpy Rise Hot Channel.Factor 2 3.2.4 Quadrant Power Tilt 2 3.2.5 DNB Parameters 2. 3.3 INSTRUMENTATION 3.3.1 Reactor Protection System Instrumentation (Note 2) 3 3.3.2 Engineered Safety Feature Actuation"System Instrumentation (Note 2) 3 3.3.3.1 Radiation Monitoring Instrumentation (Notes 2 A 3) 3 3.3.3.5 Remote Shutdown Instrumentation (Notes 2 &.4) Risk 3.3.3.6 Accident Monitoring Instrumentation 3 3.4 REACTOR COOLANT SYSTEM 3.4.1.1 Startup and Power Operation " 3 3.4.1.2 Hot Standby 3 3.4.1.3 Hot Shutdown 3 3.4.1.4 Cold Shutdown Policy Statement (DHR) 3.4.3 Safety Valve - Operating'. 3 3.4.4 Pressurizer 2 3 3.4.5 Relief Valve 3 3.4.6 Steam Generators - Water Level 2 3.4.7.1 Leakage Detection System I 1 A-1

B&W-TABLE I (Continued) CRITERIA LCO 3.4.7.2 Operational Leakage 2 3.4.9 4Pecific Activity 2 3.4.10.1 Reactor Coolant System Pressure/Temperature Limits 2 3.4.10.3 Overpressure Protection System 2 3.5 EMERGENCY CORE COOLING SYSTEM,(ECCS) 3.5.1 Core Flooding Tanks 2 &3 3.5.2 ECCS Subsystems - T .t (305)°F 3 3.5.3 ECCS Subsystems -Tav <(305)°F 3 3.5.4 Borated Water Storage Tank 2 &3 3.6 CONTAIIENT SYSTEMS 3.6.1.1 Containment Integrity 3 3.6.1.3 Containment Air Locks 3 3.6.1.5 Internal Pressure 2 3.6.1.6 Air Temperature 2 3.6.1.8 Containment Ventilation System 3 3.6.2.1 Containment Spray System 3 3.6.2.2 Spray Additive System 2 &3 3.6.2.3 Containment Cooling System 3 3.6.3 Iodine Cleanup System 3 3.6.4 Containment Isolation Valves 3 3.6.5.1 Hydrogen Analyzers 3 3.6.5.2 Electric Hydrogen'Recombiners (Note 5) 3 3.6.6 Penetration Room Exhaust Air Cleanup System 3. 3.7 PLANT SYSTEMS 3.7.1.1 Safety Valves 3 3.7.1.2 Auxiliary Feedwater System 3 3.7.1.3 Condensate Storage Tank 2 &3 3.7.1.4 Activity 2 3.7.1.5 Main Steam Line Isolation Valves 3 3.7.3 Component Cooling.'ater System 3 3.7.4 Service Water System 3 3.7.5 Ultimate Heat Sink 3 3.7.6 Flood Protection (optional) 3 3.7.7 Control Room Emergency Air Cleanup System 3 3.7.8 ECCS Pump Room Exhaust Air Cleanup System. 3 (optional) A-2

I B&W-TABLE I (Continued) LCO CRITERIA 3.8 ELECTRICAL POWER SYSTEMS 3.8.1.1 A.C. Sources - Operating 3 3.8.1.2 A.C. Sources - Shutdown Policy Statement (DHR) 3.8.2.1 A.C. Distribution - Operating 3 3.8.2.2 A.C. Distribution - Shutdown Policy Statement (DHR) 3.8.2.3 D.C. Distribution - Operating 3 3.8.2.4 D.C. Distribution - Shutdown Policy Statement (DHR) 3.9 REFUELING OPERATIONS 3.9.1 Boron Concentration 2 3.9.2 Instrumentation 3 3.9.3 Decay Time . 2 3.9.4 Containment Building Penetration 3, 3.9.8.1 Residual Heat RemovAl and Coolant Circulation - All Water Levels Policy Statement (DHR) .3.9.8.2 Residual Heat Removal and Coolant Circulation - 3.9.9 Low Water Levels Policy Statement (DHR) Containment Purgeand Exhaust Isolation System 3 3.9.10 Water Level - Reactor'Vessel 2 3.9.11 Water Level - Storage Pool 2 3.9.'!2 Storage Pool Air Cleanup System 2 Notes:

1. Required for Modes 3 through 5. May be relocated for Modes 1 and'2.

2. The LCO for this-system should be retained In STS. The Policy Statement criteria should not be used as the basis for relocating specific trip functions, channels, or instruments within these LCOs.

3. The staff is pursuing alternative approaches which would allow relocation of some of these LCOs on a schedule consistent with'the schedule for development of the new STS. The staff is also initiating rulemaking to delete the requirement that RETS be included in Technical Specifications.

4. Because fires (either inside or outside the control room) can be a significant contributor to the core melt frequency and because the uncertainties with fire initiation frequency can be significant, the staff believes that this LCO should be retrained in the STS at this time. The staff will consider.

relocation of Remote Shutdon mnsttentation on a plant-specific basis. S. This LCO will be considered for relocation to a licensee-controlled document on a plant-specific basis. A-3

TABLE 2 (Note 1) BABCOCK & WILCOX STANDARD TECHNICAL SPECIFICAT1ON LCOs WHICH MAY BE RELOCATED 1CO 3.1 REACTIVITY CONTROL SYSTEMS 3.1.2.1 Flow Paths - Shutdown 3.1.2.2 Flow Paths - Operating 3.1.2.3 Makeup Pump - Shutdown 3.1.2.4 Makeup Pump - Operating 3.1.2.5 Decay Heat Removal 'Pump - Shutdown 3.1.2.6 Boric Acid Pumps - Shutdown 3.1.2.7 Boric Acid Pumps - Operating 3.1.2.8 Borated Water. Source - Shutdown 3.1.2.9 Borated Water Sburce - Operating 3.1.3.3 Position IndicatiottChannels - Operating (Note 2) 3.1.3.4 Position Indication'Channels Shutdown-(Note 2) 3.1.3.5 Rod Drop Time (Note 2) 3.1.3.8 Rod Program.. 3.3 INSTRUMENTATION 3.3.3.2 Incore Detectors 3.3.3.3 Seismic Instrumentation 3.3.3.4 Meteorological Instrumentation 3.3.3.7 Chlorine Detection System 3.3.3.8 Fire Detection 3.3.3.9 Radioactive Liquid Effluent Monitor (Note 3) 3.3.3.10 Radioactive Gaseous Effluent Monitor (Note 3) 3.3.4 Turbine Overspeed Protection 3.4 REACTOR COOLANT SYSTEM 3.4.2 Safety Valves - Shutdown 3.4.6 Steam Generators Tube Surveillance (Note 4) 3.4.8 Chemistry 3.4.10.2 Pressurizer Temperatures 3.4.11 Structural Integrity ASHE Code (Note 4) 3.4.12 RCS Vents 3.6 CONTAINMENT SYSTEMS, 3.6.1.2 Containment Leakage (Note 5) 3.6.1.7 Containment Structural Integrity (Note 2) 3.7 PLANT SYSTEMS 3.7.2 Steam Generator Pressure/Temperature Limits 3.7.9 Snubbers 3.7.10 Sealed Source Contamination

I B&W-TABLE 2 (Continued) LCO 3.7.11.1 Fire Suppression Water System 3.7.11.2 Spray and/or Sprinkler Systems 3.7.11.3 CO System 3.7.11.4 Haon System. 3.7.11.5 Fire Hose Stations 3.7.11.6 Yard Fire Hydrants and Hydrant Hose Houses 3.7.12 Fire Barrier Penetrations 3.7.13 Area Temperature Monitoring 3.9 REFUELING OPERATIONS 3.9.5 Communications 3.9.6 Fuel Handling Bridge 3.9.7 Crane Travel ;pent Fuel Storage Pool Building 3.10 SPECIAL TEST EXCEPTJONS 3.10.1 Shutdown Margin (Note 6) 3.10.2 Group Height Insertion Limits and Power Distribution Limits (Note 6) 3.10.3 Physics Tests (Note 6). 3.10.4 Reactor Coolant Loops (Note 6) 3.11 RADIOACTIVE EFFLUENTS (Note 3) 3.11.1.1 Concentration 3.11.1.2 Dose 3.11.1.3 Liquid Radwaste Treatment System 3.11.1.4 Liquid Holdup Tanks 3.11.2.1 Dose 3.11.2.2 Dose - Noble Gases 3.11.2.3 Dose - Iodine - 131, Tritium and Radionuclides in Particulate Form 3.11.2.4 Gaseous Radwaste Treatment Systen 3.11.2.5 Explosive Gas Mixture 3.11.2.6 Gas Storage Tanks 3.11.3 Solid Radioactive Waste 3.11.4 Total Dose 3.12 RADIOACTIVE ENVIRONMENIAL MONITORING,(Note 3) 3.12.1 Monitoring Program 3.12.2 Land Use Census 3.12.3 Interlaboratory Comparison Program A-5

B&W-TABLE 2 (Continued) Notes:

1. Specifications listed in this table may be relocated contingent upon NRC staff approval of the location of and controls over relocated requirements.

2. This LCO may be removed from the STS. However, if the associated Surveillance Requirement(s) is necessary to meet the OPERABILITY requirements for a retained LCO, the Surveillance Requirement(s) should be relocated to the retained LCO.

3. The staff Is pursuing alternative approaches which would allow relocation of some of these LCUs on a schedule consistent with the schedule for develop-ment of the new STS. The staff is also initiating rulemaking to delete the requirement that RETS be included in Technical Specifications.

4. This LCO may be relocated.opt of Technical Specifications. However, the associated Surveillance Reqbirement(s) must be relocated to Technical Specification Section 4.0, Survrillance Requirements.

5. This LCO may be relocated. However, Pa, La, Ld, and Lt must be either retained in TS or in the Bases of the appropriate Containment LCO.

6. Special Test Exceptions may be included with corresponding LCOs.

NRC ITS Tracking Page I of 2 49Return to View Menu Print DOcuen RAI Screening Required: Yes Status: Closed This Document will be approved by: Gerald Regulatory Basis must be included in Comments Waig; Tim Kobetz section of this Form This document has been reviewed and Yes information in this question contains NO SUNSI sensitive material (the checkbox to the right must be selected before this question can be submitted) NRC ITS TRACKING NRC Reviewer ID ]200712261136 Conference Call Requested? No Category BSI - Beyond Scope Issue ITS Section:9 TB POC: JFD Number: Page Number(s): ITS 3.3 Aron Lewin None Information ITS Number. OS.!.:; DOC Numbern: Bases.-JFD .Number: 3.3.10 None None None NRC OSI#62 Discuss how the channel calibration is physically effected by referencing the RPS cabinet vice the preamplifier, and would therefore still assure that the necessary quality of systems and components is maintained, that facility operation will be within safety limits, and that the limiting conditions for operation will be met in accordance with 10 CFR 50.36(d)(3).

Background

                   -The Bases for CTS 3/4.3.1 and 3/4.3.2 discuss channel calibrations, but does not include some statements found in the ITS Bases discussion on channel Comment    calibrations.
                   -The ITS Bases (page 355 of 636) states "for intermediate range neutron flux channels, channel calibration is a complete check and readjustment of the channels from the RPS cabinet input to the indicators."
                   -The Bases for STS LCO 3.3.10 (NUREG-1430) states "for intermediate range neutron flux channels, channel calibration is a complete check and readjustment of the channels from the preamplifier input to the indicators."

10 CFR 50.36(d)(3) states that "surveillance requirements are requirements relating to test, calibration, or inspection to assure that the necessary quality of systems and components is maintained, that facility operation will be within safety limits, and that the limiting conditions for operation will be met." Issue D!ate 12/26/2007 Close Date 101/17/2008 Logged in User: Anonymous ' Responses http://www.excelservices.com/exceldbs/itstrack davisbesse.nsf/1 fddcea 1Od3bdbb585256e... 7/18/2008

NRC ITS Tracking Page 2 of 2, Licensee Response by Bryan The RPS Intermediate Range instrumentation is a compensated ion Kays on 01/13/2008 chamber whose output goes directly to a logarithmic amplifier (which is not a preamplifier) in the RPS cabinets. There is no preamplifier for the Intermediate Range instrumentation. Therefore, the words in the ISTS Bases (Volume 8, Page 330) were changed to be consistent with the Davis-Besse design. As described in the ITS Bases (Volume 8, Page 355), the CHANNEL CALIBRATION checks from the RPS cabinets (which includes the logarithmic amplifier) to the indicator, consistent with the manner the current CHANNEL CALIBRATION is performed. As such, this. Bases change should not be considered a beyond scope issue. NRC Response by Aron Lewin No further questions at this time. on 01/17/2008 Date Created: 12/26/2007 11:36-AM by Aron Lewin Last Modified: 01/17/2008 09:18 AM http://www.excelservices.com/exceldbs/itstrack-davisbesse.nsf/lfddcealOd3bdbb585256e... 7/18/2008

NRC ITS Tracking Page I of 2 Return to View Menu Print Docmn RAI Screening Required: Yes Status: Closed This Document will be approved by: Greg Regulatory Basis must be included in Comments Cranston section of this Form This document has been reviewed and Yes information in this question contains NO SUNSI sensitive material (the checkbox to the right must be selected before this question can be submitted) NRC ITS TRACKING NRC Rpvipvwr ID200712030909 Conference Call Requested? No Categoy BSI - Beyond Scope Issue ITS Section: TB POC: JFDD Number: Page..Number(s):. ITS 3.3 Aron Lewin None 3 Information ITS Number.: 0S1:1 D.OCNumber: Bases..JFD Number: 3.3.11 2 M.2 None In the Discussion of Changes section, Item M02, changes the Allowable Values for the Steam Line Pressure-Low, Steam Generator Level-Low, and Steam Generator Feedwater Differential Pressure-High Functional Units. The staff Comment believes that these parameters have been changed due to the proposed 1.6% power uprate. Please describe the method used to determine and justify the proposed Allowable Values for the Steam Line Pressure-Low, Steam Generator Level-Low, and Steam Generator Feedwater Differential Pressure-High Functional Units.

       !ssue :D:!ate   12/03/2007 Close Kate] 01/16/2008 Logged in User: Anonymous

'" Responses Licensee Response by Bill The License Amendment Request for the measurement uncertainty Bentley on 12/05/2007 recapture power uprate is LAR 05-0007. The proposed markup of the technical specifications that was submitted as part of LAR 05-0007 had no changes to the SFRCS Technical Specifications. Therefore, the parameters have not been changed due to the proposed power uprate. As described in DOC M02, revised calculations were performed for these specific instrument strings. The revisions were required for various reasons as determined by the Davis-Besse corrective action process. As stated in DOC M02, the proposed Allowable Values are calculated using Method 1 or Method 2 of ISA RP 67.04.02-2000. The actual calculations can be http://www.excelservices.com/exceldbs/itstrackdavisbesse.nsf/1 fddcea 1Od3bdbb585256e... 7/18/2008

NRC ITS Tracking Page 2 of 2 1iprovided, if desired. ii Date Created: 12/03/2007 09:09 AM by Jason Paige Last Modified: 01/16/2008 10:39 AM http://www.excelservices.com/exceldbs/itstrackdavisbesse.nsf/1 fddceal Od3bdbb585256e... 7/18/2008

NRC ITS Tracking Page I of 3 14ýReturn to View Menua Print Documen RAI Screening Required: Yes Status: Closed This Document will be approved by: Gerald Regulatory Basis must be included in Comments Waig; Tim Kobetz section of this Form This document has been reviewed and Yes information in this question contains NO SUNSI sensitive material (the checkbox to the right must be selected before this question can be submitted) NRC ITS TRACKING NRC' Rpvipawr ID 200712261240 Conference Call Requested? No Categor [BSI - Beyond Scope Issue ITS Section: TB POC: JFD Number: Page Number(s): ITS 3.3 Aron Lewin Iqbal Ahmed 11 371 Information ITS Number: OSI: DPOC Nurmber: Bases JFD Number: 3.3.11 2 M.2 None Questin submitted by Iqbal Ahmed. With regard to TS Table 3.3-12 trip setpoint allowable values (AV) for Steam Line Pressure-Low, Steam Generator Level-Low, and Steam Generator Feedwater Differential Pressure-High, functional units instrumentation: Provide documentation (including sample calculations) used for establishing the limiting setpoint (or NSP) and the limiting acceptable values for the As-Found and As-Left setpoints as measured in periodic surveillance testing. Com.!nmenr~t Indicate the related Analytical Limits and other limiting design values (and the sources of these values) for each setpoint. To determine the acceptability of the proposed TSs change involving revision of instrumentation setpoints, the NRC staff generically requests all licensees who propose revision of instrumentation setpoint and/or setpoint AVs (conservative or non-conservative), to provide the above information (I&C Branch Guideline for Setpoint-Related TSs License Amendment Request - ADAMS Accession No. ML061810132) Issue Date 1F2/26/2007 Close.Date 04/08/2008 Logged in User: Anonymous

' Responses Licensee Response by Jerry             Calculation C-ICE-083.03-003 for the Main Steam Line Pressure -

Jones on 03/10/2008 Low channels is provided in the attachmffent. The Allowable Value is discussed in Section 5.3, Limiting Trip Setpoint is discussed in Section 5.4, the Nominal Trip Setpoint is discussed in Section 5.5, http://www.excelservices.com/exceldbs/itstrackdavisbesse.nsf/1 fddcea 1Od3bdbb585256e... 7/18/2008

NRC ITS Tracking Page 2 of 3 the As-Found tolerance is discussed in Section 5.6, the As-Left tolerance is discussed in Section 4.12, and the Analytical Limit is discussed in Section 5.2. Licensee Response by Jerry Calculation C-ICE-083.03-004 for the Feedwater/Steam Generator Jones on 03/10/2008 Differential Pressure - High channels is provided in the attachment. The Allowable Value is discussed in Section 5.4, Limiting Trip Setpoint is discussed in Section 5.5.1, the Nominal Trip Setpoint is discussed in Section 5.5.2, the As-Found tolerance is discussed in Section 4.8, the As-Left tolerance is discussed in Section 4.7, and the Analytical Limit is discussed in Section 1.2. Licensee Response by Jerry Calculation C-ICE-083.03-001 for the Steam Generator Level - Jones on 03/10/2008 Low channels is provided in the attachment. The Allowable Value is discussed in Section 5.10.1.1, Limiting Trip Setpoint is discussed in Section 5.10.1.2, the Nominal Trip Setpoint is discussed in Section 5.10.1.3, the As-Found tolerance is discussed in Section 4.11, the As-Left tolerance is discussed in Section 4.10, and the Analytical Limit is discussed in Section 1P0 (Known Inputs) and 5.1. NRC Response by Timothy Kolb Comment by Hukam Garg In regards to Calculation No. C-ICE-on 03/21/2008 083.03-004, Davis Besse has used the drift value which is for 18 months +25% while the CFT is being done monthly in determining the AS Found Tolerance. By using this drift value it will mask the operability of the instrument and does not meet the guidance provided in RIS 2006-17. Provide the basis for using this drift value or revise the calculation to detemine the As Found Tolerance. Licensee Response by Bill Davis-Besse agrees that the drift evaluation over an 18 month Bentley on 04/01/2008 period (Channel Calibration frequency) results in a larger as-found value. To ensure that the as-found values are conservative, the calculations will be revised with a drift value calculated consistent with the Channel Functional testing frequency. This calculation change does not impact the Allowable Values. Licensee Response by Jerry Davis-Besse believes that the reviewer comment from 3/21/2008 Jones on 04/04/2008 also applies to Calculation C-ICE-083.03-003. Therefore, Davis-Besse will agree in a commitment to the NRC that calculations C-ICE-083.03-003 and C-ICE-083.03-004 will be revised such that the As Found tolerance uses a drift value consistent with the Channel Functional Testing frequency. This commitment will be documented in the supplement to the ITS Conversion Amendment. Licensee Response by Bill For clarification, the commitment will state that the calculation Bentley on 04/04/2008 revisions will be completed prior to implementation of the Improved Tech Specs. NRC Response by Timothy Kolb Information supplied by the licensee is sufficient to complete the on 04/08/2008 safety evaluation input. No further questions at this time. This item is closed. http://www.excelservices.com/exceldbs/itstrackdavisbesse.nsf/1 fddceal Od3bdbb585256e.... 7/18/2008

NRC ITS Tracking Page 3 of 3 Date Created: 12/26/2007 12:40 PM by Timothy Kolb Last Modified: 04/08/2008 02:40 PM http://www.excelservices.com/exceldbs/itstrackdavisbesse.nsf/1 fddceal Od3bdbb585256e... 7/18/2008

Page I FirstEne~rgy CALCULATION COMPUTATION NOP-CC-3002-01 Rev. 03 CALCULATION NO.: REVISION: C-ICE-083.03-003 8 Analysis Methodology This calculation will perform an ISA Standard 67.04.01 setpoint and error analysis calculation for the SFRCS low pressure trip switches DB-PS3687A, DB-PS3687C, DB-PS3687E, DB-PS3687G, DB-PS3689B, DB-PS3689D, DB-PS3689F, and DB-PS3689H. These switches are Static-O-Ring Model No. 9TA-B5-NX-C1A-JJTTX12 (DIN 1) pressure switches. The minimum analytical limit for these pressure switches is fixed at 600 psia, decreasing basedon memorandum NEN-90-10190 (DIN 11). This calculation will establish the Allowable Value, the Limiting Trip Setpoint (LTSP), the Nominal Trip Setpoint (NTSP), and the As-Found and As-Left Tolerances consistent with Technical Specification Task Force Traveler 493 (DIN 30) and Regulatory Issue Summary 2006-17 (DIN 36) to ensure the analytical limits are not exceeded. This calculation will also calculate an eighteen month drift value for compliance with the Channel Calibration surveillance interval. This supports the Bases discussion in LAR 06-0003 (DIN 42). In addition, this would support a potential extension of the channel functional testing frequency from one month to three months. A License Amendment Request (LAR) independent of LAR 06-0003 and NRC approval is required before changes in the channel functional surveillance frequency may be utilized in the plant. j 1.1 Design Description The SFRCS low pressure trip switches are located in Rooms 500 and 501. The pressure switches monitor the steam pressure in the 36" main steam headers in Rooms 601 and 602. The safety function of the SFRCS low pressure trip switches is to detect a main steam line break (MSLB) or a main feedwater line break (MFWLB) in 18" feedwater lines between check valve DB-FW147 and steam generator 1 and check valve DB-FW156 and steam generator 2. Upon detection of low steam pressure by two-out-of-two logic channels, specifically channels 1 and 3 or channels 2 and 4, a trip signal is generated by the affected logic channel pressure switches. The trip signal occurs when the measured main steam line pressure is equal to or less than the pressure switch setpoint. This trip signal is utilized by the SFRCS to:, a) Determine and distinguish the affected (faulted) steam generator from the other (intact) steam generator. b) Isolate the supply of main feedwater and main steam to/from the steam generators. c) Initiate the Auxiliary Feedwater System to supply feedwater to the unaffected "intact" steam generator. d) Trip the reactor via the Anticipatory Reactor Trip System (ARTS). e) Trip the main turbine. The environmental conditions to which the SFRCS low pressure trip switches are exposed are:

1) The normal operating conditions of Rooms 500 and 501 are normal atmospheric pressure per DB1-100 (DIN 9, Pages 500-1 and 501-1), a minimum temperature of 60°F per System Description 028C (DIN 33, Section 1.2.1), and a maximum temperature of 104 0 F per DBl-100 (DIN 9, Page TAB-3). It should be noted that the normal atmospheric pressure in DBl-100 (DIN 9) is 14.7 psia, while this calculation conservatively uses 14.4 psia due to being approximately 600 feet above sea level. The conditions do not change in the room prior to switch actuation for a MSLB of the main steam line headers or a main feedwater line break between check valves FW147/FW156 and the steam

Page 2 FRrstEnergy CALCULATION COMPUTATION NOP-CC-3002-01 Rev. 03 CALCULATION NO.: REVISION: C-ICE-083.03-003 8 generators as these scenarios do not immediately affect rooms 500 and 501. (Conditions for switch safety function).

2) Harsh environmental conditions in Rooms 500 and 501 are provided by a HELB in the 6" main steam line to the Auxiliary Feedwater Pump Turbine (Reference EQ Package DB1-034A (DIN 3) and EQ File DBl-100 (DIN 9)). The peak pressure and temperature conditions in Rooms 500 and 501 during a HELB are 3670 F and 16.0 psia and 374 0F and 16.0 psia, respectively. The pressure switches are not required to provide a safety related function when exposed to a 6" main steam line HELB. However, failure of the pressure switch could cause an inadvertent SFRCS trip and since the switches are located in Rooms 500 and 501, both steam generators could be affected. Therefore, the pressure switches are required not to fail for 10 minutes (DIN 10) to allow operator time to respond to the event.

3) The harsh environmental conditions of radiation imported to Rooms 500 and 501 during a LOCA in conjunction to the normal operating conditions of Rooms 500 and 501 (conditions for pressure switch safety function).

2 Assumptions

1) No assumptions are necessary for this calculation.

3 Acceptance Criteria The acceptance criteria are that the calculation is performed in accordance with the ISA Standard 67.04.01-2000 (DIN 4) and the ISA Recommended Practice RP67.04.02-2000 (DIN 27). There are no specific numerical acceptance criteria associated with this calculation. The calculation must establish an Allowable Value and Limiting Trip Setpoint that include all required instrument uncertainties for the instrument string. If margin is added to the LTSP, the calculation must specify the Nominal Trip Setpoint. In addition, the calculation must specify the acceptable As-Found and As-Left Tolerances for incorporation into the Technical Requirements Manual and surveillance procedures. The setpoint must also be verified to be acceptable to allow plant shutdown without actuating the SFRCS. The SFRCS Block Permissive Switches are only associated with one steam generator in each actuation channel. Because the SFRCS Trip Switches have inputs from both steam generators in each actuation channel, the SFRCS may actuate on one of the actuation channels if the steam generator pressure is not kept relatively equal between steam generators during plant shutdown prior to reaching the block permissive setpoint. To assist in this, a minimum pressure difference between the trip setpoint and the postulated block permissive setpoint of 45 psi must be maintained. This is based on normally controlling the steam generator pressures within 20 psi by procedure DB-OP-06903 (DIN 32, Section 3.28) with a 25 psi margin. 4 Computation 4.1 Methodology The standard used by this calculation to determine the setpoint and setpoint tolerance based on a known safety limit is ISA 67.04.01-2000 (DIN 4). The standard defines minimum requirements and calculation methods for assuring that setpoints are established and held within specified limits in nuclear safety-related instruments. As provided in ISA 67.04.01-2000, determination of whether the instrument

Page 3 FirstEner,y CALCULATION COMPUTATION NOP-CC-3002-01 Rev. 03 CALCULATION NO.: REVISION: C-lCE-083.03-003 8 uncertainties are tested or not tested will dictate how the uncertainties are include in the calculations for the Allowable Value and trip setpoint. A graphical representation from the ISA standard is provided below. SAFETY LIMITf ANALYTICAL UMIT NOTE: THIS FIGURE IS INTENDED TO PROVIDE RELATIVE POSITION AND NOT TO IMPLY DIRECTION A C ALLOWABLE VALUE (LSSS) B KI' TRIP SETPOINT (LSSS) D NORMAL A. ALLOWANCE DESCRIBED IN PARAGRAPH 4.3.1 B. ALLOWANCE DESCRIBED IN PARAGRAPH 4.3.2 C. REGION WHERE CHANNEL MAY BE DETERMINED INOPERABLE D. PLANT OPERATING MARGIN E. REGION OF CALIBRATION TOLERANCE (ACCEPTABLE AS LEFT CONDITION) DESCRIBED IN PARAGRAPH 4.3.1. Figure I - Nuclear safety-related setpoint relation ships The Static-O-Ring pressure switches were tested and environmentally qualified under AETC report numbers 17344-82N-C (DIN 5) and 17344-82N-D (PIN 6). Discussion with Static-O-Ring (DIN 7) revealed that AETC report 17344-82N-D only applies to the aging tests. After the aging tests were completed, the switch internals were removed and installed in the pressure switch tested under AETC Report 17344-82N-C. This report covers the remainder of the qualification testing. The effects of static head will not be considered by this calculation. They are incorporated via the Data Packages for each individual switch (DIN 15, 16, 17, 18, 19, 20, 21, and 22).

Page 4 FirstEnem CALCULATION COMPUTATION NOP-CC-3002-01 Rev. 03 CALCULATION NO.-. REVISION: 0-I0E-083.03-003 8 There is no response time errors/effects accounted for in this calculation. The SFRCS analysis established delays of the instrumentation. The response time requirements from the analysis are in the Technical Requirements Manual (DIN 38) and verified by surveillance testing (DIN 39 and 40). An ambient pressure of 14.4 psig will be used as the cbnversion from the safety limit which is in psia to the gauge pressure in psig. This is conservative compared to the use of 14.7 psig since it will result in a slightly higher calculated psig value when converting from psia to psig. With the switch actuating on a decreasing signal, it will actuate sooner. The drift~will be evaluated separately to determine the impact on the existing plant setpoint for the pressure switches. See Attachment 1. 4.2 Calculation The uncertainties associated with the definitions of ISA 67.04.01-2000 (DIN 4), section 4.3.1 for determination of the Trip Setpoint are: Subsection 1, Instrument Calibration Uncertainty. Calibration Standard Calibration Equipment Calibration Method Subsection 2, Instrument Uncertainties During Normal Operation. Switch Accuracy Power Supply Voltage Effects Power Supply Frequency Effects Switch Temperature Effects (Normal) Switch Humidity Effects Switch Pressure Effects Switch Vibration Effects

                .'Switch Radiation Effects (Normal)

Analog to Digital Conversion Effects Digital to Analog Conversion Effects Subsection 3, Instrument Drift. Drift Subsection 4, Instrument Uncertainties Caused by Design Basis Events. Switch Temperature Effects (Abnormal) Switch Radiation Effects (Abnormal) Switch Seismic Effects Subsection 5, Process-Dependent Effects.

       'Subsection 6, Calculation Effects.

Subsection 7, Dynamic Effects. Subsection 8, Calibration and Installation Bias Accounting Also included, beyond the sections listed in the standard, are assessment/inclusion of: Switch Aging Effects Insulation Resistance Effects

Page 5 _FrstE~nerjyCALCULATION COMPUTATION NOP-CC-3002-01 Rev. 03 CALCULATION NO.: REVISION: C-lCE-083.03-003 8 As-Left (Calibration) Tolerance The uncertainties, which are "tested" as required by ISA 67.04.01-2000 (DIN 4), section 4.3.2 for inclusion in the determination of the uncertainty between the Allowable Value and Trip Setpoint are: Subsection 1, Instrument calibration Uncertainty. Calibration Standard Calibration Equipment Calibration Method Subsection 2, Instrument Uncertainties During Normal Operation. Switch Accuracy Power Supply Voltage Effects Power Supply Frequency Effects Switch Temperature Effects (Normal) Switch Humidity Effects Switch Pressure Effects Switch Vibration Effects Switch Radiation Effects (Normal) Analog to Digital Conversion Effects Digital to Analog Conversion Effects Subsection 3, Instrument Drift. Drift And: Switch Aging Effects As-Left (Calibration) Tolerance 4.3 Subsection 1, Instrument Calibration Uncertainty. 4.3.1 Calibration Standard (CS) The calibration standard will be set equal to the M&TE value. As the calibration standard is typically more accurate than the M&TE, this is conservative. CS + 1.0 psig 4.3.2 Calibration Equipment (CE) A pressure test gauge is used to calibrate the pressure switches by procedures DB-MI-03201 and DB-MI-03202 (DINs 12 & 13). The range and accuracy of the gauge is 0-1000 psig and + 0.1% of span, respectively. CE = + 1.0 psig Procedures DB-MI-03201 and DB-MI-03202 (DINs 12 & 13) are to use the above M&TE requirement or M&TE more accurate than the above requirement.

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.FrstEne...rgy                           CALCULATION COMPUTATION NOP-CC-3002-01 Rev. 03 CALCULATION NO.:                                                                                    REVISION:

C-lCE-083.03-003 8 4.3.3 Calibration Method There are two potential calibration method effects. The first effect is associated with the density change of the water in the reference legs. Procedures DB-MI-03201 and DB-MI-03202 (DINs 12 and 13) require the use of Data Packages (DINs 15, 16, 17, 18, 19, 20, 21, and 22) for calibration. Head affects due to the reference leg length are corrected in the Data Packages. The specific volume of water during calibration is 0.01605 (DIN 41). This is based on a temperature of 70OF (the M&TE is calibrated with a 68°F reference temperature) and atmospheric pressure. The specific volume of the water during the trip is 0.01600. This is based on temperature of 60°F in the room and process pressure of 650 psia (conservative value). As the water is more dense when expected to actuate, this will add a small fraction of pressure in the reference legs. The correction of the reference leg already assumes a pressure of 0.4335 psi / ft. The Calibration Method uncertainty is the difference between the expected error during the switch actuation and the calibration correction. There are two head correction differences used in the 8 Data Packages listed above, 18.25 feet and 18.83 feet. For the 18.25 foot difference, this results in: CM = (0.01605/0.01600 - 18.25 ft

• 0.4335 psi/ 1 ft) - (18.25 ft
• 0.4335 psi /l ft)

CM = 7.936 psig - 7.911 psig CM = 0.025 psig As the Data Packages use 8.0 psig as the calibration correction for reference leg head, this would bound the 7.936 psig for the worst case reference leg pressure. For the 18.83 foot difference, this results in: CM = (0.01605/0.01600

• 18.83 ft
• 0.4335 psi/ 1 ft) - (18.83 ft
• 0.4335 psi/ 1 ft)

CM = 8.188 psig - 8.163 psig CM = 0.025 psig As the Data Packages use 8.5 psig as the calibration correction for reference leg head, this would, bound the 8.188 psig for the worst case reference leg pressure. The second effect is the impact on the switches being located in Rooms 500 and 501 with the indication used to determine switch status change being located in the SFRCS cabinet in the Control Room Cabinet area. There is a delay between the switch setpoint being reached, indication provided in the SFRCS cabinet, the technician at the SFRCS cabinet responding to the status change and informing the technical at the switch, and the technician at the switch reading the pressure. With this delay, a value more conservative than the actual trip setpoint will be documented. For example, the technician at the switch will slowly depressurize the input to the switch from a value above the trip setpoint. If the switch actuates at 630 psig, the technician may document a setpoint of 629 based on the delay between the switch actuation and the reading of the M&TE value since the pressure continues to be reduced. With the actual value being higher and more conservative than the documented value, no additional uncertainty needs to be included in the calculation. Based on both reference leg density effects being bounded and the delay in response being conservative, the Calibration Method will not be included in the final calculated value. 4.4 Subsection 2. Instrument Uncertainties Durina Normal Operation.

Page 7 FirstEnery CALCULATION COMPUTATION NOP-CC-3002-01 Rev. 03 CALCULATION NO.: REVISION: C-ICE-083.03-003 8 4.4.1 Switch Accuracy (SA) Since the device is a pressure switch, repeatability is the only component given for Reference Accuracy. Reference Accuracy is normally comprised of conformity, hysteresis, dead band, and repeatability per ANSI/ISA S51.1-1979 (DIN 34, page 12, Note 3). Only repeatability is applicable to the switches. Per Static-O-Ring's Certificate of Compliance and the associated Purchase Order (DIN 35), the pressure switches are repeatable to within + 1.0% of top range (1% of 1000 psig). SA = + 10.0 psig 4.4.2 Power Supply Voltage Effects The pressure switches are not affected by voltage variations. As the only interface with power is across the switch contacts, a nominal change in power supply output will not have any affect on the instrument setpoint. 4.4.3 Power Supply Frequency Effects The pressure switches are not affected by frequency variations. As the only interface with power is across the switch contacts, a nominal change in power supply output will not have any affect on the instrument setpoint. 4.4.4 Switch Temperature Effects (Normal) (STEN) For the normal effect of temperature on the calibrated setpoint, Static-O-Ring developed equations for installations with and without a plugged vent as provided in DBE-07-00034 (DIN 37). Per DB-MI-03201 (DIN 12, Section 8.2) and DB-MI-03202 (DIN 13, Section 8.2), the vent plug is installed following switch calibration and reinstallation of the switch cover. The maximum normal operating temperature per DB1-100 (DIN 9, Page TAB-3) for Rooms 500 and 501 is 1040 F. The setpoint is 630 psig and the instruments are calibrated at a possible low temperature of 60°F (DIN 33, Section 1.2.1). Therefore, for a plugged vent pressure switch the following equation applies from DBE-07-00034 (DIN 37). STEN = [0.027 (psi/°F) - (SP x 0.0003 / OF)] x (Tf-Ti)

                           = [0.027 (psi/°F) - (630.0 x 0.0003 / OF] (104-60 0 F)
                           = -7.128 p'sig Where          SP = Setpoint Tf = Temperature.- Final Ti = Temperature - Initial (calibration)

As using a negative value in the formula would result in the trip setpoint being moved in the incorrect direction, it will be changed to a positive bias. STEN = 7.128 psig Since the temperature effects will be present during calibrations, per ISA-67.04.02 (DIN 27), Annex I, Section 4.3.1(b)4 - Temperature Changes, the temperature effect may be included between the Allowable Value and the Limiting Trip Setpoint. Based on this, the uncertainty will be included between the Allowable Value and Limiting Trip Setpoint.

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.FirstEnergy                             CALCULATION COMPUTATION NOP-CC-3002-01 Rev. 03 CALCULATION NO.:                                                                                REVISION:

C-ICE-083.03-003 .8 4.4.5 Switch Humidity Effects The Static-O-Ring pressure switches are totally enclosed and not vented to atmosphere, therefore, any change in humidity within rooms 500 and 501 will not affect the switch setpoint. 4.4.6 Switch Pressure Effects

      .The pressure switch setpoint is calibrated relative to the ambient pressure. Since the vent on the pressure switches is plugged, the atmospheric pressure during calibration will be captured as the reference pressure. A sampling of plant computer point P991 for turbine building atmospheric pressure for the years of 2004 - 2007 revealed a high of 30.03 inches of mercury and a low of 28.45 inches of mercury, or a difference of 1.58 inches of mercury. Converting this value to psi using a conversion factor of 0.4912 psi/

inch of mercury results in approximately 0.78 psi. A conservative value of 1.0 psi will be used as a random variable. SPE =+ 1.0 psi 4.4.7 Switch Vibration Effects The pressure switches are wall mounted and will therefore have minimal or no effects from vibration. 4.4.8 Switch Radiation Effects, Normal (SREN) The environmental qualification report tested the pressure switches by applying a generic-level Total Integrated Dose (TID) of 2.2 x 108 rads/gamma radiation which is equivalent to the maximum estimated dosage in service plus DBE event. The effect on setpoint due to radiation testing by Acton and documented in report 17344-82N-C (DIN 5 and specifically DIN 8, page 7-5), resulted with an increase in setpoint of 0.40 psig on the 0.5 to 6.0 psig range test switch. This would be equivalent to approximately 60 psig on the 200- 1000 psig range switch used in the SFRCS application. In the electrical equipment qualification manual DBI-100 (DIN 9), a normal radiation dose for 40 years is equal to 16 rads and 1.1 rads for Rooms 500 and 501, respectively. For peak DBE conditions due to a LOCA over a one hour period, the radiation dose for Rooms 500 and 501 is 9.2 rads. The pressure switches do not provide a safety function during a LOCA. However, the switches must not change to the extent where SFRCS could be initiated. This is not an issue since the setpoint increased during testing, which is in the conservative direction, and even at the worst case of 60 psig, the difference between normal pressure and the trip setpoint will not be impacted by this change in setpoint during a LOCA. Comparison of the normal and DBE radiation levels to the test radiation dose and its effect on setpoint reveals the former levels to be too low (almost 7 orders of magnitude lower) to affect the switch setpoint. Therefore, the effect on setpoint is negligible. 4.4.9 Analog to Digital Conversion Effects As these are simple pressure switches, there is no analog to digital conversion of the output. Therefore, there is no Switch Analog to Digital Conversion effect. 4.4.10 Digital to Analog Conversion Effects

Page 9 FirstEnertj CALCULATION COMPUTATION . NOP-CC-3002-01 Rev. 03 CALCULATION NO.: REVISION: C-ICE-083.03-003 8 As these are simple pressure switches, there is no digital to analog conversion of the output. Therefore, there is no Switch Digital to Analog Conversion effect. 4.5 Subsection 3, Instrument Drift. 4.5.1 Drift (DR) A drift evaluation performed in Appendix A calculated the drift that would be expected over an eighteen-month surveillance interval plus an additional 25% as allowed by Technical Specification (DIN 2) Section 4.0.2. This surveillance interval is to be consistent with the Technical Specification Bases being revised by LAR 06-0003 (DIN 42). The final value determined was + 22.690 with a bias of 4.4357 psig. Therefore: DR(Random) = + 22.690 psig DR(Bias) = + 4.4357 psig As these are drift values for 18 months, a one month drift would be equal to or less than the 18 month drift. The above values are therefore also applicable for the currently required one month drift for compliance with the Technical Specifications and the surveillance testing. 4.6 Subsection 4, Instrument Uncertainties Caused by Design Basis Events. 4.6.1 Switch Temperature Effects, Abnormal (STEA) Even though the pressure switches are not required to provide a safety function to SFRCS during a HELB of the 6" main steam line in Rooms 500 and 501, the switches must not fail or appreciably depart from setpoint to allow an inadvertent actuation of SFRCS (Reference EQ Package DBI-034A (DIN 3)). Specifically, the switches must remain operable for a period of 10 minutes. Since this HELB impacts the operating temperatures of both rooms, the pressure switches for both steam generators could be affected. Per Acton test reports 17344-82N-C and 17344-82N-D (DINs 5 and 6), the pressure switches did not fail open during the tested temperature transient. For the effect of temperature on the calibrated setpoint, Static-O-Ring developed equations for installations with and without a plugged vent per DBE-07-00034 (DIN 37). Per DB-MI-03201 (DIN 12, Section 8.2) and DB-MI-03202 (DIN 13, Section 8.2), the vent plug is installed following switch calibration and reinstallation of the switch cover. The instruments are calibrated at a possible low temperature of 60°F per System Description 028C (DIN 33, Section 1:2.1). Therefore, for a plugged vent pressure switch the following equation applies from DBE-07-00034 (DIN 37). STEA = [0.027 (psi/OF) - (SP x 0.0003 / OF)] x (Tf-Ti) The peak DBE temperature after 10 minutes following a HELB for Rooms 500 and 501 are 367 0 F and 374°F, respectively per DBI-100 (DIN 9, Page TAB-3). Using a setpoint of 630 psig and the worst case DBE temperature of 374°F, the temperature reduction effect on setpoint is: STEA = [0.027 (psi/°F) - (630 x 0.0003 / OF)] x (374-60)

                          = -50.868 This equates to an approximate setpoint of 579.132 (630.0-50.868) psig. Since a HELB of the 6" main steam line will not result in a significant decrease of steam pressure in the main steam headers per DB1-

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------                                   CALCULATION COMPUTATION NOP-CC-3002-01 Rev. 03 CALCULATION NO.:                                                                                  REVISION:

C-lCE-083.03-003 8 034A (DIN 3), the pressure switches will not cause an inadvertent SFRCS actuation during a HELB of the 6" main steam line. For the purposes of this calculation, the effect on setpoint is zero. 4.6.2 Switch Radiation Effects, Abnormal (SREA) The abnormal radiation effects are the same as those described above in the Switch Radiation Effects, Normal. There are no abnormal radiation effects. 4.6.3 Switch Seismic Effects (SSE) The seismic testing is to be based on Static-O-Ring Nuclear Qualification Test Report 9058-102 (DIN 44) based on a discussion with Static-O-Ring documented on DBE-08-00013 (DIN 43). There are three switches seismically tested that have a range that can be compared to the SFRCS switches. Two switches, serial numbers 92-6-7026 and 92-6-7027 have a range of 45 to 550 psig or a span of 505 psig. One switch, serial number 92-6-7041, has a range of 200 to 1750 psig or 1550 psig. Data for the three switches from Appendix B of the report provided the following pre-seismic and post seismic test results (all values are in psig unless stated otherwise): Serial Number 92-6-7026 92-6-7027 92-6-7041 Pre-seismic setpoint - Test 1 312.5 307 900 Test 2 312.7 307.1 902.8 Test 3 312.6 307.8 903.2 Post-Seismic Setpoint - Test 1 306.6 306 899.5' Test 2 307 304.5 900.6 Test 3 307.5 305 902 Taking the worst case for each from above results in: Serial Number 92-6-7026 92-6-7027 92-6-7041 Pre-seismic setpoint 312.7 307.8 903.2 Post-Seismic Setpoint 306.6 304.5 899.5 Difference 6.1 3.3 3.7 Switch Range 505 505 1550 Difference percentage 1.21% 0.65% 0.24% Base on the above, a worst case value of 1.21% will be used. Correlating that error to the ,SFRCS pressure switches with a range of 200 to 1000 psi, or a span of 800 psi, equals: SSE = 0.0121 x 800 psi SSE = + 9.68 psi 4.7 Subsection 5. Process-DeDendent Effects. There are no process dependent effects. Pressure oscillations are possible in the main steam system. Since this is a switch, it would have no affect other than the possibility of an inadvertent trip. However,

Page 11 FArstEnergy CALCU.LATION COMPUTATION NOP-CC-3002-01 Rev. 03 CALCULATION NO.: REVISION: C-lCE-083.03-003 8 there is approximately a 300 psi differential between the normal operating pressure and the trip setpoint, which is considered acceptable margin. Therefore, it is concluded that there is no affect on the setpoint. 4.8 Subsection 6, Calculation Effects. There are no calculation effects to account for in this calculation., This is a simple switch that changes the output based upon input pressure. There are no calculations done by the instruments that could have an affect on the outcome. 4.9 Subsection 7, Dynamic Effects. There are no dynamic effects for these pressure switches. If the setpoint is reached, the switch changes state. Any other time delay is included in the overall time response of the SFRCS analysis. Proper response times for the loops are demonstrated by successful time response surveillance testing. Response times are therefore not required to be included in the determination of the setpoint and allowable value for this calculation. 4.10 Subsection 8, Calibration and Installation Bias Accounting The only possible calibration and installation bias accounting for the switches would be head effect for the installation. The head difference is accounted for in the I&C Data Packages (DINs 15, 16, 17, 18, 19, 20, 21, and 22) for the switches and discussed in detail in Section 4.3.3. 4.11 Subsection 9, Other effects beyond the sections listed in the standard 4.11.1 Insulation Resistance (IR) The cable insulation resistance component is not applicable to switches. The change in insulation resistance will not have the same type of effect that could be seen with a transmitter current loop. A small leakage current will not change the signal to the SFRCS Input Buffer enough to actuate the switch similar to the contact of the switch opening. 4.11.2 Switch Aging Effects (SAE) Per the environmental qualification test report 17344-82N-D (DIN 6), the pressure switch was thermally aged. The offset in setpoint as a result of thermal aging indicated an average increase in setpoint of 0.01 psig. Three initial actuation points were taken for decreasing pressure. The actuation test results were 2.4, 2.4, and 2.37 psig. The post-accelerated aging actuation test results were 2.4, 2.4, and 2.4 psig. As can be seen, the resulting difference is an average of 0.01 psig or a worst case of 0.03 psig. Since there is very little evidence that there is an actual difference in setpoint post-accelerated aging (i.e., 5 of the 6 actuation points are identical), the difference is in the conservative direction, and any aging effect will be calibrated out during normal calibrations of the instruments over time, no Accelerated Aging effect will be included. 4.12 As-Left (Calibration) Tolerance (ALT) Per the TSTF Improved Technical Specification Traveler 493, (DIN 30, page 7) the As-Left tolerance must be calculated to include only uncertainties of reference accuracy, M&TE accuracy, and M&TE readability. Regulatory Issue Summary (RIS) 2006-17 (DIN 36), page 5, states:

Page 12 .FirstEnerc CALCULATION COMPUTATION NOP-CC-3002-01 Rev. 03 CALCULATION NO.: REVISION: C-lCE-083.03-003 8 Additionally, the TSTF did not sufficiently address the NRC staff concern with the practice of using NSPs for establishingthe test acceptance criteriaband for as-found instrument values. The NRC staff concern was that excessive changes in the TSP could go undetected and also that a high incidence of false detections could result from such a practice. Subsequently, the NRC staff investigated the acceptabilityof basing operability determinations for as-found instrument values on NSP values. The NRC staff review concluded that if specific conditions are met, then the NRC staff would find a NSP-based assessment of as-found values acceptable. Those conditions are: (1) the setting tolerance band is less than or equal to the square root of the sum of the squares of reference accuracy,measurement and test equipment, and readabilityuncertainties;(2) the setting tolerance is included in the total loop uncertainty,and (3) the pre-defined test acceptance criteriaband for the as-found value includes either, the setting tolerance or the uncertaintiesassociatedwith the setting tolerance band,but not both of these. The as-left tolerance, using the values of reference accuracy (SA), M&TE (includes both Calibration Equipment (CE) and Calibration Standard (CS)) accuracy, and M&TE readability (no readability component included), yields (SRSS=Square Root Sum of the Squares): As-Left Tolerance = SRSS (CS, CE, SA) As-Left Tolerance = SRSS (1.0, 1.0; 10.0) As-Left Tolerance = 10.10 psig, reduced to 10.0 psig ALT = + 10.0 psig

                                                                                                       'Page 13 FirstEner                                 'CALCULATION COMPUTATION NOP-CC-3002-01 Rev. 03 CALCULATION NO.:                                                                               REVISION:

C-ICE-083.03o0038 5 Results 5.1 ISA Method for Calculation of Allowable Value and Trip Setpoint The calculation must preserve the analytical (safety) limit. Based upon the ISA Standard and Recommended Practice, this is accomplished by combining terms and moving the setpoint away from the analytical limit. There are three methods described in the ISA Recommended Practice (DIN 27), Section 7.3. This calculation will use Method 2. Method 2 establishes the Allowable Value by combining the uncertainties that are not."tested" and moving the value conservatively away from the Analytical Limit. The remaining "tested" uncertainties are combined with the "non-tested" uncertainties and again moved conservatively away from the Analytical Limit to arrive at a Limiting Trip Setpoint. Margin is added to the Limiting Trip Setpoint to establish the Nominal Trip Setpoint. 5.2 Conversion of Analytical Limit from psia to psig The analytical limit is 600 psia per memo NEN-90-10190 (DIN 11), which must be converted to psig. An atmospheric pressure of 14.4 will be used for the conversion based on the facility being 585 feet above sea level and it being a more conservative value, i.e., the smaller conversion will result in a setpoint further. from the analytical limit. The conversion from psia to psig results in: Analytical Limit (AL) = 600 psia - 14.4 psi AL = 585.6 psig 5.3 Allowable Value The Allowable Value is calculated by adding the values which are not tested during the normal surveillance testing to the analytical limit value. The only parameter which is not zero and is not tested during the surveillance is: SSE = Switch Seismic Effects The resulting equation is: AV = AL(psig) + SSE AV = 585.6 psig + 9.68 psig AV = 595.28 psig The allowable value will be increased in the conservative direction to the value submitted in LAR 06-0003: AV = 600.2 psig 5.4 Limiting Trip Setpoint (LTSP) Two components, DR(BiaS) and STEN are biased in one direction. These components will be included independent from theother components. Based on using the square-root-sum-of-the-squares (SRSS) for the remainder of the components, the Limiting Trip Setpoint will be: LTSP = AL(psig) + SRSS [CS, CE, SA, SPE, DR(Random), SSE, ALT] + STEN + DR(Bias)

Page 14 FirstEne...g CALCULATION COMPUTATION NOP-CC-3002-01 Rev. 03 CALCULATION NO.: REVISION: 0-10E-083.03-003 8 Where CS Calibration Standard + 1.0 psig CE Calibration Equipment + 1.0 psig SA Switch Accuracy + 10.0 psig STEN = Switch Temperature Effect - Normal + 7.128 psig SPE Switch Pressure Effect + 1.0 psig DR(Random) = Drift(Random) + 22.690 psig DR(Bias) = Drift(8 8as) + 4.4357 psig SSE = Switch Seismic Effects + 9168 psig ALT = As-Left Tolerance + 10.0 psig LTSP =585.6 + SRSS [1.0, 1.0,10.0,22.690,1.0, 9.68,10.0] + 7.128 + 4.4357 psig LTSP = 585.6 + [28.49] + 7.128 + 4.4357 psig LTSP = 625.65 psig 5.5 Nominal Trip Setpoint Addition of margin to the LTSP results in a value defined as Nominal Trip Setpoint (NTSP). Addition of margin for ease of calibration and conservatism, the LTSP is moved away from the analytical limit to: NTSP = 630.0 psig 5.6 As-Found (AFT) The as-found tolerance for the setpoint is defined in TSTF-493, Rev 1 (DIN 30), page 7, as the square root sum of the squares value of referenceaccuracy, M&TE accuracy, M&TE readability, and projected drift. The combination of these values for the as-found tolerance yields: As-Found = SRSS (CS, CE, SA, DR(Random)) As-Found = SRSS (1-.0, 1.0, 10.0, 22.690) As-Found = + 24.84 psig from NTSP A value of + 20.0 psig will be used. 5.7 Agreement Criteria

Page 15 FirstEner gy CALCULATION COMPUTATION NOP-CC-3002-01 Rev. 03 CALCULATION NO.: REVISION: C-lCE-083.03-003 8 There are no calculated Agreement Criteria associated with the switches for compliance with the Technical Specification Channel Check requirement. As there is no indicated output'from the switches for comparison, an Agreement Criteria value cannot be established. 6 Conclusion Based on this calculation, the Trip Setpoint for the SFRCS low pressure switches will be set to 630 psig, decreasing (excluding head effects) and an Allowable Value of 600.2 psig, decreasing. This setpoint provides enough margin to ensure the pressure switch will trip at its setpoint under normal and/or DBE conditions and prior to the lower analytical limit of 600 psia (585.6 psig) (DIN 11). As a result of this calculation, the instrument index / SAP (DIN 1) will require revision to a setpoint of 630.0 psig and a Calibration Tolerance (As-Left Tolerance) of + 10.0 psig. The'drift analysis contained herein is consistent with the Channel Calibration frequency of 18 months. This value supports extension of the current monthly Channel Functional frequency to a period longer than the current one month. Although extension to 18 months is not recommended, a revision to 3 month Channel Functional testing would be supported by the drift analysis. The Setpoint of 630.0 + 10 psig would allow for the switch to be set and left at up to 640 psig. The block permissive is 720 + 10 psig (DIN 1) allowing it to be set and left at down to 710 psig. The difference between these two values is 70 psig, thus exceeding the minimum margin of 45 psig established in the Acceptance Criteria. Based on the calculation using the ISA Standard and Recommended Practice for development; establishment of the Allowable Value, Limiting Trip Setpoint, Nominal Trip Setpoint, As-Found and As-Left Tolerances; and meeting the Block Permissive margin; all Acceptance Criteria requirements have been met.

Page 1 F rstFrg CALCULATION COMPUTATION NOP-CC-3002-01 Rev. 03 CALCULATION NO.: REVISION: C-ICE-083.03-0046

1. ANALYSIS METHODOLOGY The purpose of this calculation is to determine the Allowable Value (AV), Limiting Trip Setpoint (LTSP), Nominal Trip Setpoint (NTSP), As-Found Tolerance (AFT), and As-Left Tolerance (ALT) for the Steam and Feedwater Rupture Control System (SFRCS) Main Feedwater/Steam Generator reverse differential pressure switches. The differential pressure switches are manufactured by ITT Barton, Model 288A with local indication per M-07201 / SAP (DIN 1). The switches have a calibration range of 0 to 400 PSID per M-07201 / SAP (DIN 1).

The calculation will use an eighteen month (550 days) surveillance interval for the channel functional test plus an additional 25% allowance, as permitted by Technical Specifications, to determine drift. The Technical Specifications have a one month required Channel Functional test frequency and an eighteen month Channel Calibration requirement. The drift forthe subject loops is determined by statistical analysis of plant surveillance as-found/as-left data (AFAL). 1.1. DESIGN REQUIREMENTS The SFRCS Main Feedwater/Steam Generator (MFW/SG) reverse differential pressure switches DB-PDS2685A, DB-PDS2685B, DB-PDS2685C, and DB-PDS2685D are located in room 326 and DB-PDS2686A, DB-PDS2686B, DB-PDS2686C, and DB-PDS2686D are located in room 303,,per drawing M-0568 (DIN 11) and M-07201 / SAP (DIN 1). The differential pressure switches monitor the feedwater differential pressure across check valves FW 147 (Feedwater line 1) and FW 156 (Feedwater line 2). Specifically, the switches'monitor the differential pressure produced by the difference of steam generator pressure and feedwater pressure. The Safety Function of these switches is to actuate SFRCS upon a loss of feedwater due to pumping / flow problems as well as a loss of feedwater due to a rupture of the 18" Feedwater lines upstream of FW147 and FW156. These equipment failures will typically be detected by switches on both feedwater lines. For a feedwater line break downstream of the check valves, the depressurization effects would be sensed by SFRCS Low Pressure Trip switches and the opposite train reverse differential pressure trip switches due to a common feedwater header upstream of the check valves and the continued flow across the check valve on the failed line (DINs 2, 9). Upon detection of a loss of feedwater via a high reverse differential pressure across FW147 and FW156, a trip signal is generated by the affected Logic Channel differential pressure switches. When two-out-of-two Logic Channels, specifically Logic Channels 1 and 3 (Actuation Channel 1) or Logic Channels 2 and 4 (Actuation Channel 2), receive trip signals, Actuation Channel 1 and/or 2 will trip. Trip of both Actuation Channels results in initiation of both trains of Auxiliary Feedwater, alignment of Auxiliary Feed pumps to their associated steam generator, isolation of the main feedwater, main steam and the steam generators, trip of the reactor via the Anticipatory Reactor Trip System (ARTS), and trip of the main turbine. The SFRCS MFW/SG differential pressure switches must function without failure in the worst case normal environmental conditions (standard pressure at 119'F and 104'F) of Rooms 326 and 303. 1.2. METHODOLOGY The guideline for performance of this setpoint calculation is Instrument Society of America's Standard ANSI/ISA 67.04.01-2000 and Recommended Practice ISA RP67.04.02-2000 (DINs 6 and 24). The standard defines minimum requirements and calculation methods for assuring that setpoints are established and held within specified limits in nuclear safety-related instruments. As described in ANSI/ISA 67.04.01-2000, depending on whether the instrument uncertainties are "tested" or not "tested" during surveillance testing determines which uncertainties that will be included in determining the Allowable Value and which will be included in determining the trip setpoint.' A graphical

Page 2 FirstEnergy CALCULATION COMPUTATION NOP-CC-3002-01 Rev. 03 CALCULATION NO.: REVISION: C-ICE-083.03-004 6 representation of the ISA standard requirements and the calculations to be performed herein is provided below. Applicable Error Definitions for ANSI/ISA 67.04.01-2000 Setpoint Determination Analytical Limit Allowable Value Included are those values identified by ANSI/ISA 67.04.01, Section 4.3.1 (All uncertainties) Included are those values identified by ANSI/ISA 67.04.01, Section 4.3.2 ("tested" uncertainties) Trip Setpoint In addition to the ISA Standard and Recommended Practice, the Limiting Trip Setpoint, Nominal Trip Setpoint, As7Found Tolerance and As-Left Tolerance will be developed consistent with Technical Specification Task Force Traveler 493 (DIN 29) and Regulatory Issue Summary 2006-17 (DIN 30). The methodology for instrument setpoints and uncertainties is described in Design Criteria Manual (DIN 31), Section III.C.13. Clarifications to the above documents when multiple options are allowed are included in the Design Criteria Manual methodology description. The methodology for determining the drift for the SFRCS differential pressure switches corresponding to an eighteen month surveillance interval is described in Appendix A. This method is in compliance with the Electric Power Research Institute (EPRI) document TR-103335-R1 (DIN 26). There are no response time errors/effects accounted for in this calculation. The SFRCS analysis established allowed time response of the instrumentation. The response time requirements from the analysis are in the Technical Requirements Manual (DIN 5) and verified by surveillance testing. The string uncertainties to be addressed are described in Section 4.1 of this calculation. As described in ISA Recommended Practice (DIN 24), Section 6.1, uncertainties that occur randomly and independently

Page 3 . irstEnergy CALCULATION COMPUTATION NOP-CC-3002-01 Rev. 03 CALCULATION NO.: REVISION: C-ICE-083.03-004 6 may be combined using the square root sum of the squares (SRSS) method. Non-random uncertainties will be combined by summation. As defined in memo NEN-90-10190 (DIN 8), the Analytical (Safety) Limit is _ 200 psid.

2. ASSUMPTIONS There are no Assumptions required for this calculation.

3. ACCEPTANCE CRITERIA There are no numerical acceptance criteria associated with the establishment of the Allowable Value, Limiting Trip Setpoint, Nominal Trip Setpoint, As-Found Tolerance, and As-Left Tolerance. The following are the Acceptance Criteria.

1. The calculation complies with the ISA Standard and Recommended Practice (DINs 6 and 24).

The trip setpoints will be derived in accordance with these documents and Acceptance Criteria #2.

2. Appropriate Limiting Trip Setpoint, Nominal Trip Setpoint, As-Found Tolerance and As-Left Tolerance are derived in compliance with the Technical Specification Task Force (TSTF) Traveler 493 (DIN 29) and the NRC Regulatory Issue Summary (RIS) 2006-17 (DIN 30).

3. There are no unacceptable operational burdens associated with the setpoints.

4. CALCULATION 4.1. KNOWN DATA ANSi/ISA 67.04.01-2000 (DIN 6) defines the uncertainties that should be addressed in the calculation. Although other uncertainties may be included, such as insulation resistance effect, the following list from the standard includes the uncertainties to be accounted for in this calculation. It should be noted that insulation resistance effect is not included since the sensing device is a simple switch. Small changes in insulation resistance and the resulting leakage current will not affect the trip signal to. the SFRCS cabinet input buffer.

Subsection A, Instrument calibration uncertainties Calibration standard

• Calibration equipment Calibration method Subsection B, Instrument uncertainties during normal operation
• Accuracy including linearity, hysteresis, dead band and repeatability Power supply voltage changes Power supply frequency changes Temperature changes Humidity changes Pressure changes Vibration Radiation effects Analog to digital conversion Digital to analog conversion

Page 4 FirstEnergy CALCULATION COMPUTATION NOP-CC-3002-01 Rev. 03 CALCULATION NO.: REVISION: C-ICE-083.03-004 6 Subsection C, Instrument drift Subsection D, Design basis event effects Temperature effects Radiation effects Seismic effects Subsection E, Process dependent effects Subsection F, Calculation effects Subsection G, Dynamic effects Subsection H, Calibration and installation bias accounting The uncertainties will be discussed below. Any uncertainty that is zero (0) will not be included in the formulas. Depending on whether the uncertainty is tested (per the ISA standard) will determine if the uncertainty is applied to the allowable value and the trip setpoint, or to the allowable value alone. 4.2. ERRORS. UNCERTAINTIES, AND TOLERANCES 4.2.1. SUBSECTION A, INSTRUMENT CALIBRATION UNCERTAINTIES 4.2.1.1. Calibration Standard (CS) The calibration standard will be set equal to the Calibration Equipment value. As the calibration. standard is typically at least a 4:1 ratio more accurate than the Calibration Equipment, this is conservative. CS = +/-1.00 psid 4.2.1.2. Calibration Equipment (CE) A pressure test gauge is used to check the setpoint of the differential pressure switches based on the Data Packages and Surveillance Procedures for each switch (DINs 14, 15, 16, 17, 18, 19, 20, 21, 22 and 23). The range and accuracy of the gauge are 0-500 psig and + 0.2% of span, respectively. A DMM may also be used if the switch requires calibration following setpoint verification, however, it is used to detect switch contact change, thus adds no additional uncertainty. CE = 0.2% x span of gauge

                                              =            0.002 x 500 psid"
                                              --           +/-1.00 psid 4.2.1.3. Calibration Method J

Page 5 FirstEnergy CALCULATION COMPUTATION NOP-CC-3002-01 Rev. 03 CALCULATION NO.: REVISION: C-ICE-083.03-004 6 There is no uncertainty that will be included due to the calibration method. Procedures DB-MI-03203 and DB-MI-03204 (DINs 22 and 23) require the use of Data Packages (DINs 14, 15,16, 17, 18, 19, 20, and

21) for calibration. The indication used for determining switch actuation is in the associated SFRCS cabinet in the Control Room Cabinet area; while the technician increasing the pressure to test the switch is located at the switch. There will be some conservative effect on setpoint due to the time delay between the trip, the corresponding indication in the Control Room Cabinet area, the notification of indication change to the technician doing the test, and the technician reading the M&TE. Since this time delay results in conservative values being documented, no uncertainty need be added. For example, with an Analytical Limit of 200 psid increasing, the technician starts at 100 psid and slowly increases pressure. If the actual trip value was 125 psid, but due to the delay, the pressure continues to increase to 127 psid before a reading is taken, the actual value would be conservative compared to the documented value. If the documented value was too high, it would require calibration away from the Analytical Limit before putting the equipment back in service.

There are no head effects attributed to calibration method since the switches measure pressure differential. 4.2;2. SUBSECTION B, INSTRUMENT UNCERTAINTIES DURING NORMAL OPERATION 4.2.2.1. Switch Accuracy (SA) Per ITT Barton Model 288A published data in vendor manual M-385-00019 (DIN 13), the differential pressure switches are accurate at point of switch actuation to within + 1.5% of the full scale differential pressure of 400 psid. In vendor manual M-385-00019, the published data also describes "Accuracy of Repeatability" as + 0.2% of full scale on Tab 1, page 1-2 of the Bulletin and + 0.25% of full scale on Tab 5, page 5 of the Bulletin. The more conservative repeatability value of + 0.25% of full scale will be used. The Instrument Society of America standard ANSI/ISA S51.1-1979 (DIN 28) states: "Accuracy rating includes the combined effects of conformity, hysteresis, dead band, and repeatability errors." As repeatability is part of accuracy, it could be excluded. For conservatism, it will be included as a dependent component of the stated accuracy and summed. SA = (0.015 + 0.0025) x (400)

                                             = + 7.00 psid 4.2.2.2. Power Supply Effects (PSE)

The differential pressure switches, since they are simple switches, are not affected by voltage or frequency variations. The switches provide dry contacts for detection by the SFRCS cabinet input buffers. The input buffers provide a wetting voltage for indication of switch contact state change. 4.2.2.3. Switch Temperature Effects, Normal (STEN) The worst case normal temperature where the'switches are located is 1 19*F per DB1-100, Section 3.1.1 (DIN 7) for the switches in Room 326 of the turbine building. The switches in Room 303 have a worst case normal temperature of 104'F per DB1-100, Page 303-1 (DIN 7). Per Qualification Summary Report (QSR) 027-A-01 (DIN 3), the switches were tested between 70°F and 212°F and found to have an affect on setpoint of approximately 5% of full scale (Page 7 of DIN 3). Since the report did not provide sufficient detail to determine if the temperature effect error was linear, the worst case 5% full scale offset will be used in the calculation even though the switches will not be exposed to the maximum 212°F temperature.

Page 6 FirstEnergy CALCULATION COMPUTATION NOP-CC-3002-01 Rev. 03 CALCULATION NO.: REVISION: C-ICE-083.03-004 6 For a differential pressure switch of a range of 0-400 psid, the offset in setpoint in terms of differential pressure at full scale is; STEN = (400 psid) x (5.0%)

                                            = 20.0 psid Since the temperature effects are significant and will be present during calibrations, per ISA-67.04.02, Annex I, Section 4.3.1(b)4 - Temperature Changes, the temperature effect may be included between the Allowable Value and the Limiting Trip Setpoint. Since the switches in Room 326 will be exposed to ambient temperature plus the heat from the turbine and feedwater systems, a potentially significant effect will be present during calibrations. Based on this, the uncertainty will be included between the Allowable Value and Limiting Trip Setpoint.

4.2.2.4. Switch Humidity Effects Per vendor manual M-385-00019 (DIN 13), page 1-1, the ITT Barton 288A differential pressure switch "is enclosed in a NEMA 4 watertight case, made of die-cast aluminum and finished with a weather resistant black epoxy resin paint. The glass cover is secured in the bezel with an elastomer ring, thus reducing the possibility of accidental glass breakage. This ring also acts as a seal between the bezel and case and ensures a moisture, fume, and dust-free atmosphere for the indicator and switch mechanism." Based on this, any change in humidity within rooms 303 and 326 will not affect the switch setpoint and no Switch Humidity Effect will be included. 4.2.2.5. Switch Pressure Effects (SPE) Because the switches are differential pressure switches, any change in atmospheric pressure will affect both sensing lines and cancel each other out. Therefore, any change in atmospheric pressure within rooms 303 and 326 will not affect the switch setpoint. In addition, any change in operating pressure will be seen by both sensing lines and again cancel each other out. Thus, there is no Switch Pressure Effect. 4.2.2.6. Switch Vibration Effects The differential pressure switches are wall mounted and will therefore have minimal-or no effects from vibration. 4.2.2.7. Switch Radiation Effects, Normal (SREN) Per DBl-100 (DIN 7), Table 1, Page TAB-2, the Normal TID for room 303 is 2.5 X 103 rads. DBl-100 (DIN 7), Section 3.2.5 establishes the environmental threshold for radiation total integrated dose. Since the pressure switches donot contain semiconductor material, per DB1-100, Section 3.2.5 any radiation level below 1 X 104 rads is considered to be low enough to have a negligible effect on switchesDB-PDS2686A through DB-PDS2686D. The Turbine Building, including Room 326 for switches DB-PDS2685A through DB-PDS2685D, per DBI-100 (DIN 7), Section 3.1.3, is considered a mild environment without radiation effects. Therefore, the switch radiation effects are considered negligible. 4.2.2.8. Switch Analog to Digital Conversion (SADC)

Page 7 _Fir-stEnergy CALCULATION COMPUTATION NOP-CC-3002-01 Rev. 03 CALCULATION NO.: REVISION: C-ICE-083.03-004 6 As these are simple differential pressure switches, there is no Analog to Digital conversion of the output. Therefore, there is no Switch Analog to Digital Conversion effect. 4.2.2.9. Switch Digital to Analog Conversion (SDAC) As these are simple differential pressure switches, there is no Digital to Analog conversion of the output. Therefore, there is no Switch Digital to Analog Conversion effect. 4.2.3. SUBSECTION C, DRIFT 4.2.3.1. Drift (DR) The Technical Specifications require Channel Functional testing every month and Channel Calibration testing every 18 months. This calculation determines the drift value for an 18 month period with an allowed variation of 25% (% extension allowed by Technical Specification (DIN 4), Section 4.0.2). This is consistent with Channel Calibration frequency. No drift value is given by Barton. Therefore, Attachment 1 determined the instrument drift for the 18 month plus 25% (687.5 days) period to be: DR(random) = +/- 14.66 psid DR(bias) = 1.29 psid For conservatism and to ensure future drift analysis does not invalidate the calculated values, the drift values will be increased. This results in: DR(random) = + 20.0 psid DR(bias) = + 1.50 psid 4.2.4. SUBSECTION D, DESIGN BASIS EVENT EFFECTS 4.2.4.1. Switch Temperature Effects, Abnormal (STEA) For High Energy Line Break (HELB) scenarios, as stated in Section 1.1, the line breaks will be detected by either switches on both feedwater lines or the line opposite of the break. Based on this, at a minimum, the opposite line switches will detect the break. Due to the location of the switches, both sets of switches would not be affected by the same break prior to the switches performing the intended safety function. Since the HELB is sensed by the opposite train switches and the resulting actuation results are identical, the effect of the temperature transient on the switches is considered to be negligible. Therefore, there is no abnormal temperature effect. 4.2.4.2. Switch Radiation Effects, Abnormal (SREA) The abnormal radiation effects are the same as those described above in the Switch Radiation Effects, Normal. The differential pressure switches are to mitigate a feedwater line break or loss of feedwater. As described in USAR (DIN 10) Section 15.2.8, loss of feedwater events do not result in core damage, thus there are no abnormal radiation effects. 4.2.4.3. Switch Seismic Effects (SSE)

                                                                                                         .Page 8 FArsterý                                   CALCULATION COMPUTATION NOP-CC-3002-01 Rev. 03 CALCULATION NO.:                                                                                   REVISION:

C-ICE-083.03-004 6 Per ITT Barton Test Report R3-288-13 (DIN 12), two Barton Model 288A differential pressure switches were seismically tested. The following table displays the information for a 0 to 60 psid switch that is most similar to the installed SFRCS Differential Pressure Switches. Switch data for the 288A switch with a range of 0 to 30 inches water column was not used. Since the range of the SFRCS switches is 0 to 400 psid, the difference in detection range from 30 inches water column was considered to large for comparative results. The switches had dual setpoints and were calibrated and tested for decreasing and increasing values. Serial # Test # Pre-test Post-test Worse Pre-test Post-test Worse setpoint - setpoint - Case setpoint - setpoint - Case Decreasing Decreasing Delta Increasing Increasing Delta (psid) (psid) (psid) (psid) (psid) sid 36816 1 Low 14.24 10.88 -3.47 16.76 13.53 -3.23 36816 2 Low 14.22 10.75 16.71 13.55 36816 3 Low 14.22 10.80 16.67 13.55 36816 1 High 44.26 43.73 -0.55 46.5 46.03 -0.47 36816 2 High, 44.27 43.72 46.43 46.15 36816 3 High 44.27 43.72 46.45 46.10 The errors converted to percent of full scale (0 to 60 psid) are:

                  -3.47 psi       = -5.8%
                  -0.55 psi       =  -0.9%
                  -3.23 psi       =  -5.4%
                  -0.47 psi       = -0.8%

As can be seen from the table, the errors are all in the negative direction, which is conserVative with respect to the SFRCS reverse differential pressure setpoint. For this reason, the seismic value could be considered to be zero. However, for conservatism, the worse case of 5.8% will be used. SSE = 400 psid x (5.8%) SSE = 23.2 psid 4.3. SUBSECTION E, PROCESS-DEPENDENT EFFECTS There are no process dependent effects. Since the switches are reading reverse differential pressure with a normal positive pressure detected during forward flow of feedwater, the only potential process dependent effect would be pressure oscillations. Pressure oscillations that would actuate the switch would require closure of the check valve and a feedwater perturbation. If the check valve closure occurred, the switch setpoint will either be satisfied or not satisfied with a resulting change of state of the contact output. The pressure oscillations would not affect the actual setpoint value. Based on this, there is no process dependent effect. 4.4. SUBSECTION F, CALCULATION EFFECTS There are no calculation effects to account for in this calculation. This is a simple switch that changes the output based upon input pressure. There are no calculations done by the instruments that could have an affect on the outcome. 4.5. SUBSECTION G, DYNAMIC EFFECTS

Page 9 FirstEner CALCULATION -COMPUTATION . NOP-CC-3002-01 Rev. 03 CALCULATION NO.: REVISION: C-ICE-083.03-O04 6 The only dynamic effect for these differential pressure switches is the 0.5 second time delay included in the SFRCS logic for the associated switches. The switches will actuate immediately upon reaching the setpoint and start the 0.5 second logic delay. The delayis included in the analysis scenario for oVerall time response of the SFRCS. Proper response times for the loops are demonstrated by successful time response surveillance testing. Based on this, response times are not required to be included in the determination of the setpoint and allowable value for this calculation. 4.6. SUBSECTION H,CALIBRATION AND INSTALLATION BIAS ACCOUNTING The only possible calibration and installation bias accounting for the switches would be head effect for the installation., There is no head effect sinceit is a differential; pressure switch and; with the tap points atthe same elevation, the errors will be nullified. In addition, if there is any head difference, it is accounted for in the I&C Data Packages for the switches. 4.7. AS-LEFT TOLERANCE Per the Technical Specification Task Force (TSTF) Improved Technical Specification Traveler 493, (DIN 29, page 8) the As-Left tolerance must be calculated to include only uncertainties of reference Accuracy, M&TE accuracy, and M&TE readability. Regulatory Issue Summary (RIS) 2006-17 (DIN 30), page 5, states: Additionally, the TSTF did not sufficiently address the NRC staff concern with the practice of using NSPs for establishing the test acceptance criteriaband for as-found instrument values. The NRC staff concern was that excessive changes in the TSP could go undetected and also that .a high incidence of false . detections could result from such a practice. Subsequently, the NRC staff investigated the acceptabilityof basing operability determinationsfor as-found instrument values on NSP values. The NRC staff review concluded that if specific conditions are met, then the NRC staff would find a NSP-based assessment of as-found values acceptable. Those conditions'are: (1) the setting tolerance band is less thdn or*equal to the square root of the sum of the squares of reference accuracy, measurement and test equipment,. and readabilityuncertainties;(2) the setting tolerance is included in the total loop uncertainty,and (3) the pre-defined test acceptance criteriaband for the as-found value includes either,the setting tolerance or the uncertaintiesassociated with the setting tolerance band, but notboth of these. The as-left tolerance, using the values of reference accuracy (SA), M&TE (includes both Calibration Equipment (CE) and Calibration Standard (CS)), and M&TE readability (no readability component included), yields: As-Left Tolerance = SRSS (CS, CE, SA) As-Left Tolerance SRSS (1.00, 1.00, 7.00) psid As-Left Tolerance = + 7.14 psid 4.8. AS-FOUND TOLERANCE Per the TSTF Improved Technical Specification Traveler 493, (DIN 29, page 7) the As-Found tolerance must be calculated to include only uncertainties of reference accuracy, M&TE accuracy, M&TE readability, and drift. Regulatory Issue Summary (RIS) 2006-17 (DIN 30), page 5, states: Additionally, the TSTF did not sufficiently address the NRC staff concern with the practice of using NSPs for establishing the test acceptance criteriaband for as-found instrument values. The NRC staff concern

Page 10 -irmstlEnewg CALCULATION COMPUTATION NOP-CC-3002-01 Rev. 03 CALCULATION NO-: . "REVISION: CACE-083.03-004 6* was that excessive changes'in;the TSP could go.undetected and also that a high incidence of false detections could result from such a practice. Subsequently, the NRC staff investigated the.acceptabilityof basing operabilitydeterminationsfor as-found instrument values on NSP values. The NRC staff review concluded that if specific conditions are met, then the NRC.staff would find a NSP-based assessment of as-found values acceptable., Those conditions are: (1). the setting tolerance band is less than or equal to the square root of the sum of the squares of reference accuracy,measurementand test-equipment,.and readabilityuncertainties;(2) the setting tolerance is included in the total loop uncertainty,and (3) the pre-defined test acceptance criteriaband for-the as-found value includes either, the setting.toleranceeorthe uncertaintiesassociated with the setting tolerance band, but not both of these. The As-Found tolerance, using the values of reference accuracy. (SA), M&TE (includes both Calibration Equipment (CE) and Calibration.Standard (CS)) accuracy, M&TE readability (no readability component included), and drift (DRR and DRB) yields: As-Found Tolerance = SRSS (CS, CE, SA, DRR) + DRB. As-Found Tolerance . = SRSS.(1.00, 1.00, 7.00, 20.0).+ 1,.50 psid As-Found Tolerance ' + 22.74 psid An As-Found tolerance of + 20.0 psid will be used. AFT ,.+ 20.0,psid 4.9. AGREMENT CRITERIA

       'There are no calculated Agreement Criteria associated with the switches for compliance with the.

Technical Specification Channel Check requirement. As there is.no indicated output from th'e switches for comparison, an Agreement Criteria value cannot be established.

5. RESULTS 5.1. SAFETY LIMIT DESIGNATION The calculation must preserve the analytical (safety) limit. Based upon the ISA Standard and Recommended Practice, this is accomplished by combining terms, and moving the setpojnt, away from the analytical limit. There are three methods described in the ISA Recommended Practice. This-calculation will use Method 1. Method 1 establishes the Allowable Value by combining the uncertainties that are not "tested" with the Analytical Limit. The remaining "tested" uncertainties are combined with the Allowable Value to arrive at a Limiting Trip Setpoint. Margin is added to theLimiting Trip Setpoint to establish the Nominal Trip Setpoint.

5.2. NON-ZERO UNCERTAINTIES As described earlier in this calculation, only the non-zero uncertainties will be. included in thefinal calculations. This provides a clearer more concise calculation. Those values described above that are non-zero -are: Calibration Standard CS = +/-1.00 psid Calibration Error CE = +/-1.00psid Switch Accuracy SA = +/-7.00 psid Switch Temperature Effects (Normal) STEN = 20.0 psid Drift (random) DRR = +/-20.0 psid

Page 11 FirstEner CALCULATION COMPUTATION NOP-CC-3002-01 Rev. 03 CALCULATION NO.: REVISION C-ICE-083.03-004 6. Drift (bias) DRB = 1.50 psid Switch Seismic Effects SSE = 23.2 psid As-Left Tolerance ALT = +/-7.14 psid 5.3. DETERMINATION OF TESTED UNCERTAINTIES The ISA Standard and Recommended Practice define how the allowable value and the trip setpoints are to be determined. If uncertainties are "tested", those uncertainties may be excluded in the determination of the allowable value. The only uncertainty which will is not "tested" and will be used in determining the High Differential: Pressure Allowable Value is Switch Seismic Effect (SSE). 5.4. ALLOWABLE VALUE DETERMINATION The Allowable Value is calculated by subtracting the values which are not tested during the normal surveillance testing from the Analytical (Safety) Limit (AL). The only parameter which is not tested during the surveillance is: Switch Seismic Effects SSE = 23.2 psid Thus, Allowable Value (AV) equals: AV = AL - SSE AV = 200.0 - 23.2 psid AV = 176.8 psid 5.5. TRIP SETPOINT DETERMINATION 5.5.1. LIMITING TRIP SETPOINT (LTSP) The following equations will be used to calculate the setpoint of the Limiting Trip Setpoint for the differential pressure switches. The Allowable Value (AV) from above is 176.8 psid. The bias portion of the drift (DRB) and normal temperature effects (STEN) are considered biases. The other terms are random. Thus, a combination of SRSS and subtraction is used. Calibration Standard CS = +/- 1.00 psid Calibration Error ........................... CE = +/- 1.00 psid Switch Accuracy ............................ SA =+7.00 psid Switch Temperature Effects (Normal) STEN = 20.0 psid Drift (random) ......................... DRR +/- 20.0 psid Drift (bias) .............. DRB = 1.50 psid As-Left Tolerance ..................... ALT = +/- 7.14 psid LTSP = AV- SRSS [CS, CE, SA, DRR, ALT] - STEN - DRB

Page 12 FirstEnerg 'CALCULATION COMPUTATION NOP-CC-3002-01 Rev. 03 CALCULATION NO.: REVISION:. C-lCE-083.03-004 6 LTSP = 176.8- SRSS [1.00, 1.00, 7.00, 20.0, 7.14]- 20.0 - 1.50 psid LTSP = 176.8 - [22.40] - 20.0 - 1.50 psid LTSP = 132.90 psid 5.5.2. NOMINAL TRIP SETPOINT (NTSP) To establish the Nominal Trip Setpoint, additional margin is combined with the Limiting Trip Setpoint such that the value is conservatively moved away from the 200 psid analytical (safety) limit. The Nominal Trip Setpoint is: NTSP = LTSP - margin NTSP = 132.90- 7.90 psid NTSP = 125.00 psid

Page 13 CALCULATION COMPUTATION NOP-CC-3002-01 Rev. 03 CALCULATION NO.: REVISION: C-ICE-083.03-004 6 FIGURE 1: HIGH dPSETPOINT ERROR ANALYSIS Analytical

                                                             ----- (Safety) Limit
                                                                   </= 200. psid Switch Seismic Effect, Tech. Spec.

_______ Allowable Value for Channel Functional.

                                                                   <1= 176.8 psid Calibration Standard Calibration Equipment Switch Accuracy
                -Temperature Effect Drift for 18 Months As-Left Tolerance Margin Nominal Trip
                                                           <-       Setpoint 125.0 psid

                                                                * '                                        Page 14 FqrstEneW                               -CALCULATION COMPUTATION                                                .       .

NOP-CC-3002-01 Rev. 03 CALCULATION NO.:. REVISION. Cl-ICE-083.03-004 6

6. CONCLUSION 6.1. FINAL

SUMMARY

The values developed in this setpoint derivation satisfy the Acceptance Criteria set forth in Section 3 of this calculation. The calculation is developed in compliance with the ISA Standard and Recommended Practice with the Limiting Trip Setpoint, Nominal Trip Setpoint, As-Left Tolerance and As-Found Tolerance being developed in accordance with the TSTF Traveler 493 and the Regulatory Issue Summary. This satisfies Acceptance Criteria 1 and 2. The Nominal Trip Setpoint (field setpoint) of 125.00 psidis not changed, the setpoint is reverse pressure compared to the normal positive pressure across the check valve, and the logic includes a 0.5 second time delay prior to actuation. These three items ensure the setpoint is not an Operator burden, thus, Acceptance Criterion 3 has been satisfied. A summary of the results is given in the Summary Table below. Drift study information and the amount of conservatism in the calculation indicate that the likelihood of not tripping prior to the analytical (safety) limit value being reached is low. The drift analysis. contained herein was determined based on a 18 month drift. If a Channel Functional surveillance extension is pursued, this calculated value would bound an extension frequency of quarterly (3 months) or semi annually (6 months) including the Technical Specification allowance of 25%. The Tech Spec Allowable Value for the high differential pressure condition is to be revised. The change to the Allowable Value has been demonstrated not to impair. the capability of the safety systems to perform their intended function. The selection of the recommended Nominal Trip Setpoint was performed through an examination of all effects that could influence the performance of the instrument strings. Summary Table Description Tech Spec Tech Spec Remarks Existing Revised Value Value Tech Spec Allowable Value < 197.6 psid < 176.8 psid Tech Spec change recommended.' Tech Spec Trip Setpoint _<197.6 psid # # The Trip Setpoint is being removed from the Tech Specs. The calculated Nominal Trip Setpoint is 125.0 psid.

Page 1 CALCULATION NOP-CC-3002-01 Rev. 03 CALCULATION NO. [ ] VENDOR CALC

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C-ICE-083.03-001, Rev 17 VENDOR CALCULATION NO. N/A

1. ANALYSIS METHODOLOGY INTRODUCTION Instrument Configuration Figure 1 depicts the relationship between the lower tube sheet, downcomer orifice plate and the tap locations for the three types of level measurement. The transmitters of interest for this calculation are the SFRCS start-up range transmitters. These transmitters differ from the Operate Range transmitters in that they are not temperature compensated, and they have their lower taps on the downstream side of the downcomer orifice plate. The location of the upper taps for the Operate and Start up Range are identical.

Discussion of Steam Generator SFRCS Loop Sketch The instrument loop shown on Figure 2 is provided as a typical layout to highlight the components that will-be discussed in this calculation. Not shown, are the Signal Monitor calibration jacks and LED's that are utilized by field technicians during the calibration of the Signal Monitors. All other loops are similar with the exception that some loops do not have the remote indication similar to DB-LISP9B8A. Only instrument loops A6, A8I B6, and B8 have the remote indicator. (For full loop information, see drawings SF-0003A, Sheetsý 13 - 16 (DINs 79 - 82). The loop devices shown on Figure 2 perform the following functions: DB-LT-SP9A8: Steam generator level transmitter which produces a 4 to 20 mA signal proportional to steam generator level. DB-LSLL-SP9A8: Low level Signal'Monitor which produces a contact opening on steam generator 2 low level. When reached, the low level setpoint in conjunction with low level condition in DB-LSLLSP9A9 Will result in initiation of the auxiliary feedwater system, trip of the Anticipatory Reactor Trip I System (ARTS) and trip of the main turbine through SFRCS. The safety function of the low level trip setpoint is to ensure adequate secondary side heat sink is available. The accident analysis in Chapter 15 of the USAR discusses an SFRCS trip on steam generator low level upon loss of feedwater (Reference Attachment 3 for additional information). DB-LSHH-SP9A8: High level Signal Monitor which produces a contact opening on steam generator 2 high level. When reached, the high level setpoint in conjunction with high level condition in DB-LSHHSP9A9 will result in isolation of the main feedwater system, initiation of the auxiliary feedwater system, isolation of the steam generators, trip of the Anticipatory Reactor Trip System (ARTS) and trip of the main turbine through SFRCS. This will preventIcarry over of liquid into the main steam lines. DB-LI-SP9A8: Analog indicator mounted in the SFRCS cabinet to display "indicated" steamrgenerator level. DB-LI-SP9A8A: Analog indicator located on the center console in the control room to display-"indicated" steam generator level. DB-LY-SP9A8-1: Analogsignal converter which receives the 4-20 mA input from the field transmitter and outputs 0-10 VDC to the Signal Monitors. DB-LY-SP9A8-2: Analog current to current isolator which facilitates the external monitoring of the loop signal at the center console in.the control room. DB-JY-SP9A8: Regulated 36VDC power supply which provides power for the analog loop. I

Page 2 g Farstnej " ,CALCU LATION NOP-CC-3002-01 Rev. 03 CALCLATIN NO [ ]VENDOR CALC

SUMMARY

C-ICE-083.03-001, Rev 17 VENDOR CALCULATION NO. N/A STEAM GENERATOR 1-2 LEVEL INSTRUMENT TAPS Figure I Main Feedwater Header and Nozzles Notes:

1) Pressure measurements noted above are as follows:

1. Pressure sensed at upper tap utilized by the operate and startup range transmitters.

2. Pressure sensed by the lower tap of the operate range transmitter.

3. Pressure on the upstream side of the downcomer orifice plate.

4. Pressure sensed on the downstream side of the downcomer orifice plate.

5. Pressure sensed by the lower tap of the startup and wide range transmitters.

2) ICS Operate transmitters are DB-LTSP9A1 and 9A2.

3) SFRCS Startup range transmitters are DB-LTSP9A6, A7 (Chan. 1) & DB-LTSP9A8, A9 (Chan.2).

I

4) AFW Startup range transmitters are DB-LTSP9A4 (Chan. 1-AFPT1) & DB-LTSP9A3 (Chan.

2 - AFPT 2)

Page 3 F!-rst n3Y , CALCULATION NOP-CC-3002-01 Rev. 03 CALCULATION NO. [ ]VENDOR CALC

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VENDOR CALCULATION NO. N/A Steam Generator No. 2 Level Signals (SFRCS) Figure 2

• 0-388" Reference leg 0-300" measured DB-LTSP9A8 I

SFRCS CABINET C5792A

                                    ----------------------------------                                               I

_____ SIGNAL MONITOR DB-LYSP9A8 36vgc -VI I DB-JYSP9A8 Power Supply. SIGNAL COMPARATORS I T. r,,.

                                                                                               *            ~Highi.=             .

Level I Trip S High

• _ _ _] '

Comparator I Toi DB-LSHHSP9A8 SFRCS DB-LYSP9A8-1 . Logic Signal Converter I Channels I 2&4 Isolator' E/ Low . Comparator DB-LSLLSPgA8 II DB-LISP9A8A 0-300 inches

Page 4 CALCULATION NOP-CC-3002-01 Rev. 03 CALCULATION NO. I1VENDOR CALC

SUMMARY

C-ICE-083.03-001, Rev 17 VENDOR CALCULATION NO. N/A "Actual" Level vs "Indicated" Level Throughout this calculation, use of the words "actual" level, "indicated" level and "inches of H 20" take on specific meanings as clarified below. "Actual" level is the level in the steam generator as measured in the physical dimension of length. It is independent of the temperature and or pressure in the steam generator. "Actual" level is independent of any transmitter calibration technique. "Actual" level is typically referenced to the top of the lower tube sheet. During power operation above 25%, the term "Actual" level is inappropriate. It should be replaced with the term "Inventory." "Indicated" level is the output of the transmitter in response to a measurement of differential pressure (dP) between two elevations of the steam generator tube bundles. This "level" is a differential pressure reading and, an indirect measurement of inventory. The dP sensed by the transmitter is composed primarily of two components, a flow dP and a head dP. At low reactor power (<25%) the inventory in the steam generator is essentially a. collapsed level such that the dP reading will be a good indication of the steam generator inventory. As reactor power increases and, consequently, primary to secondary side heat transfer increases, this level becomes progressively voided within the steam generator. Also, as power increases, the feedwater dP flow component of the signal will become increasingly important, and will increase proportionally to the square of the flow. To summarize: at values below 25% reactor power, or during other periods of collapsed level, the dP sensed by the Startup (SU) range level transmitters is a good indication of actual level as the flow component is small in comparison to the head component and the water-steam transition zone is shorter and less voided. At values above 25% reactor power, the ability of the transmitters to provide operators information on actual inventory is limited by the effects of the flow dP component and the larger transition zone caused by increased'voiding. I In addition to the process influences on '"indicated" level identified above, the output of the transmitters is also affected by changes in steam generator inventory pressure and temperature from those assumed during calculation of the transmitters' calibrated range. If the basis for the transmitter calibration were to be the steam generator normal operating conditions, and if the operating conditions never varied, then the "indicated" level would be almost identical to the "actual" level during periods of collapsed level. As the transmitter is calibrated based on water at 68°F in the steam generator and 105'F in the reference leg, there is a large deviation between the "indicated" level and the "actual" level at power operations. The potential process measurement errors have been eliminated through selection of a field Signal Monitor setpoint in ."indicated" level that has been compensated to reflect the desired "actual" level. "Inches of H2O" is used in reference to the calibration of the transmitter and is based on inches of water at standard conditions. The units are not an expression of length, but are an expression of weight. Indirectly the steam generator level in inches can be determined if the density of the fluid is known and the differential pressure reading in inches of H2 0 is known. The instrument loop errors can be expressed in inches of H 20. The use of this term requires correction to enable it to be used, or combined, with other units such as "actual" level. No correction is required to enable it to be combined with "indicated" level. This is due to the calibrated range of the transmitter being based upon water at 68 0 F in the steam generator.

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C-ICE-083.03-001, Rev 17 VENDOR CALCULATION NO. N/A DESIGN REQUIREMENTS Calculation Methodology The guideline for performance of this setpoint calculation is ISA Standard 67.04.01-2000 and ISA Recommended Practice RP67.04.02-2000 (DINs (11 and 40). Inaddition, the methodologies described in Technical Specification Task Force (TSTF) Traveler 493 (DIN 67) and Regulatory Issue Summary 2006-17 (DIN 68) were used for identification of the Limiting Trip Setpoint, Nominal trip Setpoint, As-Found Tolerances, and As-Left Tolerances. Note that these are applicable only to the SFRCS Low Level trips function. The equipment will be assessed for operation of the transmitters and signal monitors based on a twenty'-four month fuel cycle and quarterly surveillance for the signal monitor. The current requirements for the signal monitor are monthly testing. This calculation will support both the monthly testing and an extended surveillance interval. Margin shall be included to provide additional assurance the signal monitor will trip prior to reaching the Analytical Limit. (Applicable to low level setpoirt only.) Signal Monitor setpoint shall contain sufficient room for normal'operational maneuvering. The operational maneuvering margin.is required to ensure that the plant will not trip unnecessarily during slight operational transients such as steam generator level control overshoot from feedwater runback at power operation Or rapid feedwater reduction (RFR) circuit, marginal performance of pumps and valves which could lead to arelatively slow decay of steam generator level, and spurious oscillations in feedwater flow at moderate power'levels due to improper tuning. The setpoint, with respect to operational maneuvering, is not designed to protect against the abrupt failure of the plant hardware, i.e. loss of NNI 'X' or 'Y' cabinet power, main feedwater valve or pump problem, etc. See Appendix F of Rev 3 of this calculation (Reel 4028, Frame 344) for a review of the Davis-Besse Transient Assessment (TAP) Reports from 1982 through 1987 associated with feedwater upsets. Known Inputs

1. The Analytical Limit for the Low Level trip is 10" as defined in EXT-87-00788 (DIN 9).

2. The analyzed setpoint for the HighLevel trip is 220" as defined in Calculation C-NSA-083.03-005 (DIN 62).

3. The thermal growth of the steam generator may be neglected for the low level trip. The reference line will' grow to some degree with the steam generator. As they grow, this lengthens the reference line indicating a lower level. For example, the transmitter is calibrated for a 388" reference leg. If the reference leg grows to 389", this will increase the amount of water head produced in the reference leg. This results in a larger differential between the actual level and the reference leg level. Since the difference is larger, a lower level will be indicated, which is conservative for the low level trip.

4. The steam generator pressure utilized by B&W in their analysis (EXT-87-00788 (DIN 9), pages 2 and 3) is 1065 psia (1050 psig) when operating near the low level setpoint. This value will be used for determination of "actual" versus "indicted" levels.

5. The calibration of the transmitters, in accordance with the Channel Calibration Surveillance procedures, is performed with the average containment temperature at or above 60'F. This requirement is included in the transmitter calibration procedures (DINs 29 and 30).

6. Minimal boil-off will take place in the reference legs. The B&W analysis used 1050 psig in the analysis (EXT-87-00788 (DIN 9), pages 2 and 3). Since this pressure is higher than the normal operating pressure (approximately 900 psig), this increased pressure would prevent the boil off of the reference leg.

7. Process errors associated with obtaining the inventory measurement during high power level conditions are approximately 2 inches (BAW-1655 (DIN 27), page 5-3).

Page 6 Rrst~nei .CALCUIATIrON NO'P-CC-3002-01 Rev. 03 CALCULATION NO. " . [ I VENDOR CALC

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C-IC-08.03001,Rev17[VENDOR CALCULATION NO. N/A

2. ASSUMPTIONS The following assumptions have been made during the performance of this setpoint calculation:

1. It is assumed that the average reference leg temperature will not be above 120*F. See Attachment 8 for the justification.

2. It is assumed that the process errors associated with obtaining the inventory measurements during low power level conditions are negligible. This is based upon a review of B&W report BAW-1655 (DIN 27, page 5-3),

dated January 1981, which states that the level measurement process errors at full power are approximately 2 inches. During periods of collapsed level, the flow dP components and the flowing frictional factors are no longer present. These error influences contribute the majority of the 2 inch process error and therefore their absence enables the above assumption to be made.

3. It is assumed that a collapsed steam generator level. condition occurs shortly after the loss of main feedwater and the subsequent turbine trip.: For those scenarios in which a loss offeedwater occurs without a turbine trip, credithas been taken for the SFRCS low pressure actuation. This- precludes the needs to evaluate how responsive the leveltransmitters are without a collapsed level and at a low steam generator inventory. (See Task 865 (DIN 35) for additional information).

3. ACCEPTANCE CRITERIA There are no numeric acceptance criteria associated with this calculation. The acceptance criteria are:

1. The calculation complies with the ISA Standard and Recommended Practice (DINs 11 and 40). The.Allowable Value will be derived in accordance with these documents. The trip setpoints will be derived in accordance with these documents and Acceptance Criteria #2.

2. Appropriate Limiting Trip Setpoint, Nominal Trip Setpoint, As-Found Tolerances, and As-Left Tolerances are derived in compliance with the Technical Specification Task Force (TSTF) Traveler 493 (DIN 67) and t1-i NRC Regulatory Issue Summary (RIS) 2006-17 (DIN 68).

3. There are no unacceptable operational burdens associated with the setpoints.

Page 7 CALCCALCULATION NOP-CC-3002-01 Rev. 03 [] VENDOR CALC

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C-ICE-083.03-001, Rev 17 VENDOR CALCULATION NO. N/A

4. COMPUTATION ISA 67.04.01 (DIN 8) defines the uncertainties that should be addressed in the calculation. Although other uncertainties may be included, the following list from the standard includes the uncertainties to be accounted for in this calculation.

Instrument calibration uncertainties Calibration standard Calibration equipment Calibration method Instrument uncertainties during normal operation Accuracy including linearity, hysteresis, dead band and repeatability Power supply voltage changes Power supply frequency changes Temperature changes Humidity changes Pressure changes Vibration Radiation effects Analog to digital conversion Digital to analog conversion Instrument drift Design basis event effects, Temperature effects Radiation effects Seismic effects Process dependent effects Calculation effects Dynamic effects Calibration and installation bias accounting In addition to the above, Insulation Resistance effects will be addressed. The uncertainties will be discussed below. Each uncertainty that is zero (0) will not be included in the formulas. Depending on whether the uncertainty is tested or untested (per the ISA standard) will determine how the uncertainty is applied with respect to the allowable value and the trip setpoint. 4.1. Instrument Calibration Uncertainties 4.1.1. Calibration Standard The calibration standard .is the equipment used to calibrate the M&TE. Typically, the calibration standard is at least 4 times more accurate than the M&TE. For conservatism, it will be set equal to the M&TE uncertainty value. CS Transmitter (CS-T) + 0.40" H 20 CS Signal Monitor (CS-SM) +0.20" H 20

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.C-ICE-083.03-001, Rev 17

                    ....        RvVENDOR                                               CALCULATION NO. N/A 4.1.2. Calibration (M&TE) Uncertainty The surveillance test procedures (DINs 29, 30, 31, and 32) in conjunction with the I&C Data Packages (DINs 43 -

58) specify the calibration equipment to be utilized. The M&TE identified in these documents shall be maintained consistent with or better than the accuracies for M&TE contained in this calculation. The error components are noted below:

a) Transmitter Calibration Pressure gauge, 0-500" H 2 0, +/-0.05% 250 ohm precision resistor, +/-0.01% Fluke 884OA/AF DMM, +/-0.006% of reading + 3 counts on a 20VDC scale The equipment uncertainties are random and independent from each other. Therefore, they will be combined using the square root sum of the squares (SRSS) method. Pressure gauge uncertainty = (500 in H 2 0 x 0.05%) = 0.25" H 20 For the resistor, the uncertainty is equivalent to 0.01% of the 0-300" H20 range. Therefore, Resistor Uncertainty (300" H2 0 x 0.01%) = 0.03" H 2 0 The refueling calibrations use a digital voltmeter Fluke 8840A/AF, with a calibration error of 0.006% of reading + 3 counts on the 5 1/2 digit scale (DIN 42). The resolution of the 5 1/2 digit scale is 0.0001 (use of 5 1/2 -digitscale is based on the data retrieved from field calibrations for the 24-month drift study (DIN 61) all being to 4 decimals). Since the maximum output voltage of the transmitter is 5.0 VDC (20mA x 250 ohm): Voltmeter Uncertainty = 0.00006 x 5.0 +0.0003 = 0.0003 + 0.0003 = 0.0006 mV The output range of the transmitter is 1 to 5 VDC, a difference of 4 volts which is equal to 0-300" H20: Voltmeter uncertainty = (0.0006 / 4) x 300 = 0.0450" H20 Transmitter M&TE uncertainty = SRSS (0.25, 0.03, 0.0450) 0.256" H20 b) Sigqnal Monitor Calibration Fluke 8840A/AF DMM, +/-0.006% of reading + 3 Counts on a 20VDC scale 250 ohm precision resistor, +/-0.01% The equipment uncertainties are random and independent from each other. Therefore, they will be combined using the SRSS method. For the resistor, the uncertainty is equivalent to 0.01% of the 0-300" H20 range. Therefore, Resistor Uncertainty = (300 in H2 0 x 0.01%) = 0.03" H 2 0. The Channel Functional and Calibration procedures (DINs 31 and 32) use a digital voltmeter Fluke 8840A/AF, with a calibration error of 0.006% of reading + 3 counts on the 5 1/2 digit scale (DIN 42) The resolution of the 5 1/2 digit scale is 0.0001 (use of 5 1/2 digit scale is based on the data retrieved from field calibrations for the drift study (Attachment 6) all being to 4 decimals). Since the maximum input voltage to the signal monitor is 5.0 VDC: Voltmeter Uncertainty = 0.00006 x 5.0 = 0.0003 + 0.0003 = 0.0006 VDC The input range to the signal monitor is 1 to 5 VDC, a difference of 4 volts which is equal to 0-300" H20: Voltmeter uncertainty = (0.0006 / 4) x 300 = 0.0450" H20 Signal Monitor M&TE uncertainty = SRSS (0.03, 0.0450) = 0.0541" H20

Page 9 FirstEnezyYCALCULATION NOP-CC-3002-01 Rev. 03 CALCULATION NO. *[1 ]VENDOR CALC

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C-ICE-083.03-001, Rev 17 VENDOR CALCULATION NO. N/A Performance of the transmitter calibration and the signal monitor calibration are independent of each other. The Refueling Calibration Surveillance Tests'(DINs 29 and 30)'calibrate the transmitter. The monthly tests will calibrate the signal monitor (DINs 31 and 32). Therefore, the calibration Uncertainty will be included for each test. For conservatism and to ensure that the uncertainty is not compromised if less accurate M&TE is used, M&TE Uncertainty for the transmitter and the signal monitor will each be +0.40" H 20 and +0.20" H2 0, respectively. V TE Transmitter. (MTE-T) = + 0.40" H 20 MTE Signal Monitor (MTE-SM) - 0.20" H 20 4.1.3. Calibration Method I There is no uncertainty due to the calibration method. The calibration of both the transmitter and signal monitor are done with digital multi-meters, thus there is no readability effect associated with the calibration. The reference leg head correction is compensated in the transmitter data packages (DINs 51 - 58) and density changes are addressed with process measurement effects. 4.2. Instrument uncertainties during normal operation 4.2.1. Accuracy including linearity, hysteresis, dead band and repeatability a) Transmitter effects: The transmitter base accuracy is . 0.25% of span (300" H20) or +/- 0.75" H20 (Reference Attachment 2). Transmitter Accuracy (TA). = +/- 0.75" H 20 b) Signal Monitor effects:

The signal monitoreffects will be divided into three parts, signal monitor resolution, signal monitor accuracy, and analog isolator effects.

1) Siqnal Monitor Resolution:

Based upon.data provided in EXT-91-01982 (DIN 15), the following values are established for the SAIC signal monitor resolution. The error contribution is the sum of the device settability and precision. The values are as follows:

a. Signal Converter Resolution Gain Setability +/-100 microvolts Zero Offset Contribution +/-267 microvolts (Fixed Value)

b. Comparator Resolution Comparator Settability +/-1000 microvolts C. Isolator Resolution Isolator Settability +/-2000 microvolts

Page 10

                                           ,           *~~~CALCULATION                                    .. .-

NOP-CC-3002-01 Rev. 03 CALCULTION O. [I VENDOR CALC

SUMMARY

C-ICE-083.03-001, Rev 17 VENDOR CALCULATION NO. N/A Based upon the calibration methods utilized in the surveillance test procedures at Davis-Besse, only the comparator settability is of interest at this time. This value is included in the base accuracy listed below and therefore will not be repeated in this section.

               .2)       Signal Monitor Accuracy:

The basic accuracy for a SAIC P/N 1138860101 Signal Monitor as stated in Vendor Manual G-CS-00436 (DIN 17), page 5-1, is expressed as follows: Signal Converter Accuracy @ 25°C (1) +/-0.025% Accuracy @ 40-140°F & Vibration (2) +/-0.08% Signal Comparator Accuracy @ 25°C (1) +/-0.01% Accuracy @ 40-140°F & Vibration (2). +/-0.07%. Transmitter Power Sun" v Output Voltage +36 VDC + 1.8,-3.2

1. Accuracy is expressed in percent of span at reference conditions, 25 0C _+50C.

2. Accuracy is expressed in % of span. Errors include environmental condition of 40'F to 140'F, shock and vibration. A significant contributor to the error is the maximum shift of adjusting potentiometers over the full MIL-SPEC. test condition.

The above values will be utilized in this calculation. However, if there is a need to reduce the setpoint at some time in the future, the accuracy may be-reduced. At Toledo Edison's request, SAIC provided revised accuracy and tolerance data that was based upon additional performance tests, and the knowledge of Toledo Edison's setpoints. This information is in EXT-91-01982 (DIN 15). Since the errors are independent of each other, they may be combined using the SRSS method. This results in:. Signal Monitor Accuracy (SMA) = SRSS (0.08%, 0.07%) x 300" H 2 0 SMA =+ 0.319" H2 0 4.2.2. Power Supply Voltage Changes a) Transmitter Effects: The power supply effect is +_0.016% of span (300' H20) or + 0.048" H20 (Reference Attachment 2). TPSE = + 0.048" H2 0 b) SAIC Signal Monitor Effects:

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C-ICE-083.03-001, Rev 17 VENDOR CALCULATION NO. N/A The SAIC Signal Monitor module is not influenced by the performance of the, regulated power supplies, or variations in input line conditions. These results are documented in M-324AQ-00357 (DIN 28), pages 144-147. 4.2.3. Power Supply Frequency Changes The transmitter and SAIC Signal Monitor both are DC devices. Any frequency changes would be filtered out by the power supplies or, be included in the power supply voltage change described above. 4.2.4. Temperature Changes a) Transmitter Location: The ambient temperature effects due to operation of the transmitters in the containment at 120'F for the low level trip is calculated in Attachment 2. Transmitter Temperature Effects (TTE) = + 3.15" H20 "b) Signal Monitor Location: Testing of the SAIC Signal Monitor has been conducted for ambient temperature effects. The results of the testing (DIN 28) indicated that the signal monitors maintained their published accuracy during the entire test. The test was conducted up to 140°F to simulate and envelop the expected worst case cabinet conditions. Preliminary temperature readings taken during the initial start-up tests of the SFRCS cabinets at DB-1 indicated that the temperature at the top of the cabinets was in excess of 11 50F. To redistribute heat within the cabinet, a circulating fan was installed at the top of each SFRCS logic cabinet to remove heat away from 'the SAIC signal monitors. Ambient temperature affects have been included for the SAIC signal monitor for conservatism in

              'the overall accuracy. For this reason, no additional ambient temperature effects have been incldude6d in this section. (Reference EXT-91-01982 (DIN 15)):

4.2.5. Humidity Changes a) Transmitter effects: Since the transmitter is a sealed unit, the normal changes of humidity will have no effect on the instruments. b) Signal Monitor effects: Since the signal monitor is located in the controlled environment of the control room, the humidity will have no effect on the instruments. 4.2.6. Pressure Changes a) Transmitter effects: Since the transmitter is a sealed unit, the normal changes of external pressure will have no effect on the instruments. The static pressure effect is the change in transmitter output when pressure is applied to both sides of the capacitance cell. The formula, as determined by Rosemount in M-327AQ-00036 (DIN

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C-ICE-083.03-00i, Rev 17 ~VENDOR CALCULATION NO. N/A 16, pages 1-11 and 1-12), for the transmitter is stated as 0.81% + 0.25%. The 0.81% value is calculated in Attachment 4 and calibrated out in the data packages (DINs 51- 58), however, the + 0.25% will be included as an uncertainty. It is defined as % of span. Pressure Effect (TPE) = + 0.25% of 300" H20= + 0.75" H20 b) Signal Monitor effects: Since the signal monitor is an electronic device, pressure changes will have no effect on the instruments. 4.2.7. Vibration a) Transmitter effects: The transmitter is mounted rigidly to the "D" ring wall. Based upon. this, the vibration is considered to be negligible. b) Signal Monitor effects: Vibration is addressed as part of accuracy (Refer to EXT-91-01982 (DIN 15), page 11) and therefore will not be included separately. 4.2.8. Radiation"Effects a) Transmitter effects:. The transmitter is not in .a high radiation area. during normal operation., Th'e Roseemount data specifies the radiation field as being 5 x 106 Rads, total integrated dose, over a 12.5 hour period. The transmitters are exposed to only 6.94 x 104 over 40 years during normal operation (Refer to EQ Package DB1-030B (DIN 21)), which is equivalent to 2.47 x 101 Rads, total. integrated dose over a 12.5 hour period. Sincejhe radiation exposure is more'than 6 orders of magnitude less than the Rosemount specified data during equivalent time periods, the effect will be considered to be negligible for normal operation. b) Signal Monitor effects: Since the signal monitor is located in the controlled environment of.the control room, radiation will have no effect on the instruments. 4.2.9. Analog to Digital Conversion No analog to digital conversions are done in either the transmitter or the signal monitor. Therefore, this component will be zero (0). 4.2.10. Digital to Analog Conversion No digital to analog conversions are done in either the transmitter or the signal monitor. Therefore, this component will be zero (0). 4.3. Instrument Drift a) Transmitter Drift: The Rosemount 1152 transmitter drift over a 30 month period has been determined to be 1.5" H20 (Reference Attachment 2).

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C-ICE-083.03-001, Rev 17 VENDOR CALCULATION NO. N/A Transmitter Drift (TD) = + 1.5" H20 b) Signal Monitor Drift: The drift for a three-month surveillance interval for the signal monitor has: been determined in Attachment 6 to be: 0.09 Inches of H2 0. The data determined the drift to be not normally distributed, thus it will be included as a bias in the final calculated value. Signal Monitor Drift (SMD) = 0.09" H20 4.4. Design Basis Events Effects. 4.4.1.' Temperature Effects The transmitters are installed in a harsh environment as defined by DBI-100 and DBI-030B'(DINs20 and 21). DBE effects need not be included in the calculation of the Allowable Value and setpoint based upon Attachment .3. 4.4.2. Radiation Effects The discussion above for DBE temperature effects also applies to radiation effects. 4.4.3. Seismic Effects As the SFRCS system could be called upon to perform its safety function during or after a design basis seismic event, the error contribution for this shall be included.

         'a)    For a Rosemount 1152 transmitter, the value is 0.25% of Upper Range Limit which equates to 0.25%of 750" H20 (for a range code 5 capsule).'

SSE Effects (SSE) = _ 1.875" H20 (Reference Attachment 2). b) For a SAIC signal monitor, the SSE influences have beendemonstrated.to be bounded by the quoted accuracy and performance data. Therefore, no influences are.included in this section due to seismic effects on the SAIC signal monitor. (Reference EXT-91-01982 (DIN 15)), 4.5. Process Dependent Effects . The process dependent effect for this instrument string is the change in density-of the reference leg.JrIf the density is reduced, the low level trip setpoint becomes less conservative, i.e. the indicated level increases. The worst case temperature in the containment during normal (non-LOCA or non-steam line break) for Rooms 215 (DB-LTSP9B6-B9) and.220 (DB-LTSP9A6-A9) is 118.8°F (DIN 19). Attachment 8 evaluates the temperature gradient on the reference leg and concludes the:average temperature in the reference leg is 120°F. Based on. these. inputs, an average reference leg temperature of 120°F will be used. The range is adjusted to account~for the difference between 68°F and 105°F in the transmitter data packages (DINs 50 - 57). The 68°F value is the reference temperature for the density of water used to calibrate the M&TE. The remaining density difference: between the 120'F and 105TF in the 388" reference leg will be calculated. The density correction in the data package is at 0 psig or 15 psia. The steam generator pressure used in the analysis during a low level actuation is 1050 psig (DIN 9, pages 2 and 3). As the .pressure decreases, the density decreases causing a larger difference.- Since the SFRCS Low Pressure trip analytical limit is 600_psia per memorandum NEN-90-10190 (DIN 69) and the low pressure trip will override a low level trip, a more conservative value of 600. psia will be used as the 120oF reference pressure. From the ASME Steam Tables (DIN 87): Density of H20 at 120°F @ 600 psia = 61.84292 (specific volume of 0.01617) Density of H20 at 105'F @ 15 psia = 61.93868 (specific volume of 0.016145)

                                   = 61.93868/61.84292
                                   = 1.00155

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SUMMARY

C-IC-08303-01, 17VENDOR Rv CALCULATION NO.' N/A Equivalent Ref.Leg = 1.00155 x 388"

                                   = 388.60" H 20 Error                               = 388.60" H20 -388" HO0
                                   = 0.60" H 20 PDE-L    = 0.60" H2 0 There is also a 2" process error associated with high power level conditions per BAW-1 655 (DIN 27, page 5-3).

Since the low level process dependent effect calculated above acts in the conservative direction for a high level trip, they will be conservatively excluded for the high level calculation. Therefore, the process dependent effects will be 0.60" and 2.0" H20 for the low and high level trips, respectively. The low level process dependent effects are one-sided and will be calculated as a bias. The high level process dependent effects are random and will bei calculated as such. PDE-H = 2.0" H 20 4.6. Calculation Effects There are no calculation effects to account for in this calculation. There are no calculations accomplished by any of the instruments in the string. 4.7. Dynamic Effects The only dynamic effect for this instrument string is the time delay associated with the transmitters and signal monitors. The transmitters have a time constant of approximately 1.6 seconds. This is to preclude any transient trips from occurring. Per FCR 85-0161 (DIN 6), there are no uncertainties to be accounted for in this calculation. The time delays are within the analysis and verified by the successful time response surveillance testing. 4.8. Calibration and Installation Bias Accounting The calibration and installation bias accounting of static span and zerd'shift are accounted for in the data packages; The uncertainty associated with the span shift is accounted for in the Pressure Changes (Section 4.2.6) described above. 4.9. Cable, EQ Connector and Electrical Penetration IR Effects Although not specified in the ISA Standard, IReffects are addressed in the Recommended Practice. Therefore, they will be addressed in this calculation. This influence can be important if the trip setpoint occurs after the ambient environment rises above 200°F;.- This is due to the decreased IR values observed in the cable, EQ connector and the electrical penetration modules. Decreased IR values indicatethat leakage current to ground or between conductors may be taking place. Vendor: test results have shown that the IR values generally remain above 2 Megohm as long as the ambient' temperatures remain below 2000 F. Toledo Edison calculation C-ECS-099-023 "EQ Acceptance Criteria-Insulation Resistance for Davis-Besse Nuclear Power Station" (DIN 83) reviewed theeffects of a 1 Megohm IR value on the performance of an analog safety related instrumentstring and concluded thatthe error contributions were small. As the subject instrument strings do not have to perform a safety function in environments above approximately 120 0 F, the effect noted in the EQ calculation would be significantly less than that calculated. For this reason the potential error contribution is acknowledged but will not be included. 4.10. As-Left Tolerance Per the Technical Specification Task Force (TSTF) improved Technical Specification Traveler 493, (DIN 67, page

7) the As-Left Tolerance must be calculated to include only uncertainties of reference accuracy, M&TE accuracy, and M&TE readability.

Page 15

-FirstEnen                                             CALCULATION NOP-CC-3002-01 Rev. 03 CALCULATION NO.         -                                                  [   ENDOR CALC 

SUMMARY

C-ICE-083.03-001, Rev 17 VENDOR CALCULATION NO. N/A Regulatory Issue Summary (RIS) 2006-17 (DIN 68), page 5, states: Additionally, the TSTF did not sufficiently address the NRC staff concern with the practiceof using NSPs for establishingthe test acceptancecriteriaband for as-found instrument values. The NRC staff concern-was that excessive changes in the TSP could go undetected and also that a high incidence of false detections could result from such a practice. Subsequently, the NRC staff investigated the acceptabilityof basingoperability determinationsfor as-found instrument values on NSP values. The NRC staff review concludedthat if specific conditions are met, then the NRC staff would find a NSP-based assessment of as-found values acceptable. Those conditions are: (1) the setting tolerance band is less than or equal to the square root of the sum of the squaresof reference accuracy,measurementand test equipment, and readabilityuncertainties;(2) the'setting tolerance is included in the total loop uncertainty,and (3) the pre-definedtest acceptance criteriaband for the as-found value includes either, the setting tolerance or the uncertaintiesassociatedwith the setting tolerance band, but not both of these. Transmitter As-Left Tolerance The As-Left Tolerance, using the values of reference accuracy (TA),'M&TE (includes both Calibration Equipment (MTE-T) and Calibration Standard (CS-T)) accuracy, and M&TE readability (no readability component included), yields: As-Left Tolerance = SRSS (CS-T, MTE-T, TA) As-Left Tolerance = SRSS (0.40, 0.40, 0.75)" H20 As-Left Tolerance = _ 0.94" H20 The current As-Left Tolerance in the surveillance test procedures (DINs 29 and 30) of + 0.75 inches will be used. ALT-T = + 0.75" H 2 0 Signal Monitor As-Left Tolerance The As-Left Tolerance, using the values of reference accuracy (SMA), M&TE (includes both Calibration' Equipment (MTE-SM) and Calibration Standard (CS-SM)) accuracy, and M&TE readability (no readability component included), yields: As-Left Tolerance = SRSS (CS-SM, MTE-SM, SMA) As-Left Tolerance = SRSS (0.20, 0.20, 0.319)" H20 As-Left Tolerance = + 0.43" H20 The current As-Left Tolerance in the surveillance test procedures (DINs 31and 32) of + 0.135 inches will be used. ALT-SM = + 0.135" H2 0 4.11. As-Found Tolerance Per the TSTF Improved Technical Specification Traveler 493, (DIN 67, page 7) the As-Found Tolerance must be calculated to include only uncertainties of reference accuracy, M&TE accuracy, M&TE readability, and drift. Regulatory Issue Summary (RIS) 2006-17 (DIN 68), page 5, states:

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VENDOR CALCULATION NO. N/A Additionally, the TSTF did not sufficiently addressthe NRC staff concern with the practiceof using NSPs for establishingthe test acceptancecriteria band for as-found.instrument values. The NRC staff concern was that excessive changes in the TSP could go undetected and also that a high incidence of false detections could result from such a practice. Subsequently, the NRC staff investigated the acceptabilityof basing operability determinationsfor as-found instrument values on NSP values. The NRC staff review concluded that if specific conditions are met, then the NRC staff would find a NSP-basedassessment of as-found values acceptable. Those conditions are: (1) the setting tolerance band is less than or equal to the square root of the sum of the squares of reference accuracy, measurement and test equipment, and readabilityuncertainties;(2) the setting tolerance is included in the total loop uncertainty, and (3) the pre-defined test acceptance criteria.bandfor the as-found value ýincludes either,.the setting tolerance or the uncertaintiesassociatedwith the setting tolerance band, but not both of these. Transmitter As-Found Tolerance The As-Found Tolerance, using the values of reference accuracy (TA), M&TE (includes both Calibration Equipment (MTE-T) and Calibration Standard (CS-T)) accuracy, M&TE readability (no readability component included), and drift (TD) yields: As-Found Tolerance = SRSS (CS-T, MTE-T, TA, TD) As-Found Tolerance SRSS (0.40, 0.40, 0.75, 1.5)" H20 As-Found Tolerance + 1.77" H2 0 An As-Found Tolerance of + 1.5" H2 0 will be used. AFT-T = + 1.5" H 2 0 Signal Monitor As-Found Tolerance The As-Found Tolerance, using the values of reference accuracy (SA), M&TE (includes both Calibration Equipment (MTE-SM) and Calibration Standard (CS-SM)) accuracy, M&TE readability (no readability component included), and drift (SMD) yields: As-Found Tolerance = SRSS (CS-SM, MTE-SM, SMA, SMD) As-Found Tolerance = SRSS (0.20, 0.20, 0.319, 0.09)" H20 As-Found Tolerance = + 0.44" H2 0 An As-Found Tolerance of + 0.25" H20 will be used. AFT-SM = + 0.25" H2 0

Page .17 Firs~ner

                 , 'CALCULATION NOP-CC-3002-01 Rev. 03*

CALCULATION NO. I VENDOR CALC

SUMMARY

C-ICE-083.03-001, Rev 17 VENDOR CALCULATION NO. N/A

5. RESULTS I 5.1. Safety Limit Designation The calculation must preserve the analytical (safety) limit. Based upon the ISA Standard and Recommended Practice, this is accomplished by combining terms and moving the setpoint away from the analytical limit. There are three methods described in the ISA Recommended Practice. Toledo Edison has determined that Method 1 or Method 2 will be the methods used. This calculation will use Method 1 (applies to Low Level trip setpoint only). I The analytical limit is 10" actual level per EXT-87-00788 (DIN 9).

5.2. Non-Zero Uncertainties As described earlier in this calculation, only the non-zero uncertainties will be included in the final calculations. I This provides a clearer more concise calculation. Those values described above that are non-zero are: Transmitter Calibration Standard (CS-T) = + 0.40" H20 SignalMonitor Calibration Standard (CS-SM) = + 0.20" H20 Transmitter M&TE Uncertainty (MTE-T) = + 0.40" H2 0 Signal Monitor M&TE Uncertainty (MTE-SM) = _ 0.20" H2 0 Transmitter Accuracy (TA) = + 0.75" H2 0 Signal Monitor Accuracy (SMA) = + 0.319" H 20 Transmitter Power Supply Effect (TPSE) = +/-_0.048" H 20 Transmitter Temperature Effects: (TTE) = +/-.3.15" H 2 0 Transmitter Pressure Effects (TPE) =+/- 0.75" H20 Transmitter Drift (TD) =+/- 1.5" H2 0 Signal Monitor Drift (SMD)- 0.09" H 2 0 (includedas a bias) SSE Effects (SSE) = 1.875" H 20 Process Dependent Effects: Low Setpoint (PDE-L) = 0.60" H 2 0 (included as a bias) High Setpoint (PDE-H) = + 2.0" H2 0 Transmitter As-Left Tolerance (ALT-T) = + 0.75" H 2 0 Signal Monitor As-Left Tolerance (ALT-SM) = + 0.135" H 20 5.3. Determination of Tested Uncertainties The ISA Standard and Recommended Practice define how the allowable valueand the trip setpoints-are'to'be: determined. Method 1 combines all of the "untested" uncertainties and sums that with the Analytical Limit to determine the Allowable Value. To determine the trip setpoint, the "tested" uncertainties are combined and that value is summed with the Allowable Value. The tested uncertainties are: CS-SM = +/- 0.20" H 2 0 MTE-SM = +/- 0.20" H 2 0 SMA =+/- 0.319" H 2 0 SMD = 0.09" H2 0 ALT-SM = +/- 0.135" HO The untested uncertainties which will be used in determining the Low Level Allowable Value are: CS-T = +/- 0.40" H 2 0 MTE-T = +/- 0.40" H 2 0 TA =-0.75"7H 20 TPSE = + 0.048" H2 0 TTE =+ 3.15" H 2 0 TPE = +/- 0.75" H 2 0 TD =+/- 1.5" H2 0 SSE =+/- 1.875" H2 0

Page 18 SrstnercCALCULATION NOP-CC-3002-01 Rev. 03 CALCULATION NO. []VENDOR CALC

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C-ICE-083.03-001, Rev 17

                                      ~VENDOR                                        CALCULATION NO. N/A PDE-L             = 0.60" H 2 0 ALT-T             = +/- 0.75" H2 0 5.4.      Determination of Uncertainty Randomness All of the uncertainties are considered to be random with the exception of the signal monitor drift and the low level Process Dependent Effect. All other uncertainties may be combined using the SRSS method as they also are considered independent.

5.5. Determination of Uncertainty Independence For the Low Level Trip, all of the uncertainties are considered to be independent of each other with the exception of the Transmitter Temperature Effects and the Process Dependent Effect. Revisions of this calculation previous to Revision 17 calculated the Transmitter Temperature Effects based on specific testing. The effects were much smaller than the Rosemount specified uncertainty and were in the (c0nservative direction for the low level trip. Based on the use of the larger Rosemount uncertainty and the Process Dependent Effect being included as a bias independent of the SRSS calculation, this adequately processes the dependent terms. For the High Level Trip, the process dependent effect is independent of the transmitter temperature effect. Since they are random, they both may be included as SRSS terms. 5.6. Calculation of the Uncertainties for the Low Level Trip Setpoint Note: Since all values are in inches H20, the units will only be displayed in the finalcalculated Value. This applies to all of the calculations. LL Trip Setpoint Uncertainty SRSS (CS-SM, MTE-SM, SMA, ALT-SM) + SMD LL Trip Setpoint Uncertainty SRSS (0.20, 0.20, 0.319, 0.135) + 0.09 LL Trip Setpoint Uncertainty 0.5372" H20 5.7. Calculation of the Uncertainties for the High Level Trip Setpoint Since the High Level Trip is not a Technical Specification trip, strict compliance with the ISA Standard and, Recommended Practice are not required. DIN 41 defines the uncertainties to be included for determining-non-safety analysis setpoints in calculations. Per the paper, DBE effects and M&TE do not need to be included.' For conservatism, all of the uncertainties will be included. HL Trip Setpoint Uncertainty = SRSS (CS-T, CS-SM, MTE-T, MTE-SM, TA, SMA, TPSE, TTE, TPE, TD, SSE, PDE-H, ALT-T, ALT-SM) + SMD HL Trip Setpoint Uncertainty SRSS (0.40, 0.20, 0.40, 0.20, 0.75, 0.319, 0.048, 3.15, 0.75, 1.5, 1.875, 2.0, 0.75, 0.135) + (0.09) HL Trip Setpoint Uncertainty = 4.7695" H20 5.8. Calculation of the Uncertainties for the Low Level Allowable Value This Allowable Value will only be for the channel functional value. The Channel Calibration will not be calculated since the new standard Technical Specifications do not have two Allowable Values. LL Allowable Value Uncertainty = SRSS (CS-T, MTI-E-T, TA, TPSE, TTE, TPE, TD, SSE, ALT-T) + PDE-L LL Allowable Value Uncertainty = SRSS (0.40, 0.40, 0.75, 0.048, 3.15, 0.75, 1.5, 1.875, 0.75) + 0.60 I

Page 19 Rrstner~  : 'CALCU LATION NOP-CC-3002-01 Rev. 03 CALCULATION NO. []VENDOR CALC

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C-ICE-083.03-001, Rev 17 VENDOR CALCULATION NO. N/A LL Allowable Value Uncertainty = 4.8069" H 2 0 5.9. Conversion of "Actual Level" to "Indicated Level" As discussed in Section 1, PCAQ 86-0336 (DIN 10), and memo NED-87-40217 (DIN 22), the "actual" steam generator level differs from the "indicated" level in part due to the temperature and pressure changes of the steam generator inventory and reference leg. As documented through Attachment 5, for collapsed level conditions the conversion of "actual" level to "indicated" level can be performed as shown below: Eq. 1) Li= [1/(l/vv1 - 1/vl)][La(l/vv 2 - 1/v12) + Hr(1/vv - t/vr1 - l/vv 2 + l/vr 2)] The conversion of "indicated" level to "actual" level can be performed as shown below: Eq. 2) La = [1/(/vV2 - 1/v12)][Li(l/vvl - 1/v11) - Hr(l/vv l- 1/r 1 - 1/VV2 + 1/vr 2)] Where:. Hr = 388 inches Lr = 300 inches vrl 0.016145 ft3/lb m - 105°F, 15 psia vvl = 26.290 ft/lb m - 68°F, 15 psia vii = 0.016046 ft3/lb m - 68 0 F, 15 psia vr 2 = 0.016150 ft3/lb m - 120'F, 1065 psia w2= 0.41555 ft/lb m - 552*F, 1065 psia v12 0.021815 ft/lb m - 552°F, 1065 psia La = actual level as measured from the transmitter's zero and not from the top of the lower tubesheet. Li = indicated level as output from the transmitter. Note: The zero reference of the transmitter is elevated 6" above the top of the lower tube sheet. For this reason, all "actual" (La) levels are reduced by 6" prior to calculation of "indicated" level. Lact = La - 6" Substituting the values above and also taking into account the 6" elevation of zero reference above equations can be simplified as below: Eq. 1) Li =0.698Lact + 10.68 in wc " Eq.2) Lact = 1.4325 Li - 15.3 in wc (Note: The conversion formula is Used in calculation C-NSA-064.02-035 (DIN'66).) 5.10. Determination of Technical Specification Allowable Value and Trip Setpoints The Technical Specification Allowable Value and the Trip Setpoint can now be established utilizing the values calculated above. It must be remembered however that the units are "inches of H20". To enable these values to be combined properly, it is required to convert the steam generator safety limit from "actual" to "indicated" level. This is done as shown above utilizing Eq. No. 1 and variables identified above. The units of inches "indicated" and "inches of H20" can be summed directly without conversion. The Safety Limit in "indicated" level is derived through solving Eq. No. 1 noted above, for the 10 inch Safety Limit case. A 6-inch elevation difference is accounted for in the calculation. The resultant value is: Safety Limit = 17.66 inches "indicated" level

Page 20 FLrsEne g CALCULATION NOP-CC-3002-01 Rev. 03 CALCULATION NO. []VENDOR CALC

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C-IC-08303-01 17VENDOR Re CALCULATION NO. N/A 5.10.1.1. Determination of Technical Specification Allowable Value The Tech Spec Allowable Value is based upon the Safety Limit and the Allowable Value Uncertainties. This results in: Tech Spec Allowable Value. = Safety Limit + Allowable Value Uncertainties Tech Spec Allowable Value (Indicated) = 17.66 + 4.8069" H20

                                                    = 22.4669".H 20
                                                     = 22.47" H 2 0 Converting this value to "actual" level through Eq. No. 2 and rounding yields:.

T.S. Allowable Value = 16.88" "actual", Margin is added to preclude a License Amendment Request if minor changes are made to the equipment and/or calculation. The final Allowable Value will be 17.3 inches "actual" The indicated Allowable Value will be calculated based upon Equation 1 above. This results in: Indicated Allowable Value = 0.698 x 17.3 + 10.68" H20 22.76" 1-1O0 5.10.1.2. Determination of the Limiting Trip Setpoint (LLLTSP) The Low Level Limiting Trip Setpoint is based upon the Allowable Value and the Low Level Trip Setpoint Uncertainties when using Method 1 from the ISA Recommended Practice (DIN 40). This results in: LL-LTSP = Allowable Value + Low Level Trip Setpoint Uncertainties LL-LTSP = 22.76 +.0.5372 LL-LTSP =23.2972" H 20-' Rounded off to = 23.30" H 2 0 As the Low Level Trip Setpoint will not be included in the new revision of the Tech Spec, there is no conversion to the "actual" level. 5.10.1.3. Determination of the Low Level Nominal Trip Setpoint (LL-NTSP) To reduce the likelihood of entering into a violation of Technical Specifications due to abnormal drift measured during the monthly functional tests, additional margin is applied between the Limiting Trip Setpoint and the Signal Monitor Setpoint. This final value is referred to as the Nominal Trip Setpoint. Additional margin = 0.20" H2 0 The Signal Monitor Trip Setpoint is defined as follows: LL-NTSP = LL-LTSP + Margin Substituting the values from above yields: LL-NTSP = 23.30 inches indicated + 0.20" H20 LL-NTSP = 23.50 inches indicated level

Page 21 t-lrstE CALCULATION ' NOP-CC-3002-01 Rev. 03 CALCULATION NO. I ] VENDOR CALC

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• C-ICE-083.03-001, Rev 17 VENDOR CALCULATION NO. N/A 5.10.1.4. Determination of the High Level Trip Setpoint The High Level Trip Setpoint is based upon an analysis done by Nuclear Engineering in calculation C-NSA-083.03-005 (DIN 62). The value was determined to be 220" H20. As discussed in Task 836 by Babcock & Wilcox (DIN 26, page 35), and reiterated in calc C-NSA-083.03-005, the calculated setpoints may be used as the actual Signal Monitor setpoint as long as the total error is below 5" H20. The total uncertainty calculated herein as 4.7695" H20 is within the B&W value of 5" H20. For this reason, the setpoint of 220" H20 will be used without additional uncertainty margin.

5.11. Agreement Criteria The transmitters located in the containment are surveilled every 24 months. To ensure failures are detected as soon as possible, a Channel Check is required by Technical Specifications every 12 hours. Compliance with this requirement is accomplished by evaluating the indicated outputs every 12 hours during normal operation via procedure DB-OP-03006 (DIN 84). To determine if a failure or significant drift has occurred, the indicated outputs of all 4 transmitters in the SFRCS cabinets are compared with each other. A maximum difference or Agreement Criteria, as it is defined in LAR 06-0003 (DIN 85), is established "...based on a combination of the channel instrument uncertainties, including isolation, indication, and readability." The Dixson model SA101 indicators are in the current loop of the transmitter, thus no uncertainties other than the transmitter and the indicator need to be included. The indicators have a resolution of 1% (3.0 inches) bargraph and 0.01% (0.03 inches) digital (ACCIND) based on vendor manual M-538-00061 (DIN 86). Since the indicator is a 4 digit digital output, the smallest digit is 0.1 inch on the 300 inch required range. The value of 0.1 inch will be used as indicator accuracy. Combining these uncertainties with the normal transmitter uncertainty results in: Agreement Criteria = SRSS (CS-T, MTE-T, TA, TPSE, T-TE, TPE, TD, ALT-T, ACC-IND)

                             = SRSS (0.40, 0.40, 0.75, 0.048, 3.15, 0.75, 1.5, 0.75, 0.1)
                             = 3.77 inches As one transmitter could be high and the other low, a total differential range of 7.54 inches is established. Based on the readability of the gauge being 0.1 inches due to the digital readout, the total difference for the Agreement Criteria is to be 7.5 inches.

Agreement Criteria 7.5 inches differential or less

6. CONCLUSION The values developed in this setpoint derivation satisfy the acceptance criteria set forth in this calculation. The calculation was developed in compliance with the ISA Standard and Recommended Practice (DINs 11 and 40),

the TSTF Traveler (DIN 67), and the Regulatory Issue Summary (DIN 68). Based on this, Acceptance Criteria 1 and 2 are satisfied. For Acceptance Criterion 3, Figure 4 depicts the Operational Maneuverability. Based on the Figure, there is approximately 4 inches of additional margin between the overshoot and the worst case instrument setpoint error. This is acceptable operational maneuverability, therefore, Acceptance Criterion 3 is satisfied. The final calculated values are: Actual Indicated Analytical Limit - Low 10" 17.66" H20 Allowable Value - Low 17.3" 22.47" H2 0 Limiting Trip Setpoint - Low N/A 23.30" H20 Nominal Trip Setpoint - Low N/A 23.50" H20

Page 22 CALCULATION NOP-CC-3002-01 Rev. 03 CALCULATION NO. [ VENDOR CALC

SUMMARY

C-ICE-083.03-001, Rev 17 VENDOR CALCULATION NO. N/A Nominal Trip Setpoint - High N/A 220" H20 As-Left Tolerance: Signal Moniitbr + 0.135" Transmitter + 0.75" As-Found Tolerance: Signal Monitor + 0.25" Transmitter + 1.5" Agreement Criteria 7.5 inches differential or less

Page 23 CALCULATION NOP-CC-3002-01 Rev. 03 CALCULATION NO. [1 VENDOR CALC

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C-ICE-083.03-001, Rev 17 VENDOR CALCULATION NO. N/A Figure 3 S.G. LOW LEVEL SETPOINT ERROR ANALYSIS Note: all values are "Indicated? levels at 1065 psia and 552 degrees F referenced to the top of the tube sheet except those within brackets. Those within brackets are "Actual"values 23.635" Signal Monitor Setpoint (Max.) Nominal Field Setpoint 23.5" p 23.365" Signal Monitor Setpoint (Min.) Margin

                                  }                                               23.30" Limiting Trip Setpoint

" M&TE Uncertainty

• Signal Monitor, Accuracy
• Signal Monitor Drift
• SignalMon6itor As-Left Tolerance
• All uncertainties from 22.47" (17.3") Tech.

below .Spec. Allowable Value 4 For Channel Functional Test " Transmitter Pwr.Supply effect " Transmitter temperature effect " Transmitter.pressure effect " Transmitter drift

• SSE effects
• Process dependant effects
• Transmitter As-Left Tolerance

                                                                                 -17.66" (10") Safety Limit

.Fit EJneQ                                               CALCULATIONPae2 NOP-CC-3002-01 Rev. 03 CALCULATION NO....                                                          [ ]VENDOR CALC 

SUMMARY

SC-ICE-083.03,ý001, Rev 17

                                                .                          VENDOR CALCULATION NO. N/A Figure 4                                                                                                               I)

S.G. LOW LEVEL OPERATIONAL MANUEVERING ANALYSIS Note all values are indicated level readings at 1065 psia and 552° F 4- ,40.00"- ICS LOW LEVEL LIMITS EXPECTED RANGE OF ICS LEVEL CONTROL 36.00" - NORMAL LOWER OVERSHOOT CONTROL BAND 4__ 33.00" - SLIGHT LEVEL CONTROLLER OVERSHOOT AVAILABLE MARGIN FOR ADDITIONAL LOW LEVEL LIMIT OVERSHOOT 28.98" - UPPER EXPECTEDI RANGE OF. LOW LEVEL:. ACTUATION-(23.64" (Low Levtel setpoint (Max))4,4.8069", (Allowable Value Uncertainty) t, 0.5372" (Low Level Uncertainly)) 23.635" - LOW LEVEL 4 EXPECTED RANGE SETPOINT (MAX) OF SFRCS S.G. LOW LEVEL TRIP ACTUATIONS 23.365" - LOW LEVEL I SETPOINT (MIN) 4 17.66"- SAFETY LIMIT

NRC ITS Tracking Page I of 2 Reunto View. Menu pintDocum~ent R.A Screening Required: Yes Status: Closed This Document will be approved by: Gerald Regulatory Basis must be included in Comments Waig; Tim Kobetz section of this Form This document has been reviewed and Yes information in this question contains NO SUNSI sensitive material (the checkbox to the right must be selected before this question can be submitted) NRC ITS TRACKING NRC Reviewer FID 200712261243 Conference Call Requested? No Categor J[BSI - Beyond Scope Issue ITS Section: TB POCD D..Num-ber;. P.age..Number (s$):. ITS 3.3 Aron Lewin Iqbal Ahmed *11 371 Information ITS.Numnber:. 01: _DQC...Numr:*l Bases..JFDMNmber:. 3.3.11 2 M.2 None Question submitted by Iqbal Ahmed. With regard to TS Table 3.3-12 trip setpoint allowable values (AV) for Steam Line Pressure-Low, Steam Generator Level-Low, and Steam Generator Feedwater Differential Pressure-High, functional units instrumentation: Provide a statement as to whether or not these three setpoints ate limiting safety system settings (LSSSs) for the variables on which a safety limit (SL) has been placed as discussed in 10 CFR 50.36(d)(1)(ii)(A). These variables Comment provide protection against violating reactor core safety limits, or reactor

         .................... coolant system pressure boundary safety limits. For each setpoint that you determined not to be SL-related, explain the basis for this determination.

To determine the acceptability of the proposed TSs change involving revision of instrumentation setpoints, the NRC staff generically requests all licensees who propose revision of instrumentation setpoint and/or setpoint AVs (conservative or non-conservative), to provide the above information (I&C Branch Guideline for Setpoint-Related TSs License Amendment Request - ADAMS Accession No. ML061810132) Issue Date 12126/2007 I Close Date 04/08/2008 Logged in User: Anonymous 'vResponses Licensee Response by Jerry Davis-Besse has determined that these three setpoints are limiting Jones on 03/10/2008 safety system settings (LSSS) to protect against violating safety limits. I. 11 http://www.excelservices.com/exceldbs/itstrackdavisbesse.nsf/ Ifddceal Od3bdbb585256e... 7/18/2008

NRC ITS Tracking Page 2 of 2 NRC Response by Timothy Kolb Information supplied'by the licensee is: sufficient to complete the on 04/08/2008 safety evaluation input. No further questions at this time. This item is closed. Date Created: 12/26/2007 12:43 PM by Timothy Kolb Last Modified: 04/08/2008 02:40 PM http://www.excelservices.com/exceldbs/itstrackdavisbesse.nsf/1 fddcealOd3bdbb585256e... 7/18/2008

NRC ITS Tracking Page I of 2 Return to View Menua Prit D=1~1 FLI Screening Required: Yes Status: Closed This Document will be approved by: Gerald Regulatory Basis must be included in Comments Waig; Tim Kobetz section of this Form This document has been reviewed and Yes information in this question contains NO SUNSI sensitive material (the checkbox to the right must be selected before this question can be submitted) NRC ITS TRACKING NRC Reviewer ID 1200712261254 Conference Call Requested? No Category BSI -Beyond Scope Issue. ITS Section.: TBWPOC.:. JFD Numniber: Page.Numnber(s). ITS 3.3 Aron Lewin Iqbal Ahmed 11 371

    -Information  ITS Nunb.ter:.        OR:                 DOC.Number:        BasesJF   Number; 3.3.11                2                   None               None Question submitted by IqbalAhmed.

With regard to TS Table 3.3-12 trip setpoint allowable values (AV) for Steam Line:Pressure-Low, Steam Generator Level-Low, and Steam Generator Feedwater Differential Pressure-High, functional units instrumentation: For setpoinfts that are determined to be SL-related, the NRC letter to the Nuclear Energy Institute (NEI) SetpointMethods Task Force (SMTF) dated September 7, 2005 (ADAMS Accession No. ML052500004), describes Setpoint-Related TS (SRTS) that are acceptable to the NRC for instrument settings. associated with SL-related setpoints. Specifically, part "A" of the enclosure to the letter provides LCO notes to be added to the TS, and part "B" includes a check list of the information to be provided in the TS Bases for the proposed TS changes. In this regard, please address items a, b, and c of this section. Comment a. Describe whether and how you plan to implement the SRTS suggested in the Comment September 7, 2005, letter. If you do not plan to adopt the suggested SRTS, then explain how you will ensure compliance with 10 CFR 50.36 by addressing items b and c below.

b. Describe how surveillance test results and the associated TS limits are used to establish operability of the safety system. Show that the As-Found Setpoint valuation is consistent with the assumptions and results of the setpoint calculation methodology.

c. Describe the controls employed to ensure that the instrument setpoint is, upon completion of surveillance testing, consistent with the assumptions of the associated analyses. If the controls document is other than the TS (e.g. plant test procedure), explain how the requirements of 10 CFR 50.36 are met.

To determine the acceptability of the proposed TSs change involving revision of instrumentation setpoints, the NRC staff generically requests all licensees http://www.excelservices.com/exceldbs/itstrack-davisbesse.nsf/lfddceal Od3bdbb585256e... 7/18/2008

NRC ITS Tracking Page 2 of 2 who propose revision of instrumentation setpoint and/or setpoint AVs (conservative or non-conservative), to provide the above information (I&C Branch Guideline for Setpoint-Related TSs License Amendment Request - ADAMS Accession No. ML061810132) II Issue Date 12/26/2007 IClse Date 04/08/2008 Logged in User: Anonymous

'Responses Licensee Response by Bryan         Davis-Besse has determined that these three setpoints are limiting Kays on 03/11/2008                 safety system settings (LSSS) that protect against violating safety limits, as stated in our response to NRC question 200712261243.

Therefore, two notes have been added to the Channel Functional Test and Channels Calibration requirements in ITS Table 3.3.11-1 for Functions' 1, 2, and 3, consistent with similar notes in ITS 3.3.31, Reactor Protection System Instrumentation for Functions 1.a and 5. In addition, changes have been made to the Bases, consistent with similar changes made to ITS 3.3.1 Bases. The Notes and additional Bases changes are consistent with the Setpoint-Related Techncial Specifications isuggested in the NRC letter to the NEI Setpoints Methods Task Force, dated September 7, 2005. A draft markup regarding this change is attached. This change will be reflected in the supplement tothis sectionof0 the ITS Conversion Amendment. Since the two n6tes have been _ _ _ _ _ _ _ adopted, items b and c are not required to bel answered. NRC Response by Timothy Kofb Information supplied by the licensee is sufficient to complete the on 04/08/2008 safety.evaluation input. No further questions: at this time. This item is closed. Date Created: 12/26/2007 12:54 PM by Timothy Kolb Last Modified: 04/08/2008 02:42 PM http://www.excelservices.comlexceldbs/itstrackdavisbesse.nsfl1 fddcealOd3bdbb585256e... 7/18/2008

NRC ITS Tracking Page I of 2 Returnto Viw Men Print Docuen RAI Screening Required: Yes Status: Closed This Document will be approved by: Gerald Regulatory Basis must be included in Comments Waig; Tim Kobetz section of this Form This document has been reviewed and Yes information in this question contains NO SUNSI sensitive material (the checkbox to the right must be selected before this question can be submitted) NRC ITS TRACKING NRC Reviewer ID 200712261257 Conference Call Requested? No Category BSI - Beyond Scope Issue ITS Section: TBRPOC:. JFD.Number: Page Number(s):. ITS 3.3 Aron Lewin Iqbal Ahmed 11 371 Information ITS Number: os!" DOC Number: Bases JFD Number: 3.3.11 2V None None Question submitted by Iqbal Ahmed. With regard to TS Table 3.3-12 trip setpoint allowable values (AV) for Steam Line Pressure-Low, Steam Generator Level-Low, and Steam Generator Feedwater Differential Pressure-High, functional units instrumentation: For setpoints that are not determined to be SL-related, describe the measures to be taken to ensure that the associated instrument channel is capable of performing its specified safety functions, in accordance with applicable design requirements and associated analyses. Include in your discussion the Comm-nent information on controls you employ to ensure that the as-left trip setpoint setting after completion of periodic surveillance is consistent with your setpoint methodology. To determine the acceptability of the proposed TSs change involving revision of instrumentation setpoints, the NRC staff generically requests all licensees who propose revision of instrumentation setpoint and/or setpoint AVs (conservative or non-conservative), to provide the above information (I&C Branch Guideline for Setpoint-Related TSs License Amendment Request - ADAMS Accession No. ML061810132) Issue Date 12/26/2007 f Close Date 04/08/2008 Logged in User: Anonymous

 'Responses Licensee Response by Jerry            Davis-Besse has determined that these three setpoints are limiting Jones on 03/11/2008 safety system settings (LSSS) that protect against violating safety http://www.excelservices.comn/exceldbs/itstrackdavisbesse.nsf/1 fddceal Od3bdbb585256e... 7/18/2008

NRC ITS Tracking Page 2 of 2 limits, as stated in our response to NRC question 200712261243. __Therefore, this questionis not applicable. NRC Response by Timothy Kolb Information supplied by the licensee is sufficient to complete the on 04/08/2008 safety evaluation input. No further questions at this time. This item is closed. Date Created: 12/26/2007 12:57 PM by Timothy Kolb Last Modified: 04/08/2008 02:42 PM http://www.excelservices.com/exceldbs/itstrack davisbesse.nsf/lfddcea10d3bdbb585256e... 7/18/2008

NRC ITS Tracking Pagel1 of 2 Return to View Menu Print Document RAI Screening Required: Yes Status: Closed This Document will be approved by: Carl Regulatory Basis must: be included in Comments Schulten; Tim Kobetz; Gerald Waig section of this Form This document has been reviewed and, Yes information in this question contains NO SUNSI sensitive material (the checkbox to the right must be selected before this question can be submitted) NRC ITS TRACKING NRC Reviewer ID 200801101044 Conference Call Requested? No Category BSI - Beyond Scope Issue ITS.Section: T.B POC;. JFD Number: Page-Number(s): ITS 3.3 Aron Lewin None Information ITS.Number: OS!: DOC.Number: Bases JFD.Number: 3.3.11 None None None NRC OSI#64 Discuss how allowing Method 1 or Method 2 of Reference 3 JISA 67.04-Part II-1994] or 3 [ISA 67.04.02-2000] for all SFRCS Functional Units in the ITS Bases ensures that the limiting safety system setting is chosen so that automatic protective action will correct the abnormal situation before a safety limit is exceeded in accordance with 10 CFR 50.36(d)(1)(ii)(A).

Background:

                           -The Bases for CTS 3/4.3.1 and 3/4.3.2 (page 398 of 490 in the CTS), state that "for the SFRCS Table 3.3-12 Functional Unit 2, only the Allowable Value is specified for each Function. Nominal trip setpoints are specified in the setpoint analysis. The nominal trip setpoints are selected to ensure the setpoints measured by CHANNEL FUNCTIONAL TESTS do not exceed the Allowable Comment Value if the bistable is performing as required. Operation with a trip setpoint less conservative than the nominal trip setpoint, but within its Allowable Value, is acceptable provided that operation and testing are consistent with the assumptions of the specific setpoint calculations. Each Allowable Value specified is more conservative than the analytical limit assumed in the safety analysis to account for instrument uncertainties appropriate to the trip parameter. These uncertainties are defined in the specific setpoint analysis."
                           -The Bases for the ITS (page 394 and 395 of 636) states that "the trip setpoint is established using Method 1 or Method 2 of Reference 3 [ISA 67.04-Part 11-19941 or 4 [ISA 67.04.02-2000]."
                            -The Bases for the STS for LCO 3.3.11 (NUREG-1430), state "a detailed description of the methodology used to calculate the trip setpoints, including their explicit uncertainties, is provided in "[Unit Specific Setpoint Methodology] ".

http://www.excelservices.com/exceldbs/itstrackdavisbesse.nsf/1 fddceal Od3bdbb585256e... 7/18/2008

APPENDIX B SETPOINT: BASES (cont.) The setpoints for the reactor coolant pump (RCP) motor high and low current are outside the normal operating motor current variations during normal operating conditions. Refer toReference 4.5.41 for additional details on the setpoint calculations and assumptions. Since all four RCPsmust indicate a tripped condition simultaneously on a low or highsignal for SFRCS to initiate action, an SFRCS loss of all RCPs trip initiation signal will-not occur when a single pump is being started and the motor inrush current may be higher than the motor high current setpoint. The 720 psig setpoint permitting the block of the. lowmain steam line pressure, trip is above the 620 psig low main steam pressure setpoint, and below the minimum expected operating steam pressure. B-2 SD-010 Rev. 4

APPENDIX B SETPOINT BASES The criteria for the selection of setpoint values for the process variables monitored by the Steam and Feedwater Line Rupture Control System (SFRCS) are as follows: o Select values which will not be'reached during normal operation. o Select trip values near enough to the normal operating limit value to provide early detection and mitigation of an accident. o Select an SFRCS steam pressure bypass setpoint value that allows sufficient time during normal cooldowns for the operator to set the bypass switches prior to reaching the low pressure trip setpoint value, including considerations for switch setting tolerances. USAR Sections 15.2.8 and 15.4.4 (Reference in Section 4.4.1) summarized the analysis of the loss of: main feedwater, main feedwater line break, and the main steam line break accidents. The setpoint values used in the analysis were the setpoint values indicated in the Technical Specification for the low main steam 'pressure, main feedwater differential pressure, and steam generator low level (Reference in Section .4.4.2) . The results of the analyses indicated the plant met all specified acceptance criteria during each event. In all cases, the auxiliary feedwater was initiated by the SFRCS, secondary side cooling was maintained, and the primary system pressure boundary was maintained intact. The resultant doses for each event fell well within the allowed values as specified by 10 CFR 100. The values used for the low main steam pressure, high main feedwater/steam generator differential pressure, and steam generator low level are the allowed trip limits for these variables. The selected setpoints shall incorporate the setting tolerance, the loop uncertainty, and instrumentation drift over the time period between calibrations. These considerations will ensure the trip signal is initiated prior to reaching the, allowed trip limits set by the analyses. The steam generator startup level transmitter is calibrated for a 100 percent. span value of 300 inches. The actual water level at 100 percent indicated level is below the point in the steam generator where water could enter, the steam lines for all expected operating conditions. The setpoint value for steam generator high level is selected to initiate a trip at a maximum 220 inches indicated level, or 80 inches below the 100 percent calibrated range of the transmitter. B-I SD-010 Rev. 4

APPENDIX A ACRONYMS AND ABBREVIATIONS (cont.) RDM relay driver module RS- SFRCS trip output signal-RSI- SFRCS digital input signal-SAIC Scientific Application International Corporation SD System Description SF- SFRCS drawing series SFAS Safety Features Actuation System SG Steam Generator SRTP System Review and Test Program SFRCS Steam and Feedwater Line Rupture Control System Sov solenoid(s) operated valve SP secondary plant STM steam TE Toledo Edison Company USAR Updated Safety Analysis Report Vac voltage alternating current Vdc voltage direct current VLV valve A-2 SD-010 Rev. 4

APPENDIX A ACRONYMS AND ABBREVIATIONS The meanings of the acronyms and abbreviations used in this document are provided below: AC alternating current AFP auxiliary feed pump AFPT auxiliary feed pump turbine-AFS auxiliary feedwater system AFW auxiliary feedwater' AOM alarm output module ARTS Anticipatory Reactor Trip System B&W Babcock & Wilcox CCC Eaton/Consolidated Control Corporation CH channel CMOS Complementary Metal Oxide Semiconductor DB Davis-Besse DC direct current DHRTF Decay Heat Removal Task Force Dwg drawing FB field buffer FBM field buffer module FCR Facility .Change Request FW feedwater ICM Intra Company Memorandum ICS Integrated Control System ISI Inservice Inspection ISO isolation LCH logic channel LED light emitting diode LM logic module MCC Motor Control Center MFWLB Main Feedwater Line Break MN main MOD modification MOV motor operated valve MPR MPR Associates MS main steam MSLB Main Steam Line Break OTSG Once Through Steam Generator P&ID Piping & Instrument Diagram P/N part number PAM Post Accident Monitoring Pnl panel PWB printed wiring board RCP reactor coolant pump RD relay driver A-I SD-010 Rev. 4

F RESET/RILOCK -- I SD-OIO BOUNDARY HISB

REFERENCES:

M-007B)

                                                                                                               . REF.

IT-5'8 (7.1l.6) (P&IO SPTI TRIP LOGIC ICS CONTROL I. PROTECTION CHANNEL2i PROTECTION CHANNEL I RS-6582B RS-65B4B RS-64AIB RS-64A3B FIC ICS338 sA--- I SV I SV I SV F- -- SV FY SPT7 ZC SPTB II I

I I I TRIPOy(Rhiml OTISctRO FURESET/RLOC2 TRIP (CLOS FW-SP7B VALVE FW-SP7B SP78 START-UP CONTROL VALVE FIGURE 2.2-26 F2. 2-26-I SD-OlO, REV.4 D0:12-22-04 DFN-H:/SYSDES/SDF22261.ODGN

S10BOUNDARY ~

REFERENCES:

I. REF.' 7.1.6 (PUDO -- 007b) I TRIP LOGIC ICS CONTROL 10 PROTECTION CHANNEL I  % RS-65A3A RS-GSAIA FiC C A/S I _ _ _ _ _ I I F S, 6AI S AIA . ... PIe

                                                      %ZF.                                                    ICEISA 7
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                            .... R

__ ~ I SP ~SP6A i

-                          -T1Pý_OVERRIDE 5M            L (V)

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REFERENCES:

I. REF. 7. 1.3 (P & I D (4-003A) SD-010 BOUNDARY ~*~ TRIP LOGIC PROTECTION CHANNEL2 PROTECTION CHANNEL I 1011 RS-6213A I ROOS 4I CLOG-R-E-) - J-.-.-.-

                                         / PY SNt0lA
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                                                                                      )                     I/                                I                      EDC PL                                                          IS                  I0 IOIF        IOIJ L                           F..J          (V      J
                                                            -304-6      F             0i                   01 cF TRIP (CLOSE)

MS-101 I I MS-I01 PNEUMAT[C DIAGRAM MAIN STEAM LINE-I ISO VALVE MS- 101 FIGURE 2.2-24

                                                                                        -I                                                SD-OIO,             REV.4 OB:12-21-04   OFN=H:/SYSDES/SDF2224I.OGi

REFERENCES, I.REF. 7.1.14.11 4SF-0038 SH.11)

2. REF 7. 1.27.8 (E-46B SH.32A)

3. REF. 7.1.4 (PSI0 M-O03C)

NOTES: I.MANUAL INITIATION IS SIMPLIFIED, FOR SD-010 BONDARY DETAIL SEE REFERENCE 7.1.14.1 (SF-OO3B SH.1) 81 125 VOC F2/F8 FROM LA-081 FIG. G -n CONTROL LOGIC DIAGRAM MAIN STEAM LINE-I WU ISO VALVE _ SOENOI STATUS MS-101-1 OPEN ENERGIZEO NORMAL II CLOSE/TRIP E-ENERGIZEJCLOSE/TRI FIGURE 2.2-23 F2. 2723-1 S)-01O , REV.4 OBD 12-21-04 DFN=H /SYSOES/SOF22231.DC

REFERENCES:

IREF. 4.1,.14.21 (SF-0036 SH.211 2.REF. 4.1.?7.15 iE-46B SH,71l

3. REF. 4.1.4 (P11O M-003C)

S-OI BOUNDARY - NOTES, I.MANUAL INITCATION IS SIMPLIFIED. FOR DETAIL SEE REFERENCE 4. .14.1 (SF-_03 SH.A ) F.. -r? (v) F..OV CONTROL LOGIC DIAGRAM AFPT-I MAIN STEAM IN [SO VALVE A ENO10 STATUS MS-5889A ENERGIZE NORMAL VENT/TRP 'NRG[ZEq VENT/TR[P FIGURE 2.2-22 F2. 2-22-1 SD-OO, REV.4 DBS12-21-04 DFN-H:/SYSDES/SDF22221.DG

REFERENCES. I.REF. 7.1.14.I9 (SF-003R SH.19)

2. REF. 7. 1.27.9 6 10 (E468 SH.33/A)

SD-010 BOUNDARY 3.REF. 7.1.6 0P&ID M-O0B) NOTESý 33 to CLOSE TOROUE I.MANUAL INITIATION 1S SIMPLIFIED, FOR LTRI-001 UL PDETAILS SEE REFERENCE 7.1.14.1 3(SF-D03 SH.J)

2. THIS DIAGRAMDESCRISES THE FOLLOWING BLOCK SFRCS FEATURES:'OUTPUT AND-GATE, K ._.OR LOCK, TESTING. MANUAL TRIP.

HIS-6l1IR HI611 TA 1VA PO1R 3.FOR CONTROL POWER AND OTHER CONTROLS SEE REFERENCE 2. TA-101 LA-101 (RS-6I16A) MANUAL(NOLE LTAB-103 D G SF-CLOSE TSB-10 DS rM S-SI TB-103

                                                                                                -                       I   RS-6      1 CONTOLSOGI             DIGRA F2.PU  -IG-AE

_L.,E TRIPFIGURE 2.2-21 F2.2-21-1 SD-OIO, REV.4 OB:I2-21-04 DFN=H:/SYSfIES/SDF222I1.DC

REFERENCES:

I.REF. 4.1.14.8 (SF-0038 $H.8) 2.REF. 4.1.27.3 t 4 (E46B SH,IE/FI 3.REF. 4.1.3 (P&lD M-003A) NOTES, t.FOR PNUEMATIC CONTROL CIRCUITS SEE FIGURE 2.2-24 NJ NJ NJ C MAIN STEAM LINE-I ISO VALVE MS-101. SOLENOID VALVES SA SOLNID STATUS SV-101E, SV-1I01C/D 11 NORMAL ENRIE I NRA M - ET/RP EEERGIZE00VET/TRIP FIGURE 2.2-20 SO-OlO, REV.4 F2. 2-20-1 F2. 2-20-1l D8 12-21-OA DFN=H:/SYSDES/S0F2220I.0CI

REFERENCES; I.REF. 4.1.14.9 ISF-0038 SH.9)

2. REF. 4. 1.27.1 2 1E46B SH. A/0)

3. REF. 4.1.3 (P&lO N-0O3AI NOTES, I.FOR PNEUMATIC CONTROL CIRCUITS SEE FIGURE 2.2-24 2.MANUAL INITIATION IS SIMPLIFIED. FOR DETAILS SEE REFERENCE 4.1.14.1 (SF-0038 SR.I)

'1 N) N) CONTROL LOGIC DIAGRAM MAIN STEAM LINE-I ISO AND SOLENOID VALVES A I SOLENOIO STATUS SV-IOI8, SV-IOIA NORMAL ENER EDD NORMAL VENT/TRIP D'NERGIZE4 VENT/TR IP FIGURE 2.2-19 F2. 2- 19-4I SD-O1O, REV.A D8 12-20-04 DFN=H:/SYSDES/SDF22191.DGN

REFERENCES:

I.REF. 4.1.14.3 (SF-003R SH.3) D.REF. 4.1.26.5 & 6 IE-44B SR.14A/B) 3.REF. 4.1.6 (P&ID M-007B) NOTES: I.MANUAL INITIATION IS SIMPLIFIED, FOR DETAILS SEE REFERENCE 7.1.14.1 (SF-003B O .1)

2. THIS DIAGRAMDESCRIBES THE FOLLOWING SFRCS FEATURES: OUTPUT AND-CATE, BLOCK, TESTING. MANUALTRIP.

3. FOR CONTROL POWER AND OTHER CONTROLS SEE REFERENCE 2.

~'1 ND ND CONTROL LOGIC'DIAGRAM AFP-I DISCHARGE TO SG-2 VALVE AF-3869 FIGURE 2.2-18 F2. 2-18-1 SD-I01, REV.4 08:12-21-0.4 DFN=H:/SYSDES/SDF2218I.DG

OS f

                                                                                             -5CCK-TLOGC'c ONNNEL               CLOSE/TRIlP        -I LrH-2            CLOSl/T-RIP-                     OP-E N                 BLPCN                                                                                          BLOCK        LCH,-

M TALTB LA CLD TC SA LEA. TRA ?2 A 5 tB LB TA S S5OLLC R

              .1           0       k         02                    0     0 0sI,   0                              0         0                                     *F-37 00 0                   0 X'            0 0             0             AF-3071                     ~W TRIP

_00 000 na-I7A 0 OW4 OOSO ___ r MS-58828 5'o' P2 0 6 A TS _______________ TURBINE 07- ____________ 0 0~ a~ CLOSE 0%B 0 X B 0 )1 10 0 0 0 MS-6O3 0 . *0 00 0 W@ 11= 0 0 SV'ICS IIAI 0 0 0 "~ 0

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0 FW-601 0 0 CLM, CLM W.00* ==n=== 0 0*0 0 0 o . 0 l2 0 e ,y 0 X O I e..0 ,- 0  % 0 1'4 N)o 0 E0 13 FW-779""

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                        '0 0              21                                                                                    0        0.21 10         @0 2                                    ---               -                                  0       0       0 22 NOTES, ant   I  '-'       -    ~Lna~eamI                   ~            L2.~      '-'

MANUALFTMl"l 0 0EE 0 a-Ea 0

                 ,, I                                                                                                                       .                                                 II               I1 REFERENCE DRAWING SF-O08 SH,      2 T. 4Tlf - 1m       ITA M(C *a LH L        ItC)

A L- In LIOnTa LOTa I LTC) 'onIT l-L TRIP A (CI . I n Z rA (TMT)na

                                                                                                                                  '*m                  )        -   mn      . (LaP a1                             (SECTION 4.1.20.2)

Th(OIM) TT TRIP. (DI Ia .. (..I - IIe ( lO a T (LTI- - aTatISLi[e" ITIP 1 urs n Ia (C a 10 l - SPa-I PAn mlS T ( (=L.l LTITfl}l EST0an LAO (af 2 l f

   )

I ..... I i OUTPUT PANEL A5 PROTECTION CHANNEL 2 FIG 2.2-12

     --                                                                                                                        F2.2-12-1 SO-010,    REV.4 DB:12-20-04 DFN-H:/SYSDES/SDF22121.DGN/CI7

I- - - CLOSE/TRIP OPEN BLOCK LOGIC CHAT1t*EL CLOSE/TRIPF OPEN BLOCK LC TL-TA LA LTB TC LC LTD

• LTC TEE LEE .TRS L LC-3 LSA TRA 1 3 TB LB LTA 2 TO PL 0~ .o0 ,5
• 1 ..01 MS-i 0E o I 0*zO 0 ©lo ©* e0( AF-38TO 0 0~ % 0 AF-3869 101

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0, 'o 0* 0 0 mJp ARTS TURBINE o ~'o HAS Tr,-ot -7* ME- 101-i A, omm 0 * . 0 0 0 7 O (' MS-B I I ICsI IB 0 I *,1 == 0) .10 0 O" 0 ====

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0 *( 0 0 0 TRI N) AS* 0~ ~ 0**o"* 0, 0 14 B ~ 0 TRIp N) 61.1 o AK 0 '30 FW-780 FW-SP78 0 0 is' o E1 *z * '2 B0 0 STOP50SO Ptel 0 0O === 0 O 0 o l~0 0 0 0 X *IS SPARE 0 0 0.,0 o 0 02,~ SPARE- o0 .O SPARE SPARE 0 0o*, S9-= o VX, lx o0r~~22 0 E0 AIONUAL AI/M2 0 0 f5i10 - - NOTES; TRIP INHIBIT I. REFERENCE DRAWING SF-DO0 SH. I (SECTION 4.1.20.1) T. 1 )- 3 A;: 1

                    . T.ST          1 L* I. 1A     11.01
                                                   .-   - ST.- LIT 2*21.5T L

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                                                                                                                                                    -1*T SET1.0 IiOi 1    1 1.0001 3 Ii L     I) 1    ,

TIo1 T ) . TEIT II 101 10 I 1U .1 3TIIn1174 . TOOT MOOST JKLOCI LO I 1.003) j5*1 lO 2 OUTPUT PANEL A5 PROTECTION CHANNEL I FIG 2.2-11

                                                                                                                                                                                                      .. - . .8:12-20-04    0 0, EVH:/SYSES/SOF22114.

LOGIC CH ANNEL NO 2 " LOGIC CHANNEL NO 4 SIGNAL NS BYp T L SIGNAL NORSFBypT L I SIGNAL NOR5-FYP T L SIGNAL T L

                                              -S-368TLK                                            h SPARE  162    -Q       0     'So    ILK PERM I2               5-'368"7M1 ILK PERM              I'd 10        SPARE 164              0     ,° IBo SPARE172      C*       0     170
                                              ,LK PERM 022    08%

02 LK PERM S-3687E 0 2% SPARE 174 Q 17 034

                                               -S-36BTA SPARE  I82    CQ       C     '60              032 0             SPARE    184 -         0    (le*

SO-2 S-36870 SG-I

                                               -S-3587C SPARE  192    C)Q        I0["9                04,2 0 4%          SPARE 194      C       0Q '90 SO-I                         DS-2SR10354 SPRE      202          0    zo       0DS-265A0 052 SG-26 "TS-26868 0             SPARE 204      C       2)200oo LESEND SB- TWITCHBYPASS LT    - LEVEL WORM-       SWITCH NOAMAL SOG-072    o'l 06.4         0 80        LEGEND                 LT - LEVEL SWITCH SO - SWITCHBYPASS NORM NORMAL T TEST/TRIP BUTTOBYP - BYPASS                                                                            T - TEST/TRIP BUTTOfBYP - BYPASS

-nJ L -STATUS LAMP S/0. SHUITDOWN As KES WI TS -TEST SWITCH SG-6

                                              ;G- I LEM 07L2#' 040             S97074 S- I LSOIW              0 I7*          L - STATUSLAMP 2/D- SHUTDOWN KS - KEYSWITCH TS - TEST SWITCH r\-

SPAB SP9A9 A - 5S C -LEVEL X.ITTER TEST POINTS BUC PERM -BLOCK PERMIT 'ROWSO-C C-C 0 LOOHI 050 CO-2 L0-0 0814 0 60 A - B - C - LEVEL XTITTER TEST POINTS BLK PERM - SLOCKPERMIT FROMS0-2 ORANGE INSERTLED NOT USED ORANGEINSERT LEO NOT USED SGI 092 LOL 0'7 CO-1 LSLL 0 LISPSSWOM)lfl 0 0 0 SP9A9 00 0 00-2 LOLL

                                                       .1LLC02 00-C LSLL               0          I:s~TT-IINPUTOE        00 A

0EST 0 (bTO-0 00 RCPM-2 112 RCPM-4 114 0 ,00 SPARE 122 SPARE 124 0 SPARE 122 SPARE 134 HIS- I oCR 4 At5- 1OOC-144 130 - ~ 5/0 BLK /0 SILK U00 o% NOTES. TEST 5 TEST. 154 0IA ENABLE ONABLE "I. REFERENCE DRAWING SF-007 SH. 2 (SECTION 4.1.19.2) INPUT PANEL A2 PROTECTION CHANNEL 2 FIG 2.2-10 F2.2-10-1 SD-010,-REV. 4 DB:12-20-04 OFN:H:/SYSDES/SDF22 01.DGN/CI

LOGIC CHANNEL NO I LOGIC CHANNEL NO 3 SIGNAL SOB NOR-BYP T L SIGNAL NORM-S SB 7SIGNAL SB NOMIy T L SPARE 161 :Q 0 - Oil 0 I _SPARE 163 @ 0 ,E BLK PERM PS- 6EBL SPARS 171 CQ QI.70 SLV PERM 02- 0 2 SPARE 173 C 0 17@ SPARE I E31 CQ 0Qie P369031 0 30 SPARE 183 CQ O 180 SPARE 191 c*0 g 0 4N SPARE 193 C~Q Q 190 SG- 2 SPARE 20 1 Q Q0o.6 0 5 SPARE 203 CQ UQ 20

-`1 rJ LEG-EN !

SB S'HITOYBYPASS

                                  - LEVEL BBIlTHS 1-1 NORM.-NORMAL.

SO-2 0 6 LEOSEN sBo SWITCHBYPAOS S'OR-LT -LEVEL NORMA SWITCH

          - TEST/TRIP BUTTONBYP -BYPASS                                                  rET NTEST/TBP BUTTON By            PASS NJ    L - STKTUSLA, S/i-    BITEON KS - KEYSWITCH OS - TEST SW-ITCH SPS-O SG- 1 LSHH1             0    1SBTOS "P S/0 LA SHUJTDOWNS RB S

SWITCH TEST SWITCH 100 A C

      ,LKPERU
                    - LEVEL XMITTERTESTPOINTS ELOCXPERMITFROM5.-1 S                          SG-ý2 LSHH              0. Ba           A - B- C "L PERM
                                                                                                         -LEVEL: SMITTEPTEST POINTS
                                                                                                         -1BLOOBPERMITFROMSO-S ORANGE   INSERT- LED NOTUSEO                                                          ORANGE INSERT-LEM NOTUSED
                                   .0 C0 0 041           0
                  ""TS  OE Ll SPS958 NOR                          SPBARE O*S-       12 TEST INPUT   OPEN        0   0  0      SEN- LSEV 0                       TOOENC          0 0 0 0         '"  TEST-LNP'                                 K5-SO-D 'ESS LS.L 0    1I0 ENSABL 0ý 4

130 LTISSPS NOR KELT. iT>FET [!4% (O LBP S] 0j NOTES, I. REFERENCE DRAWING SF-007 SH. I (SECTION 4.1.19.1) INPUT PANEL A2 PROTECTION CHANNEL I FIG 2.2-9 F2. 2-9-1 SD-010, REV.4 B: 12-20-04 DFN-H./SYSDES/S0F2291.DCN/CI

LOGIC CHANNEL LOGIC CHANNEL 3 LC

             ~i- G             CAB I             I KI J3 E121     R4   6. 2K CR7   El L

OUTPUT El I CONTACTS CHANNEL I 2A F7 125VOC RETURN NOTES: I. ALL OUTPUT CONTACTS SHOWN IN SHELF POSITION.

2. OUTPUT CONTACTS ARE NORMALLY CLOSED (OPEN TO TRIP). TYPICAL POWER

3. BOTH CHANNEL OUTPUT CONTACTS NEED TO BE TRIPPED TO DEENEGIZE SOLENOID VALVE COIL. AUCTIONEERED

4. GREEN LEO IS NORMALLY ON (OFF WITH ONE SOLENOID OUTPUT CHANNEL CONTACTS OPEN OR LOSS OF POWER).

FIGURE 2.2-8 F2. 2-8-1 SD-O1O, REV.A DB:12-20-04 0FN=H:/SYS0ES/S0F2281 .00W/C

LCH-2 3A 2

               .3 OUTPUT           B CONTACT A

xI [c] X3[C] LOCAL MOMENTARY TEST BUTTON 4z SOLENOID VALVE POSITION SWITCH SOLENOID VALVE COIL zz LED AT TEST PANEL A5 I( SP7A4"

                        .rSV      I
                               \  I SFF3AA P---A    -

OIODE/RESISTOR NETWORK FOR LEO wo [c]

                                             -j NOTE 3 A

120VAC RETURN _ NOTES: I. ALL CONTACTS SHOWN IN SHELF POSITION. 2, OUTPUT TO TRIPCONTACT IS 'NORMALLY CLOSED (OPEN OR DEENERGIZE SOLENOID). TYPICAL 120 VAC

3. GREEN LED IS NORMALLY ON (OFF WITH CONTACT OPEN OR LOSS OF 120 VAC).

SOLENOID OUTPUT FIGURE 2.2-6 F2..2-6-1 SD-GIG, REV.4 DB:12-20-04 DFN=H,/SYSDES/SDF2261.DGN/C

SET ANO RESET BLOCK TEST SWITCHES AT PANEL A5 NO TES:

1. THIS FIGURE DESCRIBES THE TYPICAL BLOCKING TYPICAL SFRCS FEATURES. FOR TYPICAL SFRCS OUTPUT INFORMATION SEE FIGURE 2.2-I. OUTPUT WITH BLOCK CONTROL FEATURE FIGURE 2.2-3

_______________________________________________________________________________________________ 4 F2. 2-3-1 SD-OIO, REV.1 D8:12-20-04 0FN=H,:/SYSDES/SDF2231.DGN/l

K60

• MANUAL INITIATION CONTACT 48VDC 24 y RETURN RD A3\

28VDC LCH- I RELA Y DRI VER TYPICAL SFRCS LOCATION NOTES: OUTPUT WITH SOLENOID I. OUTPUT RELAY IS ENERGIZED AFTER CS CONTROL/OPEN CONTROL FEATURE SWITCH IS MOMENTARILY DEPRESSED AS LONG AS THE SFRCS IS NOT TRIPPED.

2. YELLOW LEO IS NORMALLY OFF (ON WHEN FIGURE 2.2-2 COMPLIMENTARY CHANNEL IS TRIPPED).

F2. 2-2-I SD-OIO, REVA DB: 12-20-04 DFN=H :/SYSDES/SDF2221 .DGN/C

6 L 6 FAN-OUT - RESISTOR NETWORK 4BVDC is RETURN RD 28VOC RETURN LCH- I LC --- RELAY ORIVER LOCATION NOTES: I. OUTPUT RELAY NORMALLY ENERGIZEO (DE-ENERGIZE TO TRIP). TYPICAL SFRCS

2. YELLOW LED IS NORMALLY OFF (ON WHEN COMPLIMENTARY CHANNEL IS TRIPPED). OUTPUT, WITH MANUAL INITIATION FIGURE 2.2-I F2. 2-1-1 SD-OlO, REV.4 DB:12-20-04 0FN:H:/SYSDES/SDF221 .DGN/C!

SFRCS ACTUATED COMPONENTS 100% POWER NORMAL LINEUP-FIGURE 2.1-16 F2.1-16-1 SD-OO REV.4 08:12-20-04 DFN-H:/SYSDES/SDF21161.DGN

NOTES: THE LOGIC DIAGRAMS IN SD-OO USE THE FOLLOWING CONVENTION: LOGIC "I" TO TRIP I.FOR ADDITIONAL -SYMBOLS REFER TO P&ID M-O01 & M-002 (REF. 7.1.1 & 7.1.2) RD AOM LOGIC LOGIC FIELD RELAY ALARM MODULE MODULE BUFFER DRIVER OUTPUT OUTPUT INPUT MODULE 4A NOT t F AN OUT AND-Gate OR-Gate ON TIME-DELAY J9IIIBB MOMENTARY SFRCS CABNET INTER- LED CONTACT CONNECTING CABLE G. .,green R...red Y. . . yellow I T RELAY RELA MEMORY LED LED COIL CONTAC:T S... SET ON OFF R... RESET (OVERRIDE) INDICATING LIGHT LOGIC SYMBOLS AND LEGEND G... green R... red Y.. .yellow FIGURE 2.1-15 F2. 1-15-1 SD-OO REV. 4 DB: 12-20-04 DFN=H:/SYSDES/SDF21151.DG

NOTE I NOTES: I. SOURCE OF SIGNAL SHOWN ON FIGURE 2.1-I1

2. ON-TIME DELAY SETTINGS: 2.5 HZ+I/-O RC PUMP MONITORING (41.67 - 58.33 msec.) SFRCS LOGIC CHANNEL 4 FIGURE 2.1-14 F2. 1-14-I SD-O1O REV. 4 FN:SDF21141.DGN SD-6I0 REV.

NOTE I NOTES: I. SOURCE OF SIGNAL SHOWN ON FIGURE 2.1-1I

2. ON-TIME DELAY SETTINGS: 2.5 HZ+1/-O ,RC PUMP MONITORING (41.67.- 58.33 msec.) SFRCS LOGIC CHANNEL 3 FIGURE 2.1-13 F2. 1-13-1 SD-010 REV.. 4 DB: 12-20-04 DFN=H:/SYSDES/SDF21131.DC

NOTE I NOTES: I. SOURCE OF SIGNAL SHOWN ON FIGURE 2.1-I1

2. ON-TIME DELAY SETTINGS: 2.5 HZ+I/-O RC PUMP MONITORING (41.67 - 58.33 msec.) SFRCS

                                                       .LOGIC CHANNEL 2 FIGURE   2.1-12 F2. 1-12-1              SD-010    REV. 4 DB:12-20-04 DFN=H:/SYSDES/SDF21121.DG

                             .RC MP0361 PUMP 1-2-1 A

NOTES:

1. SHARED SIGNAL - CONTINUATION SHOWN ON FIGURES 2.1-12, 2.1-13, AND 2.1-14

2. ON-TIME DELAY SETTINGS: 2.5 HZ+I/-O RC PUMP MONITORING (41.67 - 58.33 msec.) SF RCS-LOGIC CHANNEL I FIGURE 2.1-1I F2. I1-ll-1 SD-010 REV. 4 DB:12-20-04 DFN=H:/SYSDES/SDF2I111I.D(

18*-EBD- 12 TO SG-2 FW601 SD-O0O BOUNDARY TRIP DP: TRIP DP: MAIN FEEDWATER LINE-2 DIFFERENTIAL PRESSURE INSTRUMENTATION

                                                /

FIGURE 2.1-10 F2. 1-10-I SD-OO REV. 4 DB:12-17-04 DFN=H:/SYSDES/SDF21101.DGI

18'-EBD-12 TO SG-I FW612 TRIP DP: TRIP DP:'

                                     - -- 4  RS-6    I
               * -~-

z MAIN FEEDWATER LINE-I DIFFERENTIAL PRESSURE INSTRUMENTATION FIGURE 2.1-9 F2. 1-9-1 SD-OO REV. 4 DB:12-17-04 DFN=H:/SYSDES/SDF219I.DG

BLOCK CH. 1:

                  ý38K      3689K        --

I. 36896687G PS I I I 1F BLOCK CH. It PS I I I I I I I I. I I SI II TRIP PI'

                              --I r I         I    FI L]

II TRIP PIt MAIN STEAM LINE-I Tktr~rl PRESSURE I11r Kl? A 7 T/%kI jI N1 I IMUIlrN I A I LIUI

      ------        I FIGURE 2.1-7 F2. 1-7-1                            SD-OIO REV.                       4 DB:12-17-04           DFN=Ht/SYSDES/SDF217I.DGý

TRIP LH: iSD-010 BOUNDARY C5792A

           !i                                                             1F~iO8~

II i 65792A II II LY II SP9A8-2 II I C5792A C579: 2As ISLEE I.U-U +1 TRIP LL: r-" I 2A I C5792A I C579

                                     -r      LY       L .LS~

SPSA9-A

l C5792A LY SPARE ANALOG SP9A9-2 OUTPUT I C5792A I

                   'LSEE SD-051                         NOTES:

1. FOR START-UP LEVEL INSTRUMENTATION LOGIC CHANNELS I & 3 SEE FIGURE 2.1-5 STEAM GENERATOR - 2 START-UP LEVEL INSTRUMENTATION LOGIC CHANNELS 2 & 4 FIGURE 2.1-6 F2. 1-6-1 SD-OIO REV. 4 DB:12-17-04 DFN=H:/SYSDES/SDF216I.DG

C5761A TRIP LH: SD-0IO BOUNDARY LSHH SP9A6 C7571A C5761A LT SPIA6 A S "C5761A C5799 . I C5761A I I

LLJ. TRIP LL:

RSI-0 C5761A I C5761A C5761A I LV SPARE ISOLATED F-ANALOG OUTPUT S C5761A W29 LT SP9A4I

• I s0o .,

_SEE I NOTES:

1. FOR START-UP LEVEL INSTRUMENTATION LOGIC CHANNELS 2 & 4 SEE FIGURE 2.1-6 STEAM GENERATOR - 2 START-UP LEVEL INSTRUMENTATION LOGIC CHANNELS I & 3 FIGURE 2.1-5 F2. 1-5-1 SD-010 REV. A O8:12-17-04 DFN=H:/SYSDES/SDF2151.DGI

TRIP LH: iSD-OIO BOUNDARY C5792A SP9B4B

   .*1 F-I1 C5798 SP9B16-2 S

LY C5792A II II C5792A LI I 1 TRIP LL: F-S C579.2A C5792A C5792A SPARE ISOLATED ANALOG OUTPUT L LYI LII I SP9B4LT SIl SEE SD-051~ NOTES: I. FOR START-UP LEVEL. INSTRUMENTATION LOGIC CHANNELS I & 3 SEE FIGURE 2.1-3 STEAM GENERATOR " I START-UP LEVEL INSTRUMENTAT ION LOGIC CHANNELS 2 & 4 FIGURE 2.1-4 F2. 1-4-I SD-OO REV. 4, DB:12-17-04 DFN=H:/SYSDES/SDF2141,.D

C5761A TRIP LH: SD-010 BOUNDARY LSHH SP9B8 C6761A I C5761A SP9B3B I. C5710 LI C5761A LSEE S - 051 TRIP LL: C5761A S LLL - SP9B9 SPARE ISOLATED ANALOG

                                           \SP ý9B-I       OUTPUT C5761A LI SP9B9 W29
                                      -- 9      I LSEE SD-051            I NOTES :

I. FOR START-UP'LEVEL INSTRUMENTATION LOGIC 'CHANNELS 2 & 4 SEE FIGURE 2.1-4 STEAM GENERATOR - I START-UP LEVEL INSTRUMENTATION LOGIC CHANNELS I & 3 FIGURE 2.1-3 F2. I I SD-OIO REV. 4 OB:12-17-04 DFN=H:/SYSDES/SDF213I.DGý

STEAM-LINEPRESSURE I LOSS oFRER'. I STEM4G4ENERATOR N INVENTORY SI SGI.Il....PRESýSURE LECEND. ANO-GATE I 5-SI OR-GATE PS-36ATA PS-368TE NOT (INVERTER) ON hU1GDELAY INPUT CONTACT (A .. POWERED BY CO4PILIRENTARY CHANNEL) SIGNALSTRETCHER Z-OUTOaF-4 LOGIC -n

ýj

1. THE LOGIC SHOWN IS TYPICALFOR ALL POURLOGIC CHANNELS.

2. THE INPUTS REFLECTLOGICCHANNEL-2

3. THE OUTPUTSDGESCRIBES PROTECTION CXANEL-2

4. ALL INPUTS ARE SHARED-NOT SHOWN-BYLOGIC CHANNELS 2 & 4.

5. THE OUTPUTAND-GATES REOUIREA TRIP CONDITIONFRONLOGIC CHANNEL 4

                                                                                                    .S-IO0                              TO TRIP.

FW-601 5.FOR DETAILEDLOGIC DIAGRAN SEE RAG FW-TIN E-IN (REFERENCE7.1.10) F-SP TA OEN FELD I SI MS-100-i, MS-375, MS-603. _8722 LINES TO A*PT-2 L HF 38lt SO O . S-I F2. 1-2-1 SD-10 REV. 4 0B:12-17-04 DFN=H:/SYSDES/S0F2121.DGN

I STEAM-LINE PRESSURE STEAMGENERATORINVENTORY S/I 1 FF. PRESSURE LEGEND:

                                                   .L-SPg8A   LSLL-SP9O9                  LSHH-SP980 LSHH-SPS89               POS-2686A       PUS-2666B                                              AND-GATE e-    SGI.L                                      OR -GATE SG-' t 1S"I

• so" G G SG' R A-GATE A LOW LSLL-SPSA6 LSLL-SPAIr HIGH HIGH LSTH-SPSA6 LSHH-SP9AT HIGH HIGH PDS-2685C PDS-2685D 101 (INVERTERI SG-2 0- SG- SG-2
• SG-2 S.-2 ,4.. SG-Z LOW LOW HIGH HIGH HI TIME DELAY INPUT CONTACT I- . . POWEREC

                                                                                                                                                                        *  "    -         L        BY COMPLIMENTARY    CHANNEL)

INPUT AND-OATE BLOCK - ITYPICAL) SIGNAL STRETCHER (SHUTDOWN BYHPASS)I E..A 3 2 1 2ll0-OUT-F0-4 LOGIC I/2 SEC. M M 2 SEC. (TYPICAL) NOTESI h THE LOGIC SHOWH IS TYPICAL FOR ALL L.. EHI FOUR LOGIC CHANNELS.

2. THE INPUTS REFLECT LOGIC CHANNEL-I 44.OUTPUT AND-GATE THE OUTPUTS DESCRIBES PROTECTION 4 - UTUTHA-GTECHANNEL -I; ITYPICAL) 4. ALL INPUTS ARE SHARED -NOT SHOWN-By LOGIC CHANNELS OPEN. I & 3.

C5S SOI . TRIP THE OUTPUT AND-OTES EAR CONOITION FROM LOGIC CHANNEL

                                                    -   D1 M ADML         IHM-5889A                                      STIMLINE ISO VALV NS-I1I                                           TO TRIP.

fWA STOP VALVE FW-612 6. FOR DETAILED LOGIC DIAGRAMSEE OWC W W ISO VALVE FP-TO E-1B (REFERENCE 7.I.O) r CLOSE OP'EN SG-1 STEAM& AFI Fh MS-I06 IFSRO 13 TRIP WAINTURBINE PFW SU CONTROLVALVE FW-SPHB THN& FW ISO VLV'S HS-101-", MS-34. NOS-N1l.ICSIIB LINES TO WTPT-I AF-3TO - HSEALO NO-SIMPLIFIED SFRCS APP-I MFwCONTROLVALVE FW-SP6A LOGIC DIAGRAM W SU CONTROLVALVE PW-SPTA PROTECTION CHA1NNEL I FIGURE 2.1-I F2.1-I-1 SD-010. REV. 4 DB:12-17-04 OFN=H:/SYSDES/SDF2ll .DGN

_-SD-OlO BOUNDRY INPUT I NSTRUMENTATION OPERATOR MCB INTERFACE I MS SG MF/SG RCP SG SU MANUAL MANUAL MANUAL MANUAL I LOW START-UP PRESS MONITOR LEVEL INITIATION INITIATION SHUTDOWN OUTPUT I PRESS LEVEL DIFF STATUS INDICATION W/O ISO W/ ISO BYPASS BLOCKS

   '1                                                                    __ _ _ _ _ _

STEAMAND FEEDWATER LINE RUPTUREi

       -                                         CONTROL      SYSTEM         -     SFRCS        -
           -"                     I SD-O11A         N/A           SD-032A        SD-044        SD-013        sD-o04      SD-015       SD-012A     SD-014 SP     STEAM GENERATOR MF     MAIN FEEDWATER COOLAST PSMP                                                    GNPREAOTOR                            SYSTE PRSOIs PRSuRMNsOLATIONSTA                                             TR IP   ISI[MPL                                  I F IED SF RC S SIFF DIFFERENTIAL      NOTES/                                   SD-04                                     BLOCK        D-IAGRAM RCP1.-1 REACTO COOLAN       PUOPTEACTO START-UP             1R               BOUNDARP OTESIZED SON LISTISC REFER TO GAALE REFERENCES TO DRAWINGS WITH DETAILED BOUNDARIES WHERE APPLICABLE..

Figure 1. -1 F. - I SD-010, REV.4 DFN=H:/SYSDES/SDFIIII.DGN DB 12-17-04

TABLE 3.3-1 SFRCS SETPOINTS (Cont'd)

References:

(cont.) (4.6.29) B&W, Doc. No. 36-3333000001-00, Balance of Plant Criteria for Reactor Coolant Pump Monitors. (4.6.30) B&W letter to Bechtel, BWB-297, RCP Motors (Locked Rotor Current at 80% Voltage), dated 05/13/71. (4.6.31) Test Data from Westinghouse for B&W, General Order No. RO-39700-P, VSS Induction Motor (Loss of Motor Load at 80% Voltage), dated 02/26/73. [4] (4.4.2) Technical Specification, Section 3/4.3. [5] (4.1.33) Dwg M-7201, Instrument Index. [6] (4.5.40) EXT-89-07631, Bechtel Calculation Sheet,

Title:

, Tech. Spec. Allowable Values for Surveillance Tests,

Subject:

SFAS and SFRCS, by M. David, dated 04/04/77. [7] (4.5.43) Calculation No. C-ICE-083.03-004, Setpoint Determination for SFRCS'SG High AP Pressure Switches. T3.3-1-3 SD-010 Rev. 4

TABLE 3.3-1 SFRCS SETPOINTS (Cont'd)

References:

[1] (4.5.35) Calculation No. C-IC-83.03-001, Lowering SteamGenerator Low and High Level Setpoints. (4.8.20) FCR 85-0157 Rev. A Supp 03, High Level Steam Generator Setpoint for SG A is to be Raised from 215' to 225". (4.5.36) B&W letter to TE, SGBM-87-1687, Task 836 - Determination of SFRCS Startup Range High Steam Generator dP Setpoint, dated 12/08/87. (4.8.23) Function of high level trip and setpoint revised by MOD 98-0046. (4.5.42) Letter to the NRC, Serial No. 2194, dated 12-16-93 concerning commitments for an SFRCS High SG Level Trip. [2] (4.5.37) B&W letter to TE, TED 87-0033, Task 520 - Transmittal of 600 GPM Auxiliary Feedwater Case, dated 02/02/87. [3] (4.5.34) Bechtel Calculation No. EC128H Rev. 00, Reactor Coolant Pump Monitor Setting, dated 02/04/77. (4.5.41) Calculation No. C-ICE-058.01-001, RCPM Monitor.Setpoint for Loss of a Reactor Coolant Pump. T3 .3-1-2 SD-010 Rev. 4

TABLE 3.3-1 SFRCS SETPOINTS Safety Tech. Spec. Instrument Setpoint Limit Value [4] Setpoint [5] Description Note 4 750 psig 720 psig Block Permission Setpoint Note 4 800 psig 775 psig Block Reset Setpoint Note 3 591.6 psig [6] 620 psig Steam Line Pressure Low Note 6 197.6 psid .125 psid [7] MFW/SG High Diff. Pressure Note 8*) [1] N/A Note 5 2201*) [1] Steam Generator Level High 10" ' [2] 16.4 " 18.4 " [1] Steam Generator Level Low 17.66 " *) 22.14 " *) 23.5 " 1560 A [3] 1384.6 A 513.7 A [3] RCP current, high (Note 7) 91 A [3] 106.5 A 197.9 A [3] RCP current, low (Note 7) N/A ' N/A N/A. Manual Initiaion Notes:

1. [ ] ... Reference listed below..

2. *) ... the steam generator values are "lactuall, level values referenced to the top of the;lower tube sheet, except those flagged with *). Those flagged values are "indicated" water level values at a reference point of 1065 psia and 552'F.

3. The analysis value for the steam line low pressure setpoint for typical B&W Plants is 600 psia. See MOD 87-1005 (Reference 4.8.22), calculation C-ICE-083.03-003 for documentation on these setpoints.

4. See SCR 91-5003 (Reference 4.8.21) and LAR 90-46 (Reference 4.4.16) for documentation on these setpoints.

5, The steam generator high level SFRCS trips do not provide a USAR required safety function. Therefore no Tech. Spec. limits are applicable. However Reference 4.5.42 discusses commitments to the NRC to test this trip function and to bring any failures of this function to the attention of senior plant management. 6, The safety limit for the reverse main feedwater/steam generator high trip setpoint is 200 psid. See Reference 4.6.33.

7. All values shown are "primary" Amperes in phase B for the power feed to the RC motors. The equivalent high and low setpoint values for trip bistables are 4.28 V and 1.65 V, respectively. See Reference 4.5.34.

8, The ICS high level limiter and procedural guidance provides protection against long term flooding of the aspirator ports. The setpoint in MOD 98-0046 is to prevent moisture carryover into the main steam lines. T3.3-1-1 SD-010 Rev. 4

TABLE 2.9-7 SFRCS TRIP SIGNALS TO ARTS Equipment Device Description SFRCS SFRCS Reference No. Mode Output Drawing Protection Channel 1 N/A ARTS PROTECTION CH.1 Trip RS-5211A E-65B SH.10 N/A ARTS PROTECTION CH.3 Trip RS-5213A E-65B SH.10 Protection Channel 2 N/A ARTS PROTECTION CH.2 Trip RS-5222A E-65B SH.10 N/A ARTS PROTECTION CH.4 Trip RS-5224A E-65B SH.10 T2 .. 9-7-1 SD-010 Rev. 4

TABLE 2.9-6 SFRCS TRIP SIGNALS TO TURBINE TRIP SYSTEM Equipment Device Description SFRCS SFRCS Reference No. Mode Output Drawing Protection Channel 1 N/A MAIN TURBINE TRIP A Trip RS-53AA E-42B SH.53 Protection Channel 2 N/A MAIN TURBINE TRIP B Trip RS-53BA E-42B SH.53 T2.9-6-1 SD-010 Rev. 4

TABLE 2.9-5 SFRCS ACTUATED VALVES OF THE MAIN STEAM SYSTEM Equipment Device Description SFRCS SFRCS Reference No. Mode Output Drawing Protection Channel 1 MS-106 AFPT-1 MN STM-1 IN ISO VLV Close RS-111A E-46B SH.54A/B MS-106 AFPT-1 MN STM-1 IN ISO VLV Open RS-311A E-46B SH.54A/B. MS-106A AFPT-l MN STM-2 IN ISO VLV Close RS-411A E-46B SH.46A/B MS-106A AFPT-1 MN STM-2 IN ISO VLV Open RS-211A E-46B SH.46A/B MS-5889A AFPT-l MN STM IN ISO VLV Open RS-511A E-46B SH.71 MS-101-1 MN STM LINE-1 WU ISO VLV Close RS-611A E-46B SH.32A MS-394 MN STM LINE-1 WU DRN ISO V Close RS-611B E-46B SH.3 MS-611 SG-l DRAIN STOP VLV Close RS-611C E-46B SH.33/A ICSIIB SG-1 ATM VENT VLV Close RS-611D E-46B SH.78A/B MS-101 MN STM LINE-1 ISO VLV Close RS-621A E-46B SH.IA/D MS-100 MN STM LINE-2 ISO VLV Close RS-631A E-46B SH.iE/F Protection Channel 2 MS-107 AFPT-2 MN STM-2 IN ISO VLV Close RS-112A E-46B SH.4A/B MS-107 AFPT-2 MN STM-2 IN ISO VLV Open RS-312A E-46B SH.4A/B MS-107A AFPT-2 MN STM-I IN ISO VLV Close RS-412A E-46B SH.46A/B MS-107A AFPT-2 MN STM-I IN ISO VLV Open RS-212A E-46B SH.46A/B MS-5889B AFPT-2 MN STM IN ISO VLV Open RS-512A E-46B SH.71 MS-100-1 MN STM LINE-2 WU ISO VLV Close RS-612A E-46B SH.32A MS-375 MN STM LINE-2 WU DRN ISO V Close RS-612B E-46B SH.3 MS-603 SG-2 DRAIN STOP VLV Close RS-612C E-46B SH.33/A ICS11A SG-2 ATM VENT VLV Close RS-612D E-46B SH.79A/B MS-100 MN STM LINE-2 ISO VLV Close RS-622A E-46B SH.l A/D MS-101 MN STM LINE-1 ISO VLV Close RS-632A E-46B SH.l E/F T2.9-5-I SD-010 Rev. 4

TABLE 2.9-4 SFRCS ACTUATED VALVES OF THE SECONDARY PLANT SYSTEM Equipment Device Description SFRCS SFRCS Reference No. Mode Output Drawing Protection Channel 1 FW-612 MN FW-1 STOP VLV Close RS-611E E-44B SH.4A/B FW-780 SG-1 MN.FW ISO VLV Close RS-64AA E-44B SH.5 FW-SP7B MN FW-I SU CTRL VLV Close RS-64AB E-44B SH.21B/C FW-SP6A MN FW-2 CONTROL VLV Close RS-65AA E-44B SH.9 FW-SP7A: MN FW-2 SU CTRL VLV Close RS-65AB E-44B SH.21B/C Protection Channel 2 FW-601 MN FW-2 STOP VLV Close RS-612E E-44B SH. 4A/B FW-779 SG-2 MN FW ISO VLV Close RS-64BA E-44B SH. 5 FW-SP7A MN FW-2 SU CTRL VLV Close RS-64BB E-44B SH.21A/D FW-SP6B MN FW-1 CONTROL VLV Close RS-65BA E-44B SH. 9 FW-SP7B MN FW-1 SU CTRL VLV. Close RS-G5BB E-44B SH. 21A/D T2.9-4-1 SD-010 Rev. 4

TABLE 2.9-3 SFRCS ACTUATED VALVES OF THE AUXILIARY FEEDWATER SYSTEM Equipment Device Description SFRCS SFRCS Reference No. Mode Output Drawing Protection Channel 1 AF-3870 AFP-1 DISCH TO SG-1 VLV Close RS-111B E-44B SH.20 AF-3870 AFP-1 DISCH TO SG-1 VLV Open RS7311B E-44B SH.20 AF-3869 AFP-1 DISCH TO SG-2 VLV Close RS-111C E-44B SH.14A/B AF-3869 AFP-1 DISCH TO SG-2 VLV -Open RS-311C E-44B SH.14A/B

                         .Protection       Channel 2 AF-3872   AFP-2  DISCH TO  SG-2      VLV,    Close    RS-112B E-44B SH.15 AF-3872   AFP-2  DISCH TO  SG-2      VLV     Open     RS-312B E-44Bl SH.15 AF-3871   AFP-2  DISCH TO  SG-1      VLV     Close    RS-112C E-44B SH.14A/B AF-3871   AFP-2  DISCH TO  SG-1      VLV     Open     RS-312C E-44B SH. 14A/B T2.9-3-1                      SD-010 Rev. 4

TABLE 2.9-2 SFRCS MANUAL SWITCH LISTING (Cont'd) Definition: Block...... Switch contains one' (1) momentary pushbutton to override the SFRCS trip signal without changing the state of the valve; the block function resets automatically with absence of SFRCS trip signal. Control.... Switch contains two (2.) momentary pushbuttons for the "Open" and !'Close" function. With the SFRCS trip signal present the function opposite to SFRCS function is impaired. Reset ...... Switch contains one (1) momentary pushbutton to energize and seal-in SFRCS output relay to energize associated solenoid coils. This function is impaired with the SFRCS trip signal present. Trip...... Switch contains one (1) momentary pushbutton to manually actuate an array of equipment. This function is impaired with the SFRCS trip signal present.. S/D Block.. switch contains one (1) momentary pushbutton to manually block the steam line low pressure trip and the steam generator high level trip. *This function is enabled only when the steam line pressure is below the permissive setpoint. T2.9-2-3 SD-010 Rev. 4

TABLE 2.9-2 SFRCS MANUAL SWITCH LISTING (Cont'd) Protection Channel 2 . Manual Panel- Switch Actuated/Controlled Equipment SFRCS Switch No. Location Function ",,Description Function HIS-3872B C5709 BLOCK AFP-2 DISCH TO SG-2 VLV AF-3872 Close/Open HIS-3871B C5709 BLOCK AFP-2 DISCH TO SG-l VLV AF-3871 Close/Open HIS-601A C5708 BLOCK MN FW-2 STOP VLV FW-601 -Close HIS-SP7DB C5712 RESET MN FW-2 SU CTRL.VLV FW-SP7A Close HIS-SP7DB C5712 BLOCK MN FW-2 SU CTRL VLV FW-SP7A Close HS -SP6B C5792N RESET MN FW-1 CONTROL VLV FW-SP6B Close HIS-SP7CB C5712 RESET MN.FW-I SU CTRL VLV FW-SP7B Close HIS-SP7CB C5712 BLOCK MN FW-I SU CTRL VLV FW-SP7B- Close HIS- 107AB C5709 BLOCK AFPT MN STM-2 IN ISO VLV MS-10-7 Clbse/Open HIS-107EB C5709 BLOCK 'AFPT-2 MN STM-I IN ISO VLV MS-107A Close/Open HIS-5889B* C5709 CONTROL AFPT-2 MN STM IN ISO VLV MS-5889B. Open, HIS-100-I* C5708 CONTROL MN'STM LINE-2 WU ISO VLV MS-100-1 Close HIS-375* C5708 CONTROL MN STM LINE-2 WU DRN ISO VLV MS-375 Close HIS-603B C5710 BLOCK SG-2 DRAIN STOP VLV MS-603 Close HIS*ICS11A* C5708 CONTROL SG-2 ATM VENT VLV ICS11A -Close HIS-ICS11C C5708 BLOCK SG-2 ATM VENT VLV ICSI1A Close HIS-100* C5708 CONTROL MN STM LINE-2 -ISO VLV MS-100 Close HS -101 C5792N RESET MN STM LINE-1 ISO VLV MSI01 , Close HIS-6402 C5707 TRIP MANUAL AFW-2 INITIATION W/O SG ISO ' Trip HIS-6404 C5707 TRIP MANUAL AFW-2 INITIATION WITH SG-2 ISO Trip HIS-100B C5721 S/D BLOCK SHUTDOWN BLOCK LOGIC CHANNEL12 Block HIS-100C. C5721 S/D BLOCK SHUTDOWN BLOCK LOGIC CHANNEL 4, - -Block Notes':

1. For definition of the switch functions: BLOCK, CONTROL, ',RESET and TRIP refer to page 3 of this table.

2. The indicating lights of manual switches flagged~with an asterisk (*)

are controlled by their valve limit or position switch. The power supply to these indicating lights is being provided by the center console power distribution. These lights and circuits are outside the SFRCS boundary. T2.9-2-2 SD-010 Rev. 4

TABLE 2.9-2 SFRCS MANUAL SWITCH LISTING Protection Channel 1 Manual* Panel Switch Actuated/Controlled Equipment SFRCS Switch No. Location Function Description Function HIS-3870B C5706 BLOCK AFP-1 DISCH TO SG71 VLV AF-3870 Close/Open HIS-3869B C5706 BLOCK AFP-I DISCH TO SG-2 VLV AF-3869 Close/Open HIS-612A C5708 BLOCK MN FW-I STOP VLV FW-612 Close HIS-SP7AB C5712 RESET MN FW-1 SU CTRL VLV FW-SP7B Close HIS-SP7AB C5712 BLOCK MN FW-l SU CTRL VLV FW-SP7B Close HS -SP6A C5762N RESET MN FW-2 CONTROL VLV FW-SP6A Close HIS-SP7BB C5712 RESET MN FW-2 SU CTRL VLV FW-SP7A Close HIS7SP7BB C5712 BLOCK MN FW-2 SU CTRL VLV FW-SP7A Close HIS-106AB C5706 BLOCK AFPT-1 MN STM-1 IN ISO VLV MS-106 Close/Open HIS-106EB C5706 BLOCK AFPT-1 MN STM-2 IN ISO VLV MS-106A Close/Open HIS-5889A* C5706 CONTROL" AFPT-1 MN STM IN ISO VLV MS-5889A Open HIS-101-1* C5708 CONTROL MN STM LINE-1 WU ISO VLVMS-101-1. Close HIS-394* C5708 CONTROL MN STM LINE-1 WU DRN ISO V MS-394 Close HIS-611B C5708 BLOCK, SG-1 DRAIN STOP VLV MS-611 Close HIS-ICS11B* C5708 CONTROL SG-1 ATM VENT VLV ICS11B Close HIS-ICS11D C5708 BLOCK SG-I ATM VENT VLV ICS11B Close HIS-101* C5708 CONTROL MN STM. LINE-1 ISO VLV MS-101 Close

• HS -100 C5762N RESET MN STM'LINE-2 ISOVLV MS-100 Close HIS-6401 C5707 TRIP' MANUAL AFW-l INITIATION W/O SG ISO Trip HIS-6403 C5707 TRIP MANUAL AFW-1.INITIATION WITH SG-1 ISO Trip HIS-101B C5721 S/D BLOCK: SHUTDOWN BLOCK LOGIC CHANNEL 1 Block HIS-101C C5721 S/D BLOCK SHUTDOWN:BLOCK LOGIC CHANNEL 3 Block Notes:'

1. For definition of the switch functions: BLOCK, CONTROL, RESET and TRIP refer to page 3 of this table.

2. The indicating lights of manual switches flagged with an asterisk (*).. are controlled by their valve limit or position switch. The power supply to these indicating lights is being provided by the center console power distribution. These lights and circuits are outside the SFRCS boundary.

T2.9-2-1 SD-010 Rev. 4

TABLE 2.9-1 DIGITAL OUTPUTS TO ANNUNCIATOR AND COMPUTER Alarm Protection Annunciator ID # System Status Channel Panel Location P424 - SFRCS SG 2 HIGH REVERSE DP CH 4 2 N/A *.) P425 - SFRCS SG 1 HIGH REVERSE DP CH 4 2 N/A *) Q201 - SFRCS LOSS OF FOUR RCP'S CH ,1 1 N/A') Q203 - SFRCS LOSS OF FOUR RCPIS CH 2 2 N/A *) SFRCS LOSS OF FOUR RCP'S CH 3 1 N/A.*)" Q205 - 2 Q207 SFRCS LOSS OF FOUR RCP'S CH 4 N/A *) To Computer Only T2.9-1-3 SD-010 Rev. 4

TABLE 2.9-1

                  'DIGITAL OUTPUTS TO ANNUNCIATOR AND COMPUTER Alarm                                           Protection'      Annunciator-ID ,#         System Status                      Channel        Panel Location L418  -  SFRCS SG 1 LOW. LEVEL CH 3                      1             N/A *)

L419 - SFRCS SG 2 LOW LEVEL CH 3 1 N/A *) L420 - SFRCS SG 1 HIGH LEVEL CH 3 1 N/A *) L421 - SFRCS SG 2 HIGH LEVEL CH 3 1 N/A *) L422 - SFRCS SG 1 LOW LEVEL CH 4 2 N/A *) L423 - SFRCS SG 2 LOW LEVEL CH 4 2 N/A *) L424 - SFRCS SG 1 HIGH LEVEL CH 4 2 N/A *) L425 - SFRCS SG 2 HIGH LEVEL CH 4 2 N/A *) P410 - SFRCS SG' 1 LOW PRESS CH 1 Ni N/A *) P411 - SFRCS SG 2 LOW PRESS CH 1. 1 N/A *) P412 - SFRCS SG 1 HIGH REVERSE DP CH 1 1 N/A *) P413 - SFRCS SG 2 HIGH REVERSE DP CH 1 1 N/A *) P414 - SFRCS SG 2 LOW PRESS CH 2 2 N/A *) P415 - SFRCS SG 1 LOW PRESS CH 2 2 N/A *) P416 - SFRCS SG 2 HIGH REVERSE DP CH 2 2 N/A *) P417 - SFRCS SG 1 HIGH REVERSE DP CH 2 2 N/A *) P418 - SFRCS SG 1 LOW PRESS CH 3 1 N/A *) P419 - SFRCS SG 2 LOW PRESS CH 3 1 N/A *) P420 - SFRCS SG 1 HIGH REVERSE DP CH 3 1 N/A *) P421 - SFRCS SG 2 HIGH REVERSE DP-CH 3 1 N/A *) P422 - SFRCS SG 2 LOW PRESS CH 4 2 N/A *) P423,- SFRCS SG 1 LOW PRESS CH 4 2 N/A *) T2.9-1-2 SD-010 Rev. 4

TABLE 2.9-1 DIGITAL OUTPUTS TO ANNUNCIATOR AND COMPUTER Alarm Protection Annunciator ID # System Status Channel Panel Location P685 - SFR CS LO PRESS/HI LVL BLK, SG1 1 12-4-C P684 - SFR CS LO PRESS/HI LVL.BLK, SG2 2 12-4-D Q693 - SFR CS LO PRESS/HI LVL TRIP, SG1 1 12-5-C Q692 - SFR CS LO PRESS/HI LVL TRIP, SG2 2 12-5-D P681 - SG 1 LO PRESS TRIP 1, 2 12-1-C P680 - SG 2 LO PRESS TRIP 2 12-1-D L886 - CH 1 LO LVL OR NO RCPS TRIP 1 12-3-C L896 - CH 2 LO LVL OR NO RCPS TRIP 2 12-3-D P671 - SFRCS HI LVL/DP, CH 1 1 12-2-C P672 - SFRCS HI LVL/DP, CH 2 2 12-2-D Q963 - SFRCS ACTUATED 1, 2 8-6-A Q964 - SFRCS TRBL I, 2 12-6-D Z840 - SFAS,,RPS, ARTS, OR SFRCS DOOR OPEN 1, 2 5-5-F X044 - T-G MN STM & FW TURB TRIP 1, 2 N/A *) L410 - SFRCS SG 1 LOW LEVEL CH 1 1 N/A *) L411 - SFRCS SG 2 LOW LEVEL CH 1 1 N/A *) L412 - SFRCS SG 1 HIGH LEVEL CH 1 1 N/A *) L413 - SFRCS SG 2 HIGH LEVEL CH 1 1 N/A *) L414 - SFRCS SG 1 LOW LEVEL CH 2 2 N/A *) L415 - SFRCS SG 2 LOW LEVEL CH 2 2 N/A *) L416 - SFRCS SG 1 HIGH LEVEL CH 2 2 N/A *) L417 - SFRCS SG 2 HIGH LEVEL CH 2 2 N/A *) T2.9-1-1 SD-010 Rev. 4

TABLE 2.7-3 VALVE LIST WITH LOSS OF POWER OVERRIDE INTERLOCKS Valve Description Function Remark Loss of Power of SFRCS Protection Channel 1 AF-3870 AFP-l DISCH TO SG-I VLV Open (overriding Close) AF-3869 AFP-1 DISCH TO SG-2 VLV Close (Overriding Open) MS-.06 AFPT-l MN STM-1 IN ISO VLV Open (Overriding-Close) MS-106A AFPT-I MN STM-2 IN ISO. VLV Open (Overriding Close) Loss of Power of SFRCS Protection Channel 2 AF-3872 AFP-2 DISCH TO SG-2 VLV Open (Overriding Close) AF-3871 AFP-2 DISCH TO SG -1 VLV Close (Overriding Open) MS-107 AFPT-2 MN STM-2 IN ISO VLV Open (Overriding Close) MS-107A AFPT-2 MN STM-I IN ISO VLV Open (Overriding Close) T2.7-3-1 SD-010 Rev. 4

TABLE 2.7-2 NON-ESSENTIAL SOLENOID VALVE LIST Valve No. Description Function Note Protection Channel 1 FW-SP7B FW-1 SU CTRL VLV' Close D FW-SP7A FW- 2 SU CTRL VLV Close D FW-SP6A FW -2 CONTROLVLV Close D Protection Channel 2 FW-SP7B FW- 1 SU CTRL VLV Close D FW-SP7A FW- 2 SU CTRL VLV Close D FW-SP6B FW- 1 CONTROL VLV Close D Note D ... Dual Solenoids pneumatically AND-gated each with a Power Sources. T2 . 7-2-1 SD-010 Rev. 4

TABLE 2.7-1 ESSENTIAL SOLENOID VALVE LISTING Valve No. Description Function Note Protection Channel 1 MS-5889A AFPT-l MN STM IN ISO VLV Open A MS-101-1 MN STM LINE-1 WU ISO VLV Close A MS-394 MN STM LINE-1 WU DRN ISO V Close A ICSl1B1/2 SG-1 ATM VENT VLV Close A MS-101 MN STM LINE-1 ISO VLV Close D MS-100 MN STM LINE-2 ISO VLV Close D Protection Channel 2 MS-5889B AFPT-2 MN STM IN ISO VLV Open A MS-100-1 MN STM LINE-2 WU ISO VLV Close A MS-375 MN STM LINE-2 WU DRN ISO V Close A ICS 1AI/2 SG-2 ATM VENT VLV Close A MS-100 MN STM LINE-2 ISO VLV Close D MS-101 MN STM LINE-1 ISO VLV Close D Note A ... Single or Dual Solenoid with auctioneered Power Source. D ... Dual Solenoids pneumatically AND-gated each with a Power Source. T2.7-1-1 SD-010 Rev. 4

TABLE 2.3-4 ALARM OUTPUT MODULE OUTPUT LISTING (Cont'd) TABLE C TABLE D T152 T154 PS-3687K PS-3687M PS-3687L PS-3687N PS-3687E or T034 PS-3687A or T032 PS-3687G or T044 PS-3687C or T042 LSLL-SP9B7 or T094 LSLL-SP9B6 or T092 LSLL-SP9A9 or T104 LSLL-SP9A8 or T102 RCPM-4 or T114 RCPM-2 or T112 LSHH-SP8B7 or T074 LSHH-SP8B6 or T072 LSHH-SP9A9 or T084 LSHH-SP9A8 or T082 PDS-2685B or T054 PDS-2685A or T052 PDS-2686D or T064 PDS-2686C or T062 PDS-2685A or T052 PDS-2685B or T054 PDS-2686C or T062 PDS-2686D or T064 LOSS OF OSCILLATOR-2 LOSS OF OSCILLATOR-4 PS-3687A or T032 PS-3687E or T034 PS-3687C or T042 PS-3687G or T044 LSLL-SP9B6 or T092 LSLL-SP9B7 or T094 LSLL-SP9A8 or T102 LSLL-SP9A9 or T104 RCPM-2 or T112 RCPM-4 or T114 LSHH-SP9B6 or T072 LSHH-SP9B7 or T074 LSHH-SP9A8 or T082 LSHH-SP9A9 or T084 T2.3-4-4 SD-010 Rev. 4'

TABLE 2.3-4 ALARM OUTPUT MODULE OUTPUT LISTING (Cont'd) The following tables list all variables or test switches which are connected to the reference points on the AOM's, any single item will cause to alarm. TABLE A TABLE B TI51 T153 PS-3689K PS-3689M PS-3689L PS-3689N PS-3689F or T033 PS-3689B or T031 PS-3689H or T043 PS-3689D or T041 LSLL-SP9B9 or T093 LSLL-SP9B8 or T091 LSLL-SP9A7 or T103 LSLL-SP9A6 or TI01 RCPM-3 or T113 RCPM-I or Till LSHH-SP8B9 or* T073 LSHH-SP8B8 or T071 LSHH-SP9A7 or T083 LSHH-SP9A6 or T081 PDS-2686B or T053 PDS-2686A or T051 PDS-2685D or T063 PDS-2685C or T061 PDS-2686A or T051 PDS-2686B or T053 PDS-2685C or T061 PDS-2685D or T063 LOSS OF OSCILLATOR-I LOSS OF OSCILLATOR-3 PS-3689B or T031 PS-3689F or T033 PS-3689D or T041 PS-3689H or T043 LSLL-SP9B8 or T091 LSLL-SP9B9 or T093 LSLL-SP9A6 or TI01 LSLL-SP9A7 ok T103 RCPM-I or Till RCPM-3 or TI13 LSHH-SP9B8 or T071 LSHH-SP9B9 or T073 LSHH-SP9A6 or T081 LSHH-SP9A7 or T083 T2.3-4-3 SD-010 Rev. 4

TABLE 2.3-4 ALARM OUTPUT MODULE OUTPUT LISTING (Cont 'd) Protection Channel 2 AOM Circuit Logic Logic Alarm Location No. Channel 2 Channel 4 ID # A4 - A2/AI5 1 PS-3687A PS-3687E Q964 2 PS-3687C PS-3 G687G Q964 3 LSLL-SP9B6 LSLL-SP9B7 Q964 4 LSLL-SP9A8 LSLL-SP9A9 Q964 RCPM-2 RCPM-4 Q964 6 LSHH-SP9B6 LSHH-SP9B7 Q964 7 LSHH-SP9A8 LSHH-SP9A9 Q964 8 Spare Spare 9 Spare Spare

    +             10         PS-,3687K/L                 PS-3687M/N           Q962 A4 - A3/AI4        1         SPS-3687K/L                  PS-3687M/N           P684 2          PSr3687A/E                  PS-3687E/A           P680 3          PS-,3687C/G                 PS-3687G/C           P681 4         LSLL-SP9B6/7 or              LSLL-SP9B6/7 or LSLL-SP9A8/9'                LSLL-SP9A9/8         L896 5         RCPM 4/2                     RCPM 2/4             L896 6

• LSHH-SP9B6/7 or LSHH-SP9B7/6 or LSHH-SP9A8/9 LSHH-SP9A9/8 P672 7 PDS-2585A/B. or PDS-2585B/A or PDS-2586C/D PDS-2586D/c P672 8 AUTO-2 or MAN-2 AUTO-4 or MAN-4 Q963 9 SEE TABLE C SEE TABLE D Q964 10 NOTE 1 NOTE'1 Q964 NOTE 1. This alarm input point monitors the following parameter withini.ts logic channel:

o Keyswitch in BYPASS, o Module removed, o Loss of 28 Vdc or 48 Vdc power. NOTE 2. For TABLE C or TABLE D see~sheet 3. T2.3-4-2 SD-010 Rev. 4

TABLE 2.3-4 ALARM OUTPUT MODULE OUTPUT LISTING Protection Channel 1 AOM Circuit Logic Logic' Alarm Location .No. Channel 1 .Channel 3 ID # A4 - A2/A15 1 PS-3689B PS-3689F Q964 2 PS-3689D PS-3689H Q964 3 LSLL-SP9B8 LSLL-SP9B9 Q964 4 LSLL-SP9A6 *LSLL-SP9A7 Q964 S RCPM 1 kCPM 3 Q964 6 LSHH-SP9B8 LSHH-SP9B9 Q964 7 LSHH-SP9A6 LSHH-SP9A7* Q964 8 Spare Spare

9. Spare Spare A 10 PS-3689K/L PS-3689M/N Q963 I.

1 PS-3689K/L PS-3689M/N P685 2 PS-3689B/F PS-3689F/B P681 3 PS-3689D/H PS-3689H/D P680 4 LSLL-SP9B8/9 or LSLL-SP9B9/8 or L886

    +

LSLL-SP9A6/7 LSLL-SP9A7/6 5 RCPM 3/i RCPM 1/3 L886 6 LSHH-SP9B8/9 or LSHH-SP9B9/8 or LSHH-SP9A6/7 LSHh-SP9A7/6 P671 7 PDS-2586A/B or PDS-2586B/A or PDS-2585C/D PDS-2585D/C P671 8 AUTO-1 or MAN-i AUTO-3 or MAN-3 Q963 9 SEE TABLE A SEE TABLE B Q964 10 NOTE 1 NOTE 1 Q964 NOTE 1. This alarm input point monitors the following parameter within its logic chann ei: 0 Keyswitch in BYPASS, 0 Module removed, 0 Loss of 28 Vdc or 48 Vdc power. NOTE 2. For TABLE A or TABLE B see sheet 3. T2.3-4-1 SD-060 Rev. 4

TABLE 2.3-3 RELAY DRIVER MODULE OUTPUT LISTING (Cohnt'd) RDM Circuit Protection Protection Action Location No. Channel. 1 Channel 2 A3 - A5/A12 1 MS-106 MS-107. BLOCK 2 AF-3870 AF-3872 BLOCK 3 AF-386&9 AF-3871 BLOCK 4 MS-106A MS-107A BLOCK 5 MS-611 MS-603 BLOCK 6 ICS-liB ICS-1IA BLOCK 7 FW-612 FW-601 BLOCK M 8 SV-SP7B5,ISV-SP7BI/3 SV-SP7A4 SV-SP7A2 BLOCK 1 SV-SP7A5LSV-SP7AI/3 SV-SP7B4 SV-SP7B2 BLOCK 2 Spare Spare

     +         3.          Spare                     Spare 4,          Spare                     Spare 5           MI-I       M1-3           M1-2      j MI-4       TRIP 6           M2-1       M2-3           M2-2        M1-4       ýTRIP 7           Spare                     Spare 8           Spare                     Spare T2.3-3-2                            SD-010 Rev. '4

TABLE 2.3-3 RELAY DRIVER MODULE OUTPUT LISTING RDM Circuit Protection Protection Action Location go. Channel 1 Channel 2 A3 - AI/A16 1 MS-106 MS-107 CLOSE 2 AF-3870 AF-3872 CLOSE 3 AF-3869 AF-3871 OPEN 4 MS-106A MS-107A OPEN 5 MS-106 MS-107 OPEN 6 AF-3870 AF-3872 OPEN 7 AF-3869 AF-3871 CLOSE

     +         8        MS-106A                    MS-107A                CLOSE A3 -  A2/AI5    1      " MS-5889A                   MS-5889B               OPEN 2     ARTS-I         ARTS-3,        ARTS-2       ARTS-4    TRIP 3     TURB-1 j TURB-3               TURB-2       TURB-4    TRIP 4        MS-101-1                   MS-100-1               CLOSE 5        MS-394                     MS-375                 CLOSE 6       .MS-611                       MS-603               CLOSE 7        ICS-1IB                    ICS-ilA                CLOSE
     +         8        FW-612                     FW-601                 CLOSE A3 -  A3/A14    1     SV-101BI SV-101A              SV-100BI SV-100A       CLOSE 2     SV-100Ej SV-10OC/D            SV-101EI SV-101C/D CLOSE 3        FW-780                     FW-779                 CLOSE 4    SV-SP7B51SV-SP7B1/3            SV-SP7A41 SV-SP7A2 CLOSE 5    SV-SP6All SV-SP6A2             SV-SP6B1      SV-SP6B2 CLOSE 6    SV-SP7A51SV-SP7A1/3            SV-SP7B41 SV-SP7B2 CLOSE 7    INHIB-1       I INHIB-3        INHIB-2       INHIB-4  MANUAL 8        Spare                          ISpare A3 -  A4/A13    1    HIS-101BI       HIS-10ic       HIS-100BI     HIS-100C PERM 2    HIS-101BI       HIS-101C       HIS-100BI     HIS-100C  BLOCKED 3        Spare                      Spare*

4 Spare Spare 5 Spare Spare 6 Spare Spare 7 Spare Spare 8 Spare Spare T2.3-3-1 SD-010 Rev. 4

Table 2.3-2 (cont.) Logic Module Input/Output Listing Output Pin Signal Service Description No. No. No. El 28 LIGHT; 13 AND 14 LOW E2 27 ALARM; 13 AND 14 LOW E3 25 LIGHT.; 13 AND 14 LOW AND IS MOMENT. LO W E4 24 ALARM; 13 AND 14 LOW AND IS MOMENT. LOW ES 23 ALARM; 17 LOW E6 17 RS-111 (2,3, 4) A CLOSE STM-l (2,1,2) TO AFPT-1 (2'1,2) RS-111 (2,3,4) B CLOSE AFW-l (2,1,2) FROM AFP-1 (2,1,2) RS-111 (2,3,4) C OPEN AFW-1 (2,1,2) CROSS-TIE E7 4 RS-211 (2,3,4) A OPEN STM-1 (2,1,2) CROSS-TIE E8 3 RS-311 (2, 3,4)A. OPEN STM-1 (2,1,2) TO AFPT-1 (2,1,2) RS-311 (2,3, 4)B OPEN AFW-1 (2,1,2) FROM AFP71 (2,1,2), RS-311 (2,3,4) C CLOSE AFW-l (2,1,2) CROSS-TIE, E9 48 ALARM; 19 LOW' El0 45 ,RS-411 (2,3, 4)A CLOSE STM-1 (2,1,2) CROSS-TIE Eli 44 RS-511 (2,3,4)A OPEN STM ADMISSION VALVE TO AFPT-1 (2, 1,2) E12 43 RS-521 (2,3,4)A TRIP ARTS-i (2,3,4) E13 37 RS-53A (B,A,B)A TRIP TURBINE-A (B,A,B) E14 36 ALARM; Ill OR 113 LOW El5 35 ALARM; 115 LOW E16 29 RS-611 .(2, 3,4)A CLOSE MN STM-1 (2,1,2) WARM UP ISO VALVE RS-611 (2,.3, 4) B CLOSE MN STM-1 (2,1,2) WU DRAIN ISO VALVE

            .RS-611    (2,3, 4.)C         SG-1 (2,1,2) DRAIN STOP. VALVE
           .RS-611     (2; 3,4)_D         SG-I (2,1,2)    ATMOSPHERIC VENT VALVE PRS-611    (2,3, 4)E          CLOSE MAIN FEEDWATER-1 (2,1,2) STOP VALVE E17    50    RS-621     (2.,.3, 4)A        CLOSE MSIV-1 (2,1,2)

E18 52 RS-631 (2,3, 4)A CLOSE MSIV-2 '(1,2,1) E19 63 RS-64A (B,A,B)A CLOSE MFW-I (2,1,2) ISO VALVE RS-64A (B,A,B)B CLOSE MFW-1 :(2,1,2) STARTUP CONTROL VALVE E20 61 RS-64A (B,A,B)A CLOSE MFW-2 (1,2,1) CONTROL VALVE RS-64A (B,A,B) B CLOSE MFW-2 (1,2,1) STARTUP CONTROL VALVE E21 76 ALARM; LOGIC CHANNEL-I (2,3,4) SFRCS TRIP E22 77 RS-661 (2,3,4)A INHIBIT MANUAL TRIPS-i (2,3,4) E23 78 ALARM;-I17 OR 119 LOW E24 79 ALARM; 121 OR 123 LOW E25 53 ALARM; 18, 110, 112, 114, 116, 118, 120, 122, 124 OR LOSS OF CLOCK. Note: Signal No. designation and Service Description shown is for logic module in logic channel 1 only. For logic channels 2, 3 and 4 refer to characters in parentheses in the same order. T2.3-2-2 SD-010 Rev. 4

TABLE 2.3-2 LOGIC MODULE INPUT/OUTPUT LISTING Input Pin Signal Service Description No. No. No. I1 5 RSI-121 (2,3,4) Spare 12 6 RSI-131 (2,3,4) Spare 13 7 RSI-011 (2,3,4) SG-1 (2,1,2) < Block Permission Setpoint 14 8 RSI-021 (2,3,4) SG-1 (2,i,2) , Block Permission Setpoint 15 9 RSIr141 (2, 3,4) Shutdown'Manual Block 16 10 RSI-151 (2,3,4) Test Enable-i (2,3,4) at Panel A2 17 11 RSI-031 (2,3,4) SG-I (2,1,2) Low Pressure 18 12 RSI-033 (4,1,2) SG-1 (2,1,2) Low Pressure [Comp:1. Ch.] 19 13 RSI-041 (2, 3,4) SG-2 (1,2,1) Low Pressure I10 14 RSI-043 (4,1,2) SG-2 (-1,2,1) Low Pressure [Comp:L. Ch.) Ill 15 RSI-091 (2,3,4) SG-i (1,1,1) Low Level 112 16 RSI-093 (4,1, 2) SG-1 (1,1,1) Low Level [Comp ch.] C. 113 18 RSI-101 (2,3,4) SG-2 (2,2,2) Low Level 114 19 RSI-103 (4,1,2) SG-2 (2.2.2) Low Level [Comn 1.ý Ch.] 115 20 RSI-111 (2,3,4) RCPM-1 (2, 3,4) 116 21 RSI-103 (4,1,2) RCPM-3 (4, 1,2) [Compl. Ch.] 117 22 RSI-071 (2,3,4) SG-i (1,1, 1) H igh Level 118 26 RSI-073 (4,1,2) SG-1 (1,1, 1) H igh Level [Compl. Ch.] 119 30 RSI-081 (2, 3,4) SG-2 (2,2, 2) H igh Level' 120 46 RSI-083 (4,1,2) SG-2 (2,2, 2) H igh Level [Compl. Ch.] 121 47 RSI-051 (2,3,4) SG-1 (1,1, 1) H igh Diff. Pressure 122 49 RSI-053 (4,1,2) SG-2 (2,2, 1) H igh Diff. Pressure [Compl. Ch.] 123 51 RSI-061 (2,3,4) SG-2 (2,2, 2) H igh Diff.4 Pressure 124 38 RSI-063 (4,1,2) YSG-2 (2,2, 2) H igh Diff. Pressure [Compl. Ch.] N/A 32 KEYING PIN N/A 33 KEYING PIN. N/A 39 REMOVAL ALARM N/A 40 REMOVAL ALARM N/A 1 28VDC SUPPLY #1 N/A 2 28VDC SUPPLY #2 N/A 41 28VDC SUPPLY #2 [not used], N/A 42 28VDC SUPPLY #2 [not used] N/A 81 28VDC RETURN N/A 82 28VDC RETURN Note: Signal No. designation and Service Description shown is .for logic module in logic channel 1 only. For logic channels 2, 3 and 4 refer to characters in parentheses in the same order. T2.3-2-1 SD-010 Rev. 4

TABLE 2.3-1 FIELD BUFFER MODULE INPUT LISTING (Cont'd) FBM Circuit Protection Protection Location No. Channel 1 Channel 2 A4 - Al0 1 *PS-3689F *PS-3687E 2 *PS-3689H *PS-3687G 3 *PDS-2686B *PDS-2685B 4 *PDS-2685D *PDS-2686D 5 *RCPM-3 *RCPM-4 6 *LSLL-SP9B9 *LSLL-SP9B7 7 *LSHH-SP9B9 *LSHH-SP9B7 8 *LSLL-SP9A7 *LSLL-SP9A9 9 *LSHH-SP9A7 *LSHH-SP9A9 10 Spare Spare A4 - A12 1 LSLL-SP9B9 LSLL-SP9B7 2 LSHH-SP9B9 LSHH-SP9B7 3 LSLL-SP9A7 LSLL-SP9A9 4 LSHH-SP9A7 LSHH-SP9A9 5 Spare Spare 6 HIS-101C HIS-100C 7 Spare Spare 8 Spare Spare 9 Spare Spare 10 Spare Spare A4 -A13 1 PS-3689M PS-3687M 2 PS-3689N PS-3687N 3 PS-3689F PS-3687E 4 PS-3689H PS-3687G 5 PDS-2686B PDS-2685B 6 PDS-2685D PDS-2686D 7 RCPM-3 RCPM-4 8 Spare Spare 9 Spare. Spare 10 Spare Spare

• ... identifies isolated cross ties between complementary logic channels.

T2.3-1-2 SD-010 Rev. 4

TABLE 2.3-1 FIELD BUFFER MODULE INPUT LISTING FBM circuit Protection Protection Location No. Channel 1 Channel 2 A4 - A4 1 PS-3689K PS-3687K 2 PS-3689L PS-3687L 3 PS-3689B PS-3687A 4 PS-3689D PS-3687C 5 PDS-2686A PDS-2685A 6 PDS-2685C PDS-2686C 7 RCPM-1 RCPM-2 8 Spare Spare

                    ,9 Spare                         Spare 10              Spare                         Spare A4    - A5             I            LSLL-SP9B8                    LSLL-SP9B6 2           LSHH-SP9B8                    LSHH-SP9B6 3           LSLL-SP9A6                    LSLL-SP9A8 4           LSHH-SP9A6                    LSHH-SP9A8 5              Spare                         Spare 6           HIS-101Bl                     HIS-100B 7              Spare                         Spare
                     .8               Spare                         Spare 9              Spare                         Spare 10             Spare                         Spare A4 -    A7                          *PS-3689B                     *PS-3687A 2           *PS-3689D                     *PS-3687C 3           *PDS-2686A                    *PDS-2685A 4           *PDS-2686C                    *PDS-2685C 5           *RCPM-l      -                *RCPM-2
                                   *LSLL-SP9B8                   *LSLL-SP9B6 7           *LSHH-SP9B8                   *LSHH-SP9B6 8           *LSLL-SP9A6                   *LSLL-SP9A8 9           *LSHH-SP9A6                   *LSHH-SP9A8
     +                 10                Spare                         Spare

• ... identifies isolated cross ties between complementary logic channels.

T2.3-1-1 SD-010 Rev. 4

TABLE 2.2-7 TRIP CONFIRM LED'S FOR MAIN TURBINE AND ARTS TRIP LED LED DWG Description Function CH.1/2 CH.3/4 SF-003B Protection Channel 1 MAIN TURBINE TRIP A Trip LA-071 LB-073 SH. 37 ARTS PROTECTION CH.I Trip LA-061 N/A SH. 35 ARTS PROTECTION CH.3 Trip N/A LB-063 SH. 35 Protection Channel 2 MAIN TURBINE TRIP B Trip LA-072 LB-074 SH. 38 ARTS PROTECTION CH.2 Trip LA-062 N/A. SH. 36 ARTS PROTECTION CH.4 Trip N/A LB-064 SH. 36 T2.2-7-1 SD-010 Rev. 4

TABLE 2.2-6 TRIP CONFIRM LED'S FOR VALVES WITH POWER AUCTIONEERING Valve LED LED DWG ID # Description Function CH.1/2 CH.3/4 SF-003B Protection Channel 1 MS-5889A AFPT-1 MN STM IN ISO VLV Open LC-051 LD-053 SH. 21 MS-101-1 MN STM LINE-1 WU ISO VLV Close LA-081 LB-083 SH. 11 MS-394 MN STM LINE-1 WU DRN ISO V Close LA-091 LB-093 SH.17 ICS11B SG-I ATM VENT VLV Close LA-Ill LB-113 SH. 23 Protection Channel 2 MS-5889B AFPT-2 MN STM IN ISO VLV Open LC-052 LD-054 SH.22 MS-100-1 MN STM LINE-2 WU ISO VLV Close LA- 082 LB-084 SH. 12 MS-375 MN STM LINE-2 WU DRN ISO V Close LA- 092 LB-094 SH.18 ICS11A SG-2 ATM VENT VLV Close LA-112 LB-114 SH.24 T2.2-6-1 SD-010 Rev. 4

TABLE 2.2-5 TRIP CONFIRM LED'S FOR VALVES WITH PNEUMATIC AND-GATES Valve LED LED DWG ID # Description Function CH.l/2 CH.3/4 SF-003B Protection Channel 1 FW-SP7B MN FW-1 SU CTRL VLV Close LA-161 LB-163 SH.33 FW-SP6A MN FW-2 CONTROL VLV Close LA-171 LB-173 SH.29 FW-SP7A MN FW-2 SU CTRL VLV Close LA-181 LB-183 SH.31 MS-101 MN STM LINE-1 ISO VLV Close LA-131 LB-133. SH. 9 MS-100 MN STM LINE-2 ISO VLV Close LA-141 LB-143 SH. 7 Protection Channel 2 FW-SP7A MN FW-2 SU CTRL VLV Close LA-162 LB-164 SH.34 FW-SP6B MN FW-1 CONTROL VLV Close LA-172 LB-174 SH.30 FW-SP7B MN FW-1 SU CTRL VLV Close LA-182 LB-184 SH.32 MS-100 MN STM LINE-2 ISO VLV Close LA-132 LB-134 SH.10 MS-101 MN STM LINE-1 ISO VLV Close LA-142 LB-144 SH. 8 T2.2-5-1 SD-010 Rev. 4

TABLE 2.2-4 TRIP CONFIRM LED'S FOR MOV'S Valve LED LED DWG ID # Description Function CH.I/2 CH.3/4 SF-003B Protection Channel 1 AF-3870 AFP-l DISCH TO SG-l VLV Close LA-021 LB-023 SH. 5 AF-3870 AFP-1 DISCH TO SG-l VLV Open LC-021 LD-023 SH. 5 AF-3869 AFP-i DISCH TO SG-2 VLV Close LA-031 LB-033 SH. 3 AF-3869 AFP-I DISCH TO SG-2 VLV Open LC-031 LD-033 SH. 3 FW-612 MN FW-I STOP VLV Close LA-121 LB-123 SH.25 FW-780 SG-I MN FW ISO VLV Close LA-151 LB-153 SH.27 MS-106 AFPT-1 MN STM-IlIN ISO VLV Close LA-011 LB-013 SH.13 MS-106 AFPT-l MN STM-I IN ISO VLV Open LC-011 LD-013 SH.13 MS-106A AFPT-I MN STM-2 IN ISO VLV Close LA-041 LB-043 SH.15 MS-106A AFPT-l MN STM-2 IN ISO VLV Open LC-041 LD-043 SH.15 MS-611 SG-l DRAIN STOP VLV Close LA-101 LB-103 SH.19 Protection Channel 2 AF-3872 AFP-2 DISCH TO SG-2 VLV Close LA-022 LB-024 SH. 6 AF-3872 AFP-2 DISCH TO SG-2 VLV Open LC-022 LD-024 SH. 6 AF-3871 AFP-2 DISCH TO SG-l VLV Close LA-032 LB-034 SH. 4 AF-3871 AFP-2 DISCH TO SG-I VLV Open LC-032 LD-034 SH. 4 FW-601 MN FW-2 STOP VLV Close LA-122 LB-124 SH.26 FW-779 SG-2 MN FW ISO VLV Close LA-152 LB-154 SH.28 MS-107 AFPT-2 MN STM-2 IN ISO VLV Close LA-012 LB-014 SH.14 MS-107 AFPT-2 MN STM-2 IN ISO VLV Open LC-012 LD-014 SH.14 MS-107A AFPT-2 MN STM-I IN ISO VLV Close LA-042 LB-044 SH.16 MS-107A AFPT-2 MN STM-I IN ISO VLV Open LC-042 LD-044 SH.16 MS-603 SG-2 DRAIN STOP VLV Close LA-102 LB-104 SH.20. T2.2-4-1 SD-010 Rev. 4

TABLE 2.2-3 VALVE LIST WITH SFRCS INDEPENDENT INTERLOCKS Valve ID # Description Function Elementary Dwg Interlock MS-106 AFPT-1 MN STM-1 IN ISO VLV Open E-46B SH.54A/B Interlock 1 MS-106A AFPT-1 MN STM-2 IN ISO VLV Open E-46B SH.46A/B Interlock 2 MS-107 AFPT-2 MN STM-2 IN ISO VLV Open E-46B SH. 4A/B Interlock 3 MS-107A AFPT-2 MN STM-1 IN ISO VLV Open E-46B SH.46A/B Interlock 4 Interlock 1 The open function will be inhibited with o Steam Pressure at AFPT-1 (PSL-106A/B/C/D) is low or o Suction Pressure at AFP-1 (PSL-4930A) is low or o Valve DH-12 is fully closed. Interlock 2 The open function will be inhibited with o Steam Pressure at AFPT-1 (PSL-106A/B/C/D) is low or o Suction Pressure at AFP-1 (PSL-4930B) is low. Interlock 3 The open. function will be inhibited with o Steam Pressure at AFPT-2 (PSL-107A/B/C/D) is low or o Suction Pressure at AFP-2 (PSL-4931A) is low or o Valve DH-11 is fully closed. Interlock 4 The open function will be inhibited with o Steam Pressure at AFPT-2 (PSL-107A/B/C/D) is low or o Suction Pressure at AFP-2 (PSL-4931B) is low. With the interlock present the same valves receive a closing signal on the low steam pressure or low suction pressure. For further details refer to SD-015 (Reference 4.1.38) T2.2-3-1 SD-010 Rev. 4

TABLE 2.2-2 LIST OF ALL DIGITAL VARIABLES INPUTS (Cont'd) Instrument SFRCS Input No. Signal Description Logic Channel 2 PS-3687K RSI-012 SG-2 Block Permission Setpoint PS-3667L RSI-022 SG-2 <. Block Permission Setpoint PS-3687A RSII-032 SG-2 Low Pressure PS-3687C RSI-042 SG-1 Low Pressure PDS-2685A RSI-052 SG-2 High Differential Pressure PDS-2686C RSI-062 SG-1 High Differential Pressure LSHH-SP9B6 RSI-072 .SG-1 High Level LSHH-SP9A8 RSI-082 SG-2 High Level LSLL-SP9B6 RSI-092 SG-I Low Level* LSLL-SP9A8 RSI-102 SG-2 Low.Level RCPM-2 RSI-112 Loss of all RC Pumps SPARE RSI-122 SPARE RSI-132 HIS-100B RSI-142 Shutdown Manual Block T152 at Pnl A2 RSI-152 Test Enable at C5792A Logic Channel 4 PS-3687M RSI-.014 SG-2 " Block Permission Setpoint PS-3687N RSI-024 SG-2 " Block Permission Setpoint PS-3687E RSI-034 SG-2 Low Pressure PS-3687G RSI-044 SG-I Low Pressure PDS-2685B RSI-054 SG-2 High Differential Pressure PDS-2686D RSI-064 SG-I High Differential Pressure LSHH-SP9B7 RSI-074 SG-I High Level LSHH-SP9A9 RSI-084 SG-2 High Level LSLL-SP9B7 RSI-094, SG-I Low Level SG-2 LSLL-SP9A9 RSI-104 Low Level RCPM-4 RSI-114 Loss of all RC Pumps SPARE RSI-124 SPARE RSI-134 HIS-100C RSI-144 Shutdown Manual Block T154 at Pnl A2 RSI-154 Test Enable at C5792A T2 .2-2-2 SD-010 Rev- 4

TABLE 2.2-2 LIST OF ALL DIGITAL VARIABLES INPUTS Instrument SFRCS Input No. Signal Description Logic Channel 1 PS-3689K RSI-011 SG-1 " Block Permission Setpoint PS-3689L RSI-021 SG-1 < Block Permission Setpoint PS-3689B RSI-031 SG-1 Low Pressure PS-3689D RSI-041 SG-2 Low Pressure PDS-2686A RSI-051 SG-1 High Differential Pressure PDS-2685C RSI-061 SG-2 High Differential Pressure LSHH-SP9B8 RSI-071 SG-1 High Level LSHH-SP9A6 RSI-081 SG-2 High Level LSLL-SP9B8 RSI-091 SG-1 Low Level LSLL-SP9A6 RSI-101 SG-2 Low Level RCPM-1 RSI-111 Loss of all RC Pumps SPARE RSI-121 SPARE RSI-131 HIS-101B RSI-141 Shutdown Manual Block TISI at Pnl A2 RSI-151 Test Enable at C5761A Logic Channel 3 PS-3689M RSI-013 SG-1 " Block Permission Setpoint. PS-3689N RSI-023 SG-1 " Block Permission Setpoint PS-3689F RSI-033 SGý-l Low Pressure - PS-3689H RSI-043 SG-2 Low Pressure PDS-2686B RSI-053 SG-1 High Differential Pressure PDS-2685D RSI-063 SG-2 High Differential Pressure LSHH-SP9B9 RSI-073 SG-1 High Level LSHH-SP9A7 RSI-083 SG-2 High level LSLL-SP9B9 RSI-093 SG-1 Low Level LSLL-SP9A7 RSI-103 SG-2 Low Level RCPM-3 RSI-113 Loss of all RC Pumps SPARE RSI-123 SPARE RSI-133 HIS-101C RSI-143 Shutdown Manual Block T153 at Pnl A2 RSI-153 Test Enable at C5761A T2.2-2-1 SD-010 Rev. 4

TABLE 2.2-1 LIST OF ALL ANALOG VARIABLE INPUTS Instrument Steam Generator No. No. Logic Channel 1 LT-SP9B8 SG-1 LT-SP9AG SG-2 Logic Channel 3 LT-SP9B9 SG-l LT-SP9A7 SG-2 Logic Channel 2 LT-SP9B6 SG-1 LT-SP9A8 SG-2 Logic Channel 4 LT-SP9B7 SG-1 LT-SP9A9 SG-2 T2.2-1-1 SD-010 Rev. 4

TABLE 2.1-19 SFRCS OUTPUT PANEL STATUS LIGHTS (Cont'd) RED LEDs ON All Components - Component is SFRCS blocked. NOTES/EXCEPTIONS

1. Dim lights are considered OFF.

2. During MOV stroking, LED indications will not follow all these rules.

3. For parallel SVs, (100C&D, 101C&D, SP7AI&3, SP7BI&3) green LED will be on if either SV is energized and in its non SFRCS position.

4. Yellow light for ICS 11A,B is only on when complimentary Cchannel is tripped.

T2.1-19-2 SD-010 Rev. 4

TABLE 2.1-19 SFRCS OUTPUT PANEL STATUS LIGHTS GREEN LEDs ON Single Solenoid Valve Solenoid(s) are energized from that channel. Dual Solenoid Valve - Solenoid is energized and in NON SFRCS position. Motor Operated Valve - SFRCS circuit is "armed". "Ready" to go to the SFRCS position. On dual position valves (AF 3869, 3870, 3871, 3872, MS106, 106A, 107,, 107A), Valve is :"armed" and ready to go the position with the green LED on. Manual initiation exists (only on for 5 second Ml/M2 - initiation sequence). ARTS/Turbine SFRCS is "armed" and ready to actuate. GREEN LEDs OFF Single Solenoid Valve - Solenoid is not energized from that channel. Dual Solenoid Valve - Solenoid is in SFRCS position. Motor Operated Valve - Loss of MCC power to valve, or SFRCS is tripped, or valve is in SFRCS position, or SFRCS valve is blocked. For MS106, 106A, 107, 107A green open LEDs will be off for low AFP suction pressure and/or low AFPT steam pressure. ARTS/Turbine - SFRCS LCH trip YELLOW LEDs ON

                              - Complimentary channel        is tripped or valve is   in Dual/Single Solenoid Valve SFRCS position (solenoids not reset).

Motor Operated Valve - Complimentary channel is tripped. ARTS/Turbine - Complimentary channel is tripped. T2.1-19-1 SD-010 Rev. 4

TABLE 2.1-18 VALVES WITH BLOCK FEATURES Valve No. Description Function Block Switch No. Protection Channel 1 AF-3870 AFP-1 DISCH TO SG-l VLV Close HIS-3870B AF-3870 AFP-1 DISCH TO SG-1 VLV Open HIS-3870B AF-3869 AFP-1 DISCH TO SG-2 VLV Close HIS-3869B AF-3869 AFP-1 DISCH TO SG-2 VLV Open HIS-3869B FW-612 MN FW-1 STOP VLV Close HIS-612A FW-SP7B MN FW-1 SU CTRL VLV Close HIS-SP7AB FW-SP7A MN FW-2 SU CTRL VLV Close HIS-SP7BB MS-106 AFPT-l MN STM-l IN ISO VLV Close HIS-106AB MS-106 AFPT-I MN STM-l IN ISO VLV Open HIS--106AB MS-106A AFPT-1 MN STM-2 IN ISO VLV Close HIS-106EB MS-106A AFPT-1 MN STM-2 IN ISO VLV Open HIS-106EB MS-611 SG-1 DRAIN STOP VLV Close HIS-611B ICS11B SG-1 ATM VENT VLV , Close HIS-ICS11D Protection Channel 2 AF-3872 AFP-2 DISCH TO SG-2 VLV Close HIS-3872B AF-3872 AFP-2 DISCH TO SG-2'VLV Open HIS-3872B AF-3871 AFP-2 DISCH TO SG-1 VLV Close HIS-3871B AF-3871 AFP-2 DISCH TO SG-l VLV Open HIS-3871B FW-601 MN FW-2 STOP VLV Close HIS-601A FW-SP7A MN FW-2 SU CTRL VLV Close HIS-SP7DB FW-SP7B MN FW-1 SU CTRL VLV Close HIS-SP7CB MS-107 AFPT-2 MN STM-2 IN ISO VLV Close HIS-107AB MS-107 AFPT-2 MN STM-2 IN ISO VLV Open HIS-107AB MS-107A AFPT-2 MN STM-I IN ISO VLV Close HIS-107EB MS-107A AFPT-2 MN STM-1 IN ISO VLV Open HIS-107EB MS-603 SG-2 DRAIN STOP VLV Close HIS-603B ICS11A SG-2 ATM VENT VLV Close HIS-ICS11C T2.1-18-1 SD-010 Rev. 4

TABLE 2.1-17 HIS-6404 MANUAL TRIP OF PROTECTION CHANNEL 2 WITH SG-2 ISOLATION o Line-up AFP-2 with SG-2

      *Open         AF-3872 AFP-2 Discharge to SG-2 Valve
      *Close        AF-3871 AFP-l Discharge to SG-l Valve o  Line-up steam line from SG-2 to AFPT-2 Open        MS-107   AFPT-2 Main Steam-2 In     Isolation Valve o  Initiate       turbine driven auxiliary feedwater flow Open        MS-5889B AFPT-2 Main Steam In Isolation Valve o  Trip ARTS o  Trip main turbine o  Isolate main steam from SG-2
       .Close       MS-100   Main Steam Line-2 Isolation Valve
      *Close        MS-i00-1 Main Steam Line-2 Warm-up Isolation Valve o  Isolate main feedwater supply to SG-2 Close       FW-601   Main Feedwater-2 Stop Valve Close       FW-SP7A Main Feedwater-2 Start-up Control Valve Close.      FW-779   Steam Generator-2 Main Feedwater Iso Valve o  Isolate steam generator misc. valves
      *Close        ICS11A   Steam Generator-2 Atmospheric Vent Valve
      *Close        MS-603   Steam Generator-2 Drain Stop Valve Close       MS-375   Main Steam Line-2 Warm-up Drain Iso Valve
      *    ... normal valve position Note:           Depressing both Test Buttons M-2 at-Output Panel A5'in Cabinet C5792A will initiate     the same components.

T2.1-17-1 SD-010 Rev. 4

TABLE 2.1-16 HIS-6403 MANUAL TRIP OF PROTECTION CHANNEL.1 WITH SG-I ISOLATION o Line-up AFP-I with SG-I

     *Open        AF-3870  AFP-I Discharge to SG-i Valve
     *Close       AF-3869 AFP-l Discharge to SG-2 Valve o  Line-up steam line from SG-I to AFPT-I Open       MS-106   AFPT-1 Main Steam-i In   Isolation Valve o  Initiate     turbine driven auxiliary feedwater flow Open       MS-5889A AFPT-l Main Steam In   Isolation Valve o  Trip ARTS o  Trip main turbine o  Isolate main steam from SG-i Close      MS-101   Main Steam Line-i Isolation Valve
     *Close       MS-101-1 Main Steam Line-i Warm-up Isolation Valve.

o Isolate main feedwater supply to SG-I Close FW-612 Main Feedwater-I Stop Valve Close FW-SP7B Main Feedwater-i Start-up Control Valve

       ;Close     FW-780   Steam Generator-i Main Feedwater Iso Valve o  Isolate steam generator-i - misc. valves
     *Close       ICSIIB   Steam Generator-i Atmospheric Vent Valve
     *Close       MS-611   Steam Generator-i Drain Stop Valve Close      MS-394   Main Steam Line-i Warm-up Drain Iso Valve
     * ... normal valve position Note:        Depressing both Test Buttons M-2 at Output Panel A5 in Cabinet C5761A will initiate   the same components.

T2.1-16-i SD-010 Rev. 4

TABLE 2.1-15 HIS-6402 MANUAL TRIP OF PROTECTION CHANNEL 2 WITHOUT SG ISOLATION o Line-up AFP-2 with SG-2

           *Open         AF-3872  AFP-2 Discharge to SG-2 Valve
           *Close        AF-3871  AFP-I Discharge to SG-1 Valve o     Line-up steam line from SG-2 to AFPT-2 Open         MS-107   AFPT-2 Main Steam-2 In Isolation Valve o     Initiate     turbine driven auxiliary feedwater flow Open         MS-5889B AFPT-2 Main Steam In Isolation Valve o     Trip ARTS o     Trip main turbine o   Main steam,        main feedwater,  and steam generator isolation will not be initiated.
   *   ... normal valve position Note:       Depressing both Test Buttons M-1 at Output Panel A5 in      Cabinet C5792A will initiate     the same components.

T2.1-15-1 SD-010 Rev. 4

TABLE 2.1-14 HiS-6401 MANUAL TRIP OF PROTECTION CHANNEL 1 WITHOUT SG ISOLATION o Line-up AFP-l with SG-1

         *Open              AF-3870    AFP-l Discharge to    SG-1 Valve
         *Close             AF-3869    AFP-1 Discharge to    SG-2 Valve o    Line-up steam line             from SG-1 to AFPT-l Open            MS-106     AFPT-1 Main Steam-i    In  Isolation         Valve o    Initiate          turbine   driven auxiliary      feedwater flow Open            MS-5889A AFPT-l Main Steam In Isolation               Valve o    Trip ARTS o    Trip main turbine o    Main steam,            main feedwater,     and steam generator       isolation      will   not be initiated.
          *   ... normal valve position Note:     Depressing both Test Buttons M-1 at               Output   Panel AS        in  Cabinet C5761A will     initiate      the same components.

T2.1-14-1 SD-010 Rev. 4

TABLE 2.1-13 LOSS OF REACTOR COOLANT PUMPS TRIP o Line-up AFP-1 with SG-.I and AFP-2 with SG-2

           *Open      AF-3870 AFP-1 Discharge to SG-i     Valve
           *Open      AF-3872 AFP-2 Discharge to SG-2     Valve
           *Close     AF-3869 AFP-1 Discharge to SG-2     Valve
           *Close     AF-3871 AFP-1 Discharge to SG-I     Valve o     Line-up steam lines from either SG to either AFPT
           *Open      MS-107A AFPT-2 Main Steam-I In Isolation     Valve
           *Open      MS-106A AFPT-1 Main Steam-2 In Isolation     Valve Open      MS-106      AFPT-1 Main Steam-i In Isolation Valve Open      MS-107      AFPT-2 Main Steam-2 In Isolation Valve o     Initiate    turbine driven auxiliary feedwater flow Open      MS-5889A AFPT-1 Main Steam In Isolation Valve Open      MS-5889B AFPT-2 Main Steam In Isolation Valve o     Trip ARTS o     Trip main turbine o   Main steam, main feedwater,         and steam generator isolation will not be initiated.
   *   ... normal valve position T2.1-13-1                      SD-010 Rev. 4

TABLE 2.1-12 HIGH STEAM GENERATOR LEVEL o Line-up AFP-i with SG-I and AFP-2 with SG-2

    *Open         AF-3870 AFP-l Discharge to SG-I     Valve
    *Open         AF-3872   AFP-2 Discharge to SG-2   Valve
    *Close        AF-3869 AFP-l Discharge to SG-2     Valve
    *Close        AF-3871 AFP-i Discharge to SG-i     Valve o Line-up steam lines from either SG to either AFPT

• pen MS-107A AFPT-2 Main Steam-i In Isolation Valve

    *Open         MS-106A AFPT-I Main Steam-2 In Isolation    Valve Open. MS-106    AFPT-I Main Steam-I In Isolation  Valve Open      MS-107    AFPT-2 Main Steam-2 In Isolation  Valve 0 Initiate      turbine driven auxiliary feedwater flow Open      MS-5889A AFPT-i Main Steam In Isolation Valve Open      MS-5889B AFPT-2 Main Steam In Isolation Valve o Trip ARTS o Trip main turbine o Isolate- main steam from both steam generators Close     MS-101    Main Steam Line-i Isolation Valve
     *Close       MS-101-1 Main Steam Line-i Warm-up Isolation Valve Close     MS-100    Main Steam Line-2 Isolation Valve
     *Close       MS-100-1 Main Steam Line-2 Warm-up Isolation Valve o Isolate main feedwater supply to both steam generators Close     FW-612    Main Feedwater-i Stop Valve Close     FW-601     Main. Feedwater-2 Stop-Valve Close     FW-SP6A Main Feedwater-2 Control Valve Close     FW-SP6B Main Feedwater-i Control Valve Close     FW-SP7B Main Feedwater-I Start-up Control Valve Close     FW-SP7A Main Feedwater-2 Start-up Control Valve Close     FW-779,    SG-2 MN FW ISO VLV Close     FW-780     SG-i MN FW ISO VLV o Isolate steam generator-i - misc. valves
     *Close        ICS1IB    Steam Generator-i Atmospheric Vent Valve
     *Close       MS-611     Steam Generator-i Drain Stop Valve Close     MS-394    Main Steam Line-i Warm-up Drain IsoIValve o Isolate steam generator misc. valves
     *Close        ICS1iA    Steam Generator-2 Atmospheric Vent Valve
     *Close       MS-603     Steam Generator-2 Drain Stop Valve
       .Close     MS-375     Main Steam Line-2 Warm-up Drain Iso Valve
     *    ... normal valve position T2 .1-12-1                    SD-010 Rev., 4

TABLE 2.1-11 LOW STEAM GENERATOR LEVEL TRIP o Line-up AFP-1 With SG-1 and AFP-2 with SG-2

          *Open      AF73870 AFP-1 Discharge to SG-I    Valve
          *Open      AF-3872 AFP-2 Discharge to SG-2    Valve'
         .*Close     AF-3869 AFP-1.Discharge to SG-2    Valve
          *Close     AF-3871 AFP-1 Discharge to SG-1    Valve o     Line-up steam lines from either SG to either AFPT
          *Open      MS-107A AFPT-2 Main Steam-l In Isolation    Valve
          *Open      MS-106A AFPT-1 Main Steam-2 In Isolation    Valve Open     MS-i6O     AFPT-l Main Steam-i In Isolation Valve Open     MS-107     AFPT-2 Main Steam-2 In Isolation Valve o     Initiate   turbine driven auxiliary feedwater flow Open     MS-5889A AFPT-l Main Steam In Isolation Valve Open. MS-5889B AFPT-2 Main Steam In Isolation Valve o     Trip ARTS o     Trip main turbine o   Main steam,     main feedwater,   and steam generator isolation will not be initiated.
        ... normal valve position T2.1-11-1                      SD-010 Rev. 4

TABLE 2.1-10 HIGH REVERSE DIFFERENTIAL PRESSURE TRIP o Line-up AFP-I with SG-1 and AFP-2 with SG-2

     *Open        AF-3870 AFP-I Discharge to SG-l    Valve
     *Open        AF-3872 AFP-2 Discharge to SG-2    valve
     *Close       AF-3869 AFP-I Discharge to SG-2    Valve
     *Close       AF-3871" AFP-I Discharge to SG-l   Valve o  Line-up steam lines from either SG to either AFPT
     *Open        MS-107A AFPT-2 Main Steam-i In Isolation    Valveý
     *Open        MS-106A AFPT-I Main Steam72 In Isolation    Valve Open       MS -106   AFPT-l Main Steam-i In Isolation  Valve open       MS-107    AFPT-2 Main Steam-2 In Isolation  Valve o  Initiate     turbine driven auxiliary feedwater flow Open       MS-5889A AFPT-i Main Steam In Isolation Valve Open       MS-5889B AFPT-2 Main Steam In Isolation Valve o  Trip ARTS o  Trip main turbine o  Isolate main steam from both steam generators Close      MS-101    Main Steam Line-i Isolation Valve
      *Close      MS-101-1 Main Steam Line-i Warm-up Isolation Valve
       -Close     MS-100,   Main Steam Line-2 Isolation Valve
      *Close      MS-100-1 Main Steam Line-2 Warm-up Isolation Valve o  Isolate main feedwater supply to both steam generators Close     FW-612    Main Feedwater-1 Stop Valve Close     FW-601    Main Feedwater-2 Stop Valve Close      FW-SP6A Main Feedwater-2 Control Valve Close      FW-SP6B   Main Feedwater-i Control Valve Close     FW-SP7B Main Feedwater-iStart-up Control yalve Close     FW-SP7A Main Feedwater-2 Start-up Control Valve Close     FW-779    SG-2 MN FW ISO VLV Close     FW-780   .SG-I MN FW ISO VLV o  Isolate steam generator-I - misc. valves
      *Close       ICSIIB,  Steam Generator-i Atmospheric Vent Valve
      *Close      MS-611    Steam Generator-i Drain Stop Valve Close     MS-394    Main Steam Line-i' Warm-up Drain Iso Valve o 'Isolate' steam generator misc. valves
      *Close       ICSIIA    Steam Generator-2 Atmospheric Vent Valve
      *Close       MS-603    Steam Generator-2 Drain Stop Valve Close      MS-375   Main Steam Line-2 Warm-up Drain Iso Valve
      * ... normal valve position 7T2.1-10-1                     SD-010 Rev. 4

TABLE 2.1-9 LOW STEAM LINE-2' PRESSURE TRIP (Cont'd) o Line-up AFP-I and AFP-2 with SG-l Open AF-3871 AFP-2 Discharge to SG-I Valve

    *Open        AF-3870 AFP-l Discharge     to, SG-l   Valve
    *Close       AF-3869 AFP-I Discharge     to  SG-2   Valve Close      AF-3872 AFP-2 Discharge     to  SG-2   Valve o Line-up steam lines from SG-2 to       AFPT-1 and     AFPT-2 Open       MS-106    AFPT-l Main  Steam-i In     Isolation Valve
    *Open        MS-107A AFPT-2 Main    Steaml In      Isolation Valve ClosE-     MS-106A AFPT-l Main    Steam-2 In     Isolation Valve
    *ClosE-      MS-107    AFPT-2 Main  Steam-2 In     Isolation Valve o Initiate,    turbine driven auxiliary feedwater flow open       MS-5889A AFPT-I Main Steam In Isolation Valve Open       MS-5889B AFPT-2 Main Steam In Isolation Valve o Trip ARTS o Trip main turbine o Isolate main steam from both steam generators

Close MS-101 Main Steam Line-I Isolation Valve

     *Close      MS-101-1 Main Steam Line-i Warm-up Isolation Valve Close     MS-100    Main Steam Line-2 'Isolation Valve
     *Close      MS-100-1 Main Steam Line-2 Warm-up Isolation Valve o Isolate main feedwater supply to both steam generators Close     FW-612    Main Feedwater-1 Stop Valve Close     FW-601    Main Feedwater-2. Stop     Valve Control Valve Close     FW-SP6A Main Feedwater-2 Control Valve Close     FW-SP6B Main Feedwater-1 start-up.Control Valve Close     FW-SP7B Main Feedwater-1 Start-up Control Valve Close     FW-SP7A Main Feedwater-.2 Close     FW-779    SG-2 MN FW ISO VI NV Close     FW-780    SG-I MN FW ISO VI LV o Isolate steam generator-i - misc. valves
     *Close       ICSllB 'Steam Generator-i Atmospheric Vent Valve
     *Close      MS-611    Steam Generator-I Drain Stop Valve Close     MS-394    Main Steam Line-l Warm-up Drain Iso Valve o Isolate steam generator misc, valves
     *Close       ICS11A   Steam Generator-2 Atmospheric Vent Valve
     *Close      MS-603    Steam Generator-2 Drain Stop Valve Close     MS-375    Main Steam Line-2 Warm-up Drain Iso Valve
     * ... normal valve position T2.1-9-1                           SD-010 Rev. 4

TABLE 2.1-8 LOW STEAM LINE-1 PRESSURE TRIP o Line-up AFP-I and AFP-2 with SG-2 Open AF-3869 AFP-I Discharge to SG-2 Valve

    *Open         AF-3872   AFP-2 Discharge      to SG-2  Valve
     *Close       AF-3871   AFP-2 Discharge      to SG-I  Valve Close      AF-3870   AFP-I Discharge      to SG-I  Valve o Line-up steam lines from SG-2 to           AFPT-i and   AFPT-2
    *Open         MSI106A AFPT-i Main       Steam-2 In   Isolation Valve Open        MS-107    AFPT-2 Main     Steam-2 In   Isolation Valve
     *Close       MS-106    AFPT-I Main     Steam-i Ih   Isolation Valve Close      MS-107A AFPT-2 Main       Steam-I In   Isolation Valve-o Initiate      turbine driven auxiliary feedwater flow Open       MS-5889A AFPT-i Main Steam In Isolation Valve Open       MS-5889B AFPT-2 Main Steam In Isolation Valve o Trip.ARTS o Trip main turbine o Isolate main steam from both steam generators Close      MS-101    Main Steam Line-I Isolation Valve
    ,*Close       MS-101-1 Main Steam Line-I Warm-up Isolation Valve Close      MS-100    Main Steam Line-2 Isolation Valve
     *Close       MS-100-1 Main Steam Line-2 Warm-up Isolation Valve o Isolate main feedwater supply to both steam generators Close      FW-612    Main Feedwater-i Stop Valve Close      FW-601    Main Feedwater-2 Stop Valve Close      FW-SPGA Main Feedwater-2 Control Valve Close      FW-SP6B Main*Feedwater-I Control Valve Close      FW-SP7B Main Feedwater-i Start-up Control Valve Close      FW-SP7A Main Feedwater-2 Start-up Control Valve Close      FW-779    SG-2 MN FW ISO VLV Close      FW-780    SG-i MN FW ISO VLV o Isolate steam generator-i - misc. valves
     *Close        ICSIIB   Steam Generator-I Atmospheric Vent Valve
     *Close       MS-611    Steam Generator-i Drain Stop Valve Close      MS-394    Main Steam Line-i Warm-up Drain Iso Valve o Isolate steam generator misc. valves
     *Close        ICSIIA   Steam Generator-2 Atmospheric Vent Valve
     *Close       MS-603    Steam Generator-2 Drain Stop Valve Close      MS-375    Main Steam Line-2 Warm-up Drain Iso Valve
     *   ...- normal valve position T2 .1-8-i                         SD-010 Rev. 4

TABLE 2.1-7 SFRCS ACTUATED EQUIPMENT LIST-FOR PROTECTION CHANNEL 2 SFRCS SFRCS Reference Equipment No. Device Description Mode Output Drawing AF-3872 AFP-2 DISCH TO SG-2 VLV Close RS-112B E-44B SH.15 AF-3872 AFP-2 DISCH TO SG-2 VLV Open RS-312B E-44B SH.15 AF-3871 AFP-2 DISCH TO SG-I VLV Close RS-112C E-44B SH.14A/B AF-3871 AFP-2 DISCH TO SG-I VLV Open RS-312C E-44B SH.14A/B FW-601 MN FW-2 STOP VLV Close RS-612E E-44B SH.4A/B FW-779 SG-2 MN FW ISO VLV Close RS-64BA E-44B SH. 5 FW-SP7A MN FW-2 SU CTRL VLV Close RS-64BB E-44B SH.21A/D FW-SP6B MN FW-l CONTROL VLV Close RS-65BA E-44B SH.9 FW-SP7B MN FW-l SU CTRL VLV Close RS-65BB E-441 SH.21A/D MS-107 AFPT-2 MN STM-2 IN ISO VLV Close RS-112A E-46B SH.4A/B MS-107 AFPT-2 MN STM-2 IN ISO VLV Open RS-312A E-46B SH.4A/B MS-107A AFPT-2 MN STM-l IN ISO VLV Close RS-412A E-46B SH.46A/B MS-107A AFPT-2 MN STM-1IN ISO VLV Open RS-212A E-46B SH.46A/B MS-5889B AFPT-2 MN STM IN ISO VLV Open RS-512A E-46B SH.71 MS-100-1 MN STM LINE-2 WU ISO VLV Close RS-612A E-46B SH.32A MS-375 MN STM LINE-2 WU DRN ISO V Close RS-612B E-46B SH.3 MS-603 SG-2 DRAIN STOP VLV Close RS-612C E-46B SH.33/A ICS11A SG-2 ATM VENT VLV Close RS-612D .E-46B SH.79A/B MS-100 MN STM LINE-2 ISO VLV Close RS-622A E-46B SH.l A/D MS-101 MN STM LINE-1 ISO VLV Close RS-632A *E-46B SH.l E/F N/A MAIN TURBINE TRIP B Trip RS-53BA E-42B SH.53 N/A ARTS PROTECTION CH.2 Trip RS-5222A E-65B SH.10 N/A ARTS PROTECTION CH.4 Trip RS-5224A E-65B SH.10 T2.1-7-1 SD-010 Rev. 4

TABLE 2.1-6 SFRCS ACTUATED EQUIPMENT LIST FOR PROTECTION CHANNEL 1 SFRCS SFRCS Reference Equipment No. Device Description Mode Output Drawinq AF-3870 AFP-I DISCH TO SG-I VLV Close RS-IIIB E-44B SH. 20 AF-3870 AFP-i DISCH TO SG-I VLV. Open RS-311B E-44B SH.20 AF-3869 AFP-i DISCH TO SG-2 VLV Close RS-111C E-44B SH. 14A/B AF-3869 AFP-i DISCH TO SG-2 VLV Open RS-311C E-44B SH. 14A/B FW-612 MN FW-1 STOP VLV Close RS-611E E-44B SH.4A/B FW-780 SG-I MN FW ISO VLV Close RS-64AA E-44B SH. 5 FW-SP7B MN FW-i SU CTRL VLV Close RS-64AB E-44B SH. 21B/C FW-SP6A MN FW-2 CONTROL VLV Close RS-65AA E744B SH. 9 FW-SP7A MN FW-2 SU CTRL VLV Close RS-65AB E-44B SH. 21B/C MS-106 AFPT-1 MN STM-1 IN ISO VLV Close RS-I11A E-46B SH. 54A/B MS-106 AFPT-1 MN STM-I IN ISO VLV Open RS-311A E-46B SH. 54A/B MS-106A AFPT-1 MN STM-2 IN ISO VLV Close RS-411A E-46B SH. 46A/B MS-106A AFPT-1 MN STM-2 IN ISO VLV Open RS-211A E-46B SH. 46A/B MS-5889A AFPT-1 MN STM IN ISO VLV Open RS-511A E-46B SH.71 MS-101-1 MN STM LINE-1 WU ISO VLV Close RS-611A E-46B SH. 32A MS-394 MN STM LINE-1 WU DRN ISO V Close RS-611B E-46B SH. 3 MS-611 SG-i DRAIN STOP VLV Close RS-611C E-46B SH. 33/A ICS11B SG-1 ATM VENT VLV Close RS-611D E-46B SH. 78A/B MS-101 MN STM LINE-1 ISO VLV Close RS-621A E-46B SH. 1 A/D MS-100 MN STM LINE-2 ISO VLV Close RS-631A E-46B SH.I E/F N/A MAIN TURBINE TRIP A Trip RS-53AA E-42B SH. 53 N/A ARTS PROTECTION CH.I Trip RS-5211A E-65B SH.10 N/A ARTS PROTECTION CH.3 Trip RS-5213A E-65B SH. 10 T2 .1-6-1 SD-010 Rev. 4

TABLE 2.1-5 RC PUMP AND ICS POWER MONITORING SFRCS INPUT SIGNAL LIST Signal SFRCS Input Relay No. Signal Panel Logic Channel 1 RCPM-1 RSI-lil RC3601 Logic Channel 3 RCPM-3 RSI-113 RC3603 Logic Channel 2 RCPM-2 RSI-112 RC3602 Logic Channel 4 RCPM-4 RSI-114 RC3604 T2.1-5-1 SD-010 Rev. 4

TABLE 2.1-4 MAIN FEEDWATER/STEAM GENERATOR DIFFERENTIAL PRESSURE SWITCH LIST Instrument SFRCS Input Steam Generator No. Siqnal No. Logic Channel 1 PDS-2686A RSI-051. SG-1 PDS-2685C RSI-061 SG-2 Logic Channel 3 PDS-2686B RSI-053 SG-1 PDS-2685D RSI-063 SG-2 Logic Channel 2 PDS-2686C RSI-062 SG-1 PDS-2685A RSI-052 SG-2 Logic Channel 4 PDS-2686D RSI-064 SG-1 PDS-2685B RSI-054 SG-2 T2..1-4-1 SD-010 Rev. 4

TABLE 2.1-3 MAIN STEAM LINE PRESSURE SHUTDOWN BLOCK SWITCH LIST Instrument SFRCS Input Steam Generator No. Signal No. Logic Channel 1 PS-3689K RSI-011 SG-1 PS-3689L RSI-021 SG-1 Logic Channel 3 PS-3689M RSI-013 SG-I PS-3689N RSI-023 SG-1 Logic Channel 2 PS-3687K RSI7012 SG-2 PS-3687L RSI-022 SG-2 Logic Channel 4 PS-3687M RSII-014 SG-2 PS-3687N RSI-024 SG-2 T2.1-3-1 SD-010 Rev. 4

TABLE 2.1-2 MAIN STEAM LINE PRESSURE TRIP SWITCH LIST Instrument SFRCS Input Steam Generator No. Sicnal No. Logic Channel 1 PS-3689B RSI-031 SG-1 PS-3689D RSI-041 SG-2 Logic Channel 3 PS-3689F RSI-033 SG-1 PS-3689H RSI-043 SG-2 Logic Channel 2 PS-3687C RSI-042 SG-1 PS-3687A RSI-032 SG-2 Logic Channel 4 PS-3687G RSI-044 SG-1 PS-3687E RSI-034 SG-2ý T2.1-2-I SD-010 Rev. 4

TABLE 2.1-1 STEAM GENERATOR STARTUP, LEVEL TRANSMITTER LIST Instrument Steam Generator No. No. Logic Channel 1 LT-SP9B8 *) SG-1 LT-SP9A6 *) SG-2 Logic Channel 3 LT-SP9B9 SG-1 LT-SP9A7 SG-2 Logic Channel 2 LT-SP9B6 *) SG-1 LT-SP9A8 *) SG-2 Logic Channel 4 LT-SP9B7 SG-1 LT-SP9A9 SG-2 Thetransmitters marked with "*)" drive Startup Level Indicators in the main control room. The analog signals of these transmitters are buffered (isolated) with 1E isolators in the SFRCS cabinet before the signals exit the SFRCS cabinets. T2.1-1-1 SD-010 Rev. 4

Table 1.1-1 SFRCS System Boundary (Cont'-d) COMPONENT BOUNDARY Control and Reset (18).Switches - at Control Room Panels.C5706, C5708; C5709, C5712, C5762N and C5792N HIS-7AB/.BB/CB/DB, HS-SP6A/B, H-IS-5889A/B, HIS-101-1, HIS-100-1, HIS-375, HIS7394, HIS-ICS1lA/B, HIS-100, HIS-101, HS-100, HS-101 The following SFRCS Trip Alarm Acknowledge push button is outside the SFRCS boundary. For details refer to Section 2.9.2. SFRCS Trip Alarm Acknowledge (1) Push Button at Control Room Panel C5709 HIS-5891 T1.1-1-5 SD-010 Rev. 4

Table 1.1-I SFRCS System Boundary (Cont'd) COMPONENT BOUNDARY MF Line-i Differential Pressure Switches (4), PDS-2686(A/B/C/D) (Refer to Figure 2.1-9) MF Line-2 Differential Pressure Switches (4), PDS-2685(A/B/C/D) (Refer to Figure 2.1-10) SG-1 Startup Level Transmitters (4), LTSP9B(6/7/8/9) (Refer to Figures 2.1-3 and 2.1-4) SG-2 Startup Level Transmitters (4), LTSP9A(6/7/8/9) (Refer to Figures 2.1-5 and 2.1-6) Reactor Coolant Pumps (RCP) monitoring circuit (Refer to Figures 2.1-11 to 2.1-14) 0 SFRCS Cabinets

    -    SFRCS Logic Cabinets C5761A and C5792A
    -    SFRCS Relay Cabinets C5762A and C5792.
    -    SFRCS Interface   Cabinets C5762Z and C5792Z o    Control Switches
    -    Shutdown Bypass (Block) (4) Control Switches at Control Room Panel C5721 HIS-100(B/C) and HIS-101(B/C)
    -    Manual Trip (4)   Control Switches   - at Control Room Panel C5707 HIS-6401/2/3/4 SFRCS components include the following:

o Control Switches Block (18) Switches - at Control Room Panels C5706, C5708, C5709, C5710 and C5712 HIS-3869/70/71/72(B), HIS-601A, HIS-603B, HIS-611B, ,HIS-612A, HIS-106AB, HIS-106EB, HIS-107AB, HIS-107EB, HIS-SP7AB/BB/CB/DB, HIS-ICSIC/D T1.1-I-4 SD-010 Rev. 4

                                   .Table 1.1-1 SFRCS System Boundary (Cont'd)

COMPONENT BOUNDARY o Annunciator

    -     SFRCS System Input                                 S FRCS Cabinets, o    Post Accident Monitoring
    -     SG Startup Level                                  'SFRCS Cabinets,

o. Integrated Control System

    -     Loss of ICS Power                                  SFRCS'Cabinets o    Essential Power Supply
    -     125 Vdc Panels DIP and D2P                         Branch Breaker (DIP11, D2PI1) 1-20 Vac Panels Y1 and Y2                          Branch Breaker (Y115, Y121, Y215, Y221) 120 Vac MCC's YE2 and YF2                           Branch Breaker (YE211, YF211) o    Non-Essential Power Supply
    -     120 Vac Panels Y4501 and Y4502                      Branch Fuse (Circuits 15 and.15) 125 Vdc Panels DAP and DBP                          Branch Fuse (DAP22, DBPI6)

SFRCS components include the following: o Process. Sensors

     -    Main Steam Line- 1 Pressure Switches (8), PS-3687(C/G)    and PS-3689(B/F/K/L/M/N) (Refer to Figure 2.1-7)
    -     Main Steam Line- 2 Pressure Switches   (8), PS-3687(A/E/K/L/M/N)   and PS-3689(D/H) (Refer to Figure 2.1-8)

T1.1-1-3 SD-010 Rev.' 4

Table 1.1-1 SFRCS System Boundary (Cont'd) COMPONENT BOUNDARY o Main Steam (MS) (Reference P&ID M-007A and M-003C) (Cont'd) MS Line Warmup Drain Isolation Valves SFRCS Cabinets (MS394 and MS375) SG Atmospheric Steam Vent Valves SFRCS Cabinets

(ICS1IB and ICS11A)

Auxiliary Feedwater Pump Turbine (AFPT) SFRCS Cabinets Steam Isolation Valves (MS106, MS107, MSI06A, MSl07A, MS5889A, and MS5889B) o Steam Generators (Reference P&ID M-007A/B) Instrumentation Root Valves SP9B3A/B Root Valve (Refer to Figure 2.1-3)

 -      Instrumentation Root Valves SP9B4A/B             Root Valve (Refer to Figure 2.1.4),

Instrumentation Root Valves SP9A4A/B Root Valve (Refer to Figure 2.1.5) Instrumentation Root Valves SP9A3A/B Root Valve (Refer to Figure 2.1.6) o Reactor Protection System RC Pump Monitoring, Relay Cabinet RC3601/2/3/4 Relay Cabinets (Refer to Figures 2.1-11/12/13/14) o Main Turbine

 -      Turbine Trip Circuit                             SFRCS Cabinets o Anticipatory Reactor Trip System      (ARTS)
 -      Trip Contact to ARTS                             SFRCS Cabinets o -Plant Computer
 -      SFRCS System Input                               SFRCS Cabinets T1.1-1-2                    SD-010 Rev. 4

TABLE 1.1-1 SFRCS SYSTEM BOUNDARY The SFRCS interfaces with other plant systems as follows: COMPONENT BOUNDARY 0 Main Feedwater (MFW) (Reference P&ID M-007B)

    -    Instrumentation Root Valves FW2686A/C/E/F         Root Valve (Refer to Figure 2.1-9)
    -    Instrumentation Root Valves FW2685A/C/E/F         Root Valve (Refer to Figure 2.1-10)
    -    MFW Stop Valves    (FW612   and FW601)            SFRCS Cabinets
    -    Steam Generator MFW Isolation Valves              SFRCS Cabinetsl (FW780 and FW779)
    -    MFW Startup Control Valves (SP7A and SP7B)        Pneumatic Control (Refer to Figure 2.2-26) (typical)

MFW Control Valves (SP6A and SP6B) Pneumatic Control (Refer to Figure 2.2-25) (typical) 0 Auxiliary Feedwater (AFW) (Reference P&ID M-007B) Auxiliary Feedwater (AFW) Discharge Valves SFRCS Cabinets' (AF3870, AF3872, AF3869, and AF3871) o Main Steam (MS) (Reference P&ID M-007A) Instrumentation Root Valves MS920/l/2/3 Root Valve (Refer to Figure 2.1-7) Instrumentation Root Valves MS914/5/8/9 Root Valve (Refer to Figure 2.1-8)

    -    MS Isolation Valves (MS101 and MSi00)             Pneumatic Control (Refer to Figure 2.2-24) (typical)
     -   MS Isolation Bypass Valves (MS101-1 and           Solenoid MS100-1) (Refer to Figure 2.2-23) (typical)

SG Steam and Condensate Drain Valves SFRCS Cabinets (MS611 and MS603) T1.1-1-1 SD-010 Rev. 4

4.8.15 FCR 87-0092 o Modification of SFRCS/AFW Manual Initiation Switches o Addition of a Second Solenoid to the Main Feedwater Control Valves FW-SP6A and FW-SP7B. 4.8.16 FCR 87-00971 o Technical Specification Change to Reduce SFRCS Low Level SG Setpoint. 4.8.17 FCR 85-0157 Rev.N/A Supp 00, o Calculation of Low Level Setpoint, Change of Safety Limit. 4.8.18 FCR 85-0157 Rev.A Supp 01, o Establish Steam Generator High Level Limit based on Introduction of new Hardware with MOD 87-1107. 4.8.19 FCR 85-0157 Rev.A Supp 02, o Revision of Setpoints to Permit + and - Tolerance verses the Traditional One-sided Tolerance. 4.8.20 FCR-85-0157 Rev.A Supp 03 o High Level Steam Generator Setpoint for SG A is to be Raised from 215' to 225". 4.8.21 SCR 91-5003 o SFRCS Low Pressure Trip Block Permit Setpoint. 4.8.22 MOD 87-1005 o Replace Low Pressure Trip Pressure Switches and Change Setpoints 4.8.23 MOD 98-0046 o SFRCS High Level Trip Setpoint 4.8.24 MOD 95-0062 o Rescale SG startup Range Level strings. 4.8.25 MOD 99-0030 0 Add Main Feedwater Control Valve (SP6A & SP6B) Solenoid Instrument Air Isolation Valves 4-25 SD-010 Rev. 4

Not Applicable 4.8 FCRs/MODs - IMPLEMENTED 4.8.1 MOD 87-1107 Supp 00, entitled DHRTF and SRTP SFRCS Changes o Removal of SFRCS and SGLIC During Modes 4 through 6. 4.8.2 MOD 87-1107 Supp 01, entitled DHRTF and SRTP SFRCS Changes o Installation of Cabinets and Power and Ground Cables for the new SFRCS 4.8.3 MOD 87-1107 Supp 02, entitled DHRTF and SRTP SFRCS Changes o Rout Remainder of Control and Instrumentation Cables Associated with New SFRCS 4.8.4 MOD 87-1107 Supp 03, entitled DHRTF and SRTP SFRCS Changes o Add Bistable Test Points o Delete Test Enable Lockout (Dwg Change Only) o Modify Q963 Alarm Circuitry o Clarify Labeling for Input/Output Panels 4.8.5 MOD 87-1107 Supp 04, entitled DHRTF and SRTP SFRCS Changes o Relabel Terminal Blocks, Switches, LEDs, Component Boards and Plates with TE Identifiers o Internal SFRCS Power Auctioneering o Modify Logic Modules for LED Indications 4.8.6 MOD 87-1107 Supp 05, entitled DHRTF and SRTP SFRCS Changes 6 Paperwork Change only 4.8.7 FCR 85-0096, Rev. B o Addition of Steam Generator Level and Pressure -Indication to Center Console. 4.8.8 FCR 85-0109 o Control Room Center Console Modification. 4.8.9 FCR 85-0154, Rev. A o Deletion .of SFRCS Signals to Valves AF-599 and AF-608. 4.8.10 MOD 90-0078 o Addition of Steam Generator Level Indication to the Post Accident Monitoring Cabinets. 4.8.11 FCR 8770063 o Relocation of Control Switches from C5717 to Center Console and Removal of SFAS Actuation Signals.' 4.8.12 FCR 87-0064 o AFPT Control Switch Relocation from C5717 to Center Console and Addition of SFRCS Block Switches for Valves MS-106, MS-l06A, MS-107, MS-107A. 4.8.13 FCR 87-0065 o Addition of SFRCS Block Switches for Valves AF-3869 through AF-3872. 4.8.14 FCR 87-0070 o Relocation of Control Switches from C5721 to Center Console. 4-24 SD-010 Rev. 4

4.6.12 B&W 86-0002184-00, Summary Report - LOFW Event Analysis, dated 08/10/78. 4.6.13 B&W 86-1130654-00, Loss of Feedwater - Core Cooling, dated 01/08/82. 4.6.14 B&W 32-1159090-00, SFRCS Accident Analysis, dated 10/01/85. 4.6.15 B&W 32-1159090-01, SFRCS Accident Analysis, dated 10/04/87. 4.6.16 B&W 32-1159090-02, SFRCS Accident Analysis, dated 01/15/88. 4.6.17 B&W 32-1170357-00, SU & OP Indications - MFW Transients, dated 11/12/87. 4.6.18 B&W '32-1159102-00, RELAP5/MOD5 Steam Line Break Analysis, dated 12/07/85. 4.6.19 B&W 86-1158463-00, Steam Line Break Single Failure Analysis, dated 11/07/85. 4.6.20 B&W-86-1126460-00, Complete Loss of Feedwater Transient, dated 06/29/81. 4.6.21 B&W 32-1170343-00, SFRCS High Steam Generator Startup Delta P Setpoint, dated il/12/87. 4.6.22 B&W 32'-106751L00, 177 FA Overcooling, dated 11/30/79. 4.6.23 B&W 86-1106752-03, Appendix A - Overcooling, dated 03/14/80. 4.6.24 B&W 32-1137043-00, PSC 7-78 Overcooling, dated 01/12/83. 4.6.25 B&W 32-1171126-00, OTSG Overfill (Appendix R Concern), dated 12/14/87. 4.6.26 B&W 51-1165555-00, OTSG Integrity - MSLB, dated 12/02/86. 4.6.27 Struthers-Dunn, Commercial/Industrial Relays, Catalog SD-5252-20M-689-FG/IP. 4.6.28 AGASTAT, Electromechanical Relays, Switches, Rotary Drives, Catalog EMD-l. 4.6.29 B&W, Doc. No. 36-3333000001-00, Balance of Plant Criteria for Reactor Coolant Pump Monitors. 4.6.30 B&W letter to Bechtel, BWB-297, RCP Motors (Locked Rotor Current at 80% Voltage), dated 05/13/71. 4.6.31 Test Data from Westinghouse'for B&W, General Order No. RO-39700-P, VSS Induction Motor (Loss of Motor Load at 80% Voltage), dated 02/26/73. 4.6.32 BT-15912, Bectel Study, Single Failure Mode and Effects Analysis (FMEA). 4.6.33 Memo NEN 90-10190, SFRCS Low Steamline Pressure and Reverse Delta P Trip Setpoints, dated 5-24-90. 4.7 AS-BUILT DESIGN CHANGES 4-23 SD-010 Rev. 4

4.5.37 B&W letter to TE, TED 87-003.3, Task 520 - Transmittal of 600 GPM. Auxiliary Feedwater Case, dated 02/02/87. 4.5.38 SE88-0673, Safety Evaluation for FCR 85-0157 Supplement 03, Revision of SFRCS OTSG High Water Level Trip Setpoint. 4.5.39 Containment Isolation Valve List 4.5.40 EXT-89-07632, Bechtel Calculation Sheet,

Title:

Tech. Spec. Allowable Values for Surveillance Tests,

Subject:

SFAS and SFRCS, by M. David, dated 04/04/77. 4.5.41 Calculation No. C-ICE-058.01-001, RCPM Monitor Setpoint for Loss of Reactor Coolant Pump 4.5.42 Letter to the NRC, Serial No. 2194, dated 12-16-93 concerning commitments for an SFRCS High SG Level Trip 4.5.43 Calculation No. C-ICE-083.03-004,'Setpoint Determination for SFRCS SG High AP Pressure Switches . 4.5.44 Calculation C-EE-002.01-010, DC .Calc-Battery/Charger Size, Short Circuit, Voltage Drop 4.5.45 Calculation C-EE-004.01-049, 4.16 KV Bus Degraded Voltage (90% Undervoltage) Relay Setpoint 4.6 UNCONTROLLED DOCUMENTS - USED FOR REFERENCE ONLY 4.6.1 Project Plan For Main Control Room Modifications Related to FCR 85-0109 and MOD 87-1107, dated 2/22/88. 4.6.2 Control Room Modifications - Decision Analysis Paper, Revision 1. 4.6.3 BAW-1655, Main Feedwater Overfill - Evaluation of an OTSG dP Overfill Parameter, K.C.Heck, dated January 1981. 4.6.4 A Vitae of Davis-Besse SFRCS, by Sushil Jain, dated 7/10/85. 4.6.5 Topic.Backgrounder - Auxiliary Feedwater System and Steam and Feedwater Rupture Control System, by Sushil Jain. 4.6.6 Rosemount Instruction Manual 4235 Revision A for Model 1152. Pressure Transmitters, Nov. 1982. 4.6.7 AGASTAT, Electromechanical Relays; Switches, Rotary Drives, Catalog EMD-1, January 1988, Amerace Corporation, Industrial Electrical Products. 4.6.8 B&W 32-1158582-00, Loss of Feedwater Transient, dated 06/20/85. 4.6.9 B&W 32-0002528-00, Auxiliary (Emergency) Feedwater System, dated 09/17/75. 4.6.10 B&W 32-0000824-00, Auxiliary Feedwater Requirements, dated 02/17/75. 4.6.11 B&W 86-1127514-00, Loss of all Feedwater Transient, dated 10/23/81. 4-22 SD-010 Rev. 4

4.5.17 Evaluation of Setpoint Program in Response to PCAQ 86-0059. 4.5.18 Toledo Letter to SAIC, V Watson to R Roberts, April 12,1988, NED 88-40190, SAIC Signal Monitor Rack Performance Evaluation Report P.O. No. Q010777ST. 4.5.19 MPR- 732, SFRCS Review of Calculation Procedure to Ensure Compliance with Tech. Spec' 4.5.20 NED-87-40217, Scaling & Setpoints Utilized to Calculate SG SFRCS Level Transmitter. 4.5.21 PCAQ 87-0094, Error Encountered while Lifting Live Leads, dated 02/05/87. 4.5.22 DBI-100, Environmental Conditions (Electrical Equipment Qualification). 4.5.23 Safety Evaluation for FCR 85-0161 Rev.B Supp 03, Time Constant Adjustment. 4.5.24 TE Calculation No.063-002 performed under FCR 80-0110 Supp '06, Temperature Effect on SFRCS Steam Generator Level Transmitters. 4.5.25 SFRCS Trip / MSIV Closure, Action Plan # 5, 6, & 7, dated 6/22/86. 4.5.26 Corrective Actions Associated with Action Plan # 5, 6, & 7. 4.5.27 ICM NED-88-10286, from TS Swim to GP Swartz, MOD 87-1107, SFRCS Seismic Qualification, dated 7/26/88. 4.5.28 SE-88-0267 Rev. 0, Safety Evaluation for .FCR 87-0130 Supplement 0, Tech. Spec. Change for SFRCS Manual Initiation Pushbutton. 4.5.29 SE-88-0100 Rev. 1, Safety Evaluation for MOD 87-1107 Supplement 5, DHRTF ahd SRTP SFRCS Changes. 4.5.30 NES-89-60045, ICM from DA Dreier to Distribution, 'System Description Boundaries, dated 4/29/89. 4.5.31 NEN-87-10349, ICM from SC Jain to VM Watson, SFRCS Redesign (MOD 87-1107) - R.G. 1.75 - dated 12/01/87 4.5.32 Dwg. E-302A'SH.39 & SH.39C, Separation Requirements for Field-Run Wiring Internal to Enclosures / Separation/Grouping Cable Requirements (Inside Enclosures) 4.5.33 'MPR Letter, H. Estrada to L. Stalter, dated 10/03/85, Filtering Requirements for Steam Generator Water Level Input to SFRCS, Davis-Besse Unit 1. 4.5.34 Bechtel Calculation No. EC128H Rev.00, Reactor Coolant Pump Monitor Setting, dated 02/04/77. 4.5.35 Calculation No C-IC-083.03-001 Rev.03, Lowering Steam Generator Low and High Level Setpoints. 4.5.36 B&W'letter to TE, SGBM-87-1687, *Task 836 - Determination of SFRCS Startup Range High Steam Generator dP Setpointrdated 12/08/87. 4-21 SD-010 Rev. 4

4.4.15 IEEE C37.90.1-1974 - IEEE Guide for Surge Withstand Capability (SWC) Tests 4.4.16 License Amendment Request 90-46, SFRCS Main Steam Low Pressure Trip Block Permit Setpoint. 4.4.17 USAR Section 7.4.2.3 4.4.18 Technical Requirements Manual Section 3/4.3.2.2. 4.5 MISCELLANEOUS CONTROLLED DOCUMENTS, 4.5.1 Design Criteria Manual 4.5.2 Fire Hazard Analysis 4.5.3 E-1039 - Environmental Qualification Master List 4.5.4 SFRCS - System Review and Test Program (SRTP) Report -Revision D, dated October 27, 1986. 4.5.5 Decay Heat Removal Task Force (DHRTF) -,Final Report- Revision 0, dated 10/15/85. 4.5.6 ICM NED-89-40528, dated January 11, 1989, Incorporation of Decay Heat Removal Task Force Recommendations into the Modification SFRCS. 4.5.7 ICM NEN-87-10349, dated November 24, 1987,. SFRCS Redesign (MOD 87-1107) - RG 1.75. 4.5.8 Letter. TB-6956, dated October 11, 1987, Main Feedwater Control

            'Valves FW-SP6A and FW-SP6B.

4.5.9 DB-OP-06901 - Plant Procedure - Plant Startup. 4.5.10 DB-OP-06903 -Plant Procedure.- Plant Shutdown and Cooldown. 4.5.11 DB-OP-06406- System Procedure -Steam and Feedwater Rupture Control System Operation Procedure. 4.5.12 .DB-PF-02000 - Emergency Procedure - RPS, SFAS, SFRCS Trip or SG Tube Rupture.. 4.5.13 ICM NED-87-40661, from WF Emerson to PW Gaffney, Environmental Qualification of Proposed Power Supplies for, the SFRCS Logic Channels 3 and 4. 4.5.14 MPR.Letter H. Estrada to C. Rupp, May.27, 1987, Startup Range Transmitter Response, TMI-l Turbine Trip Test. 4.5.15 Toledo Letter'to MPR, JA Chlapowski to H. Estrada, September 3, 1987, D-B Steam Generator Level Oscillations. 4.5.16 Test Plan/Procedure No. 60322.2, dated December 14, 1987, Commercial Quality Component Dedication Plan for a SAIC.Signal Monitor and a Dixson Vertical Panel Meter prepared by Farwell & Hendricks, Inc. 4-20 SD-010 Rev. 4

Switch W/J23-1 Valves, PS-3687A & K 4.3.2.51 M-329-36 SH.1 Main Steam Line 2, PS-3689H, PS-3687L 4.3.2.52 M-329-36 SH.2 Main Steam Line 2, PS-3689H, PS-3687L 4.3.2.53 M-329-36 SH.3 Main Steam Line 2, PS-3689H, PS-3687L 4.3.2.54 M-329-36 SH.4 Assembly Dwg for Static "0" Ring Pressure Switch W/J23-1 Valves, PS-3689H, PS-3687L 4.3.2.55 M-329-36 SH.5 Wall Mount Structures for Static "0" Ring Pressure Switches, PS-3689H, PS-3687L 4.3.3 M-304-6 Rockwell Drawing No. PD-423882 SH.5 of 9. 4.4 APPLICABLE USAR SECTIONS, TECHNICAL SPECIFICATIONS, AND REGULATORY DOCUMENTS 4.4.1 USAR Section 7.4.1.3 4.4.2 Technical Specification, Section 3/4.3.2 (Pages 3/4 3-23 through 3/4'3-30d), Safety System Instrumentation 4.4.3 Technical Specification, Section B3/4.3 (Page B3/4 3-1), Instrumentation 4.4.4 NUREG-1177, dated July, 1986 4.4.5 10CFR50,, Title 10, Code of Federal Regulations, Part 50, Domestic Licensing of Production And Utilization Facilities. 4.4.6 IEEE Standard 279-1971, Criteria for Protection Systems for Nuclear Power Plant Protection Systems. 4.4.7 IEEE Standard 338-1971, Criteria for the Periodic Testing of Nuclear Power Generating Stations. 4.4.8 IEEE Standard 384-1984, IEEE Standard Criteria for Independence of Class 1E Equipment and Circuits. 4.4.9 IEEE Standard 344-1975,' Recommended Practices for Seismic Qualification of Class 1E Equipment for Nuclear Power Generating Stations 4.4.10 IEEE Standard 308-1980, IEEE Criteria for Class 1E Power Systems for Nuclear Power Generating Stations. 4.4.11 NUREG-0737, Clarification of TMI Action Plan Requirements 4.4.12 Regulatory Guide 1.105, Instrument Setpoints for Safety Related Systems. 4.4.13 USAR Section 9.4.1.2. 4.4.14 IEEE Standard 383-1974, IEEE Standard for Type Test of Class IE Electric Cables, Field Splices, and Connections for Nuclear Power Generating Stations. 4-19 SD-010 Rev. 4

4.3.2.26 M-329-138 Assembly Dwg for Rosemount Level Transmitter LT-SP9A7 4.3.2.27 M-329-139 Assembly Dwg for Rosemount Level Transmitter LT-SP9A8 4.3.2.28 M-329-140 Assembly Dwg for Rosemount Level Transmitter LT-SP9A9 4.3.2.29 M-329-29 SH. 1 Main Steam Line 1, PS-3687G, PS-3689A & K 4.3.2.30 M-329-29 SH. 2 Main Steam Line 1, PS-3689A, B, E & F 4.3.2.31 M-329-29 SH. 3 Main Steam Line 1, PS-3687G, PS-3689K 4.3.2.32 M-329-29 SH .4 Main Steam Line 1, PS-3687G, PS-3689K 4.3.2.33 M-329-30 SH.1 Main Steam Line 1, PS-3689B & L 4.3.2.34 M-329-30 SH. 2 Main Steam Line 1, PS-3689B & L / 4.3.2.35 M-329-30 SH. 3 Main Steam Line 1, PS-3689B & L 4.3.2.36 M-329-33 SH. 1 Main Steam Line 1, PS-3687G, PS-3689E & M 4.3.2.37 M-329-33 SH. 2 Assembly Dwg. for Static "0" Ring Pressure Switch W/J 23-1 Valves, PS-3689M, PS-3687C 4.3.2.38 M-329-33 SH.3 Wall Mount Structures for Static ".0" Ring Pressure Switches PS-3687C, PS-3689M 4.3.2.39 M-329-34 SH. 1 Main Steam Line 1, PS-3689F & N 43.2..4 0 M-329-34 SH. 2 Wall Mount Structures for Static "0" Ring Pressure Switches PS-3689F & N 4.3.2.41 M-329-34 SH.3 Assembly Dwg. for Static "0" Ring Pressure Switch W/J 23-1 Valves, PS-3689F & N 4.3.2.42 M-329-31 SH. 1 Main Steam Line 2, PS-3687E & M, PS-3689C 4.3.2.43 M-329-31 SH. 2 Main Steam Line. 2, PS-3687E & M, PS-3689C 4.3.2.44 M-329-31 SH. 3 Main Steam Line 2, PS-3687E & M, PS-3689C 4.3.2.45 M-329-32 SH. I Main Steam Line 2, PS-3687N, PS-3689D 4.3.2.46 M-329-32 SH. 2 Wall Mouint Structures for Static "0" Ring Pressure Switches PS-3689D, PS-3687N 4.3.2.47 M-329-32 51.3 Assembly Dwg. for Static "0" Ring Pressure Switch W/J-23-1 Valves, PS-3687N, PS-3689D 4.3.2.48 M-329-35 SH.1 Main Steam Line 2, PS-3689G, PS-3687A & K 4.3.2.49 M-329-35 SH. 2 Wall Mount Structures for Static "0" Ring Pressure Switches, PS-3687A & K 4.3.2.50 M-329-35 SH.3 Assembly Dwg for Static "0" Ring Pressure 4-18 SD-010 Rev. 4

4.3.1.131 E-33-71 General Electric Instruction Book Relay Cabinet CH-2. 4.3.2 Johnson Service Company 4.3.2.1 M-329-681 Tubing Support for I/F PDS-2686A 4.3.2.2 M-329-682 Tubing Support for I/F PDS-2686A 4.3.2.3 M-329-683 Tubing Support for PDS-2686A 4.3.2.4 M-329-202 Small Pipe Support for PDS-2685A & B 4.3.2.5 M-329-208 Small Pipe Support for PDS-2685C & D 4.3.2.6 M-329-209 Small Pipe Support for PDS-2685C & D 4.3.2.7 M-329-203 Barriers for PDS-2685A, B, C &.D 4.3.2.8 M-329-207 PDS-2685C & D 4.3.2.9 M-329-201 PDS-2685A & B 4.3.2.10 M-329-072 SH. 1 PDS-2686A & B 4.3.2.11 Deleted 4.3.2.12 M-329-072 SH. 3 PDS-2686C & D 4.3.2-13 M-329-144 Steam Generator 1 Level Transmitter LT-SP9B6-B9 4.3.2.14 M-329-145 Steam Generator 1 Level Transmitter LT-SP9B6-B9 4.3.2.15 M-329-146 Steam Generator 1 Level Transmitter LT-SP9B6-B9 -4.3.2.16 M-329-151 Steam Generator 1 Level Transmitter LT-SP9B6-B9 4.3.2.17 M-329-147 Assembly Dwg for Rosemount Level Transmitter LT-SP9B6 4.3.2.18 M-329-148 Assembly Dwg for Rosemount Level Transmitter LT-SP9B7 4.3.2.19 M-329-149 Assembly Dwg for Rosemount Level Transmitter LT-SP9B8 4.3.2.20 M-329-150 Assembly Dwg for Rosemount Level Transmitter LT-SP9B9 4.3.2.21 M-329-134 Steam Generator 2 Level Transmitter LT-SP9A6-A9 4.3.2.22 M-329-135 Steam Generator 2 Level Transmitter LT-SP9A6-A9 4.3.2.23 M-329-136 Steam Generator 2 Level Transmitter LT-SP9A6-A9 4.3.2.24 M-329-141 Steam Generator 2 Level Transmitter LT-SP9A6-A9 4.3.2.25 M-329-137 Assembly Dwg for Rosemount Level Transmitter LT-SP9A6 4-17 SD-010 Rev. 4

KA 7251A 4.3.1.108 E-30AQ-107 Connectors KEW. 7354, KEV 7354, KMK 354 4.3.1.109 E-30AQ-108 Envir. Qual. Report - Connector Plug KKN 354 & Receptacle 4.3.1.110 E-30AQ-109 Envir. Qual. Proc. for Connector Plug KKN 354 Series 4.3.1.111 E-30AQ-110 Terminal Board KB 7300AE 4.3.1.112 E-30AQ-111 Envir. Qual. for Terminal Board KB 7300 Series 4.3.1.113 E-30AQ-112 Envir. Qual. Proc. for Terminal Board KB 7300 Series 4.3.1.114 E-30AQ--113 Power Stud Block KNR 3300A 4.31.1.115 E-30AQ-114' Envir. Qual. Report for Terminal Block (Power Block) 4.3.1.116 E-30AQ-115 Envir. Qual. Proc.for Terminal Block (Power Block) 4.3.1.117 E-30AQ-116 Power Transformer KN 7301, KY 2301, KZ 2301 4.3 .1.118 E-30AQ-117 Envir. Qual. Report for Power XFMR KZ 2301A & KY 230 4.3.1.119 E-30AQ7118 Envir. Qual. Proc.for Power 4.3.1.120 E-30AQ-119 Logic Module 6N566-1 4.3.1.121 E-30AQ-120 Envir. Qual. Report for Sequencer Control "A" Module 4.3.1.122 E-30AQ-121 Envir. 'Qual. Proc.for Sequencer.Control "A" Module 4 .3.1.123 E-30AQ-122 Relay KFU 431 4.3.1.124 E-30AQ-123 Envir. Qual. Plan for the Isolation Relay 8N37 4.3.1.125 E -30OAQ- 124 Component Boards KBA 7300 and KBB 7300 E-30AQ-125 4.3:1.126 Seismic Qual. Report for Safety Features Sequencer ' E-30AQ-126 4.3.1.127 Seismic Qual. Report on Keylock Switch 4.3.1.128 E-30AQ-1tr SAIC Operating & Service Manual for Signal Monitor G-CS-436-1 4.3.1.129 M-538-0061 Dixson, Inc. Instrument Division, Description & Installation Instructions 4.3.1.130 M-327AQ-36 Rosemount, Instruction Manual, Model 1152 Alphaline Pressure Transmitters for Nuclear Services. 4-16 SD-010 Rev. 4

System 4.3.1.82. E-30AQ-081 KDM 8317 - Proc. Pack,Ship,Store & Shipping Document 4.3.1.83 E-30AQ-082 KPM 317 - Elect.Static Disch.Sensitive Device Handling Procedure 4.3.1.84 E-30AQ-083 KLB 317 - MOS Device Handling Procedure,- AOM 4.3.1.85 E-30AQ-084 KAH 7276 - Paint & Finish Specification 4.3.1.86 E-30AQ-085 7N287 - Input Panel 4.3.1.87 E-30AQ-086 7N288 - Output Panel 4.3.1.88 E-30AQ-087 KAL 7431 Relay with Diode 4.3.1.89 E-30AQ-088 Wire List, Test Set Relay Driver 4.3.1.90 E-30AQ-089 Transformer 4.3.1.91, E-30AQ-090 Cover, Transformer 4.3.1.92 E-30AQ-091 Cover, Power Plate Assembly 4.3.1.93 E-30AQ-092 Plate, Front Power 4.3.1.94 E-30AQ-093 Plate, Rear Power 4.3.1.95 E-30AQ-094 Terminal Block Panel (Pl) Assembly 4.3.1.96 E-30AQ-095 Sleeve, Solder High Temperature 4.3'.1.97 E-30AQ-096 Switch - Toggle Miniature BAT 4.3.1.98 E-30AQ-097 Thermal Dissipation Calc. for CCC Part 9N124 & 9N125 4.3.1.99 E-30AQ-098 FCP to Install Cover Panels Over Component Boards 4.3.1.100 E-30AQ-099 FCP to Replace Power Plates A7 and A15 4.3.1.101 E-30AQ-100 FCP to Relocate Components on 6N566 Logic Module 4.3.1.102 E-30AQ-101 Terminal Board KKR 330 4.3.1.103 E-30AQ-102 Envir. Qual. Report For Terminal Board - KNL 3300E 4.3.1.104 E-30AQ-103 Envir. Qual. Proc. for Terminal Board - KNL 3300E 4.3.1.105 E-30AQ-104 Relay Socket 4.3.1.10.6 E-30AQ-105 Envir. Qual. Report - Relay Socket KK 251A & KA 7251A 4.3 .1.107 E-30AQ-106 Envir. Qual. Proc. - Relay Socket KK 251A & 4-15 SD-010 Rev. 4

4.3.1.58 E-30AQ-057 KAE 307 - Burndy Terminal, Insulated 4 .3 .1.59 E-30AQ-058 KFZ 327 - Rectifier 35 Amps 50-1000 Volts 4.3.1.60 E-30AQ-059 KL 333 - Contact, Pin 4.3.1.61 E-30AQ-060 KM 333 - Contact, Pin 4.3.1.62 E-30AQ-061 KEW 7354 - Connector, Plug Assembly 4 .3 .1.63 E-30AQ-062 KEV 7354 - Connector, Receptacle Assembly 4.3 .1.64 E-30AQ-063 KGD 7314 - Cable, 60 Conductor #22 4.3.1.65 E-30AQ-064 KKB 7314 - Assembly, Prefabricated Cable 4 .3 .1.66 E-30AQ-065 QS 204 - Inspection of Soldering Materials 4.3.1.67 E-30AQ-066 QSWR 104 - Inspection of Wire-wrapped Connections 4.3.1.68 E-30AQ-067 KDU 7317 - Accept. Test Proc. 28V Supply 4.3.1.69 E-30AQ-068 KDT 7317 - Accept. Test Proc. 48V Supply 4.3.1.70 E-30AQ-069 KAK 7315- Accept. Test Proc. Alarm Output Module 4.3.1.71 ;E-30AQ-070 KDN 8317 - Accept. Test Proc. Cable Assembly (KKB 7341) 4.3.1.72 E-30AQ-071 KAM 731.7 - Accept. Test Proc. Field Buffer 4.3.1.73 E-30AQ-072 KDR 8317 - Accept. Test Proc. Hypot& Power Dist. 9N124 4.3.1.74 E-30AQ-073 KDT 8317 - Accept. Test Proc. Hypot & Power Dist. 9N125 4.3.1.75 E-30AQ-074 KDU 8317 - Accept. Test Proc" Integrated Cabinet Test 4.3.1.76 E-30AQ-075 KEZ 1315 - Accept. Test Proc. Isolation Relay 8N13 4.3.1.77 E-30AQ-076 KDP 8317 - Accept. Test Proc. Logic Module 6N566-1 4.3.1.78 E-30AQ-077 KGU 7317 - Accept. Test Proc. Relay Driver 6N370-1/2 4.3)1.79 E-30AQ-078 KDV 8317 - Accept. Test Proc. Test Set 87N23 (for Field Buffer) 4.3.1.80 E-30AQ-079 KDW 8317 - Accept. Test Proc. Test Set 87N24 (for Relay Driver) 4.3.1.81 E-30AQ-080 KEE 8317 - Input Noise Test Procedure For 9N124 4-14 SD-010. Rev. 4

4.3.1.30 E-3OAQ-029 6N314 - PWB Alarm Output Module Assembly 4.3.1.31 E-30AQ-030 S 6N349 - Schematic Power Supply Module 48V 20A 4.3.1.32 E-3OAQ-031 PL 6N349 - Parts List Module Assembly 48V 20A Unreg PS 4.3.1.33 E-30AQ-032 6N349 - Module Assembly 48V, 20A Power Supply 4.3.1.34 E-30AQ-033 S 6N350 - Schematic Power Supply Module 28V 20A 4.3.1.35 E-30AQ-034 6N350 - Module Assembly 28V, 20A Power Supply 4.3.1.36 E-30AQ-035 PL 6N350 - Parts List Module Assembly 28V 20A Unreg PS 4.3.1.37 E-30AQ-036 KJH 7316 - Logic Cabinet, Power Distrib. Diagram 4.3.1.38 E-30AQ-037 WLKKH 7314 - Wire List, Power Distrib. Logic Cabinet 4.3.1.39 E-30AQ-038 KY 2301 - Power Transformer 4.3.1.40 E-30AQ-039 KJM 7316 - Terminal Arrangement Logic Cabinet 4.3.1.41 E-30AQ-040 KJL 7316 - Terminal Arrangement Termination Cabinet 4.3.1.42 E-30AQ-041 WLKW 7712 - Wire List, Solderless Wrap 4.3.1.43 E-30AQ-042 7N287 - Assembly, Input Panel (Voided by SF-007). 4.3.1.44 E-30AQ-043 7N288 - Assembly, Output Panel 4.3.1.45 E-30AQ-044 8N13 - Assembly, Isolation Relay 4 .3 .1.46 E-30AQ7045 KAA7299-1 - Analog Signal Monitor Rack Assembly 4.3.1.47 E-30AQ-046 KBA 7300 - Component Board Assembly 4.3.1.48 E-30AQ-047 KBD 7300 - Component Board Assembly 4 .3.1.49 E-30AQ-048 S 87N23 - Schematic Test Set Field Buffer 4.3.1.50 E-30AQ-049 87N23 - Assembly, Test Set Field Buffer 4.3.1.51 E-30AQ-050 PL 87N23 - Parts List Test Set Assembly 4.3.1.52 E-30AQ-051 KBH 7361 - PWB Logic Module 4.3.1.53 E-30AQ-052 S 87N24 - Schematic Test Set Relay Driver 4.3.1.54 E-30AQ-053 87N24 - Assembly, Test Set Relay Driver 4.3.1.55 E-30AQ-054 PL 87N24 - Parts List Test Set Assembly 4.3.1.56 E-30AQ-055 KN 251 - Relay Socket 14 Pin 4.3.1.57 E-30AQ-056 KGU 431C - Relay Struthers-Dunn Type 219 4-13 SD-010 Rev. 4

4.3.1.2 E-30AQ-001 KMF 7136 - FCP Addition of Relay with Diode 4.3.1.3 E-30AQ-002 KMA 7136 - FCP Install Bistable Test Rack 7N289 4.3.1.4 E-30AQ-003 KMB 7136 - FCP Test Enable Lockout 4.3.1.5 E-30AQ-004 KME 7136 - FCP Addition of Polycarbonate Covers 4.3.1.6 E-30AQ 005 KMG 7136 - FCP Add. of Manual Init Function'to Q963 4.3.1.7 E-30AQ-,006 S 9N124 - Schematic Logic Cabinet 4.3.1.8 E-30AQ-007 WL 9N124 Wire List, Logic Cabinet 4.3.1.9 E-30AQ-008 PL 9N124 Parts List Logic Cabinet Assembly 4.3.1.10 E-30AQ-009 AL 9N124 - Allocation List, Logic Cabinet 4.3.1.11 E-30AQ-0109 N124- Cabinet Assembly, Logic Cabinet 4.3.1.12 E-30AQ-011 R 9N124 - Installation, Cabinet 4.3.1.13 E-30AQ-012 S 9N125 - Schematic Termination Cabinet 4.3.1.14 E-30AQ-013 WL 9N125 - Wire List, Termination Cabinet 4.3.1.15. E-30AQ-014 PL 9N125 - Parts List, Termination Cabinet 4.3.1.16 E-30AQ-015 9N125 -Cabinet Assembly, Termination Cabinet 4.3.1.17 E-30AQ-016 S 6N566-l - Schematic Logic'Module (Voided by SF-006A). 4.3.1.18 E-30AQ-017 WL6N566-1 - Wire List, Logic Module (Voided by SF-006B). 4.3.1.19 E-30AQ-018 WL6N566 Wire List, Logic Module MOD Red. PS Wiring (Voided by SF-006B). 4.3.1.20 E-30AQ-019 PL 6N566 Parts List Logic Module Assembly 4.3.1.21 E-30AQ-020 6N566-1 PWB Logic Module Assembly 4.3.1.22 E-30AQ-021 S 6N341 Schematic Field Buffer 4.3.1.23 E-30AQ-022 PL 6N341 Parts List PWB Assembly Field Buffer 4.3.1.24 E-30AQ-023 6N341 - PWB Field Buffer Assembly 4.3.1.25 E-30AQ-024 S 6N370-2 - Schematic Relay Driver Module 4.3.1.26 E-30AQ-025 PL 6N370 Parts List PWB Assembly Relay Driver 4.3.1.27 E-30AQ-026 6N370 - PWB Relay Driver Assembly 4.3.1.28 E-30AQ-027 S 6N314 Schematic Alarm Module 4.3.1.29 E-30AQ-028 PL 6N314 Parts List Alarm Output Module 4-12 SD-010 Rev. 4

Steam 4.1.49 OS-012A SH.2 Operational Schematic - Main Feedwater System 4.1.50 OS-017A Operational Schematic - Auxiliary Feedwater System 4.1.51 OS-017B Operational Schematic - Auxiliary Feedwater Pumps and Turbines 4.1.52 Dwg M-566 Instrument Locations (Main Steam Line Press. Switches) Containment & Auxiliary Building Plan EL 623'-0" 4.1.53 Dwg M-569 Instrument Locations (SG Level Transmitters) Containment & Auxiliary Building Plan EL 565'-0" 4.1.54 Dwg M-568 Instrument Locations - (Diff. Pressure Switches) Containment & Auxiliary Building Plan EL 585'-0" 4.1.55 Dwg M-353 Raceway & Grounding - (Cabinet Room) AUX. BLDG. ELEV. 5(623'-0") AREA 7 4.1.56 Dwg E-007 One Line Diagram - 250/125 V DC and 120 V Instrumentation AC - 4.1.57 Dwgý E-009 One Line Diagram - 240 V AC and 120 V AC MCCs (Essential) - 4.1.58 Dwg E-52B SH.49 Elementary Wiring Diagram - Reactor Coolant System RCP Monitor Circuit 4.1.59 Dwg E-580 Station Computer Input/Output List 4.1.60 Dwg E-602 Station Annunciator Input/Output List 4.1.61 Dwg E-60SB Station Annunciator Window Layout 4 .1.62 Dwg E-28 Anticipatory Reactor Trip System Logic Diagram 4.1.63 SD-051 Integrated Control System - System Description 4.1.64 SD-032A Post Accident Monitoring - System Description 4.2 EQUIPMENT SPECIFICATIONS 4.2.1 Technical(Specification for Steam and Feedwater Line Rupture Control System - Specification Number E-30AQ 4.3 VENDOR EQUIPMENT MANUALS AND DRAWINGS 4.3.1 Consolidated Controls Corporation 4.3.1.1 E-30AQ-127 TM 9N124 - Operations and Maintenance Instructions - SFRCS - (Vendor, Manual), Revision - November 1990 4-1i SD-010 Rev. 4

4.1.29.1 Dwg E-30B SH.6A General Guides - Elementary Diagrams - Control Switch and Pushbutton Details 4.1.29.2 Dwg E-30B SH.6B General Guides - Elementary Diagrams - Control Switch and Pushbutton Details 4.1.29.3 Dwg E-30B $H.8 General Guides - Elementary Diagrams - Control Switch and Pushbutton Details 4.1.29.4 Dwg E-30B SH.18 General Guides - Elementary Diagrams - Control Switch and Pushbutton Details 4.1.29.5 Dwg E-30B SH.20 General Guides - Elementary Diagrams Control Switch and Pushbutton Details 4.1.30 Dwg E-545 *SFRCS Connection Diagram - 4.1.31 Dwg E-1595 SFRCS Connection Schedule - 4.1.32 Dwg E-1037P Grounding Standards and Details - 4.1.33 Dwg M-720I Instrument Index - 4.1.34 SD-007 125/250 V DC and 120 V Instrumentation AC -

System Description

4.1.35 SD-012A Main Steam - System Description 4.1.36 SD-013 Anticipatory Reactor Trip (,ARTS) - System Description 4.1.37 SD-014 Main Feedwater System - System Description 4.1.38 SD-015 Auxiliary Feedwater System - System Description 4.1.39 SD-011A Plant Computers - System Description 4.1.40 SD-002 Safety Features Actuation (SFAS) - System Description 4.1.41 SD-039A Reactor Coolant System - System Description 4.1.42 SD-039B Reactor Coolant System Accessories - System Description 4.1.43 SD-044 Reactor Protection System/Nuclear Instrumentation - System Description 4.1.44 SD-041 Steam 'Generator - System Description 4.1.45 SD-001 Station and Instrument Air - System Description 4.1.46. SD-036 Fire Protection -. 'System Description 4.1.47 SD-004 Main Turbine and Auxiliaries - System Description 4.1.48 OS-008 SH.1 Operational Schematic - Main Steam and Reheat 4-10 SD-010 Rev. 4

MS-106, MS-107 4.1.27.15 Dwg E-46B SH.71 Elementary Wiring Diagram - Steam and Condensate AFPT-1 Main Steam In Iso Valves - MS-5889A, MS-5889B 4.1.27.16 Dwg E-46B SH.78A Elementary Wiring Diagram - Steam and Condensate SG Atmospheric Steam Vent Valves ICS11B, ICS11A 4.1.27.17 Dwg E-46B SH.78B Elementary Wiring Diagram - Steam and Condensate SG Atmospheric Steam Vent Valves ICS11B, ICS11A 4.1.28 DRAWING E-65B Elementary Wiring Diagram - MISC. SFAS AND SFRCS CIRCUITS 4.1.28.1 Dwg E-65B SH.1 Elementary Wiring Diagram - SFRCS Input - Channel 1 - Main Steam Line Pressure 4.1.28.2 Dwg E-65B SH.1A Elementary Wiring Diagram - SFRCS Input - Channel 2 - Main Steam Line Pressure 4.1.28.3 Dwg E-65B SH.2 Elementary Wiring Diagram - SFRCS Input - Channel 1 - Main Feedwater < SG Pressure 4.1.28.4 Dwg E-65B SH.2A Elementary Wiring Diagram - SFRCS Input - Channel 2'-u Main Feedwater < SG Pressure 4.1.28.5 Dwg E-65B SH.3 Elementary Wiring Diagram - SFRCS Analog In-put/Output - Channel 1 - SG SFRCS Startup Level 4.1.28.6 Dwg E-65B SH.3A Elementary Wiring Diagram - SFRCS Analog In-put/Output Channel 2 - SG SFRCS Startup Level 4.1.28.7 Dwg E-65B SH.4 Elementary Wiring Diagram - SFRCS Input - Channel 1 - Reactor Coolant Pump Monitor 4.1.28.8 Dwg E-65B SH.4A Elementary Wiring Diagram - SFRCS Input - Channel 2 - Reactor Coolant Pump Monitor 4.1.28.9 Dwg E-65B SH.6 Elementary Wiring Diagram - SFRCS Input - Channel 1 - Operating Bypass 4.1.28.10 Dwg E-65B SH.6A Elementary Wiring Diagram - SFRCS Input - Channel 2 - Operating Bypass 4.1.28.11 Dwg E-65B SH.8 Elementary Wiring Diagram - SFRCS - Channel I - AFW Manual Initiation 4.1.28.12 Dwg E-65B SH.8A Elementary Wiring Diagram - SFRCS - Channel 2 - AFW Manual Initiation 4.1.28.13 Dwg E-65B SH.10 Elementary Wiring Diagram - Anticipatory Reactor Trip System - Input 4.1.29 DRAWING E-30B General Guides - Elementary Diagrams - CONTROL SWITCH AND PUSHBUTTON DETAILS 4-9 SD-010 Rev. 4

FW-SP7B 4,1.27 DRAWING E- 46B Elementary Wiring Diagram - STEAM AND f CONDENSATE 4.1.27.1 Dwg E-46B SH.01A Elementary Wiring Diagram - Steam and Condensate Main Steam Line Iso Valves - MS-100j MS-101 4.1.27.2 Dwg E-46B SH.01D Elementary Wiring Diagram - Steam and Condensate Main Steam Line Iso Valves - MS-100, MS-101 4.1.27.3 Dwg E-46B SH.01E Elementary Wiring Diagram - Steam and Condensate Main Steam Line Iso Valves MS-100, MS-101 4.1.27.4 Dwg E-46B SH.01F Elementary Wiring Diagram - Steam and Condensate Main Steam Line Iso Valves - MS-100, MS-101 4.1.27.5 Dwg E-46B SH.03 Elementary Wiring Diagram - Steam and Condensate Main Steam Lines WU Drain Iso Valves - MS-3.94, MS-375 4.1.27.6 Dwg E-46B SH.04A Elementary Wiring Diagram - Steam and Condensate: AFPT Main Steam In Iso Valve - MS-107 4.1.27.7 Dwg E-46B SH.04B Elementary Wiring Diagram - Steam and Condensate AFPT Main Steam In Iso Valve - MS-107 4.1.27.8 Dwg E-46B SH.32A Elementary Wiring Diagram - Steam and Condensate Main Steam Line Warmup Iso Valves - MS-101-1, MS-100-1 4.1.27.9 Dwg E-46B SH.33 Elementary Wiring Diagram - Steam and Condensate Steam Generator Drain Stop Valves - MS-611, MS-603 4.1.27.10 Dwg E-46B SH.33A Elementary Wiring Diagram - Steam and Condensate Steam Generator Drain Stop Valves - MS-611, MS-603 4.1.27.11 Dwg E-46B SH.46A Elementary. Wiring Diagram - Steam and Condensate Steam Generator AFPT Iso Valves - MS-106A, MS-107A 4.1.27.12 Dwg E-46B SH.46B Elementary Wiring Diagram - Steam .and

                           .Condensate Steam Generator AFPT Iso Valves -

MS-106A, MS-107A 4.1.27.13 Dwg E-46B SH. 54A Elementary Wiring Diagram - Steam and Condensate AFPT Main Steam In Iso Valves - MS-106, MS-107 4.1.27.14 Dwg E-46B SH.54B Elementary Wiring Diagram - Steam and Condensate AFPT Main Steam In Iso Valves-4-8 SD-010 Rev. 4

4.1.21.8 Dwg SF-009 SH.8 Physical Layout Drawing - SFRCS MSIV/MFW Control Valve Reset Switch - Mounting Details 4.1.22.1 Dwg SF-013 SH. 1 CCC - Burndy - AMP - Equivalency Table 4.1.23.1 Dwg SF-014 SH. 1 SFRCS Signal Monitor Rack Al - Module Mounting Cage 4.1.23.2 Dwg SF-014 SH.2 .SFRCS Signal Monitor Rack Al - Air Flow Duct 4.1.24.1 Dwg SF-015 SH.l SFRCS Logic Cabinet - Circulation Fan Support 4.1.24.2 Dwg SF-015 SH.2 SFRCS Logic Cabinet - Circulation Fan Assembly 4.1.25 DRAWING E-42B Elementary Wiring Diagram - MAIN TURBINE 4.1.25.1 Dwg E-42B SH.53 Elementary Wiring Diagram - Turbine Trips - TTAl/3, TTB2/4 4.1.26 DRAWING E-44Bý Elementary Wiring Diagram - FEEDWATER SYSTEM 4.1.26.1 Dwg E-44B SH.04A Elementary Wiring Diagram - Feedwater System - Main Feedwater Stop Valves - FW-612, FW-601 4.1.26.2 Dwg E-44B SH.04B Elementary Wiring Diagram - Feedwater System - Main Feedwater Stop Valves - FW-601 4.1.26.3 Dwg E-44B SH.05 Elementary Wiring Diagram - Feedwater System - Feedwater Isolation Valves - FW-779 4.1.26.4 Dwg E-44B SH.09- Elementary Wiring Diagram - Feedwater System - Main Feedwater Control Valves - FW-SP6A, FW-SP6B 4.1.26.5 Dwg E-44B SH. 14A Elementary Wiring Diagram - Feedwater System - AFP Discharge to SG Valves - AF-3869, AF-3871 4.1.26.6 Dwg E-44B SH. 14B Elementary Wiring Diagram - Feedwater System - AFP Discharge to SG Valves - AF-3869, AF-3871 4.1.26.7 Dwg E-44B SH.15 Elementary Wiring Diagram - Feedwater System - AFP Discharge to SG Valve - AF-3872 4.1.26.8 Dwg E-44B SH.20 Elementary Wiring Diagram - Feedwater System - AFP Discharge to SG Valve - AF-3870 4.1.26.9 Dwg E-44B SH.21A Elementary Wiring Diagram - Feedwater System - Main Feedwater SU Cntrl Vlvs - FW-SP7A, FW-SP7B 4.1.26.10 Dwg E-44B SH.21B Elementary Wiring Diagram - Feedwater System - Main Feedwater SU Cntrl Vlvs - FW-SP7A, FW-SP7B 4.1.26.11 Dwg E-44B SH..21C Elementary Wiring Diagram - Feedwater System - Main Feedwater SU Cntrl Vlvs - FW-SP7A, FW-SP7B 4.1.26.12 Dwg E-44B SH.21D Elementary Wiring Diagram- Feedwater System - Main Feedwater SU Cntrl Vlvs - FW-SP7A, 4-7 SD-010 Rev. 4

4.1.15.,6 Dwg SF-003C SH.6 SFRCS Internal Schematic.Diagram - Annunciator/ Computer Circuits - Q694 4.1.15.7 Dwg SF-003C SH.7 SFRCS Internal Schematic Diagram - Annunciator/ Computer Circuits - Z840, X044 4.1.16.1 Dwg SF-006A SH.1 Schematic Diagram - SFRCS Logic Module - Logic Channel 1 4.1.16.2 Dwg SF-006A SH.2 Schematic Diagram SFRCS Logic Module - Logic Channel 4.1.16.3 Dwg SF-006A SH.3 Schematic Diagram - SFRCS Logic Module - Translation of Inputs and Outputs to Logic Channels 1, 2, 3, and 4 4.1.16.4 Dwg SF-006A SH.4 Schematic Diagram - SFRCS Logic Module Translation of Inputs and Outputs to Logic Channels 1, 2, 3, and 4 4.1.17. Dwg SF-006B SFRCS Logic Module - Wire List 4.1.18. Dwg SF-006D SFRCS Logic Module - PWB Assembly. 4.1.19.1 Dwg SF-007 SH.I SFRCS Input Panel A2 - Panel Layout - Actuation Channel 1 4.1.19.2 Dwg SF-007 SH.2 SFRCS Input Panel A2 - Panel Layout -

                           .Actuation   Channel 2 4.1.19.3  Dwg SF-007 SH. 3   SFRCS Input Panel A2      -   Panel Backview 4.1.20.1  Dwg SF-008 SH. 1,  SFRCS Output Panel A5 - Panel Layout -

Actuation Channel 1 4.1.20.2 Dwg SF-008 SH.2 SFRCS Output Panel AS - Panel Layout - Actuation Channel 2 4.1.20.3 Dwg SF-008 SH. 3 SFRCS Output Panel AS Panel Backview 4.1.21.1 DwgSF-009 SH. 1 SFRCS Cabinet Drawing - Logic Cabinet C5761A / C5792A - Front View 4.1.21.2 Dwg SF-009 SH.2 SFRCS Cabinet Drawing - Logic Cabinet C5761A / C5792A - Rear View 4.1.'21.3 Dwg SF-009, SH.3 SFRCS Cabinet Drawing- Logic Cabinet C5762A / C5792- Front View 4.1.21.4 Dwg SF-009 SH.4 SFRCS Cabinet Drawing - Logic Cabinet C5762A / C5792, - Rear View 4.1.21.5 Dwg SF-009 SH.5 Physical Layout Drawing.- SFRCS Cabinets C5762Z / C5792Z 4.1.21.6 Dwg SF-009 SH.6 Physical Layout Drawing - SFRCS Panels C5762Z / C5792Z 4.1.21.7 not used 4-6 SD-010 Rev. 4

4.1.14.26 Dwg SF-003B SH.26 SFRCS Internal Schematic Diagram - Main Feedwater-2 Stop Valve - FW-601 4.1.14.27 Dwg SF-003B SH.27 SFRCS Internal Schematic Diagram - SG-1 Main Feedwater Iso Valve - FW-780 4.1.14.28 Dwg SF-003B SH.)28 SFRCS Internal Schematic Diagram - SG-2 Main Feedwater Iso Valve - FW-779 4.1.14.29 Dwg SF-003B SH.29 SFRCS Internal Schematic Diagram - Main Feedwater-2 Control Valve - FW-SP6A (SV-SP6A1, SV-SP6A2) 4.1.14.30 Dwg SF-003B SH.30 SFRCS Internal Schematic Diagram - Main Feedwater-1 Control Valve- FWTSP6B (SV-SP6B1, SV-SP6B2) 4.1.14.31 Dwg SF-003B SH.31 SFRCS Internal Schematic Diagram - Main Feedwater-2.Startup Control Vlv - FW-SP7A (SV-SP7A5, SV-SP7A1/3) 4.1.14.32 Dwg SF-003B SH.32 SFRCS Internal Schematic Diagram- Main Feedwater-1 Startup Control Vlv - .FW-SP7B

                            .(SV-SP7B4, SV-SP7B2) 4.1.14.33 Dwg SF-003B SH.33 SFRCS Internal Schematic Diagram - Main Feedwater-l Startup Control Vlv - FW-SP7B (SV-sP7B5, SP-SP7B1/3) 4.1.14.34 Dwg SF-003B SH.34 SFRCS Internal Schematic. Diagram' - Main.

Feedwater-2 Startup Control Vlv - FW-SP7A. (SV-SP7A4, SV-SP7A2) 4.1.14.35 Dwg SF-003B SH.35 SFRCS Internal Schematic Diagram - ARTS Trip

                            -ARTS 1 & ARTS 3 4.1.14.36 Dwg SF-003B SH.36 SFRCS Internal Schematic Diagram - ARTS Trip
                            -ARTS 2 & ARTS 4 4.1.14.37 Dwg SF-003B SH.37 SFRCS Internal Schematic Diagram - Turbine Trip A -    TTA1; TTA3 4.1.14.38 Dwg SF-003B SH.38 SFRCS Internal Schematic Diagram     Turbine Trip B   -TTB2,   TTB4 4.1.15.1  Dwg SF-003C SH.1   SFRCS Internal Schematic Diagram Annunciator/ Computer Circuits - P685,   P684, Q693, Q692 4.1.15.2  Dwg SF-003C SH.2   SFRCS Internal Schematic Diagram -

Annunciator/ Computer Circuits - P681, P680 4.1.15.3 Dwg SF-003C SH.3. SFRCS Internal Schematic Diagram - Annunciator/ Computer Circuits - L886, L896 4.1.15.4 Dwg SF-003C SH.4 SFRCS Internal Schematic Diagram - Annunciator/ Computer Circuits - P671, P672, Q963 4.1.15.5 Dwg SF-003C SH.5 SFRCS Internal Schematic Diagram - Annunciator/ Computer Circuits - Q964 4-5 SD-010 Rev. 4

4.1.14.7 Dwg SF-003BSH.7 SFRCS Internal Schematic Diagram -' Main Steam Line-2 Iso Valve - MS-100 (SV-100E,. SV-10oC/D) 4.1.14.8 Dwg SF-003B SH.8, SFRCS Internal Schematic Diagram - Main Steam Line-.1 Iso Valve - MS-101 ý(SV-101E, SV-101C/D) 4.1.14.9 Dwg SF-003B SH.9 SFRCS Internal Schematic Diagram - Main Steam' Line-i Iso Valve - MS-101 (SV-lOiB, SV-101A) 4.1.14.10 Dwg SF-003B SH.10 SFRCS Internal Schematic Diagram - Main Steam Line-2 Iso' Valve - MS-10,0 (SV-100B, SV-100A) 4.1.14.11 Dwg SF-003B SH.11 SFRCS Internal Schematic Diagram - Main Steam Line-I Warmup Iso Valve - MS-101-1 4.1.14.12 Dwg SF-003B SH. 12 SFRCS, Internal Schematic Diagram - Main Steam Line-2 Warmup'Iso Valve - MS-100-1 4.1.14.13 Dwg SF-003B SH.13 SFRCS Internal Schematic Diagram - AFPT.-1 Main Steam-i In Iso Valve'- MS-l1O6G 4.1.14.14 Dwg SF-003B. SH 14 SFRCS Internal Schematic Diagram - AFPT-2 Main Steam-2 in Iso Valve - MS-107 4.1.14.15 Dwg SF-003B SH. 15 SFRCS Internal Schematic Diagram - AFPT-1 Main Steam-2 In Iso Valve - MS-106A 4.1.14.16 Dwg SF-003B ,SH. 16 SFRCS Internal Schematic Diagram - AFPT-2 Main Steam-! In Iso Valve-, MS-107A 4.1.14.17. Dwg SF-003B SH.17 SFRCS Internal Schematic Diagram - Main Steam Line-i WU Drain Iso Valve - MS-394 4.1.14.18 Dwg SF-003B SN.18 SFRCS Internal Schematic Diagram - Main Steam Line-2 WU Drain Iso Valve - MS-375 4.1.14.19 Dwg SF-003B SH. 19 SFRCS Internal Schematic Diagram - SG-1 Drain Stop Valve. - MS-611 4.1.14.20 Dwg SF-003B SH. 20 SFRCS Internal Schematic Diagram - SG-2 Drain Stop Valve - MS-603 4.1.14.21 Dwg SF-003B SH. 21 SFRCS internal Schematic Diagram - AFPT-I Main Steam In Iso Valve - MS-5889A 4.1.14.22 Dwg SF-003B SH.22 SFRCS Internal Schematic Diagram - AFPT-2 Main Steam In Iso Valve - MS-5889B 4.1.14.2.3 Dwg SF-003B SH.23 SFRCS Internal Schematic Diagram - SG-l Atmospheric Vent Valve -. ICS11B 4.1.14.24 Dwg SF-003B SH. 24 SFRCS Internal Schematic Diagram - SG-2 Atmospheric Vent Valve - ICSilA 4.1.14.25 Dwg SF-003B SH.25 SFRCS Internal Schematic Diagram - Main Feedwater-l Stop Valve - FW-612' 4-4 SD-010 Rev. 4

4.1.13.3 Dwg SF-003A SH.3 SFRCS Internal Schematic Diagram - Input Circuits - Logic Channel 1 4.. 13 .4 Dwg SF-003A SH.4 SFRdS Internal Schematic Diagram -Input Circuits -,Logic.Channel 3 4.1.13.5 Dwg SF-003A SH. 5 SFRCS Internal Schematic Diagram - Input Circuits - Logic Channel 3 Dwg ,SF-003A SH. 6 SFRCS Internal Schematic Diagram - Input Circuits - Logic Channel 3 4 . 1.13 . 7 Dwg SF- 0o3A SH. 7 SFRCS Internal Schematic Diagram - Input Circuits - Logic Channel 2 4 .1 .13 .8 Dwg SF-003A SH. 8 SFRCS Internal Schematic Diagram - Input Circuits - Logic Channel 2 4 .1 .13 .9 Dwg SF-003A SH. 9 SFRCS Internal Schematic Diagram - Input Circuits - Logic Channjel, 2 4.1.13.10 Dwg SF-'b03A SH. 10 SFRCS Internal Schematic Diagram - Input Circuits - Logic Channel 4 4.1.13.11 Dwg SF-003A SH.11 SFRCS Internal Schematic Diagram - Input Circuits - Logic-Channel 4 4 .1.13 . 12 Dwg SF-003A SH. 12 SFRCS Internal Schematic Diagram - Input Circuits -Logic Channel 4 4.1.13.13 Dwg SF-003A SH .13 SFRCS Internal Schematic Diagram - Analog Input Circuits - .Logic Channel 1 4.1.13.14 Dwg SF-003A SH. 14 SFRCS Internal Schematic Diagram - Analog Input Circuits - Logic Channel 3 4.1.13.15 Dwg SF-003A SH. 15 SFRCS Internal Schematic Diagram - Analog Input Circuits - Logic Channel 2 4.1.13 .16 Dwg SF-003A SH.16 SFRCS Internal Schematic Diagram'- Analog Input Circuits - Logic Channel 4 4.1.14.13 Dwg SF-003B SH.I SFRCS Internal Schematic Diagram - Manual Initiation - Actuation Channel 1

4. 1. 14 .2 Dwg SF-003B SH.2 SFRCS Internal Schematic Diagram - Manual Initiation - Actuation Channel 2 4.1.14.3 Dwg SF-003B SH .3 SFRCS Internal Schematic Diagram - AFP-I Discharge to SG-2 Valve - AF-3869 4.1.14.4 Dwg SF-003B SH.4 SFRCS Internal Schematic Diagram - AFP-2 Discharge to SG-1 Valve - AF-3871 4.1.14.5 Dwg SF-003B SH.5 SFRCS Internal Schematic Diagram - AFP-l Discharge to SG-1 Valve - AF-3870 4.1.14.6 Dwg SF-003B SH. 6 SFRCS Internal-Schematic Diagram - AFP-2 Discharge to SG-2 Valve - AF-3872 4-3 SD-010 Rev. 4

4.1.12 .7 Dwg SF-001A SH.6 - Key Switch 4.1.12.8 Dwg SF-001A SH.7A - LED - Input Panel 4 .1.12.9 Dwg SF-001A SH.7B - LED - Input Panel 4.1.12.10 Dwg SF-001A SH.7C - LED - Input Panel 4.1.12.11 Dwg SF-001A SH.8A - LED - Output Panel 4.1.12.12 Dwg SF-001A SH.8B - LED - Output Panel 4 .1.12.13 Dwg SF-001A SH.BC - LED - Output Panel 4.1.12.14 Dwg SF-001A SH.8D - LED - Output Panel 4 .1.12.15 Dwg SF-001A SH.8E - LED - Output Panel 4 .1.12.16 Dwg SF-001A SH.8F - LED - Output Panel 4 .1.12.17 Dwg SF-001A SH.BG - LED -. Output Panel 4.1.12.18 Dwg SF-001A SH.9 - Manual Initiate 4.1.12.19 Dwg SF-001A SH.10 - Relay in Logic Cabinet 4.1.12.20 Dwg SF-001A SH.11A - Shutdown Bypass 4.1.12.21 Dwg SF-001A SH.11B - Shutdown Bypass 4.1.12.22 Dwg SF-001A SH.12A - Terminal Block 4.1.12.23 Dwg SF-001A SH.12B - Terminal Block 4 .1.12.24 Dwg SF-001A SH.13A - Test Switch - Input Panel 4.1.12.25 Dwg SF-001A SH.i3B Test Switch - Input Panel 4.1.12.26 Dwg SF-001A SH.13C Test Switch - Input Panel 4.1.12.27 Dwg SF-001A SH.14A Test Switch - Output Panel 4.1.12.28 Dwg SF-001A SH.14B Test Switch - Output Panel 4.1.12.29 Dwg SF-001A SH.14C Test Switch - Output Panel 4.1.12.30 Dwg SF-001A. SH.14D Test Switch - Output Panel 4.1.12.31 Dwg SF-001A SH.14E Test Switch - Output Panel 4.1.12.32 Dwg SF-001A SH15 Transformer - Relay Cabinet 4.1.13 Dwg SF-003 INDEX F2RCS Internal Schematic Diagram - In dex Sheet 4.1.13.1 Dwg SF-003A SH.1 SF; RCS Internal Schematic Diagram - In] put Circuits - Logic Channel 1 4.1.13.2 Dwg SF-003A SH.2 SFRCS Internal Schematic Diagram - In put Circuits - Logic Channel 1 4-2 SD-010 Rev. 4

4.0 REFERENCES

4.1 DESIGN DRAWINGS AND DOCUMENTS 4.1.1 Dwg M-001 P&ID - Piping Symbols & Diagrams Index 4.1.2 Dwg M-002 P&ID - Instrumentation Symbols 4.1.3 Dwg M-003A P&ID - Main Steam and Reheat System, Sheet 1 4.1.4 Dwg M-003C P&ID - Main Steam and Reheat System, Sheet 3 4.1.5 Dwg M-007A P&ID - Steam Generator Secondary System 4.1.6 Dwg M-007B P&ID - Steam Generator Secondary System 4.1.7 Dwg M-050A Main Steam Line & Main Feedwater Line Rupture Control System Logic 4.1.8 *Dwg M-050B Main Steam Line & Main Feedwater Line Rupture Control System Logic 4.1.9 Dwg M-051 Auxiliary Feedwater Pump Turbine Start Control System Logic 4.1.10 DRAWING E-18 SFRCS Logic Diagram 4.1.10.1 Dwg E-18 SH.1 SFRCS Logic Diagram - Logic Channels 1 & 3 and Actuation Channel 1 4.1.10.2 Dwg E-18 SH.2 SFRCS Logic Diagram -Logic Channels 2 & 4 and' Actuation Channel 2 4.1.10.3 Dwg E-18 SH.3 SFRCS Logic Diagram - Miscellaneous Circuits 4.1.11 DRAWING E-19B SFRCS Actuated Equipment Tabulation 4.1.11.1 Dwg E-19 SH.1 SFRCS Actuated Equipment Tabulation 4.1.11.2 Dwg E-19 SH.2 SFRCS Actuated Equipment Tabulation 4.1.11.3 Dwg E-19 SH.3 SFRCS Actuated Equipment Tabulation 4.1.11.4 Dwg E-19 SH.4 SFRCS Actuated Equipment Tabulation 4.1.12 Dwg SF-001A Index SH.I of 1 SFRCS Translation Tables, Index, Legends, Notes and Miscellaneous 4.1.12.1 Dwg SF-001A SH.I1 - Component Board 4.1.12.2 Dwg SF-001A SH.2A - Fuse 4.1.12.3 Dwg SF-001A SH. 2B - Fuse 4.1.12.4 Dwg SF-001A SH. 3 - Instrument Ground Bus Bar 4.1.12.5 Dwg SF-001A SH. 4 - Isolation Relay 4.1.12.6 Dwg SF-001A SH. 5 - Jacks - Bistable/Indicator Rack 4-1 SD-010 Rev. 4

The steam generators low level bistables are set at 23.5" indicated H2 0- level, which gives a margin of i.36" indicated H2 0 level above the limit required (Reference in Section 4.4.2 and 4.5.35). The low level~limit of 40" is controlled by the ICS (Reference 4.1.63). The steam generators high level bistables are set at 220" indicated H 20 level, which provides a margin above normal operating level. The steam generator high level SFRCS trip does not provide a USAR required safety function. However, the trip enhances the reliable operation of the plant in automatic termination of main feedwater to prevent steam generator overfill and spill over into the main steam lines. For detailed discussion refer to reference in Section 4.5.38. The steam generator low and high level values'referred to above are "indicated" H2 0 level values at a reference point of 1065 psia and 552 -F. Table'i3.3-1 lists also the "actual" values referenced to the top of the lower tube sheet. The Reactor Cooling Pump Motor's full load is approximately 261 A :(hot water), 348 A (cold water), 2000 A inrush (Reference in Section 4.5.34).. The Technical Specification Trip Setpoints of 1384.6 A (or higher) and 106.5 A (or lower) for thecorresponding bistables are well outside the pump motor current during normal. operating conditions. Actual field setpoints are set~to be more conservative than the Technical Specification limits. The steam line pressure switches for low pressure/high level block function are calibrated for contacts to close on decreasing pressure at'720 psig, which provides an early signal to allow the operator to block each channel prior to reaching the trip pressure of 620 psig on cooldown. The bases for the selected setpoints are described in Appendix B. The setpoints given in the System Description are typical/nominal. Refer to the Instrument Index (Reference in Section 4.1.33) for actual setpoint values. 3-2 SD-010 Rev. 4

3.0 SYSTEM LIMITATIONS, SETPOINTS, AND PRECAUTIONS 3.1 OPERABILITY MATRIX This section has been deleted. 3.2 OTHER LIMITS AND PRECAUTIONS To prevent an SFRCS trip during plant cooldown, the following should occur: o Block (Shutdown Bypass) the Main Steam Line Low Pressure-and High Steam Generator Level trip between the shutdown block permissive and prior to low steam line pressure trip.

   .0   'Place     the motor-driven feedwater pump in operation prior to removing the last   Main Feedwater Pump from service.

0 Ensure that both Decay. Heat Normal Suction Valves DHll and DHl2 are fully open before the last RCP is tripped. o Maintain Steam Generator levels at or above 40 inches on Startup Range indication.* Operators and maintenance personnel must be aware of the following: o Deenergizing one logic channel in each protection channel will trip ARTS. Therefore, the associated ARTS trip test bypass switch must be

          *in SFRCS position.

o Testing of an SFRCS input signal will have the same effect as if that input was present and outputs will trip in accordance with the logic for the actual conditions. o Deenergizing of Y1, Y2, YE2 or YF2 will deenergize an SFRCS logic channel. Deenergizing DIP, D2P, DAP, DBP, YAU or YBU will deenergize solenoid valves or will remove the auctioneered power supply to solenoid valves. This action may result in an initiation of selected equipment if the complementary logic channel is under test or deenergized. o The bypassing of Technical Specification required input parameters at the SFRCS input panel is not allowed in modes 1, 2 and 3. 3.3 SETPOINTS Instrument setpoints of the SFRCS input sensors and bistables, the Technical Specification setpoints and the Safety Limits, are shown in Table 3.3-1 SFRCS Setpoints. Low steam line pressure switches are calibrated for contacts to open on decreasing pressure at 620 psig, which gives a safety margin of 28.4 psig above the minimum required (Reference in Section 4.4.2). The minimum steam line pressure under normal operating conditions is approximately 885 psig, with a controlled turbine header pressure of 870 psig. (References in Sections 4.1.35 and 4.1.47). The normal operating pressure at the Differential Pressure switches is approximately 0 psid. The Differential Pressure switches are calibrated for contacts to open at 125 psid increasing differential pressure, positive on the steam side. That gives a margin of 72.6 psid from the required value (Reference in Section 4.4.2) and approximately 125 psid from the normal operating value. 3-1 SD-010 Rev. 4

Steam System. 2.9.6.4 Turbine Trip System The SFRCS provides trip signals to the Main Turbine' Customer trip bus. The main turbine will receive a trip signal under, any SFRCS trip condition. The SFRCS trip interface with the main turbine is different from any other trip, interface. To meet TE's separation requirements the usage of slave relays was necessary. For reference on separation requirements see Reference in Section 4.5.32. The SFRCS output relay in each logic channel provides a dry Form A contact, which drives the slave relay located in the non-iE interface cabinet C5762Z for protection channel 1 and cabinet C5792Z for protection channel 2. Each of the cabinets provides two (2)' fused and independent non-essential power supplies of 125 Vdc to the relay coils. The relays are normally energized, de-energize to trip. Dry Form B contacts from the two slave relays are wired in series and cabled to the cabinets RC4601 and RC4602, respectively, which are located adjacently. Both series connections are wired in parallel between these cabinets and cabled to the Customer Trip Bus of the Main Turbine. On an SFRCS trip both series contacts in either protection channel will closeand energize the Customer Trip Relay using the 125 Vdc provided by the turbine trip system. Either protection channel is capable'of tripping the main turbine independently.,- The trip circuit is fail-to-trip except for the final master trip relay at the main turbine control which is required to pick-up to trip. For the SFRCS trip signal listing refer to Table 2.9-6 SFRCS TripSignals to Turbine Trip System. For SFRCS internal schematic diagrams on Turbine Trip refer to drawings SF-003B SH.37 and SH.38,.Reference in Sections 4.1.14ý.37 and 4.1.14.38. 2.9.6.5 Anticipatory Reactor Trip System Since SFRCS logic channel 1 and logic channel.2 are associated with the same protection channels in the SFRCS and in ARTS, a direct communication of the trip signals was permissible. For logic channels 3 and 4, 1E isolation relays in metal enclosures and separate wire ways were required to interface the mismatch of channels. CAUTION: The trip logic in ARTS is a 2-out-of-4.logic. Anpytwo SFRCS logic channels tripped. (e.g. test trip, loss of power trip, etc.) will initiate a full ARTS trip,. resulting in a Reactor Trip. For the SFRCS trip signal listing refer to Table 2.9-7 SFRCS Trip Signals to ARTS. For reference on separation requirements see Reference in Section.'.4.5.32. 2.9.6.6 Post Accident Monitoring System SFRCS provides the process signal for two PAMS SG startup level indicators located in the control room on cabinets C5798 and C5799. 2-53 SD-010 Rev. 4

SFRCS output relays in both complementary logic channels de-energize and closes its series contacts and energizes and seals-in either the open or closing coil of the motor starter as appropriate. Should the subject valve already be in the SFRCS mode of operation the contact closures of the series contacts will not energize the motor starter circuit, unless the valve is being placed manually in the opposite of the SFRCS mode of operation. For the operational detail of the MOV control refer to 4.1.26. The SFRCS output to MOVs are dry contacts. The control power of the MOV is derived from the power to the MOV. For a complete listing refer to Table 2.9-3 SFRCS Actuated Valves of the Auxiliary Feedwater System. 2.9.6.2 Secondary Plant System The SFRCS provides trip signal to the listed Secondary Plant System motor operated valv'es (MOV) and solenoid operated Valves (SOV). When the SFRCS logic senses a trip condition, the SFRCS output relays in both complementary logic channels de-energize. For MOVs, it closes series contacts and energizes and seals-in the closing coil of the motor starter. Should'the subject valve already be in the SFRCS mode of operation the contact closures of the series contacts will not energize the motor starter circuit unless the valve;is being placed manually in the opposite of the SFRCS mode of operation. For SOVs, the SFRCS output relays open their contacts and de-energize the solenoid-coil(s). For the operational detail of the MOV control refer to 4.1.26. The SFRCS output to MOVs are dry contacts. The control power of the MOV is derived from the power to the MOV' The SFRCS provides the control power to the SOVs. The power is individually fused. In addition, the SFRCS provides the control circuits and the control switches at the center console for each SOV. For a complete listing refer to Table 2.9-4 SFRCS Actuated Valves of the Secondary Plant System.

• 2.9.6.3 Main Steam System The SFRCS provides trip signals to the listed Main Steam System motor operated valves (MOV) and solenoid operated valves (SOY). When the SFRCS logic senses a trip condition, the SFRCS output relays in both complementary logic channels de-energize. For MOVs, it closes series contacts and energizes and seals-in the closing coil of the motor starter. Should the subject valve already be in the SFRCS mode of operation the contact closures of the series contacts will not energize the motor starter circuit, unless the valve is being placed manually in the opposite of the SFRCS mode of operation. If low AFP suction pressure and/or low AFPT steam pressure is sensed, then MS-106, MS-106A, MS-107 and MS-107A will not open when demanded by SFRCS. For SOVs, the SFRCS output relays open their contacts and de-energize the solenoid coil(s). For the operational detail of the MOV control, refer to 4.1.27.

The SFRCS output to MOVs are.dry contacts. The control power of the MOV is derived from the power to the MOV. The SFRCS provides the control power to the SOVs. The power is individual fused. In addition, the SFRCS provides the control circuits and the control switches at the center console for each SOV. For a complete listing refer to Table 2.9-5 SFRCS Actuated Valves of the Main 2-52 SD-010 Rev. 4

2.9.1 Plant Computer The SFRCS transmits digital signals t6 the plant computer. These signals are used for data logging, and sequence of events determination and recording. Refer to Table 2.9-1 Digital Outputs to Annunciator and Computer. See References in Sections 4.1.39 and 4.1.59. 2.9.2 Plant Annunciator The plant annunciator processes two types of signals from the SFRCS, system status and channel status alarms. The system status alarms sum the inputs from the channels to provide an alarm if any of the channels have the condition indicated. Because of limited input capabilities of the plant annunciator and/or station computer, alarm signals are combined. The channel status alarms-indicate the bypass and trip'status of each SFRCS channel. Most of the following alarms are on Alarm Window Panel 12, except for the SFRCS Trip Alarm Q963, which is located at Panel 8 and for the SFRCS Door Alarm which can be found on Panel 5. Refer to Table 2.9-1 Digital Outputs to Annunciator and Computer. For schematics refer to the SFRCS Internal Schematic Diagrams, Reference in Section 4.1.15.1 through 4.1.15.7. See References in Sections 4.1.60 and 4.1.61. The SFRCS Trip Alarm Q963 has an alarm acknowledge push buttonHIS-5891, which is independent from the other plant annunciator acknowledge push buttons. The manual switch is located in the control room on the center .console, Panel C5709. The. function of this manual switch is to ensure that an SFRCS trip condition will be-recognized and acknowledged separately from other incoming alarms. This switch is outside the SFRCS boundary. 2.9.3 Operator Control Panel See Section 2.3.2 for a listing of the SG startup level indicators supplied by SFRCS and located in the control room. The SFRCS provides hand indicating control switches; block switches, manual initiating switches and shutdown bypass (block) switches located at the Center Console and at C5721. For a listing refer to Table:2:9-2'SFRCS Manual Switch Listing. Although not part of the Operator Control Panel, wall mounted cabinets C5762N and C5792N house required operator controls for reset of the Main Steam Isolation Valve and Main Feedwater Control Valve' trips. These cabinets are located in the back of the cabinet room. 2.9.4 Startup Test Panel The SFRCS does not communicate with the Startup Test Panel. 2.9.5 Technical Support Center The SFRCS does not communicate with the Technical Support Center. 2.9.6 Interfaces with other Systems 2.9.6.1 Auxiliary Feedwater System The SFRCS'provides trip signals to the listed Auxiliary Feedwater motor operated valves (MOV). When the SFRCS logic senses a trip condition, the 2-51 SD-010 Rev. 4,

solenoid circuit are separately fused. In addition, the same incoming 120 Vac is being utilized directly to feed, via two (2) fuses, the solenoids requiring 120 Vac. The return is not fused' Each of the logic channel 3 and logic channel 4 power supplies consist of eight (8) fuses, utilizing the station battery power directly. The +125 Vdc supply lead and the floating 125 Vdc Return lead for each solenoid circuit are separately fused. 2.7.3 Loss of Power The SFRCS is a de-energize to trip system.. The-output relays, which may be normally energized, will be selectively de-energized upon an SFRCS Trip condition. All alarm relays will be de-energized and the contacts will open to alarm. Loss of power to a single logic channel will not cause any trip. Loss of power to two complementary logic channels will trip that protection channel. Loss of power to two non-complementary logic channels will exclusively cause to trip the 2-out-of-4 logic of ARTS, which in turn will cause all CRDCS trip breakers to trip. This action will initiate a reactor trip only. Special interlocks were added to those MOV circuits with open and close trip functions to prevent cycling and valve motor burn out for the unlikely eventý of loss of power to two complementary logic channels at the same time.. The overriding function was selected to insure, with a minimum of valve movements, that auxiliary feedwater is supplied by the auxiliary feedwater turbine to the associated steam generator and steam being supplied to the turbine from either steam generator. Refer to Table 2 .7Z3 Valve List with Loss of Power Override Interlocks. 2.7.4 Grounding All voltages generated within the SFRCS are floating: 0 28 Vdc for-logic module interfaces, o 48 Vdc for field contact interfaces and for relay controls, o 36 Vdc for SG Level transmitters, o 125 Vdc,- essential - for solenoid power supply, o 125 Vdc - non-essential - for solenoid power supply. The shields of the analog instrument cables - for the SG level instrumentation are connected to an insulated ground bus and grounded to the station instrumentation ground., The power ground and protective ground and the grounding of the shielded cables to station annunciator and plant computer are in accordance with the grounding requirements and recommendations in the Reference in Section 411.32. 2.8 SPECIAL MATERIAL OR SYSTEM CHEMISTRY CONSIDERATIONS Not Applicable 2.9 SYSTEM INTERFACES 2-50 SD-010 Rev. 4

0 Reference operating temperature 75 - 105'F CAUTION: The Power Source Modules are plug-in modules. After loosening the captive knurled screw at the top and bottom of the module, the module is designed to be removed and replaced with input power present under full load. This option should not be exercised with any of the Power Source Modules in Slots 1 and 2 of either logic channel 1 or logic channel 2. The insertion of either Power Source Module may develop a momentary inrush in excess of 70 amperes on the 120 Vac feeder Y1 or Y2 to the SFRCS. See the SFRCS Operating Procedure (Reference 4.5.11) for details on how to energize the SFRCS. 2.7.2.3 Relay Cabinet Power Distribution All essentials solenoid circuits require two independent power sources of-125 Vdc, one power source for logic channel 1 and logic channel 2 respectively and one power source for logic channel, 3 and logic channel 4. The essentials power distributions in the cabinets C5762A and C5792 are configured as follows: Each of the logic channel 1 and logic channel 2 power supplies consist of o one (1) incoming 120 Vac / 120 Vac isolation transformer, o one (1) full wave rectifier assembly, and o twelve (12) fuses. The +125 Vdc supply lead and the floating 125 Vdc Return lead for each. solenoid circuit are separately fused. Each of the logic channel 3 and logic channel 4 power supplies consist of o twelve (12) fuses, utilizing the station battery power directly. The +125 Vdc supply lead and the floating 125 Vdc Return lead for each solenoid circuit are separately fused. All non-'essential solenoid circuits and the non-essential Main Turbine Trip circuits require two independent power sources, one power source for logic channel 1 and logic channel 2 respectively and one power source for logic channel 3 and logic channel 4. All circuits require 125 Vdc except for two (2) solenoid valves, which require 120 Vac for logic channel 1 and logic. channel 2. The non-essential power distributions in the cabinets C5761A and C5792A are configured as follows: Each of the logic channel 1 and logic channel 2 power supplies consist of o one (l) incoming 120 Vac / 120 Vac isolation transformer, o one (1) full wave rectifier assembly, and o ten (10) fuses. The +125 Vdc supply lead and the floating 125 Vdc Return lead for each 2-49 SD-010 Rev. 4

used for SFRCS circuits interfacing with external components, e.g. pressure switches, and for the output relays: o Input Buffer Module o Relay Driver Module The SFRCS Power Source Modules are AC input/DC output, full wave rectified, filtered, but unregulated voltage sources. The Power Source Module consists basically of a rectifier network used in conjunction with a series filter network. The combination of these two networks provides a rated' output of 28 Vdc and 48 Vdc respectively at 0 to 20 amperes. Both power supplies are not connected together and their Returns (Commons) are floating from ground. The Power Source Modules contain the following protective functions: o A current limiting fuse of 40 amperes in the DC output (internally mounted). o An isolating diode in the DC output. / o Alarm Relay with a normally closed (Form A) contact, open on loss of power. Each Power Source Module has the following features on its front plate: o White indicating lamp, ON with AC power available. o Red indicating lamp, ON with DC power avail-able. o Three output test jacks for voltage measurements. The following are the 48 Vdc power source module performance specifications: o Rated output current 0 to 20 amps DC o AC input 39.78 (34.98 to 44.58) Vac at 117 Vac @ XFMR input o Maximum load 800 W o Output voltage accuracy unregulated o CCC P/N for 48 Vdc Module 6N349-1 o Reference operating temperature 75 - 105OF The following are the,28 Vdc power source module performance specifications: o Rated output current 0 to 20 amps DC o AC input 22.55 (19.73 to 25.37) Vac at 117 Vac @ XFMR input o Maximum load 500 W o Output voltage accuracy unregulated o CCC P/N for 28 Vdc Module 6N350-1 2-48 SD-010 Rev. 4

125 Vdc Distribution Panel DAP, Circuit DAP22 0 SFRCS Relay Channel 4 (C5792) - 125 Vdc Distribution Panel DBP, Circuit DBP16 For listing of the valves refer to Table 2.7-2, Non-Essential Solenoid Valve List. 2.7.2 Internal Power Supplies 2.7.2.1 Logic Cabinet Power Distribution Each of the l1gic.channnel power supplies consist of one (I)'circuit breaker, two (2) transformers and two (2) power source modules. The power supply components are located in the SFRCS Logic Cabinets (C5761A .and C5792A). The incoming power cablelis connected to a 20A circuit breaker at the bottom rear of the cabinet. There are two circuit breakers per cabinet located in the rear of Panel A7, one for each logic channel. The right circuit breaker is labeled CBI and feeds in cabinet C5761A, logic-channel 1 and in cabinet C5792A, logic channel 2. The left circuit breaker is labeled CB2 and feeds logic channel 3 and 4 similarly. The circuit breakers are closed with the lever placed in the upright position. After the, circuit breaker the 120 Vac power is being distributed to the following: o 48 Vdc Power Source Module via Transformer Ti (T3), o 28 Vdc Power Source Module via Transformer T2 (T4), o Signal Monitor, & Bargraph Indicator Rack Al, Slots 1-4 (5-8). The transformer designations shown without parentheses are for logic channel 1 and' for, logic channel 2. The designations. shown in parentheses are for logic channels 3 and 4 accordingly. The power availability is, indicated by white and red lamps, on the front panel of the 48 Vdc and 28 Vdc Power Source Modules. The non-essential power to the circulation fan in either of the Logic Cabinets is routed directly in wire ways and.flexible metal conduit from the, corresponding cabinets C5762Z and C5792Z directly.to the terminals of the fan motor. The circuit breaker for the fan in Logic Cabinet C5761A is in cabinet C5762Z, the circuit breaker for the fan in Logic Cabinet C5792A is in cabinet C5792Z. For the 120 Vac, 48 Vdc and 28 Vdc distribution refer to Drawing E-30AQ-036, Reference 4.3.1.37. 2.7'.2.2 System Power Source Modules (6N350-1 & 6N349-l) The SFRCS requires unregulated +28 Vdc and +48 Vdc power supplies for proper operation each of logic channel. For logic channels 1 or 2 the 28 Vdc Power Source Module is located in Rack A6 at Slot 2 and for logic channels 3 or 4 at Slot 4. The 28 Vdc power is being used for SFRCS internal circuits only: o Logic Module o Input Buffer Module 0 Relay Driver Module 0 Alarm Output Module For logic channels 1 or 2 the 48 Vdc Power Source-Module is'located in Rack A6 at Slot 1 and for logic channels 3 or 4 at Slot 3. The 48 Vdc power is being 2-47 SD-010' Rev. 4

will be tripped. With logic channels'! and 2 not de-energized, no inadvertent SFRCS Trip will occur since SFRCS requires two complementary channels to be tripped simultaneously. After the return of power, the SFRCS automatically resets to its normal mode of operation. Thi's scenario was analyzed and accepted, see References 4.5.13 and 4.5.29. See section 1.2.6 for discussion of degraded Voltage conditions. The SFRCS logic channels, including the SFRCS level transmitters, receive power from the following power sources: o SFRCS Logic Channel 1 (C5761A) - 120 Vac Distribution Panel YI, Circuit Y115 o SFRCS Logic Channel 2 (C5792A) - 120 Vac Distribution Panel Y2, Circuit Y215 o SFRCS Logic Channel 3 (C5761A) - 120 Vac MCC YE2, Circuit YE211 o SFRCS Logic Channel 4 (C5792A) - 120 Vac MCC YF2, Circuit YF211 2.7.1.2 SFRCS Controlled Solenoids System Power Sources The power sources for the SFRCS controlled solenoid valves are from 120 Vac Distribution Panels, from battery backed inverters and"from 125 Vdc Distribution Panels supplied by the station batteries. Only the AC'power distribution system has the capability to'transfer~the supply source to 120 Vac regulated supplies during maintenance of the normal source of 120 Vac. The essential solenoid valves receive essential power from the following power sources: o SFRCS Relay Channel 1 '(C5762A) - 120 Vac Distribution Panel Yl, Circuit Y121 o SFRCS Relay Channel 2 (C5792) - 120 Vac Distribution Panel Y2, Circuit Y221 o SFRCS Relay Channel 3 (C5762A)- 125 Vdc Distribution Panel DIP, Circuit DIP11 o SFRCS Relay Channel 4 (C5792) 125 Vdc Distribution Panel D2P, Circuit D2PlI For listing of the valves refer to Table 2.7-1 'Essential Solenoid Valve List. The non-essential solenoid valves receive non-essential power from the following power sources: o SFRCS Relay Channel 1 (C5762A) 120 Vac Distribution Panel YAU, via Panel Y450i, Circuit 15 o SFRCS Relay Channel 2 (C5792) - 120 Vac Distribution Panel YBU, via Panel*Y4502, Circuit 15 o SFRCS Relay Channel 3 (C5762A) 2-46 SD-010 Rev. 4

or LTC (LTD) as applicable - "ON". This LED confirms that the relay successfully tripped and also a warning that this equipment of this logic channel is tripped and as such the light is located on the side of the complementary logic channel in the vicinity of the complementary test trip button. The green LED LA (LB) - or LC (LD) as applicable - changes.status from normally "ON" to "OFF" to confirm the trip. For a discussion of the various trip confirm functions-refer to Section 2.2.5. See Table T2.1-19 for a description of how the output panel lights function. The test trip condition exists as long as the momentary test push button is depressed. While the trip condition exists, depressing the test block set button TSA (TSB) will energize and seal-in the block relay. The green LED LA (LB) - or LC (LD) as Depressing the test block reset button TRA (TRB) will release the seal-in circuit of the block function. For detailed schematics refer to SFRCS Internal Schematic Diagrams Dwg. SF-003B SH.3 through SH.38 (Reference in Sections 4.1.14.3 through 4.1.14.38) For typical sample drawings refer to Figures 2.2-1 through 2.2-8. The output panel also contains momentary trip test buttons for the manual trip without steam generator isolation (M-l) and with steam generator isolation (M-2). Depressing either button will cause the same response as pressing a single test trip button except that all the affected relays and LEDs will change state within the tested logic channel. Initiation of either manual test trip button M-1 or M-2 will turn a red LED on. The trip and the light will be on for approximately 5 seconds. For a listing of the affected equipment refer to Tables 2.1-14 through 2.1-17. In addition, there is a momentary push button labeled INHIBIT MI/M2. This button, when depressed, simulates SFRCS trip condition and inhibits the manual initiation or resets the manual initiation if already present. For detailed schematic on the manual initiation, refer to SFRCS Internal Schematic Diagrams Dwg. SF-003B SH.I and SH.2 (Reference in Sections 4.1.14.1 and 4.1.14.2) 2.7 ELECTRICAL SYSTEMS AND POWER SUPPLIES 2.7.1 External Power Supplies 2.7.1.1 SFRCS Logic Channel Power Sources The essential instrumentation power distribution system supplies four separate sources (Y1, Y2, YE2 and YF2) of 120 Vac to the SFRCS logic channels, two of which are from battery backed inverters (Y1 and Y2), the other two are emergency diesel generators backed (YE2 and YF2). The power distribution system for Y1 and Y2 also has the capability to transfer the supply source to 120 Vac regulated supplies during maintenance of the normal source of 120 Vac. In the case of loss of Off-site power, Y1 and Y2 will be transferred without interruption to.the battery backed inverters, while buses YE2 and YF2 will be without power for approximately ten (10) seconds until the emergency 'diesels are generating power. During the ten seconds the SFRCS logic channels 3 and 4 2-45 SD-010 Rev. 4

2.6.2 Output Panel (7N288) Each SFRCS protection channel is supplied with one (1) Output Panel. The panel is mounted in Rack/Panel location A5 in the Logic Cabinet. For illustration of the output panel for protection channeli refer to Figure 2.2-11 and for protection channel 2 refer to Figure 2.2-12. The output panel is divided in two-parts. The left half is assigned to logic channel 1 and the right half is assigned to logic channel 3 in protection channel 1. Protection channel 2 is similarly divided, with logic channel 2 on the left side and logic channel 4 on the right side. Both panels contain the same devices and provide the same function for their assigned SFRCS actuated equipment outputs. For a listing of the actuated equipment outputs refer to Tables 2.1-6 and 2.1-

7. For a listing of those valves which are provided with block features refer to Table 2.1-18.

For each SFRCS trip output the following devices are provided as applicable on the panel: o Momentary Test Trip Button TA (TB) for Close or Trip function 0o Momentary Test Trip Button TC (TD) for Open function o Momentary Test Block Button TSA (TSB) for Block Set function o Momentary-Test Reset Button TRA (TRB) for Block Reset function o Green Status Light (LED) LA (LB) for Close or Trip function o Green Status Light (LED) LC (LD) for Open function o Yellow Status Light (LED) LTB (LTA) for Close or Trip function o Yellow Status Light (LED) LTD (LTC) for Open function o Red Block Status Light (LED) LSA (LSB) for Block function. The device identification shown is f6r logic channels 1 and 2, the identification shown in parentheses is for logic channels 3 and 4. The SFRCS output logic is a 2-out-of-2, which'means both associated logic channels must trip in order to initiate the equipment. The test trip button discussed below will only trip one logic channel, therefore rendering the SFRCS output logic to a l-out-of-i as long as the test trip condition prevails. A test of any part of the SFRCS should only-be performed after making sure that no single trip conditions exist. The logic module processes the inputs and issues output trip signals. These signals are fanned out as necessary, looped through the normally closed contact of the test 'trip button TA (TB) - or TC (TD) as applicable -and wired

to the relay driver. The SFRCS provides for each initiated piece of equipment one test trip button, one relay driver circuit andone relay.

Depressing this test button is functionally identical with an automatic trip signal. The relay driver input receives a high signal and deenergizes the associated output relay. A relay contact will turn the yellow LED LTA (LTB) - 2-44 SD-010 Rev. 4

of associated logic channels must trip before the logic module will further process the. signal and issue a trip condition of that channel. The test trip button discussed below will only trip one logic channel, therefore rendering the SFRCS input logic to a 1-out-of-i as long as the test trip condition prevails. A-test of any part of the SFRCS should only be performed after making sure that no single trip conditions exist. '. Each digital input is looped through the normally closed contact of the test trip button T to the field buffer. Depressing this test button is functionally identical with opening the field contact of the process variable. The LED.L monitors the status of the output signal of the field buffer to the input of the logic module. The LED is "ON" while the input is normal and is "OFF" with either or both the field contact and the test buttonx contact opened. The toggle switch, which is normally in the "NORM" position bypasses the field contact when placed in the "BYP" position while the logic channel key switch KS is in the "Bypass" position as well. This feature "resets" the SFRCS inputs to allow channel testing during MODES 4, 5 and 6 when most inputs are tripped without jumpering terminal blocks. The keyswitch is under administrative control. The bypassing of technical specification required inputs in modes 1, 2 or 3 is not allowed. There are no toggle switches provided for the Shutdown Block Switches input and for the local Test Enable Switches which otherwise function similarly. For detailed schematic refer to SFRCS Internal Schematic Diagrams Dwg. SF-003A SH.I through SH.12 (Reference in Sections 4.1.13.1 through 4.1.13.12) For each analog input the following devices are provided on the panel: o Maintained Toggle Test Switch TS, o Three Test Jacks, labeled A, B and C, o Keyswitch KS-LT (one for each logic channel).- The steam generator startup level signals are-looped through normally closed contacts of test switch TS. A normally closed contact of the keyswitch' KS-LT. is wired parallel to the contact "of test switch TS. The test jacks may be used to test the analog signal, (4 to 20 mA) as follows: o A to C Measure the Transmitter Current, (with both switches open). 0 A to B Test the Signal Monitor & Bargraph Indicator with External Current Source, (with both.switches'open). 0 B to C Transmitter Calibration using the SFRCS transmitter power supply by measuring the voltage drop across a calibrated 250 Ohm resistor, with, an additional burden of 500 Ohm resistor connected in series, to simulate normal burden, (with both switches open). The keyswitch KS-LT, is under administrative control, however no restriction of the Mode of the station applies. For detailed schematic refer to SFRCS Internal Schematic Diagrams Dwg. SF-003A SH.13 through SH.16 (Reference in Sections 4.1.13.13 through:4.1.13.16) 2-43 SD-010 Rev. 4

deep. Access doors on the front and the rear requires a minimum of'21 inches to fully swing open.. The front access doors anddthe rear access doors are equipped with ventilation louvers that function by convection. The cabinets are supplied with doors that may be locked for access control. Door alarm switches are installed in each door to provide alarm input to the plant annunciator when the doors are opened. 2.5.4 Non-lE Interfaceý Cabinets The wall mounted Interface cabinets are single door NEMA Type 12 enclosures manufactured by Hoffman (P/N A-423012LP). Each enclosure is approximately 42 inches high, 30 inches wide, and 12 inches deep. The enclosure includes a panel (P/N A-42P30) and lock (P/N A-CLSNI2). All internal equipment is panel mounted. The cabinets are installed to meet the seismic requirements in the control/cabinet room. For further details refer-to Reference.4.1.21.5 and 4.1'.21.6. 2.5.5 Interconnecting Hardware All external wiring to the SFRCS is terminated on terminal or connector panels mounted in the bottom of the cabinets. Individual wires are terminated on barrier-strip terminal blocks. Pre-formed cables are terminated in multi pin connectors, supplied with locking latches. 2.5.6 Normal System Configuration See figure 2.1-16 for normal plant configuration of SFRCS actuated components at 1001 power., 2.6 ANCILLARY INDICATIONS 2.6.1 Input Panel (7N287) Each SFRCS protection channel is supplied with one (1) Input Panel. The panel is mounted in Rack/Panel location A2 in the Logic Cabinet. For illustration of the input panel for protection channel 1 refer to Figure 2.2-9 and for protection channel 2 refer to Figure 2.2-10. The input panel is divided in two parts. The left half is assigned to logic channel 1 and the right half is assigned to logic channel 3 in protection channel 1. Protection channel 2 is similarly divided, with logic channel 2 on the left side and logic channel 4 on the right side. Both panels contain the same devices and provide the same function for their assigned input variables. For a listing of the monitored analog and digital inputs refer to Tables 2.2-1 and 2.2-2. For each digital input the following devices are provided on the panel: o Momentary Test Trip Button T, o Red Indicating. Light (LED) L, 0 Maintained Toggle Switch SB, o Maintained Keyswitch KS (one for each logic channel). The SFRCS input logic is a 2-out-of-2, which means that both input variables 2-42 SD-010 Rev. 4

FUNCTION CHANNEL IDENTIFICATION COLOR-CODE" Logic Cabinet Channel 1 C5761A Green Relay Cabinet Channel 1 C5762A Green Interface Cabinet Channel A C5762Z N/A: PROTECTION CHANNEL 2 FUNCTION CHANNEL IDENTIFICATION -COLOR CODE Logic Cabinet Channel 2 ,,C5792A Orange Relay. Cabinet Channel 2 C5792 Orange Interface Cabinet Channel B C5792Z N/A 2.5.2 Logic Cabinet (9N124-l/2) The free-standing Logic Cabinets are supplied by Eaton/Consolidated Controls Corporation (CCC). The CCC Part Numbers for the cabinet assemblies are 9N124-1 for protection channel 1 and 9N124-2 for protection channel 2. The seismic qualification of the cabinets including the components assembled within the cabinets is documented under Reference,4.'5.27. Each cabinet is approximately 90 inches high, 24 inches wide, and 30 inches deep. Access doors on the front and the rear requires a minimum of 21 inches to fully swing open. The front access doors are equipped with a transparent Lexan window to allow viewing of equipment status without opening cabinet door. The rear doors. areo.equipped with ventilation louvers that function by convection. The cabinet is designed to accept standard 19-inch racks.. The following is a tabulation of the installed racks and panels Identification Function Slots No' Panel AO Spare N/A Rack Al SG Level Instrumentation 1 to 8 Panel A2 Input Panel Assembly N/A Rack A3 Logic-, Input Buffer-, AOM Modules. Al to A16 Rack A4 Relay Driver Modules. Al to AI6' Panel. A5 Output Panel Assembly N/A Rack A6 Power Source Modules 1 to 4 Panel A7 Spare* N/A

• Circuit Breakers installed in rear The cabinets are supplied with doors that may be locked for access control.

Door alarm switches are installed in each door to provide alarm input to the plant annunciator when the doors are opened. 2.5.3 Relay Cabinet (9N125-l/2) The free-standing Relay Cabinets are supplied by Eaton/Consolidated Controls Corporation (CCC). The CCC Part Numbers are 9N125-I for protection channel 1 and 9N125-2 for protection channel' 2. The seismic qualification of the cabinets, fully assembled,. including the components assembled within the. cabinets is documented under Reference 4.5.27. Each cabinet is approximately 90 inches high; 24 inches wide, and 30 inches 2-41 SD-010-Rev. 4

The SFRCS provides the following groups of outputs: 2.4.1 Reactor Trip via ARTS The SFRCS provides reactor trip signals via the ARTS, 'which in turn open the CRDCS trip breakers. For further details refer to the System Description of the ARTS, Reference 4.1.36. Opening of the normally closed SFRCS trip output contacts result in a ARTS trip. 2.4.2 Signals to Plant Computer The SFRCS provides various digital signal inputs to the Plant Computer. For details refer to Section 2.9.1 and for a listing of the alarms see Table 2.9-1. 2.4.3 Signals to Station Annunciator The SFRCS provides various digital signal inputs to the, Plant Annunciator. For details refer to Section 2.9.2 and for listing of the alarms see Table 2.9-1. 2.4.4 Signals to the Startup Test Panel The SFRCS'provides no signal to the Startup Test Panel. 2.4.5 Signals to Technical Support Center The SFRCS provides no signal- to *the Technical Support Center. However, signals from SFRCS actuated valve position or limit switches and Plant Computer output signals are being monitored at the Technical Support Center. 2.4.6 Signals to Post Accident Monitoring The SFRCS provides two SG level signals (LISP9A6A and LISP9B6A) used by PAMS for SG startup level indication in the control room. 2.4.7 Controlled Devices The SFRCS does not interface with any analog controlled devices. The. SFRCS provides Open/Close control for all SFRCS solenoid operated valves. The valves are listed in Tables 2.7-1 and 2.7-2. The'manual control switches are located on the center console. For schematics refer to the SFRCS Internal Schematic Diagrams, Reference in Section 4.1.14.1 through 4.1.14.34. 2.5 SYSTEM ARRANGEMENT 2.5.1 Equipmeht'Layout The SFRCS consists of four (4) free-standing cabinets and two (2) wall-mounted cabinets located in the Control Cabinet Room. These cabinets make up the two (2) redundant and independent protection channels 1 and 2. Each protection channel consists of, one (1) logic cabinet, one (1) relay cabinet, and one (1) wall-mounted non-lE interface cabinet. The logic and relay cabinet of the same protection channel are interconnected electrically by ten (10) prefabricated interconnection cables. The non-1E interface cabinet is the termination cabinet for all non-lE field cables-from and to the logic and relay cabinets. The cabinets are identified'and color-coded as shown below. PROTECTION CHANNEL 1 2-40 SD-010 Rev. 4

The transmitter power supplies are an integral part of the Signal Monitor. For details refer to Section 2.3.1.1. 2.3.12 SFRCS Manual Initiation The SFRCS Trip Switches provide the operator with a means of tripping the SFRCS independent of the automatic actions of the SFRCS. The manual actuation will be overridden or prevented once an automatic SFRCS trip condition is present. There are four (4) trip switches, located on the SFRCS Control Panel on the operators console. The switches' are identified as HIS-6401 through HIS-6404 on operators panel C5707. Pressing switch HIS-6401 will start the Auxiliary Feedwater Pump Turbine .1 (AFPT-I). Main steam to AFPT-l and feedwater from AFP-l will be lined up with SG-I. The cross connection of the auxiliary feedwater to SG-2 will be closed, while the cross connection of the main steam from SG-2 will remain as is; that means for normal system line-up, both steam generators will feed AFPT-l. Further, ARTS and the Main Turbine will' be tripped. For a listing of the actuated equipment refer to Table 2.1-14. Pressing switch HIS-6402 will; similarly, start the Auxiliary Feedwater Pump Turbine 2 (AFPT-2). Main steam to APFT-2 and feedwater.from AFP-2'will be lined up with SG-2. The cross connection of the auxiliary feedwater to SG-l will be closed, while the cross connection of the main steam from SG-1 will remain as is; that means for normal system line-up, both steam generators will feed AFPT-2. Further,. ARTS and the Main Turbine will be tripped. For a listing of the actuated equipment refer to Table '2.1-15. Pressing switch HIS-6403 will start AFPT-l, as described above for switch-,HIS-6401, in addition, all SFRCS isolation valves of SG-l from protection channel 1 will be closed, including the Main Steam Isolation Valve, the Main Steam Warm-up Isolation Valve and the Main Feedwater Valves. For a listing of the actuated equipment refer to Table 2.1-16. Pressing switch HIS-640.4 will start 'AFPT-2, as described above for switch HIS-6402, *in addition, all SFRCS isolation yalves of SG-2 will be closed, including the Main Steam Isolation Valve, Main Steam Warm-up Isolation Valve and the Main Feedwater Valves. For a listing' of the actuated equipment refer to Table 2.1-17. The trip switch is a Cutler Hammer type E30, spring loaded normally closed, momentary action switch. The switch has a guarded press-to-open actuator and two (2) active switch blocks stacked on top ,of each other. For the switches HIS-6401 and HIS-6403',. the first switch block top (nearest the actuator) is logic channel 1 and the second switch block is logic channel 3. Similarly; for the switches HIS-6402 and HIS-6404, the first switch block top, (nearest the actuator) is logic channel 2 and the second switch block is logic channel 4. Pressing the actuator opens the contacts of the switch for both channels. Once pressed, the manual' SFRCS trip switch indicating light in the switch will light for five (5) seconds, acknowledging to the operator that his manual actuation was received by the SFRCS. The indicating light will not be lit or will be turned off immediately if an automatic SFRCS trip condition is present or received.' 2.4 CONTROLLED DEVICES AND INDICATIONS The SFRCS provides signals for control of plant components, for input to other systems, and for plant indications. 2-39 SD-010 Rev. 4

2.3.7.6 125 Vdc Auxiliary Relay (General Electric) The auxiliary relay, employed in the reactor coolant pump monitoring circuitry is a General Electric type 12HGA11J52 relay. The following are the time delay relay performance specifications: o Coil Voltage 125 Vdc o Contact Arrangement Double Pole Double Throw o Contact Rating (at 48 Vdc)' 8 Amps Non-Inductive 3 Amps Inductive

• More information on this relay can be found in Reference 4.3.1.131.

2.3.8. Door Alarm Each of the four SFRCS cabinets is equipped with one (1) front and one (1) rear access door. 'The doors are normally closed and locked. One key fits *one cabinet only. The keys are under administrative control. The position of each door is monitored by a limit switch. The limit switch contact opens with the door open. The contacts of the eight (8) door limit switches of the Logic and Relay Cabinet of one protection channel are looped together and energize a relay while the doors are closed. The relay output contact alarms the SFAS, RPS, ARTS, OR SFRCS DOOR OPEN alarm Z840 ,at the station annunciators and plant computer. 2.3.9 Fan Failure Detector Each of the SFRCS Logic Cabinets C5761A and C5792A are provided with a fan mounted at the top of the cabinet. A fan failure detector is not provided. The fan operation is being monitored by inspection during routine surveillance testing. The fan, which runs continuously, circulates the air within the cabinet to prevent built up of potential heat pockets. The SFRCS system is. designed to operate indefinitely With natural heat circulation without the operation of the fan. The rear doors of all SFRCS cabinets are provided with louvers for natural heat exchange. The SFRCS Relay Cabinets and the SFRCS Interface Cabinets have no fans. 2.3.10 Key Switch The SFRCS employs four (4) key switches for channel bypass, one for each logic channel. The key switches control the access to the channel bypass features to allow testing in Modes 4, 5, and 6 as defined in the Technical Specifications (Reference in Section 4.4.2). The keys are under administrative control. For further details refer to Section 2.1.2.5.1. The SFRCS also employs four (4) key switches for transmitter/bistable calibration and testing, one for each logic channel. The key switches control the access to the transmitter input~bypass to allow testing in all modes. The keys are under administrative control. For further details refer to Section 2.6.1. 2.3.11 Transmitter Power Supplies 2-38 SD-010. Rev. 4

1. The time delay relays for the manual initiation circuits are industrial electropneumatic AGASTAT Series 7000 Timing Relays. The Manufactures model number is P/N 7012NC.

The following are the time delay relay performance specifications: 0 Adjustable Time Range 1.5 to 15 seconds 0 Repeat Accuracy + 5% of setting 0 Coil Voltage 48 Vdc 0 Relay Release (Recycle) Time 50 ms maximum 0 contact Arrangement Double Pole Double Throw 0 Contact Rating 1.0 A, Resistive at 125 Vdc 10.0 A, Inductive at 120Vac o Operation On-Delay Reference Section 4.6.28.

2. The time delay relays for the RCP Monitor circuit utilizes an Agastat P/N 7022PJ.

The following are the time delay relay performance specifications: 0 Adjustable Time Range 3 to 120 cycles 0 Repeat Accuracy +/- 5% of setting 0 Coil Voltage 125 Vdc 0 Relay Release (Recycle) Time 50 ms maximum 0 Contact Arrangement Double Pole Double Throw 0 Contact Rating 1.OA, resistive at 125 Vdc 10.OA, inductive at 120 Vac o Operaton Off-Delay 2.3.7.5 AOM Output Relay (KG7331A) The alarm output module (AOM) output relay is a Reed Relay made by Douglas Randall, Division of Kidde (P/N 378686). This reed relay has one (1) Form A contact. The contact rating is 100 Wdc @ 3A or 250 Vdc. The contact must be arc suppressed for inductive load application. The operate and release time is 5 msec maximum. The coil 'must operate' voltage is 17 Vdc and the 'must release' voltage is 3.5 Vdc. The coil dc resistance is 2900 Ohm, + 10%. The relay is an integral part of. the alarm output module, for details refer to Section 2.3.6. 2-37 SD-010 Rev. 4

the SFRCS output relay described in Section 2.3.7.1. The relay is an 300 Volt general purpose, plug-in, electromechanical relay, 219 Series from Struthers Dunn (P/N 219BBX194), installed in a metal enclosure and metal barriers internal to the enclosure separating the coil and the contact areas. The relay has two (2) Form C (2PDT) and two (2) Form A (NO) contacts, from which only the two Form C contacts are accessible. The contact ratings for typical voltages used for the SFRCS are: Break Volts Make Carr Resistive Inductive 48 Vdc 30 A 10 A 1 A 0.3 A 125 Vdc 30 A i0 A 0.5 A 0.1 A 120 Vac 30 A 10 A 10 A 3 A The nominal coil voltage is 48 Vdc with a coil resistance of 870 to 1000 Ohm @ 25 0 C. The response time of the relay by itself, based on the manufacturer's information is as follows: Operate time is 25 ms maximum and release time is 20 ms maximum. The relay is being driven directly by the Relay Driver Module. This driver has as integral part an arc suppressing diode installed across the output which slows down the release time of the relay to approximately 50 ms. The operate time is not affected by the arc suppressor. The relay requires a 12-pin mating socket for installation. A locking device comprised of two springs holds the seismically qualified relay in place. 2.3.7.3 125 Vdc Auxiliary Relay (Struthers Dunn) The auxiliary relay, employed in the SFRCS Interface Cabinets C5762Z and C5792Z is an 300 Volt general purpose, plug-in, electromechanical relay, 219 Series from Struthers Dunn (P/N 219XDXP) with four (4) Form C contacts (Four Pole Double Throw - 4PDT). The relay is identical to the SFRCS output relay except for the 115-125 Vdc coil. The contact ratings for typical voltages used for the SFRCS are: Break Volts Make Carr Resistive Inductive 48 Vdc 30 A 10 A 1 A 0.3 A 125 Vdc 30 A 10 A .0.5 A 0.1 A 120 Vac 30A 10 A 10 A 3 A The Aominal coil voltage is 125 Vdc with a coil resistance of 6.2 kOhm + 15% @ 25°C. The response time of the relay by itself, based onthe manufacturer's information is as follows: Operate time is 25 ms maximum and release time is 20 ms maximum. For applications with an arc suppressing diode across the coil the release time of the relay will be slowed down to approximately 70 ms. The operate time will not be affected by the arc suppressor. The relay requires a.14-pin mating socket for installation. A locking device comprised of two springs holds the relay in place. For Reference see Section 4.6.27. 2.3.7.4 Agastat Adjustable Time Delay Relays 2-36 SD-010 Rev. 4

IC5792. o The 1E Isolation Relay to ARTS, installed in the Relay Cabinets C5762A and C5792. o The 125 Vdc Auxiliary Relay (Struthers Dunn), installed in the SFRCS Interface Cabinets C5762Z and C5792Z. o The Agastat adjustable time delay relay, installed inthe Relay Cabinets C5762A, C5792, RC 3601, RC 3602, RC 3603 and RC 3604. 0 The Alarm Output Module (AOM) Output Relay, an integral part of the AOM, installed in the Logic Cabinets C5761A and C5792A. o The 125 Vdc Auxiliary Relay (General Electric), installed in Relay Cabinets RC 3601, RC 3602, RC 3603 and RC 3604. 2.3.7.1 48 Vdc SFRCS Output Relay (KGU431C) To interface the SFRCS with external equipment a single type of output relay is employed. The exceptions are the alarm'outputs (refer to Section 2.3.7.5), the isolation relay to ARTS for logic channels 3 and 4 (refer to Section 2.3.7.2), the auxiliary relays for the turbine trip (,refer to Section 2.3.7.3) and the Agastat time delay relay (refer to Section 2.3.7.4). The SFRCS output relay is an 300 Volt General Purpose; Plug-in, Electromechanical Relay, 219 Series from Struthers Dunn (P/N 219XDX162) with' four (4) Form C contacts (Four Pole Double Throw - 4PDT). The contact ratings for typical voltages used for the SFRCS are: Break Volts Make Carry Resistive Inductive 48 Vdc 30 A I0 A 1 A 0.3 A 125 Vdc 30 A 10 A 0.5 A 0.1 A 120 Vac 30 A 10 A 10 A 3 A The nominal coil voltage is 48 Vdc with a coil resistance of 870 to 1000 Ohm @ 25°C. The 'must operate' voltage is 38.4 Vdc minimum. The response time of the relay by itself, based on the.manufacturer's information is as follows: Operate time is 25 ms maximum and release time is 20 ms maximum. For most relay applications in the SFRCS the relays are being driven directly by the relay driver module. These drivers have an arc suppressing diode across the output which slows down.the release time of the relay to approximately 50 ms. The operate time is not affected by the arc suppressor. The relay requires a 14-pin mating socket for installation. A locking device comprised of two.springs holds the seismically qualified relay in place. 2.3.7.2 lE Isolation Relay (8N13), The 1E isolation relay is being used in logic channel 3,' which is part of the SFRCS protection channel 1. This channel has to communicate with the ARTS protection channel 3. Likewise, an isolation relay is required in logic channel 4, which is required in SFRCS protection channel 2 to communicate with' the ARTS Channel 4. The isolation relay is an assembly of a metal enclosure with an internal metal barrier, a 12-pin relay socket and a plug-in relay. The relay is similar to 2-35 SD-010 Rev. 4

o Input Current Logic "1" 15 - 20 mA @ 28Vdc Logic "0" appr. 0.20.mA o Field Voltage 48 Vdc o Output Current 500 mA max. @ 48 Vdc o Circuits per Module 8 o Power Supply +48 Vdc, 100 - 4000 mA

                                                      +28 Vdc,   150 mA o     Response Time driving 1 relay            appr. 50 msec o     Reference Operating Temperature          75 to 105 OF (for above data) o     Operating Temperature Range              40 to 150 OF o     Arc Suppression Diode                    IN4002,   across output For Reference see Section 4.3.1.1.

2.3.6 Alarm Output Module (6N314-1) The alarm output modules are packaged in standard one unit wide modules. The alarm output module provides 1500 Vac isolation between the common potential of the logic circuit input signal and the relay contact output signal. There are ten (10) independent alarm circuits on each module. On the front, board mounted are two test jacks to measure the on board regulated 12 Vdc. The 12 Vdc test jack is resistor buffered. The module is designed to satisfy the IEEE 384 isolation requirements, except for the physical installation within the SFRCS cabinets. With the circuit and cable configurations at Davis-Besse the 1E / non-iE requirements for Davis-Besse are met. The alarm output circuitry responds to a logic- ,1 at its input with energizing the output relay and closing the relay contact. For relay details refer to Section 2.3.7.5. The logic side'uses +28 Vdc unregulated power supply. An on board regulation is provided to accept the varying power source conditions. The relay contacts are dry. The alarm output modules are provided with on board auctioneering diodes if power supplies from two sources are provided. This option is currently not being used. Refer to Table 2.3-4 Alarm Output Module Output Listing. This list identifies, for each protection channel separately, the alarm output module location (Rack - Slot A/Slot B), the alarm output circuit number, the - . associated field device being alarmed in either complementary iogic channel and the alarm ID # used in the SFRCS, with slot B complementary to slot A. 2.3.7 Electromechanical Relays-The SFRCS employs six (6) different types of relays: 0 The 48 Vdc SFRCS Output Relay, installed in the Relay Cabinets C5762A and 2-34 SD-010 Rev. 4

o Output Signal Stretcher 2. 0 sec o Input Time Delay for Diff. Press. 0.5 sec o Power Supply +28 Vdc, unregulated o On Board regulated Power Supply +15 VDC o Reference Operating Temperature 75 to 105 OF o Response Time Input to Output 2 to 3 ms o Solid State Devices CMOS Devices, 14-/16-Pin Package o Operating Temperature Range 40 to 150 OF For Reference see Section 4.3.1.1. 2.3.5 Relay Driver Module (P/N 6N370-2) The relay driver modules are packaged in standard one unit wide modules. The Relay Driver provides adequate current to energize the output relays of the system. Each driver can produce the current to energize four (4) relay coils wired in parallel. The relay driver circuit provides 1500 Vac isolation between the common potential of the logic circuit and the reference potential of relay coil output signal. There are eight (8) independent drivers on each module. On the front, board mounted, are test jacks to monitor the input signal status and the output signal status for each of the eight drivers. In addition, test jacks are provided to measure the incoming voltages of +48 Vdc and +28 Vdc against their returns. The test jacks are resistor buffered. The relay driver circuitry responds to a logic "1" at its input with a high current drive to its output. The logic side uses +28 Vdc unregulated power supply. The control side , utilizes the +48 Vdc unregulated power supply. The relay driver modules are provided with on board auctioneering diodes if power supplies from two sources are provided. This option is currently not being used. All relay driver modules are exclusively installed in Rack A3. The SFRCS employs six (6) Relay Driver Modules and provides one (1) reserved slot for future use for each of the four logic channels. The spare slot locations are A3-A7 and A3-AI0. The slots A3-A8 and A3-A9 are unused without any power distribution for future expansion. Refer to Table 2.3-3 Relay Driver Module Output Listing. This list identifies the relay driver module location (Rack - Slot A/Slot B), the' relay driver circuit number, the actuated equipment for protection channel 1 (Cabinet C5761A), the actuated equipment for protection channel 2 (Cabinet C5792A) and the action used in the SFRCS, with slot B complementary to slot A. The following are the relay driver module performance specifications (Note: .Not all of the performance specifications are contained in other design documents and must be evaluated or verified prior to use (See CR 02-07256): 2-33 SD-010 Rev. 4

A signal stretcher is provided for each bonafide variable trip condition to extent the trip signal to a minimum of 2 seconds regardless of the length of the input signal. After two seconds, the trip output signal will reset when the trip condition of the variable ceases to exist. The 2 second minimum trip duration ensures that all actuated equipment had sufficient time to seal-in or to de-energize, as applicable. The logic module provides independent output current drivers where a fan-out is required by the SFRCS logic diagram (Reference in Section 4.1.10) rather than having one output current driver only and an wired fan-out instead. The specified grouping of fan-outs is designed to minimize potential component failures affecting the plant. The handling of the CMOS devices and of the logic module shall be in accordance with the handling precautions. All CMOS devices should be stored or transported in materials that are antistatic only. Usage of ground straps when handling is required. For detailed precautions see Reference in Sections 4.3.1.82 and 4.3.1.83. Caution is required with an apparent inconsistency of pin references in various design drawings: The printed circuit board employs - as described above - exclusively 16-pin sockets only. The logic uses 16-pin and 14-pin devices. The 14-pin device shall always be inserted such that pin 1 of socket and pin 1 of the device mates. This means that pins 1 through 7 of socket and device matches the assigned pin designations. Pins 8 through 14 of the device will engage in pins 10 through 16 of the socket. The notation on schematic diagrams - unless noted differently - shows the pins of the device, while the wiring list refers to the pins of the sockets, because that is where the wire has to be connected. The Logic Modules are packaged in standard one unit wide modules. On the front, board mounted, are test jacks to monitor the clock frequency and the various power supply voltages: Incoming voltage of +28 Vdc and internally generated regulated voltage of +15 Vdc and unregulated, but filtered + 26 Vdc against the returns. The test jacks are resistor buffered. The Logic Modules are provided with on board auctioneering diodes if power supplies from two sources are provided. This option is currently not being used. For the input and output signals connected to the logic modules refer to Table 2.3-2, Logic Module Input/Output Listing. Slot Al in Rack A4 is the assigned slot location of the logic module for.logic channel 1 and logic channel 2, respectively. Similarly, Slot A16 in the same rack is the slot location of the logic module for the logic channels 3 and 4. The following are the logic module performance specifications: o Input/Output Signal Logic "1" < 2 Vdc Logic "0" > .26 Vdc 0 Input Filtering, Noise, Contact, 2 to 3 ms duration J Bouncing etc. 0 High Voltage Input Protection up to 400 V 2-32 SD-010 Rev. 4

power consumption. The CMOS devices being used are standard commercial integrated circuits with an extended temperature range and are burned-ini to minimize infant mortality. The logic module is fully socketed. The printed wiring board is equipped with sixty (60) 16-pin sockets arranged out in 6 rows by 15 columns. The rows are labeled 1 to 6 and the columns A to R. Thus, the row-column number provides an unique CMOS device location reference. The sockets are provided with wire-wrap pins. A multi-pin connector, also provided with wire-wrap pins, interfaces with the SFRCS system. The Logic module receives the unregulated 28 Vdc available in the SFRCS. The board contains its own regulated power supply circuitry. The regulated voltage for the CMOS devices is 15 Vdc. To interface with the relay drivers the logic module uses filtered but unregulated 26 Vdc. All inputs signals to the logic module are filtered. An in-line diode, which is pulled up to 28 Vdc with a resistor, protects against high voltage propagation up to approximately 400 Vdc. An RC network with a time constant of approximately 2 to 3 ms prevents unwanted noises and switch bouncing being processed by the logic module. Except for the printed wiring which for the most part is for component power supply, all other wiring is done by wire-wrapping. Wire-wrapping provides high reliable connections and at the same time provides high flexibility for expansions and/or logic changes. The logic module provides two (2) optical outputs DS1 and DS2 with LEDs mounted near the edge of the board to make them visible when installed in the SFRCS through the cabinet's see-through front doors. The function of DS1 is to provide an indication when any of the inputs from the complementary channels are tripped. The light is normally "ON". The function of DS2 is to provide a flashing monitoring light of approximately 1 Hz frequency. The flashing light is an indication that the on-board clock is working. The clock circuit, which is driven by a quartz time base crystal with fundamental frequency of 20.48 kHz, outputs to the various "ON"- and "OFF"-time delays. A loss of the clock signal will impair all time delays, but will not effect the trip signals with one exception: The differential pressure signal circuit with its 1/2 second "ON"-time delay will be non-functional. A loss of the clock signal will be alarmed together with the loss of signal alarms from the complementary inputs. The logic module expects a logic "1" on the input ports and issues a logic "1" signal on the output ports with no trip condition present. The logic "1" translates to approximately 2 Vdc. With the trip condition (logic "0") the voltage changes to 26 to 28 Vdc at the logic module outputs. For the CMOS devices "high" or logic "1" translates to a minimum of 14.3 Vdc, although the device will accept a signal above 7.8 Vdc still as a "high". The "low" signal range is approximately between 1.8 and 1.2 Vdc. This value applies to the 15 Vdc power supply. A single shot circuit feature is provided for the shutdown block signal. This signal is originated from a momentary control switch at C5721 and buffered by the input buffer module. The circuit shall prevent a permanent "block" signal from, for example, a stuck switch or a wire short. Once the signal is received the circuit blocks out any signal from this input after about a millisecond until the input opens again. Without this feature the logic module would inadvertently "automatically" block the steam line pressure trip and high level trip when its input decreases below the trip setpoint if one of the above failures were present. 2-31 SD-010 Rev. 4

regulation to accept the varying power source conditions. The input contact, when closed, connects 48 Vdc Return to the input of the control side. The input current is approximately 4 mA. The output of the logic side employs a high-current driver to interface with the Logic Module. The field buffer modules are packaged in standard one unit wide modules. On the front, board mounted, are test jacks to monitor the input signal status and the output signal status for each of the ten channels. In addition, test. jacks are provided to measure the incoming voltages of +48 Vdc and +28 Vdc against their returns. The test jacks are resistor. buffered. The field buffer modules are provided with on board auctioneering diodes if power supplies from two sources are provided. This option is currently not being used. For the input signals connected to the field buffer modules refer to Table 2.3-1, Field Buffer Module Input Listing. This list identifies the field buffer module location (Rack - Slot), the module circuit number, the SFRCS signal for protection channel 1 (Cabinet C5761A) and protection channel 2 (Cabinet C5792A) used in the SFRCS. Slots A6 and All in Rack A4 are assigned spare slots for field buffer modules. The following are the field buffer module performance specifications (Note: Not all of the performance specifications are contained in other design documents and must be evaluated or verified prior to use. (See CR 02-07256): o Input Current appr. 16.5 mA o Input Impedance appr.3 kOhm o Field Voltage 48 Vdc o Output Voltage Logic 1" appr. 1.2 Vdc Logic "0" appr. 27 - 32 Vdc o Circuits per Module 10 o Power Supply +48 Vdc @ 150 mA

                                                +28 Vdc @ 170 mA o     Response Time                      25 msec (20 to 30 msec) o     Reference Operating Temperature    75 to 105. F (for above data) o     Operating Temperature Range        40 to 150 OF For. Reference see Section 4.3.1.1.

2.3.4 Logic Module (6N566) All of the SFRCS solid state logic functions are provided by the logic module. For detailed description of the circuitry refer to Reference in Section 4.3.1.1 and reference drawings in Section 4.1.16. The module uses CMOS devices of the 4000 series for high reliability and low 2-30 SD-010 Rev. 4

The power requirement for each indicator module is 115 Vac (103.5 to 126.5 Vac) with ii VA and an inrush of approximately 1.35 A maximum. Each logic channel has its independent power supply. A 3/16 A, slow blow, style 3AG fuse is provided within the module assembly, the module has to be removed to replace the fuse. An additional 0.25A fuse is installed within the Dixson bargraph enclosure, a replacement of this fuse requires a disassemble of the enclosure. For power supply details refer to Section 2.7.2.1. The indicator modules are packaged in standard one unit wide modules. The calibration access area for the Zero Adjustment and the Gain Adjustment is on the bottom of the module. All 12 SG startup level indicators have a 0-300" H2 0 meter scale. The following are the bargraph indicator module performance specifications: o Linearity Digital/Bar + 0.02% of F.S. / + 1 count* o Accuracy Digital/Bar + 0.05% of F.S. / + 1 count* o Zero Stability + 0.01%/°C o Gain Stability

• 0.02%/°C o Input Impedance 100 Ohm + 0.05%

o Input Signal 4 to 20 mADC 0 Response Time 300 msec max. o Overload Signal + 200% or 250 Vdc max. o Resolution Bar/Digital 1% / 0.01% o Operating Temperature Range to 60 0C o Storage Temperature Range -40 to +85 0C 0 AC Power Requirements 115 Vac (103.5 to 126.5), 60 Hz, 11 VA max.

• 1 count is equivalent to 3.0" of the range of 0-300.0" (F.S.)

The bargraph indicator module can be removed from its location indefinitely and/or replaced under power without causing any harm to the electronic components nor will the corresponding signal monitor be affected including its digital and analog output signals. 2.3.3 Field Buffer Module (P/N 6N341-1) The field buffer module is a general purpose digital isolator. The field buffer provides 1500 Vac isolation between the input signals and the logic common of the output signal. This module has ten (10) channels. An input ,contact closure will result in an output logic "1". Each of the ten channels is independent of the other channels. The control side utilizes +48 Vdc unregulated power supply. The logic side uses +28 Vdc unregulated power supply. Each channel provides its own 2-29 SD-010 Rev. 4

2.3.2 Dixson Bargraph Indicator Module (SAI01) The Dixson Bargraph Indicator Module is designed to plug into the SAIC Rack, Al, Slot locations 2, 4, 6 and 8. This indicator is also used in the control room on panels C5708, C5710, C5798, and C5799 for SG startup level indicators fed by SFRCS. The indicators on C5798 and C5799 are used for Post Accident Monitoring. The Module is composed of an Edgewise Bargraph Indicator Model SAI01-1E from Dixson, Inc. and abargraph mounting module (P/N 141660100) designed and provided by SAIC. The analog display in the bar mode consists of 101 visible segments with a 4" long scale with a resolution of 1.0 6, the scale is vertically oriented. An additional 4-digit LED display with one decimal point and a resolution of 0.01 % is provided. Both displays contain nominal dampening of the input signal to limit flickering. For Reference see Section 4.3.1.129. The input signal range of the indicator module is 1 to 5 Vdc. A 250 Ohm resistor installed on the backplane of the SAIC Rack Al converts the 4 to 20 mA loop signal into the required 1 to 5 Vdc. This arrangement allows removal of the indicator module (e.g. for maintenance) without interrupting the current loop to the signal monitor. The indicator has a zero and span adjustment internally. The display range is 0 to 300"' water. The following Dixson bargraph indicator modules, installed in the SFRCS Logic Cabinets, are supplied by the SFRCS. The indicator identification along with the monitored steam generator, logic channel, rack and slot location and cabinet is given. Indicator SG Logic Ch. Location Cabinet LI-SP9B8 1 1 Al-2 C5761A LI-SP9A6 2 1 Al-4 C5761A LI-SP9B9 1 3 A1-6 C5761A LI-SP9A7 2 3 Al-8 C5761A LI-SP9B6 1 2 Al-2 C5792A LI-SP9A8. 2 2 Al-4 C5792A LI-SP9B7 1 4 Al -6 C5792A LI-SP9A9 2 4 Al-8 C5792A The control room indicators are powered from the. control room cabinet power and receive their process signal from four of the SFRCS level signals. Indicators LI-SP9A6A and LI-SP9B6A are used for Post Accident'Monitoring. For Reference, see Section 4.1.64. Indicator SG Cabinet Powered From LI-SP9B8A 1 C5708 Yl ckt12 LI-SP9A6A 2 . C5799 YlA ckt 7 LI-SP9B6A 1 C5798 Y2A ckt 7 LI-SP9A8A 2 C5710 Y2 ckt 11 2-28 SD-010 Rev- 4

o Accuracy at 40-140 OF & Vibration +0.07% of span 0 Hysteresis 99 mV o Input Signal Range Normal +10.5 Vdc Maximum +100 Vdc o Input Impedance >10 MOhm o Output 2 - Form C o Switch Point Range -10 to +10 Vdc o Relay Release Time 10 msec (typical) 2.3.1.4 Analog Isolator The isolator provides an 4-20 mA output that tracks the 4-20 mA to the Signal Monitor. The Isolator protects the Signal Monitor functions from damage, transient or steady state errors greater than 0.05% of full scale for fault conditions specified. The Isolator has the following isolation characteristic: o Common Mode Design: non recurring + 1500 V peak Design: continuous + 1000 V peak Test: + 340 V peak o Differential Mode Design: + 1000 V peak Test: + 340 V peak Common Mode is defined as the voltage between either or both isolated output terminals and the signal converter common. Continuous operation without damage is required. Differential Mode is defined as a fault voltage imposed between the isolator output terminals. Output error is expected. Such faults may damage the isolator, but shall not affect the signal monitor functions. A 100 mA fuse is provided to minimize the isolator damage, but is not required to protect the signal monitor functions. For Reference see Section 4.3.1.128. The following are the isolator performance specifications: o Accuracy at 25 'C +0.09% of span o Accuracy at 40-140 OF & Vibra~ion +0.29% of span o Input Signal 4 to 20 mA o -Input Impedance 250 Ohm + 0.1% o Output Signal 4 to 20 mA o Output Impedance > 1 MOhm // 10OOpF 2-27 SD-010 Rev. 4

The signal converter has a 5 Hz low pass filter to reduce noise problems. It will provide about 21.5 db reduction of 60 Hz noise. Two test jacks are provided on the front panel of the signal monitor labeled IN and OUT. These points may be used to confirm correct operation and calibration. IN is a voltage measurement across the input resistor, not a true current measurement, therefore this input signal, should not be used for calibration. For Reference see Section 4.3.1.128. The following are the signal converter performance specifications: 0 o Accuracy at 25 C +0.025% o Accuracy at 40-140 OF plus Vibration +0.08% o Filter 5 Hz Low Pass o Input Signal Range 4-20 mA o Input Fuse 50 mA o Output (User Selectable) 0 to +10 Vdc o Output Impedance 0.7 Ohm typical o Output Current 5 mA o Output Load greater than 2 kOhm 2.3.1.3 High and Low Comparator (Bistable) The Signal Monitor Module contains two (2) identical comparator circuits. For the SFRCS the jumpers are set for one for HIGH limits and one for LOW limits. The following discussion will describe the HIGH Comparator operation. Paragraphs at the end of this section will describe how the LOW comparator is normally different in use. When the input signal exceeds the switch point the output relay changes state. The switch point is designed to be set anywhere in the range of +10 Volts. The switch point is set by a COARSE switch with 11% of range overlapping steps and by a 22 turn FINE adjust potentiometer. Internal jumpers provide for FORWARD (minus to plus) action or REVERSE (plus to minus) action for clockwise motion of the COARSE and FINE controls. For the SFRCS the jumpers are set FWD for, both the HIGH and LOW comparator. A hermetically sealed military style relay is used for the output. The front panel LED indicates the relay is energized. The state of the relay can be selected by internal jumpers. For the SFRCS the relay for the HIGH and LOW comparator is energized with the signal below the switch point for the High comparator and exceeding the switch point for the LOW comparator. The relays will be de-energized on trip condition or on power failure. For Reference see Section 4.3.1.128. The following are the bistable performance specifications: 0 o Accuracy at 25 C +0.01% of span 2-26 SD-010 Rev. 4

The Signal Monitor Module can be removed and replaced under power without causing any harm to the electronic components. However, the digital output circuits will propagate a trip signal to the digital part of the SFRCS. Further, the adjacent indicator and the indicator in the control room, if applicable, will display the loss of signal. The following are the signal monitor module performance specifications: o Ambient Temperature Range Normal 40 - 140 OF Limiting 0 - 160 OF 0 Supply Voltage Normal 120 Vac(108 to 132 Vac) Limiting 90 to 132 Vac 0 Supply Current Typical 0.06 A Maximum 0.15 A Fused 0.50 A 2.3.1.1 Transmitter Power Supply The transmitter power supply is designed to power one 4-20 mA transmitter. A choice of two regulated output voltages - 24 Vdc or 36 Vdc - is selectable by an internal jumper. For the SFRCS 36 Vdc is selected. The selection is to be based on the transmitter manufacturer's data and on total current loop resistance including wire size and length. For example calculation refer to Reference in Section 4.3.1.128. The power supply will limit the current at 29 mA typically (26 to 35 mA) to protect both the power supply and the precision resistors used for measurement in the event of short circuits in the loop. The power supply can withstand an external short indefinitely without degradation. The voltage of the power supply can be measured at test jacks on the front panel of the Signal Monitor. For Reference see Section 4.3.1.128. The following are the transmitter power supply performance specifications: o Output Voltage User Selectable +24 Vdc (24.6 to 28.3)

                                                         +36 Vdc   (32.8 to 37.8) o    Current'Limit                                29 mA (26 to 35) o    Output Impedance                             less than 30 Ohms 2.3.1.2        Signal Converter   (Amplifier)

The signal converter is used to convert a 4-20 mA signal into a voltage signal suitable for use in monitoring and control systems. Internal signal converter jumpers (Jl, J2, J3) allow to set up for six output voltage ranges. For the SFRCS the jumpers are set to generate an output voltage of 0 to +10 Vdc. The 'input circuit of the signal converter is protected by a subminiature microfuse rated at 50 mA to protect against large transients (e.g. shorts to 120 Vac). The input to the converter is a current with the span of 4 to 20 mA. It is connected across an input resistance of 250 Ohm. The signal converter output is a voltage with a minimum drive capability of 10 mA. 2-25 SD-010 Rev. 4

consist of two (2) resistor networks each driving an LED on Panel A5. These networks are switched on by a contact of the auxiliary relays in the SFRCS Interface Cabinets for the Main Turbine and for ARTS by the SFRCS output relay. The voltage for. the LEDs are derived from the SFRCS internal 48 Vdc supply. As an exception to all other SFRCS actuated equipment, where the opening or closing - as applicable - of the actual trip contact is verifiable, the contact opening for neither the turbine trip nor the ARTS trip is directly verifiable. In addition, the LEDs do not monitor the performance of the ARTS 1E isolation relays for the trips from logic channels 3 and 4. However, all trips to ARTS can be verified with an indicating light labeled '1/5 light' at the ARTS cabinets. This light will be lit when the SFRCS trip contact opens (trip). For details refer to ARTS System Description SD-013, Reference in Section 4.1.36. The performance of each of the in series wired contacts for the Main Turbine-trip cannot be verified during operation of the Main Turbine. For a more detailed description of the turbine trip circuit refer to Section 2.9.6.4. The trip confirm LEDs on panel A5 for the Main Turbine and ARTS trip are listed in Table 2.2-7 Trip Confirm LEDs for Main Turbine and ARTS Trip. 2.3 SIGNAL PROCESSING AND OUTPUT DEVICES The following is an index to the modules and output relays described in this section: DEVICE SECTION Signal Monitor Module 2.3.1 Bargraph Indicator Module 2.3.2 Field Buffer Module 2.3.3 Logic Module Relay Driver Module 2.3.5 Alarm Output Module 2.3.6 SFRCS Relays 2.3.7 2.3.1 Signal Monitor Module (P/N 1138860101) The Signal Monitor Modules monitor the eight (8) SFRCS level transmitters on both steam generators. The purpose of each Signal Monitor Module is to provide the following functions: o Transmitter Power Supply o Signal Converter (4-20 mA to 0-10 Vdc) o High Input Comparator (bistable) o Low Input Comparator (bistable) o Analog Signal Isolator (4-20 mA output signal) The Signal Monitor Modules are designed to plug into Rack Al, slot locations 1, 3, 5, and 7. The remaining Slot locations are designed to fit the Bargraph Indicator Module. See Section 2.3.2 for the Bargraph Indicator Module details. The Signal Monitors are driving the corresponding Bargraph Indicator mounted adjacently. The racks, consisting each of one (1) card cage with eight (8) slots, four (4) Signal Monitor Modules, four (4) Bargraph Indicator Modules and the backplane wiring including precision resistors, are manufactured by Science Applications International' Corporation (SAIC). For more details on the Signal Monitor refer to the Operating and Service Manual referenced in Section 4.3.1.128. 2-24 SD-010 Rev. 4

With the SFRCS in normal mode - untripped 7 and the.valve in the 'open' position, all associated local lights and both LEDs on Panel A5 shall be lit. Thus confirming to the operator that o the valve control powers are available, AND o neither SFRCS output relay is tripped, AND o the solenoids valves are energized. With one SFRCS output contact opened (due to test trip or otherwise) the local indicating light(s) and the LED on Panel A5 extinguishes. Thus confirming to the operator that o one SFRCS output relay is successfully tripped, OR o the solenoid power supply is lost, OR o the solenoid valve is inadvertently tripped, OR o the valve position indication does not function. With both SFRCS output contacts opened, the SFRCS de-energizes all associated solenoids, which changes the valve position to the SFRCS position. The trip confirming networks will not sense any voltage and therefore the trip confirm LEDs will extinguish. Thus indicating to the operator that o the SFRCS was successfully tripped OR o the valve is in the SFRCS position.

                                                   ~/

The trip confirm LEDs on panel A5 for the pneumatically AND-gated SFRCS valves are listed in Table 2.2-5 Trip Confirm LEDs for Valves with Pneumatic AND-Gates. 2.2.5.3 Trip Confirm for Power Auctioneered SOVs The trip confirm circuitry for power auctioneered solenoid operated valves (SOVs) consist of two (2) resistor networks driving each.an LED on Panel AS. These networks are wired to monitor the SFRCS controlled voltages at the output relay contacts before the auctioneering diodes. With the SFRCS in normal mode - untripped - and the solenoid valve in the

,open, position, both LEDs on Panel AS shall be lit.         Thus confirming to the operator that o    the valve control powers are available,                      AND o    neither SFRCS output relay is tripped.

With one SFRCS output contact opened (due to test trip or otherwise) the associated LED on Panel AS extinguishes. Thus confirming to the operator that: o one SFRCS output relay is successfully tripped, OR o the solenoid power supply is lost. With both SFRCS output contacts opened, the SFRCS de-energizes all associated solenoids, which changes the valve position to the SFRCS position. The trip confirming networks will not sense any voltages and therefore the trip confirm LEDs will extinguish. Thus indicating to the operator that o the SFRCS was successfully tripped. The trip confirm LEDs on panel AS for the power auctioneered SFRCS valves are listed in Table 2.2-6 Trip Confirm LEDs for Valves with Power Auctioneering. 2.2.5.4 Trip Confirm for Main Turbine and ARTS The typical trip confirm circuitry for the Main Turbine trip and ARTS trip 2-23 SD-010 Rev. 4

while the related trip confirm LED on Panel A5 extinguishes. Thus confirming to the operator that o the MCC has control power available, o the SFRCS trip circuit is not interrupted, o one SFRCS output relay is successfully tripped. With both SFRCS output contacts closed, the SFRCS trip contacts complete the electrical circuit and energize the starter coil, which changes the valve position to the SFRCS position. Valve limit switches now interrupt the SFRCS trip circuit, even when the SFRCS output contacts return to normal (open contact). In either' case the trip confirming network will not sense any voltage and therefore the trip confirm LEDs will remain extinguished. With both LEDs "OFF" the message is ambiguous and requires some analysis of the situation. Thus indicating to theoperator that o the SFRCS was successfully tripped, OR o the SFRCS MOV is in the SFRCS position, OR o the SFRCS trip circuit is interrupted, OR o the MOV supply power is not available. Both "Open" LEDs for the AFPT Valves MS-106, MS-106A, MS-107, MS-107A might be OFF because the pressure switches PSL-4930A, PSL-4930B, PSL-4931A and PSL-4931B respectively have responded to a low AFP suction pressure and isolated the steam flow to the AFPTs. Individual interlocks inhibit the SFRCS initiating signal from opening the valves. For details refer to the Auxiliary Feedwater System Description SD-015 (Reference in Section 4.1.38). For valves MS-106 and MS-107, an interlock exists such that if DH1I (DH12) is off its seat, MS-107 (MS-106) will not open by an SFRCS signal (Reference in Section 4.1.27.6, 4.1.27.7, 4.1.27.13 and 4.1.27.14). For references to the.Elementary'Wiring Diagrams of the control of these valves refer to Table 2.2-3 Valve List with SFRCS Independent Interlocks. For details on the interlocks refer to the listed elementary diagrams and to the Auxiliary Feedwater System Description SD-015 (Reference in Section 4.1.38). The trip confirm LEDs on panel AS for the SFRCS MOVs are listed in Table 2.2-4, Trip Confirm LEDs.for MOVs. 2.2.5.2 Trip Confirm for Pneumatically AND-gated SOVs The trip confirm circuitry for pneumatically AND-gated solenoid operated valves (SOVs) consist of two (2) resistor networks driving each an LED on Panel AS. These networks are wired in parallel to local indicating lights mounted in the vicinity of the solenoid valves. When the solenoid valve is energized, either a valve position switch or, a low pressure switch contact closes and lights the associated local indicating light and the LED on Panel A5. The pressure switch monitors' the presence of the instrument air pressure controlled by the solenoid. The indicating light, the LED and the SFRCS controlled solenoid share the same fused power supply. The fuses are located in the SFRCS Relay Cabinets. In some cases a single SFRCS output controls two independent solenoids, each with its own low pressure switch and local-light. For these cases, field mounted auctioneering diodes are provided to feed the single resistor network and LED on Panel AS. 2-22 SD-010. Rev. 4

o Power Supply Requirements (at 22-26 Vdc) 200 ma o Power Supply Voltage Limits 20 - 28 Vdc o Operating Temperature Limits 20 - 140 0 F 0 Relay Contact Rating (at 24 Vdc non-inductive) 2 a o Maximum Temperature Influence (for 40 - 120°F) +/- 0.5% o Maximum Power Supply Voltage Influence (for 22 - 26 Vdc) +/- 0.2% 2.2.5 SFRCS Trip Confirm The SFRCS design includes 'Trip confirm' circuitries to support the testing of the SFRCS output circuits. The trip confirm data lights (LEDs) are located on the corresponding Output Panels AS in the Logic Cabinets. The trip confirm circuitries vary with each different type of SFRCS actuated equipment. The intent of the trip confirm circuitry is to provide to the operator a verification that the SFRCS output contacts do open. The indicating LEDs shall not be used to verify the actual response of the actuated equipment. The valve status of all SFRCS actuated valves are displayed at the center control. The power supply of these indications are independent from the power supply for the SFRCS. In addition, local indicating lights are provided. Except for the solenoid circuits addressed in Section 2.2.5.2 the supply powers are also independent from the SFRCS power supply. For more details refer to the system description of the system the valve is related to and/or to the.Elementary Diagram of the valve control. Each type of trip confirm circuit is briefly described below, followed by a tabulation of the effected actuated equipment. The tabulation includes ID number of the associated LEDs and the sheet of the SFRCS Internal Schematic Diagram, Drawing SF-003B. 2.2.5.1 Trip Confirm for MOVs The typical trip confirm circuitry for motor operated valves (MOVs) consist of two (2) rectifier and resistor networks each driving an LED on Panel A5. These networks are wired in parallel to the two SFRCS trip output contacts for that particular MOV. With the SFRCS not tripped (normal mode) both contacts, which are wired within the SFRCS in series, are open. This set of series contacts is normally directly field wired with the MCC of the MOV. The exceptions are listed on Table 2.2-3. One wire connects to the 120 Vac control voltage via a series and/or parallel connection of valve limit and torque switches.- The other wire connects to open (or close as applicable) starter coil via the close (or open as applicable) interlock contact. With both SFRCS output contacts open, the trip confirm networks complete an electrical circuit and allows a trickle current of less than approximately 9 mA to flow through the starter coil without energizing the starter. This current will light both trip confirm LEDs on panel AS. Thus confirming to the operator that o the MCC has control power available, o the SFRCS trip circuit is not interrupted, o either SFRCS output relay is not tripped. With one SFRCS output contact closed (due to test trip or inadvertent) the trickle current approximately doubles, still not affecting the starter coil, 2-21 SD-010 Rev. 4

2.2.4 Reactor Coolant Pump Monitors Each RCP motoi has a current transformer that feeds four GE type 4722 current transducers (one to each channel of the RCP monitor channels). Each current transducer feeds a Bailey type 745 dual alarm module. The high and.low trip contacts from the dual alarm module are then run in series to pick up an Agastat model 7022 time delay drop out relay, set at 2.5 Hz. A normally open contact from four Agastat relays (one per each RCP) are run in parallel to pick up a GE type 12HGAllJ auxiliary relay which is used by SFRCS for the loss of all four RCP trip input. See Reference 4.1.58 for details. The following are the specifications for the GE type 4722 current transducers: o Input 0-5 a ac o Output 0-1 ma dc o Maximum Burden @ 60 Hz 2.0 va o Continuous Overload 10 a o One-Second Overload 250 a o Operating Temperature -20 to.650 C o Maximum Temperature Influence +/- 0.75% o Humidity 0-90% o Output Load Range 0-10 K ohms o Accuracy @ 23'C and Nominal Frequency + 0.5% full scale o 100% Overload Linearity +/- 0.5% o Calibration Adjustment

• 10%

o Ripple on Output (peak) < 1% o Response Time (to 99% final value) < 400 ms o Dielectric Test 1500 vrms The following are the specifications for the Bailey type 745 dual alarm module: 0 Input Signal 1 -5 Vdc 0 Input Resistance > 1 meg ohm 0 Output 2 sets of contacts 0 Alarm Setpoint Deadband Adjustment 0.5 to 5%'of span 0 Response Time < 100 ms 0 Accuracy (at 24 Vdc, 80'F) +/- 0.5% 2-20 SD-010 Rev. 4

O Over-range 2500 psi o Contact Rating 5.0 A @ 250 Vac max. 0.3 A @ 125 Vdc o Diaphragm Material 316 SS o Housing NEMA 4 Housing 2.2.3 Differential Pressure Switches (288A) The SFRCS employs eight (8) ITT Barton Model 288A Indicating Differential Pressure Switches. This model is actuated by the Barton Model 224 Rupture-Proof Differential Pressure Unit. The principle of operation of the pressure unit is as follows: Two inter-connected bellows containing a liquid fill are mounted in separate chambers on opposing sides of a center plate. The difference in pressure between the two chambers causes the bellows to travel toward the side of lowest pressure. The motion of the bellows is transmitted through a rotating shaft to the input mechanism of the indicating switch instrument. The models employed at Davis-Besse were furnished with two (2) (high and low) actuated switches each driving a relay. With MOD 87-1107 the relay circuit was abandoned in place and the normally closed contact of the high switch was wired to terminals to drive the SFRCS input buffer directly. This change has improved the system reliability by reduction of the interacting components (relay, fuses, terminals) and has increased the plant availability by eliminating the additional 120 Vac and 125 Vdc feeders separate from the SFRCS. The following are the differential pressure switch Model 288A performance specifications: o Ambient Temperature Range -60 - 200'F o Maximum Non-Linearity + 0.5% o Full Scale Differential Pressure 0 - 400 psig o Torque Tube Rotation 80 + 10 % o Switch Type Mechanical, Snap Action o Contact Type Single Pole, Double Throw o Switch Rating 5 A at 120 Vac inductive 0.1 A at 120 Vdc resistive 0.2 A at 120 Vdc inductive 3 A at 30 Vdc resistive 4 A at 30 ;Ydc o Relay Coil Supply Voltage 120 Vac (Usage at D-B abandoned) 125 Vdc o Relay Contact Rating resistive 10 A at 115 Vac or 26.5 Vdc inductive 5 A at 115 Vac or 26.5 Vdc 2-19 SD-010 Rev. 4

O Span and Zero Continuously adjustable externally. o Elevation and Suppression Maximum Zero Elevation: 600% of calibrated span. Maximum Zero Suppression: 500% of calibrated span. o Temperature Limits -20 to +220 *F o Static Pressure Limits 0.5 psia to 2000 psig o Overpressure Limits 2000 psig on either side without damage to transmitter o Humidity Limits 0 to 100% relative humidity o Volumetric Displacement < 0.01 cubic in. (0.16 cm 3 ) o Turn-on Time 2 seconds. No Warmup required. o Damping Time constant continuously adjustable between 0.2 and 1.67 seconds. For performance specifications and functional specifications reference refer to Section 4.3.1.130., 2.2.2 Steam Line Pressure Switches (9V2) The SFRCS employs eight (8) Static "01 Ring (SOR) Block Pressure Switches(Types 9V2-ES-X4TT) and eight (8) SOR Trip Pressure Switches (Type 9TA-B5-NX-ClA-JJTTX12). The following are the pressure switch type 9V2 performance specifications: o Pressure Range 100 to 1000 psi o Maximum Deadband 15 to 30 psi o Maximum Sustained Pressure 2000 psi o Switching Element Feature Narrows Reset DC o Contact Rating AC 5.0 A @ 250 Vac max. DC Resistive 5.0 A @ 30 Vdc o Diaphragm Material Viton (for high temp.) o O-Ring Material Viton (for high temp.) o Housing NEMA 4 Housing (3.5" by 5.5") The following are the pressure switch type 9TA performance specifications: o Pressure Range 200 to 1000 psi o Maximum Deadband 65. psi 2-18 SD-010 Rev. 4

For the filtering requirements see Reference in Section 4.5.33. The level transmitter amplifier board includes a filtering circuit to dampen the process signal to prevent spurious low level trips due to transient pressure impulses that may occur when the turbine stop valves close. The time constant of the dampening circuit is calibrated to a value between 1.4 seconds and 1.8 seconds (Reference 4.5.33). A built-in current limiter prevents the output current from exceeding 30 mA in an overpressure condition. The signal above 20 mA is linear up to approximately 25 mA, beyond this approximate point the value is less proportional to the monitored input signal. The transmitter is protected against reverse polarity. The transmitters are located inside the containment at elevation 56510". For maintenance and installation details refer to the Instruction Manual, (Reference 4.3.1.130). The following are the differential pressure transmitter 1152DP5 performance specifications: o Accuracy +0.25% of calibrated span o Deadband None o Stability +0.25% of upper range limit for 6 months o Temperature Effect +(0.5% upper range limit + 0.5% span) per 100OF ambient temperature change o Overpressure Effect < +3% of upper range limit o Static Pressure Effect Zero Error

                                                  +0.25% of upper range limit per' 2000 psi o      Power Supply Effect                < 0.005% of span per volt o      Load Effect                        No load effect other than in   voltage supplied to transmitter The following are the 1152DP5 functional         specifications:

0 Range 0-125" to 0-750" H20 o D-B calibrated range 0-300" indicated level 9 Output 4-20 mA dc o Power Supply External power supply required, up to 45 Vdc. Transmitters operate on 12 Vdc with no load. 2-17 SD-010 Rev. 4

If an SFRCS signal to an individual SFRCS actuated equipment is "BLOCKED" (i.e. overridden), this equipment still will respond to a subsequent automatic SFRCS actuation signal without operator action. In order to change a valve position against the automatic SFRCS trip signal, two operator actions are required. The first action will be pressing the block switch for this valve on the center console. No change in valve positioning will occur with the

'blocking' of the SFRCS trip        signal. A second deliberate action by the operator is required to open or close this valve by pressing the provided control switch on the center console.          Before an operator "BLOCKS" any SFRCS signal, he must insure that the safety function of that equipment is no longer needed.      Re-actuation by the operator, subsequent to a "BLOCK", can be accomplished in two ways.          First, at the equipment-level, "Blocked equipment" will respond to the individual control switches that control the particular equipment.      Second, at the SFRCS system level, operation of the individual "Reset" push button on Output Panel AS in the Logic Cabinet will clear that particular "BLOCK".         The equipment will return to its    SFRCS actuated mode of operation.      The valves with block control switches at the center console are listed    in Table 2.1-18 Valves with Block Features.

2.1.2.7 Other Functions The SFRCS performs a number of other functions during plant operations providing the following indications, outputs, and capabilities. o Status indications of all input variables at the input panel A2 in each protection channel. For details refer to Section 2.6.1. o Status indications of all SFRCS outputs at the output panel AS in each protection channel. For details refer to Section 2.6.2. o Digital output signals to the plant computer and to the station annunciator. Refer to Sections 2.9.1 and 2.9.2 and to Table 2.9-1. 2.2 SENSORY EQUIPMENT Various process parameters are input to and monitored by the SFRCS. Refer to Table 2.2-1 List of All Analog Variable Inputs and Table 2.2-2 List of All Digital Variables Inputs to the SFRCS. 2.2.1 Steam Generator Level Transmitter (1152 DP5) The Rosemount Model 1152DP5 Alphaline Differential Pressure Transmitters are being used to monitor the steam generator levels. These transmitters are designed for use in nuclear application and as such qualified to IEEE Std. 323-1971 and IEEE Std. 344-1975 for use in extreme radiation and seismic conditions. The transmitters have a variable capacitance sensing element, the delta-Cell. Differential capacitance between the sensing diaphragm and the capacitor plates is converted electronically to a 4-20 mAdc signal. The zero adjustment and the span adjustment on the amplifier board allows for calibration of the transmitter. The additional linearity adjustment is provided for factory adjustment only. An adjustable filter of the output signal on the amplifier board permits to adjust the time constant within a range of approximately from 0.2 to 1.67 seconds. 2-16 SD-010 Rev. 4

generator and aligning steam and auxiliary feedwater to/from this steam generator. There are four (4) independent control switches provided to initiate auxiliary feedwater with or without steam generator isolation provided in the control room on the center console, panel C5707. The control switches are HIS-6401, HIS-6402, HIS-6403 and HIS-6404. Each of the control switches have a different response as described in Section 2.3.12. The different responses for the control switches are listed in tables as referred to below. Manual Initiation by control switch HIS-6401 will actuate the equipment listed in Table 2.1-14 HIS-6401 Manual Trip of Protection Channel 1 without SG Isolation. Manual Initiation by control switch HIS-6402 will actuate the equipment listed in Table 2.1-15 HIS-6402 Manual Trip of Protection Channel 2 without SG Isolation. Manual Initiation by control switch HIS-6403 will actuate the equipment listed in Table 2.1-16 HIS-6403 Manual Trip of Protection Channel 1 with SG-1 Isolation. Manual Initiation by control switch HIS-6404 will actuate the equipment listed in Table 2.1-17 HIS 6404 Manual Trip of Protection Channel 2 with SG72 Isolation. All listed equipment, flagged with an asterisk (*), is already in the SFRCS trip state during normal power operation. The SFRCS still issues a trip signal to insure that the equipment is in the required state. Normally, the equipment does not have to move. For the determination of the functions and quantities of the manual actuation switches refer to Reference in Section 4.5.5. 2.1.2.5 SFRCS Bypasses/ Blocks 2.1.2.5.1 Channel Bypass The SFRCS provides a built-in feature to allow testing of the SFRCS while the reactor is shutdown and the station is in Modes 4, 5 or 6 and some input variables are in a trip state. The SFRCS provides a channel bypass feature, one (1) for each logic channel, to simulate an untripped condition for any digital input variable with the use of toggle switches together with one (1) keylock switch for each logic channel. The keys are under administrative control. The channel bypass condition will be alarmed with the SFRCS Trouble Alarm to the Plant Computer and the Station Annunciator. 2.1.2.5.2 Shutdown Bypass/Block The SFRCS provides a shutdown block feature to allow blocking the SG High Level and Low Pressure Trips during normal plant startups or shutdowns. The variables listed in Table 2.1-3 provide the SFRCS with permissive signals for the shutdown bypass circuit. The shutdown block is automatically reset as main steam line pressure increases. For logic information refer to SFRCS Logic Diagrams Drawing E-18 SH.1 and 2 (Reference in Section 4.1.10). The logic is in its entirety implemented with solid state logic component in the Logic Module, see Section 2.3.4 for details on the Logic Module. 2.1.2.6 Output Signal Blocks 2-15 SD-010 Rev. 4

operator initiation at the center console in the control room. For button and light locations on the output panels A5 refer to Figure 2.2-11 and Figure 2.2-12. For test circuit logic information refer to SFRCS Logic Diagrams Drawing E-18 SH.1-3 (Reference in Section 4.1.10). 2.1.2.2.9 Module Interlock Trip The removal of any module in the SFRCS cabinets will cause a logic channel trip of the string interrupted by the removal of the module. If no trip is present in the complementary channel or for certain strings, which are related to the ARTS trip strings, in the redundant protection channel the removal of any module will not cause an SFRCS trip. In general, the removal will trigger the SFRCS trouble alarm in addition to the process variable alarm(s). The bargraph indicating modules may be removed any time without impairing any SFRCS function. These modules will not interrupt the analog signal string and will not trigger the SFRCS trouble alarm. 2.1.2.3 ARTS Trips The ARTS serves as an interface system to trip the reactor as required. For Reference see Section 4.4.11. The SFRCS interfaces the ARTS with one (1) signal from each of the four logic channels. ARTS has a two-out-of-four trip logic. Any two or more SFRCS logic channel trip signals to ARTS will result in a reactor trip. For more details, refer to the ARTS system description, Reference in Section 4.1.36. 2.1.2.4 Manual SFRCS Trips The SFRCS is a system with more than one trip response, contrary to most other safety systems. For example the NI/RPS has only one automatic trip response: tripping the reactor when the monitored input variables call for a trip. The manual initiation of the NI/RPS therefore results in a reactor trip as well. The automatic SFRCS trip logic has the following three different distinct trip responses in addition to the turbine trip and the reactor trip via ARTS: a) isolation of main steam and main feedwater from/to both steam generators and aligning steam and auxiliary feedwater to/from the good steam generator, b) isolation of main steam and main feedwater from/to both steam generators and aligning steam from both steam generators and auxiliary feedwater to the associated steam generator (i.e. AFP-I feeds SG-l and AFP-2 feeds SG-2), c) no isolation of steam generators and aligning steam from both steam generators and auxiliary feedwater to the associated steam generator (i.e. AFP-1 feeds SG-l and AFP-2 feeds SG-2) The manual SFRCS trip logic has the following two different distinct trip responses in addition to the turbine trip and the reactor trip via ARTS: d) Aligning steam and auxiliary feedwater to/from a selected steam generator, e) isolation of main steam and main feedwater .from/to a selected steam 2-14 SD7010 Rev. 4

concept as much as possible. This criterion and the SFRCS design supports overlapping testing of all trip paths. The SFRCS employs two (2) test panels, Input Panel A2 and Output Panel AS, in each logic cabinet. For more detail refer to Sections 2.6.1 and 2.6.2 respectively. On the input side, the SFRCS provides one (1) test trip button for each incoming digital variable and one (1) test enable button. For button locations on the input panels A2 refer to Figure 2.2-9 and Figure 2.2-10. For test circuit logic information refer to SFRCS Logic Diagrams Drawing E-18 SH.l-3 (Reference in Section 4.1.10). To test the incoming SFRCS circuits it is necessary to depress the test enable button simultaneous with the variable test button to process the signal beyond the two-out-of-two acceptance logic. All test buttons are identified with the letter 'T' followed by a unique numeric designation of three numerals, of which the first and the second numerals are the row numbers of the switch located on Panel A2 and the third numeral describes the associated logic channel. All characters together make an unique identifier. Depressing any test button, including the test enable button will turn OFF an associated red LED indicating the successful change of signal state. The red LED is identified with 'L', followed similarly by the row and logic channel designation. Depressing the input test button together with the test enable button will trip the instrument string in that logic channel and will change the state of the red and yellow LEDs on Output Panel AS, described below, associated with this input string under test. On the output side, the SFRCS provides two (2) *test trip buttons for each SFRCS actuated equipment, one for each logic channel. In logic channels 1 and 2 the test switches are labeled 'TA' for trip or closing function and 'TC' for opening function of the actuated equipment. In logic channels 3 and 4 the labels are 'TB' and 'TD' respectively. To make the switch reference unique, a numeric designation is followed with three numerals, of which the first and the second enumerate the row number of the switch located on Panel AS and the third numeral describes the logic channel. All characters together make an unique identifier. Depressing one test button will, in general, change the status of a green LED from 'ON' to 'OFF' and a yellow LED from 'OFF' to 'ON'. The green LEDs are labeled 'LA' or 'LC' in logic channels 1 or 2 and 'LB' or 'LD' in logic channels 3 or 4. The yellow LEDs are similarly labeled with 'LTA', 'LTC',

'LTB' and 'LTD'     respectively. On documents the complete reference label always includes the three numerics, defining row and logic channel.

The yellow light reflects the status of the SFRCS output relay. The light serves also as a reminder that pressing the complementary test button will cause an actuation of that particular equipment, therefore the yellow light was located in the vicinity of the complementary test button. The red light is the trip confirm light, which is described in detail in Section 2.2.5. Consistent with the design criteria, the manual initiation of the SFRCS can also be simulated on a logic channel basis. Tripping both associated output test buttons will cause a full trip of the selected equipment. However, these buttons are not required as a backup for 2-13 SD-010 Rev. .4

The SFRCS logic channel provides seal-in circuits, one for each process variable located down stream of the input AND-gate. This seal-in circuit monitors a trip condition at the output of the AND-gate and maintains the trip condition, even though the trip condition may have been present for milliseconds only. This is to insure that all actuated devices - to be initiated for a given incident - have received the trip signal and changed state of operation, e.g. seal-in of the closing starter coil of an MOV device, or de-energization' of a solenoid and completion of travel to its de-energized state. The trip seal-in response times of the SFRCS actuated devices vary typically between approximately 7 milliseconds to 80 milliseconds. (Reference in Section 4.5.25). The circuit functions as a signal stretcher. Regardless of the duration of the input signal, the SFRCS output sees a 2 second trip condition minimum. After the two (2) seconds, the output will follow the input signal without delay. The automatic reset of the SFRCS trip logic is required so that the SFRCS can automatically respond to potential changes of the input condition and trip the SFRCS accordingly. Once the SFRCS sensing channel trip condition has been cleared, no actions by the operator must be taken to reset (un-trip) the SFRCS. It should be noted that the clearing of one of the two sensing channels clears the associated protection channel. Because of tolerance in the' sensoring circuits, reset of one protection channel may occur while the other protection channel is still in a trip condition. None of the actuated devices return to the non-SFRCS trip mode automatically. The operator has to reposition manually each actuated equipment out of its SFRCS position with its manual control switch at the center console. In addition to its trip action of the sensing channel string, an SFRCS logic channel will also trip in response to the following: o Loss of power to the logic channel. (Refer to Section 2.7) o Simulation of sensing channel input test by pressing a momentary test button at the input panel A2 simultaneously with activating the momentary Test Enable push button (Refer to Sections 2.1.2.2.8) o Simulation of an individual output test by pressing a momentary test button at the output panel A5 (Refer to Sections 2.1.2.2.8) o Removal of the input buffer module(s), logic module, relay driver module(s) and output relay from the SFRCS 'cabinet (Refer to Section 2.1.2.2.9) 2.1.2.2.7 Reactor Trip The SFRCS does not communicate with the reactor trip circuits directly. The SFRCS interfaces the ARTS with one (1) signal from each of the four logic channels. ARTS has a two-out-of-four trip logic. Any two or more trip signals from SFRCS to ARTS will result in a reactor trip. Refer to Section 2.1.2.3 for ARTS trips. 2.1.2.2.8 Test Trip The SFRCS variable input signal acceptance logic and the SFRCS output trip logic is a two-out-of-two logic with the exception of the interfacing ARTS which trips on SFRCS trip signals with two-out-of-four SFRCS trip signal. The SFRCS design criterion is to utilize a fail-to-trip, fail-to-deenergize 2-12 SD-010 Rev. 4

All listed equipment, flagged with an asterisk (*), is already in the SFRCS trip state during normal power operation. The SFRCS still issues an trip signal to insure that the equipment is in the required state. Normally, the equipment does not have to move. 2.1.2.2.5 Loss of all Reactor Coolant Pumps Trip The absence of the -48 Vdc signal to the SFRCS signifies a loss of all reactor coolant pumps trip. Refer to Figures 2.1-11, 2.1-12, 2.1-13 and 2.1-14 for the instrumentation. This trip is the primary trip for conditions of loss of off-site power resulting in loss of all four RC pumps. This trip will also occur in the unlikely event of sheared shaft or locked rotor conditions on all four RC pumps or any combination of either condition on all four RC pumps. For more details refer to the RC System Description SD-39A (Reference 4.1.41). The SFRCS will not isolate main feedwater flow to and main steam from either steam generator, but will initiate turbine driven auxiliary feedwater flow from both auxiliary feedwater trains to their respective steam generators, while providing steam for AFPT-1 from both Steam Generators and AFPT-2 from both Steam Generators, trip the reactor via the Anticipatory Reactor Trip System (ARTS) and trip the main turbine. The SFRCS equipment actuated on loss of all four reactor coolant pumps condition is listed in Table 2.1-13, Loss of Reactor Coolant Pumps Trip. All listed equipment, flagged with an asterisk (*), is already in the SFRCS trip state during normal power operation. The SFRCS still issues a trip signal to insure that the equipment is in the required state. Normally, the equipment does not have to move. 2.1.2.2.6 Logic Channel Trip Each trip function described above controls one state of the input AND-gate in its associated logic channel. The other input to the AND-gate is being provided by the same trip function but from the complementary logic channel. For electrical independence the signal from the complementary logic channel is being isolated by an input buffer circuit with optical isolator, which is being powered on the primary side by the complementary logic channel, while the power supply to the secondary side circuit is being provided by the receiving logic channel. Only with the simultaneous presence of both trip conditions at the AND-gate will the logic channel process the trip condition. The logic module output signals connect, via a normally closed momentary push button at the output panel A5, directly to the input of individual relay driver circuits. Refer to the Figures 2.2-1 through 2.2-8, which illustrates typical SFRCS output, control, block and interlock circuits. For complete schematics refer to the SFRCS Internal Schematic Diagrams, Reference in Section 4.1.13. These figures are typical for all four logic channels of the SFRCS. The output of the relay driver drives a relay with four (4) Form C contacts. The presence of a trip condition at the output of the AND-gate will result in removal of power from the logic channel trip relays. The de-energization of these relays causes their output contacts to change state, sending a logic channel trip signal to the 2-out-of-2 protection channel trip logic. One exception is the trip signal to ARTS which is a 2-out-of-4 trip logic. The tripping of one logic channel to either the 2-out-of-2 or the 2-out-of-4 logic does not cause an SFRCS trip. 2-11 SD-010 Rev. 4

2.1.2.2.3 Low Steam Generator Level Trip The 4 to 20 mA signal from the level transmitter is being converted to a voltage signal by the Signal Monitor. Refer to Figures 2.1-3, 2.1-4, 2.1-5 and 2.1-6 for the instrumentation. The 0 to 10 Vdc signal representing Steam Generator Level is compared with a preset low level setpoint in a Bistable. A trip signal is generated if the measured level equals or is less than the Bistable setpoint. The low level trip is the primary trip for steam generator level decreasing transients such as reduction or loss of feedwater resulting in a low steam generator inventory. The low level trip does not differentiate which steam generator has low inventory or which steam generator signaled low level first. The SFRCS will not isolate main feedwater flow to and main steam from either steam generator, but will initiate turbine driven auxiliary feedwater flow from both auxiliary feedwater trains to their respective steam generators, while providing steam for AFPT-1 from both Steam Generators and AFPT-2 from both Steam Generators, trip the reactor via the Anticipatory Reactor Trip System (ARTS) and trip the main turbine. The SFRCS equipment actuated on low steam generator level condition is listed in Table 2.1-11 Low Steam Generator Level Trip. All listed equipment, flagged with an asterisk (*), is already in the SFRCS trip state during normal power operation. The SFRCS still issues a trip signal to insure that the equipment is in the required state. Normally, the equipment does not have to move. 2.1.2.2.4 High Steam Generator Level Trip The 4 to 20 mA signal from the level transmitter is being converted to a voltage signal by the Signal Monitor. Refer to Figures 2.1-3, 2.1-4, 2.1-5 and 2.1-6 for the instrumentation. The 0 to 10 Vdc'signal representing steam generator level is compared with a preset high level setpoint in a Bistable. A trip signal is generated if the measured level equals or exceeds the Bistable setpoint. Although, it is not a safety function, the high level trip is the primary trip to prevent steam generator overfill condition and spill over into the main steam lines and main turbine and to prevent thermal shock to internal structures of the steam generators (References 4.6.3, 4.6.17 and 4.8.23). Davis-Besse has committed to the NRC (Reference 4.5.42) to test the high level trip functions and to bring any failures of this trip signal to the attention of upper management personnel. The high level trip does not differentiate which steam generator has high inventory or which steam generator signaled high level first. The SFRCS will isolate main feedwater flow to and main steam from both steam generators, initiate turbine driven auxiliary feedwater flow from both auxiliary feedwater trains to their respective steam generators, while providing steam for AFPT-l from both Steam Generators and AFPT-2 from both Steam Generators, trip the reactor via the Anticipatory Reactor Trip System (ARTS) and trip the main turbine. The SFRCS equipment actuated on high steam generator level condition is listed in Table 2.1-12 High Steam Generator Level Trip. 2-10 SD-010 Rev. 4

The low steam line pressure trip is the primary trip for rapid secondary pressure transients resulting from a main steam line break (MSLB) or from main feedwater line break (MFWLB) downstream of the last check valve before the feedwater block valves. This trip is the backup for the slow pressure transients resulting from the loss of main feedwater. The SFRCS will determine and distinguish the affected (not-good) steam generator from the unaffected (good) steam generator. Feedwater and steam line valves will be closed to isolate the steam line rupture. Steam supply from the unaffected (good) steam generator will be lined up to the two redundant auxiliary feedpump turbines. Steam supply to the main turbine and to the main feedpump turbines will be cut-off to preserve steam. Likewise, auxiliary feedwater from the two auxiliary feedpumps will be diverted to feed the unaffected steam generator. The reactor - via ARTS - and the main turbine will be tripped. The SFRCS equipment actuated on low steam line-i pressure condition is listed in Table 2.1-8 Low Steam Line-i Pressure Trip. The SFRCS equipment actuated on low steam line-2 pressure condition is listed in Table 2.1-9 Low Steam Line-2 pressure Trip. All listed equipment, flagged with an asterisk (*), is already in the SFRCS trip state during normal power operation. The SFRCS still issues a trip signal to insure that the equipment is in the required state. Normally, the equipment does not have to move. 2.1.2.2.2 High Reverse Differential Pressure Trip The measured main feedwater differential pressure signal across the check valve FW147 for main feedwater flow into the steam generator-i and check valve FWI56 for main feedwater flow into the steam generator-2, is compared with the preset high differential setpoint of the Differential Pressure Switches. Refer to Figures 2.1-9 and 2.1-10 for the instrumentation. A trip signal is generated if the measured main feedwater differential pressure signal equals or exceeds the Differential Pressure Switch setpoint. The differential pressure trip does not differentiate in which line the feedwater was lost or which line lost feedwater first. The SFRCS will isolate main feedwater flow to and main steam from both steam generators, initiate turbine driven auxiliary feedwater flow from both auxiliary feedwater trains to their respective steam generators, while providing steam for AFPT-I from both steam generators and AFPT-2 from both steam generators, trip the reactor via the Anticipatory Reactor Trip System (ARTS) and trip the main turbine. The SFRCS equipment actuated on high reverse differential pressure condition is listed in Table 2.1-10 High Reverse Differential Pressure Trip. All listed equipment, flagged with an asterisk (*), is already in the SFRCS trip state during normal power operation. The SFRCS still issues a trip signal to insure that the equipment is in the required state. Normally, the equipment does not have to move. The high reverse differential pressure trip is the primary trip for rapid pressure transients resulting from a main feedwater line break (MFWLB) upstream of check valves FWI47 and FWI56. Since both main feedwater pumps feed into a common header, this trip can also occur if both main feedwater pumps are tripped or the feedwater is ceased for any reason. 2-9 SD-010 Rev. 4

Figure 2.1-12 RC Pump Monitoring, SFRCS Logic Channel 2, Figure 2.1-13 RC Pump Monitoring, SFRCS Logic Channel 3, Figure 2.1-14 RC Pump Monitoring, SFRCS Logic Channel 4. The current transducer (GE type 4722) for each 13.2 kV RCP Motor provides a milliamp output signal proportional to the motor current. This signal produces a'voltage drop across a 5 kOhm resistor which is used as the input signal into a Bailey Meter 745 dual-alarm bistable unit. Contacts in series from the high and low bistable initiate a time delay dropout (41.67 msec/2.5 Hz) relay. One set of 'contacts from this relay goes to RPS, while another set of contacts is used for SFRCS. For SFRCS, this contact, in parallel with similar contacts from the other three motors for 4-out-of-4 logic, drives a relay at Relay Panel RC3601 located at 585 ft (Level '3) in the Auxiliary Building, NE Quarter (Area 6). One normally open contact from this relay is monitored by the SFRCS logic channel 1, another-normally open contact is being used to initiate Alarm Q774 (Reference in Section 4.1.58). Similarly, the contacts for SFRCS logic channels 2, 3, and 4 and for the common Alarm Q774 are derived from Relay Cabinets RC3602, RC3603, and RC3604 respectively. All cabinets are located at the same level and area. For the RC Pump Monitoring variables refer to Table 2.1-5, RC Pump Monitoring SFRCS Input Signal List. Power (-48 Vdc) for the Pump Monitor contacts is supplied by the SFRCS from an Input Buffer Module in the respective SFRCS channels.' A -48 Vdc input indicates normal pump operation and an open contact input (0 Vdc) indicates abnormal pump operation such as a sheared RC pump shaft, a locked' RC pump rotor, or a loss of AC power to the RC pump. 2.1.2.2 SFRCS Trips The SFRCS provides protection for the reactor core and the reactor coolant system on an approach to unsafe conditions. To provide'this protection, the signals developed by the SFRCS instrumentation strings are processed through six (6) trip strings in the SFRCS cabinets to determine the need for an SFRCS initiation. The two (2) SFRCS protection channel-s operate identically in detecting conditions which require an SFRCS initiation. The trip conditions described below apply to each protection channel. Each tripprovides either steady-state or transient protection and is categorized as a primary or backup SFRCS initiation function. The SFRCS actuated equipment is tabulated in Table 2.1-6, SFRCS Actuated Equipment List for Protection Channel 1 and Table 2.1-7, SFRCS Actuated, Equipment List for Protection Channel 2. Refer to Section 3.3, SETPOINTS 'and Table 3.3-1 for a listing of SFRCS trip setpoints. 2.1.2.2.1 Low Steam Line Pressure Trip The measured main steam line pressure signal is compared' with a preset low pressure setpoint in a Pressure Switch. A trip signal is generated if the measured main steam line pressure signal equals or is less than the Pressure Switch setpoint. Refer to Figures 2.1-7 and 2.1-8 for instrumentation. 2-8 SD-010 Rev. 4

are monitoring SG-2 pressure. This configuration requires that SG-1 and 2 pressures be kept fairly equal during start up to prevent a SFRCS low pressure trip. For the steam generator pressure shutdown block variables refer to Table 2.1-3 Main Steam Line Pressure Shutdown Block Switch List. All switches have normally open (shelf position) contacts. The contacts are closed under normal operating condition and open when steam line pressure reaches or decreases below setpoint. Power (-48 Vdc) for the pressure switch contacts is supplied by the SFRCS from Input Buffer Modules in the respective SFRCS channels. A -48 Vdc input therefore, indicates normal operation and an open contact input (0 Vdc,) indicates abnormal operation or shutdown condition. The pressure switches are wall mounted at 623 ft (Level 5) in the Auxiliary Building, SW Quarter for Main Steam Line-i (Area 8) and SE Quarter for Main Steam Line-2 (Area 7). 2.1.2.1.3 Differential Pressure Instrumentation The Main Feedwater/Steam Generator differential pressure is an uncontrolled variable. The differential pressure instrumentation is shown in the following figures: Figure 2.1-9 Main Feedwater Line-1 Diff. Pressure Instrumentation,and Figure 2.1-10 Main Feedwater Line-2 Diff. Pressure Instrumentation. The reverse differential pressure is measured in each of the two 18 inch main feedwater lines (18"-EBD-12) across check valve FW147 for main feedwater flow No.1 and across check valve FW156 for main feedwater flow No.2 by ITT Barton Model 288A indicating type redundant differential pressure switches (total four (4) switches per feedwater line). For the differential pressure variables refer to Table 2.1-4 Main Feed-water/Steam Generator Differential Pressure Switch List. All indicating differential switches have normally closed (shelf position) contacts. The contacts are closed under normal operating condition and open when feedwater pressure decreases or steam generator pressure increases to reach or exceed the high differential setpoint. Power (-48 Vdc) for the differential pressure switch contacts is supplied by the SFRCS from Input Buffer Module in the respective SFRCS channels. A -48 Vdc input indicates normal operation and an open contact input (0 Vdc) indicates abnormal operation. The differential pressure switches are wall mounted at 585 ft (Level 3) in the Auxiliary Building, SW Quarter (Area 8) for Main Feedwater Line No.1 and in the Heater Bay Area (Area 5) for Main Feedwater Line No. 2. 2.1.2.1.4 RC Pump Monitor The RC Pump Monitor string receives contact inputs from the RC Pump monitoring which indicate the status of all four RC pumps. The RC pump monitor strings are shown in the following figures: Figure 2.1-11 RC Pump Monitoring, SFRCS Logic Channel 1, 2-7 SD-010 Rev. 4

The steam generator startup level instrumentation is shown in the following figures: Figure 2.1-3 SG-1 Startup Level Instrumentation, Logic Channels 1 & 3, Figure 2.1-4 SG-1 Startup Level Instrumentation, Logic Channels 2 & 4, Figure 2.1-5 SG-2 Startup Level Instrumentation, Logic Channels 1 & 3, Figure 2.1-6 SG-2 Startup Level Instrumentation, Logic Channels 2 & 4. The steam generator startup level is monitored in the downcomer section of each steam generator by redundant SFRCS level transmitters (total four (4) transmitters per steam generator) and is used to provide input signals for the SFRCS and to the SFRCS./PAMS indicators in the main control room. The steam generator startup level is measured from 0 to 300 inches of water indicated in the steam generator downcomer by Rosemount 1152 type differential pressure transmitters. A filtering of the steam generator low and high level SFRCS actuation signal is required to.prevent spurious initiations caused by pressure transients triggered by sudden turbine stop valve closure which are not indications of changes in the steam generator inventory. (Reference in Section 4.5.14). For the steam generator startup level variables, refer to Table 2.1-1, Steam Generator Startup Level Transmitter List. The transmitters are wall mounted at 565 ft (Level 2) of the containment vessel (Area 9). The transmitters receive their power supplies (36 Vdc) from the associated logic channel in the' SFRCS cabinets. The transmitter output signal of 4-20 mA is directly proportional to the level signal of 0 to 300 inches indicated. 2.1.2.1.2 Steam Generator Pressure Instrumentation The steam generator outlet steam pressure is a controlled variable. The steam generator pressure instrumentation is shown in the following figures: Figure 2.1-7 Main Steam Line-i Pressure Instrumentation and Figure 2.1-8 Main Steam Line-2 Pressure Instrumentation. The steam generator steam pressure is monitored in each of the two 36 inch main steam lines (36"-EBB-1) from each steam generator by Static-O-Ring 9V2-E5-X4TT (block pressure switches) and 9TA-B5-NX-CIA-JJTTX12 (trip pressure switches) type redundant SFRCS pressure switches. For the steam generator pressure trip variables refer to Table 2.1-2, Main Steam Line Pressure Trip Switch List. The pressure switches automatically initiate the SFRCS when the steam line pressure reaches or decreases below setpoint. The low pressure trip block pressure switches monitor steam generator pressure at the same location as the low pressure trip switches. The block switches provide the SFRCS with permissive signals for the shutdown bypass circuit on decreasing pressure (before the trip setpoint of the above pressure switches is reached) and automatic removal of the shutdown'bypass with increasing pressure. Unlike the low pressure trip switches, the block switches are set up such that all ACH 1 switches are monitoring SG-1 pressure and all ACH 2 switches 2-6 SD-010 Rev. 4

4 (orange) 4 (orange) 2 (orange) B (tan) .4 (maroon) The SFRCS Startup System Number is 83C or 83-03. For the SFRCS input and output signals the following unique signal identifiers are used: SFRCS Digital Input Signal Description For example RSI-091 RSI- 09 1 I II----------- Logic Channel [1 4] I I------------Unique Input String No. [01 - 20] *)

                -I----------------          Rupture Control System Digital Input
          *)     The unique string number corresponds with the row number on the SFRCS Input Panels A2 (See Figures 2.2-9 and 2.2-10).

SFRCS Output Trip Signal Description For example RS-4213C RS- 4 2 1 3 C SI I I------Signal Fan-out Letter [A - El SI I --------- Logic Channel [1 - 4] *)

                         ---------- ------ Actuation Channel [1, 2, A, B]
                              --------      Trip Condition Fan-out     [1  - 6)
                  ------------------        Unique Trip Condition [1 - 6]
              -       -----------------     Rupture Control System Trip Output
          *)     This character is omitted when the output signals shown is a combined (AND-gated) signal of two complementary logic channels.

2.1,2 Loop Description 2.1,2.1 Instrumentation Strings The SFRCS has seven (7) instrumentation strings which monitor and process non-nuclear plant parameters and states. These measurements continuouslysupply the SFRCS with the steam generator No.1 and No.2 startup level monitoring the low and the high level status, the main steam line-i and -2 pressure status, steam generator / main feedwater-1 and -2 differential pressure status, and the reactor coolant pump status. The SFRCS strings are redundant and each of the four logic channels monitors the same plant parameter and plant status. Each SFRCS channel is served by a set of independent sensors which are physically separated and electrically independent of the other channels. 2.1.2.1.1 Steam Generator Startup Level Instrumentation The steam generator startup level is an uncontrolled variable at high power, but it becomes a variable controlled by the Integrated Control System (ICS) at low power when it reaches the minimum startup level control setpoint under normal conditions or it becomes controlled by the Auxiliary Feedwater Control (Reference 4.1.38) under emergency conditions. The startup level provided is the only measurement of steam generator inventory at low power levels, because the operate range is sensed at a steam generator tap 102' above the lower tube sheet while startup range is sensed 6" above the lower tube sheet. 2-5 SD-010 Rev. 4

o High Reverse Differential Pressure 2 Trip o Loss of all Reactor Coolant Pumps Trip 2.1.1.3 Other Functions o The SFRCS provides signals for plant indications and annunciating. o The SFRCS provides bypass capability during power operation for the normal plant startup or shutdown process. Other bypass capabilities during power operation are not provided. o To facilitate testing, the SFRCS provides bypass capabilities, while the plant is shutdown in Modes 4, 5 and 6. 0 The SFRCS has block capabilities for certain SFRCS trip output signals while SFRCS actuation signals are present with auto reset when the SFRCS actuation signal is absent. 0 The SFRCS monitors and displays the valve status of SFRCS actuated solenoid valves on the output panels A5. o The SFRCS monitors and displays at the output panel A5 the trip relay contact status of all MOVs' trip contacts using a trickle current through the opening starter coil, or closing coil if applicable. The display is OFF when the power supply of the MCC control circuit is unavailable or a field interlock to the SFRCS trip circuit is present. o The relay status of all other SFRCS trip outputs is monitored and their status is displayed on output panel A5. 2.1.1.4 Designations, Nomenclature, and Conventions The following listing identifies the various channel designations used in this document and in other TE documentation: Sensing Channels (input loops), logic channels (SFRCS channels), and Actuation Channels (output loops). Generally, the numerical designations will be used in'this document to identify SFRCS channels and plant loops. The color designations shown in parentheses are listed to identify the associated cable/raceway color coding and/or the cabinet colors, where applicable. The SFRCS is a two (2) protection channel system. Each protection channel encompasses two (2) sensing channels, two (2) logic channels and one (1) actuation channel: Sensing .... Logic--- I ---------- Actuation Channel-------- Channel Channel Essential Non-essential To ARTS Protection Channel 1 i (green) 1 (green) 1 (green) A (dark blue) 1 (green)

3. (green) 3 (green) 1 (green) A (dark blue) 3 (blue)

Protection Channel 2 2 (orange) 2 (orange) 2 (orange) B (tan) 2 (orange) 2-4 SD-010 Rev. 4

Both inputs to the input AND-gates - sensing the same process variable - must be present in either complementary pair of logic channels 1 and 3 and/or 2 and 4 before either logic channel will accept and process the trip condition. This feature, which was added with the newly designed system (References 4.5.4, 4.5.5 and 4.8.1), prevents the unwanted trip coincidence by unrelated process variables. The simplified figures show only one input to the output AND-gate. The second input is marked "LCH.3" (logic channel 3) or "LCH.4" (logic channel 4) respectively. To trip SFRCS actuated equipment, the output AND-gates monitor the presence of a trip condition in both the complementary logic channels 1 and 3 or in logic channels 2 and 4. Manual trip circuits and shutdown bypasses are also not shown. For the complete logic refer to Drawing E-18 Sheets 1 though 3 (Reference 4.1.10). In addition to its SFRCS trip functions, the SFRCS also provides: containment isolation valve operation, operator indications, the capability for shutdown and system bypass, the capability to selectively block SFRCS trip signals, and the alarm outputs to station annunciator and plant computer. The SFRCS is a safety system qualified to operate and perform its safety functions in the environment specified in Reference 4.2.1. 2.1.1.1 Measured Variables The SFRCS monitors the following plant parameters: o Steam Generator-1 Startup Level o Steam Generator-2 Startup Level o Main Steam Line-i Pressure o Main Steam Line-2 Pressure o Main Feedwater Line-i / Steam Generator-i Differential Pressure o Main Feedwater Line-2 / Steam Generator-2 Differential Pressure o Reactor Coolant Pump Status 2.1.1.2 Trip Functions The SFRCS incorporates the following automatic trip functions: o Low Steam Generator-i Pressure Trip o Low Steam Generator-2 Pressure Trip o Low Steam Generator-i Level Trip o Low Steam Generator-2 Level Trip o High Steam Generator-i Level Trip o High Steam Generator-2 Level Trip o High Reverse Differential Pressure 1 Trip 2L3 SD-010 Rev. 4

opening or the closing starter coil at the MCC of the MOV. The SFRCS trip signal or the loss of the power or the contact closure in both complementary logic channels causes the motor starter to open or to close the valve. For the main turbine trip the SFRCS output of each logic channel drives one slave relay located in the two non-1E SFRCS interface cabinets. The series connection of the dry Form B contacts of both slave relays located within one interface cabinet, are wired in parallel with the other series connection at a third cabinet location and cabled to the main turbine master trip bus. Either protection channel will trip the Main Turbine. Both the SFRCS output relays and the slave relays are normally energized and de-energize to trip. For the ARTS trip the SFRCS output relay in logic channels 1 and 2 provide a dry Form B contact, each which is directly connected to the input of ARTS protection channel 1 and ARTS protection channel 2 respectively. SFRCS Logic channels 3 and 4 are connected to the ARTS protection channels 3 and 4 of ARTS via an isolation relay each. The output relays and isolation relays are normally energized (de-energize to trip). A trip of any two of the four SFRCS logic channels will trip ARTS. The SFRCS trip interface to ARTS is different than all other interfaces. ARTS is a four (4) channel protection system and SFRCS is two a (2) channel protection system. While channels 1 and 2 of either system have the same channel classification (same color codes), channels 3 and 4 have separate channel classifications - SFRCS logic channel 3 is part of protection channel 1 and therefore cannot directly interface protection channel 3 of ARTS. Same criterion applies to logic channel 4 of SFRCS and protection channel 4 of ARTS. Therefore, an isolation scheme with metal barriers and enclosed raceways between the ARTS cabinets and the SFRCS Relay Cabinets are installed to meet the separation criteria for. Davis-Besse (References 4.4.8 and 4.5.32) Caution: In addition, the trip logic for ARTS is different'from all other SFRCS actuated equipment. While the SFRCS trip signal to every other actuated equipment has a 2-out-of-2 trip logic, the ARTS trip logic within the ARTS cabinets has 2-out-of-4 trip logic. That means that any combination of two or more input trip signals will trip ARTS, they may be from the two different SFRCS protection channels. An ARTS initiation will result in a Reactor trip. If the ARTS trip was initiated from logic channels of different SFRCS protection channels, none of the remaining SFRCS actuated equipment will receive an SFRCS trip signal. Four (4) auxiliary feedwater initiation switches on the operators console provide a manual SFRCS trip capability independent of the automatic trip action. For a simplified functional diagram of the SFRCS trip system refer to Figure 2.1-1, Simplified SFRCS Logic Diagram, protection channel 1, and Figure 2.1-2 Simplified SFRCS Logic Diagram, protection channel 2. The logic for all four logic channels is identical. The figures represents logic channel 1 and 2. The logic channels 3 and 4 are not shown, since they are monitoring the same digital input signals as logic channels 1 and 2 respectively. Electrical isolation is provided to eliminate propagation of electrical faults between the complementary channels. The input AND-gates and the output AND-gates on the figures are identified by arrows for reference in the following discussion. The inputs of the two variables connected to the input AND-gate marked with an asterisk (*) are powered by logic channels 3 or 4 respectively. 2-2 SD-010 Rev. 4

2.0 SYSTEM DESIGN DESCRIPTION 2.1 DESIGN DESCRIPTION 2.1.1 General Description The SFRCS is a protection system as defined by IEEE 279 (Reference 4.4.6) which ultimately protects the reactor core from fuel cladding damage and prevents overpressurization of the reactor coolant system and the containment. The safety function of the SFRCS is to detect and isolate the affected steam generator from either main steam line break (MSLB) or a main feedwater line break (MFWLB) . The SFRCS also automatically starts the Auxiliary Feedwater Pumps (AFPs) and supplies the Auxiliary Feedwater (AFW) to the unaffected steam generator. The other safety function of the SFRCS is to automatically start the AFPs in the event of a low level in the steam generator or loss of all four reactor coolant pumps and to supply AFW to respective steam generators. Although its not a safety function, SFRCS also isolates the MFW to the steam generator in the event of high steam generator level to prevent the steam generator overfill and subsequent spill over into the main steam lines. The high level trip also isolates main steam isolation valves to prevent damage to down stream plant equipment and isolate main feedwater. To accomplish this protection, the SFRCS monitors various plant parameters and automatically initiates SFRCS trip signals to the SFRCS actuated equipment when a sensed parameter or group of parameters indicates the approach of an unsafe condition. The SFRCS is comprised of two (2) independent and redundant protection channels. Each channel has its own independent sensors, which are physically separated from the other channel's sensors and from non-safety system components. No communication of any kind exists between either protection channel. For purpose of testability and reliability, each protection channel is further divided into two (2) sensing channels and two (2) trip logic channels. Each sensing channel provides all monitored digital plant status signals to either logic channel via signal buffer modules. Thus making both sets of sensing and logic channels electrically independent. The corresponding output signals of each logic channel are AND-gated to form the actuation channel. Signal processing is performed in the logic cabinets. The status signal from each corresponding sensing channel monitoring the same plant variable is combined in a 2-out-of-2 logic before it is further processed by the SFRCS logic module. The SFRCS observes continuously two SFRCS sensing and logic channels for a simultaneous trip condition before actual SFRCS trip signals are sent to the SFRCS actuation channel. This makes the actual trip logic of each of the two redundant SFRCS protection channels a '2-out-of-21 logic. For solenoid operated SFRCS valves, the SFRCS supplies 125 Vdc - in few exceptions 120 Vac - to the solenoid coils, controlled by Form A contacts (make when energized, open to trip) to keep the solenoid coils normally \ energized. For a trip the SFRCS will de-energize the coils. For motor operated valves (MOVs) the SFRCS provides dry Form B contacts (break when de-energized, closed to trip) of normally energized (de-energize to trip) output relays, which energizes and seals-in the holding current for either the

                                               . 2-1                           SD-010 Rev. 4

The safety-related portions of the SFRCS are subject to environmental qualification. For more information, refer to the EQ Master Equipment List (Reference 4.5.3) and Electrical Equipment Qualification File No. DBl-100 (Reference in Section 4.5.22). 1.2.10 Fire Protection and Security Requirements 1.2.10.1 Fire Protection There are no special fire protection requirements. There are Detection and Suppression Systems in the equipment areas to meet industry standards for fire protection. For more information, refer to the Design Criteria Manual (Reference 4.5.1), the Fire ProtectionSystem Description (Reference 4.1.46), or the Fire Hazard Analysis Report (Reference in Section 4.5.2). 1.2.10.2 Security The SFRCS is located within the vital area and hence has no special security requirements. 1-14 SD-010 Rev. 4

1.2.8 .2 Industry Standards (Reference 4.4) The SFRCS shall meet all applicable requirements of the following IEEE Standards: IEEE Standard 279-1971 - "Criteria for Protection Systems for Nuclear Power Generating Stations." IEEE Standard 308-1980 - "Criteria for Class 1E Power Systems for Nuclear Power Generating Stations." IEEE Standard 338-1971 - "Criteria for the Periodic Testing of Nuclear Power Generating Station Safety Systems." IEEE Standard 344-1975 - "Recommended Practices for Seismic Qualification of Class 1E Equipment for Nuclear Power Generating Stations." IEEE Standard 383-1974 - "Standard for Type Test of Class IE Electric Cables, Field Splices, and Connections for Nuclear Power Generating Stations." IEEE Standard 384-1984 - "Standard Criteria for Independence of Class 1E Equipment and Circuits." IEEE C37.90.1-1974 - "IEEE Guide for Surge Withstand Capability (SWC)

                                      -Tests" 1.2.8.3          NRC Regulatory Guides The SFRCS shall    meet all applicable portions of the following NRC Regulatory Guides:

RG 1.22 - Periodic Testing of Protection System Actuation Functions RG 1.29- Seismic Design Classification RG 1.30 - Quality Assurance Requirements for the Installation, Inspection and Testing of Instrumentation and Electric Equipment RG 1.47 - Bypassed and Inoperable Status Indication for Nuclear Power Plant Safety Systems RG 1.53- Application of the Single Failure Criterion to Nuclear Power Plant Protection Systems'ý' RG 1.97*- Instrumentation for Light-Water-Cooled Nuclear Power Plants to Access Plant and Environ Conditions During and Following an Accident. SFRCS is only involved in supplying the signal for meeting the room, diverse powered, redundant SG level indication requirement. 1.2.9 Environmental Qualification Requirements 1-13 SD-010 Rev. 4

primary power of 120 Vac (108 to 132 Vac) and 60 Hz (57 to 63 Hz), grounded, for logic and control circuits and of 125 Vdc (105 - 140 Vdc), ungrounded, for the remote solenoid coil circuits. A transfer time of 1/2 cycle or a voltage dip of 20% for 30 milliseconds shall not result in any trip or loss of the SFRCS system. (Reference in Section 4.2.1). The station's electrical system meets these requirements with the following exceptions:

1. Following a loss of offsite power with a LOCA and a single failure of 4160 volt bus C1, the logic channel 3 power source to cabinet C5762Z may drop below 105 VDC. With the SFRCS being a fail safe (de-energize to trip)system, low voltage could lead to a half trip in actuation channel 1 for the main turbine and the start-up & main feedwater valves. (See Reference 4.4.1 and 4.5.44).

2. With bus Cl/DI voltage degraded to just above-the 90% undervoltage relay minimum trip value, the logic channel 3/4 power supply (for logic and SG level transmitters), YE211/YE211, may not meet the minimum of 108 VAC (120-10%) . In this case, all the logic channel 3/4 outputs may trip, giving a one half trip for all actuation channel 1/2 actuated equipment. If both SFRCS logic channels 3 and 4 tripped due to the degraded voltage condition at the same time, then ARTS would trip the reactor. With the logic channel 3/4 power supply coming from CI/Di, on a loss of offsite power, the logic channels would trip due to their fail safe design. Logic channel power would be restored when the respective EDG powered its essential 4160 VAC bus. (See Reference 4.4.1 and 4.5.45).

1.2.7 Quality Assurance Requirements The SFRCS shall be designed, fabricated, installed, tested and operated with the application of a Quality Assurance program as defined in 10CFR50,. Appendix B, "Quality Assurance Criteria for Nuclear Power Plants and Fuel Processing Plants" and 10CFR50, Appendix A, GDC 1, "Quality Standards and Records." (Reference in Sections 4.4.5 and 4.2.1). 1.2.8 Codes and Standards 1.2.8.1 Code of Federal Regulations (References 4.4.5, 4.4.1 and 4.2.1) The SFRCS shall meet all applicable portions of 10CFR50. In particular, the following General Design Criteria of Appendix A are applicable: Criterion 1 Quality Standards and Records Criterion 2 Design Bases for Protection against Natural Phenomena Criterion 3 Fire Protection Criterion 4 Environmental and Missile Design Bases Criterion 13 Instrumentation and Control Criterion 15 Reactor Coolant System Design Criterion 20 Protection System Functions Criterion 21 Protection System Reliability and Testability Criterion 22 Protection System Independence Criterion 23 Protection System Failure Modes Criterion 24 Separation of Protection and Control Systems The following additional appendices are also applicable: Appendix B - Quality Assurance Criteria for Nuclear Power Plants and Fuel Reprocessing Plants Appendix R - Fire Protection Program For Nuclear Power Facilities Operating Prior to January 1, 1979

                                            '1-12                         SD-010 Rev. 4

1.2.2.2 Seismic The SFRCS system equipment shall be classified as Seismic Class I. The remote transducers and switches that provide input for a trip function shall be classified as Seismic Class I-The SFRCS system shall be designed to maintain structural integrity during a Maximum Possible Earthquake as-required and defined by the Davis-Besse Design Criteria Manual (Reference in Section 4.5.1). For reference see Sections 4.2.1 and 4.4.9. 1.2.3 System Configuration Requirements The SFRCS shall consist of two independent redundant protection channels. Each protection channel shall consist of two electrically independent complementary logic channels. Each complementary logic channel shall monitor the same key parameters involved in SFRCS protection and shall issue trip signals - without initiating the protection channel trip (SFRCS trip) - when any of the measured variables or groups of measured variables'indicates that a limiting condition is being reached. The trip output of each complementary logic channel shall be combined in each protection channel in a two-out-of-two logic, so that the SFRCS will initiate a protection channel trip if both of the complementary logic channels trip. The trip command shall be the de-energization of the SFRCS output relays in each of the logic channels. The SFRCS shall function as a "de-energize totrip" system. (Reference in Section 4.2.1) Similarly, the removal of power, or loss of power, or test of one complementary logic channel shall de-energize all affected relays, without causing an SFRCS initiation, but shall be alarmed by the station annunciator and plant computer. 1.2.4 Surveillance Testing and Inservice Inspection (ISI) Requirements The SFRCS shall be designed with built-in test features for testing and calibrating the system at all levels of plant operation without interfering with normal plant operation. (References in Section 4.4.6). Surveillance testing requirements for setpoint, response times and logic are defined in reference 4.4.2 and 4.4.18. Response times are defined to ensure not only that the safety action occurs, but occurs in a time sufficient to satisfy the accident analysis. The SFRCS is not subject to any ISI requirements. 1.2.5 Setpoint Bases The SFRCS setpoints are based on accident analysis assumptions, equipment performance, and anticipated operational needs. The resulting setpoints create an operating envelope that provides the necessary protection to ensure that the reactor does not violate certain safety limits or accident acceptance criteria. For a listing of all setpoints refer to Table 3.3-1. For the setpoint bases refer to Appendix B. 1.2.6 Electrical Requirements The SFRCS shall be designed for continuous operation when supplied with i-Ii SD-010 Rev. 4

1.2.1.11 Periodic Testing and Calibration The SFRCS shall permit periodic testing and calibration of its functions when the reactor is in operation, including a capability to test channels independently without initiating protective action. (References in Sections 4.4.2, 4.4.6 and 4.4.7) 1.2.1.12 Loss of Power Loss of power to two complementary SFRCS channels shall initiate an SFRCS trip and send a signal to the Plant Annunciator and Computer. (Reference in Section 4.4.6). 1.2.1.13 Completion of Protective Action Once initiated, the SFRCS trip signals shall go to completion for two seconds. After the SFRCS sensed parameter(s) returned to normal and after 2 seconds have expired, the SFRCS shall reset automatically. No operator action shall be required to reset the SFRCS. The automatic reset is required to permit the SFRCS to respond to changing input conditions and to automatically realign the SFRCS controlled valves appropriately. The 2 second seal-in is to insure that the control of all actuated equipment has responded. The SFRCS actuated equipment shall go to completion and shall require operator action to reset the equipment individually to normal operation. (References in Section 4.4.6) 1.2.1.14 Access to Setpoint Adjustments, Calibration Adjustments, and Test Points The system design shall provide for administrative control of access to setpoint adjustments, module calibration adjustments, and test points as stated in USAR Section 7.4.2.3. (Reference in Sections 4.4.6, 4.4.7, and 4.4.17). 1.2.1.15 Equipment Removal The removal of any module required to perform a protective function shall initiate the protective action normally associated with that portion of the system. (References in Section 4.4.6). 1.2.2 Structural Requirements The SFRCS shall be specified to the following environmental and seismic requirements: 1.2.2.1 Environmental All portions of the SFRCS that are located in the cabinet room shall be designed for continuous operation over a temperature range of 40 to 110'F, 80% RH, and atmospheric pressure. This equipment shall also be designed for one week (168 hour) operation at a temperature of 130OF at 100% relative humidity (RH) without condensation. For reference see Section 4.2.1. The cabinet room, where the SFRCS cabinets are located, is maintained at approximately 75°F and 50 percent relative humidity in the summer and 75'F and 30 percent relative humidity in the winter. If for any reason the control room temperature should reach 110'F and continue to rise during normal station operation, administrative procedures will require a station shutdown. For reference see Section 4.4.1. 1-10 SD-010 Rev. 4

o High Steam Generator-1 Level 0 High Steam Generator-2 Level shall be bypassed. During this bypass operation, the remainder of the SFRCS shall continue to meet the requirements of the single failure criteria. (Reference in Section 4.4.6). While the station is in MODES 4, 5 and 6 most SFRCS sensed parameters may be in a tripped condition, making it then impossible to verify proper operation of the SFRCS instrumentation strings and trip logic. Therefore the SFRCSx design shall provide individual manual means (bypasses) allowing to restore individually the untripped condition of all input process signals to permit trip testing without the usage of wire jumpers. (Reference in Section 4.5.21) The control of this bypass shall be administrative only. In MODES 4, 5 and 6, as defined in the Technical Specifications (Reference in Section 4.4.2), the SFRCS performs no safety function and therefore this provision does not have to meet the requirements of the single failure criteria. For definition of the Modes see Reference 4.4'.2 (Section Definition). 1.2.1.6 Anticipatory Reactor Trip System The SFRCS shall provide trip signals to the Anticipatory Reactor Trip System. (Reference in Section 4.4.11). For details refer to Section 2.9.6.5. 1.2.1.7 Annunciator and Computer The SFRCS -shall provide signals for annunciator alarms and computer monitoring. (References in Sections 4.4.6 and 4.4.7). For details refer to Sections 2.9.1 and 2.9.2. 1.2.1.8 Operator Display The SFRCS shall provide a display of steam generator startup levels for the operator at the operators panel in the control room. (Reference in Section 4.8.7). 1.2.1.9 Single Failure No single failure within the SFRCS shall prevent proper protection system action when required. (Reference in Section 4.4.6). The SFRCS shall provide, two (2) independent protection channels to meet the single failure criterion. In order to meet the above single failure criteria, the following cross channel' actuations are necessary: o Both startup feedwater valves are actuated by both SFRCS actuation channels,, o Both main steam isolation valves are actuated by both SFRCS actuation channels, o The main feedwater valves are closed by the opposite SFRCS actuation channel. 1.2.1.10 Independence The SFRCS channels that provide signals for the same protective function shall be independent and physically separated. (Reference in Section 4.4.6) 1-9 SD-010 Rev. 4

Main Feedwater-2 / Steam Generator-2 Differential Pressure Steam Generator-I Level Steam Generator-2 Level Reactor Coolant Pump Status 1.2.1.2 Automatic SFRCS Trip Functions The SFRCS shall automatically initiate trip output signals based on the following: Low Main Steam Line-i Pressure Low Main Steam Line-2 Pressure High Main Feedwater-i / Steam Generator-i Differential Pressure High Main Feedwater-2 / Steam Generator-2 Differential -Pressure Low Steam Generator-i Level Low Steam Generator-2 Level High.Steam Generator-I Level *) High Steam Generator-2 Level *) Loss of Four Reactor Coolant Pumps

            ... the steam generator overfill is a design basis for the SFRCS only.

Overfill protection is not a design basis accident reported in the TJSAR and not required in the Technical Specification. For the complete listings of actions to be accomplished refer to Section 2.9.6. The SFRCS shall initiate its trips with the accuracy and in the response time assumed in the safety analysis for Design Basis Accident calculations used to determine the various trip setpoints. These setpoints are used in the safety analysis of the postulated accidents for which the SFRCS is to provide protection. Any change in SFRCS accuracy, setpoint, or response time shall require a re-analysis of the trip function to ensure that adequate protection, as analyzed in the safety analysis, is still provided. '1.2.1.3 Manual Auxiliary Feedwater Initiation The SFRCS shall provide the operator with the capability to manually initiate auxiliary feedwater from the operators panel in the control room (Reference 4.4.6). The automatic SFRCS shall override the manual initiation to ensure that the steam to the auxiliary feedwater pump turbine is being taken from and the auxiliary feedwater is being fed to the 'good' steam generator. This eliminates potential erroneous operator action. Credit for manual initiation is not assumed in the safety analysis for Design Basis Accidents. 1.2.1.4 Steam Generator Startup Level Instrumentation The SFRCS shall provide Steam Generator Startup Level signal indications for operator information atthe main'control board. Reference in Sections 4.8.7 and 4.8.10. 1.2.1.5 Bypasses and Removal From Operation The SFRCS design shall provide a bypass during plant heatup and cooldown and wet layup without initiating a channel trip. Specifically, the SFRCS initiation on o Low Main Steam-i Line Pressure o Low Main Steam-2 Line Pressure 1-8 SD-010: Rev. 4

or shutdown. (References in Section 4.4.6.) Provide channel output blocks for selected valves (see Table 2.1-18 for listing) at the main control board to block the SFRCS output signal while the SFRCS output signal is present. This feature shall allow the operator .to regain manual control of actuated valve(s). (References in Sections 4.5.5, 4.8.12, and 4.8.13) Provide individual input parameter bypass features to facilitate maintenance and testing in Modes 4, 5 and 6. (References in Sections 4.4.6 and 4.4.7) 1.1.2.2.3 Output Trip Signals Provide output trip signals to actuate solenoid valves or solenoid controlled valves, to interface motor operated valves as inputs to other systems, to interface the main turbine trip bus and to interface the four channels of ARTS. 1.1.2.2.4 Solenoid Valve Control Signals Provide seal-in control circuits for each SFRCS solenoid valve and solenoid controlled valve to interface a momentary switch contact from the main control board for normal manual control (opening and closing) of the valves. 1.2 DESIGN REQUIREMENTS The SFRCS shall automatically monitor plant parameters and automatically initiate an SFRCS trip when the parameters reach or exceed the setpoint values indicating the approach of accident conditions. The SFRCS trip shall be a function of the monitored plant parameter exceeding a set point value and also a function of the sequence in which the set point value was exceeded. With the exception of the reactor trip which shall be facilitated via the Anticipatory Reactor Trip System (ARTS), the SFRCS trip output shall be direct acting and shall not interface intermediate devices or control systems. The operator shall have the capability of manually initiating auxiliary feedwater based on his assessment of plant conditions and independent of any other systems inputs. However, the automatic Signal of the SFRCS shall override the manual initiation signal and shall align the actuated valves appropriately. Refer to Figures 2.1-1 and 2.1-2 for the simplified SFRCS Logic Diagram for protection channel 1 and 2 respectively. This system requirement section documents the requirements and describes the operation of the SFRCS and the equipment within its boundaries. This document does not encompass all the systems and equipment which take partin the SFRCS trip function. In particular, the auxiliary feedpump turbine control and the steam generator level control mustbe reviewed to completely understand the auxiliary feedwater supply initiated by the SFRCS. For detail see the Auxiliary Feedwater System Description SD-015 (Reference 4.1.38). 1.2.1 Process/Performance Requirements 1.2.1.1 Sensed Parameters The SFRCS shall monitor the following plant parameters for use in trip initiations: Main Steam Line-1 Pressure Main Steam Line-2 Pressure Main Feedwater-i / Steam Generator-i Differential Pressure 1-7 SD-010 Rev. 4

1.1.2.1.5 Loss of Four Reactor Coolant Pump Incident Provide mitigation for the incident loss of off-site power resulting in loss of four reactor coolant pumps, which causes loss of reactor coolant flow and therefore auxiliary feedwater is needed to establish reactor coolant natural circulation flow. The SFRCS starts the auxiliary feedwater supplies to either steam generator by opening the steam supply from either steam generator to either auxiliary feedwater pump turbine and aligning the auxiliary feedwater pump to its associated steam generator. The main feedwater flow, the main steam and the steam generators will not be isolated. The reactor - via ARTS - and the main turbine will be tripped. The following plant parameter is used: o Reactor Coolant Pump Status For listing of the actuated equipment refer to Table 2.1-13. For Reference see Section 4.6.16 1.1.2.1.6 Manual Auxiliary Feedwater Initiation Provide the capabilities for the operator to manually start the auxiliary feedwater supply to either steam generator from the main control board in the control room with or without steam generator isolation. The main turbine and the reactor - via ARTS- shall be tripped in either case. The automatic SFRCS signal shall override the manual actuation. For a listing of equipment, refer to Tables 2.1-14, 2.1-15, 2.1116, and 2.1-17. For reference see Section 4.5.28. 1.1.2.1.7 Containment Isolation SFRCS actuates the following containment isolation valves. See Reference 4.5.39. o FW-601, FW-612 o ICSIIA, ICS11B o MS-100, MS-101 o MS-100-1, MS-101-1 o MS-106, MS-106A o MS-107, MS-107A o MS-375, MS-394 o MS-603, MS-611 1.1.2.2 Other Operational Functions 1.1.2.2.1 Steam Generator Startup Level Indication Provide steam generator startup level indications for operator information at the main control board. (Reference in Sections 4.6.17 and 4.8.7) 1.1.2.2.2 Bypasses/Block Provide operating bypass features to manually block the steam generator low pressure trip or the high SG level trip initiation during normal plant startup 1-6 SD-010 Rev. 4

auxiliary feedwater pump turbine and aligning the auxiliary feedwater pump to its associated steam generator and isolating main feedwater, main steam and the steam generators.- The reactor - via ARTS - and the main turbine will be tripped. The SFRCS responds similarly, with reduced steam generator(s) inventory, except that main feedwater, main steam and steam generators will not be isolated. The following plant parameters are used: o Main Feedwater Line-i/Steam Generator-i Diff. Pressure o Main Feedwater Line-2/Steam Generator-2 Diff. Pressure o Steam Generator-i Startup Level o Steam Generator-2 Startup Level For listing of the actuated equipment,, when actuated by the differential pressure or together with low steam generator level, refer to Table 2.1-10. For listing of the actuated equipment, when actuated only by the steam generator low level, refer to Table 2.1-11. In the case that either steam generator pressure depletes rapidly the action of the following plant parameters override the above listed parameters: o Main Steam Line-i Pressure o Main Steam Line-2 Pressure The SFRCS responds differently, as detailed in Section 1.1.2.1.1, by isolating the steam generator with the low steam line pressure and aligning both auxiliary feedpump turbines and feedpumps to the second steam generator. For listing of the resulting actuated equipment refer to Table 2.1-8 or Table 2.1-9. References in Sections 4.6.16 and 4.ý.20. 1.1.2.1.4 Steam Generator Overfill Incident Provide prevention of liquid carryover into the steam lines which, would challenge the integrity of piping and support caused by excessive main feedwater addition. Protection against long term flooding of the aspirator port is achieved through procedural requirements. With high inventory in either or both steam generators the SFRCS starts the auxiliary feedwater supplies to either steam generator by opening the steam supply from either steam generator to either auxiliary feedwater pump turbine and aligning the auxiliary feedwater pump to its associated steam generator and isolating main feedwater, main steam and the steam generators. The reactor - via ARTS - and the main turbine will be tripped. The following plant parameters are used: o Steam Generator-i Startup Level o Steam Generator-2 Startup Level For listing of the actuated equipment refer to Table 2.1-12. References in Sections 4.6.3 and 4.6.25 i-5 SD-010 Rev. 4

Steam supply from the unaffectedsteam generator is being lined up to the two redundant auxiliary feedpump'turbines. Steam.supply to the main turbine and to the main feedpump turbines are being cut-off to preserve steam. Likewise, auxiliary feedwater from the two auxiliary. feedpumps',are directed to feed the unaffected steam generator. The reactor via ARTS - and the main turbine will be tripped. The following plant parameters are used: o Main Steam Line-i Pressure (SG-1) o Main Steam Line-2 Pressure (SG-2) For listing of the actuated equipment refer to Tables 2.1-8 and 2.1-9. (References in Sections 4.6.18, 4.6.19 and 4.6.26) 1.1.2.1.2 Main Feedwater Line Rupture Incident Provide mitigation for the incident of main feedwater line rupture upstream of check valve FW147 in feedwater line-i and upstream of check valve FW156 in feedwater line-2 to assure that specified acceptable fuel design limits are not exceeded due to rapid blow down of both steam generators, resulting in a rapid Reactor Coolant System (RCS) cool down and therefore a rapid reactivity insertion under certain core conditions. Main feedwater and main steam valves are closed and the steam 'supply to the main turbine and to the main feedwater turbines are cut-off to preserve steam. Steam from either steam generator is being supplied to either of the two redundant auxiliary feedpump turbines. Likewi'se, auxiliary feedwater is being supplied to either steam generator to replace the main feedwater. The'reactor - via ARTS - and the main turbine will be tripped. The following plant parameters are used: o Main Feedwater Line-I/Steam Generator-i Diff. Pressure o Main Feedwater Line-2/Steam Generator-2 Diff. Pressure For listing of the actuated equipment refer to Table 2.1-10. In the case that either steam generator pressure depletes rapidly the action of the following plant parameters override the above listed parameters: o Main Steam Line-i Pressure (SG-i) o Main Steam Line-2 Pressure (SG-2) The SFRCS responds differently, as detailed in Section i.1.2.1.i1 by isolating the steam generator with the low steam line pressure-and aligning both auxiliary feedpump turbines and feedpump's to the second or good steam generator. For listing of. the actuated equipment refer to Table 2.1-8 or Table 2.1-9. 1.1.2.1.3 Loss of Main Feedwater. Incident Provide mitigation-for the incident of loss of feedwater by initiating auxiliary feedwater to replace main feedwater. With high reverse differential pressure across the main feedwater check valves, the SFRCS starts the auxiliary feedwater supplies to either steam generator by opening the steam supply from either steam generator to either 1-4 SD-010 Rev. 4

For listing of these valves refer to Table 2.7-1. The supply voltage for non-essential solenoid valves is provided from Non-essential 120 Vac Instrument AC Distribution Panels Y4501 and Y4502 for logic channels 1 and 2 respectively. For logic channels 3 and 4 the power is provided from Non-essential 125 Vdc Distribution panels DAP and DBP respectively. For listing of these valves refer to Table 2.7-2. The input terminals in the SFRCS cabinet to which the power is connected form the system boundary. Refer to Section 2.7, ELECTRICAL SYSTEMS AND POWER SUPPLIES, for a more detailed description of the SFRCS power. The SFRCS requires power feeds for the logic and control circuits as well as control power for the field installed solenoid valves. 1.1.1.4 Annunciator and Computer Alarm Interface The SFRCS outputs various signals to the control room and the annunciator system for indication of plant conditions and SFRCS status and to the plant computer for data gathering purposes. The SFRCS cabinet terminal blocks to which these output signals are connected form the system boundary. For a listing of alarm outputs refer to Table 2.9-1. 1.1.2 Functions 1.1.2.1 Functions Important to Safe Plant Operation The SFRCS is a nuclear power plant protection system as required and defined by 10CFR50 and IEEE 279. (References 4.4.5 and 4.4.6) The SFRCS is required to actuate auxiliary feedwater to the NSSS steam generators to remove reactor decay heat during periods when normal feedwater supply .and/or the supply to the reactor coolant pump motors have been lost. One auxiliary-feedwater supply is normally aligned to each steam generator, and crossover piping may be used to direct feedwater from either source to either steam generator. The SFRCS functions to isolate steam and main feedwater lines to mitigate ov'ercooling events caused by steam depressurization. In every automatic and manual SFRCS initiation, ARTS (and therefore the reactor) and the Main Turbine will be tripped. The following are SFRCS functions important to safe plant operation to mitigate in the following incidents: 1.1.2.1.1 Main Steam Line Rupture Incident Provide mitigation for the incident of main steam line rupture, either upstream or downstream of main steam isolation valve (MSIV) to assure that specified acceptable fuel design limits are not exceeded during any condition due to rapid blow down of both steam generators, resulting in a rapid Reactor Coolant System (RCS) cool down and therefore a rapid reactivity insertion under certain core conditions. For the unlikely event that both steam generators lose pressure, the SFRCS logic determines the 'first' steam generator with low pressure and isolates this steam generator only. The SFRCS assumes that the other steam generator ('second') is not.affected. Should the 'first' steam generator recover, while the 'second' steam generator maintains a low steam generator pressure, the SFRCS logic will isolate the 'second' steam generator and will line-up the valves for auxiliary steam and feedwater to the 'first' steam generator. Feedwater and steam line valves are closed to isolate the steam line rupture. 1-3 SD-010 Rev. 4

1.1.1.2 Signal Interface The SFRCS output signals are: dry contacts, contacts which apply 120 Vac or 125 Vdc to the field installed devices, or SG level indication signals. The SFRCS output signals are wired to terminal blocks in the SFRCS cabinets. The terminal block connections form the SFRCS boundary for all output signals except for the below listed valves. Main Steam Line-i Isolation Valve MS-101 Main Steam Line-2 Isolation Valve MS-100 Main Feedwater-1 Startup Control Valve FW-SP7B Main Feedwater-2 Startup Control Valve FW-SP7A Main Feedwater-1 Control Valve . FW-SP6B Main Feedwater-2 Control Valve FW-SP6A. The SFRCS output signal for those valves is a pneumatic pressure signal at the output port of the SFRCS activated solenoid valves. The pneumatic pressure signals are making up the SFRCS output AND-gate. The boundary is being formed by the input port with the air supply and by the output port or the pneumatic piping with the pneumatic pressure signal to the booster or main valve. The SFRCS actuated valves listed above are the exception. Refer .to Figures-2.2-24, 2.2-25 and 2.2-26, which show the typical boundary for these valves. Refer to Section 2.2, SENSORY EQUIPMENT, and Section 2.4, CONTROLLED DEVICES AND INDICATIONS, for a listing of SFRCS inputs and outputs. The SFRCS interfaces directly with the following systems: System Signal, Reactor Protection System Reactor Coolant Pump Monitor Anticipatory Reactor Trip System ARTS/Reactor Trip Main Turbine Turbine Trip Main Feedwater System Feedwater Isolation Main Steam System SteamIsolation Auxiliary Feedwater System Auxiliary Feedwater Initiation Post Accident Monitoring System SG Startup Level 1.1.1.3 Power Interface The SFRCS requires power feeds for the logic and control circuits as well as control power for the field installed solenoid valves. The logic and control circuits of the SFRCS receives 120 Vac power from Essential Instrumentation AC Distribution Panels Y1 and Y2 for logic channels 1 and 2 respectively. For logic channels 3 and 4 120 Vac power is supplied from YE2 'and YF2 respectively. The supply power for essential solenoid valves is being provided 120 Vac power from Essential Instrumentation AC Distribution Panels Y1 and Y2 for logic channels 1 and 2 respectively. For logic channels 3 and 4 the power is being provided from Essential 125 Vdc Distribution Panels DIP and D2P respectively. 1-2 SD-010 Rev. 4

STEAM AND FEEDWATER LINE RUPTURE CONTROL SYSTEM 1.0 SYSTEM REQUIREMENTS 1.1 SYSTEM BOUNDARIES AND FUNCTIONS 1.1.1 System Boundaries The Steam and Feedwater Line Rupture Control System (SFRCS) interfaces with several plant systems to provide protection for the reactor core and the reactor coolant system. These interfaces can be divided into four major categories: (1) operator interface, (2) signal interface, (3) power interface, and (4) computer and alarm interface. These interfaces form the system boundaries as described below. In addition to the above interfaces, the SFRCS also requires proper operation of the control room ventilation system, but there is no direct interface and, therefore, no boundary with that system. Figure 1.1-1 Simplified SFRCS Block Diagram shows the SFRCS boundaries. Table 1.1-1 SFRCS System Boundary defines the boundary in detail. 1.1.1.1 Operator Interface The SFRCS provides the operator with the capability of manually initiating auxiliary feedwater flow to either or both steam generators without steam generator isolation or with steam generator isolation from four (4) switches located in the control room on the center console, panel C5707. The SFRCS provides the operator manual shutdown block features to block the automatic SFRCS steam generator low pressure trip or the high level trip during normal plant startup or shutdown. The switches are located in the control room on panel C5721. The SFRCS provides block switches for the SFRCS actuated equipment with an output block feature. Once activated, the operator is enabled to manually control (SFRCS override) the SFRCS actuated equipment. To initiate the block, the SFRCS trip signal has to be present. The block switches are located next to the actuated equipment control switches in the control room on the center console, panels C5706, C5708 through C5710 and C5712. The actuated equipment control switches, except those for the solenoid operated SFRCS actuated equipment, are outside the SFRCS boundary. They interface the motor control centers which are part of the various systems to which the controlled valves belong. For all solenoid operated SFRCS actuated equipment, the SFRCS provides manual control switches located on the control room panel to allow the Operator to manually control (Open(Reset)/Close) these valves under normal conditions or under SFRCS trip conditions after the block switch has been activated, if provided. The switches are located in the control room on the center console, panels C5706, C5708, C5709 and C5712 and in the cabinet room on panels C5762N and C5792N. For a listing of the SFRCS manual switches refer to Table 2.9-2. In addition, the SFRCS provides steam generator startup level indications for operator information. The manual auxiliary feedwater initiation switches, the manual shutdown bypass switches, the individual manual output block switches and the steam generator startup level indicators which interface directly with the SFRCS cabinets are within the SFRCS boundary. 1-i. SD-010 Rev. 4

LIST OF APPENDICES Appendix Title Page. A. Acronyms and Abbreviations A-I B. Setpoint Bases B-I viii SD-010 Rev. 4

LIST OF FIGURES Figure Title Page 1.1-1 Simplified SFRCS Block Diagram F1.1-i-i 2.1-1 Simplified SFRCS Logic Diagram, Protection Channel 1 F2 .1-1-1 2.1-2 Simplified SFRCS Logic Diagram, Protection Channel 2 F2 .1-2-1 2.1-3 SG-I Startup Level Instrumentation, Logic Channels 1 & 3 F2 .1-3-i 2.1-4 SG-I Startup Level Instrumentation, Logic Channels 2 & 4 F2 .1-4-1 2.1-5 SG-2 Startup Level Instrumentation, Logic Channels 1 & 3 F2 .1-5-1 2.1-6 SG-2 Startup Level Instrumentation, Logic Channels 2 & 4 F2 .1-6-1 2.1-7 Main Steam Line-I Pressure Instrumentation F2 .1-7-1 2.1-8 Main Steam Line-2 Pressure Instrumentation F2 .1-8-1 2.1-9 Main Feedwater Line-i Diff. Pressure Instrumentation F2 .1-9-1 2.1-10 Main Feedwater Line-2 Diff. Pressure Instrumentation F2 .1-10-1 2.1-11 RC Pump Monitoring, SFRCS Logic Channel 1 F2. I-li-i 2.1-12 RC Pump Monitoring, SFRCS Logic Channel 2 F2 .1-12-1 2.1-13 RC Pump Monitoring, SFRCS Logic Channel 3 .F2.1-13-1 2.1-14 RC Pump Monitoring, SFRCS Logic Channel 4 F2;1-14-1 2.1-15 Logic Symbols and Legend F2.1-15-1 2-1-16 SFRCS Actuated Components, 100% Power Normal Line-up F2.1-16-1 2.2-1 Typica 1l SFRCS Output, with Manual Initiation F2.2-I-I 2.2-2 Typica 1i SFRCS Output, with Solenoid Control Feature F2.2-2-1 2.2-3 Typica 1iSFRCS Output, with Block Control Feature F2.2-3-1 2.2-4 Typica 1iMOV Output with Open Function F2.2-4-1 2.2-5 Typica.1 MOV Output with Open/Close Function F2.2-5-i 2.2-6 Typica.1 120 VAC Solenoid Output F2.2-6-1 2.2-7 Typica.1 125 VDC Solenoid Output F2.2-7-1 2.2-8 Typica.1 Power Auctioneered Solenoid Output F2.2-8-1 2.2-9 Input Panel A2 Protection Channel 1 F2.2-9-1 2.2-10 Input Panel A2 Protection Channel 2 F2.2-10-i 2.2-11 Output Panel A5 Protection Channel 1 F2.2-11-1 2.2-12 Output Panel A5 Protection Channel 2 F2 .2-12-i 2.2-13 throug'h 2.2.17 not used 2.2-18 Contro 1 Logic Diagram, AFP-i Disch to SG-2 Vlv AF-3869 F2.2-18-1 2.2-19 Contro 1 Logic Diagram, Main Steam Line-i Iso Valve MS-101 Solenoid Valves SV-101B, SV-101A F2.2-19-1 2.2-20 Contro 1 Logic Diagram, Main Steam Line-i Iso Valve MS-101 I Solenoid Valves SV-101E, SV-101C/D F2.2-20-i 2.2-21 Contro i Logic Diagram, SG-i Drain Stop.Valve MS-611 F2.2-21-1 2.2-22 Contro 1 Logic Diagram, AFPT-I Main Steam In Iso Valve MS-5889A F2.2-22-I 2.2-23 Control Logic Diagram, Main Steam Line-I WU Iso Valve MS-101-1 F2. 2-23-1 2.2-24 Pneumatic Diagram, Main Steam Line-i Iso Valve MS-101 F2 .2-24-i 2.2-25 Pneumatic Diagram, Main Feedwater-2 Control Valve FW-SP6A F2 .2-25-1 2.2-26 Pneumatic Diagram, Startup ControlValve FW-SP7B F2 .2-26-1 vii SD-010 Rev. 4

LIST OF TABLES Table Title Page 1.1-1 SFRCS System Boundary T1.1-1-1 2.1-1 Steam Generator Startup Level Transmitter List T2. 1-1-1 2.1-2 Main Steam Line Pressure Trip Switch List T2.1-2-1 2.1-3 Main Steam Line Pressure Shutdown Block Switch List T2.1-3-1 2.1-4 Main Feedwater/Steam Generator Differential Pressure Switch List T2.1-4-1 2.1-5 RC Pump Monitoring SFRCS Input Signal List T2.1-5-1 2.1-6 SFRCS Actuated Equipment List for Protection Channel 1 T2.1-6-1 2.1-7 SFRCS Actuated Equipment List for Protection Channel 2 T2.1-7-1 2.1-8 Low Steam Line-i Pressure Trip T2. 1-8-1 2.1-9 Low Steam Line-2 Pressure Trip T2 .1-9-1 2.1-10 High Reverse Differential Pressure Trip T2 .1-10-1 2.1-11 Low Steam Generator Level Trip T2.1-11-1 2.1-12 High Steam Generator Level Trip T2.1-12-1 2.1-13 Loss of Reactor Coolant Pumps Trip T2.1-13-1 2.1-14 HIS-6401 Manual Trip of Protection Channel 1 without SG Isolation T2.1-14-1 2.1-15 HIS-6402 Manual Trip of Protection Channel 2 without SG Isolation T2.1-15-1 2.1-16 HIS-6403 Manual Trip of Protection Channel 1 with SG-1 Isolation T2.1-16-1 2.1-17 HIS 6404 Manual Trip of Protection Channel 2 with SG-2 Isolation T2.1-17-i 2.1-18 Valves with Block Features T2 .1-18-1 2.1-19 SFRCS Output Panel Status Lights T2 .1-19-1 2.2-1 List of All Analog Variable Inputs T2 .2-1-1 2.2-2 List of All Digital variables Inputs T2 .2-2-1 2.2-3 Valve List with SFRCS Independent Interlocks T2 .2-3-1 2.2-4 Trip Confirm LEDs for MOVs T2 .2-4-1 2.2-5 Trip Confirm LEDs for Valves with Pneumatic AND-Gates T2 .2-5-1 2.2-6 Trip Confirm LEDs for Valves with Power Auctioneering T2 .2-6-1 2.2-7 Trip Confirm LEDs for Main Turbine and ARTS Trip T2 .2-7-1 2.3-1 Field Buffer Module Input Listing T2 .3-1-1 2.3-2 Logic Module Input/Output Listing T2 .3-2-1 2.3-3 Relay Driver Module Output Listing T2 .3-3-1 2.3-4 Alarm Output Module Output Listing T2 .3-4-1 2.7-1 Essential Solenoid Valve List T2 .7-1-1 2.7-2 Non-Essential Solenoid Valve List T2 .7-2-.1 2.7-3 Valve List with Loss of Power Override Interlocks T2 .7-3-1 2 .9-1 Digital Outputs to Annunciator and Computer T2 .9-1-1 2.9-2 SFRCS Manual Switch Listing T2 .9-2-1 2.9-3 SFRCS Actuated Valves of the Auxiliary Feedwater System T2. 9-3-1 2.9-4 SFRCS Actuated Valves of the Secondary Plant System T2.9-4-1 2.9-5 SFRCS Actuated Valves of the Main Steam System T2.9-5-1 2.9-6 SFRCS Trip Signals to Turbine Trip System T2.9-6-1 2.9-7 SFRCS Trip Signals to ARTS T2.9-7-1 3.3-1 SFRCS Setpoints T3.3-1-1 vi SD-010 Rev. 4

TABLE OF CONTENTS (Continued) SECTION PAGES 2.5 System Arrangement 2-40 2.5.1 Equipment Layout 2-40 2.5.2 Logic Cabinet 2-41 2.5.3 Relay Cabinet 2-41 2.5.4 Non-IE Interface Cabinets 2-42 2.5.5 Interconnecting Hardware 2-42 2.5.6 Normal System Configuration 2-42 2.6 Ancillary Indications 2-42 2.6.1 Input Panel 2-42 2.6.2 Output Panel 2-44 2.7 Electrical Systems and Power Supplies 2-45 2.7.1 External Power Supplies 2-45 2.7.2 Internal Power Supplies 2-47 2.7.3 Loss of Power 2-50 2.7.4 Grounding 2-50 2.8 Special Material or System Chemistry Considerations 2-50 2.9 System Interfaces 2-50 2.9.1 Plant Computer 2-51 2.9.2 Plant Annunciator 2-51 2.9.3 Operator Control Panel 2-51 2.9.4 Startup Test Panel 2-51 2.9.5 Technical Support Center 2-51. 2.9.6 Interfaces with Other Systems 2-51 3.0 SYSTEM LIMITATIONS, SETPOINTS, AND PRECAUTIONS 3-1 3.1 Section Deleted 3-1 3.2 Other Limits and Precautions 3-1 3.3 Setpoints. 3-1

4.0 REFERENCES

4-1 4.1 Design Drawings and Documents 4-1 4.2 Equipment Specifications 4-11 4.3 Vendor Equipment Manuals and Drawings 4-11 4.4 Applicable USAR Sections, Technical Specifications, and Regulatory Documents 4-19 4.5 Miscellaneous Controlled Documents 4-20 4.6 Uncontrolled Documents -Used for Reference Only 4-22 4.7 As-built Design Changes 4-23 4.8 FCRS/MODS - Implemented 4-24 v SD-010 Rev. 4

TABLE OF CONTENTS SECTION PAGES LIST OF EFFECTIVE PAGES i RECORD OF REVISIONS iii TABLE OF CONTENTS iv LIST OF TABLES vi LIST OF FIGURES vii LIST OF APPENDICES viii 1.0 SYSTEM REQUIREMENTS 1-1 1.2 System Boundaries and Functions i-1 1.1.1 System Boundaries 1-1 1.1.2 Functions 1-3 1.2 Design Requirements 1-7 1.2.1 Process/Performance Requ:irements 1-7 1.2.2 Structural Requirements 1-10 1.2.3 System Configuration Req uirements 1-11 1.2.4 Surveillance Testing & I]niservice Inspection (ISI) Requirements 1-11 1.2.5 Setpoint Bases 1-11 1.2.6 Electrical Requirements 1-11 1.2.7 Quality Assurance Requirements 1-12 1.2.8 Codes and Standards 1-12 1.2.9 Environmental Qualification Requirements 1-13 1.2.10 Fire Protection and Security Requirements 1-14 2.0 SYSTEM DESIGN DESCRIPTION 2-1 2.1 Design Description 2-1 2.1-1 General Description 2-1 2.1.2 Loop Description 2-5 2.2 Sensory Equipment 2-16 2.2.1 Steam Generator Level Transmitter 2-16 2.2.2 Steam Line Pressure Switches 2-18 2.2.3. Differential Pressure Switches 2-19 2.2.4 Reactor Coolant Pump Monitors 2-20 2.2.5 SFRCS Trip Confirm 2-21 2.3 Signal Processing and Output Devices 2-24 2.3.1 Signal Monitor Module 2-24 2.3.2 Dixson Bargraph Indicator Module 2-28 2.3.3 Field Buffer Module 2-29 2.3.4 Logic Module 2-30 2.3.5 Relay Driver Module 2-33 2.3.6 Alarm Output Module 2-34 2.3.7 Electromechanical Relays 2-34 2.3.8 Door Alarm 2-38 2.3.9 Fan Failure Detector 2-38 2.3.10 Key Switch 2-38 2.3.11 Transmitter Power Supplies 2-38 2.3.12 SFRCS Manual Initiation 2-39 2.4 Controlled Devices and indications 2-39 2.4.1 Reactor Trip via ARTS 2-40 2.4-.2 Signals to Plant Computer 2-40 2.4.3 Signals to Station Annunciator 2-40 2.4.4 Signals to the Startup Test Panel 2-40 2.4.5 Signals to Technical Support Center 2-40 2.4.6 Controlled Devices 2-40 iv SD-010 Rev. 4

RECORD OF REVISIONS Preparer Checker Rev. (Initials (Initials No. Date Summary of Chanqe and Date) and Date) 0 Issued for Use

• 1 Revised to Incorporate *
• SDCN's 010-00-01, 010-00-02 010-00-03, 010-00-04 and 010-00-05, and to Remove Unused Sections.

2 Revised to Incorporate SDCN's 010-00-09, 010-00-10 010-00-11, 010-00-12, General Update and inclusion of Reactor Coolant Pump Monitor Circuitry. 3 Revised to Incorporate SDCN's 010-02-01, 010-02-02 010-02-03, 010-02-04, 010-02-05 and general update to correct admin

• L errors.

4 Revised to Incorporate SDCN 010-01-001, 010-03-001, 002, 003, 004, 005, 006, 009, 010, 013, 014

• See previous revision for information.

iii SD-010 Rev. 4

LIST OF EFFECTIVE PAGES (Continued) Page Revision Page Revision Page Revision T2.1-19-i 4 F2 .1-12-1 4 T2.1-19-2 4 F2 . 1-13-1 4 T2.2-i-1 4 F2.1-14-1 4 T2 .2-2-i 4 F2..1-15-i 4 T2..2-2-2 4 F2. 1-16-1 4 T2 .2-3-1 4 F2.2-i-i 4 T2 .2-4-1 4 F2.2-2-1 4 T2 .2-5-1 4 F2.2-3-1 4 T2 .2-6-1 4 F2 .2-6-1 4 T2 .2-7-1 4 F2.2-8-1 4 T2. 3-1-1 4 F2 .2-9-1 4 T2 3-1-2 4 F2.2-10-I 4 T2 .3-2-1 4 F2.2-li-i 4 T2 .3-2-2 4 F2.2-12-1 4 T2 3-3-1 4 F2.2-18-1 4 T2 3-3-2 4 F2.2-19-1 4 T2. 3-4-1 4 F2 .2-20-1 4 T2 .3-4-2 4 F2 .2-21-1 4 T2 .3-4-3 4 F2.2-22-1 4 T2 3-4-4 4 F2.2-23-i 4 T2 7-1-1 4 F2.2-24-i 4 T2 .7-2-1 4 F2.2-25-1 4 T2 7-3-1 4 F2.2-26-1. 4 T2 9-1-1 4 A-I 4 T2. 9-1-2 4 A-2 4 T2. 9-1-3 4 B-i 4 T2 9-2-1 4 B-2 4 T2 9-2-2 4 T2 9-2-3 4 T2. 9-3-1 4 T2 9-4-1 4 T2.9-5-1 4 T2 . 9-6-1 4 T2.9. 7-1 4 T3.3-1-1 4 T3 .3-1-2 4 T3.3-1-3 4 FI.1-I-i 4 F2 . 1-i-i 4 F2.1-2-1 4 F2.1-3-1 4 F2 . 1-4-1 4 F2. 1-5-1 4 F2.1-6-1 4 F2.1-7-1 4 F2.1-9-1 4 F2. 1-10-i 4 F2 . i-1i-i 4 ii SD-010 Rev. 4

LIST OF EFFECTIVE PAGES Page Revision Page Revision Page Revision i 4 2-23 4 4-4 4 ii 4 2-24 4 4-5 4 iii 4 2-25 4 4-6 4 iv 4 2-26 4 4-7 4 v 4 2-27 4 4-8 4 vi 4 2-28 4 4-9 4 vii 4 2-29 4 4-10 4 viii 4 2-30 4 4-11 4 1-1 4 2-31 4 4-12 4 1-2 4 2-32 4 4-13 4 1-3 4 2-33 4 4-14 4 1-4 4 2-34 4 4-15 4 1-5 4 2-35 4 4-16 4 1-6 4 2-36 4 4-17 4 1-7 4 2-37 4 4-18 4 1-8 4 2-38 4 4-19 4 1-9 4 2-39 4 4-20 4 1-10 4 2-40 4 4-21 4 1-11 4 2-41 4 4-22 4 1-12 4 2-42 4 4-23 4 1-13 4 2-43 4 4-24 4 1-14 4 2-44 4 4-25 4 2-1 4 2-45 4 T1.1-1-1 4 2-2 4 2-46 4 T1.1-1-2 4 2-3 4 2-47 4 T1.1-1-3 4 2-4 4 2-48 4 T1.1-1-4 4 2-5 4 2-49 4 T1.1-1-5 4 2-6 4 2-50 4 T2.1-1-1 4 2-7 4 2-51 4 T2.1-2-1 4 2-8 4 2-52 4 T2.1-3-1 4 2-9 4 2-53 4 T2.1-4-1 4 2-10 4 3-1 4 T2.1-5-1 4 2-11 4 3-2 4 T2.1-6-1 4 2-12 4 4-1 4 T2.1-7-1 4 2-13 4 4-2 4 T2.1-8-1 4 2-14 4 4-3 4 T2.1-9-1 4 2-15 4 T2.1-10-1 4 2-16 4 T2.1-11-1 4 2-17 4 T2.1-12-1 4 2-18 4 T2.1-13-1 4 2-19 4 T2.1-14-1 4 2-20 4 ýT2.1-15-1 4 2-21 4 T2.1-16-1 4 2-22 4 T2.1-17-1 4 T2.1-18-1 4 SD-010 Rev. 4

SYSTEM DESCRIPTION FOR STEAM AND FEEDWATER LINE RUPTURE CONTROL SYSTEM FOR THE TOLEDO EDISON COMPANY DAVIS-BESSE NUCLEAR POWER STATION UNIT 1 OAK HARBOR, OHIO Prepared by: (/2 , 4i'l

                              /1)  ~/
                                           /                  Date 7

Checked by: AJA Date Approved by: Systems Engineering Supervisor iatE SD-.010 Rev. 4

S F t2- C- Cc "ý *Q 05i\/ Lcc (- Se SFRCS ACTUATED COMPONENTS IOO1 POWER NORMAL LINEUP FIGURE 2.1-16. 4-- F2. 1-16-1 SD-0IO REV. 1 DB:I2-2O-04 OfNH:/SY S S/StW 2Vi16 O-1

rz c I tY\aA T~~'rYAJ2~ Tryf' (C~'sF~ ~ S 4o~ SFRCS ACTUATED COMPONENTS IOO1 POWER NORMAL LINEUP FIGURE 2.1-16 F2. 1-16-1 SD-OIO REVA 08:12-20-04 DFiNH:/SYSDLSlSDW2 1 61.

Standard Initiation and Isolation displayed on following pages. Note: The below listed valves MS 106/106A/1 07/107A AF 3869/3870/3871./3872 Operate as needed based on logic depending on a low pressure condition in the steam generators. They operate as needed to line up steam supply to both Aux Feed Pumps from the "good" steam generator and both Aux Feed Pump discharges to the "good" steam generator. SFRCS Initiation will:

    - Start each Aux Feed Pump and align steam supply and pump discharges to respective steam generator.
    - Trip the main turbine (close Turbine Stop Valves)
    - No effect on Main Steam or Main Feedwater

sRP-Cs Ac Coýo" ,. 4

      -S4    va SFRCS ACTUATED COMPONENTS lOO0 POWER NORMAL LINEUP FIGURE 2.1-16 F2.I1-16-1                       SD-OO         REV.4 I. D8:12-2-0-04    DFN=H:/SYSDES/SDf2 11'1."DGN

SF~RC~ /1/24~~,f$cAl\ I JT, ý - (ý".4

                                                     - / 17,g 1ý/ 4 e--            rý07vl-C~o~ T~-Y~ S 4~

SFRCS ACTUATED COMPONENTS 1OOZ POWER NORMAL LINEUP FIGURE 2.1-16 F2. 1-16-I SD-010 REV.I1 DB: I2-20-04 DFNIl:/SYSOLS/SOF2 2 16 1 DON

SFRCS Actuated components are shown on the following pages by Actuation Channel. Components are shown in their normal lineup.

NRC ITS Tracking Page 4 of 4 Date Created: 01/10/2008 10:37 AM by Aron Lewin Last Modified: 02/25/2008 07:53 AM http://www.excelservices.com/exceldbs/itstrackdavisbesse.nsf/1 fddceal Od3bdbb585256e... 7/18/2008

NRC ITS Tracking Page 3 of 4 feed to the good steam generator." The following was not discussed on the call, but some details concerning the circuitry are contained inthe attached system description. The logic is shown in the simplified figures. The system description provides some information concerning the functioning of the circuits and modules. All of the logic functions forSFRCS are performed in the Logic Modules. The Logic Modules provide input to Relay Driver Modules, which energize the output relays to cause the required component actions. Again, it was not clear what the reviewer wanted to know, but this information might help. NRC Response by Aron Lewin - Can you confirm that the two out of two taken twice logic applies on 01/29/2008 to the AFW pump valve isolations as well when determining wether or not to feed a steam generator. - In addition, can you discuss why Required Action A in LCO 3.3.13 (page 456 of 636) does not have an operator verify that the AFW pump for the unaffected Actuation Channel is operable (i.e. even if by administrative means), given that an Actuation Channel will only start its associated pump. The STS is based on a design that assumes each Actuation Channel can start both AFW pumps. Licensee Response by Bill ITS 3.3.13 Bases, Insert 1, page 461 of Volume 8, describes the Bentley on 02/18/2008 logic operation of SFRCS. The description also refers to UFSAR Figure 7.4-4. The description of the logic given in the ITS 3.3.13 Bases is correct, and applies to the actuation of the steam inlet and pump outlets for feeding the "good" steam generator. Required action A in 3.3.13 does not need to have the operator verify the AFW pump for the unaffected channel. The reason for this is because of LCO 3.0.6. SFRCS is a support system for AFW (a supported system in ITS 3.7.5). Since AFW is a supported system, LCO 3.0.6 states that "When a supported system LCO is not met solely due to a support system LCO not being met, the Conditions and Required Actions associated with this supported system are not required to be entered. Only the support system LCO ACTIONS are required to be entered. This is an exception to LCO 3.0.2 for the supported system. In this event, an evaluation shall be performed in accordance with Specification 5.5.15, "Safety Function Determination Program (SFDP)." If a loss of safety function is determined to exist by this program, the appropriate Conditions and Required Actions of the LCO in which the loss of safety function exists are required to be entered." In this way, the administrative requirements of the SFDP will ensure that no loss of safety function exists. For the specific example raised by the reviewer, if an SFRCS actuation channel was declared inoperable

                                     - the SFDP would require a review of the status of AFW on the
                                   ,,opposite train.

NRC Response by Aron Lewin Will request conference call with licensee via PM. on 02/20/2008 ii NRC Response by Aron Lewin No further questions at this time. on 02/25/2008 i http://www.excelservices.com/exceldbs/itstrackdavisbesse.nsf/1 fddcea 1Od3bdbb585256e... 7/18/2008

NRC ITS Tracking Page 2 of 4

                   -Does one actuation channel isolate both main steam headers?
                   -Does one actuation channel isolate both main feed headers?
                   -Does one actuation channel start both AFW pumps?
                   -Is an AFW "pump start" signal needed for automatic AFW pump isolation valve manipulation, and if so, how is this signal provided?
                   -Which specific complimentary logic inputs and specific actuation channel inputs control the AFW pump isolation valves during various plant conditions (i.e. intact steam generators, rupture in steam generator A, and rupture in L                   steam generator B)?

Issue_Date[ 01/10/2008 Close Date [ 02/25/2008 Logged in User: Anonymous "'Responses Licensee Response by Bill Questions 200801101037 and 200801101119 requested technical Bentley on 01/12/2008 background information concerning the Steam Feed Rupture Control System (SFRCS). The attached overview provides a general description of how each Actuation Channel of SFRCS actuates various plant components. The SFRCS System Description will also be attached in the next response. The System Description provides a much more detailed description of the SFRCS design, logic channels, and actuation channels. This information should also be an aid to assist with the background for __ ____ __ question 200801101123. Licensee Response by Bill The SFRCS System Description is attached for background Bentley on 01/12/2008 information. SNRC Response by Aron Lewin Requesting conference call via PM. on 01/17/2008 Licensee Response by Bill A call was held with the reviewer on 1/23/08. The below is an Bentley on 01/24/2008 attempt to summarize the discussion, as requested by the reviewer:

1. As shown on the SFRCS overview attachment, each Actuation Channel of SFRCS will: Close both Main Steam Isolation Valves, Close a combination of Feedwater Isolation Valves that will isolate feedwater flow on both headers, Trip the Main Turbine (which closes all 4 Turbine Stop Valves), and will start its respective Aux Feed Pump. 2. The logic for actuation is 2 out of 2 taken twice.

The simplified figures in the attached System Description show the logic scheme. For example, in Logic Channel 1, both PS3689B (SG-1) and PS3689F (SG-1, powered by Logic Channel 3) must trip to give a trip of Logic Channel 1. Similarly, in Logic Channel 3, both pressure switches must trip to give a trip of Logic Channel

3. Logic Channel 1 and Logic Channel 3 must both trip to cause an Actuation of Actuation Channel 1. 3. A question was asked, but joint understanding could not be reached during the call.

Paraphrasing, the reviewer wanted to know "where or how are the input signals for low steam generator pressure converted such that the aux feed pump valves are aligned to receive steam from and http://www.excelservices.com/exceldbs/itstrack-davisbesse.nsf/lfddceal Od3bdbb585256e... 7/18/2008

NRC ITS Tracking Page 1 of 4 Return to View Menu I,.Print Document RAI Screening Required: Yes Status: Closed This Document will be approved by: Carl Regulatory Basis must be included in Comments Schulten; Tim Kobetz; Gerald Waig section of this Form This document has been reviewed and Yes information in this question contains NO SUNSI sensitive material (the checkbox to the right must be selected before this question can be submitted) NRC ITS TRACKING NRC Reviewer ID 200801101037 Conference Call Requested? No Category Other Technical Challenge ITS..S.ectiom:' T"B.POC: JFD Number: P.age Nu.mber(s):

             ITS 3.3 Aron Lewin                             None Information [TS Niumnbe-r:         OS-.:.               DOC Number:        Bas$e s..JFD Numn!.ber :.

3.3.11 None None, None NRC OSI#63 Discuss the logic of the SFRCS in order to determine if appropriate actions, as permitted by 10 CFR 50.36(d)(2)(i), are being taken for an inoperable instrument channel.

Background:

                   - The CTS (page 365 of 636) has Action 16 for when a SFRCS Functional Unit of Table 3.3-11 (starting on page 362 of 636) is inoperable. Action 16 states "with the number of operable channels one less than the total number of channels, startup and/or power operation may proceed until performance of the next required channel functional test provided the inoperable section of the channel is placed in the tripped condition within 1 hour."
                   -The ITS (page 378 of 636) has a Condition A that requires an instrumentation Comment channel to be placed in trip within 1 hour if it is inoperable.
                   -Condition A of the STS for LCO 3.3.11 (NUREG-1430) is different from the ITS and CTS, but is based on a different SFRCS design.

10 CFR 50.36(d)(2)(i) states that "limiting conditions for operation are the lowest functional capability or performance levels of equipment required for safe operation of the facility..When a limiting condition for operation of a nuclear reactor is not met, the licensee shall shut down the reactor or follow any remedial action permitted by the technical specifications until the condition can be met." The logic of the SFRCS is unclear and therefore it is difficult to determine if appropriate actions, as permitted by 10 CFR 50.36(d) (2)(i), are being taken for an inoperable instrument channel (i.e. with regards to continued plant operation in ITS Condition A and SFRCS actuation given a single failure). In order to better understand the SFRCS, the following information is needed: http://www.excelservices.com/exceldbs/itstrackdavisbesse.nsf/1 fddceal Od3bdbb585256e... 7/18/2008

Remote Shutdown Monitoring Instrumentation 3.3.4 3.3 INSTRUMENTATION 3.3.4 Remote Shutdown Monitoring Instrumentation LCO 3.3.4 The remote shutdown monitoring instrumentation Functions shall be OPERABLE. APPLICABILITY: MODES 1, 2, and 3. ACTIONS i ------------------------- NOTEZ------------ - ---------- - - ---- - -- - Separate Condition entry is allowed for each Funct CONDITION REQUIRED ACTION COMPLETION TIME A. One or more required A.1 Restore required Function 30 days Functions inoperable, to OPERABLE status. B. Required Action and B.1 Be in MODE 3. 6 hours associated Completion Time not met. AND B.2 Be in MODE 4. 12 hours SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.3.4.1 Perform CHANNEL CHECK for each required 31 days instrumentation channel that is normally energized. SR 3.3.4.2 Perform CHANNEL CALIBRATION for each 24 months required instrumentation channel. Cook Nuclear Plant Unit 1 3.3.4-1 Amendment No. 287

• Attachment 1, Volume 8, Rev. 1, Page 527 of 827 JUSTIFICATION FOR DEVIATIONS ITS 3.3.4, REMOTE SHUTDOWN MONITORING INSTRUMENTATION

1. ISTS 3.3.4 requires Remote Shutdown System Functions to be OPERABLE. As stated in the Bases, these Functions include not only instrumentation to monitor plant parameters, but also control switches and circuits to operate equipment necessary to shut down and maintain the unit in MODE 3. The requirements of ITS 3.3.4 only include the instrumentation necessary to monitor the prompt shutdown to MODE 3, including the necessary instrumentation to support maintaining the unit in a safe condition in MODE 3. This change is consistent with the current licensing basis for the Remote Shutdown Instrumentation in CTS 3/4.3.3.5. As a result of this change, the Specification's title and LCO statement have been changed from "Protection System" to "Monitoring Instrumentation," and ISTS SR 3.3.4.2, which verifies control circuit and transfer switch capability, has not been included in the ITS.

2. The brackets are removed and the proper plant specific information/value is provided.

3. ISTS SR 3.3.4.4 requires performance of a TADOT of the reactor trip breaker open/closed indication. This requirement has not been included in the CNP Unit 1 and Unit 2 ITS. CTS 3/4.3.3.5 does not contain this requirement. Thus, this deviation from the ISTS has been made to retain the current licensing basis.

OPERABILITY of the Reactor Trip Breaker Indication will be adequately verified by the performance of a CHANNEL CALIBRATION (ITS SR 3.3.4.2). CNP Units 1 and 2 Page 1 of 1 Attachment 1, Volume 8, Rev. 1, Page 527 of 827

Attachment 1, Volume 8, Rev. 1, Page 525 of 827 Remote Shutdown4 e 3.3.4 3.3 INSTRUMENTATION --- .....

                                                                                                                         .4-,.

3.3.4 Remote Shutdown t _s__vs -~, ~. 3. C- LCO 3.3.4 The ,,,emoted'hutdown: ýFunctions shall be OPERABLE. APPLICABILITY: MODES 1, 2, and 3. ACTIONS

                                                            - NOTI     -

1. LCO 3.0.4 is not a licable yf'~

i.c. A.7 12.Sep~arate Condition entry is allowed for each Function. CONDITION REQUIRED ACTION COMPLETION TIME A. One or more required A.1 Restore required Function 30 days A c ict* rk Functions inoperable, to OPERABLE status. B. Required Action and B.1 Be in MODE 3. 6 hours associated Completion Time not met. AND B.2 Be in MODE 4. 12 hours SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY

                                                                                                                        ;2-SR 3.3.4.1      tPerform CHANNEL CHECK for each required                      31 days instrumentation channel that is normally energized.

I1= I SR3 Verif eac required control circ and transfer switchý capable of performi the intended function. WOG STS 3.3.4 - 1 Rev. 2, 04/30/01 Attachment 1, Volume 8, Rev. 1, Page 525 of 827

NRC ITS TrackingP Page 3 of 3 Design Criteria for Nuclear Power Plants as published in the Federal-Register on February 20, 1971, and as amended in the Federal Register on July 7, 1971." NRC Response by Aron Lewin Technical Branch assistance formally requested. Issue being on 03/24/2008 tracked by TAC MD8349. NRC Response by Aron Lewin No further questions regarding GDC 19. Issue of Remote on 05/12/2008 Shutdown Panel being deleted from TS to be resolved in Thread 200801231234. Date Created: 01/23/2008 12:33 PM by Aron Lewin Last Modified: 05/12/2008 04:26 PM http://www.excelservices.com/exceldbs/itstrackdavisbesse.nsf/lfddcea 1Od3bdbb585256e... 7/18/2008

NRC ITS Tracking Page 2 of 3. prompt hot shutdown of the reactor, including necessary instrumentation and controls to maintain the unit in a safe condition during hot shutdown, and (2) with a potential capability for subsequent cold shutdown of the reactor through the use of suitable procedures." Given the discussion in the USAR, it is unclear how the TS ensure that equipment at appropriate locations outside the control room is operable, in order to ensure that a prompt hot shutdown of the reactor could occur in accordance with 10 CFR 50, Appendix A, GDC 19. IIssue Date 01/23/2008 IClose Date 1 05/12/2008 Logged in User: Anonymous 'Responses Licensee Response by Jerry The Davis-Besse CTS does not include requirements for remote Jones on 02/14/2008 shutdown equipment control circuits and transfer switches. As stated in the NRC reviewer's question, the Davis-Besse UFSAR states that equipment is provided to meet GDC 19. Thus, currently the UFSAR adequately controls these requirements. Davis-Besse believes that it is not necessary to include in the ITS the Surveillance on the control circuits and transfer switches. The NRC has previously agreed that this SR is not necessary, as shown in the ITS conversion for DC Cook Units 1 and 2, approved June 1, 2005 (ADAMS Accession No. ML051520259). DC Cook used a similar Justification for Deviation (JFD) as the JFD proposed by Davis-Besse. The applicable pages of the DC Cook ITS conversion are provided as an attachment. Furthermore, the last two B&W ITS conversions, Oconee Units 1, 2, and 3 (dated December 16, 1998, ADAMS Accession No. ML012060036) and ANO Unit 1 (dated October 29, 2001, ADAMS Accession No. ML013050554) did not even include the Remote Shutdown Technical Specification. The NRC allowed the requirements to be maintained under utility control outside of the Technical Specifications. Therefore, Davis-Besse believes that it is acceptable to not include ISTS SR 3.3.18.2 in the Davis-Besse ITS and to maintain the appropriate controls in the UFSAR. NRC Response by Aron Lewin ill request conference call with licensee via PM. on 02/20/2008 NRC Response by Aron Lewin During a 2/21/2008 conference call, the licensee stated they would on 02/25/2008 provide a discussion of GDC 19 as it applies to the design of the plant, given the discussion in the USAR. Licensee Response by Jerry Davis-Besse was designed and under construction prior to the Jones on 03/19/2008 promulgation of 10 CFR 50, Appendix A. However, the design of Davis-Besse meets the intent of 10 CFR 50, Appendix A published in the Federal Register on February 20, 1971, and as amended in Federal Register on JulyT7, 1971. This is specifically stated in the Davis-Besse USAR, Appendix 3D. 110 (Page 1412 of 4076). The USAR states "The design of the Davis-Besse Nuclear Power Station meets the intent of Appendix A, 10CFR50, the General http://www.excelservices.com/exceldbs/itstrack-davisbesse.nsf/lfddcealOd3bdbb585256e... 7/18/2008

NRC ITS Tracking Page I of 3 II Return to..,View....... M,,,enu Print Document JAI Screening Required: Yes Status: Closed This Document will be approved by: Carl Regulatory Basis must be included in Comments Schulten; Gerald Waig section of this Form This document has been reviewed and Yes information in this question contains NO SUNSI sensitive material (the checkbox to the right must be selected before this question can be submitted) NRC ITS TRACKING NRC Reviewer ID 200801231233 Conference Call Requested? No C.ategory BSI - Beyond Scope Issue ITS.S.ection.: TB POC: JFDP.Numnber: Page.,Number(s): ITS 3.3 Aron Lewin None Information ITS Number: OS.1:1. DO.C. Number: Bas.es JFVD..Nu!m ber: 3.3.18 None None None NRC OSI#89 Discusss how the TS ensure that equipment at appropriate locations outside the control room is operable, in order to ensure that a prompt hot shutdown of the reactor could occur in accordance with 10 CFR 50, Appendix A, GDC 19.

Background:

                    -The CTS (page 593 of 636) only have monitoring instrumentation to support maintaining the unit in a safe shutdown condition from locations other than the control room. The USAR (page 1421 of 4076 in the USAR) states that in order to meet 10 CFR 50, Appendix A, GDC 19, "equipment at appropriate locations outside the control room is provided (1) with a design capability for prompt hot shutdown of the reactor, including necessary instrumentation and controls to maintain the unit in a safe condition during hot shutdown, and (2)

Comment with a potential capability for subsequent cold shutdown of the reactor through the use of suitable procedures."

                    -The ITS Bases (page 611 of 636) only have monitoring instrumentation to support maintaining the unit in a safe shutdown condition from locations other than the control room. The ITS Bases (pages 605 thru 611 of 636) are extensively marked up to reflect this. In addition the ITS Bases (page 605 of 636) deletes the reference to 10 CFR 50, Appendix A, GDC 19, even though the USAR discusses it.
                    -STS LCO 3.3.18 (NUREG-1430) provides for a Remote Shutdown System in order to provide the control room operator with sufficient instrumentation and controls to place and maintain the unit in a safe shutdown condition from locations other than the control room.

10 CFR 50, Appendix A, GDC 19 states "equipment at appropriate locations outside the control room shall be provided (1) with a design capability for http://www.excelservices.com/exceldbs/itstrackdavisbesse.nsf/1 fddcealOd3bdbb585256e... 7/18/2008

NRC ITS Tracking Page 2 of 2 Logged in User: Anonymous 'Responses Licensee Response by Bryan The CTS Bases words referenced in the NRC reviewers question Kays on 03/03/2008 were added to the CTS to clarify that while any two of the four (RE4596A, RE4596B, RE4597AB, and RE4597BB) canbe used to meet the Table 3.3-10 (Volume 8, Page 546), the preferred two channels are RE4596A and B. While CTS Table 3.3-10 does not specifically list the two types of channels, CTS Table 4.3-10 (Page 548) does list the two types of channels (Containment High Range Radiation and Containment Wide Range Noble Gas). Basically, the allowance to use any of the two types of channels is analogous to the ISTS, which allows continued operation with one or both Containment Area Radiation (High Range) provided the preplanned alternate method of monitoring is established (ISTS 3.3.17, ACTION F, Page 559 and ISTS 5.6.5, Volume 16, Page 135). Since RE4597AB and BB channels are the preplanned alternate methods of monitoring, the Davis-Besse ITS submittal maintained this manner of using either of the two types, consistent with our CTS. However, Davis-Besse has re-evaluated this decision and will now adopt the ISTS requirements fully. ITS Table 3.3.17-1 (Pages 561 and 562) will be changed to require two channels, with only the RE4596A and B channels acceptable. ISTS 3.3.17 ACTION F (Page 559) will be added back into the ITS as the ACTION to take when both Containment High Range.. Radiation channels are inoperable. Appropriate changes to the CTS Markup, Discussion of Changes, Justifications for Deviations, and Bases will also be made. Note that since only the Containment High Range Radiation channels will be used to meet the LCO requirements, the Surveillance Requirement for the Containment Wide Range Noble Gas channels will not be maintained. This is consistent with the ISTS in that the ISTS does not provide any requirements for the preplanned alternate means of monitoring - it is controlled by the Licensee. In addition, during the development of the draft markup it was noted that the description of how to perform a CHANNEL CALIBRATION for the Containment High range Radiation channels was in the wrong Surveillance Requirements Bases (it was described in SR 3.3.17.2 and should have been described in SR 3.3.17.3. This has been corrected. A draft markup regarding these changes is attached. These changes will be reflected in the supplement to this section of the ITS Conversion Amendment. NRC Response by Aron Lewin No further questions at this time. on 03/11/2008 Date Created: 01/29/2008 07:56 AM by Aron Lewin Last Modified: 03/11/2008 12 :02 PM http://www.excelservices.com/exceldbs/itstrack-davisbesse.nsf/1fddcealOd3bdbb585256e... 7/18/2008

NRC ITS Tracking Page I of 2 Return to View Menu] Pint Document RAI Screening Required: Yes Status: Closed This Document will be approved by: Carl Regulatory Basis must be included in Comments Schulten; Gerald Waig section of this Form This document has been reviewed and Yes information in this question contains NO SUNSI sensitive material (the checkbox to the right must be selected before this question can be submitted) NRC ITS TRACKING NRC Reviewer ID 20.0801290756 Conference CallRequested? No [ Categoy BSI - Beyond Scope Issue ITS Section: TB POC: JFD Number: Page Number(s):. ITS 3.3 Aron Lewin None

     -Information ITS NAniber:            OS!:                 DOC Number:          Bases JFD.Number:

3.3.17 None None None NRC OSI#95 Discuss what, if any, conditions on the license exist, that ensures that the directives found in Section II.F.1, Attachment 3, of NUREG-737, are met.

Background:

                     -The CTS Bases (page 403 of 490 in the CTS) state "LCO 3.3.3.6, Table 3.3-10 requires only two "Containment Vessel Post-Accident Radiation" channels be operable, i.e., any two of RE4596A, RE4596B, RE4597AB, and RE4597BB can be utilized to comply with the LCO. Since RE4596A and RE4596B were specifically credited for meeting NUREG-0737 Item II.F.1.3, and LCO 3.3.3.6 was credited as providing requirements for their operability,.RE4596A and Comment     RE4596B are the preferred monitors for complying with LCO 3.3.3.6."
                     -The ITS Bases do not contain this discussion.
                     -The STS LCO 3.3.17 Bases (NUREG-1430) do -not contain the discussion as well, however the STS acknowledges that plant specific PAM Instrumentation exists and is to be evaluated by the reviewer.
                     -NUREG-737, "Clarification of TMI Action Plan Requirements," Section II.F.1, Attachment 3 (on page 128 of 258 in ADAMs No. ML051400209),

references directives that required licensees to have containment high-range radiation monitors.

                     -With the removal of the information found in the CTS Bases, discuss what, if any, conditions on the license exist, that ensures that the directives found in Section II.F.1, Attachment 3, of NUREG-737, are met.

lssue.. Date 01/29/2008 Close Date 03/11/2008 http://www.excelservices.com/exceldbs/itstrackdavisbesse.nsf/1 fddceal Od3bdbb585256e... 7/18/2008

NRC ITS Tracking Page 2 of 2

                   -Modify Note (c) to make it more apparent that it applies to the Containment Vessel Post-Accident Radiation Instruments as a whole (ITS Instrument 8), or discuss why Note (c) ensures that the lowest functional capability or performance levels of equipment required for safe operation of the facility are met per 10 CFR 50.36(d)(2).

Issue Date]F01/29/2008 Cl 03/11/2008 Logged in User: Anonymous "R'esponses Licensee Response by Bryan As stated in the NRC reviewer's question only two channels of Kays on 03/03/2008 Containment Vessel Post-Accident Radiation are required to be OPERABLE. ITS Table 3.3.17-1, Function 8 (Volume 8, Page 561), breaks the Function up into two parts: 8.a, Containment High Range Radiation; and 8.b, Containment Wide Range Noble Gas. ITS Table 3.3.17-1 Note (c) (Page 561) states that two of the four total channels are required to be OPERABLE. The intent of this Note was to allow any combination of Function 8.a and 8.b channels such that a total of two are OPERABLE. However, based upon the Davis-Besse response provided in question 200801290756, the ITS submittal is being changed to only allow the Containment High Range radiation channels to meet the LCO requirements. Therefore, Note (c) is being deleted based on that response. See the response and the proposed draft markup for 200801290756. NRC Response by Aron Lewin No further questions at this time. on 03/11/2008, Date Created: 01/29/2008 07:55 AM by Aron Lewin Last Modified: 03/11/2008 12:01 PM http://www.excelservices.com/exceldbs/itstrackdavisbesse.nsf/ lfddceal Od3bdbb585256e... 7/18/2008

NRC ITS Tracking *Page I of 2 Return to View Menu Q Print D =cument RAI Screening Required: Yes Status: Closed This Document will be approved by: Carl Regulatory Basis must be included in Comments Schulten; Gerald Waig section of this Form This document has been reviewed and Yes information in this question contains NO SUNSI sensitive material (the checkbox to the right must be selected before this question can be submitted) NRC ITS TRACKING, NRC Reviewer ID 1200801290755 Conference Call Requested? No Catfegor BSI - Beyond Scope Issue ITS Section: TB POC: JFD N11,umb.er:. Page Number(s):. ITS 3.3 Aron Lewin None Information ITS Nu...nber:Z OS.'1. DOC Number:. Bases.,JFD Number: 3.3.17 None None None NRC OSI#93 Discuss why Note (c) ensures that the lowest functional capability or performance levels of equipment required for safe operation of the facility are met per 10 CFR 50.36(d)(2).

Background:

                    -The CTS (page 546 of 636) require that two channels of the Containment Vessel Post-Accident Radiation Instrument (CTS Instrument #6) be operable.

The CTS Bases (page 403 of 490 in the CTS) state "LCO 3.3.3.6, Table 3.3-10 requires only two "Containment Vessel Post-Accident Radiation" channels be operable, i.e., any two of RE4596A, RE4596B, RE4597AB, and RE4597BB can be utilized to comply with the LCO.

                    -The ITS (page 562 of 636) have a Note (c) for the Containment High Range Comment Radiation Instrument (ITS Instrument 8a) and for the Containment Wide Range Noble Gas Instrument (ITS Instrument 8b) that states "Two of the four
                   .total channels are required to be operable." The Note is vague in that it appears to apply individually to Instrument 8a and Instrument 8b (i.e.

Instruments 8a and 8b each have 4 channels and only 2 are required for operability) instead of being applied to Containment Vessel Post-Accident Radiation Instrument (ITS Instrument 8).

                    -STS LCO 3.3.17 (NUREG-1430) states that 2 channels of the Containment Area Radiation (High Range) Instrument shall be operable. The STS acknowledges that plant specific PAM Instrumentation exists and is to be evaluated by the reviewer.
                    -10 CFR 50.36(d)(2) states "limiting conditions for operation are the lowest functional capability or performance levels of equipment required for safe operation of the facility."

http://www.excelservices.com/exceldbs/itstrackdavisbesse.nsf/1 fddcea1Od3bdbb585256e... 7/18/2008

NRC ITS Tracking Page 4 of 4 monitors.) The NRC Safety Evaluation for Amendment 84 states:

                                  "We conclude that the proposed TSs for containment pressure monitor are acceptable." RHR System Flow CTS Table 3.3-10, instrument 8 is Low Pressure Injection (DHR) Flow. This is becoming Function 15 in ITS Table 3.3.17-1. The same flow instrumentation is used to monitor the DHR system flow in both modes of operation (LPI/DHR). Control Room Vent Status Serial 1879, dated March 15, 1.991 documented that: "Toledo Edison has re-reviewed RG 1.97, Revision 3, the NRC inspection reports, and the Babcock and Wilcox (B&W) Owners Group RG 1.97 Task Force Evaluation of Selected RG 1.97 Variables (B&W Document
                                  #47-1150378-01).. Based on this review, TE concurs that the CRNVS Isolation Status should properly be classified as a Category 2, Type D variable." Containment Hydrogen Concentration instrumentation Amendment 265 authorized changes to the Technical Specifications related to Combustible Gas Control Systems. The Containment Hydrogen Concentration instrumentation has been downgraded. A rule change to 10CFR50 dated September 16, 2003 (68 FR 54123) eliminated the requirement that the hydrogen analyzers be safety-related components, and allowed their requirements to be relocated from the Technical Specifications. Section III.D of the final rule (68 FR 54123) categorized the hydrogen monitoring system as "Category 3" of Regulatory Guide 1.97 because the monitors are required to diagnose the course of significant beyond design-basis accidents.

Section III.D further stated that "Category 3" applies to high-quality, off-the-shelf backup and diagnostic instrumentation. Reactor Coolant Loop Pressure and Containment Pressure (Wide Range) The Reactor Coolant Loop Pressure and Containment Pressure (Wide Range) are still considered to be Type A variables. The ITS Bases B 3.3.17 will be updated to state they are Type A variables. A draft markup regarding this change is attached. This change will be reflected in the supplement to this section of the ITS Conversion Amendment. NRC Response by Aron Lewin No further questions at this time. on 03/24/2008 bn Date Created: 01/27/2008 09:36 PM by Aron Lewin Last Modified: 03/24/2008 03:03 PM http://www.excelservices.com/exceldbs/itstrackdavisbesse.nsf/1 fddceal Od3bdbb585256e... . 7/18/2008

NRC ITS Tracking Page 3 of 4 the licensee's plant specific PAM submittal dated 06/28/1984 and the safety evaluation report (SER) dated 12/04/1987. The 06/28/1984 submittal and 12/04/1987 SER identified Containment Pressure (Narrow Range), RHR System Flow, and Containment Hydrogen Concentration, as Type A and Category 1 variables, and Control Room Vent Status as a Type A variable. Containment Pressure (Narrow Range), RHR System Flow, and Control Room Vent Status were not included in either CTS Table 3.3.3.6 or ITS Table 3.3.17-1. Are Containment Pressure (Narrow Range), RHR System Flow, and Control Room Vent Status still considered to be Type A variables? If not, was this determined via a 10 CFR 50.59 review? If these variables are still considered to be Type A variables, why are they not included in ITS Table 3.3-17.1 and ITS BASES B 3.3.17? If Containment Pressure (Narrow Range) and RHR System Flow have been determined not to be Type A variables; they would still be Category 1 variables. If this is the case, why is Containment Pressure (Narrow Range) and RHR System Flow not included in ITS Table 3.3.17 1 and ITS BASES 3.3.17? 10 CFR 50.44 allows licensees to request a downgrade of the Containment Hydrogen Concentration instrumentation and, therefore, this instrumentation would no longer meet the criteria for inclusion in the PAM TS. Has the licensee documented the downgrade of the Containment Hydrogen Concentration instrumentation? If not, why is Containment Hydrogen Concentration not included in ITS Table 3.3.17-1 and ITS BASES B 3.3:17? The 06/28/1987 submittal and 12/04/1987 SER identified Reactor Coolant Loop Pressure (identified in the submittal and SER as RCS Pressure) and Containment Pressure (Wide Range), as Type A and Category 1 variables. ITS BASES B 3.3.17 identifies Reactor Coolant Loop Pressure and Containment Pressure (Wide Range) as Category 1 but not as Type A variables. Are Reactor Coolant Loop Pressure and Containment Pressure (Wide Range) still considered to be Type A variables? If not, was this determined via a 10 CFR 50.59 review? If these variables are still considered to be Type A variables, why are they not indentified as Type A variables in ITS BASES B 3.3.17? Licensee Response by Jerry The following information is being supplied to answer the Jones on 03/20/2008 additional information request by the NRC on 3/11/2008. This information is to be used in conjunction with the information supplied in the response on 2/15/2008. Containment Pressure The purpose of the Post Accident Monitoring System is to follow the course of an accident condition with wide range instrumentation, which will provide to the plant operators the essential safety status information allowing the operators to return the plant to a maintained, safe, shutdown condition. The Containment Wide Range Pressure Monitors consist of two safety grade, Class I E, electrically independent, physically separated, pressure instrument strings. Amendment 84 added containment pressure to the list of post-accident instrumentation that must be OPERABLE and subject to surveillance requirements. (It added the Wide Range http://www.excelservices.com/exceldbs/itstrack-davisbesse.nsf/lfddcea1Od3bdbb585256e... 7/18/2008

NRC ITS Tracking Page 2 of 4

                         -Remove the individual classifications found in the ITS Bases for each instrument or provide justification for the classifications, which will require technical branch review, in order to ensure that instruments, which are components that are part of the primary success path and which function or actuate to mitigate a design basis accident or transient that either assumes the failure of or presents a challenge to the integrity of a fission product barrier, are properly classified per Criterion 3 of 10 CFR 50.36(d)(2)(ii), as Type A.

Is.ss.ue..:D:ate] 01/27/2008 ICloseate 03/24/2008 Logged in User: Anonymous

• 'Responses Licensee Response by Jerry The ISTS Background Bases (Volume 8, Page 567), last paragraph Jones on 02/15/2008 (just before the Reviewer's Note) states the following: "The key variables are identified by the unit specific' Regulatory Guide 1.97 analysis (Ref. 1). This analysis identifies the unit specific Type A and Category 1 variables and provides justification for deviating from the NRC proposed list of Category 1 variables." Davis-Besse maintained this paragraph, but changed the words "NRC proposed list of Category 1 variables" to "NRC guidance in Reference 2" for clarity. (The ISTS Bases have previously identified that Reference 2, which is Regulatory Guide 1.97, is where the recommendations are located). Davis-Besse identified in the ITS Reference Section of the Bases (Page 585) the correct plant specific document for Reference 1 - UFSAR Section 7.13. Thus, as stated in the Bases, UFSAR Section 7.13 is where the variables, are identified as Category 1 and/or Type A. Davis-Besse noted that the ISTS Bases was not consistent in identifying whether variables were Category 1 or Type A. For instance, the ISTS Bases for the Wide Range Neutron Flux, Variable 1 (Page 569), does not include any Category or Type classification. However, the ISTS Bases for the RCS Hot and Cold Leg Temperature, Variables 2 and 3 (Page 569) does include a statement that they are Category 1 variables. For consistency, Davis-Besse included this information for all the Davis-Besse PAM instruments. In addition, Davis-Besse does not believe that this additional, clarifying information is a beyond scope change. It is simply amplifying information based on the

_current Davis-Besse PAM analysis. NRC Response by Aron Lewin TTechnical branch conducting cursory review to determine if on 02/25/2008 additional information / BSI TAC is warranted. NRC Response by Aron Lewin Discussion with the technical branch yielded the following on 03/11/2008 (request conference call with licensee to discuss): The licensee has proposed to identify in ITS BASES B 3.3.17 which PAM instruments are classified as either Type A or Category 1. This information was not provided in CTS BASES B 3.3.3.6. However, this information provides the rational for the inclusion of each PAM instrument in ITS Table 3.3.17-1. The following is based on http://www.excelservices.com/exceldbs/itstrackdavisbesse.nsf/ 1fddcea 1Od3bdbb585256e... 7/18/2008

NRC ITS Tracking Page 1 of 4 V Return to ViewMe.nu t.Print.Doe RAI Screening Required: Yes Status: Closed This Document will be approved by: Carl Regulatory Basis must be included in Comments Schulten; Gerald Waig section of this Form This document has been reviewed and Yes information in this question contains NO SUNSI sensitive material (the checkbox to the right must be selected before this question can be submitted) NRC ITS TRACKING NRC Reviewer I D200801272136 Conference Call Requested? No Category BSI - Beyond Scope Issue ITS. Section: TB P...O.C,:ý JFD Number: Page. Nmber(s):. ITS 3.3 Aron Lewin None Information ITS-Number.: OR: DOC Number: Bases JFD Number.:, 3.3.17 None None None NRC OSI#94 Provide justification for the PAM instrument classifications, in order to ensure that instruments, which are components that are part of the primary success path and which function or actuate to mitigate a design basis accident or transient that either assumes the failure of or presents a challenge to the integrity of a fission product barrier, are properly classified per Criterion 3 of 10 CFR 50.36(d)(2)(ii), as Type A.

Background:

                          -The CTS Bases (page 403 of 490 in the CTS) do not discuss whether instruments are Type A or Category 1.
                          -The ITS Bases (pages 569 thru 580 of 636) classify the instruments as either Type A or Category 1. The ITS Bases (page 568 of 636) state "PAM Comment            satisfies Criterionthat instrumentation
          .........................                 meets the definition of Type A in Regulatory Guide 1.97 3 of 10 CFR 50.36(c)(2)(ii). Category 1, non-type A, instrumentation must be retained in Technical Specifications because it is intended to assist operators in minimizing the consequences of accidents.

Therefore, Category 1, non-Type A variables are important for reducing public risk."

                          -The STS LCO 3.3.17 Bases (NUREG-1430) do not. classify the instruments individually as either Type A or Category 1. The STS Bases also have the ITS Bases statement found on page 568 of 636.
                          -Criterion 3 of 10 CFR 50.36(d)(2)(ii) states a TS is needed for a "structure, system, or component that is part of the primary success path and which functions or actuates to mitigate a design basis accident or transient that either assumes the failure of or presents a challenge to the integrity of a fission product barrier."

http://www.excelservices.com/exceldbs/itstrackdavisbesse.nsf/1 fddceal Od3bdbb5g85256e... 7/18/2008

NRC ITS Tracking Page 2 of 2 Logged in User: Anonymous 'Responses Licensee Response by Bill Please clarify what information in Discussion of Change L03 Bentley on 01/29/2008 (page 555 of Volume 8) is lacking for this issue. Also note that the same BWST Level instruments for PAM are also included in the ITS 3.3.5 SFAS LCO. All 4 channels of BWST Level require a channel check, a channel functional and channel calibration as specified in ITS 3.3.5. onRC0Respnse by Aron Lewin ill request conference call with licensee. onLicensee Response by Jerry See the response for 200801272133. Jones on 02/23/2008 ____________________________ NRC Response by Aron Lewin ]Technical branch conducting cursory review to determine if on 02/25/2008 additional information /TAC is warranted. NRC Response by Aron Lewin No further questions at this time. ýon 03/10/2008 i____________________________ Date Created: 01/27/2008 09:35 PM by Aron Lewin Last Modified: 03/10/2008 02:14 PM http://www.excelservices.comlexceldbs/itstrackdavisbesse.nsf/1 fddceal Od3bdbb585256e... 7/18/2008

NRC ITS Tracking .Page I of 2 Return to Vie Men _ Print Documnt RII Screening Required: Yes Status: Closed This Document will be approved by: Carl Regulatory Basis must be included in Comments Schulten; Gerald Waig section of this Form This document has been reviewed and Yes information in this question contains NO SUNSI sensitive material (the checkbox to the right must be selected before this question can be submitted) NRC ITS TRACKING NRC Reviewer ID200801272135 Conference Call Requested? No Cal BSI - Beyond Scope Issue ITS Section: TB POC: JFD Nu!mber-:. Page..Number(s): ITS 3.3 Aron Lewin None Information ITS Nuniber: OS1: DOC-Number: Bases.JFD-Number: 3.3.17 None None None NRC OSI#92 Discuss how reducing the periodicity of the BWST Level channel check still assures that the necessary quality of systems and components is maintained, that facility operation will be within safety limits, and that the limiting conditions for operation will be met per 10 CFR 50.36(d)(3).

Background:

                    -The CTS (page 548 of 636) requires that a channel check be done on the BWST Level (CTS Instrument 14) every 12 hours.
                    -The ITS (page 559 of 636) requires that a channel check be done on the BWST (ITS Instrument 16) every 31 days.

Comment -STS LCO 3.3.17 (NUREG-1430) does not list BWST level.

                    -10 CFR 50.36(d)(3) states "surveillance requirements are requirements relating to test, calibration, or inspection to assure that the necessary quality of systems and components is maintained, that facility operation will be within safety limits, and that the limiting conditions for operation will be met."
                    -It is unclear why the BWST Level was theonly instrument to be initially licensed to have a channel check done every 12 hours (as opposed to other instruments that are checked monthly), and how reducing the periodicity of the channel check still assures that the necessary quality of systems and components is maintained, that facility operation will be within safety limits, and that the limiting conditions for operation will be met per 10 CFR 50.36(d) 1(3).

Issue Date 01/27/2008 Close Date 03/10/2008 http://www.excelservices.com/exceldbs/itstrackdavisbesse.nsf/1 fddcea 1Od3bdbb585256e... 7/18/2008

NRC ITS Tracking Page 3 of 3 NRC Response by Aron Lewin Technical branch conducting cursory review to determine if on 02/25/2008 additional information / TAC is warranted. NRC Response by Aron Lewin New further questions at this time. on 03/10/2008 Date Created: 01/27/2008 09:33 PM by Aron Lewin Last Modified: 03/10/2008 02:13 PM http://www.excelservices.com/exceldbs/itstrackdavisbesse.nsf/1 fddcealOd3bdbb585256e,.. 7/18/2008,

NRC ITS Tracking Page 2 of 3 [tIssue Date101/27/2008

     ,Co        03/10/2008 Logged in User: Anonymous
"  Responses Licensee Response by Bill        Please clarify what information in Discussion of Change L02 Bentley on 01/29/2008             (page 555 of Volume 8) is lacking for this issue. Also note that the same BWST Level instruments for PAM are also included in the ITS 3.3.5 SFAS LCO. All 4 channels of BWST Level require a channel check, a channel functional and channel calibration as specified in ITS 3.3.5.

nNRC Response by Aron Lewin Will Request Conference Call with Licensee [on 01/29/2008 ____________________________ Licensee Response by Jerry During a recent NRC phone conference, the NRC reviewer Jones on 02/23/2008 clarified that he was looking for the reason that the CTS Table 3.3-10, Instrument 14, BWST Level (Volume 8, Page 546) required 3 channels to be OPERABLE while all other Post Accident Monitoring (PAM) instruments in the Table required no more than 2 channels. In addition, the NRC reviewer was also looking for the reason the CHANNEL CHECK Frequency for the BWST Level channels in CTS Table 4.3-10 (Page 548) is shifily (i.e., S) when all the other PAM instruments have a Monthly (i.e., M) CHANNEL CHECK. Davis-Besse has researched this issue and has found the following history concerning this issue: License Amendment 36 allowed the plant to use a manual switchover of the ECCS pumps from the BWST to the emergency sump during a LOCA after the BWST reaches a low level. The plant was previously licensed to require an automatic switch over feature. As part of the Amendment, requirements were added to Post-Accident Monitoring (PAM) section of the TechnicalSpecifications consistent with the requirements that existed for BWST level within the Safety Features Actuation System (SFAS) Specification (CTS 3.3.2.1). As shown in Table 3.3-3 (Page 174), the MINIMUM UNITS OPERABLE column requires 3 channels of BWST Level - Low Low to be OPERABLE. As shown in Table 4.3-2 (Page 180), the CHANNEL CHECK Frequency is shiftly (i.e., S) for the BWST Level-Low Low instrumentation. Davis-Besse believes that the two Specifications should stand alone and are not required to be consistent with one another, with respect to the number of required BWST Level channels and the CHANNEL CHECK Frequency, since they are in the Technical Specifications for two different reasons. ITS 3.3.5 continues to maintain the proper number of BWST Level - Low Low SFAS channels and the appropriate CHANNEL CHECK Frequency. Thus, deleting one of the required BWST Level channels from the PAM Specification and changing the CHANNEL CHECK Frequency will still ensure that the requirements for PAM are met and the channel requirements are consistent with the ISTS PAM requirements. HI http://www.excelservices.com/exceldbs/itstrack-davisbesse.nsf/lfddceal. d3bdbb585256e... 7/18/2008

NRC ITS Tracking Page I of 3 Return to View Me"n Print Document RAI Screening Required: Yes Status: Closed This Document will be approved by: Carl Regulatory Basis must be included in Comments Schulten; Gerald Waig section of this Form This document has been reviewed and Yes information in this question contains NO SUNSI sensitive material (the checkbox to the right must be selected before this question can be submitted) NRC ITS TRACKING NRC Reviewer ID 200801272133 Conference Call Requested? No Category BSI - Beyond Scope Issue ITS Section-: TB P.OC.:. JFD.NuImb.er: Page Number(s): ITS 3.3 Aron Lewin None Information ITS Number: OS0: D OC Number: Bases JFD Nlumber.: 3.3.17 None None None NRC OSI#91 Discuss how reducing the number of BWST Level required channels operable will still ensure that a structure, system, or component that is part of the primary success path and which functions or actuates to mitigate a design basis accident or transient that either assumes the failure of or presents a challenge to the integrity of a fission product barrier, will be adequately maintained in the TS per Criterion 3 of 10 CFR 50.36(d)(2)(ii).

Background:

                  -The CTS (page 546 of 636) requires that 3 channels be operable for the BWST level (CTS Instrument 14).
                  -The ITS (page 562 of 636) requires that 2 channels be operable for the BWST level (ITS Instrument 16).

Comment -STS LCO 3.3.17 (NUREG-1430) does not list BWST level.

                  -Criterion 3 of 10 CFR 50.36(d)(2)(ii) states a TS is needed for a "structure, system, or component that is part of the primary success path and which functions or actuates to mitigate a design basis accident or transient that either assumes the failure of or presents a challenge to the integrity of a fission product barrier."
                  -It is unclear why the BWST Level was the only instrument to be initially licensed to have 3 channels operable (as opposed to other instruments that only required 1 or 2 channels), and how reducing the number of required channels operable will still ensure that a structure, system, or component that is part of the primary success path and which functions or actuates to mitigate

a. design basis accident or transient that either assumes the failure of or presents a challenge to the integrity of a fission product barrier, will be adequately maintained in the TS per Criterion 3 of 10 CFR 50.36(d)(2)(ii).

http://www.excelservices.com/exceldbs/itstrack-davisbesse.nsf/ 1fddceal Od3bdbb585256e... 7/18/2008

NRC ITS Tracking Page 3 of 3 with the current licensing basis (as described in the ITS Bases) for this specific CHANNEL CALIBRATION. A draft markup regarding this change is attached. This change will be reflected in the supplement to this section of the ITS Conversion Amendment. Licensee Response by Jerry During a recent phone conversation with the NRC reviewer, Jones on 06/30/2008 clarification was provided concerning the words being requested to be added to the Bases. A draft markup regarding this change is. attached and supersedes the draft markup provided with the Davis-Besse 6/10/08 response.. This change will be reflected in the supplement to this section of the ITS Conversion Amendment. NRC Response by Aron Lewin No further questions at this time. on 06/30/2008 ___________________________ Date Created: 01/16/2008 03:51 PM by Aron Lewin Last Modified: 06/30/2008 10:11 AM http://www.excelservices.com/exceldbs/itstrackdavisbesse.nsf/1 fddcea 1Od3bdbb585256e... 7/18/2008

NRC ITS Tracking Page 2 of 3 Ion 03/24/2008 Itracked by TAC MD8346. NRC Response by Aron Lewin Proposed LCO 3.3.16, "Station Vent Normal Range Radiation on 06/06/2008 Monitoring," contains a Surveillance Requirement (SR) 3.3.16.3 which is a Channel Calibration SR. The Bases for SR 3.3.16.3 contains a discussion on Channel Calibrations that does not discuss instrument adjustments with regards to drift between successive calibrations in order to ensure that the channel remains operational between successive tests. In addition, the Bases to not specify which methodology is used during the Channel Calibration. Also there is no discussion in the LCO 3.3.16 Bases on "Trip Setpoints and Allowable Values," which typically describe instrument setpoint methodology and operability determinations during Channel Calibrations. These discussions, which would provide amplifying and clarifying information on Channel Calibrations, are expected since it is information that is not found in the definition of a Channel Calibration in proposed Section 1.1, "Definitions." For comparison, NUREG-1430, "Standard Technical Specifications Babcock and Wilcox Plants," contains STS LCO 3.3.16, "Control Room Isolation - High Radiation." Proposed LCO 3.3.16, "Station Vent Normal Range Radiation Monitoring," is similar to STS LCO 3.3.16 in that both LCOs ensure that the high radiation isolation function provides assurance that under the required conditions, an isolation signal will be given. STS LCO 3.3.16 contains a (SR) 3.3.16.3 which is a Channel Calibration SR. The Bases for STS SR 3.3.16.3 contain a discussion that states "Channel Calibration leaves the channel adjusted to account for instrument drifts between successive calibrations to ensure that the channel remains operational between successive tests. Channel Calibrations must be performed consistent, with the unit specific setpoint analysis." In addition, the Bases for STS LCO 3.3.16, contains a discussion "Trip Setpoints and Allowable Values," which describes instrument setpoint methodology and operability determinations during Channel Calibrations. These discussions provide amplifying and clarifying information on Channel Calibrations that are not found in the STS Section 1.1 definition of a Channel Calibration. 10 CFR 50.36(d)(3) states technical specifications will include surveillance requirements which "are requirements relating to test, calibration, or inspection to assure that the necessary quality of systems and components is maintained, that facility operation will be within safety limits, and that the limiting conditions for operation will be met." Based on the discussion in NUREG-1430, it is unclear how 10 CFR 50.36(d) (3) is met for proposed SR 3.3.16.3 on Channel Calibrations, if the expected Bases discussions, which provide amplifying and clarifying information on Channel Calibrations not found in the definition of a Channel Calibration in proposed Section 1.1, is not included. Licensee Response by Jerry See the response for 200801161550. Also, Davis-Besse has re-Jones on 06/10/2008 reviewed the ITS SR 3.3.16.3 Bases and will add words similar to those in other CHANNEL CALIBRATION Bases, but consistent http://www.excelservices.com/exceldbs/itstrackdavisbesse.nsfl1 fddcealOd3bdbb585256e... 7/18/2008

NRC ITS Tracking Page I of 3 IVReturn to View Menu Print. ocumen RA-I Screening Required: Yes Status: Closed This Document will be approved by: Carl Regulatory Basis must be included in Comments Schulten; Tim Kobetz; Gerald Waig section of this Form This document has been reviewed and Yes information in this question contains NO SUNSI sensitive material (the checkbox to the right must be selected before this question can be submitted) NRC ITS TRACKING NRC Reviewer ID I o200801161551 Conference Call Requested? No Cate oryl BsI-Beyond Scope Issue ITS Section; TB POC: SJFD .Number.: Page..Nunib.e.r.(s). ITS 3.3 Aron Lewin None Information ITS Number: 0SI: DOCNNumber: Bases JFD Number: 3.3.16 None None None NRC OSI#87 Discuss how the ITS discussions on setpoint methodology physically effect LCO application in assuring the lowest functional capability or performance levels of equipment are met per 10 CFR 50.36(d)(2)(i).

Background:

                     -The CTS Bases for LCO 3.7.6 (page 438 of 490 in the CTS) do not discuss setpoint methodology.

Comment -The ITS Bases (page 530 and 532 of 636) state "the detector setpoints are

         .. ommen. established so as not to exceed the offsite dose limits required by the Offsite Dose Calculation Manual (ODCM)." The ITS Bases (page 529 of 636) also delete the STS discussion of Trip Setpoints and Allowable Values.
                     -The STS LCO 3.3.16 Bases (NUREG-1430) discuss setpoint methodology that is different from the ITS. The STS is based on a different design.

10 CFR 50.36(d)(2)(i) states that "limiting conditions for operation are the lowest functional capability or performance levels of equipment required for safe operation of the facility." Issue.D.ate 01/16/2008 Close Date [06/30/2008 Logged in User: Anonymous 1WResponses I[yLicensee Response by Bryan See the response for question 200801161550. Kays on 03/03/2008 1ý ]NRC Response by Aron Lewin IlTechnical Branch assistance formally requested. Issue being II http://www.excelservices.com/exceldbs/itstrack-davisbesse.nsfl/fddcea1Od3bdbb585256e..,. 7/18/2008

NRC ITS Tracking Page 4 of 4 Manual and to prevent spurious actuations. Station Vent alarm setpoints are established to initiate Control Room isolation when the activity level exceeds the derived Air Concentration limits of 10 CFR 20 and to ensure the release rate of noble gas, radioiodine, and particulate effluents do not exceed any 10 CFR limit. This is also stated in the Background and LCO section of the ITS Bases (Pages 530 and 532). The Bases description is our current licensing basis, which we are not changing as part of this conversion. The current licensing basis (that the Detector getpoints are established so as not to exceed the offsite dose limits required by the Offsite Dose Calculation Manual) is also stated in the UFSAR, Section 11.4.2.2.4. Therefore, since Davis-Besse is not deleting any current requirements, and the proposed ITS is consistent with the current licensing basis, Davis-Besse does not believe that 'any changes to add the trip setpoint into the ITS are required. NRC Response by Aron Lewin further questions at this time. on 06/18/2008 JN usin tti ie Date Created: 01/16/2008 03:50 PM by Aron Lewin Last Modified: 06/18/2008 09:20 AM http://www.excelservices.com/exceldbs/itstrackdavisbesse.nsf! 1fddcea 1Od3bdbb585256e... -7/18/2008

NRC ITS..Tracking Page 3 of 4 channel calibration alarm setpoint in the improved Technical Specifications being voluntarily adopted. Include as part of the discussion 10CFR50.36(d)(3) and how not having Surveillance Requirement acceptance criteria assures that the necessary quality of systems and components is maintained (the ability to detect and mitigate the consequence of a fuel handling accident in containment involving recently irradiated fuel). Licensee Response by Jerry CTS 3.9.3 precludes moving irradiated fuel prior to the reactor Jones on 06/04/2008 being shutdown for 72 hours. This Specification has been relocated to the Technical Requirements Manual (TRM), consistent with the allowance provided in NUREG-1430. Furthermore, in the latest response (6/04/08) to RAI 200801161532, Davis-Besse has proposed to maintain CTS 3.9.3 in the ITS. Thus, in either case (CTS 3.9.3 requirements in the TRM or in the ITS), Davis-Besse is not allowed tomove irradiated fuel prior to the reactor being shutdown for 72 hours. NRC Response by Aron Lewin As discussed on 5/28/08 and 6/4/08 during a teleconference, on 06/05/2008 address the following: Discuss why it is acceptable to remove the Surveillance acceptance value for the channel calibration alarm setpoint in the Technical Specifications. Include as part of the discussion 10CFR50.36(d)(3) and how not having Surveillance Requirement acceptance criteria assures that the necessary quality of systems and components is maintained (the ability to detect and mitigate the consequence of an accident). Licensee Response by Jerry Davis-Besse is not removing a Surveillance acceptance value for Jones on 06/10/2008 the CHANNEL CALIBRATION requirements. CTS 3.7.6.1 (Volume 8, Pages 518 and 519) provides the requirements for the station vent normal radiation monitor. The only Surveillance Requirement in the CTS is CTS 4.7.6.1.e:2, which requires a verification that a station vent normal radiation monitor signal isolates the control room normal ventilation system. This test is essentially a system functional test; there are no CHANNEL CHECK, CHANNEL FUNCTIONAL TEST, or CHANNEL CALIBRATION requirements. Furthermore, the CTS does not include any trip setpoint or Allowable Value requirements. The trip setpoint is totally under Davis-Besse control. Davis-Besse included a new instrumentation LCO for the station vent normal radiation monitor, including a CHANNEL CHECK, CHANNEL FUNCTIONAL TEST, and CHANNEL CALIBRATION to be consistent with the format of NUREG-1430. All three of these Surveillance Requirements are new, more restrictive requirements. Maintaiiiing the trip setpoint under Davis-Besse control continues to maintain the necessary quality of systems and components, since the proposed Technical Specifications require the proper tests to be performed. As stated in Justification for Deviation (JFD) 3 (Page 527), the Allowable Value has not been included in ITS SR 3.3.16.3 because the setpoint is not based on a specific safety analysis assumption or result, but is chosen to not exceed the offsite dose limits required by the Offsite Dose Calculation http://www.excelservices.com/exceldbs/itstrackdavisbesse.nsf/1 fddcea 1Od3bdbb585256e... 7/18/2008

NRC ITS Tracking Page 2 of 4 Issue WDate 01/16/2008 Close Date 06/18/2008 Logged in User: Anonymous

'Responses Licensee Response by Bryan        The Allowable Value has not been incorporated in ITS SR 3.3.16.3 Kays on 03/03/2008                (Volume 8, Page 526). As stated in the Justification for Deviation (JFD) 3 (Volume 8, Page 527), the Allowable Value has not been included in ITS SR 3.3.16.3 since the setpoint is not based on a specific safety analysis assumption or result, but is chosen to not exceed the offsite dose limits required by the Offsite Dose Calculation Manual (ODCM) and to prevent spurious actuations.

Station Vent alarm setpoints are established to initiate Control Room isolation when the activity level exceeds the derived Air Concentration limits of 10 CFR 20 and to ensure the release rate of noble gas, radioiodine, and particulate effluents do not exceed any to CFR limit. This is further stated in the ITS Bases (Page 530). The ITS Bases states: The Station Vent Normal Range Radiation Monitoring performs an additional function of ensuring the average annual gaseous effluent concentrations at the boundary of the unrestricted area do not exceed 10 CFR 20 requirements. The setpoints for limiting the offsite dose are more limiting than would be required for control room isolation purposes. The detector setpoints are established so as not to exceed the offsite dose limits required by the Offsite Dose Calculation Manual (ODCM). This bounds the Technical Specification reason for the detectors. Additionally, Davis-Besse does not agree that this is a beyond scope item since this is consistent with the current requirements. NRC Response by Aron Lewin Technical Branch assistance formally requested. Issue being on 03/24/2008 trackedby TAC MD8346. NRC Response by Aron Lewin The Technical Branch has the following questions: RAI-1: In the on 05/23/2008 justification for excluding the Surveillance Requirement setpoint acceptance criteria, FENOC states that "[t]he setpoint is not based on a specific safety analysis assumption or result." However, FENOC then goes on to state "Station Vent alarm setpoints are established to initiate Control Room isolation, ... to ensure the release rate of noble gas, radioiodine, and particulate effluents do not exceed any 10 CFR limit." Please discuss the setpoint with regard to fuel from the reactor core is being moved within 72 hours after the reactor has been shut down (recently irradiated fuel) and 10CFR50 Appendix A, GDC-19 limits. RAI-2: Please discuss if the Station Vent radiation monitors provide any safety function in the event of a fuel handling accident with fuel from the reactor core is being moved within 72 hours after the reactor has been shut down. Include in discussion 10CFR100 limits, and 10CFR50 Appendix A, GDC-19 limits. RAI-3: If the radiation monitors do provide a safety function', please discuss why it is acceptable to remove the Surveillance acceptance value for the http://www.excelservices.com/exceldbs/itstrack davisbesse.nsf/lfddceal0d3bdbb585256e... 7/18/2008

NRC ITS Tracking Page I of 4' Return to View Mendu Print.Document RAI Screening Required: Yes Status: Closed This Document will'be approved. by: Carl Regulatory Basis must be included in Comments Schulten; Tim Kobetz; Gerald Waig section of this Form This document has been reviewed and Yes information in this question contains NO SUNSI sensitive material (the checkbox to the right must be selected before this question can be submitted) NRC ITS TRACKING NRC Reviewer ID 200801161550 Conference Call Requested? No Category BSI- Beyond Scope Issue ITS.Section: TBPO.C.;. JFD.Number: Page..N~u~mb.er(s): ITS 3.3 Aron Lewin None Information ITS Number;: OSI: DOC Number: BasesJFD Numb.er. 3.3.16 None None None NRC OSI#86 Discuss how the lack of sPecific allowable value in ITS SR 3.3.16.3 assures that the necessary quality of systems and components is maintained as required per 10 CFR 50.36(d)(3).

Background:

                  -CTS LCO 3.7.6 (page 519 of 636) has SR 4.7.6.1.e that states "at least once each refueling interval {verify} that the control room normal ventilation system is isolated by a SFAS test signal and a Station Vent Normal Range Radiation Monitoring test signal." The USAR (page 4017 of page 4076 in the USAR) has an analysis done for a fuel handling accident containment. It is unclear if the analysis assumed an allowable value for control room isolation (Assumption #9). in addition, the USAR (page 3983 of 4076) has an analysis Comrmente  done for a LOCA. It is unclear if the analysis assumed an allowable value for control room isolation (Assumption d).
                  -ITS LCO 3.3.16 (page 526 of 636) has a calibration SR 3.3.16.3 with no allowable value. In addition the ITS Bases (page 530 of 636) states "the Station Vent Normal Range Radiation Monitoring performs an additional function on ensuring the average annual gaseous effluent concentrations at the boundary of the unrestricted area do not exceed 10 CFR 20 requirements."
                  -STS LCO 3.3.16 (NUREG-1430) has a channel calibration SR 3.3.16.3, and includes an allowable value. The STS is based on a different design.

10 CFR 50.36(d)(3) states that "surveillance requirements are requirements relating to test, calibration, or inspection to assure that the necessary quality of systems and components is maintained, that facility operation will be within safety limits, and that the limiting conditions for operation will be met." http://www.excelservices.com/exceldbs/itstrack-davisbesse.nsf/ lfddceal Od3bdbb585256e... 7/18/2008

NRC ITS Tracking Page 4 of 4 Date Created: 01/16/2008 03:48 PM by Aron Lewin Last Modified: 06/06/2008 03:13 PM http://www.excelservices.com/exceldbs/itstrackdavisbesse.nsf/1 fddceal Od3bdbb585256e... 7/18/20081

NRC ITS Tracking Page 3 of 4 1430 (B&W Plants STS) model for TS 3.3.16 being used by FENOC does not permit any grace time to return at least one channel to operability but instead either requires immediately placing one OPERABLE CREVS train in emergency operation mode OR immediate suspension of the movement of irradiated fuel. Please discuss why the less restrictive action proposed in DBNPS ITS 3.3.16 is acceptable. Include in the discussion Control Room Habitability and the movement of fuel that has occupied part of a critical reactor core within the previous 72 hours. Licensee Response by Jerry The current licensing basis at Davis-Besse, as shown in CTS Jones on 05/29/2008 3.7.6.1 (Volume 8, Page 518) does not require the Station Vent Normal Range Radiation Monitoring to be OPERABLE during movement of irradiated fuel assemblies. Davis-Besse added this new Applicability to ITS 3.3.16 (Page 524) as justified in DOC M03 (Page 521). As part of this addition, ACTIONS for inoperable channels when moving irradiated fuel (i.e., ACTIONS A, B, and D) were also added. Thus, the addition of ITS 3.3.16 ACTIONS A, B, and D (during movement of irradiated fuel) is not a less restrictive change, but a more restrictive change. ITS 3.3.16 Required Action B.I (Page 525) allows 1 hour to isolate the Control Room Normal Vent System. This Required Action applies during MODES 1, 2, 3, and 4, and also during movement of irradiated fuel. Davis-Besse believes that since 1 hour is provided in CTS 3.7.6.1 Action c for when both channels are inoperable in MODE 1, 2, 3, or 4; then the same 1 hour is acceptable when moving irradiated fuel assemblies. This 1 hour time was approved by the NRC as documented in the Safety Evaluation for Amendment 227, dated October 5, 1998. However, Davis-Besse has noted that DOC M03 does not clearly state that the addition of ACTIONS A and B, as they relate to moving irradiated fuel, is part of DOC M03. Therefore, DOC M03 will be revised to clearly describe the entire more restrictive change. A draft markup regarding this change is attached. This change will be reflected in the supplement to this section of the ITS Conversion Amendment. The NRC reviewer also requested that Davis-Besse include in the discussion Control Room Habitability and the movement of fuel that has occupied part of a critical core within the previous 72 hours. The. Davis-Besse accident analysis does not assume any irradiated fuel movement prior to 72 hours. Fuel movement prior to this time is currently precluded by CTS 3.9.3 (Volume 14, Page 128). Davis-Besse is relocating this current requirement to the Technical Requirements Manual (TRM), consistent with NUREG-1430. The NUREG does not include this Specification. The TRM is currently incorporated into the UFSAR, thus is controlled by the requirements of 10 CFR 50.59. Davis-Besse expects to receive a License Condition that all changes covered by LA type and R type Discussion of Changes (DOC), which include CTS 3.9.3, be moved to the location specified in the applicable DOC (in this specific case, the TRM )and controlled by the process specified in the DOC (in this case, 10 CFR 50.59) as part of the ITS http://www.excelservices.com/exceldbs/itstrackdavisbesse.nsf/1 fddcea 1Od3bdbb585256e... 7/18/2008

NRC ITS Tracking Page 2. of 4 Close Date 06/06/2008 Logged in User: Anonymous 'Resoonses Licensee Response by Bryan ITS 3.3.16 (Volume 8, Pages 524 through 526) has been changed Kays on 03/03/2008 to match the requirements of ITS 3.7.10 (Volume 12, Page 235). The current licensing basis at Davis-Besse does not require the Control Room Emergency Ventilation System (CREVS) to be OPERABLE during movement of irradiated fuel assemblies. The only requirement in the safety analyses is to isolate the control room boundary. As shown in ITS 3.7.10, only this part (i.e., control room envelope) is required to be OPERABLE during movement of irradiated fuel assemblies. Therefore, the ACTIONS for inoperable instrumentation in ITS 3.3.16 have been modified to be consistent with the System the instrumentation actuates. Thus, when one or both channels are inoperable during movement of irradiated fuel assemblies, only the control room has to be isolated (which includes isolating the control room and securing the normal control room ventilation system) - the CREVS is not required to be started. This is consistent with the current analyses. Furthermore, this is described in the Applicable Safety Analyses section of the ITS Bases (Page 532, Insert 1A), as well as the ACTIONS Section of the ITS Bases (Page 534 - Inserts 3 and 4). This is also described in Justification for Deviation 1 (Page 527), which states that the changes are consistent with the actual system specification in ITS 3.7.10. As stated in the NRC reviewer's question, the CTS does not include any requirements during movement of irradiated fuel assemblies. Davis-Besse added the new requirements as described in ITS 3.3.16 Discussion of Change M03 (Page 521) and ITS 3.7.10 Discussion of Change MO1 Volume 12, Page 228) to be consistent with the safety analyses assumptions. However, Davis-Besse does not believe these changes are beyond scope changes since they are being, made to adopt the ISTS requirements, consistent with our current licensing basis. UFSAR Section 15.4.7 describes that the control room is assumed to be isolated during a fuel handling accident. Furthermore, the current licensing basis include two channels of station vent normal range monitoring instrumentation compared to the bracketed [one] channel in ISTS 3.3.16. Thus, Davis-Besse included both channels in ITS 3.3.16, consistent with our design. NRC Response by Aron Lewin Technical Branch assistance formally requested. Issue being on 03/24/2008 tracked by TAC MD8347. NRC Response by Aron Lewin The technical branch has the following question: RAI-1: Technical on 05/23/2008 Specification 3.3.16, Station Vent Normal Range Radiation. Monitoring, Required Action D. 1 specifies immediate suspension of irradiated fuel assemblies if Condition A or B are not met during the movement of irradiated fuel assemblies. Condition B, Two channels inoperable, permits one hour grace time to correct the condition before required action D. 1 takes effect. NUREG-http://www.excelservices.com/exceldbs/itstrack-davisbesse.nsf/1 fddcealOd3bdbb585256e... 7/18/2008

NRC ITS Tracking Page I of 4 100Return to View MenuI Print Documen RAT Screening Required: Yes Status: Closed This Document will be approved by: Carl Regulatory Basis must be included in Comments Schulten; Tim Kobetz; Gerald Waig section of this Form This document has been reviewed and Yes information in this question contains NO SUNSI sensitive material (the checkbox to the right must be selected before this question can be submitted) NRC ITS TRACKING NRC Reviewer ID 200801161548 Conference Call Requested? No Category BSI - Beyond Scope Issue ITS .Sectoii: TB POC:. JFD Number: Page Number(s): ITS 3.3 Aron Lewin None Information ITS Number: 0S1: DOC Number: Bases JFD Number: 3.3.16 None None None NRC OSI#85 As permitted by 10 CFR 50.36(d)(2)(i), discuss why the CREVS is not required to be placed in operation during the movement of irradiated fuel for an inoperable channel (ITS Conditions A and B), or why irradiated fuel movements are not suspended immediately if two channels are inoperable and compensatory actions are not immediately carried out (Condition B).

Background:

                    -CTS LCO 3.7.6 (page 518 of 636) has no actions or applicability when moving irradiated fuel.
                    -ITS LCO 3.3.16 (page 524 of 636) has Conditions A, B, and Dwhich apply to irradiated fuel movements. Condition B states that if two channels are Com melnt inoperable the control room must be isolated within 1 hr. If that is not done, Condition D requires immediate suspension of irradiated fuel movement.
                    -STS LCO 3.3.16 (NUREG-1430), Condition C states that if no channel is operable, the CREVS must be placed in operation immediately or requires immediate suspension of irradiated fuel movement. The STS is based on a different design.

10 CFR 50.36(d)(2)(i) states that "limiting conditions for operation are the lowest functional capability or performance levels of equipment required for safe operation of the facility. When a limiting condition for operation of a nuclear reactor is not met, the licensee shall shut down the reactor or follow any remedial action permitted by the technical specifications until the condition can be met." Issue!Date] 01/16/2008 II http://www.excelservices.com/exceldbs/itstrackdavisbesse.nsf/1 fddcealOd3bdbb5.85256e... 7/18/2008

NRC ITS Tracking Page 2 of 2 Logged in User: Anonymous

'Responses Licensee Response by Bryan         As defined in ITS Section 1.1 (Volume 3, Page 32), a CHANNEL Kays on 03/03/2008                 CHECK is a qualitative assessment, by observation, of channel behavior during operation. The Bases for ISTS SR 3.3.15.1 (Volume 8, Page 511) CHANNEL CHECK states: A CHANNEL CHECK is normally a comparison of the parameter indicated on one channel to a similar parameter on other channels. It is based on the assumption that instrument channels monitoring the same parameter should read approximately the same value. Significant deviations between two instrument channels could be an indication of excessive instrument drift in one of the channels or of something even more serious. Performance of the CHANNEL CHECK helps to ensure that the instrumentation continues to operate properly between each CHANNEL CALIBRATION. The high radiation instrumentation should be compared to similar unit instruments located throughout the unit. If the radiation monitor uses keep alive sources or check sources OPERABLE from the control room, the CHANNEL CHECK should also note the detector's response to these sources. Davis-Besse maintained this ISTS Bases information and wording in our ITS Bases. Thus, Davis-Besse will compare the containment purge and exhaust isolation - high radiation instrumentation to similar instrumentation located throughout the unit, as is required by the ISTS Bases. Since the instrument has a gas sampler, particulate sampler, and an iodine sampler, the gas sampler readout can be compared to the particulate and iodine sampler. This comparison should determine if the gas sampler is indicating properly, since the three samplers are all indicating radiation exhaust. In addition, the CTS Surveillance referenced by the NRC reviewer (CTS 4.9.4.b) is essentially a system functional test surveillance, not an instrument only surveillance. As described in Discussion of Change M02 (Page 496), Davis-Besse is adding into the ITS a CHANNEL CHECK, CHANNEL FUNCTIONAL TEST, and CHANNEL CALIBRATION, none of which are. currently required by the CTS. The manner in which these three new Surveillances are performed is consistent with the ISTS definitions. Therefore, since Davis-Besse is adopting the ISTS requirements, this change is not a beyond scope change.

NRC Response by Aron Lewin TTechnical Branch assistance formally requested. Issue being on 03/24/2008 itracked by TAC MD8345. NRC Response by Aron Lewin No further questions at this time. on 05/22/2008 Date Created: 01/16/2008 03:37 PM by Aron Lewin Last Modified: 05/22/2008 08:52 AM http://www.excelservices.com/exceldbs/itstrack-davisbesse.nsf/1 fddcea 1Od3bdbb585256e... 7/18/2008

NRC ITS Tracking Page I of 2 VReturn to View Menu Print D~ocum~entj RAI Screening Required: Yes Status: Closed This Document will be approved by: Carl Regulatory Basis must be included in Comments Schulten; Tim Kobetz; Gerald Waig section of this Form This document has been reviewed and Yes information in this question contains NO SUNSI sensitive material (the checkbox to the right must be selected before this question can be submitted) NRC ITS TRACKING NRC Reviewer ID 1200801161537 Conference Call Requested? No SategorJ[ BSI - Beyond Scope Issue ITS Section: TB POC: JFD Number: Page Number(s): ITS 3.3 Aron Lewin None Information ITSNumber: 0S1: DO CNumber: BAses JFD Number: 3.3.15 None None None NRC OSI#84 Discuss how the channel check is performed, thereby providing assurance that the necessary quality of systems and components is maintained as required per 10 CFR 50.36(d)(3).

Background:

                    -CTS LCO 3.9.4 (page 494 of 636) has a SR 4.9.4.b that states "verifying that with the containment purge and exhaust system in operation, and the containment purge and exhaust system noble gas monitor capable of providing a high radiation signal to the control room, that after initiation of the high radiation signal, the containment purge and exhaust isolation valves can be Comment     closed from the control room."
                    -ITS LCO 3.3.15 (page 501 of 636) has a SR 3.3.15.1 for a channel check.
                    -STS LCO 3.3.15 (NUREG-1430) has a SR 3.3.15.1 for a channel check as well.

The STS is based on a different design. 10 CFR 50.36(d)(3) states that "surveillance requirements are requirements relating to test, calibration, or inspection to assure that the necessary quality of systems and components is maintained, that facility operation will be within safety limits, and that the limiting conditions for operation will be met." Given that only one channel of the containment purge and exhaust noble gas monitor exists, it is unclear how the channel check is performed, thereby providing assurance that the necessary quality of systems and components is maintained as required per 10 CFR 50.36(d)(3). [ Issue.Date 1101/16/2008 Close Kate 05/22/2008 http://www.excelservices.com/exceldbs/itstrackdavisbesse.nsfl1 fddcealOd3bdbb585256e... 7/18/2008

NRC ITS Tracking Page 2 of 2. F Date Issue 01/16/2008 Closate 05/29/2008 Logged in User: Anonymous 'vResponses Licensee Response by Bryan As stated in the Base for ITS 3.3.15 (Volume 8, Page 507),' Kays on 03/03/2008 Containment Purge and Exhaust Isolation - High Radiation has no safety function and is not assumed to function during any UFSAR design basis accident or transient analysis. ISTS 3.3.15 was retained at Davis-Besse in case the analysis is changed, in the future, to allow movement of fuel prior to 72 hours after shutdown. It also was retained to align Davis-Besse to the ISTS NUREG 1430. Additionally, Davis-Besse has determined that a change is necessary for Insert 2 to the Applicable Safety Analysis Bases (Page 507) to clarify the reason the Containment Purge and Exhaust Isolation - High Radiation is being retained in the Technical Specifications. A draft markup regarding this change is attached. This change will be reflected in the supplement to this _section of the ITS Conversion Amendment. Licensee Response by Bryan The markup is now attached. Kays on 03/14/2008 i NRC Response by Aron Lewin Technical Branch assistance formally requested. Issue being on 03/24/2008 ittracked by TAC MD8345. No further questions at this time. on 05/29/2008Respnse by Aron Lewin Date Created: 01/16/2008 03:36 PM by Aron Lewin Last Modified: 05/29/2008 08:31 AM http://www.excelservices.com/exceldbs/itstrackdavisbesse.nsfl1 fddcea 1Od3bdbb585256e... 7/18/2008

NRC ITS Tracking Page I of 2

  ',ýReturn to View Menul   F Irnt Docunientl RUA Screening Required: Yes                          Status: Closed This Document will be approved by: Carl              Regulatory Basis must be included in Comments Schulten; Tim Kobetz; Gerald Waig                    section of this Form This document has been reviewed and                  Yes information in this question contains NO SUNSI sensitive material (the checkbox to the right must be selected before this question can be submitted)        .

NRC ITS TRACKING NRC Reviewer DD 200801161536 Conference CallRequested? No Category BSI - Beyond Scope Issue ITS Section: TB POC: J4D1Number: Page.Number(s): ITS 3.3 Aron Lewin None Information ITS Numbcr: ' OSI: DOC Number:. Bases JFD Number:: 3.3.15 None None None NRC OSI#83 Discuss what the ITS Bases term "in case of a fuel handling accidentprior to 72 hours shutdown" means given the USAR assumption that fuel is not moved prior to 72 hours, thereby still assuring that the lowest functional capability, or performance levels of equipment required for safe operation of the facility are still met, as required by 10 CFR 50.36(d)(2)(i).

Background:

                   -The CTS LCO 3.9.4 Bases (page 448 of 490 in the CTS) do not discuss TS criterion.
                   -The ITS 3.3.15 Bases (page 507 of 636) states the LCO does not meet any TS criterion. The USAR (page 4017 of 4076 inthe USAR) assumes fuel is not moved prior to 72 hours following reactor shutdown. The ITS Bases says the Comment LCO is retained in case of a fuel handling accident prior to 72 hours shutdown.
                   -The STS Bases for LCO 3.3.15 (NUREG-1430) state that the LCO is included in order to satisfy Criterion 3 of 10 CFR 50.36(d)(2)(ii). The STS is based on a different design.

10 CFR 50.36(d)(2)(i) states that "limiting conditions for operation are the lowest functional capability or performance levels of equipment required for safe operation of the facility." It is unclear what the ITS Bases term "in case of a fuel handling accident prior to 72 hours shutdown" means given the USAR assumption that fuel is not moved prior to 72 hours, thereby still assuring that the lowest functional capability or performance levels of equipment required for safe operation of the facility are still met, as required by 10 CFR 50.36(d) (2)(i). http://www.excelservices.com/exceldbs/itstrackdavisbesse.nsf/1 fddcea1Od3bdbb585256e... 7/18/2008

NRC ITS TrackingP Page 2 of 2 Licensee Response by Bryan See the response for question 200801161532. Kays on 03/03/2008 ____________________________ NRC Response by Aron Lewin Technical Branch assistance formally requested. Issue being on 03/24/2008 Jtracked by TAC MD8345. NRC Response by Aron Lewin N further questions at this time.

ýon 05/22/2008qusinathstme Date Created: 01/16/2008 03:33 PM by Aron Lewin Last Modified: 05/22/2008 08:51 AM http://www.excelservices.com/exceldbs/itstrackdavisbesse.nsf/l fddceal Od3bdbb585256e...                7/18/2008

NRC ITS Tracking Yage I of 2 14Return to View Menu& Print Do-cumen RAI Screening Required: Yes Status: Closed This Document will be approved by: Carl Regulatory Basis must be included in Comments Schulten; Tim Kobetz; Gerald Waig section of this Form This document has been reviewed and Yes information in this question contains NO SUNSI sensitive material (the checkbox to the right must be selected before this question can be submitted) NRC ITS TRACKING NRC Reviewer ID F200801161533 Conference Call Requested? No Category ]l BSI - Beyond Scope Issue ITS Section: TB-.PO.C.:. JFD_.Numbh.er.:. Page Number(s): ITS 3.3 Aron Lewin None Information ITS.Number: OR" DOC Number: Bases JFD Number: 3.3.15 None None None NRC OSI#82 Discuss how the ITS discussions on setpoint methodology physically effect LCO application in assuring the lowest functional capability or performance levels of equipment are met per 10 CFR 50.36(d)(2)(i).

Background:

                       -The CTS Bases (page 448 of 490 in the CTS) do not discuss'setpoint methodology.
                       -The ITS Bases (page 504 of 636) state the "setpoint is selected based on historical operating experience to avoid spurious/nuisance alarms and to Comtment provide an early indication of increased activity to terminate the release prior to exceeding Offsite Dose Calculation Manual limits." The ITS Bases (page 504 of 636) also delete the STS discussion of Trip Setpoints and Allowable Values.

In addition, the ITS Bases (page 508of 636) also state that "nominal trip setpoints are specified in the Radiation Monitor Setpoint Manual."

                       -The STS LCO 3.3.15 Bases (NUREG-1430) discuss setpoint methodology that is different from the ITS. The STS is based on a different design.

10 CFR 50.36(d)(2)(i) states that "limiting conditions for operation are the lowest functional capability or performance levels of equipment required for safe operation of the facility." Issue Date] 01/16/2008 [C.IjQes te[/2008 Logged in User: Anonymous

'Responses http://www.excelservices.com/exceldbs/itstrack-davisbesse.nsf/lfddcealOd3bdbb585256e...              7/18/2008

NRC ITS Tracking Page 4 of 4 monitors that continuously monitor the station vent for particulate, iodine, and gross gaseous radioactivity. An isolation signal from either monitor will result in an isolation of the CRNVS. ITS 3.3.16 is Applicable whenever there is a chance for a significant accidental release of radioactivity; i.e., MODES 1, 2, 3, and 4 and during movement of irradiated fuel assemblies. If a radioactive release were to occur during any of the above conditions, the control room would have to remain habitable to ensure reactor shutdown and cooling can be controlled from the control room. As discussed in the ITS 3.3.16 Bases for ACTIONS B.1 and B.2 (Page 534), the Control Room Emergency Ventilation System (CREVS) is only required to be placed in operation during MODES 1, 2, 3, and 4. No credit is taken in the fuel handling accident analysis for operation of CREVS. UFSAR Figure 9.4-11 shows the various ventilation systems that discharge into the Station Vent Stack. The Station Vent Stack is the assumed release point, and this release point is 160 feet away from the Control Room intake. The ability of the radiation to get to the Station Vent radiation monitors is not dependent on whether the Containment Purge and Exhaust System is in service. If Containment Purge is not in service, then the radiation would be released by some other ventilation system via the Station Vent Stack. Licensee Response by Jerry In the NRC response to 200801161530, dated 6/5/2008, the NRC Jones on 06/17/2008 reviewer stated to post the proposal that adds the Decay Time Specification back into the ITS and deletes ITS 3.3.15 and ITS 3.9.3. The changes also include renumbering ITS 3.3.16 to become ITS 3.3.15 and deletes a reference to old ITS 3.3.15 in the Bases of ITS 3.9.4 and ITS 3.9.5. A draft markup regarding these changes is attached. These changes will be reflected in the supplement to this section of the ITS Conversion Amendment. In addition, this response only includes the changes to ITS Section 3.3 and the next response includes the changes to ITS Section 3.9. Licensee Response by Jerry The changes for ITS Section 3.9 are attached to this response, as Jones on 06/17/2008 stated in the previous response. Licensee Response by Jerry During the weekly NRC/Davis-Besse phone conversation, the Jones on 06/18/2008 NRC verbally communicated to Davis-Besse that they would like the word "OPERABLE" deleted from ITS 3.9.4 Required Action A.6 and ITS 3.9.5 Required Action A.5. A draft markup regarding these changes is attached and supersedes the draft markup provided for Section 3.9 changes in the previous Davis-Besse response (dated 6/17/2008). These changes will be reflected in the supplement to this section of the ITS Conversion Amendment. NRC Response by Aron Lewin No further questions at this time. on 06/18/2008 J____________________________ Date Created: 01/16/2008 03:32 PM by Aron Lewin Last Modified: 06/18/2008 04:10 PM http://www.excelservices.comlexceldbs/itstrackdavisbesse.nsf/1 fddceal Od3bdbb585256e... 7/18/2008

NRC ITS Tracking -Page 3 of 4 is operating and fuel from the reactor core is being moved within 72 hours after the reactor has been shut down please discuss why it is acceptable to remove the Surveillance acceptance value for the channel calibration in the improved Technical Specifications being voluntarily adopted. Include as part of the discussion 10 CFR 50.36(d)(3) and how not having Surveillance Requirement acceptance criteria assures that the necessary quality of systems and components is maintained (the ability to detect and mitigate the consequence of a fuel handling accident in containment involving recently irradiated fuel). 06/04/2008by Jerry

Response

Jones on Response by Jerry Licensee Licensee Issue 1: The NRC reviewer posted questions on 5/23/08 that Jones on 06/04/2008 requested information related to moving irradiated fuel prior to 72 hours after the reactor has been shutdown. Davis-Besse does not have any analysis that allows irradiated fuel to be moved prior to 72 hours after a reactor shutdown. During a phone conversation' with the NRC reviewer on 5/28/08, Davis-Besse understands that the reviewer's concern is the lack of NRC control of the 72 hour decay time requirement. Specifically, CTS 3.9.3 precludes moving irradiated fuel prior to the reactor being shutdown for 72 hours. Davis-Besse relocated this Specification to the Technical Requirements Manual (TRM), consistent with the allowance provided in the ISTS, NUREG-1430. Once relocated to the TRM, changes to the 72 hour decay time requirement can be made in accordance with 10 CFR 50.59, since the TRM is currently incorporated by reference into the UFSAR. The NRC reviewer was concerned that Davis-Besse might be able to decrease the time to something less than 72 hours using 10 CFR 50.59, and not obtain NRC approval for the change. To alleviate the NRC reviewer's concern, Davis-Besse is willing to maintain the CTS 3.9.3 in the ITS; i.e., we will not relocate the Decay Time Specification to the TRM. If the Decay Time Specification is maintained in the ITS, then it is also not necessary to include proposed ITS 3.3.15 and ITS 3.9.3 in the Davis-Besse Technical Specifications. The Applicability of these two' Specifications is "During movement of recently irradiated fuel assemblies within containment." Since the term "recently" is defined as fuel that has occupied part of a critical reactor core within the previous 72 hours, if fuel is prohibited by Technical Specifications from being moved prior to 72 hours, then there is no need for a Technical Specification that places requirements when moving fuel prior to 72 hours. Davis-Besse will provide appropriate markups to show the inclusion of CTS 3.9.3 and the deletion of ITS 3.3.15 and ITS 3.9.3 after the NRC accepts the Davis-Besse approach. Issue 2: In addition, the NRC also requested a discussion of how the release is detected and how the Normal HVAC air intake isolation is accomplished. As discussed in the ITS 3.3.16 Bases (Volume 8, Page 530), the Station Vent Radiation Monitors are located in the station vent stack and provide isolation and shutdown of the Control Room Normal Ventilation System (CRNVS). The isolation signal is provided by two normal range radiation http://www.excelservices.com/exceldbs/itstrackdavisbesse.nsfl1 fddceal Od3bdbb585256e... 7/18/2008

NRC ITS Tracking Page 2 of 4 Licensee Response by Bryan rhe Allowable Value has not been incorporated in ITS SR 3.3.15.3 Kays on 03/03/2008 (Volume 8, Page 501). As stated in the Justification for Deviation (JFD) 3 (Volume 8, Page 527), Allowable Value has not been included in ITS SR 3.3.15.3 since the current trip setpoint is not based on a specific safety analysis assumption or result, but is chosen based on historical operating experience to avoid spurious/nuisance alarms and to provide an early indication of increased activity to terminate the release prior to exceeding Offsite Dose Calculation Manual release limits. Furthermore, as stated in the ITS Bases (Page 507), the Containment Purge and Exhaust Isolation - High Radiation has no safety function and is not assumed to function during any UFSAR design basis accident or transient analysis. The ISTS wording in the Background section of the Bases (Page 506) states that the trip setpoint is based on analytical limits derived from the FSAR. This is not true for Davis-Besse. Therefore, this Davis-Besse alarm only function cannot have an Allowable Value. Additionally, Davis-Besse does not agree that this is a beyond scope item since this is consistent with the current requirements. NRC Response by Aron Lewin Technical-Branch assistance formally requested. Issue being on 03/24/2008 tracked by TAC MD8345. NRC Response by Aron Lewin The Technical Branch has the following questions: RAI-1: Please on 05/23/2008 discuss if the radiation monitors provide any safety function in the event of a fuel handling accident in containment when the Containment Purge and Exhaust system is operating and fuel from the reactor core is being moved within 72 hours after the reactor has been shut down(recently irradiated fuel). Include in discussion 10 CFR 100 limits and 10 CFR 50 Appendix A, GDC-19 limits. RAI-2: USFAR Section 15.4.7.3.4.3 states as one of the assumptions (Assumption No. 6) for the analysis for control room dose for a fuel handling accident inside containment is that the control room normal HVAC (heating, ventilation, and air-conditioning) air intake is isolated prior to the release from containment reaching the intake. The assumption goes on to state that the HVAC air intake is automatically isolated upon receipt of a high radiation signal from the station vent. These assumptions help assure that the control room dose remains within the acceptance criteria as given in GDC 19 of 10CFR50 Appendix A. Please discuss how the release is detected and how the normal HVAC air intake isolation is accomplished. Include in discussion how isolation prior to the release reaching the HVAC air intake is assured when the Containment Purge and Exhaust System is in operation and when the Containment Purge and Exhaust System is not in operation at the time of the fuel handling accident. Also include in the discussion a fuel handling accident with fuel from the reactor core is being moved within 72 hours after the reactor has been shut down and single failure criteria with regard to radiation monitoring. RAI-3: If the radiation monitors do provide a safety function when the Containment Purge and Exhaust system http://www.excelservices.com/exceldbs/itstrack davisbesse.nsf/1 fddceal Od3bdbb585256e... 7/18/2008

NRC ITS Tracking Page I of 4 j4ýReturn to View Menu~ I" ocLnt: ent RAI Screening Required: Yes Status: Closed This Document will be approved by: Carl Regulatory Basis must be included in Comments Schulten; Tim Kobetz; Gerald Waig section of this Form This document has been reviewed and Yes information in this question contains NO SUNSI sensitive material (the checkbox to the right must be selected before this question can be submitted) NRC ITS TRACKING NRC Reviewer ID 200801161532 Conference Call Requested? No Ca.tegory BSI - Beyond Scope Issue 1TS SeCtioff: TB P.O.C.:. JFD Nu mber: Page .Nunmber(s): ITS 3.3 Aron Lewin None Information ITS Number: OSI: DOC Number: Bases JFD Number: 3.3.15 None None None NRC OSI#81 Discuss how the ITS SR 3.3.15.3 assures that the necessary quality of systems and components is maintained as required per 10 CFR 50.36(d)(3).

Background

                    -CTS LCO 3.9.4 (page 494 of 636) has a SR 4.9.4.b that states "verifying that with the containment purge and exhaust system in operation, and the containment purge and exhaust system noble gas monitor capable of providing a high radiation signal to the control room, that after initiation of the high radiation signal, the containment purge and exhaust isolation valves can be Comment closed from the control room."
                    -ITS LCO 3.3.15 (page 501 of 636) has a channel calibration SR 3.3.15.3, but deletes the STS calibration value. In addition, the ITS Bases (page 512 of 636) delete the STS setpoint methodology discussion associated with a calibration.
                    -STS LCO 3.3.15 (NUREG-1430) has a channel calibration SR 3.3.15.3, and includes an allowable value. The STS is based on a different design.

10 CFR 50.36(d)(3) states that "surveillance requirements are requirements relating to test, calibration, or inspection to assure that the necessary quality of systems and components is maintained, that facility operation will be within safety limits, and that the limiting conditions for operation will be met." Issue Date 01/16/2008 Close Date 06/18/2008 Logged in User: Anonymous .vResponses http://www.excelservices.com/exceldbs/itstrackdavisbesse.nsf/1 fddcea 1Od3bdbb585256e... 7/18/2008

NRC ITS Tracking Page 3 of 3 1_ 1150.36. Licensee Response by Jerry 1The proposal is posted in RAI 200801161532. Jones on 06/17/2008 II NRC Resp0 nse by Aron Lewin No further questions at this time; see thread 200801161532. Date Created: 01/16/2008 03:30 PM by Aron Lewin Last Modified: 06/18/2008 04:11 PM http://www.excelservices.com/exceldbs/itstrackdavisbesse.nsf/ 1fddcea 1Od3bdbb585256e... 7/18/2008

NRC ITS Tracking Page 2 of 3 Issue Date 01/16/2008 [ Close Date I06/18/2008 Logged in User: Anonymous

'Responses Licensee Response by Bryan        The Applicability of ITS 3.3.15 (Volume 8, Page 500) is derived Kays on 03/03/2008                from CTS 3.9.4. CTS LCO 3.9.4 (Page 494) requires that the containment purge and exhaust noble gas monitor channel be OPERABLE. Additionally, CTS 4.9.4.b requires that the containment purge and exhaust system be in operation in order to perform the Surveillance Requirement. ISTS 3.3.15 Applicability was changed to agree with the CTS 3.9.4 and 4.9.4.b. The ITS 3.3.15 Applicability includes the requirement that the Containment Purge and Exhaust System must be in service on the containment since the containment purge and exhaust noble gas monitors draw a sample from the containment purge and exhaust duct. Thus, if the Containment Purge and Exhaust System is not in operation, the noble gas monitor cannot perform its designed function (i.e.,

provide an alarm). That is, when the Containment Purge and Exhaust System is not in operation, the associated penetration will be closed and the containment purge and exhaust noble gas monitor channel cannot receive a signal. This is described in the Applicability section of ITS 3.3.15 Bases (Page 509,Insert 3). Furthermore, since this requirement is consistent with the current Technical Specifications, Davis-Besse does not agree that this is a beyond scope issue. NRC Response by Aron Lewin [Technical Branch assistance formally requested. Issue being .1 on 03/24/2008 tracked by TAC MD8345. NRC Response by Aron Lewin There is a concern that the term "in service" in the Applicability is on 05/23/2008 not defined. Therefore, if the system fans are not operating, or if the dampers are shut, the system may be considered not in service (even if the system is not isolated). A future safety analysis, which may not have to reviewed by the NRC, may require that the system be isolated to mitigate an accident. A scenario can result in which the system is unisolated during fuel movements, but the applicability of the LCO may not apply if the system fans are off or if the dampers are shut. In this scenario, it is unclear how the LCO ensures that the lowest functional capability or performance levels of equipment required for safe operation of the facility are met per 10 CFR 50.36. Licensee Response by Jerry In the latest response (6/04/08) to 200801161532, Davis-Besse Jones on 06/04/2008 stated that a solution for the NRC reviewer's concern posted in 200801161532 was to maintain CTS 3.9.3, Decay Time, in the ITS. This would allow deletion of the entire ITS 3.3.15. Therefore, if this proposal is accepted by the NRC reviewer, ITS 3.3.15 will be deleted and the questions posted for this RAI are moot. NRC Response by Aron Lewin Post the proposal for review. When discussing removal of the on 06/05/2008 LCO's, consider applicability of the four Criterion in 10 CFR http://www.excelservices.com/exceldbs/itstrackdavisbesse.nsf/1 fddcea 1Od3bdbb585256e... 7/18/2008

NRC ITS Tracking Pagel of3 14ýReturn to View Menu Pint D~ocuien RAI Screening Required: Yes Status: Closed This Document will be approved by: Carl Regulatory Basis must be included in Comments Schulten; Tim Kobetz; Gerald Waig section of this Form This document has been reviewed and Yes information in this question contains NO SUNSI sensitive material (the checkbox to the right must be selected before this question can be submitted) NRC ITS TRACKING NRC Reviewer ID 1200801161530 Conference-Call Requested? No Category BSI - Beyond Scope Issue ITS Sectilon:; TB POC: JFD NuI.mber.: P!age Number(s).: ITS 3.3 Aron Lewin None Information [TS Number: 0S1: DOC Number: Bases.JFD Number.: 3.3.15 None None None NRC OSI#80 Discuss how addition of the applicability term "when the Containment Purge and Exhaust System is in service," effects assurance that the lowest functional capability or performance levels of equipment required for safe operation of the facility are met, as required by 10 CFR 50.36(d)(2)(i).

Background:

                   -The CTS LCO 3.9.4 (page 494 of 636) applicability is during core alterations or movement of irradiated fuel within the containment.
                   -The ITS LCO 3.3.15 (page 500 of 636) applicability is during movement of recently irradiated fuel assemblies within the containment when the Containment Purge and Exhaust System is in service.
                   -STS LCO 3.3.15 (NUREG-1430) is applicable in Modes 1, 2, 3, 4, and during Comment     movement of [recently] irradiated fuel assemblies within the reactor building.

The STS is based on a different design. 10 CFR 50.36(d)(2)(i) states that "limiting conditions for operation are the lowest functional capability or performance levels of equipment required for safe operation of the facility." It is unclear how addition of the applicability term "when the Containment Purge and Exhaust System is in service," effects assurance that the lowest functional capability or performance levels of equipment required for safe operation of the facility are met, as required by 10 CFR 50.36(d)(2)(i). Specifically, it is unclear how the ITS LCO would be physically applied since there seems to be no need to ever enter Condition A (i.e. the system could just be secured since it is not part of a safety analysis). In addition, even if the Containment Purge and Exhaust System is not in service, active signals would prevent the system from being placed in service. http://www.excelservices.com/exceldbs/itstrack-davisbesse.nsf/lfddcealOd3bdbb585256e... 7/18/2008

NRC ITS Tracking Page 2 of 2 Licensee Response by Bryan The bracketed term "recently" was added to the applicability of Kays on 02/27/2008 LCO 3.3.15, as allowed by the reviewers note in ITS 3.9.3 Bases, page 57 and 59 of Volume 14. As stated in the Discussion'of Change (DOC) L01, the Applicability of recently irradiated fuel assemblies is justified based upon the accident analysis demonstrating that after 72 hours of radioactive decay, offsite doses resulting from a fuel handling accident remain below the Standard Review Plan limits and well within 10 CFR 100 requirements. Additionally, Davis-Besse does not agree that this is a beyond scope item, since the Applicability of ISTS 3.3.15 provides a bracketed allowance for the use of the word "recently." That is, Davis-Besse is adopting the ISTS allowance. NRC Response by Aron Lewin Technical Branch assistance formally requested. Issue being on 03/24/2008 tracked by TAC MD8345. NRC Response by Aron Lewin It is unclear how Criterion 3 of 10 CFR 50.36 would be met if a on 05/27/2008 future analysis credited automatic isolation of the purge system during a fuel handling accident when moving recently irradiated fuel. Page 508 of 636 states "The containment purge and exhaust noble gas monitor is required to be OPERABLE, which includes the correct valve lineup to the Containment Purge and Exhaust System, sample pump operation, and detector OPERABILITY." This is different from the STS that also emphasises "when these sampling features are necessary to initiate a trip as assumed by the safety analysis or setpoint analysis." It is unclear if the automatic trip actions that the detector initiates are also required to be operable. Licensee Response by Jerry The current design for the containment purge and exhaust system Jones on 05/29/2008 is that it is not automatically isolated. If a future analysis was performed that did assume an automatic -isolation, then the design would have to be changed in accordance with 10 CFR 50.59. This would require prior NRC approval per 10 CFR 50.59, since a Technical Specification change would be required (to change the system from manual isolationto automatic isolation). Thus, the analysis could not be changed until after the NRC approved the design change/Technical Specification change. NRC Response by Aron Lewin No further questions at this time. on 05/29/2008 DateCreated: 01/16/2008 03:28 PM by Aron Lewin Last Modified: 05/29/2008 08:31 AM http://www.excelservices.com/exceldbs/itstrack-davisbesse.nsfl1 fddceal Od3bdbb585256e.. 7/18/2008

NRC ITS Tracking Page I of ý Return to View Menu a Print Doc= n RA Screening Required: Yes Status: Closed This Document will be approved by: Carl Regulatory Basis must be included in Comments Schulten; Tim Kobetz; Gerald Waig section of this Form This document has been reviewed and Yes information in this question contains NO SUNSI sensitive material (the checkbox to the right must be selected before this question can be submitted) NRC ITS TRACKING NRC Reviewer IF200801161528 Conference Call Requested? No Category ]BSI - Beyond Scope Issue ITS Section: T-BPOC: JFD Number: PageNujnber(s): ITS 3.3 Aron Lewin None Information ITS Number: OSR: DOC Number: Bases JFD Number: 3.3.15 None None None NRC OSI#79 Discuss how adding the term "recently" effects physical application of ITS LCO 3.3.15, and thereby effects assurance that the lowest functional capability or performance levels of equipment required for safe operation of the facility are still met, as required by 10 CFR 50.36(d)(2)(i).

Background:

                     -The CTS LCO 3.9.4 (page 494 of 636) applicability is during core alterations or movement of irradiated fuel within the containment. The uSAR (page 4017 of 4076 in the USAR) assumes fuel is-not moved prior to 72 hours following Comment      reactor shutdown.
                     -The ITS LCO 3.3.15 (page 500 of 636) applicability is during movement of recently irradiated fuel assemblies within the containment when the Containment Purge and Exhaust System is in service. The term "recently" is also used in ITS LCO 3.9.3 (page 48 of 138 in Section 3.9).
                     -STS LCO 3.3.15 (NUREG-1430) is applicable in Modes 1, 2, 3, 4, and during movement of [recently] irradiated fuel assemblies within the reactor building.

The STS is based on a different design. 10 CFR 50.36(d)(2)(i) states that "limiting conditions for operation are the lowest functional capability or performance levels of equipment required for safe operation of the facility." I Issue :Date] 01/16/2008 Close Date [05/29/2008 Logged in User: Anonymous

' Responses http://www.excelservices.com/exceldbs/itstrackdavisbesse.nsf/1 fddcea 1Od3bdbb585256e...       7/18/2008

NRC ITS Tracking Page 2 of 2 SCDlow.,,atII 08421/2008 Logged in User: Anonymous

'Responses Licensee Response by Bill           UFSAR Section 15.4.7.3 is for the fuel handling accident inside Bentley on 02/06/2008               CTMT. All assumptions are made in accordance with the documents referenced in UFSAR Section 15.4.7.3.4.1. There is no feature that will automatically align Station EVS to the CTMT Purge Ventilation System on a high radiation condition. Therefore, it could not be credited. UFSAR Section 15.4.7.2 is for the fuel handling accident outside CTMT (i.e. in the Spent Fuel Pool). As pointed out by the reviewer, use of EVS is credited for the analysis for the accident in the Spent Fuel Pool area. Also, the requirements for Spent Fuel Pool EVS are addressed in CTS 3.9.12 and its associated Bases, not CTS 3.9.4.

NRC Response by Aron Lewin Will request conference call with licensee via PM. on 02/19/2008 NRC Response by Aron Lewin Understanding of the EVS design is required for disposition of the on 02/25/2008 licensee's statement in the Bases (page 507 of 636) that discusses why the LCO is being retained. During a 2/21/2008 conference call, the licensee stated that the plant was never designed with the capability to automatically align the EVS to the CTMT Purge Ventilation System. In addition, the licensee stated that it was unclear why the fuel accident analysis outside containment utilizes the EVS, when perhaps an analysis could have been done, similiar to the analysis inside containment, that would have precluded the need for the EVS. For the docket, please confirm the above or ___modify as required. Licensee Response by Bill The 2/25/08 post by the reviewer refers to two statements made by Bentley on 02/28/2008 Jthe licensee. The two statements are correct. NRC Response by Aron Lewin Potential concern regarding Containment Ventilation on 03/25/2008 Instrumentation LCO with incorrect application of 10 CFR 50.36 Criterion in Bases to be resolved during review associated with MD8345. on 04/2sponse by Aron Lewin No further questions at this time. Date Created: 01/16/2008 03:26 PM by Aron Lewin Last Modified: 04/21/2008 10:20 AM http://www.excelservices.com/exceldbs/itstrack davisbesse.nsf/1 fddceal Od3bdbb585256e... 7/18/2008

NRC ITS Tracking .Page I of 2 jj-ýReturn to View McmiQ Print Docuen RAI Screening Required: Yes 'Status: Closed This Document will be approved by: Carl Regulatory Basis must be included in Comments Schulten; Tim Kobetz; Gerald Waig section of this Form This document has been reviewed and Yes information in this question contains NO SUNSI sensitive material (the checkbox to the right must be selected before this question can be submitted) NRC ITS TRACKING NRC Reviewer ID 200801161526 Conference Call Requested? No Category BSI - Beyond Scope Issue ITS Section: TB POC: JFD Number: P.ageNumber(s): ITS 3.3 Aron Lewin None Information ITS Number: OS1:; DOC Number: Bases...JFD Numbe.r: 3.3.15 None None None NRC OSI#78 Discuss why use of the EVS is credited the fuel handling accident outside containment scenario and not the fuel handling accident inside containment scenario, and would therefore effect necessity for TS inclusion as required by 10 CFR 50.36(d)(2)(ii).

Background:

                    -The CTS LCO 3.9.4 Bases (page 448 of 490 in the CTS) do not discuss TS criterion. The USAR (page 4017 of 4076 in the USAR) discusses the EVS (Assumption #8) with regards to a Fuel Handling Accident outside of containment. There is a Note that says Assumption #8 is not used for a Fuel Handling Accident inside of containment.
                    -The ITS Bases (page 507 of 636) state "the Containment Purge and Exhaust Comment. Isolation - High Radiation has no safety function and is not assumed to function during any UFSAR design basis accident or transient analysis."
                    -The STS Bases for LCO 3.3.15 (NUREG-1430),state that the LCO is included in order to satisfy Criterion 3 of 10 CFR 50.36(d)(2)(ii). The STS is based on a different design.

10 CFR 50.36(d)(2)(ii) discusses how a technical specification limiting condition for operation of a nuclear reactor must be established for an item meeting one of the four criteria listed. Given that the specific location of a Fuel Handling Accident would seem independent of the immediate local release, it is unclear why use of the EVS is credited in one scenario and not the other, and would therefore effect necessity for TS inclusion as required by 10 CFR 50.36(d)(2)(ii). Issue.Date 01/16/2008 http://www.excelservices.com/exceldbs/itstrackdavisbesse.nsf/1 fddceal 0d3bdbb585256e... 7/18/2008

NRC ITS Tracking Page 3 of 3 setpoint analysis." In addition, the Bases for STS LCO 3.3.16, contains a discussion "Trip Setpoints and Allowable Values," which describes instrument setpoint methodology and operability determinations during Channel Calibrations. These discussions provide amplifying and clarifying information on Channel Calibrations that are not found in the STS Section 1.1 definition of a Channel Calibration. 10 CFR 50.36(d)(3) states technical specifications will include surveillance requirements which "are requirements relating to test, calibration, or inspection to assure that the necessary quality of systems and components is maintained, that facility operation will be within safety limits, and that the limiting conditions for operation will be met." Based on the discussion in NUREG-1430, it is unclear how 10 CFR 50.36(d) (3) is met for proposed SR 3.3.14.3 on Channel Calibrations, if the expected Bases discussions, which provide amplifying and clarifying information on Channel Calibrations not found in the definition of a Channel Calibration in proposed Section 1.1, is not included. Licensee Response by Jerry Davis-Besse has re-reviewed the ITS SR 3.3.14.3 Bases and will Jones on 06/09/2008 add words similar to those in other CHANNEL CALIBRATION Bases, but consistent with the current licensing basis (as described in the ITS Bases) for this specific CHANNEL CALIBRATION. Note that the responses to RAI 200801161429 changed the SR to require a "Trip Setpoint" versus an "Allowable Value," consistent with the current licensing basis and as requested by the NRC reviewer. A draft markup regarding this change is attached. This change will be reflected in the supplement to this section of the ITS Conversion Amendment. Licensee Response by Jerry During a recent phone conversation with the NRC reviewer, Jones on 06/30/2008 clarification was provided concerning the words being requested to be added to the Bases. A draft markup regardingthis change is attached and supersedes the draft markup provided with the Davis-Besse 6/9/08 response. In addition, a typographical error has been corrected in the USAR Figure identified in Reference 1. This change will be reflected in the supplement to this section of the ITS Conversion Amendment. NRC Response by Aron Lewin No further questions at this time. on 06/30/2008 Date Created: 01/i6/2008 02:33 PM by Aron Lewin Last Modified: 06/30/2008 10:10 AM http://www.excelservices.com/exceldbs/itstrackdavisbesse.nsf/1 fddceal Od3bdbb585256e... 7/18/2008

NRC ITS Tracking Page 2 of 3 'Responses Licensee Response by Bryan Section 1.1 (Volume 3, Page 32) defines what a CHANNEL Kays on 02/27/2008 CALIBRATION is. There is no need to redefine it in the Bases of 3.3.14 (Volume 8, Page 488). The definition in Section 1.1 adequately addresses the adjustments during calibration. Furthermore, the NRC reviewer in his comment even stated that this discussion is not in all of the CHANNEL CALIBRATION discussions in the NUREG. Therefore, since this is a Bases change only, and it has no affect on the Technical Specification requirements (the statement is only stating why the requirement is in the ITS), the change is not a beyond scope change, as defined in NRC Generic Letter 96-04. The Generic Letter states that beyond scope issues are those that differ from existing Technical Specifications and the improved Standard Technical Specifications. Since this specific change is not a Technical Specification change and does not differ from the Davis-Besse CTS, it is not a beyond scope issue. NRC Response by Aron Lewin IrRequesting TAC for technical branch support. on 02/27/2008 I NRC Response by Aron Lewin Technical Branch assistance formally requested. Issue being on 03/24/2008 tracked by TAC MD8346. NRC Response by Aron Lewin Proposed LCO 3.3.14, "Fuel Handling Exhaust - High Radiation," on 06/06/2008 contains a Surveillance Requirement (SR) 3.3.14.3 which is a Channel Calibration SR. The Bases for SR 3.3.14.3 contains a discussion on Channel Calibrations that does not discuss instrument adjustments with regards to drift between successive calibrations in order to ensure that the channel remains operational between successive tests. In addition, the Bases to not specify which methodology is used during the Channel Calibration. Also there is no discussion in the LCO 3.3.14 Bases on "Trip Setpoints and Allowable Values," which typically describe instrument setpoint methodology and operability determinations during Channel Calibrations. These discussions, which would provide amplifying and clarifying information on Channel Calibrations, are expected since it is information that is not found in the definition of a Channel Calibration in proposed Section 1.1, "Definitions." For comparison, NUREG-1430, "Standard Technical Specifications Babcock and Wilcox Plants," contains STS LCO 3.3.16, "Control Room Isolation - High Radiation." Proposed LCO 3.3.14, "Fuel Handling Exhaust - High Radiation," is similar to STS LCO 3.3.16 in that both LCOs ensure that the high radiation isolation function provides assurance that under the required conditions, an isolation signal will be given. STS LCO 3.3.16 contains a (SR) 3.3.16.3 which is a Channel Calibration SR. The Bases for STS SR 3.3.16.3 contain a discussion that states "Channel Calibration leaves the channel adjusted to account for instrument drifts between successive calibrations to ensure that the channel remains operational between successive tests. Channel Calibrations must be performed consistent with the unit specific http://www.excelservices.comlexceldbs/itstrackdavisbesse.nsf/1 fddceal Od3bdbb585256e... 7/18/2008

NRC ITS Tracking Page. I of 3 1',ýReturn to View Menu Print Doctiien RAI Screening Required: Yes Status: Closed This Document will be approved by: Carl Regulatory Basis must be iincluded in Comments Schulten; Tim Kobetz; Gerald Waig section of this Form This document has been reviewed and Yes information in this question contains NO SUNSI sensitive material (the checkbox to the right must be selected before this question can be submitted) NRC ITS TRACKING NRC Reviewer ID]200801161433 Conference CallRequested? No Category] BSI - Beyond Scope Issue ITS Section: TB POC: JFD Number: P!age.Nuinber(s).: ITS 3.3 Aron Lewin None Information ITS.-Number: OS.I:; DO.C.Number: Bases JFD.Number: 3.3.14 None None None NRC OSI#77 Discuss how not including a channel adjustment discussion in the ITS Bases for the calibration SR will effect physical application of the SR, and therefore still assure that the necessary quality of systems and components is maintained, that facility operation will be within safety limits, and that the limiting conditions for operation will be met per 10 CFR 50.36(d)(3).

Background:

                    -The CTS Bases (page 402 of 490 in the CTS) do not discuss calibrations for the Fuel Storage Pool Area Emergency Ventilation System Actuation Area Monitor.

Comment -The ITS Bases (488 of 636) discusses Channel Calibrations, but does not discuss the adjustments during calibration that are found in most calibration SR Bases discussions (i.e channel calibration leaves the channel adjusted to account for instrument drifts between successive calibrations to ensure that the channel remains operational betweensuccessive tests, etc).

                    -The STS (NUREG-1430) contains no LCO for Fuel Handling Exhaust - High Radiation Monitors.

10 CFR 50.36(d)(3) states that "surveillance requirements are requirements: relating to test, calibration, or inspection to assure that the necessary quality of systems and components is maintained, that facility operation will be within safety limits, and that the limiting conditions for operation will be met." Issue Date 01/16/2008 Close Date 06/30/2008 Logged in User: Anonymous http://www.excelservices.com/exceldbs/itstrackdavisbesse.nsf/l fddceal Od3bdbb585256e... 7/18/2008

NRC ITS Tracking Page 2 of2 changing the Fuel Handling Exhaust - High Radiation Monitor setpoint to an allowable value effects physical application of the LCO, which assures mitigation of a design basis accident or transient that either assumes the failure of or presents a challenge to the integrity of a fission product barrier, thereby still satisfying Criterion 3 of 10 CFR 50.36(d)(2)(ii). F Issue Date 101/16/2008 Close Date 03/18/2008 Logged in User: Anonymous

'Responses Licensee Response by Bill              [Please clarify what information in Discussion of Change A02 Bentley on 02/05/2008                  [(page 478 of Volume 8) is lacking for addressing this issue.

via PM. on NRC 02/20/2008 Response by Aron Lewin [Will request conference call with licensee 1 NRC Response by. Aron Lewin During a 2/21/2008 conference call, the licensee stated that they on 02/25/2008 would consider rephrasing the setpoint to a trip setpoint as opposed to an allowable value since the term allowable value Itypically has a methodology associated with it. Licensee Response by Bryan Based on a recent discussion between the NRC and Davis-Besse Kays on 03/18/2008 personnel, Davis-Besse has determined that replacing the term "TRIP SETPOINT" with "ALLOWABLE VALUE" is appropriate for the ITS 3.3.14. This change is consistent with the CTS requirements, which only specifies the Alarm "Trip Setpoint" in, CTS Table 3.3-6 (Volume 8, Page 475). Therefore, changes have been made to CTS Table 3.3-6 (Page 475), Discussion of Changes A02, ITS SR 3.3.14.3 (Page 482), and the Background and LCO section of ITS 3.3.14 Bases (Pages 485 and 486). A draft markup regarding this change is attached. This change will be reflected in the supplement to this section of the ITS Conversion Amendment. NRC 0]No Response by Aron Lewin further questions at this time."

ýon 03/18/2008                       J____________________________

Date Created: 01/16/2008 02:29 PM by Aron Lewin

                                                                               .. Last Modified: 03/18/2008 02:52 PM http://www.excelservices.com/exceldbs/itstrack davisbesse.nsf/ 1fddceal Od3bdbb585256e...                  7/18/2008

NRC ITS Tracking Page I of 2 V Return to Viexw ...Menu *Print Document RkI Screening Required: Yes Status: Closed This Document will be approved by: Carl RegulatoryvBasis must beincluded in Comments Schulten; Tim Kobetz; Gerald Waig section of this Form This document has been reviewed and Yes information in this question contains NO SUNSI sensitive material (the checkbox to the right must be selected before this question can be submitted) NRC ITS TRACKING NRC Reviewer Ib_1200801161429. Conference Call Requested? No Category BSI - Beyond Scope Issue ITS S.ction: TBOIPOC: JFD1Nuniber: Page Number(s).; ITS 3.3 Aron Lewin None Information ITS.Number: OS:. DOC Number: Bases JFD Number: 3.3.14 None None None NRC OSI#76 Discuss how changing theFuel Handling Exhaust - High Radiation Monitor setpoint to an allowable value effects physical application of the LCO, which assures mitigation of a design basis accident or transient that either assumes the failure of or presents a challenge to the integrity of a fission product barrier, thereby still satisfying Criterion 3 of 10 CFR 50.36(d)(2)(ii).

Background:

                  -The CTS (page 475 of 636) lists a Fuel Storage Pool Area Emergency Ventilation System Actuation Area Monitor setpoint.
                  -The ITS (page 482 of 636) lists a Fuel Storage Pool Area Emergency Ventilation System Actuation Area Monitor allowable value. The value is the same in both cases. The ITS Bases (page 486 of 636),also states that "only the Comment Allowable Values are specified for each Fuel Handling Exhaust - High Radiation channel in SR 3.3.14.3. Nominal trip setpoints are specified in. the Radiation Monitor Setpoint Manual. The nominal setpoints are based on the UFSAR~design normal radiation levels {Figure 12.1-5} and are set at 50% of the Allowable Value to ensure that conditions~are well within the limits of 10 CFR 100." The ITS Bases do not have a "Trip Setpoints and Allowable Value" discussion.
                  -The STS (NUREG-1430) contains no LCO for Fuel Handling Exhaust - High Radiation Monitors.

Criterion 3 of 10 CFR 50.36(d)(2)(ii) states a TS must be established for "a structure, system, or component that is part of the primary success path and which functions or actuates to mitigate a design basis accident or transient that either assumes the failure of or presents a challenge to the integrity of a fission product barrier." Given the ITS Bases discussion, it is still unclear how http://www.excelservices.com/exceldbs/itstrackdavisbesse.nsf/1 fddceal Od3bdbb585256e... .7/18/2008

NRC ITS Tracking Page 3 of 3 NRC Response by Aron Lewin No further questions at this time. on 03/25/2008 Date Created: 01/16/2008 02:26 PM by Aron Lewin Last Modified: 03/25/2008 01:05 PM http://www.excelservices.com/exceldbs/itstrackdavisbesse.nsf/ 1fddcea 1Od3bdbb585256e... 7/18/2008

NRC ITS Tracking Page 2 of 3 I[lacking in the above ITS information with regards to this issue. NRC Response by Aron Lewin Will request conference call with licensee via PM. on 02/19/2008 1. NRC Response by Aron Lewin The ITS Bases discussion (page 486 of 636) does not address the on 02/25/2008 original question of physical application. During a 2/21/2008 conference call, the licensee attemped to discuss, but it was not clearly understood by the NRC, how the Note could be potentially used by the licensee to prevent an unnecessary shutdown while in Mode 1, 2, 3, or 4. In the CTS, (page 474 of 636) the Note is present because it could be applied to CTS Actions a and b. Discuss how Condition A does not adress all possible conditions, or how Required Action A. 1 could not be carried out, that would require the necessity to apply the Note that LCO 3.0.3 is not applicable. Licensee Response by Bryan The Applicability of ITS 3.3.14 (Volume 8, Page 482) is during Kays on 03/20/2008 movement of irradiated fuel assemblies. This operation can occur during any MODE; that is, it can occur while the reactor is in MODE 1, 2, 3, or 4. The ISTS normally includes an LCO 3.0.3 exception Note when this type of Applicability is listed since LCO 3.0.3 does not provide any actions to take if the unit is in, for example, MODE 1 when fuel is being moved. Thus, to preclude an inappropriate entry into LCO 3.0.3 and to ensure the proper actions for an inoperable feature required when moving irradiated fuel assemblies, this LCO 3.0.3 exception note has been included. This Note inclusion is consistent with CTS Table 3.3-6 Action 22, which provides the same action as is in ITS 3.3.14 ACTION A. This Note is also consistent with similar Notes in the ISTS, when the ISTS has an Applicability of moving fuel assemblies. For example, ISTS 3.7.13, which is the system specification that this instrumentation applies, has a LCO 3.0.3 Note. The ISTS Bases for this Note (Volume 12, Page 322) states: "LCO 3.0.3 is not applicable while in MODE 5 or 6. However, since irradiated fuel assembly movement can occur in MODE 1, 2, 3, or 4, the ACTIONS have been modified by a Note stating that LCO 3.0.3 is not applicable. If moving irradiated fuel assemblies while in MODE 5 or 6, LCO 3.0.3 would not specify any action. If moving irradiated fuel assemblies while in MODE 1, 2, 3, or 4, the fuel movement is independent of reactor operations. Entering LCO 3.0.3, while in MODE 1, 2,3, or 4 would require the unit to be shutdown unnecessarily." The ITS 3.3.14 Bases (Page 486) has included this same explanation for the Note. Thus, Davis-Besse belives that this provides adequate discussion of the application of the Note (i.e., since it is adequate for the ISTS application of the Note in ISTS 3.7.13, it should be adequate for the instrumentation Specification that supports the system specification). Therefore, Davis-Besse believes that this Note, Which is currently in the CTS, is necessary and should not be deleted. Furthermore, based on the above, Davis-Besse does not believe that we can provide adequate justification for deleting the Note from the CTS. 1! http:l//www.excelservices.com/exceldbs/itstrack-davisbesse.nsf/1fddcea10d3bdbb585256e...' 7/18/2008

NRC ITS Tracking Pagel1 f3 jjVReturn to View Menu Print Docuen RAI Screening Required: Yes Status: Closed This Document will be approved by: Carl Regulatory Basis m'ust-be included in Comments Schulten; Tim Kobetz; Gerald Waig section of this Form This document has been reviewed and Yes information in this question contains NO SUNSI sensitive material (the checkbox to the right must be selected before this question can be submitted) NRC ITS TRACKING NR C Rpvlpowr HD 200801161426 Conference Call Requested? No Category BSI - Beyond Scope Issue ITS Section: TB POC: JFD Number: Page Number(s): ITS 3.3 Aron Lewin None Information ITS Number: OSI: DOC Number: Bases JFDNumbe*r: 3.3.14 None None None NRC OSI#75 In order to ensure that the lowest functional capability or performance levels of equipment required for safe operation of the facility are maintained per 10 CFR 50.36(d)(2)(i), discuss how the ITS Applicability Note would be physically applied when the Actions Table refers to another LCO.

Background:

                   -The CTS LCO 3.3.3 (page 474 of 636) has Action c that states "the provisions Comment   of Specifications 3.0.3 and 3.0.4 are not applicable."
                   -The ITS (page 482 of 636) has a Note that states "LCO 3.0.3 is not applicable."
                   -The STS (NUREG-1430) contains no LCO for Fuel Handling Exhaust - High Radiation Monitors.

10 CFR 50.36(d)(2)(i) states that "limiting conditions for operation are the lowest functional capability or performance levels of equipment required for safe operation of the facility." Issue Date 01/16/2008 Close Date[ 03/25/2008 Logged in User: Anonymous

'Responses Licensee Response by Bill             3.0.3 does not apply in either CTS or ITS as described in the first Bentley on 02/05/2008                paragraph of the Action section of the ITS Bases (page 486 of Volume 8). 3.0.4 was removed as described by Discussion of Change A03 (page 478 of Volume 8). Please clarify what is http://www.excelservices.com/exceldbs/itstrackdavisbesse.nsf/1 fddceal Od3bdbb585256e... 7/18/2008

NRC ITS Tracking 'Page 2 of 2 placed in service and the fuel handling area pumps are not secured when the associated Fuel Handling Exhaust - High Radiation Monitor is inoperable as in other ventilation instrumentation LCOs (i.e ITS / STS 3.3.15 and ITS / STS 3.3.16). [ Issue:Datel'01/46/2008 Close [2/20/2008 Logged in User: Anonymous

' Responses Licensee Response by Bill             CTS 3'3.3.1 (Volume 8, Pages 474 and 476) only require taking' Bentley on 02/07/2008                 action in accordance with CTS 3.9.12 (ITS 3.7.13) when both radiation monitoring instrument channels are inoperable. This requires both trains of Spent Fuel Pool EVS to be declared inoperable, and CTS 3.9.12 Action c is applied. ITS 3.3.14 (Page 482) requires both~radiation monitoring instrument channels to be OPERABLE, as described in Discussion of Change M02 (Page 479). A trip of either radiation instrument channel causes the same actuations on the Spent Fuel Pool Ventilation System, described in the ITS 3.3.14 Bases (Page 485) and in the ITS 3.7.13 Bases (Volume 12, Page 318 and 319). Also, a trip of either radiation instrument channel will start its respective Emergency Ventilation Fan. Therefore, the most conservative action to take (which is also' consistent with current licensing basis) is to declare the associated train of Spent Fuel Pool Emergency Ventilation System inoperable, In this way, the applicable actions of ITS 3.7.13, which provide the non-instrument requirements for the, Spent Fuel Pool

_Emergency Ventilation System, will be applied.. NRC Response by Aron Lewin lNo further questions at this time. on 02/20/2008I Date'Created: 01/1 6/2008 02:25 PM by Aron Lewin Last Modified: 02/20/2008 03:05 PM http://www.excelservices.com/exceldbs/itstrack davisbesse.nsf/1 fddceal Od3bdbb585256e... 7/18/2008

NRC ITS Tracking Page I of 2 Return to View Menu a Print Doc~ument RAI Screening Required: Yes Status: Closed This Document will be approved by: Carl Regulatory Basis must be included in Comments Schulten; Tim Kobetz; Gerald Waig section of this Form This document has been reviewed and Yes information in this question contains NO SUNSI sensitive material (the checkbox to the right must be selected before this question can be submitted) NRC ITS TRACKING NRC Reviewer ID 1200801161425 Conference CallRequested? No Catego*ry BSI - Beyond Scope Issue ITS, Section:. TBPOC: JFD Number: PageNumber(s)! ITS 3.3 Aron Lewin None Information ITS.Number: OS1:. DOC. Number: Bases JFD Number: 3.3.14 None. None None NRC OSI#74 As permitted by 10 CFR 50.36(d)(2)(i), discuss why a train of the Spent Fuel Area Emergency Ventilation System is not placed in service and the fuel handling area pumps are not secured when the associated Fuel Handling Exhaust - High Radiation Monitor is inoperable..

Background:

                   -The CTS (page 476 of 636) states that when the minimum requirement of having one Fuel Storage Pool Area Emergency Ventilation System Actuation Area Monitor operable is not met (i.e both monitors inoperable), Action 22 applies. Action 22 states that "with the number of channels operable less than required by the Minimum Channels operable requirement, comply with the Action requirements of Specification 3.9.12."

Comment -ITS Condition A (page 482of 636) requires that a Spent Fuel Area Emergency Ventilation System train be declared inoperable when its associated channel monitor is inoperable. ITS LCO 3.7.13, "Spent Fuel Pool Area Emergency Ventilation System (EVS)," (page 313 of 461 in Section 3.7) has various actions that differ from the CTS Specification 3.9.12.

                   -The STS (NUREG-1430) contains no LCO for Fuel Handling Exhaust - High Radiation Monitors.

10 CFR 50.36(d)(2)(i) states that "limiting conditions for operation are the lowest functional capability or performance levels of equipment required for safe operation of the facility. When a limiting condition for operation of a nuclear reactor is not met, the licensee shall shut down the reactor or follow any remedial action permitted by the technical specifications until the condition can be met." As permitted by 10 CFR 50.36(d)(2)(i), it is unclear why a train of the Spent Fuel Area Emergency Ventilation System is not http://www.excelservices.com/exceldbs/itstrack davisbesse.nsf' 1fddceal Od3bdbb585256e... 7/18/2008

NRC ITS Tracking Page 2 of 2 an inoperable instrument channel. In order to better understand the Fuel Handling Exhaust - High Radiation Monitors, the following information is needed:

                   - Does one channel initiate only one train of EVS?
                   - Does one channel initiate isolation of all three fuel handling area pumps?
                   - What is the physical composition of each channel (i.e. detectors, detector P

inputs required for actuation)? Issue Date 101/16/2008 Close Date] 02/25/2008 Logged in User: Anonymous 'Responses Licensee Response by Bill The detaileddescription in the ITS Bases for ITS 3.3.14 Bentley on 02/06/2008 (Background, page 485 of Volume 8) and for ITS 3.7.13 (Background, page 318 and 319 of Volume 12) appear to provide all of the necessary information to address this question. Although not explicity stated in the Bases-descriptions, each radiation detector will only start its respective EVS fan. NRC Response by Aron Lewin Will request conference call with licensee via PM. on Response by Licensee Response by Jerry During a recent NRC phone conversation, the NRC reviewer asked Jones on 02/21/2008 Davis-Besse to clarify the actions when a channel trips. When the Fuel Handling Exhaust - High Radiation instrumentation detects a radiation level in excess of the high radiation setpoint, a signal from the applicable radiation monitor is sent to the logic for the FHAVS and the Spent Fuel Pool Area EVS. The FHAVS supply and exhaust fans will trip and their respective inlet and outlet dampers will isolate. The Fuel Handling Area to Emergency Ventilation dampers open and the Station EVS fans start. Each channel starts only one of the two Station EVS fans, but performs all the other actions listed above. NRC Response by Aron Lewin on 02/25/2008 1No further questions at this time. Date Created: 01/16/2008 02:22 PM by Aron Lewin Last Modified: 02/25/2008 07:07 AM http://www.excelservices.com/exceldbs/itstrack_,davisbesse.nsf/1 fddceal Od3bdbb585256e... 7/18/2008

NRC ITS Tracking Page 1 of 2 140Return to View Menu Prnt cu=en RAI Screening Required: Yes Status: Closed This Document will be approved by: Carl Regulatory Basis must be included in Comments Schulten; Tim Kobetz; Gerald Waig section of this Form This document has been reviewed and Yes information in this question contains NO SUNSI sensitive material (the checkbox to the right must be selected before this question can be submitted) NRC ITS TRACKING NRC Reviewer IDD 200801161422 Conference Call Requested? No Categoiy BSI - Beyond Scope Issue ITS Section: TB .P.O.C:. JFD Number: Page Number(s); ITS 3.3 Aron Lewin None Information ITS Number: 0S1. DOC.Number: Bases JFD Number: 3.3.14 None None None NRC OSI#73 Discuss the logic of the Fuel Handling Exhaust - High Radiation Monitors to determine if appropriate actions, as permitted by 10 CFR 50.36(d)(2)(i), are being taken for an inoperable instrument channel.

Background:

                   -The CTS (page 476 of 636) states that when the minimum requirement of having one Fuel Storage Pool Area Emergency Ventilation System Actuation Area Monitor operable is not met (i.e both monitors inoperable), Action 22 applies. Action 22 states that "with the number of channels operable less than required by the Minimum Channels operable requirement, comply with the Action requirements of Specification 3.9.12."
                   -ITS Condition A (page 482of 636) requires that a Spent Fuel Area Emergency Comment     Ventilation System train be declared 'inoperable when its associated channel monitor is inoperable. ITS LCO 3.7.13, "Spent Fuel Pool Area Emergency Ventilation System (EVS)," (page 313 of 461 in Section 3.7) has various actions that differ from the CTS Specification 3.9.12.
                   -The STS (NUREG-1430) contains no LCO for Fuel Handling Exhaust - High Radiation Monitors.

10 CFR 50.36(d)(2)(i) states that "limiting conditions for operation are the lowest functional capability or performance levels of equipment required for safe operation of the facility. When a limiting condition for operation of a nuclear reactor is not met, the licensee shall shut down the reactor or follow any remedial action permitted by the technical specifications until the condition can be met." The logic of the Fuel Handling Exhaust - High Radiation Monitors is unclear and therefore it is difficult to determine if appropriate actions, as permitted by 10 CFR 50.36(d)(2)(i), are being taken for http://www.excelservices.com/exceldbs/itstrack-davisbesse.nsf/lfddcea1Od3bdbb585256e... 7/18/2008

NRC ITS Tracking Page 3 of 3 irradiated fuel assemblies in the spent fuel pool area negative pressure boundary." Due to the change in Applicability, changes have been made to ITS 3.7.13 DOC L02 (Page 307), ITS 3.7.13 Required Actions B.2 and C. 1 (Page 314), and to the Bases of ITS 3.7.13 (Pages 322 through 324). Draft markups regarding these changes are attached. These changes will be reflected in the supplement to this section and, section 3.7 of the ITS Conversion Amendment. NRC Response by Aron Lewin Technical branch assistance requested. Issue will be tracked via on 03/27/2008 1MD8370. NRC Response by Aron Lewin No further questions at this time. on 05/06/2008 1L___________________________ Date Created: 01/16/2008 02:20 PM by Aron Lewin Last Modified: 05/06/2008 04:37 PM http://www.excelservices.com/exceldbs/itstrack davisbesse.nsf/1 fddceal Od3bdbb585256e... ' 7/18/2008

NRC ITS Tracking Page 2 of 3 Logged in User: Anonymous

'Responses Licensee Response by Bill          Please clarify what is lacking in Discussion of Change LO 1 (page Bentley on 02/05/2008           ]L480 of Volume 8) for addressing this issue.

NRC Response by Aron Lewin Will request conference call with licensee via PM. on 02/19/2008 i NRC Response by Aron Lewin During a 2/21/2008 conference call the licensee stated they would on 02/25/2008 provide a response discussing how "movement of irradiated fuel assemblies outside containment" is equivalent to "movement of irradiated fuel assemblies in the spent fuel pool" (i.e. movement of irradiated fuel assemblies outside of containment could not occur if not within the spent fuel pool). Licensee Response by Bill UFSAR section 15.4.7.2 discusses Fuel Handling Accidents Bentley on 02/27/2008 outside of containment. It assumes the gases released pass upward through the spent fuel pool water. Credit is taken for EVS filtration. UIFSAR section 9.1.4.3 describes that the facility design provides for loading a storage cask with spent fuel in a Cask Pit that is adjacent to the Spent Fuel Pool. While this loading were occurring, we would be in the applicability of ITS 3.3.14 (and ITS 3.7.13) since handling of irradiated fuel would be occurring in the Spent Fuel Pool. UFSAR section 15.4.7.2.5.3 discusses Dry Fuel Storage Cask Drop. No credit is taken for EVS removal of iodine for a Dry Fuel Storage Cask Drop. Therefore, the applicability of "during movement of irradiated fuel assemblies in the spent fuel pool" is correct. As a further note, Davis-Besse is not currently performing any dry spent fuel storage casking activities. Rescheduling of future casking activities is dependent on VECTRA Technologies', Incorporated, completion of actions to resolve issues stemming from the NRC Demand for Information issued to VECTRA on January 13, 1997. Licensee Response by Bill Please do not close this question thread based on the 2/27/08 Bentley on 02/28/2008 response. Davis-Besse is doing additional evaluation of the appropriate applicability for LCO 3.3.14 (and by association, LCO 3.7.13). We will post an additional response when our evalution is _complete. Licensee Response by Bryan This response supersedes the responses of 2/27/2008 and Kays on 03/20/2008 2/28/2008. Davis-Besse has determined that the Applicability of ITS 3.3.14 (Volume 8, Page 482) should be changed to include the spent fuel pool area negative pressure boundary, which includes not only the spent fuel pool, but also any area that is part of the negative pressure boundary (like the inside of the containment pressure vessel when the containment equipment hatch is open). Based on this decision, changes have been made to ITS 3.3.14 Discussion of Changes (DOC) LO0 (Page 480) and the Bases of ITS 3.3.14 (Page 486). Additionally, ITS 3.7.13 is affected by this decision since it covers the system that the instruments are associated with. Therefore, the ITS 3.7.13 Applicability (Volume 12, Page 313) has also been changed to be "During movement of http://www.excelservices.com/exceldbs/itstrackdavisbesse.nsf/1 fddcea 1Od3bdbb585256e... 7/18/2008

NRC ITS Tracking Page I of 3 jjýoReturn to View Menu] Prnt Documient RAT Screening Required: Yes Status: Closed This Document will be approved by: Carl Regulatory Basis must be included in Comments Schulten; Tim Kobetz; Gerald Waig section of this Form This document has been reviewed and Yes information in this question contains NO SUNSI sensitive material (the checkbox to the right must be selected before this question can be submitted) NRC ITS TRACKING NRC Reviewer 200801161420 Conference Call Requested? No Category BSI - Beyond Scope Issue ITS Section..: TB.POC:. JFD Nu11mb1er: Page. Number(s):. ITS 3.3 Aron Lewin None Information ITS Nunmber: 0S1: DOC Number:: Bases JFD.-Number: 3.3.14 None None None NRC OSI#72 Discuss why the ITS LCO is only applicable during movement of irradiated fuel assemblies in the spent fuel pool as opposed to movement of irradiated fuel assemblies outside containment, thereby assuring the lowest functional capability or performance levels of equipment required for safe operation of the facility, as required by 10 CFR 50.36(d)(2)(i).

Background:

                     -The CTS (page 475 of 636) requires that the Fuel Storage Pool Area Emergency Ventilation System Actuation Area Monitors be operable when fuel is in the storage pool or building. The USAR (page 4017 of 4076) discusses Comment' Emergency Ventilation assumptions for a fuel handling accident outside containment (assumption #8).
                     -The ITS (page 482 of 636) requires that the Fuel Handling Exhaust - High Radiation Monitors shall be operable during movement of irradiated fuel assemblies in the spent fuel pool. The ITS Bases (page 485 of 636) states that the applicable safety analysis is for a fuel handling accident outside containment.
                     -The STS (NUREG-1430) contains no LCO for Fuel Handling Exhaust - High Radiation Monitors.

10 CFR 50.36(d)(2)(i) states that "limiting conditions for operation are the lowest functional capability or performance levels of equipment required for safe operation of the facility." Issue.D]ate. 01/16/2008 Close Date [105/06/2008 http://www.excelservices.com/exceldbs/itstrackdavisbesse.nsf/l fddceal Od3bdbb585256e... 7/18/2008

NRC ITS Tracking Page 3 of 3 SFRCS logic can still be accomplished. For Davis-Besse, the SFRCS design is such that there can be logic channel inoperabilities that only affect one of the four Logic Functions. Thus, ITS 3.3.13 ACTIONS A and B are written such that ACTION B, which requires a unit shutdown, is only entered if both logic channels 1 and 2 are inoperable for the same Logic Function (i.e, the Logic Function cannot perform its safety function). If logic channel 1 is inoperable for reasons that affect only Logic Function a and logic channel 2 is inoperable for reasons that affect only Logic Function b, then Condition A would be entered for each Logic Function. Entry into Condition B is not required. This allowance is consistent with the CTS allowances. However, Davis-Besse has decided to take the more conservative actions required by the ISTS ACTION A. Specifically, Davis-Besse will change the ITS submittal to adopt the more conservative requirement of ISTS 3.3.13 ACTION A, modified to be consistent with plant-specific nomenclature. A draft markup regarding this change is attached. This change will be reflected in the supplement to this section of the ITS Conversion Amendment. NRC Response by Aron Lewin No further questions at this time. on 04/07/2008 ____________________________ Date Created: 01/10/2008 11:23 AM by Aron Lewin Last Modified: 04/07/2008 11:10 AM http://www.excelservices.com/exceldbs/itstrackdavisbesse.nsfl lfddceal Od3bdbb585256e... 7/18/2008

NRC ITS Tracking Page 2 of 3 understood how this situation could occur as Main Steam Pressure and Main Feedwater Differential Pressure logic seem to effect all ITS Functions).

                   -Condition A of the STS for LCO 3.3.13 (NUREG-1430), allows for an inoperable channel to be restored to operable status within 72 hours only when one or more channel A Functions are inoperable with all channel B Functions operable OR one or more channel B Functions inoperable with all channel A Functions operable. As a result one complete Channel must be fully operable for Condition A in the STS to apply.

10 CFR 50.36(d)(2)(i) states that "limiting conditions for operation are the lowest functional capability or performance levels of equipment required for safe operation of the facility. When a limiting condition for operation of a nuclear reactor is not met, the licensee shall shut down the reactor or follow any remedial action permitted by the technical specifications until the condition can be met." [IssueDate] [01/10/2008 Close D~ate]j 04/07/2008 Logged in User: Anonymous

'Responses Licensee Response by Bill           Supplemental information was provided to aid in understanding Bentley on 01/29/2008               the SFRCS design. However, ITS Bases Insert 1 (page 461 and 462 of Volume 8) appears to have sufficient information to address the question. When viewing UFSAR Figure 7.4-4, the specific operation showing how the SFRCS Actuation Channels 1 and 2 manipulate plant components can be seen. The SFRCS Overview and SFRCS System Description provided with question 200801101037 support the information contained in the UFSAR Figure and ITS Bases description. As described in the LCO Section of the ITS Bases (page 464 of Volume 8), both Actuation Channel 1 and Channel 2 shall be Operable. There are only 2 channels of automatic actuation logic per function. The discussion for Action A. 1 of the ITS Bases (page 466 of Volume 8) Lis appropriate given UFSAR Figure 7.4-4 and the rest of the information in ITS Bases Insert 1.

NRC Response by Aron Lewin Will request conference call with licensee via PM. on 01/29/2008 NRC Response by Aron Lewin During a 2/21/2008 conference call, the licensee stated that they on 02/25/2008 would provide a follow-up discussion on the NRC's concern regarding the potential that Condition A could allow for two partially inoperable channels based on the JFD4 discussion. Licensee Response by Bryan The ISTS only allows one of the two logic channels (A or B) to be Kays on 04/06/2008 inoperable. For example, itvdoes not allow a logic channel A problem for Logic Function a to exist concurrent with a logic channel B problem for Logic Function b. If this were to occur, the ISTS would require a unit shutdown per ACTION B. However, as described in the Bases for ACTION A (Page 466),.the 72 hour Completion Time is acceptable because the safety function of the http://www.excelservices.com/exceldbs/itstrackdavisbesse.nsf/lfddcea 1Od3bdbb585256e... 7/18/2008

NRC ITS Tracking Page I of 3 Return to View Menu Print Docuent RAI Screening Required: Yes Status: Closed This Document will be approved by: Carl Regulatory Basis must be included in Comments Schulten; Tim Kobetz; Gerald Waig section of this Form This document has been reviewed and Yes information in this question contains NO SUNSI sensitive material (the checkbox to the right must be selected before this question can be submitted) NRC ITS TRACKING NRC Reviewer ID11200801101123 Conference Call Requested? No Category][ BSI - Beyond Scope Issue ITS Section: TB POC: JFD Nu!mber: Page Number(s); ITS 3.3 Aron Lewin None Information ITS Number:. 0SI: DO.C.. Number: Bases JFD Number: 3.3.13 None None None NRC OSI#71 Given the background below, discuss why ITS Condition A would be an appropriate remedial action for an inoperable actuation channel, as permitted by 10 CFR 50.36(d)(2)(i).

Background:

                    -The CTS (page 365 of 636) has Action 16 for when a SFRCS Functional Unit of Table 3.3-11 (starting on page 362 of 636) is inoperable. Action 16 states "with the number of operable channels one less than the total number of channels, startup and/or power operation may proceed until performance of the next required channel functional test provided the inoperable section of the channel is placed in the tripped condition within 1 hour." As a result if Functional Units L.a and 1.c were inoperable (corresponding to an inoperable Actuation Channel 1 for the Main Steam Pressure logic), the CTS require
       .omment      placing Functions l.a and L.c in trip within 1 hour. This-would hypothetically result in SFRCS actuation and would therefore effect plant operations.. If it was the logic circuitry of Function L.a and 1.c that was inoperable, placing the functions in trip may actually have no effect, and as a result, may necessitate a LCO 3.0.3 shutdown.
                    -The ITS (page 456 of 636) has a Condition A, for when one'or more logic functions with one channel inoperable, that requires an inoperable channel be restored to operable status within 72 hours. As a result, if the Main Steam Pressure logic associated with Channel 1 is inoperable (CTS Functional Units L.a and 1.c inoperable; ITS Functions a thru d possibly inoperable), ITS Condition A allows 72 hours to restore to operable status. At the same time, ITS Condition A also allows for ITS Functions to be inoperable in Channel 2, as long as they are operable in. Channel 1 (although it is not completely http://www.excelservices.com/exceldbs/itstrack~davisbesse.nsf/lfddcealOd3bdbb585256e.'..       7/18/2008

NRC ITS Tracking Page 2 of 2 (2)(i), are being taken for an inoperable actuation channel (i.e. with regards to continued plant.operation in ITS Condition A and SFRCS actuation given a single failure). In order to better understand the SFRCS, the following information is needed:

                   -Does one actuation channel isolate both main steam headers?
                   *Does one actuation channel isolate both main feed headers?
                   -Does one actuation channel start both AFW pumps?
                   -Is an AFW "pump start" signal needed for automatic AFW pump isolation valve IWhich  manipulation,    and if so, how is this signal provided?

specific complimentary logic inputs and specific actuation channel inputs control the AFW pump isolation valves during various plant conditions (i.e. intact steam generators, rupture in steam generator A, and rupture in [ steam generator B)?. ssue Date 01/10/2008 Close Date [02/25/2008 Logged in User: Anonymous

'Responses Licensee Response by Bill              The response for question 200801101123 should also address this Bentley on 01/29/2008                 [question. Please clarify if any additional information is needed.

NRC Response by Aron Lewin This thread was opened as a means of tracking / conveying that the on 01/29/2008 issue associated with Thread 200801101037 also effects LCO 3.3.13. All discussions can be held on Thread 200801101037, and this thread (LCO 3.3.13) will be closed at the same time that Thread 200801101037 (LCO 3.3.11) is closed. No further questions on this thread at this time. NRC Response by Aron Lewin further questions at this time. on 02/25/2008 No Date Created: 01/10/2008 11:19 AM by Aron Lewin Last Modified: 02/25/2008 07:55 AM http://www.excelservices.com/exceldbs/itstrack davisbesse.nsf/lfddcea1Od3bdbb585256e... 7/18/2008

NRC ITS Tracking Page I of 2 Return to View Menu Print Docuen RAI Screening Required: Yes Status: Closed This Document will be approved by: Carl Regulatory Basis must be included in Comments Schulten; Tim Kobetz; Gerald Waig section of this Form This document has been reviewed and Yes information in this question contains NO SUNSI sensitive material (the checkbox to the right must be selected before this question can be submitted) NRC ITS TRACKING NRC Reviewer ID 200801101119 Conference Call Requested? No

        .Category          Other Technical Challenge ITS-Section:          TB POC:             JFD Nulmb er:       PageNumber(s):

ITS 3.3 Aron Lewin None Information ITS Nunmber-: 05S1: DOCNumber: Bases JFD Number" 3.3.13 None None None NRC OSI#70 Discuss the logic of the SFRCS in order to determine if appropriate actions, as permitted by 10 CFR 50.36(d)(2)(i), are being taken for an inoperable actuation channel.

Background:

                           -The CTS (page 365 of 636) has Action 16 for when a SFRCS Functional Unit of Table 3.3-11 (starting on page 362 of 636) is inoperable. Action 16 states "with the number of operable channels one less than the total number of channels, startup and/or power operation may proceed until performance of the next required channel functional test provided the inoperable section of the channel is placed in the tripped condition within 1 hour."
                           -The ITS (page 456 of 636) has a Condition A, for when one or more logic Comment functions with one channel inoperable, that requires an inoperable channel be restored to operable status within 72 hours.
                           -Condition A of the STS for LCO 3.3.13 (NUREG-1430), which is applicable when one or more channel A Functions are inoperable with all channel B Functions operable OR One or more channel B Functions inoperable with all channel A Functions operable, requires an inoperable channel be restored to operable status within 72 hours.

10 CFR 50.36(d)(2)(i) states that "limiting conditions for operation are the lowest functional capability or performance levels of equipment required for safe operation of the facility. When a limiting condition for operation of a nuclear reactor is not met, the licensee shall shut down the reactor or follow any remedial action permitted by the technical specifications until the condition can be met." The logic of the SFRCS is unclear and therefore it is difficult to determine if appropriate actions, as permitted by 10 CFR 50.36(d) http://www.excelservices.com/exceldbs/itstrackdavisbesse.nsfl1 fddceal Od3bdbb585256e... 7/18/2008

B&W-TABLE 2 (Continued) Notes:

1. Specifications listed in this table may be relocated contingent upon NRC staff approval of the location of and controls over relocated requirements.

2. This LCO may be removed from the STS. However, if the associated Surveillance Requirement(s) is necessary to meet the OPERABILITY requirements for a retained LCO, the Surveillance Requirement(s) should be relocated to the retained LCO.

3. The staff is pursuing alternative approaches which would allow relocation of some of these LCUs on a schedule consistent with the schedule for develop-merint of the new STS. The staff is also Initiating rulemaking to delete the requirement that RETS be included in Technical Specifications.

4. This LCO may be relocated. ot of Technical Specifications. However, the associated Surveillance Reqbirement(s) must be relocated toTechnical Specification Section 4.0, Surv'*illance Requirements.

5. This LCO may be relocated. However, Pa, La, Ld, and Lt must be either retained in TS or in the Bases of the appropriate Containment LCO.

6. Special Test Exceptions may be included with corresponding LCOs.

I B&W-TABLE 2 (Continued) LCO 3.7.11.1 Fire Suppression Water System 3.7.11.2 Spray and/or Sprinkler Systems 3.7.11.3 CO System 3.7.11.4 HaTon System 3.7.11.5 Fire Hose Stations 3.7.11.6 Yard Fire Hydrants and Hydrant Hose Houses 3.7.12 Fire Barrier Penetrations 3.7.13 Area Temperature Monitoring 3.9 REFUELING OPERATIONS 3.9.5 Communications 3.9.6 Fuel Handling Bridge 3.9.7 Crane Travel ;pent Fuel Storage Pool Building 3.10 SPECIAL TEST EXCEPTJONS 3.10.1 Shutdown Margin (Note 6) 3.10.2 Group Height Insertion Limits and Power Distribution Limits (Note 6) 3.10.3 Physics Tests (Note 6) 3.10.4 Reactor Coolant Loops (Note 6) 3.11 RADIOACTIVE EFFLUENTS (Note 3) 3.11.1.1 Concentration 3.11.1.2 Dose 3.11.1.3 Liquid Radwaste Treatment System 3.11.1.4 Liquid Holdup Tanks 3.11.2.1 Dose 3.11.2.2 Dose - Noble Gases 3.11.2.3 Dose - Iodine - 131, Tritium and Radionuclides in Particulate Form 3.11.2.4 Gaseous Radwaste Treatment Systems 3.11.2.5 Explosive Gas Mixture 3.11.2.6 Gas StorageTanks 3.11.3 Solid Radioactive Waste 3.11.4 Total Dose 3.12 RADIOACTIVE ENVIRONMENIAL MONITORING (Note 3) 3.12.1 Monitoring Program 3.12.2 Land Use Census 3.12.3 Interlaboratory Comparison Program A-5

TABLE 2 (Note 1) BABCOCK & WILCOX STANDARD TECHNICAL SPECIFICATION LCOs WHICH MAY BE RELOCATED LCO 3.1 REACTIVITY CONTROL SYSTEMS 3.1.2.1 Flow Paths - Shutdown 3.1.2.2 Flow' Paths - Operating 3.1.2.3 Makeup Pump - Shutdown 3.1.2.4 Makeup Pump - Operating 3.1.2.5 Decay Heat Removal Pump - Shutdown 3.1.2.6 Boric Acid Pumps - Shutdown 3.1.2.7 Boric Acid Pumps - Operating 3.1.2.8 Borated Wateto Surce - Shutdown 3.1.2.9 Borated Water Sburce - Operating 3.1.3.3 Position Indicatiof Channels - Operating (Note'2) 3.1.3.4 Position Indication-Channels - Shutdown (Note 2) 3.1.3.5 Rod Drop Time (Note 2) 3.1.3.8 Rod Program 3.3 INSTRUMENTATION 3.3.3.2 Incore Detectors 3.3.3.3 Seismic Instrnuentation 3.3.3.4 Meteorological Instrumentation 3.3.3.7 Chlorine Detection System 3.3.3.8 Fire Detection 3.3.3.9 Radioactive Liquid Effluent Monitor (Note 3) 3.3.3.10 Radioactive Gaseous Effluent Monitor (Note 3) 3.3.4 Turbine Overspeed Protection 3.4 REACTOR COOLANT SYSTEM 3.4.2 Safety Valves - Shutdovn 3.4.6 Steam Generators Tube Surveillance (Note 4) 3.4.8 Chemistry 3.4.10.2 Pressurizer Temperatures 3.4.11 Structural Integrity ASME Code (Note 4) 3.4.12 RCS Vents 3.6 CONTAINMENT SYSTEMS 3.6.1.2 Containnment Leakage (Note 5) 3.6.1.7 Containment'Structural Integrity (Note 2) 3.7 PLANT SYSTEMS 3.7.2 Steam Generator Pressure/Temperature Limits 3.7.9 Snubbers 3.7.10 Sealed Source Contamination LA-

I B&W-TABLE I (Continued) LCO CRITERIA 3.8 ELECTRICAL POWER SYSTEMS 3.8.1.1 A.C. Sources - Operating .3 3.8.1.2 A.C. Sources - Shutdown Policy Statement (OHR) 3.8.2.1 A.C. Distribution - Operating 3.8.2.2 A.C. Distribution - Shutdown 3 (DHR) 3.8.2.3 D.C. Distribution - Operating Policy Statement 3.8.2.4 D.C. Distribution - Shutdown (DHR) 3.9 REFUELING OPERATIONS 3.9.1 Boron Concentration 2 3.9.2 Instrumentation 3 3.9.3 Decay Time

• 2 3.9.4 Containment Building Penetration 3 3.9.8.1 Residual Heat RemovAl and CoolantiCirculation -

All Water Levels - Policy Statement (DHR) 3.9.8.2 Residual Heat Removal and Coolant Circulation - Low Water Levels Policy Statement (DoR) 3.9.9 Containment Purge and Exhaust Isolation System 3 3.9.10 Water Level - Reactor Vessel 2 3.9.11 Water Level - Storage Pool 2 3.9. 12 Storage Pool Air Cleanup System .2 Notes:

1. Required for Modes 3 through 5. May be relocated for Modes 1 and 2.

2. The.LCO for this system should be retained in STS. The Policy Statement criteria should not be used as the basis for relocating specific trip functions, channels, or instruments within these LCOs.

3. The staff Is pursuing alternative approaches which would allow relocation of some of these LCOs on a schedule consistent with the schedule for development of the new STS. The staff Is also initiating rulemaking to delete the requirement that RETS be included in Technical Specifications.

4. Because fires (either inside or outside the control room) can be a significar.t contributor to the core melt frequency and because the uncertainties with fire initiation frequency can be significant, the staff believes that this LCO should be retrained in the STS at this time. The staff will consider relocation of Remote Shutdown Instrumentation on a plant-specific basis.

5. This LCO will be considered for relocation to a licensee-controlled document on a plant-specific basis.

A-3

B&W-TABLE I (Continued) CRITERIA 3.4.7.2 Operational Leakage 2 3.4A9 Specific Activity 2 3.4.10.1 Reactor Cool ant System Pressure/Temperature Limits 2 3.4.10.3 Overpressure Protection System 3.5 EMERGENCY CORE COOLING SYSTEM (ECCS) 3.5.1 Core Flooding Tanks 219 3 3.5.2 ECCS Subsystems - Tavg ) 1305)*F 3 3.5.3 ECCS Subsystems - Tavg <(305)°F 3 3.5.4 Borated Water Storage Tank 2 &3 3.6 CONTAINMENT SYSTEMS 3.6.1.1 Containment Integrity .3 3.6.103 Containment Air Locks 3 3.6.1.5 Internal Pressure 2 3.6.1.6 Air Temperature 3 3.6.1.8 Containment Ventilation System 3 3.6.2.1 Containment Spray System 3.6.2.2 Spray Additive System 3 3.6.2.3 Containment Cooling System 3 3.6.3 Iodine Cleanup System 3 3.6.4 Containment Isolation Valves 3 3.6.5.1 Hydrogen Analyzers 3 3.6.5.2 Electric Hydrogen Recombiners (Note 5) 3 3.6.6 Penetration Room Exhaust Air Cleanup System 3.7 PLANT SYSTEMS 3.7.1.1 Safety Valves 3 3.7.1.2 Auxiliary Feedwater System 3 3.7.1.3 Condensate Storage Tank 2&3 3.7.1.4 Activity 2 3.7.1.5 Main Steam Line Isolation Valves 3 3.7.3 Component Cooling Water System 3 3.7.4 Service Water System 3 3.7.5 Ultimate Heat Sink 3 3.7.6 .Flood Protection (optional) 3 3.7.7 Control Room Emergency Air Cleanup System 33 3.7.8 ECCS Pump Room Exhaust Air Cleanup System (optional) A-2

APPENDIX A TABLE I LCOs TO BE RETAINED IN BABCOCK & WILCOX STANDARD TECHNICAL SPECIFICATIONS LCO CRITERIA 3.1 REACTIVITY CONTROL SYSTEM 3.1.1.1 Shutdown Margin (Note 1) 2 3.1.1.2 Moderator Temperature Coefficient 2 3.1.1.3 Minimum Temperature for Criticality 2 3.1.3.1 Group Height - Safety and Regulating Rod Groups 2 3.1.3.2 Group Height - Axial Power Shaping Rod Group 2 3.1.3.6 Safety Rod Insertion Limit 2&3 3.1.3.7 Regulating Rod Insertion Limits 2 3.1.3.9 Xenon Reactivity 2 3.2 POWER DISTRIBUTION LIMITS 3.2.1 Axial Power Imbalance 2 3.2.2 Nuclear Heat Flux Hot Channel Factor 2 3.2.3 Nuclear Enthalpy Rise Hot Channel Factor 2 3.2.4 Quadrant Power Tilt 2 3.2.5 DNB Parameters 2 3.3 INSTRUMENTATION 3.3.1 Reactor Protection System Instrumentation (Note 2) 3 3.3.2 Engineered Safety Feature Actuation System Instrumentation (Note 2) 3 3.3.3.1 Radiation Monitoring Instrumentation (Notes 2 & 3) 3 3.3.3.5 Remote Shutdown Instrumentation (Notes 2 & 4) Risk 3.3.3.6 Accident Monitoring Instrumentation 3 2.4 REACTOR COOLANT SYSTEM 3.4.1.1 Startup and Power Operation 3 3.4.1.2 Hot Standby 3 3.4.1.3 Hot Shutdown 3 3.4.1.4 Cold Shutdown Policy Statement (DHR) 3.4.3 Safety Valve - Operating 32&3 3.4.4 Pressurizer 3.4.5 Relief Valve 3 3.4.6 Steam Generators - Water Level 2 3.4.7.1 Leakage Detection System 1 A-i

APPENDIX A RESULTS OF THE NRC STAFF REVIEW BABCOCK & KXLCOX .ONERS GROUP'S SUBMITTAL RETENTION AND RELOCATION 1F SPECIFIC TECHNICAL SPECIFICATIONS

tollowing tables, application of the criteria contained in the Commission's Interim Policy Statement resulted in a significant reduction in the number of LCOs to be included in the new STS. The development of the new STS based on the staff's conclusions will result In more efficient use of NRC and industry resources. Safety Improvements are expected through more operator-oriented Technical Specifications, improved Technical Specification Bases, a reduction in action statement-Induced plant transients, and a reduction in testing at power. BABCOCK GENERAL

                  &                                   COMBUSTION            ELECTRIC LCOs            WILCOX           WESTINGHOUSE          ENGINEERING          BWR4/BWR6 Total Number          i37                 165                  159                  124/144 Retained         75                  92                   87                   81/86 Relocated        62                  73                   72                   43/58 Percent Relocated        45%                 44%                  45%                 35%/40%

We' are confident that the staff's conclusions will. provide an adequate basis for the Owners Groups to proceed with the development of complete new STS in accordance with the Commission's Interim Policy Statemefet.

plant specific implementation of the new STS, the staff plans to review the location of, and controls over, relocated requirements. In as much as practi-cable, the Owners Groups should propose standard locations for, and controls over, relocated requirements. For each LCO listedin Table 1, the criterion (criteria) that required that the LCO be retained in Technical Specifications is identified. If an LCO was retained in Technical Specifications solely on the basis of risk, "Risk" appears In the criteria column. Where an Owners Group determined that an LCO had to stay in lechnical Specificatins (because of either a particular criterion or risk) and the Staff agreed that the LCO should be retained in Technical Specif-Ications, the staff did not, in general. verify the Owners Group's basis for retention. However, In several instances the Owners Groups cited risk consider-ations alone as the basis for retaining Technical Specifications and the staff disagreed with the Owners Groups. In these instances, the staff's basis for retention appears in the criteria column of Table 1. Any LCO not specifically identified in Table 1 or Table 2 (e.g., an LCO unique to an STS not addressed in the Owners Groups submittals such as the BWR5 STS) should be retained in the STS until the Owners Group proposes and the staff makes a specific determination that it can be relocated to a licensee-controlled document. Notwithstanding the results of this review, the staff will give further consideration for relocation of additional LCOs as the staff and industry proceed with the development of the new SIS.

4. CONCLUSION The results of the effort of the Owners Groups and of the NRC staff to apply the Policy Statement selection criteria to the existing STS are an important step toward ensuring that the new STS contain only those requirements that are consistent with 10 CFR 50.36 and have a sound safety basis. As shown in the

of this application of the guidance in the Commission Policy Statement, the staff agrees with the Owners Groups' conclusions except in two areas. First, the staff finds that the Remote Shutdown Instrumentation meets the Policy State-ment criteria for Inclusion in Technical Specifications based on risk; and second, the staff is unable to confirm the Owners Groups' conclusion that Category 1 Post-Accident Monitoring Instrumentation is not of prime importance in limiting risk. Recent PRAs have shown the risk significance of operator re-covery actions which would require a knowledge of Category 1 variables. Furthermore, recent severe accident studies have shown significant potential for risk reduction from accident management. The Owners Groups'-should develop further risk-based justification tn support of relocating any or all Category 1 variables from the Standard Technieal Specifications. As stated in the Commission's Interim Policy Statement, licensees should also use plant-specific PRAs or risk surveys as they prepare license amendments to adopt the revised STS to their plant. Where PRAs or surveys are available, licensees should use them to strengthen the Bases as well as to screen those Technical Specifications to be relocated. Where such plant-specific risk surveys are not available, licensees should use the literature available on risk insights and PRAs. Licensees need not complete a plant-specific PRA before they can adopt the new STS. The NRC staff will also use risk insights and PRAs in evaluating the plant-specific submittals.

3. RESULTS OF THE STAFF'S REVIEW Appendices A through D present the detailed results of the staff's review of the Babcock and Wilcox, Westinghouse, Combustion Engineering, and General Electric application of the selection criteria to the existing STS. Each Appendix con-sists of two tables. Table 1 identifies those LCUs that must be retained in the new STS. Table 2 lists those LCOs that may be wholly or partially relocated to licensee-controlled documents (or be reformatted as a surveillance requirement for another LCO). Where the staff placed specific conditions on relocation of particular LCOs the staff has so noted In the Tables. As a part of the

provide reasonable assurance that the absolute numerical limits of the regulations will be satisfied. On a plant-specific basis, systems and equipment thatare identified in the NRC staff SER and assumed by the staff to function are considered part of the licensing basis for the plant and are captured by Criterion 3 (e.g., radiation monitoring instrumentation that initiates an isolation function, penetration room exhaust air cleanup system). (7) DBA and transients, as.used in Criteria 2 and 3, should be interpreted to include any design-basis event described In the FSAR (i.e., not just those events described in Chapters f and 15 of the FSAR).. For example, there may be requirements for some plants which should be retained in Technical Specifications because of the risks associated with some site-specific characteristic (e.g.; although not normally required, a Technical Specifi-cation on the chlorine detection system might be appropriate where a sig-nificant chlorine hazard exists in the site vicinity; similarly, a Tech-nical Specification on flood protection might be appropriate where a plant is particularly'vulnerable to flooding and is designed with special flood protection features). Criteria 2 and 3 should not be interpreted to in-clude purely generic design requirements applicable to all plants (e.g., the requirements of General Design Criterion 19 in Appendix A to 10 CFR Part 50 for control room design). The NRC staff has used the Commission's Interim Policy Statement and the conclusions described above to-define the appropriate content of the new STS. The staff plans to factor these conclusions Into the Final Policy Statement on Technical Specification Improvements that will be proposed to the Commission. The staff reviewed the methodology and results provided by each Owners Group to verify that none of the requirements proposed for relocation contains constraints of prime importance in limiting the likelihood or severity of accident sequences that are cowmonly found to dominate risk. For the purpose

P.02

                                        -40 accidents or transients or to improve reliability of the mitigation function (e.g., rod withdrawal block which is backup to the average power range monitor high flux trip in the startup mode, safety valves which are backup to low temperature over pressure relief valves during cold- shutdown).

(5) Post-Accident Monitoring Instrumentation that satisfies the definition of Type A variables in Regulatory Guide 1.97, "Instrumentation for Water-Cooled fluclear Power Plants to Assess Plant and Environs Conditions During and Following an Accident," meets Criterion 3 and should be retained in Technical Specifications. Type A variables provide primary information (i.e., information that't4 essential for the direct accomplishment of the specified manual actions (Incbading long-term recovery actions) for which no automatic control is provided and that are required for safety systems to accomplish their safety functions for DBAs or transients). Type A variables do not include-those variables associated with contingency actions that may also be identified in written procedures to compensate for failures of primary equipment. Because only Type A variables meet Criterion 3, the STS should contain a narrative statement that indicates that Individual plant Technical Specifications should contain a list of Post-Accident Instrumentation that includes Type A variables. Other Post-Accident Instrumentation (i.e., non-Type A Category 1) Is discussed on page 6. (6) The NRC's design basis for licensing a plant is the plant's Final Safety Analysis Report (FSAR) as qualified by the analysis performed by the staff and documented in the staff's safety evaluation report (SER). Because the staff's review and resulting SER are based on the acceptance criteria in the NRC's Standard Review Plan (NUREG-0800, SRP), the dose limits used in licensing a particular plant may be 'some small fraction" of those specified in the Commission's regulations in Title 10 of the Code of Federal Regulations Part 100 (10 CFR 100). Accordingly, the SRP limits should be used to define the equipnent In the primary success path for mitigating accidents and transients when developing the new STS. These types of conservatisms are required to compensate for uncertainties in analysis techniques and

1 to detect precursors to an actual breech of the reactor coolant pressure boundary or instrumentation to identify the source of actual leakage (e.g., loose parts monitor, seismic instrumentation, valve position indicators). (2) The "initial conditions" captured under Criterion 2 should not be limited to only "process variables" assumed in safety analyses. They should also include certain active design features (e.g., high pressure/low pressure system valves and Interlocks) and operating restrictions (e.g., pressure-temperature operating limit curves), needed to preclude unanalyzed accidents. In this context, *actiye design features" include only design features under the control of operTtions personnel (i.e.. licensed operators and personnel who perform control.functions at the direction of licensed opera-tors). This position is consistent with the conclusions reached by the Staff during the trial application of the criteria to the Wolf Creek and Limerick Technical Specifications. (3) The "initial conditions" of design-basis accidents (DBA) and transients, as used in Criterion 2, should not be limited to only those directl. "monitored and controllee" from the control room. Initial conditions should also in-clude other features/characteristics that are specifically assumed in DBA and transient analyses even if they can not be directly observed in the control room. For example, initial conditions (e.g., moderator temperature coefficient and hot channel factors) that are periodically monitored by other than licensed operators (e.g., core engineers, Instrumentation and control technicians) to provide licensed operators with the information required to take those actions necessary to assure that the plant is being operated within the bounds of design and analysis assumptions, meet Criterion 2 and should be retained in Technical Specifications. Initial conditions do not, however, include things that are purely design requirements. (4) The phrase "primary success path," used in Criterion 3, should be interpreted to include only the primary equipment (including redundant trains/components) not include t tSjatp iAdtj~tS ild tr~avsentS. Priary success path does

                      .So n~vru 10or                      %0AiT PTIW en j-ze

I (2) Letter dated November 12, 1987, R. A. Newton, Westinghouse Owners Group, to NRC Document Control Desk,

Subject:

*Westinghouse Owners Group MERITS Program Phase II,Task 5, Criteria Application Topical Report."

(3) Letter dated December 11, 1987, J. K. Gasper, Combustion Engineering Owners Group, to Dr. T. E. Hurley, NRC

Subject:

"CEN-355, CE Owners Group Restructured Standard Technical Specifications - Volume 1 (Criteria Application)."

(4) Letter dated November 12, 1987, R. F. Janecek, BWR Owners Group, to R. E. Starostecki, NRC,

Subject:

"BWR Owners Group Technical Specification screening Criteria Applicbtion and Risk Assessment.'

These submittals provide the rationale for why each STS requirement (e.g. Limiting Condition for Operation) should be retained in the new STS or why it can be relocated to a licensee-controlled document. They also describe how each Owners Group used risk insights in determining the appropriate content of the new STS.

2. STAFF REVIEW The NRC staff focused its review on those requirements identified by the Owners Groups as candidates for relocation. The staff evaluated each of these requirements to determine whether it agreed with the Owners Groups' conclusions.

During the NRC Staff's review, several issues were raised concerning the proper interpretation or application of the criteria in the Commission's Interim Policy Statement. The NRC Staff has considered these issues and concluded the following: (1) Criterion 1 should be interpreted to include only Instrumentation used to detect actual leaks and not more broadly to include instrumentation used

1. INTRODUCTION On February 6, 1987. the Commission issued its Interim Policy Statement on Technical Specification Improvements (52 FR 3788). The Policy Statement encourages the industry to develop new Standard Technircal Specifications (STS) to be used as guides for licensees in preparing improved Technical Specifications (TS) for their facilities. The Interim Policy Statement contains criteria (including a discussion of each) for determining which regulatory requirements and operating restrictions should be retained in the new STS and ultimately in plant TS. It also identifies four additional systems that are to be retained on the basis of operating experience and probabilistic risk assessments (PRA).

Finally, the Policy Statement- indicates that risk evaluations are an appropriate tool for defining requirerents'that should be retained in the STS/TS where including such requirements is consistent with the purpose of TS (as stated in the Policy Statement). Requirements that are not retained in the new STS would generally not be retained in individual plant M5. Current TS requirements not retained In the STS will be relocated to other licensee-controlled documents. One of the first steps in the program to implement the Commission's Interim Policy Statement is to determine which Limiting Conditions for Operation (LCOs) contained in the existing STS should be retained in'the new STS. An early decision on this issue will facilitate efforts to make the other improvements (described in the Policy Statement) to the text and Bases of those requirements that must be retained in the new STS. -Each Nuclear Steam Supply System (HSSS) vendor Owners Group has submitted a report to the NRC for review that identifies which SYS LCOs the group believes should be retained in the new STS and which can be relocated to other licensee-controlled documents. These four NSSS vendor submittals are as follows: (1) Letter dated October 15, 1987, R. L. Gill, B&W Owners Group, to Dr. T. E. Murley, NRC,

Subject:

"B&W Owners Group Technical Specification Committee Application of Selection Criteria to the B&W Standard Technical Specifications."
                                                      **  TOTAL  PAGE.01    **

I NRC STAFF REVIEW OF NUCLEAR STEAM SUPPLY SYSTEM VENDOR OWNERS GROUPS' APPLICATION OF THE COMMISSION'S IITJfRIM POLICY STATEMENT CRITERIA TO STANDARD TECHNICAL SPECIFICATIONS

0. Mr. W. S. Wilgus cc w/encl: Mr. Robert Gill B&W Owners Group P. 0. Box 33189

  *422 South Church Street       28242       it Charlotte, North Carolina Mr. R. E. Bradley BWR Owners Group c/o Georgia Power Nuclear Operations Department 14th Floor 333 Piedmont Avenue Atlanta, Georgia 30308 Hr. Edward Lozito Westinghouse Owners Group c/o Virginia Power

p. 0. Box 26666 Richmond, Virginia 23261 Mr. Joseph B. George Westinghouse Owners Group Texas Utilities 400 North Olive Dallas, Texas 75201 Mr. Stewart Webster CE Owners Group 1000 Prospect Hill Road Winstor. Connecticut 06095-0500 Mr. R. A. Bernier CE Owners Group c/o Arizona Nuclear Power Project P. 0. Box 52034 H.S. 7048 Phoenix, Arizona 85072 Mr. Thomas Tipton NUMARC 1776 Eye Street. N.W.

Suite 300 Washington, D. C. 20006-2496 I.

S -, -;

                                                                               ... d  ~

Mr. W. S. Wilgus I We are confident that the enclosed staff report provides an adequate basis for the Owners Groups to proceed with the development of complete new STS in accordance 14 with the Commission's Interim Policy Statement. We will continue to interact with the NUMARC Technical Specificationkeep Working Group and each of the individual vendor Owners Groups as r*'ded to this important program moving forward. A, Sincerely, Thc-.bs ..  !. Thomas E. Murley, Director Office of Nuclear Reactor Regulation

• t,

Enclosure:

As stated cc see next page 7-DISTRIBUTION: uTSU 7r SAVarga DOEA R/F DCrutchfield

  -OTSB Kembers           JGPartlow PDR                   JPStohr Central Files         JWRoe Murley/Sniezek        FJMiraglia TTM&rtin              BABoger CERossi               GCLainas EJButcher             FSchroeder AThadani              JRichardson LShao (W.S.WILGUS/LTR/SPLIT REPORT)

CONCURRENCE:

                     *(see previous concurrence)
     *TSB:DOEA:t*R   *TSB:NRR     *C:ISB:NRR         *D:DOEA:NRR *D:DEST:NRR *D:DEST:NRR K~esat:psc      DCFtscher EJButcher             CERossi     AThadani     LShao 4/18/88         04/19/88      04/20/88          04/22/88     04126/88    04/26/88 0     *D:DREP:NRROADT:NRR JRStohr      TIMartin     rEM4rley
                                  %(//88 J1 04/28/88     05/018

                                                          "EXT-8 -04897 UNITED STATES NUCLEAR REGULATORY COMMISSION WASHINGTON. 0. C. 20S55 me, IL soRIUm NPD UCICNSING MAY 9 1998 Hr. Walter S. Wilgus, Chairman                                     MAY 10 19R8 The B&W Owners Group Suite 525                                                              oao1wo.m Mo 1700 Rockville Pike                                                 301.230-2100          -A Rockville, Maryland 20852

Dear Mr. Wilgus:

V.

                                                                                     ~, 3ff.

This letter is in response to your report identifyIng which Standard Technical Specification (STS) requirements you believe should be retained in the new STS and which can be relocated to other licensee-controlled documents. The enclosure to this letter documents the NRC staff's conclusions as to which current STS requirements must be retained in the new STS. These conclusions are based on the Commission'-slnterim Policy Statement on Technical Specifica-tion Improvements and on severel Interpretations of how to apply the screening 9 criteria contained in that Policy.Statement. The NRC staff considered comments made by industry at a March 29, 19U8 meeting between NRC, HUMARC, and each Oners Group in making these Interpretations. Based on our review, we have concluded that a significant reduction can be made in the number of Limiting Conditions for Operation (and associated Surveillance Requirements) that must be included in the STS. Our goal Is to assure that the new STS contain only requirements that are consistent with 10 CFR 50.36 and have a sound safety basis. The development of the new STS based on the staff's conclusions will result in more efficient use of NRC and industry resources. Safety improvements are' expected through more operator-oriented Technical Specifications, improved Technical Specification Bases. a reduction in action statement-induced plant transients, and a reduction in testing at power. As you are aware, the NRC staff and industry also have underway a parallel I program of specific line item improvements to both the scope and substance of the existing Technical Specifications. The need for many of these types of improvements was identified in the report (HUREG-1024) of a major staff task group established in 1983 to study surveillance requirements in Technical Specifications and develop alternative approaches to provide better assurance that surveillance testing does not adversely impact safety. The NRC will continue to actively identify and pursue the development of specific line item improvements to Technical Specifications and will make these improvements immediately available to licensees without waiting for the new STS. We encour-age each of the Owners Groups to continue to work with the XRC staff on these types of parallel improvements to existing Technical Specifications.

NRC ITS Tracking Page 3 of 3 the basis for relocating specific trip functions, channels, or instruments within these LCOs. In the B&W report, in the summary disposition matrix, the following is noted: Page 4 of 15 RPS Manual Trip Criteria for Inclusion - No Page 5 of 15 Engineered Safety Feature Actuation Under the notes for Bases for inclusion/exclusion, it is stated that manual initiation is considered non-Tech Spec While SFRCS Instrumentation is not addressed in the B&W report, the same logic applies to this Manual Function as to the RPS and EFSAS Manual Functions. NRC Response by Aron Lewin Consider changing the following statement: "The SFRCS manual on 04/21/2008 initiation Functions do not satisfy any criteria of 10 CFR 50.36(c) (2)(ii). However, it is retained for the overall redundancy and diversity of the SFRCS as required by the NRC." with the following: "The SFRCS manual initiation Functions are retained for the overall redundancy and diversity of the SFRCS as required by the NRC." Licensee Response by Jerry Davis-Besse will make the requested change to the Bases. A draft Jones on 04/23/2008 markup regarding this change is attached. This change will be reflected in the supplement to this section of the ITS Conversion Amendment. NRC Response by Aron Lewin No further questions at this time. on 04/24/2008 IN usin tti ie Date Created: 01/10/2008 11:11 AM by Aron Lewin Last Modified: 04/24/2008 12:14 PM http://www.excelservices.com/exceldbs/itstrackdavisbesse.nsf/1 fddcealOd3bdbb585256e... 7/18/2008

NRC ITS Tracking ýPage 2 of 3 Criterion 3. Thus, Davis-Besse cannot validate that the manual SFRCS trip function meets any of the criteria. However, it is retained in the ITS for the overall redundancy and diversity of the SFRCS -as required by the NRC. Furthermore, during a phone conversation with the NRC concerning a similar issue, one NRC reviewer stated that if we did not identify these instruments as meeting at least one of the Criteria, we could then take them out of the ITS. However, the statement that they do not meet any of the criteria is a Bases statement, which simply states why the manual SFRCS trip function instrumentation is being maintained in the ITS. The statement by itself (i.e., that no criteria for inclusion are met) does not justify relocating the manual SFRCS trip function instrumentation. In order for Davis-Besse to justify their relocation, the NRC would have to review and approve a Technical Specification change. As stated above, Davis-Besse is not proposing relocating the manual SFRCS trip function instrumentation requirements. Therefore, since this is a Bases change only, and it has no affect on the Technical Specification requirements (the statement is only stating why the requirement is in the ITS), the change is not a beyond scope change, as defined in NRC Generic Letter 96-04. The Generic Letter states that beyond scope issues are those that differ from existing Technical Specifications and the improved Standard Technical Specifications. Since this specific change is not a Technical Specification change and does not differ from the Davis-Besse CTS, it is not a beyond scope issue. NRC Response by Aron Lewin 1ITSB has all information needed to make final determination. on 02/27/2008 1 Licensee Response by Bryan The following additional information is provided to supplement Kays on 03/16/2008 our response of 2/27/2008. NRC letter dated May 9, 1998, from T. E. Murley to W. S. Wilgus (letter provided in attachment), provided, in part, the results of the NRC Staff Review of Letter dated October 15, 1987, from R. L. Gill, B&W Owners Group, to Dr. T. E. Murley, NRC,

Subject:

B&W Owners Group Technical Specification Committee Application of Selection Criteria to the B&W Standard Technical Specifications. On pages 5 and 6 of the enclosure to the letter (the NRC Staff Review document), it is stated "For the purpose of this application of the guidance in the Commission Policy Statement, the staff agrees with the Owners Groups' conclusions (emphasis added) except in two areas. First, the staff finds the Remote Shutdown Instrumentation meets the Policy Statement criteria for inclusion in Technical Specifications based on risk; and second, the staff is unable to. confirm the Owners Groups' conclusion that Category 1 Post-Accident Monitoring Instrumentation is not of prime importance in limiting risk." Appendix A provides the specific results for the B&W report. Table 1 lists LCOs to be retained. Under instrumentation, Reactor Protection System and Engineered Safety Feature Actuation System Instrumentation are listed, with a Note 2. Note 2 states, in part, "The Policy Statement criteria should not be used as http://www.excelservices.com/exceldbs/itstrack davisbesse.nsf/lfddcea1Od3bdbb585256e... 7/18/2008

NRC ITS Tracking Page I of 3 jI .V1Returnto View Menu] [ ..Print Documient RAI Screening Required: Yes Status: Closed This Document will be approved by: Carl Regulatory Basis must be included in Comments Schulten; Tim Kobetz; Gerald Waig section of this Form This document has been reviewed and Yes information in this question contains NO SUNSI sensitive material (the checkbox to the right must be selected before this question can be submitted) NRC ITS TRACKING NRU Roviowur ID 200801101111 Conference Call Requested? No Catego[ BSI - Beyond Scope Issue ITS Section:; TB..P.O.C.:. JFD Number: Page..Number(s): ITS 3.3 Aron Lewin None Information ITS..Number: OS1: DQOC.Number: Bases JFD Number: 3.3.12 None None None OSI#69 Discuss why the Manual SFRCS trip function is not considered to meet any Criterion of 10 CFR 50.36(d)(2)(ii).

Background:

                    -The Bases for CTS 3/4.3.1 and 3/4.3.2 do not specifically discuss the Manual SFRCS trip function with regards to Applicable Safety Analysis.
                    -The Bases for ITS LCO 3.3.12 (page 434 of 636) state, "The SFRCS manual Comment     initiation Functions do not satisfy any criteria of 10 CFR 50.36(c)(2)(ii).

However, it is retained for the overall redundancy and diversity of the RPS as required by the NRC".

                    -The Bases for STS LCO 3.3.12 (NUREG-1430) states that "the EFIC manual initiation functions satisfy Criterion 3 of 10 CFR 50.36(c)(2)(ii).

10 CFR 50.36(d)(2)(ii) discusses how a technical specification limiting condition for operation of a nuclear reactor must be established for an item meeting one of the four criteria listed. Issue Date 101/10/2008 Clo.se D.ate 04/24/2008 Logged in User: Anonymous

'Responses Licensee Response by Bryan               As stated in the ITS Applicable Safety Analyses Bases (Volume 8, Kays on 02/27/2008                       Page 434) the manual SFRCS trip function does not satisfy any Criteria of 10 CFR 50.36(d)(2)(ii). Since the manual SFRCS trip function is not credited in any safety analysis, it cannot meet http://www.excelservices.com/exceldbs/itstrackdavisbesse.nsf/1 fddceal 0d3bdbb585256e...               7/18/2008

TABLE 3.3-11 (Continued) STEAM AND FEEDWATER RUPTURE CONTROL SYSTEM INSTRUMENTATION MINIMUM TOTAL NO. CHANNELS CHANNELS FUNCTIONAL UNIT OF CHANNELS TO TRIP OPERABLE ACTION

3. Steam Generator Level - Low Instrument Channels (continued)

Od. LSLL SP9B6 Steam Generator 1 Channel 2 LSLL SP9B7 Steam Generator I Channel 2

4. Loss of RCP Channels 2 1 2 13#

5. Manual Initiation (Push buttons)

a. Initiate AFPT #1 114

b. Initiate AFPT #2 1 1 1 14 C. Initiate AFPT #1 and Isolate SG #1 1 14

d. Initiate AFPT #2 and Isolate SG #2 1 1 1 14 ds p

0

TABLE 3.3-11 (Continued) STEAM AND FEEDWATER RUPTURE CONTROL SYSTEM INSTRUMENTATION MINIMUM TOTAL NO. CHANNELS CHANNELS FUNCTIONAL UNIT OF CHANNELS TO TRIP OPERABLE ACTION 0 C:

2. Feedwater/Steam Generator Differential Pressure - High .

Instrument Channels 2 1 2 13#

a. PDS 2685A Feedwater/Steam Generator 2 Channel 2

a. PDS 2685B Feedwater/Steam Generator 2 Channel 2 IJ,*

b. PDS PDS 2685C Feedwater/Steam Generator 2 Channel 1 2685D Feedwater/Steam Generator 2 Channel I

c. PDS 2686A Feedwater/Steam Generator 1 Channel I PDS 2686B Feedwater/Steam Generator 1 Channel 1

d. PDS 2686C Feedwater/Steam Generator I Channel 2 PDS 2686D Feedwater/Steam Generator 1 Channel 2

3. Steam Generator Level - Low Instrument Channels 2 1 2 13#

a. LSLL SP9B8 Steam Generator I Channel 1 tLSLL SP9B9 Steam Generator I Channel I 0

a. LSLL SP9A6 Steam Generator 2 Channel I LSLL SP9A7 Steam Generator 2 Channel 1

a. LSLL SP9A8 Steam Generator 2 Channel 2 LSLL SP9A9 Steam Generator 2 Channel 2

2 r 0 ii( 1 7 0 -0 .; J ATTACHMENT TO LICENSE AMENDMENT NO. 124 FACILITY OPERATING LICENSE NO. NPF-3 DOCKET NO. 50-346 Replace the following pages of the Appendix "A" Technical Specifications with the attached pages. The revised pages are identified by amendment number and contain vertical lines indicating the area of change. The corresponding overleaf pages are also provided to maintain document completeness. Remove Insert 3/4 3-26 3/4 3-26

U 0 0 1 7 0 0

• on May 3, 1988 (53 FR 15757). No request for hearing or petition for leave to intervene was filed following this notice.

For further details with respect to this action see (1) the application for amendment dated January 30, 1988 (2) Amendment No. 124 to License No. NPF-3, (3) the Commission's letter dated October 5, 1988 and (4) the Environmental Assessment dated September 23, 1988 (53 FR 38128). All of these items are available for public inspection at the Commission's Public Document Room, 2120 L Street, N.W., Washington, D.C., and at the University of Toledo Library, Documents Department, 2801 Barncroft Avenue, Toledo, Ohio 43606. A copy of items (2), (3) and (4) may be obtained upon request addressed to the U. S. Nuclear Regulatory Commission, Washington, D. C. 20555, Attention: Director, Division of Reactor Projects - III, IV, V and Special Projects. Dated at Rockville, Maryland this 5th day of October 1988. FOR THE NUCLEAR REGULATORY COMMISSION

                             \Joseph G. Glitter, Project Manager Project Directorate 111-3 Division of Reactor Projects - Ill, IV, V and Special Projects

L 0 0 1 7 0 0 di 7590-01 U. S. NUCLEAR REGULATORY COMMISSION TOLEDO EDISON COMPANY, ET AL. DOCKET NO. 50-346 NOTICE OF ISSUANCE OF AMENDMENT TO FACILITY OPERATING LICENSE The U. S. Nuclear Regulatory Commission (the Commission) has issued Amendment No. 124 to Facility Operating License No. NPF-3, issued to The Toledo Edison Company and The Cleveland Electric Illuminating Company (the licensee), which revised the Technical Specifications for operation of the Davis-Besse Nuclear Power Station, Unit No. I (the facility) located in Ottawa County, Ohio. The amendment was effective as of the date of its issuance. The amendment revised the TS's relating to the number of manual initiation pushbuttons required. Specifically, Technical Specification 3.3.2.2, Table 3.3-11, "Steam and Feedwater Rupture Control System" (SFRCS), is revised to reflect a design modification that simplifies manual initiation of SFRCS. The application for the amendment complies with the standards and requirements of the Atomic Energy Act of 1954, as amended (the Act), and the Commission's rules and regulations. The Commission has made appropriate findings as required by the Act and the Commission's rdles and regulations in 10 CFR Chapter I, which are set forth in the license amendment. Notice of Consideration of Issuance of Amendment and Opportunity for Hearing in connection'with this action was published in the FEDERAL REGISTER

0i) 1 7 0)C-(a) Technical Specifications The Technical Specifications contained in Appendices A and B, as revised through Amendment No. 124, are hereby incorporated in the license. The Toledo Edison Company shall operate the facility in accordance with the Technical Specifications.

3. This license amendment is effective as of its date of issuance and shall be implemented not later than November 19, 1988.

FOR THE NUCLEAR REGULATORY COMMISSION

                                   ?   John N. Hannon, Director Project Directorate 111-3 Division of Reactor Projects - III, IV, V, & Special Projects

Attachment:

Changes to the Technical Specifications Date of Issuance: October 5, 1988

0, i 0 1 7 00. .

UNITED STATES NUCLEAR REGULATORY COMMISSION WASHINGTON, D. C. 20555 TOLEDO EDISON COMPANY AND THE CLEVELAND ELECTRIC ILLUMINATING COMPANY DOCKET NO. 50-346 DAVIS-BESSE NUCLEAR POWER STATION, UNIT NO..1 AMENDMENT TO FACILITY OPERATING LICENSE Amendment No. 124 License No. NPF-3

1. The Nuclear Regulatory Commission (the Commission) has found that:

A. The application for amendment by the Toledo Edison Company and The Cleveland Electric Illuminating Company (the licensees) dated January 30, 1988 complies with the standards and requirements of the Atomic Energy Act of 1954, as amended (the Act), and the Commission's rules and regulations set forth in 10 CFR Chapter I; B. The facility will operate in conformity with the application, the provisions of. the Act, and the rules and regulations of the Commission; C. There is reasonable assurance (I) that the activities 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 amendment is in accordance with 10 CFR Part 51 of the Commission's regulations and all applicable requirements have been satisfied.

2. Accordingly, the license is amended by changes to the Technical Specifications as indicated in the attachment to this license amendment, and paragraph 2.C.(2) of Facility Operating License No. NPF-3 is hereby amended to read as follows:

01 3 U0 1 7 00 5.6 Mr. Donald C. Shelton October 5, 1988 With this arrangement, any one channel will cause a trip. All channels are required to be operable as before. This modification addresses a concern related to operator error which occurred during the June 9, 1985, Davis-Besse loss-of-feedwater event and also which had been identified as a result of efforts to improve the design of the control room to minimize human error. The concern is recognized in Toledo Edison Com-pany Course of Action Report Section I. C. 5, Control Room Improvement Program and NUREG-1177, Davis-Besse Restart Safety Evaluation Report, Sections 3.3.3 and 3.3.4 and Appendix D. IEEE Std. 279, Section 4.2 requires all safety systems to provide the capabil-ity to initiate manually a system level action as part of the design. Based on the staff's review of the proposed changes to the TS's and the proposed reduction in the number of manual push buttons within SFRCS, the staff concludes that the change conforms to the requirements of IEEE Std. 279 and Regulatory Guide 1.62. The staff, therefore, finds the proposed changes acceptable. Pursuant to 10 CFR 51.21, 51.32, and 51.35, an environmental assessment and finding of no significant has been prepared and published in the Federal Register (53 FR 38128 September 29, 1988). Accordingly, based upon the environmental assessment, the Commission has determined that the issuance of this amendment will not have a significant effect on the quality of the human environment. The staff has concluded, based on the considerations discussed above, that: (1) there is reasonable assurance that the health and safety of the public will not be endangered by operation in the proposed manner, and (2) such activities will be conducted in compliance with the Commission's regulations and the issuance of this amendment will not be inimical to the common defense and security or to the health and safety of the public. A copy of the notice of issuance is enclosed. The notice has been forwarded to the Office of the Federal Register for publication. Sincerely, Albert W. De Agazio, Sr. Project Manager Project Directorate 111-3 Division of Reactor Projects -III, IV, V and Special Projects

Enclosures:

1. Amendment No.124to License No. NPF-3

2. Notice cc w/enclosures: See next page

(Iri 1 7 0 0 4: UNITED STATES EXT-88 -1.0024 NUCLEAR REGULATORY COMMISSION WASHINGTON, D. C. 20555 October 5, 1988 R ECEIVFD Docket No. 50-346 Serial No. DB-88-048 OC I0: 19BBB Mr. Donald C. Shelton 'roAw~ WI$O0N Vice President, Nuclear Toledo Edison Company Edison Plaza - Stop 712 300 Madison Avenue Toledo, Ohio 43652

SUBJECT:

AMENDMENT NO. 124 TO FACILITY OPERATING LICENSE NO. NPF-3: STEAM AND FEEDWATER RUPTURE CONTROL SYSTEM MANUAL ACTUATION PUSH BUTTONS (TAC 66729) The Commission has issued the enclosed Amendment No. 124 to Facility Operating License No. NPF-3 for the Davis-Besse Nuclear Power Station, Unit No. 1. This amendment consists of changes to the Appendix A Technical Specifications (TS's) in response to your application dated January 30, 1988 (No. 1462). This amendment revises the TS's relating to the number of manual initia-tion pushbuttons required. Specifically, Technical Specification 3.3.2.2, Table 3.3-11, "Steam and Feedwater Rupture Control System" (SFRCS), is revised to reflect a design modification that simplifies manual initiation of SFRCS. Currently, SFRCS manual initiation is through the following pushbuttons: Steam pressure low 4: push buttons (2 channels required for trip) Steam generator level low 2 push buttons (I channel required for trip) Feedwater pressure differential high 2 push buttons (I channel required for trip) Loss of Reactor coolant pumps 2 push buttons (I channel required for trip) With the current arrangement, all channels are required to be operable. This amendment allows a change in the manual trip arrangement such that manual initiation will be through the following push buttons: Initiate AFPT #1 1 push button Initiate AFPT #2 I push button Initiate AFPT #1 and Isolate SG #1 I push button Initiate AFPT #2 and Isolate SG #2 1 push button

NRC ITS Tracking Page 2 of 2 Licensee Response by Bryan License Amendment 124 (dated October 5, 1988) revised the Kays on 03/03/2008 Davis-Besse Technical Specifications related to SFRCS Manual actuation push buttons to reflect a design modification that simplified manual initiation of SFRCS. Previously, up to 4 manual pushbuttons were required by the CTS based on the affected function (4 for the steam pressure low function and 2 for the other three functions), and '2 of the required pushbuttons necessary for the manual logic to actuate. License Amendment 124 modified the design such that the pushbuttons are now based on actuating/isolating individual subsystems (auxiliary feedwater pump turbines 1 and 2 and steam generators 1 and 2), and the number of channels for each actuation has been changed to only one channel (i.e., a one out of one logic). The specific logic description is provided in the ITS Bases (Page 435, Insert 1). In the NRC letter issuing License Amendment 124 (Page 2, third paragraph), the NRC states that "the staff concludes that the change conforms to the requirements of IEEE Std. 279 and Regulatory Guide 1.6.2." A copy of the NRC Safety Evaluation for the License Amendment is attached. NRC Response by Aron Lewin No further questions at this time. on 03/18/2008 Date Created: 01/10/2008 11:03 AM by Aron Lewin Last Modified: 03/18/2008 04:07 PM http://www.excelservices.com/exceldbs/itstrack davisbesse.nsf/lfddcea1Od3bdbb585256e... 7/18/2008

NRC ITS Tracking Page I of 2 ]* Return to View Menu aPritocLnt RAI Screening Required: Yes Status: Closed This Document will be approved by: Carl Regulatory Basis must be included in Comments Schulten; Tim Kobetz; Gerald Waig section of this Form This document has been reviewed and Yes information in this question contains NO SUNSI sensitive material (the checkbox to the right must, be selected before this question can be submitted) NRC ITS TRACKING NRC Reviewer I1200801101103 Conference Call Requested? No Cte ESI - Emergent Staff Issue ITS Section: TB POC: JIM Number: Page-Number(s).:. ITS 3.3 Aron Lewin None Information ITS.Number: OS: DOC Number: Bases JFD Number:. 3.3.12 None None None NRC OSI#68 Discuss how the availability of only one manual initiation channel per function satisfies IEEE-279-1971, and therefore 10 CFR 50.55a(h)(2).

Background:

                     -Table 3.3-11 of the CTS (page 424 of 636) states that there is only one channel of manual initiation (CTS Function 5), and that one channel is required to be operable.
                     -The ITS (page 430 of 636) states that one channel of manual initiation is required to be operable. The ITS Bases (page 434 of 636) states that the Comment SFRCS manual initiation circuitry satisfies the manual initiation and single-failure criterion requirements of.
                     -The STS Bases for LCO 3.3.11 (NUREG-1430) are based on a different design that utilizes redundant manual initiation switches.

10 CFR 50.55a(h)(2) states "for nuclear power plants with construction permits issued after January 1, 1971, but before May 13, 1999, protection systems must meet the requirements stated in either IEEE Std. 279, "Criteria for Protection Systems for Nuclear Power Generating Stations," or in IEEE Std. 603-1991, "Criteria for Safety Systems for Nuclear Power Generating Stations," and the correction sheet dated January 30, 1995." Issue Date 01/10/2008 I.Clo0s~e.D~atel103/18/2008. Logged in User: Anonymous

'Responses http://www.excelservices.com/exceldbs/itstrackdavisbesse.nsf/1 fddceal Od3bdbb585256e... 7/18/2008

NRC ITS Tracking Page 2 of 2 require the Main Steam Line Pressure - Low Function to be OPERABLE in MODE 3 with main steam line pressure greater than or equal to 750 psig on a reactor shutdown and with main steam line pressure greater than 800 psig during a reactor startup. A draft markup regarding this change is attached. This change will be reflected in the supplement to this section of the ITS Conversion Amendment. In addition, the Davis-Besse response to 200801101045 included a draft markup that changed similar sections in the ISTS Markup and ISTS Markup. Therefore, for clarity, the affected changes from 200801101045 are also shown in these draft markup pages. Licensee Response by Jerry During a recent phone conversation discussing Ihe draft markup Jones on 06/25/2008 provided to the NRC in the Davis-Besse response dated 6/23/08, the NRC requested that the word "startup" in ITS 3.3.11-1 Note (a) could be confused with the ITS Table 1.1-1 Title for MODE 2. Therefore, Davis-Besse proposes to change the word to "heatup." Use of the word heatup conveys the same meaning in this application. A draft markup regarding this change is attached and supersedes the draft markup previously provided. This change will be reflected in the supplement to this section of the ITS Conversion Amendment. NRC Response by Aron Lewin o further questions at this time. on 06/25/2008 Date Created: 06/17/2008 07:25 AM by Aron Lewin Last Modified: 06/25/2008 02:24 PM http://www.excelservices.com/exceldbs/itstrackdavisbesse.nsf/1 fddcealOd3bdbb585256e...; 7/18/2008

NRC ITS Tracking Page I of 2 Return to View Menu Print Documenti FLI Screening Required: Yes Status: Closed This Document will be approved by: Carl Regulatory Basis must be included in Comments Schulten section of this Form This document has been reviewed and Yes information in this question contains NO SUNSI sensitive material (the checkbox to the right must be selected before this question can be submitted) NRC ITS TRACKING NRC Rgvit-wpr ID 200806170725 Conference Call Requested? No Category Other Technical Challenge ITS Section: TB..POC: T JFD NNumb-er. Page. Nufber(s): ITS 3.3 Aron Lewin None infom-ation fTS.Number: OS.1: DOC!Number: Bases JFD..Number: 3.3.11 None None None On 6/13/08 the licensee stated:

                   "During our implementation efforts, we discovered another problem with the ITS Conversion Amendment.

It deals with ITS 3.3.11 SFRCS. See Volume 8, page 365, DOC LA05. The CTS has a note that states the bypass shall be automatically removed when the steam pressure exceeds 800 psig. Com.ent I believe Davis-Besse incorrectly relocated this note to the Bases. This note allowance was specifically added by license amendment no. 157, and it is important to station operation that we have this allowance in Tech Specs during plant heatups. Without the allowance in ITS, we'll be forced to declare SFRCS inoperable at 750 psig steam pressure if the blocks have not automatically reset. We will need a question thread started on this item." This thread is posted to facilitate the above discussion. Issue Date [06/17/2008 Close Date[ 06/25/2008 Logged in User: Anonymous

'Responses Licensee Response by Jerry           Davis-Besse has added back into the ITS the current requirement Jones on 06/23/2008                  that the bypass be removed during a startup prior to exceeding 800 psig. This is consistent with the requirements of the NRC Safety Evaluation for Amendment 157, dated June 4, 1991. The ITS will http://www.excelservices.com/exceldbs/itstrackdavisbesse.nsf/I fddcea1 Od3bdbb585256e...          7/18/2008

NRC ITS Tracking Page 3 of 3 level setpoint shift will be verified. This is the appropriate location for this requirement since the level control system is part of the AFW System, not part of the SFAS Instrumentation. Licensee Response by Bill The following additional response is provided to address the Bentley on 04/10/2008 original requested information. UFSAR Section 6.3.1 describes the design bases of the ECCS Systems. It includes a discussion of the importance of AFW in mitigating certain size and location specific small break loss of coolant accidents (i.e. AFW is credited in the LOCA analysis for SBLOCA). NRC Response by Aron Lewin Discuss in detail what is physically done during the CTS SR for on 04/10/2008 the Channel Check, Channel Functional Test, and Channel Calibration of the Auxiliary Feed Pump Turbine Steam Generator Level Control Sytem (page 98 of 461, Volume 12 of the submittal). Provide copies of the procedures for technical branch review. The information provided will be used in determining if the SR are required per 10 CFR 50.36. Licensee Response by Bill CTS surveillance 4.7.1.2.1 .d was identified for relocation to the Bentley on 04/17/2008 TRM per DOC LA06 in ITS 3.7.5. The surveillance states: "The Auxiliary Feed Pump Turbine Steam Generator Level Control System shall be demonstrated OPERABLE by performance of a CHANNEL CHECK at least once per 12 hours, a CHANNEL FUNCTIONAL TEST at least once per 31 days, and a CHANNEL CALIBRATION at least once each REFUELING INTERVAL." Therefore, the surveillance procedures ensure that the level control system performs its specified safety function. This information is provided instead of copies of the various surveillance procedures, as requested by the reviewer during a phone call on 4/16/08. Licensee Response by Jerry Davis-Besse has decided to maintain the CTS 4.7.1.2.1 .d Jones on 07/01/2008 requirements in the Technical Specifications. A draft markup regarding this change is attached and supersedes the draft response provided in the 4/6/08 response. This change will be reflected in the supplement to this section of the ITS ConversionAmendment. NRC Response by Aron Lewin No further questions at this time. on 07/01/2008 Date Created: 01/10/2008 10:49 AM by Aron Lewin Last Modified: 07/01/2008 10:38 AM http://www.excelservices.com/exceldbs/itstrack davisbesse.nsf/1 fddceal Od3bdbb585256e.... 7/18/2008

NRC ITS Tracking Page 2 of 3 to approximately 50%, providing a higher SG level for establishing and maintaining natural circulation conditions when the forced reactor coolant flow is lost. No setpoint is specified since the status indication as used by EFIC is binary in nature." Criterion 3 of 10 CFR 50.36(d)(2)(ii) states a TS must be established for "a structure, system, or component that is part of the primary success path and which functions or actuates to mitigate a design basis accident or transient that either assumes the failure of or presents a challenge to the integrity of a fission product barrier." Issue Date [01/10/2008 Close Date[ 07/01/2008 Logged in User: Anonymous

'Responses Licensee Response by Bryan            The "auto-essential" steam generator level controls are part of the Kays on 02/15/2008                    Emergency Feedwater System and are discussed in ITS 3.7.5 (Volume 12, Pages 98 and 109), as part of the overall system Specification. They are not discussed in the SFRCS Instrumentation Specification, ITS 3.3.11, because the controls are not part of the SFRCS. In addition, note that the dual setpoint discussion is associated with SFAS, not with SFRCS. As stated on Page 199 of the ITS submittal (Volume 8), the detailed list of components actuated by SFAS is identified in UFSAR Figures 7.3-1 through 7.3-8. SG auto level control is listed on Figure 7.3-4.

NRC Response by Aron Lewin ill request conference call with licensee via PM. on 02/20/2008[ NRC Response by Aron Lewin iDiscuss which specific ITS surveillance requirement would require on 02/25/2008 testing of the auto-essential steam generator level control. Licensee Response by Bill During the 2/21/08 phone call, the reviewer stated they had all the Bentley on 02/27/2008 information they needed. Then, a new response was posted by the reviewer on 2/25/08. The CTS surveillance requirement is 4.7.1.2.1.d. (page 98, Volume 12). As shown in Volume 12, the surveillance for the level controls have been relocated to the TRM. NRC Response by Aron Lewin During 4/2/08 conference call, licensee stated they would address on 04/03/2008 the auto-essential steam generator controls with regards to the accident analysis and TS Criteria. Licensee Response by Bryan The "auto-essential" steam generator level controls are part of the Kays on 04/06/2008 Emergency Feedwater as part of the overall system Specification. The ISTS does not specifically require any Surveillances related to the steam generator level controls; they are under utility control. However, the NRC reviewers requested that the automatic level setpoint shift from the low setpoint (the setpoint under a normal SFRCS actuation condition) to the high setpoint (the setpoint under an SFAS actuation condition) be included in the Davis-Besse ITS. Therefore, Davis-Besse will add into ITS SR 3.7.5.4 (the SR that verifies AFW valves actuate to their correct position on an actual or simulated actuation signal) the requirement that the http://www.excelservices.com/exceldbs/itstrack davisbesse.nsf/lfddcea1Od3bdbb585256e... 7/18/2008

NRC ITS Tracking Page I of 3 Return to View Menu[Q Print Document 1RA Screening Required: Yes Status: Closed This Document will be approved by: Carl Regulatory Basis must be included in Comments Schulten; Tim Kobetz; Gerald Waig section of this Form This document has been reviewed and Yes information in this question contains NO SUNSI sensitive material (the checkbox to the right must be selected before this question can be submitted) NRC ITS TRACKING NRC Reviewer ID 200801101049 Conference Call Requested? No Category ESI - Emergent Staff Issue ITS. Section: T-B.P.OC:. JFD. Nu!.mber-:ý Page..NUMb..er(s).:; ITS 3.3 Aron Lewin None Information ITS Number: OS1:; DOC NuA-mber: Bases J.FD ._Numbe-r: 3.3.11 None None None NRC OSI#67 Based on the USAR discussion, discuss if the "auto-essential" steam generator level control functions or actuates to mitigate a design basis accident or transient that either assumes the failure of or presents a challenge to the integrity of a fission product barrier, and would therefore be required in TS per Criterion 3 of 10 CFR 50.36(d)(2)(ii).

Background:

                  -The SFRCS CTS (page 361 thru 368 of 636) do not discuss the "auto-essential" steam generator level control. The USAR (page 1949 of 4076 in the USAR) states that "the "auto-essential" steam generator level control includes a dual setpoint. Following automatic actuation of auxiliary feedwater by the Steam and Feedwater Rupture Control System (SFRCS), steam generators Comment level will be controlled to greater than 35 inches (indicated on the Startup Range) above the lower tube sheet if no SFAS Level 2 actuation occurs. For accident conditions where both auxiliary feedwater and SFAS Level 2 are automatically actuated (indicative of loss of coolant accident conditions), the auto-essential level control will regulate water addition of the steam generator to achieve and maintain an actual level above the lower tube sheet of at least 120 inches."
                  -The SFRCS ITS (page 378 thru 418 of 636) do not discuss the "auto-essential" steam generator level control.
                  -The STS (LCO 3.3.11 in NUREG-1430) is based on a different design that utilizes some aspects of a steam generator level control as well. The STS LCO 3.3.11 Bases discusses the steam generator level control and why it is not found in the TS. The STS LCO 3.3.11 Bases states "upon the-loss of four RCPs, EFW will be automatically initiated with the EFW control level automatically raised http://www.excelservices.com/exceldbs/itstrackdavisbesse.nsf/1 fddcea 1Od3bdbb585256e...        7/18/2008

NRC ITS Tracking Page 3 of 3 Date Created: 01/10/2008 10:47 AM by Aron Lewin Last Modified: 02/25/2008 07:33 AM http://www.excelservices.com/exceldbs/itstrackdavisbesse.nsf/1 fddceal Od3bdbb585256e... 7/18/20081

NRC ITS Tracking Page 2 of 3

'Responses Licensee Response by Bryan        The intent of the ITS SR 3.3.11.5 Note (Volume 8, Page 381) is to Kays on 02/15/2008                establish the number of channels that will be tested on a STAGGERED TEST BASIS. CTS 4.3.2.2.3 (Page 361) requires testing of the actuation channels, and requires one channel per Function to be tested each Refueling Interval. ITS SR 3.3.11.5 requires the same testing on a STAGGERED TEST BASIS.

However, as described in Discussion of Change (DOC) A04 (Pages 369 and 370), to be consistent with the ITS format, each of the current channels for Functions 1, 2, and 3 actually consists of 4 inputs and for Function 4 consists of 2 inputs. Thus, the ITS now identifies a total of 8 channels or 4 channels, as applicable, for each original CTS channel. This is also described in the ITS Bases for each Function. The ITS 3.3.11.5 Note was added to make sure that the total number of channels required to be tested was completely understood and was maintained consistent with the CTS requirements. That is, the CTS essentially required all 8 inputs for one of the channels for a given Function to be tested each Refueling Interval. This Note has been previously included for similar reasons in other Response Time Surveillance Requirements. For example, ISTS NUREG-1433, SR 3.3.1.15 has a similar Note for the main steam isolation valve position switches. Therefore, Davis-Besse believes that the addition of this Note is acceptable and does not change the original intent of the Surveillance; However, during the development of the response for this question, Davis-Besse noted that the ITS 3.3.11.5 Note is not discussed in the Bases. Therefore, the Bases will be modified to clearly identify what the Note means. The proposed wording will be based on the wording in NUREG- 1433, SR 3.3.1.15 Bases, since the Davis-Besse Note is similar to the NUREG-1433 Note. A draft markup regarding this change is attached. This change will be reflected in the supplement to this section of the ITS Conversion Amendment. Furthermore, Davis Besse does not believe that this question is a beyond scope issue since the testing requirements have not changed between the CTS and the ITS (i.e., the ITS is maintaining current licensing basis). NRC Response by Aron Lewin Will request conference call with licensee via PM. on 02/19/2008 Licensee Response by Jerry During a recent phone conversation discussing the above question, Jones on 02/21/2008 the NRC asked Davis-Besse to clarify a statement in our previous response. The statement: "That is, the CTS essentially required all 8 inputs for one of the channels for a given Function to be tested each Refueling Interval" should be changed to "That is, the CTS essentially requires all the various inputs for one of the two actuation logic channels to be tested each Refueling Interval (i.e., 24 months), such that all the required channels are tested in two Refueling Intervals (i.e., 48 months)." NRC Response by Aron Lewin No further questions at this time. on 02/25/2008 http://www.excelservices.com/exceldbs/itstrack-davisbesse.nsf/ l fddcea 1Od3bdbb585256e... 7/18/2008

NRC ITS Tracking Page I of 3 Retrn o View Menuil Print Document RAI Screening Required: Yes Status: Closed, This Document will be approved by: Carl Regulatory Basis must be included in Comments Schulten; Tim Kobetz; Gerald Waig section of this Form This document has been reviewed and Yes information in this question contains NO SUNSI sensitive material (the checkbox to the right must be selected before this question can be submitted) NRC ITS TRACKING NRC Reviewer ID]1200801101047 Conference Call Requested? No Categor 11 BSI Beyond Scope Issue ITS Section: TB POC:. JFD Number: Page Number(s): ITS 3.3 Aron Lewin None Information ITS Number: OS!. DOC Number.: Bases-JFD Number:. 3.3.11 None None None NRC OSI#66 Discuss if the intent of the Note in ITS SR 3.3.11.5 is that two instrument channels associated with the same actuation channel are tested every 24 months, in order to ensure that 10 CFR 50.36(d)(3) is continued to be met.

Background:

                    -CTS SR 4.3.2.2.3 (page 361 of 636) states "the steam and feedwater rupture control system response time of each SFRCS function shall be demonstrated to be within the limit at least once per refueling interval. Each test shall include at least one {actuation} channel per function such that all {actuation} channels are tested at least once every N times the refueling interval where N is the total Comment number of redundant {actuation} channels in a specific SFRCS function as shown in the "Total No. of Channels" Column of Table 3.3-11."
                    -ITS SR 3.3.11.5 (response time testing) (page 380 of 636) has a Note that states ""N" equals 2 {instrumentation} channels for the purpose of determining the staggered test basis frequency."
                    -STS SR 3.3.11.4 (response time testing) for LCO 3.3.11 (NUREG-1430), does not contain the ITS Note.

10 CFR 50.36(d)(3) states that "surveillance requirements are requirements relating to test, calibration, or inspection to assure that the necessary quality of systems and components is maintained, that facility operation will be within safety limits, and that the limiting conditions for operation will be met." Issue D I01/10/2008 0ate Close 02/25/208 Logged in User: Anonymous http://www.excelservices.com/exceldbs/itstrack-davisbesse.nsf/l fddcea 1Od3bdbb585256e. 7/18/2008

NRC ITS Tracking Page 3 of 3 believe that this question is a beyond scope issue, since in all cases, the operational bypasses were to remain tested by the CHANNEL CALIBRATIONS and CHANNEL FUNCTIONAL ___TESTS of the affected trip functions. NRC Response by Aron Lewin No further questions at this time. on 02/19/2008 e Date Created: 01/10/2008 10:45 AM by Aron Lewin Last Modified: 02/19/2008 10:01 AM http://www.excelservices.comlexceldbs/itstrackdavisbesse.nsf! 1fddceal Od3bdbb585256e... 7/18/2008

NRC ITS Tracking Page 2 of 3 Licensee Response by Bryan Davis-Besse deleted the operational bypasses (Volume 8, Page Kays on 02/15/2008 361) by Discussion of Change (DOC) L01 (Page 375 and 376) to be consistent with the ISTS. The ISTS, NUREG-1430, did not include the specific operation bypass Surveillances.. Upon further review, it appears that in lieu of deleting the operational bypasses with an L type DOC, the intent of the ISTS was to move the' requirements to the Bases as part of the CHANNEL CALIBRATION and CHANNEL FUNCTIONAL TEST of the affected automatic trip functions. That is, an LA type DOC should be used to delete the operational bypass Surveillances from the Current Technical Specifications. Therefore, the Davis-Besse submittal has been changed to show the operational bypass relocated to the 3.3.11 Bases in accordance with DOC LA07. Additionally, the CTS markup (Page 361) has been changed to show the deletion of DOC LO1 and the addition of DOC LA07. However, it was also noted that the operational bypass requirements are not located in the most appropriate location. Currently, the ISTS Bases includes their Surveillance discussion at the beginning of the Surveillance Requirements section of the Bases (Page 412). The most consistent location for this discussion should be in the individual Surveillance Requirement discussion, i.e., in the discussion for the CHANNEL FUNCTIONAL TEST and CHANNEL CALIBRATION Surveillances (SR 3.3.11.2 and SR 3.3.11.3). Therefore, the Bases for these two SRs (Page 414) have been changed to reflect the operational bypasses being relocated to the Bases. Also, Davis-Besse noted during the development of this response that the title/description of the main steam line pressure low Function in the ITS and Bases Markups was sometimes not changed from the ISTS words of SG low pressure. As shown in the CTS (Page 362) and described in the ITS Bases (Page 390), these instruments are called main steam line pressure instruments and are located on the main steam lines. Thus, minor editorial corrections have been made for consistency. This affects ITS Markup Pages 379 and 383, ITS JFD 4 (Page 385) and ITS Bases Pages 404, 408, and 412. Furthermore, during the development of the response for this NRC question, it was determined that the SFAS Technical Specification, ITS 3.3.5, has similar operational bypasses. These bypasses were deleted by ITS 3.3.5 DOC L01 (Pages 187 and 188). For consistency, these operational bypasses will also be relocated to the Bases of ITS 3.3.5. Therefore, ITS 3.3.5 DOC L01 (Pages 187 and 188) has been deleted and ITS 3.3.5 DOC LA05 (Page 375) has been added. Additionally, the CTS markup (Page 173) has been changed to show the deletion of DOC LO1 and the addition of DOC LA05. Furthermore, the Bases for the applicable ITS 3.3.5 SRs (Page 219 and 222) have been changed to reflect the addition of the operational bypasses, similar to the discussion for ITS 3.3.11 above. A draft markup regarding this change is attached. These changes will be reflected in the supplement to this section of the ITS Conversion Amendment. Furthermore, Davis Besse does not http://www.excelservices.com/exceldbs/itstrackdavisbesse.nsf/1 fddcea 1Od3bdbb585256e..., 7/18/2008

NRC ITS Tracking Page I of 3 Rtrto View MenuIl Print Document RAI Screening Required: Yes Status: Closed This Document will be approved by: Carl Regulatory Basis must be included in Comments Schulten; Tim Kobetz; Gerald Waig section of this Form This document has been reviewed and Yes information in this question contains NO SUNSI sensitive material (the checkbox to the right must be selected before this question can be submitted) NRC ITS TRACKING NRC Reviewer ID 200801101045 Conference Call Requested? No Category BSI - Beyond Scope Issue ITS. Section.;. TB POC: JFD N11-mber.: PageNumber(s): ITS 3.3 Aron Lewin None Information [.TSNumber:. 0S1:ý DOC.Number: Bases .JFD.Number: 3.3.11 None None None NRC OSI#65 Discuss how deleting the TS requirement for bypass SRs would still assure that the necessary quality of systems and components is maintained, that facility operation will be within safety limits, and that the limiting conditions for operation will be met in accordance with 10 CFR 50.36(d)(3).

Background:

                            -CTS SR 4.3.2.2.2 (page 361 of 636) states "the logic for the shutdown bypasses shall be demonstrated operable during the at power channel functional test of channels affected by bypass operation. The shutdown bypass function shall be Comment demonstrated operable at least once per refueling interval during channel
                           -calibration Co         testing of each channel affected by bypass operation."
                            -The ITS (page 412 of 636) deletes the TS requirement for bypass testing.
                            -The Bases for the STS for LCO 3.3.11 (NUREG-1430) states that the operational bypasses associated with each instrumentation channel are also subject to SRs to ensure operability of the instrumentation channel.

10 CFR 50.36(d)(3) states that TS will contain "surveillance requirements {which} are requirements relating to test, calibration, or inspection to assure that the necessary quality of systems and components is maintained, that facility operation will be within safety limits, and that the limiting conditions for operation will be met." Issue Date 1 01/10/2008 Close Date ]02/19/2008 Logged in User: Anonymous .'Responses http://www.excelservices.com/exceldbs/itstrackdavisbesse.nsf/1 fddcea 1Od3bdbb585256e... 7/18/2008

NRC ITS Tracking Page 2 of 2 10 CFR 50.36(d)(1)(ii)(A) states that "limiting safety system settings for nuclear reactors are settings for automatic protective devices related to those variables having significant safety functions. Where a limiting safety system setting is specified for a variable on which a safety limit has been placed, the setting must be so chosen that automatic protective action will correct the abnormal situation before a safety limit is exceeded." Issue Date 101/10/2008 lose Date [03/11/2008 Logged in User: Anonymous

'Responses Licensee Response by Bryan            Method 1 and Method 2 of Reference 3 (ISA 67.04-Part 11-1994)

Kays on 01/24/2008 and Reference 4 (ISA 67.04.02-2000) are NRC approved methods for calculating Allowable Values and trip setpoints. The STS Bases for LCO 3.3.11 includes a bracketed requirement for the applicant to provide the unit specific setpoint methodology (Volume 8, Pages 394 and 395). The two above referenced documents are the Davis-Besse setpoint methodology. The proposed words in the Davis-Besse ITS Bases (Pages 394 and 395) are more explicit, in that, in lieu of referencing a unit specific setpoint methodology (i.e., ISA 67.04-Part 11-1994 and ISA 67.04.02-2000), it is specifically stated that the Allowable Values and trip setpoints are established using Method 1 or Method 2 of the two referenced documents. As these methods are acceptable and meet NRC requirements, maintaining the specific Methods in the ITS Bases is desired. However, if the NRC desires, the specific methods can be removed and the Bases could only state the two _documents. NRC Response by Aron Lewin Issue is similiar to issues'being resolved by the EICB technical on 01/28/2008 branch for LCO 3.3.1 (Thread#200711160956 /NRC OSI#23) and LCO 3.3.5 (Thread#200711161110 / NRC OSI#46). The TAC number for the work is MD7470. This issue for LCO 3.3.11 will alsobe resolved by TAC MD7470, and it is anticipated that all further work associated with this topic will be charged to TAC MD7470. This thread is being maintained open for tracking purposes until MD7470 is resolved and closed. No further __questions anticipated at this time. NRC Response by Aron Lewin New further questions at this time. on 03/11/20081 Date Created: 01/10/2008 10:44 AM by Aron Lewin Last Modified: 03/11/2008 01:59 PM http://www.excelservices.com/exceldbs/itstrack davisbesse.nsf/1 fddcealOd3bdbb585256e... 7/18/2008

NRC ITS Tracking Page I of 4 Return to View Menu.Q Print Document] RAiI Screening Required: Yes Status: Closed This Document will be approved by: Carl Regulatory Basis must be included in Comments Schulten; Gerald Waig section of this Form This document has been-reviewed and Yes information in this question contains NO SUNSI sensitive material (the checkbox to the right must be selected before this question can be submitted) NRC ITS TRACKING NRC Reviewer ID 1200801231234 Conference Call Requested? No Catego.y BSI - Beyond Scope Issue ITS Section: TB.POC:. JFD Number: Page .Number(s);. ITS 3.3 Aron Lewin None Information ITS Number.: OS1: - D.OC Number: Bases JFD Number: 3.3.18 None None None NRC OSI#90 Discuss how the ITS ensure that control circuits' and transfer switches are operable, in order to ensure that a prompt hot shutdown of the reactor could occur in accordance with 10 CFR 50, Appendix A, GDC 19.

Background:

                     -The CTS LCO 3.3.5.2.(page 592 of 636) states "the control circuits and transfer switches required for a serious control room or cable spreading room fire shall be operable." CTS SR 4.3.5.2 (page 592 of 636) states "at least once per refueling interval, verify each control circuit and transfer switch required for a serious control room or cable spreading room fire is capable of performing the intended function." The USAR (page 1421 of 4076 in the USAR) states that in order to meet 10 CFR 50, Appendix A, GDC 19, Comment "equipment at appropriate locations outside the control room is provided (1)
        ..    ...... with a design capability for prompt hot shutdown of the reactor, including necessary instrumentation and'controls to maintain the unit in a safe condition during hot shutdown, and (2) with a potential capability for subsequent cold shutdown of the reactor through the use of suitable procedures."
                     -The ITS (page 601 of 636) deletes the CTS applicability requirement and the CTS SR for control circuits and transfer switches required for a serious control room or cable spreading room fire.
                     -STS LCO 3.3.18 (NUREG-1430)'provides for a Remote Shutdown System in order to provide the control room operator with sufficient instrumentation and controls to place and maintain the unit in a safe shutdown condition from locations other than the control room. The STS also has a SR 3.3.18.2 that states to "verify each required control circuit and transfer switch is capable of performing the intended function'."

http:l//www.excelservices.com/exceldbs/itstrack -davisbesse.nsf/lfddcealOd3bdbb585256e".. 7/18/2008

NRC ITS Tracking Page 2 of 4 10 CFR 50, Appendix A, GDC 19 states "equipment at appropriate locations outside the control room shall be provided (1) with a design capability for prompt hot shutdown of the reactor, including necessary instrumentation and controls to maintain the unit in a safe condition during hot shutdown, and (2) with a potential capability for subsequent cold shutdown of the reactor through the use of suitable procedures." Given the discussion in the USAR, it is unclear how the ITS ensure that control circuits and transfer switches are operable, in order to ensure that a prompt hot shutdown of the reactor could occur in accordance with 10 CFR 50, Appendix A, GDC 19. Issue Date] 01/23/2008 [ Close DDate [06/26/2008 Logged in User: Anonymous "'Responses Licensee Response by Bill Please clarify what specifically is lacking in the Discussion of Bentley on 01/29/2008 Change RO0 (page 596 - 598 in Volume 8) for this issue. oNRC Response by Aron Lewin Will request conference call with licensee. In01/29/21008 ]Wl qe Licensee Response by Jerry During a recent NRC phone conference, the NRC reviewer Jones on 02/22/2008 clarified that he was looking to.ensure that the Appendix R control circuits and transfer switches currently required by CTS 3.3.3.5.2 (Volume 8, Page 592), and relocated from the CTS as discussed in Discussion of change RO0 (Pages 596-598) are not also needed to meet. the Remote Shutdown Monitoring Function of CTS 3.3.3.5.1. Davis-Besse has confirmed that none of the CTS 3.3.3.5.2 control circuits and transfer switches are those also required to meet CTS 3.3.3.5.1. NRC Response by Aron Lewin Discuss if any of the control circuit and transfer switches provide a Ion 02/25/2008 design capability for prompt hot shutdown of the reactor. Licensee Response by Bryan As discussed in Serial 2101 (dated December 23, 1992), testing of Kays on 03/18/2008 the transfer switches for the components listed below were added under CTS SR 4.3.3.5.2 (Volume 8, Page 592). Transfer switches are used to allow a component to be controlled only from a local location when a serious control room or cable spreading room fire renders the control room uninhabitable and control of the oomponents is required in order to. achieve and maintain safe shutdown of the plant. Auxiliary Feedwater Pump Turbine System Admission Valve ICS038B Component Cooling Water Pump P43-1 Containment Air Cooler CI-I Decay Heat Removal System Pump P42-1 Decay Heat Removal System Valve DH 1517 (Decay Heat Removal Pump 1-1 Suction Valve) Decay Heat Removal System Valve DH64 (Low Pressure Injection/High Pressure Injection Cross Tie Valve) Emergency Diesel Generator 1 Emergency Diesel Generator DA1147A/B (Air Start Solenoid Valves) Essential Power Busses C1 and El Make-up and Purification Pump P37-1 (and its Lubrication Oil Pumps) Make-up and Purification Valve MU02B (Letdown Cooler Inlet Valve). http://www.excelservices.com/exceldbs/itstrack-davisbesse.nsf/ilfddcealOd3bdbb585256e... 7/18/2008

NRC ITS Tracking Page 3 of 4 Reactor Coolant System Valve RC 11 (PORV Block Valve) Service Water Pumps P3-1 and P3-3 Service Water System Valve SW1382 (Auxiliary Feedwater Pump 1 Suction) As discussed in DOC ROl (Page 596), the control circuits and transfer switches are not used to detect a degradation of the reactor coolant pressure boundary and are not assumed to mitigate a design basis accident or transient event. The 10CFR50 Appendix R control circuits and transfer switch capability is consistent with the requirements of I 10CFR50 Appendix R. A copy of Serial 2101 is attached. NRC Response by Aron Lewin Technical Branch assistance formally requested. Issue being on 03/24/2008 tracked by TAC MD8349. Licensee Response by Jerry The following additional information is being provided to justify Jones on 05/06/2008 not including the Appendix R control circuits and transfer switches in the Davis-Besse ITS. The NRC and the industry met on March 19, 1992 and one of the items discussed was the inclusion of the Appendix R instruments and controls in ISTS 3.3.18, Remote Shutdown System. The NRC (Mr. Russell) decided that it would be inappropriate to attempt to incorporate broader requirements into the Improved Standard Technical Specifications, beyond the remote shutdown capability. A copy of the memo is attached. Furthermore, when the ISTS was issued the ISTS Bases clearly stated that the remote shutdown specification was required to meet GDC 19 only; no mention of Appendix R is provided. Thus, it appearsclear to Davis-Besse that it is acceptable to relocate the Appendix R requirements to the TRM. Licensee Response by Jerry The following additional information is being provided to justify Jones on 05/29/2008 not including the Appendix R control circuits and transfer switches in the Davis-Besse ITS. During a recent phone conversation, the NRC reviewer stated that Davis-Besse added in the Appendix R Control Circuits and Transfer Switches requirement (CTS 3.3.3.5.2) to comply with Generic Letter 88-12 (dated August 2, 1988). Therefore, Davis-Besse needed to maintain this current requirement to continue to meet the Generic Letter requirements. Davis-Besse is already aware of this fact. We stated in Discussion of Change (DOC) R01 (Volume 8, Page 597) that "these requirements were added to the Davis-Besse CTS in License' Amendment 187, dated June 14, 1994, to include testing requirements for transfer switches used to meet 10 CFR Appendix R safe shutdown requirements." However, the position of Davis-Besse is that the Generic Letter requirements that the Remote Shutdown Technical Specifications include Appendix R requirements have been superseded by the issuance of the Improved Standard Technical Specifications. The ISTS NUREGs (NUREGs- 1430, -1431, -1432, -1433, and -1434) were issued by the NRC on 9/28/02; i.e., subsequent to the issuance of Generic Letter 88-12. None of the five NUJREGs include Appendix R requirements in the Remote Shutdown Specifications. This is specifically shown by two items. 1) the ISTS Bases for the Remote Shutdown System (Applicable Safety Analyses section) states that http://www.excelservices.com/exceldbs/itstrackdavisbesse.nsf/1 fddcea 1Od3bdbb585256e... 7/18/2008

NRC ITS Tracking Page 4 of 4 it is in Technical Specifications to meet 10 CFR 50 Appendix A, General Design Criteria (GDC) 19. Nothing in the Bases describes that it is to meet 10 CFR 50 Appendix R requirements. 2) Appendix R requires the units to be able to reach Cold Shutdown (i.e., MODE 5 for PWRs), whereas Appendix A, GDC 19 requires units be able to reach and maintain Hot Shutdown (MODE 4). When the Remote Shutdown System is inoperable, the ISTS ACTIONS for the PWR NUREGs only require placing the unit in MODE 4, not MODE 5. While Davis-Besse has noted that the NRC document provided as an attachment to our 5/6/08 response could be interpreted to mean that the Appendix R remote shutdown requirements should be maintained in ISTS, this was clearly not the intent of the NRC as shown by the non-inclusion of these requirements in all of the ISTS NUREGs. Davis-Besse does not believe that we' should be required to maintain this requirement in the ITS, since this would make us inconsistent with the other ITS conversions (which did not include these Appendix R requirements). Furthermore, Davis-Besse notes that the NRC has also approved a similar relocation during a recent ITS conversion as is being requested by Davis-Besse. DC Cook Units 1 and 2 relocated the Appendix R Remote Shutdown requirements to their Technical Requirements Manual using an R type Discussion of Change. A copy of the NRC Safety Evaluation for this change is attached. Licensee Response by Jerry Davis-Besse has decided to maintain CTS 3.3.3.5.2 requirements Jones on 06/26/2008 in theTechnical Specifications. A draft markup regarding this change is attached. This change will be reflected in the supplement to this section of the ITS Conversion Amendment. NRC Response by Aron Lewin No further questions at this time. on 06/26/2008iL___________________________ Date Created: 01/23/2008 12:34 PM by Aron Lewin Last Modified: 06/26/2008 11:44 AM http://www.excelservices.com/exceldbs/itstrack-davisbesse.nsfl1fddcealOd3bdbb585256e... 7/18/2008

CENTERIOR ENERGY Donald C. Shelton 300 Madison Avenue Vice President- Nuclear Toledo, OH 436520001 Davis-Besse (419) 249-2300 Docket Number 50-346 License Number NPF-3 Serial Number 2101 December 23, 1992 United States Nuclear Regulatory Commission Document Control Desk Washington, D.C. 205!

Subject:

License Amendment Request to Revise Technical Specification 3/4.3.3.5, Instrumentation - Remote Shutdown Instrumentation and its Bases, and/Technical Specification 6.9.2, Special Reports Gentlemen: Enclosed is an application for an amendment to the Davis-Besse Nuclear Power Station (DBNPS), Unit Number 1, Operating License Number NPF-3, Appendix A, Technical Specifications (TS). As described in the attached Safety Assessment and Significant Hazards Consideration, this application requests revision of TS 3/4.3.3.5, Instrumentation - Remote Shutdown Instrumentation and its Bases, and TS 6.9.2, Special Reports. This license amendment application fulfills Toledo Edison's (TE) commitment, as documented in TE letter Serial Number 2070, dated July 28, 1992, to submit a proposed revision to TS 3/4.3.3.5 and its Bases adding testing requirements for transfer switches used to meet 10 CFR Part 50, Appendix R (Fire Protection) requirements. Toledo Edison requests that this amendment be issued by the NRC with the provision of not requiring implementation until startup (Kode 2) from the first refueling outage following NRC amendment approval. This will allow the first performance of the amendment-associated testing during shutdown conditions rather than during power operations. Operafing Companies: Cleveland Electric Illuminating Toledo Edison

Docket Number 50-346 License Number NPF-3 Serial Number 2101 Page 2 If you have any questions regarding this amendment request, please contact Mr. R. W. Schrauder, Manager - Nuclear Licensing, at (419) 249-2366. Very tryy ors, MKL/dlc cc: A. B. Davis, Regional Administrator, NRC Region III J. B. Hopkins, DB-1 NRC/NRR Senior Project Manager S. Stasek, NRC Region III, DB-l Senior Resident -Inspector J. R. Williams, Chief of Staff, Ohio Emergency Management Agency, State of Ohio (NRC Liaison) Utility Radiological Safety Board

Docket Number 50-346 License Number NPF-3 Serial Number 2101 Enclosure Page 1 APPLICATION FOR AMENDMENT TO FACILITY OPERATING LICENSE NUMBER NPF-3 DAVIS-BESSE NUCLEAR POWER STATION UNIT NUMBER 1 Attached are requested changes to the Davis-Besse Nuclear Pover Station, Unit Number 1, Facility Operating License Number NPF-3. Also included is the Safety Assessment and Significant Hazards Consideration. The proposed changes submitted under cover letter Serial Number 2101 concern: Appendix A, Technical Specification 3/4.3.3.5,,Instrumentation - Remote Shutdown Instrumentation and its Bases Appendix A, Technical Specification 6.9.2, Special Reports By: ton, Vice Prisident, Nuclear - Davis-Besse Sworn and Subscribed before me this 23rd day of December. N Wotar)KuPuat c of 0 o BUN-Y L WOOO. NoWy PublIC MyComW B9fsof 1,19

Docket Number 50-346 License Number NPF-3 Serial Number 2101 Enclosure Page 2 The following information is provided to support issuance of the! requested changes to the Davis-Besse Nuclear Power Station, Unit Number 1, Operating License Number NPF-3, Appendix A Technical Specification (TS) 3/4.3.3.5, Instrumentation - Remote Shutdown Instrumentation and its Bases, and TS 6.9.2, Special Reports. A. Time Required to Implement: This change is to be implemented no later than startup (Mode 2) from the first refueling outage following NRC amendment approval. This will allow the first performance of the amendment-associated testing during shutdown conditions, rather than during power operations. B. Reason for change (License Amendment Request 92-0010): Revise TS 3/4.3.3.5, Instrumentation - Remote Shutdown Instrumentation and its Bases to add testing requirements for transfer switches used to meet 10 CFR Part 50, Appendix R requirements in accordance with Toledo Edison's (TE) commitment to the NRC documented in TE letter Serial Number 2070, dated July 28, 1992. Transfer switches are used to allow a component to be controlled only from a local location when a serious control room or cable spreading room fire renders the control room uninhabitable and control of the components is required in order to achieve and maintain safe shutdown of the plant. In addition, revise Ts 6,9.2 to reference a new special report requirement. C. Safety Assessment and Significant Hazards Consideration: See attached.

Docket Number 50-346 License Number NPF-3 Serial Number 2101 Attachment Page 1 SAFETY ASSESSMENT AND SIGNIFICANT HAZARDS CONSIDERATION TITLE: Revise Technical Specification (TS) 3/4.3.3.5, Instrumentation -. Remote Shutdown Instrumentation and its Bases to Add a Limiting Condition for Operation and Surveillance Testing Requirements for 10 CFR Part 50, Appendix R Accredited Transfer Switches. Revise Specification 6.9.2 to Reference a New Special Report Requirement. DESCRIPTIONS: This License Amendment Request (LAR) proposes revision of TS 3/4.3.3.5, Instrumentation - Remote Shutdown Instrumentation and its Bases to add a Limiting Condition for Operation (LCO) and surveillance testing,- requirements for transfer switches which are used to shift control of components from the control room to either the remote shutdown panel or to another local location in the event of a serious fire in either the control room (Fire Area FF) or cable spreading room (Room 422A, Fire Area DD). In Toledo Edison (TE) letter Serial Number 2070, dated July 28, 1992', TE committed to submit an LAR that would add Appendix R accredited transfer switch testing requirements. This commitment resolved a Nuclear Regulatory Commission (NRC) Staff comment made during the review of TE's LAR 90-0013, which proposed removal of the Fire Protection TSs'(submitted by TE letter Serial 1789, November 1, 1991). License Amendment Request 90-0013 was approved by the NRC through issuance of License Amendment 174, by letter dated September 22, 1992. 'The testing requirements for Remote Shutdown Systems from the Babcock and Wilcox Revised Standard Technical Specifications (B&' RSTS) (NUREG-1430, Rev. 0 dated September 28, 1992), were used to meet the guidelines of Item 8 (j) (demonstrate testing of transfer switches) of Enclosure 1 to NRC Generic Letter 81-12, Fire Protection Rule (dated February 20, 1981). Specifically, it is proposed that the existing LCO 3.3.3.5 be renumbered to LCO 3.3.3.5.1, and a new LCO 3.3.3.5.2 be added which would state:

    "The control circuits and transfer switches required for a serious control room or cable spreading room fire shall be OPERABLE."

Additionally, it is proposed that the existing Action "b" be re-designated as Action "c", and a new Action "b" added which would state:

    "With one or more control circuits or transfer switches required for a serious control room or cable spreading room fire inoperable, restore the inoperable circuit(s) or'switch(es) to OPERABLE status within 30 days, or prepare and submit a Special Report to the Commission pursuant to Specification 6.9.2 within the next 30 days outlining the action taken, the cause of the inoperability, and the plans and schedule for restoring the circuit(s) or switch(es) to OPERABLE status."

Docket Number 50-346 License Number NPF-3 Serial Number 2101 Attachment Page 2 In addition, it is proposed that the existing Surveillance Requirement (SR) 4.3.3.5 be renumbered to SR 4.3.3.5.1 and a new SR 4.3.3.5.2 be added which would state:

    "At.least once per 18 months, verify each control circuit and transfer switch required for a serious control room or cable spreading room fire is capable of performing the intended function."

Additionally, the following would be added to TS Bases 3/4.3.3.5, Remote Shutdown Instrumentation:

    "1 SR 4.3.3.5.2 verifies that each Remote Shutdown-System transfer switch and control circuit required for a serious control room or cable spreading room fire performs its intended function. This verification is performed from the remote shutdown panel and locally, as appropriate. This will ensure that if the control room becomes inaccessible, the unit can be safely shutdown from the remote shutdown panel and the local control stations."

Finally, a change to Specification 6.9.2 is proposed to add a new paragraph "g" which would state:

    "Inoperable Remote Shutdown System control circuit(s) or transfer switch(es) required for a serious control room or cable spreading room fire, Specification 3.3.3.5.2."

The list of specific transfer switches to be tested has'been developed based on a review of the Fire Hazard Analysis Report (FHAR) for the control room and cable spreading room fire areas. This list will be maintained in the appropriate plant surveillance testing procedures. The surveillance testing procedure will require operation of the safe shutdown component from the local location as part of the testing. SYSTEMS, COMPONENTS, AND-ACTIVITIES AFFECTED: The transfer switches for the following components would be tested under the new Surveillance Requirement 4.3.3.5.2: Auxiliary Feedwater Pump Turbine System Admission Valve ICSO38B Component Cooling Water Pump P43-1 Containment Air Cooler Cl-1 Decay Heat Removal System Pump P42-1 Decay Heat Removal System Valve DH1517 (Decay Heat Removal Pump 1-1 Suction Valve) Decay Heat Removal System Valve DH64 (Low Pressure Injection/High Pressure Injection Cross Tie Valve) Emergency Diesel Generator 1 Emergency Diesel Generator DA1i47A/B (Air Start Solenoid Valves) Essential Power Busses Cl and El Make-up and Purification Pump P37-1 (and its Lubrication Oil Pumps) Make-up andPurification Valve MU02B (Letdown Cooler Inlet Valve) Reactor Coolant System Valve RC11 (PORV Block Valve) Service Water System Pumps P3-1 and P3-3 Service Water System Valve SV1382 (Auxiliary Feedwater Pump I Suction)

Docket Number 50-346 License Number NPF-3 Serial Number 2101 Attachment Page 3 SAFETY FUNCTIONS OF THE'AFFECTED SYSTEMS, COMPONENTS AND ACTIVI'rIEs. The transfer switches are used to transfer control of safe shutdown components from the control room to a local location when a serious control .room or cable spreading room fire renders the control room uninhabitable and control of the components is required in order to achieve and maintain safe shutdown of the plant. The purpose of testing the transfer switches is to verify on a periodic basis that the switches are capable of performing their intended functions. This testing will demonstrate that equipment operates from the local control station when the transfer or isolation switch is placed in the "local" position and that the equipment cannot be operated from the control room. This testing will also demonstrate that equipment operates from the control room when the transfer or isolation switch is returned to the normal position. EFFECTS ON SAFETY: The addition of the LCO and surveillance testing requirements to verify the ability of the transfer switches to transfer control of safe! shutdown components from the control room to a local location will periodically verify that these switches can perform their required function. The test procedures will stipulate the plant mode or condition under which the testing can be performed, normally during plant outages, in order to minimize the likelihood of adversely affecting plant status. Test procedures are required to be prepared, reviewed and approved in accordance with the requirements of TS 6.5.3, Technical Review and Control. Technical Specifications 6.5.3 requires review by a separate individual meeting or exceeding the requirements of Sections 4.2, 4.3.1, 4.4 or 4.6 of ANSI 18.1, 1971, Selection and Training of Nuclear Power Plant Personnel. Each review performed under TS 6.5.3 will also include a determination of whether an unreviewed safety question is involved as defined in 10 CFR 50.59. It is, therefore, concluded that these changes have no adverse effect on safety. The proposed change to Specification 6.9.2 is an administrative change and has no adverse effect on safety. SIGNIFICANT HAZARDS CONSIDERATION: The Nuclear Regulatory Commission has provided standards in 10 CIFR 50.92(c) for determining whether a significant hazard exists due to a proposed amendment to an Operating License for a facility. A proposed amendment involves no significant hazards consideration if operation of the facility in accordance with the proposed changes would: (1) Not involve a significant increase in the probability or consequences of an accident previously evaluated; (2) Not create the possibility of a new or different kind of accident from any accident previously evaluated; or (3) Not involve a significant reduction in a margin of safety.

Docket Number 50-346 License Number NPF-3 Serial Number 2101 Attachment Page 4 Toledo Edison has reviewed the proposed changes and determined that a significant hazards consideration does not exist because operation of the Davis-Besse Nuclear Power Station, Unit Number 1, in accordance with the proposed changes would: la. Not involve a significant increase in the probability of an accident previously evaluated because none of the proposed changes are associated with the initiation of any design bases accident. The addition of Limiting Condition for Operation (LCO) 3.3.3.5.2 and Surveillance Requirement (SR) 4.3.3.5.2 to the Technical Specifications will require each control circuit and trans:Eer switch that is required for a serious control room or cable spreading room fire to be operable during Modes 1, 2 and 3 and to be verified at least once per 18 months as capable of performing the intended function. New Action b will require restorat:ion of an inoperable control circuit or transfer switch (required for a serious control room or cable spreading room fire) within 30 days or a Special Report submitted to the NRC pursuant to Specification 6.9.2 within the next 30 days. Surveillance testing procedures will be prepared, reviewed and approved in accordance with Technical Specification (TS) 6.5;3, Technical Review and Control, which will ensure an unreviewed safety question is not created. To support the addition of the new LCO, Action and SR, the existing LCO, Action and SR are proposed to be adminstratively re-numbered or re-lettered. The new Special Report requirement is proposed to be administratively added to TS 6.9.2. lb. Not involve a significant increase in the consequences of an accident previously evaluated because no equipment, accident conditions, or assumptions are affected which could lead to significant increases in radiological consequences. The addition of LCO 3.3.3.5.2 and SR 4.3.3.5.2 to the Technical Specifications will require each control circuit and transfer switch that is required for a serious control room or cable spreading room fire to be operable during Modes 1, 2 and 3 and to be verified at least once per 18 months as capable of performing the intended function. New Action b will require restoration of an inoperable control circuit or transfer switch (required for a serious control room or cable spreading room fire) within 30 days or a Special Report submitted to the NRC pursuant to Specification 6.9.2 within the next 30 days. Surveillance testing procedures will be prepared, reviewed and approved in accordance with Technical Specification (TS) 6.5.3, which will ensure an unreviewed safety question is not created. To support the addition of a new LCO, Action and SR, the existing LCO, Action and SR are proposed to be administratively re-numbered or re-lettered. The new Special Report requirement is proposed to be administratively added to TS 6.9.2. 2a. Not create the possibility of a new kind of accident from any accident previously evaluated because no new accident initiators are introduced by the proposed changes. The addition of LCO 3.3.3.5.2 and SR 4.3.3.5.2 to the Technical Specifications will require each control circuit and transfer switch that is required for a serious control room or cable spreading room fire to be

Docket Number 50-346 License Number NPF-3 Serial Number 2101 Attachment Page 5 operable during Modes 1, 2 and 3 and to be verified at least once per 18 months as capable of performing the intended function. New Action b will require restoration of an inoperable control circuit or transfer switch (required for a serious control room or cable spreading room fire) within 30 days or a Special Report submitted to the NRC pursuant to Specification 6.9.2 within the next 30 days. Surveillance testing procedures will be prepared, reviewed and approved in accordance with TS 6.5.3, which will ensure an unreviewed safety question is not created. To support the addition of the new LCO, Action and SR, the existing LCO, Action and SR are proposed to be administratively re-numbered or re-lettered. The new Special Report requirement is proposed to be administratively added to TS 6.9.2. 2b. Not create the possibility of a different kind of accident from any accident previously evaluated because no different acc:ident initiators are introduced by the proposed changes. The addition of LCO 3.3.3.5.2 and SR 4.3.3.5.2 to the Technical Specifications will require each control circuit and transfer switch that is required for a serious control room or cable spreading room fire to be operable during Modes 1, 2 and 3 and to be verified at least once per 18 months as capable of performing the intended function. New Action b will require restoration of an inoperable control circuit or transfer switch (required for a serious control room or cable spreading room fire) within 30 days or a Special Report submitted to the NRC pursuant to Specification 6.9.2 within the next 30 days. Surveillance testing procedures will be prepared, reviewed and approved in accordance with TS 6.5.3, which will ensure an unreviewed safety question is not created. To support the addition of the new LCO, Action and SR, the existing LCO, Action and SR are proposed to be administratively re-numbered or re-lettered. The new Special Report requirement is proposed to be administratively added to TS 6.9.2.

3. Not involve a significant reduction in a margin of safety because these are not new or significant changes to the initial conditions contributing to accident severity or consequences, therefore, there are no significant reductions in a margin of safety.

CONCLUSION: On the basis of the above, Toledo Edison has determined that the License Amendment Request does not involve a significant hazards consideration. As this License Amendment Request concerns proposed changes to the Technical Specifications that must be reviewed by, the Nuclear Regulatory Commission, this License Amendment Request does not. constitute an Unreviewed safety question. ATTACHMENT: Attached are the proposed marked-up changes to the Operating License.

Docket Number 50-346 License Number NPF-3 Serial Number 2101 Attachment Page 6 INSTRUMENTATIOi REMOTE SHUTDOWN INSTRUMENTATION LIMITING CONDITION FOR OPERATION

-3..- The remote shutdown monitoring instrumentation channels shown nae 3.3-9 shall be OPERABLE with readouts displayed external to the control r..m.

A*F*-* * *"M**** and j.- - ACTION:

a. With'the number of OPERABLE remote shutdown monitoring channels less than required by Table 3.3-9, either restore the inoperable channel to OPERABLE status within 30 days, or be in HOT SHUTDOWN

(-s within the next 1Z hours. are not applicable. Th4rvsoso pcfcto .. 6 SvA,4,tt

                         ~sr,                   ,QD3S67T SURVEILLANCE REQUIREMENTS V_.T 6      43.3.6 ach remote shutdown monitoring instrumentation channel e e nstrated OPERABLE by performance of the CHANNEL CHECK and CALIBRATION operations'at the frequencies shown in Table 4.3-6.

4 ) 2x A j / A

                                                          ,r_

DAVIS-BESSE, UNIT 1 3/4 3-43

Docket Number 50-346 License Number NPF-3 Serial Number 2101 Attachment Page 7 Insert for nev LCO 3.3.3.5.2 The control circuits and transfer switches required for a serious control room or cable spreading room fire shall be OPERABLE. Insert for new Action b With one or more control circuits or transfer switches required for a serious control room or cable spreading room fire inoperable, restore the inoperable circuit(s) or svitch(es) to OPERABLE status within 30 days, or prepare and submit a Special Report to the Commission pursuant to Specification 6.9.2 within the next 30 days outlining the action taken, the cause of the inoperability, and the plans and schedule for restoring the circuit(s) or switch(es) to OPERABLE status. Insert for new SR 4.3.3.5.2 At least once per 18 months, verify each control circuit and transfer switch required for a serious control room or cable spreading room fire is capable of performing the intended function.

a W.t mQ0-.M TABLE 3.3-9 4

**4 REMOTE SHUTDOWN NONITODING INSTRURENTATION
'A
.4 a."

CPUt '4 (4 N READOUT nv.Asuuwm~lrr INSTRUMENT LOCATION awn I (Trip Breaker A) e.g I. Reactor Trip Breaker ladicatiom (a) 480v Y&DC CH. 2 O1PEN-CLOSE 6~~ Switchgaar Room (b) I (Trip Breaker A) (b) 480v UDC CU. V (b) I (Trip lreaker Q) Svitchsear loom (c) 480r FEI*uC. 2 (c) I (Trip Breaker C) Svitchesar Boom (d) CawC Cabinet Room Cd) I (Trip Breaker 3J)

2. Reactor Coolant Tenperature - not Leg Aux. Shuedows Panai 520-420 oF I

3. Reactor Coolant System pressure AuX. Swtdou. lane! 0-30 0 0 w Pressriasr Level Aux. Sbutdowm Famel 0-320 to~e~

Steem Generator Outlet Stesm IPressure Aux. Shutdown len.! 1200 poit I1/tem generator 6.

           $team Generator Level Startup Range       Aux. Sbutdoum Famel       0-250 tucksa      mistem generator

7. Ceotrol Bod Position Switches Coutrol Rod Drive 0, 25, so, 0 Pfrod I 0 Control Cabint,..

System Logic Cablst 04 Seda I OMN U 0

0q

• M- n Ml M Pr'.

                                                                                                      '0  I. CMe
                                                                                                       =r     to z

ca TABLE 4.3-6 REMOTE SHLUTDOVN MONITORING INSTRUMENTATION SURVEILLANCE REQUIREMENTS 0Z La

                                                                                                             '"I h~

CHANNIEL CHANSNEL INSTRUIENT cm CALIBRATION Lai

1. Reactor Trip Breaker Indication N N.A.

Ob

'EP 2. Reactor Coolant Temperature-Hot Legs             N               R H

3. Reactor Coolant System Pressure K

4. Pressurizer Level R

5. Steam Generator Outlet Steam Pressure H R

6. Steam Generator Startup Range Level N i

7. Control Rod Position Switches N N.A.

                                                                                                         .I M I91 Ci

-a

Docket Number 50-346 License Number NPF-3 Serial Number 2101 Attachment Page 10 BASES THIS PAGE PROVIDED FOR INFORMAtiON ONl1 BASES , .... 3/4.2.2 MONITO!ThG ISRM ENTA&rOM 3/4.232.1 RADOATION MONITORING INSTOUMPTATION Th OPElARILITT of the radiation monitoring charls's ensures that 1) the radiation levels are continually memasured in the areas served by tne individual ebannals and 2) the larm or automatic action is initiated vhen the radiation level trip setpoint is excseded. 2/4.3.1.2 NCoRZ DETECTORS The OPERA3I.IT of the incore detectors ensures that the measuremen:i obtained trom use of this system accurately represent the spatial neutron fl2uc distribution of the reactor core. See Bases Figures 3-1 and 3-2 for examples of acceptable minimum incore detector arrangements. 3/4.3.3.3 SEISMIC INSTRUNITrATION The OFPUALZ= of the seismic instrumentation ensures that sufficient capability is available to promptly determine the m@gtude of a seismic event so that the response of those featres important to satety may be evaluated. This capability is required to permit comperison of the measured response to that used in the design basis for the facility. This instrumentation is consistent vith the recommendations of elam'story Guide 1.12 "Instrumentation for Earthquakes," April 1974. 3/4.3.3.4 M*EtOROLOGICAL INS=TRUXDIAT!OtI The OPERA5ZXT of the meteorological instrumentation ensures that sufficient meteorological data is available for estimating potential radiation doses to the public an a result of routine or accidental release of radioactive materials to the atmosphere. This capability is required to evaluate the need for initiating protective measures to protect the health and safety of the public. This Instrumentation is consistent vith the recommdations of Regulatory Guide 1.23 "Onsite Meteorological Programs," February L972. 3/4.3.3.5 RMIO SoUTOM INSTRUNDTATIO The OPUAILT of the remote shutdovn instrumentation ensures that sufficiant capao2lity is available to permit shutdovn and maintenance of DAVIS-BESSE. UNIT 1 3 3/4 3-2

Docket Number 50-346 License Number NPF-3 Serial Number 2101 Attachment Page 11 3/4.3 INSTRUMENTATION BASES REMOTE SHUTDOWN INSTRUMENTATION (Continued)

        ;OT STANDBY of the facility from locations outside of the control room...

This capability is required in the event control room habitability is 3/4.3.3.6 POST-ACCIDENT MONITORING INSTRUMENTATION The OPERABILITY of the post-accident monitoring instrumentation ensures tnat sufficient information is available on selected plant oarameters to monitor and assess these variables following an accident. The containment Hydrogen Analyzers, although they are considered part of the plant post-accident monitoring instrumentation, have their OPERABILITY requirements located in Specification 3/4.6.4.1, Hydrogen Analyzers. 3/4.3.3.7 CHLORINE DETECTION SYSTEMS - Deleted 3/4.3.3.8 FIRE DETECTION INSTRUMENTATION -- Ddieted

AVIS-BESSE, UNIT I 3 3/4 3-,3 Amendment %,oa. , ,

Ea; 30. 15f 74-

Docket Number 50-346 License Number NPF-3 Serial Number 2101 Attachment Page 12 Insert for TS 3/4.3.3.5 Bases SR 4.3.3.5.2 verifies that each Remote Shutdown System transfer switch and control circuit required for a serious control room or cable spreading room fire performs its intended function. This verification is performed from the remote shutdown panel and locally, as appropriate. This will ensure that if the control room becomes inaccessible, the unit can be safely shutdown from the remote shutdown panel and the local control stations.

Docket Number 50-346 License Number NPF-3 Serial Number 2101 Attachment Page 13 ADMINISTRATIVE CONTROLS SPECIAL REPORTS 6.9.2 Special reports shall be submitted to the U.S. Nuclear Regulatory Commission in accordance with 10 CFR 50.4 within the time period specified for each report. These reports shall be submitted covering the. activities identified below pursuant to the requirements of the applicable reference specifications:

a. ECCS Actuation, Specifications 3.5.2 and 3.5.3.

6. Inoperable Seismic Monitoring Instrumentation, Specification 3.3.3.3.

c. Inoperable Meteorological Monitoring Instrumentation, Specification 3.3.3.4.

d. Seismic event analysis, Specification 4.3.3.3.2.

e. Deleted Deleted .".- - ..

6.10 RECORD RETENTION 6.10.1 The following records shall be retained for at least five years:

a. Records and logs of facility operation covering time interval at each power level.

b. Records and logs of principal maintenance activities, inspections, repair and replacement of principal items of equipment related to nuclear safety.

c. All REPORTABLE EVENTS.

d. Records of surveillance activities, inspections and calibrations required by these Technical Specifications.

e. Records of changes made to Operating Procedures.

f. Records of radioactive shipments.

g. Records of sealed source and fission detector leak tests and results.

h. Records of annual physical inventory of all sealed source material of record.

DAVIS-BESSE, UNIT I 6-18 Amendment 'lo. ,

Docket Number 50-346 License Number NPF-3 Serial Number 2101 Attachment Page 14 Insert for New 6.9.2.g

g. Inoperable Remote Shutdown System control circuit(s) or transfer switch(es) required for a serious control room or cable spreading room fire, Specification 3.3.3.5.2.

Arim

                                                                                .,-', I .:

V UNITED STATES NUCLEAR REGULATORY COMMISSION WASHINGTON. D.C. 205, April 6, 1992 MEMORANDUM FOR: Charles E. Rossi, Director Division of Operational Events Assessment, NRR FROM: Christopher I. Grimes, Chief Technical Specifications Branch Division of Operational Events Assessment, NRR

SUMMARY

OF OWNERS GROUPS MEETINGS ON THE NEW STANDARD TECHNICAL SPECIFICATIONS: MARCH 18 & 19, 1992 On March 18, 1992, the Technical Specifications Branch met with the Owners Groups, and on March 19, 1992, the Owners Groups Executives met with NRR senior management to'discuss the status of activities for resolving comments on the draft standard technical specifications (STS) and related matters. The meeting attendees are listed in Enclosures 1 and 2, respectively. There was no formal agenda for the staff's meeting with the Owners Groups on March 18, 1992; the purpose of the meeting was to discuss the status of the schedule, action assignments, and the Executive agenda. The Owners presented an updated activity schedule (Enclosure 3). Bob Tjader indicated that the staff had proposed a note to be added for the control rod movability surveillance requirement to clarify operability considerations (movability as an indicator of "trippability") for the surveillance and the application of SR 3.0.1 to trippability, as described in the condition for the control rod LCO. NRR management previously concluded during the meeting on February 5, 1992, that trippability is the attribute of importance for the control rod safety function. However, the application of this concept appeared to conflict with SR 3.0.1, which states:

   "Failure to meet a Surveillance, whether such failure is experienced during performance of the Surveillance or between performances of the Surveillance, shall be failure to meet the LCO."

The Owners Groups concluded that there was no need for any clarification. The Owners contend that the relationship between operability and trippability will be adequately explained in the Bases for Section 3.1 of the STS, to the extent that there is no need to change OPERABLE in the body of the limiting condition to read "trippable." Further, the Owners indicated that, in the event that a control rod is immovable at the time the surveillance is due, the failure would have to be corrected so that the surveillance (movement) could be performed within the 25% allowance for the'surveillance interval. The Owners Groups' explanation of operability considerations for control rods caused a tumultuous response from the staff. Particularly, the staff expressed concern that the control rods are not particularly different than other safety systems that may have non-safety functions or capabilities that also must be considered relative to "operability" of particular systems. The

                                     -2  -            April 6, 1992 staff also expressed concern that the Owners Groups' rationalization of the need to restore the "non-safety" function in order to perform the surveillance fundamentally violates long-standing principles and interpretations applied to operability and surveillances for technical specifications. The staff also expressed concern over the precedent that this particular position would have on the recently issued guidance on degraded conditions and operability, and potential future ramifications for more extensive divisions between safety and non-safety functions.

During the discussion that ensued, the staff and Owners discussed a variety of implications. and analogies to characterize the relationships between operability and safety function, and between surveillance results and operability determinations to grapple with this issue. These protracted discussions primarily involved different views regarding language meaning and consistency and did not appear to disclose any new insights into the safety functions of control rods. Consequently, I concluded that the staff's concerns involved language preferences, irrespective of the potential for misuse or abuse of this position as a demonstration of the relationship between operability and safety function with respect to broader technical specification policies. On this basis, I concluded that OTSB will defer to-the Owners Groups choice of language for control rod operability and Bases, provided that their proposed language is technically accurate. The B&W Owners indicated that, although the generic concerns regarding pressure isolation valves (PIVs) had been addressed during the meeting on March 16, 1992, there are unique design considerations for B&W plants which make the resolution of the PIV issues untenable for them. I requested that the B&W Owners submit a written appeal to ensure that staff can focus its limited resources in this area to the B&W-specific concerns. Chris Hoxie indicated that an action item for Section 1.0 concerning the definition of pressure boundary LEAKAGE had been overlooked. The Owners had agreed-to develop a clarification for the Bases to resolve the issue raised in Section 1.0. While the clarification effects several sections, the Owners had proposed to incorporate the additional Bases material in Section 3.4 for the Reactor Coolant System. Mr. Hoxie will coordinate with Ms. Weston to incorporate an appropriate clarification. Carl Schulten similarly indicated that a new issue evolved from the resolution of issues for Section 3.3; the issue involves consistency in the manner by which the potential for positive reactivity changes are treated in the Applicability provisions for Sections 3.3, 3.4 and 3.7. The Owners agreed to evaluate the concern and develop a means to achieve consistency between the three sections that would allow appropriate latitude for normal maneuvers, with appropriate constraints for Applicability considerations. Mag Weston indicated that the BWR Owners had submitted proposed changes for Section 3.9.6 (Enclosure 4) which had been previously rejected because of a lack of technical basis to incorporate the changes. The BWR Owners indicated that they believe that the proposed changes, which would distinguish the limitations on handling irradiated fuel from those for new fuel or control rods. I indicated that (1) the proof and review version of Section 3.9 had

April 6, 1992 just been issued, and I did not believe that this issue warranted pulling the. section back for such a change, and (2) I had previously concluded that additional technical support would be necessary to clarify the appropriate constraints. Consequently, I concluded that, if technical resources are available, OTSB would arrange for a technical clarification of this issue and incorporate any acceptable changes into the June issuance of the completed STS for proof and review. I also noted that, in a meeting on February 24, 1992, the SICB staff had informed the Owners Groups that all of the open issues related to B&W's topical report on "indefinite channel bypass" had been resolved; however, before OTSB could incorporate conforming changes to Section 3.3, we needed to have the staff's safety evaluation report (SER) to clearly understand the extent of the changes and provide the technical justification for the changes. However, because of resource constraints, OTSB had committed to assist SICB in the preparation of the SER, which would detract from the time available for us to resolve all of the other changes to the STS. Accordingly, I concluded that the changes to incorporate "indefinite channel bypass" for both CE and B&W plants would have to be deferred to preclude broader impacts on the comment resolution schedule. OTSB will incorporate these changes at the earliest possible time after the SER has been approved, hopefully before June 1992. The resulting updated list of STS action items is included as Enclosure 5. The Executive meeting was held on March 19, 1992; the meeting agenda is presented inEnclosure 6. 1 described the status of the schedule (Enclosure 7) and the Executive's priority issues (Enclosure 8). I indicated that Section 3.9 had been issued on March 16, 1992, and there continues to be agonizing but steady progress.. I also indicated that the staff has only had limited experience with the complete edit cycle, but I believed that process improvements would continue as they had with the editorial panel reviews. All'of the Executive Priority Issues have been resolved, except for the fbur items that are outside the scope of the comment resolution process (Encl6sure 8). 1 described the resource/priority issue associated with the topical report review, described above, and committed to address the issue at the earliest possible time our resources permit; nevertheless, this issue can still be resolved during implementation, as well. I noted that a similar resource/priority constraint has delayed the preparation of a line-item improvement for diesel testing requirements. OTSB needs to resolve the testing issues in Section 3.8 to provide the model specifications that would accompany the generic action. Subsequently, we would present the proposed action to the CRGR, and their schedules have been delayed by the President's request for a regulatory review. The appeal on the staff's position for al~ternate/dedicated and remote shutdown equipment was presented to NRR management and the Executives, as summarized in Enclosure 9. The staff's and Owners Groups' written positions on this issue had previously been distributed, and are included as Enclosure 10 for completeness. I summarized the staff's position along the following points:

• It was the staff's intent in Generic Letter 88-12, to implement the

                                      - 4             April 6, 1992 Commissions' interim policy on technical specification improvements in such a way as to retain the equipment relied upon for post-fire safe plant shutdown in the limiting conditions for operation (as defined by Generic Letter 81-12), even though these generic requirements have not been implemented consistently.

• The inclusion of this equipment in the technical specifications is consistent with "Criterion 4" of the policy (risk significance), because fires inside or outside the control room can be a significant contributor to core damage frequency, and this equipment is necessary to ensure safe shutdown capability.

The Owners Groups position was summarized as follows:

• Although the need for these safe shutdown capabilities in the plant design is clear, these features are an integral part of a larger program for fire protection, and are not otherwise required to be in technical specifications according to the applicable regulations (GDC 19 or Appendix R).

   "  Some of these safe shutdown capabilities can be important to risk, but that depends on widely varying plant-specific vulnerabilities. Not all of the safe shutdown capabilities are primary success paths to mitigate dominant accident sequences. The extent of importance to risk will be established as part of IPEEE.

Only D four plants have technical specifications for the full complement of post-fire safe shutdown equipment. All of the other plants have maintained the safe shutdown equipment (except for the Remote Shutdown Panel) as part of their Fire Protection Program; the NRC has inspected these programs and found them acceptable.

   "  The full complement of post-fire safe shutdown equipment is extensive; listings of the equipment can range from 30 to 50 pages. Such a scope of equipment would be cumbersome in the technical specifications.

The Owners Executives indicated that the administrative controls for the Fire Protection Program in Section 5.0 of the new STS could be expanded to more clearly address the equipment for the post-fire dedicated, alternate, and remote shutdown capabilities.. Further, the Owners Executives indicated that it was not their intention to remove the limiting conditions for the remote shutdown panel. However, all of the other post-fire safe shutdown equipment has been adequately maintained under these programs and, therefore, the Owners Groups do not believe that broader Technical Specification controls are necessary. Mr RignP11 enncluded that. if only four plants have the full complement of pnct-firp safe shutdawn equipment in the technical specifications, then it wnold ho inappropriate to attempt to incorporate broader requirements into the nw5., beyond the remote shutdown capability. However, Mr. Russell also indicated that the staff should pursue this matter as a potential backfit, if necessary, to resolve the consistency of control for post-fire safe shutdown

                                    -5   -

April 6, 1992 equipment. He noted that additional requirements for hot shutdown capability will likely evolve from the Shutdown Risk Study because of the particular significance of fire as dominant contributors to shutdown risks. Consequently, in the long term, additional limiting conditions may have to be imposed for all plants to ensure adequate safe shutdown capability for fire events. The Executives indicated that the next meeting should address measures of effectiveness and implementation issues, because those issues were raised by the Commission. In particular, the Executives requested that we resolve the need for renoticing of the license amendments for STS conversions. Dr. Murley indicated that whether or not hearings will be required, before or after conversion to the new STS, will depend on the quality'of the significant hazards considerations, and the extent to which the utilities application tries to accumulate changes beyond the scope of the STS conversion. I suggested that founding the STS through rulemaking be considered as one of the alternative approaches. Dr. Murley and Mr. Russell encouraged the staff and Owners Groups to be open-minded and innovative, and requested that the staff and Owners Groups develop a generic conversion process that could serve as a framework for the evolution of more detailed practices. The'next Executive meeting is scheduled for April 23, 1992. Christop er ýIGrimes, Chief Technical Specifications Branch Division of Operational Events Assessment, NRR

Enclosures:

As stated cc: T. Hurley W. Russell L. Bush, OG

 -*4W. Hall, NUMARC R. Tworek, MEREX

June 1, 2005 Mr. Mano K. Nazar Senior Vice President and Chief Nuclear Officer Indiana Michigan Power Company Nuclear Generation Group One Cook Place Buchanan, MI 49106

SUBJECT:

D.C. COOK NUCLEAR PLANT, UNITS 1 AND 2 - ISSUANCE OF AMENDMENTS FOR THE CONVERSION TO THE IMPROVED TECHNICAL SPECIFICATIONS WITH BEYOND SCOPE ISSUES (TAC NOS. MC2629, MC2630, MC2653 THROUGH MC2687, MC2690 THROUGH MC2695, MC3152 THROUGH MC3157, MC3432 THROUGH MC3453)

Dear Mr. Nazar:

The U.S. Nuclear Regulatory Commission (NRC) has issued the enclosed Amendment No. 287 to Facility Operating License No. DPR-58 and Amendment No. 269 to Facility Operating License No. DPR-74 for the Donald C. Cook Nuclear Plant, Units 1 and 2 (CNP). The amendments consist of changes to the technical specifications (TSs) and the license conditions for both units in response to your application dated April 6, 2004 (AEP:NRC:4901), as, supplemented by four letters dated April 15, 200.5 (AEP:NRC:5901, 5901-01, 5901-02, and 5901-03). Separate TSs are being issued for CNP, Units 1 and 2. The amendments convert the current TSs (CTSs) to the improved TSs (ITSs) for CNP and relocate license conditions to the ITSs or other licensee-controlled documents. The ITSs are based on NUREG-1431, "Standard Technical Specifications, Westinghouse Plants," dated April 30, 2001; the Commission's Final Policy Statement, "NRC Final.Policy Statement on Technical Specification Improvements for Nuclear Power Reactors," published on July 22, 1993 (58 FR 39132); and 10 CFR 50.36, "Technicalspecifications." The purpose of the conversion is to provide clearer and more readily understandable requirements in the TSs for the CNP units, to ensure safer operation of the units. The draft safety evaluation (SE) and the draft final SE and amendments for the ITS conversion were sent to you by our letters dated October 1, 2004, and March 31, 2005, for your review to verify the accuracy of the draft SEs and draft amendments. The draft SE was based on your application dated April 6, 2004, and the information provided to the NRC staff through the joint NRC-Indiana Michigan Power Company Cook ITS Conversion web page. You responded with comments on the draft SE, draft final SE, and draft amendments in the letters dated April 15, 2005. You provided a copy of the questions and answers on the web page in the letter also dated April 15, 2005. You submitted the ITSs and ITS Bases for CNP and certified to their correctness in your letter of April 15, 2005. The comments you provided were reviewed and incorporated in the enclosed SE for the amendments, as appropriate.

Included in the amendments are the following two conditions for the CNP operating licenses that were submitted in one of your letters of April 15, 2005: (1) the relocation of CTSs requirements into licensee-controlled documents during the implementation of the ITSs, and (2) the schedule for the first performance of new and revised surveillance requirements (SRs) for the ITSs. These license conditions, which are discussed in the enclosed SE, are part of the implementation of the ITSs and constitute enforceable commitments that the NRC staff is relying upon in approving the amendments. Any changes to these license conditions, including the implementation date for the ITS conversion for the two units, must be submitted as a separate 10 CFR 50.90 amendment to the licenses, and approved by the NRC staff. The ITSs will become the governing TSs for CNP, Units 1 and 2, upon the date of implementation of the ITSs for each unit, but no later than October 31, 2005, as stated in the license conditions. This date is based on the licensee's requested implementation date, in one of its four letters submitted April 15, 2005. Until the implementation of the ITSs is completed, the CTSs shall remain in effect and the units will be operated in accordance with the requirements of the CTSs. If there is an amendment for either unit to the TSs before the implementation of the ITSs is completed, the amendment will be to both the CTSs and the ITSs. You are requested to submit a letter stating that the ITSs have been implemented within 14 days of the date of implementation. A copy of our related SE for the amendments is also enclosed. A Notice of Issuance will be included in the Commission's next biweekly Federal Register notice. Sincerely, IRA/ Jack Donohew, Senior Project Manager, Section 2 Project Directorate IV Division of Licensing Project Management Office of Nuclear Reactor Regulation DISTRIBUTION: Docket Nos. 50-315 and 50-316 PUBLIC GHiII(2) PD 3-1 r/f TBoyce (DRIP/IROB)

Enclosures:

1. Amendment No. 287 to DPR-58 RidsNrrDIpmPdiii(WRuland)

2. Amendment No. 269 to DPR-74 RidsNrrDIpmPdiiil (LRaghaven)

3. Safety Evaluation RidsNrrPMFLyon RidsNrrLATHarris cc w/encls: See next page RidsOogRp RidsAcrsAcnwMailCenter RidsRegion3MailCenter (AVegel)

DOCUMENT NAME: E:\Filenet\ML050620034.wpd AflAMR A*..F*IflN MIIMIRFPR M hlfl9ll l.*A? PntIknn MNfl MI flI1!9fl9* T5R P~:nnp, MI Nl!IA9N95Q OFFICE PM:PDIV-2 LA:PD3-1 SRXB-B/SC SPLB-A/ASC IROB-A/SC OGC SC:PD3-1 IROB-A/.SC NAME JDonohew THarris DCoe SJones TBoyce AHodgdon LRaghavan TBoyce BSIs All G.1.2, G.1.3, G.1.12, SE w/o BSIs, All All G.1.20.t G.2.7, and G.1.13 G.1.3, 6-10, 12-15, G.1.3.c G.2.8 16-20, and G.2.8 /JStang for/ DATE 03/09/05 103/14/05 05/16/05 12/06/04 i15/24/05 15/31/05 15/26/05 6101105 101/21/05 OFFICE EMEB/SC SPSB/SC SRXB-B/SC PM:PDIV-2 EMCB/SC SRXB-B/SC EEIB-B/SC EEIB-A/SC NAME DTerao RDennig JUhle JDonohew TChan JUhle EMarinos RJenkins BSIs G.1.17 G.1.11, 14, G.2.2, G.2.9 G.1.20 G.1.9 G.1.10, EEIB BSIs EEIB BSIs 15 and G.1.7, G.1.8 (non-EEIB BSIs) G.2.12 G.1.3.d,e,f. LTOP DATE 08/31/04 0911'6/04 109/22/04 01/05/05 10/06/04 10/26/04 02/22/05 01/19/05 07/28/04 09/27/04 11/02/04 01/27/05 OFFICIAL RECORD COPY

E.12 CTS 3/4.3.3.4, DOC R.1 CTS 3/4.3.3.4 provides requirements for meteorological instrumentation. Meteorological instrumentation is used to measure environmental parameters that may affect distribution of fission products and gases following a DBA, but it is not an input assumption for any DBA analysis and does not mitigate the accident. Meteorological information is required to evaluate the need for initiating protective measures to protect the health and safety of the public. This Specification does not meet the criteria of 10 CFR 50.36 for retention in the ITSs; therefore, it will be relocated to the TRM. This change is acceptable because CTS 3/4.3.3.4 does not meet the 10 CFR 50.36(c)(2)(ii) criteria for inclusion in the ITSs. The 10 CFR 50.36(c)(2)(ii) Criteria Evaluation is the following:

1. Meteorological instrumentation is not used for, nor capable of, detecting a, significant abnormal degradation of the reactor coolant pressure boundary prior to a DBA. The Meteorological Instrumentation Specification does not satisfy criterion 1.

2. Meteorological instrumentation is not used to indicate status of, or monitor, a process variable, design feature, or operating restriction that is an initial condition of a DBA or transient. The Meteorological Instrumentation Specification does not satisfy criterion 2.

3. Meteorological instrumentation is not part of a primary success path in the mitigation of a DBA or transient. The Meteorological Instrumentation Specification does not satisfy criterion 3.

4. As discussed in Section 4.0 (Appendix A, page A-23), and summarized in Table 1 of WCAP-1 1618, the loss of meteorological monitoring instrumentation was not found to be a significant risk contributor to CDF and offsite releases.

The licensee has reviewed this evaluation, considers it applicable to CNP Units 1 and 2, and concurs with the WCAP assessment. The Meteorological Instrumentation Specification does not satisfy criterion 4. Since the 10 CFR 50.36(c)(2)(ii) criteria are not met, Meteorological Instrumentation LCO and associated surveillances may be relocated out of the TSs. The Meteorological Instrumentation Specification will be relocated to the TRM, and changes to the TRM will be adequately controlled by the provisions of 10 CFR 50.59. E.13 CTS 3/4.3.3.5.1 CTS 3/4.3.3.5.1 provides requirements for 10 CFR Part 50 Appendix R, fire protection, remote shutdown instrumentation. The Appendix R remote shutdown instrumentation is used to ensure that a fire will not preclude achieving safe shutdown. This instrumentation is independent of areas where a fire could damage systems normally used to shut down the reactor. However, the instrumentation is not used to detect a degradation of the reactor coolant pressure boundary, and is not assumed to mitigate a

DBA or transient event. The Appendix R remote shutdown instrumentation capability is consistent with the requirements of 10 CFR Part 50, Appendix R. The acceptability of the relocation of the Appendix R TS requirements from the plant TSs has already been endorsed by the NRC as indicated in GL 86-10. This Specification does not meet the criteria of 10 CFR 50.36 for retention in the ITSs; therefore, it will be relocated to the TRM. This change is acceptable because CTS 3/4.3.3.5.1 does not meet the 10 CFR 50.36(c)(2)(ii) criteria for inclusion in the ITSs. The 10 CFR 50.36(c)(2)(ii) Criteria Evaluation is the following:

1. Appendix R remote shutdown instrumentation is not used for, nor capable of, detecting a-significant abnormal degradation of the reactor coolant pressure boundary prior to a DBA. The Appendix R Remote Shutdown Instrumentation Specification does not satisfy criterion 1.

2. Appendix R remote shutdown instrumentation is not used to indicate status of, or monitor, a process variable, design feature, or operating restriction that is an initial condition of a DBA or transient. The Appendix R Remote Shutdown Instrumentation Specification does not satisfy criterion 2.

3. Appendix R remote shutdown instrumentation is not part of a primary success path in the mitigation of a DBA or transient. The Appendix R Remote Shutdown Instrumentation Specification does not satisfy criterion 3.

4. Although the Appendix R remote shutdown instrumentation has not been

        'specifically evaluated for risk significance either generically or on a plant-specific basis, the licensee stated that insight based on a review of CNP Units 1 and 2 licensing basis documentation (including the CNP PRA Final Report) indicates that the instrumentation is not risk dominant with regard to CDF or off-site health effects. The Appendix R Remote Shutdown Instrumentation Specification does not satisfy criterion 4.

Since the 10 CFR 50.36(c)(2)(ii) criteria are not met, Appendix R Remote Shutdown Instrumentation LCO and associated surveillances may be relocated out of the TSs. The Appendix R Remote Shutdown Instrumentation Specification will be relocated to the TRM, and changes to the TRM will be adequately controlled by the provisions of. 10 CFR 50.59. E.14 CTS 3/4.3.3.9, DOC R.1 CTS 3/4.3.3.9 provides requirements for explosive gas monitoring instrumentation. The Explosive Gas Monitoring Instrumentation Specification is provided to ensure that the concentration of potentially explosive gas mixtures contained in the gaseous waste processing system is adequately monitored, which will help ensure that the concentration is maintained below the flammability limit. However, the system is designed to contain detonations, and detonations would not affect the function of any safety-related equipment. The concentration of oxygen in the gaseous Waste}}